Global Hydrogen Review
2021

INTERNATIONAL ENERGY AGENCY
The IEA examines the full spectrum ofenergy issues including oil, gas andcoal supply and demand, renewableenergy technologies, electricity
markets, energy efficiency, access toenergy, demand side management
and much more. Through its work, the
IEA advocates policies that will
enhance the reliability, affordability
and sustainability of energy in its 30
member countries, 8 association
countries and beyond.
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Source: IEA. All rights reserved.
International Energy Agency
Website: www.iea.org

IEA member countries:
Australia
Austria
Belgium
CanadaCzech Republic
Denmark
Estonia
FinlandFranceGermany
GreeceHungary
Ireland
Italy
Japan
Korea
Luxembourg
MexicoNetherlands
New Zealand
NorwayPolandPortugal
Slovak Republic

Spain
SwedenSwitzerland
TurkeyUnited Kingdom
United States
IEA association countries:
BrazilChina
India
Indonesia
MoroccoSingapore
South Africa
Thailand

Revised version,
November 2021.
Information noticefound at: www.iea.org/
corrections

Table of contents

Global Hydrogen Review 2021

Table of Contents

Annexes ....................................................................................................... 214
Abbreviations and acronyms .............................................................. 215

Executive summary ......................................................................................... 4

Units of measure ................................................................................ 218

Introduction .................................................................................................... 10

Acknowledgements ............................................................................ 219

Scenarios used in this Global Hydrogen Review ......................................... 16
The role of hydrogen in the Net zero Emissions by 2050 Scenario............. 18
Policy trends across key areas for hydrogen deployment ....................... 21
Progress in five key areas for hydrogen policymaking ................................ 22
Hydrogen demand ......................................................................................... 41
Overview and outlook ............................................................................... 42
Refining .................................................................................................... 50
Industry ..................................................................................................... 54
Transport .................................................................................................. 67
Buildings ................................................................................................... 86
Electricity generation ................................................................................ 98
Hydrogen supply ......................................................................................... 106
Overview and outlook ............................................................................. 107
Electrolysis ............................................................................................. 115
Fossil fuels with carbon capture ............................................................. 127
Hydrogen-based fuels ............................................................................ 135
Emerging technologies ........................................................................... 138
Infrastructure and trade .............................................................................. 141
Infrastructure .......................................................................................... 142
Hydrogen trade ....................................................................................... 154
Investments and innovation ....................................................................... 163
Regional insights ......................................................................................... 175
Policy recommendations ............................................................................ 203

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Executive summary

Global Hydrogen Review 2021

Executive summary

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Global Hydrogen Review 2021

Executive summary

Executive Summary
After several false starts, a new beginning around thecorner
The time is ripe to tap into hydrogen’s potential contribution to asustainable energy system. In 2019, at the time of the release of
the IEA’s landmark report The Future of Hydrogen for the G20,
only France, Japan and Korea had strategies for the use ofhydrogen. Today, 17 governments have released hydrogenstrategies, more than 20 governments have publicly announced
they are working to develop strategies, and numerous companies
are seeking to tap into hydrogen business opportunities. Suchefforts are timely: hydrogen will be needed for an energy systemwith net zero emissions. In the IEA’s Net Zero by 2050: A
Roadmap for the Global Energy Sector, hydrogen use extends toseveral parts of the energy sector and grows sixfold from today’slevels to meet 10% of total final energy consumption by
2050. This is all supplied from low-carbon sources.

Hydrogen supplies are becoming cleaner … too slowly

up to 54 GW by 2030. Another 40 projects accounting for more than
35 GW of capacity are in early stages of development. If all thoseprojects are realised, global hydrogen supply from electrolysers could
reach more than 8 Mt by 2030. While significant, this is still well below
the 80 Mt required by that year in the pathway to net zero CO2emissions by 2050 set out in the IEA Roadmap for the Global Energy
Sector.
Europe is leading electrolyser capacity deployment, with 40% of
global installed capacity, and is set to remain the largest market in
the near term on the back of the ambitious hydrogen strategies of theEuropean Union and the United Kingdom. Australia’s plans suggest
it could catch up with Europe in a few years; Latin America and the
Middle East are expected to deploy large amounts of capacity as well,in particular for export. The People’s Republic of China (“China”)
made a slow start, but its number of project announcements is
growing fast, and the United States is stepping up ambitions with its
recently announced Hydrogen Earthshot.

Sixteen projects for producing hydrogen from fossil fuels with carbon
Hydrogen demand stood at 90 Mt in 2020, practically all for
capture, utilisation and storage (CCUS) are operational today,
refining and industrial applications and produced almost
producing 0.7 Mt of hydrogen annually. Another 50 projects are under
exclusively from fossil fuels, resulting in close to 900 Mt of CO2
development and, if realised, could increase the annual hydrogen
emissions. But there are encouraging signs of progress. Global
production to more than 9 Mt by 2030. Canada and the United States
capacity of electrolysers, which are needed to produce hydrogenlead in the production of hydrogen from fossil fuels with CCUS, withfrom electricity, doubled over the last five years to reach just overmore than 80% of global capacity production, although the United
300 MW by mid-2021. Around 350 projects currently underdevelopment could bring global capacity
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Executive summary

Global Hydrogen Review 2021

start at the end of 2021. Several projects at a scale of tens ofkilotonnes of hydrogen are expected to become operational over the
next two to three years. Demonstration projects for using hydrogen inindustrial applications such as cement, ceramics or glass
manufacturing are also under development.

Kingdom and the Netherlands are pushing to become leaders in thefield and account for a major part of the projects under development.

Expanding the reach of hydrogen use
Hydrogen can be used in many more applications than thosecommon today. Although this still accounts for a small share of totalhydrogen demand, recent progress to expand its reach has beenstrong, particularly in transport. The cost of automotive fuel cells has
fallen by 70% since 2008 thanks to technological progress andgrowing sales of fuel cell electric vehicles (FCEVs). Thanks to theefforts by Korea, the Unites States, China and Japan, the number of
FCEVs on the road grew more than sixfold from 7 000 in 2017 to over
43 000 by mid-2021. In 2017, practically all FCEVs were passenger
cars. Today, one-fifth are buses and trucks, indicating a shift to thelong-distance segment where hydrogen can better compete withelectric vehicles. However, the total number of FCEVs is still well
below the estimated 11 million electric vehicles on the road today.
Several demonstration projects for the use of hydrogen-based fuelsin rail, shipping and aviation are already under development and are
expected to open new opportunities for creating hydrogen demand.

Governments need to scale up ambitions and support
demand creation
Countries that have adopted hydrogen strategies have committed atleast USD 37 billion; the private sector has announced an additional
investment of USD 300 billion. But putting the hydrogen sector on
track for net zero emissions by 2050 requires USD 1 200 billion of
investment in low-carbon hydrogen supply and use through to 2030.
The focus of most government policies is on producing low-carbonhydrogen. Measures to increase demand are receiving less attention.
Japan, Korea, France and the Netherlands have adopted targets for
FCEV deployment. But boosting the role of low-carbon hydrogen inclean energy transitions requires a step change in demand creation.
Governments are starting to announce a wide variety of policy
instruments, including carbon prices, auctions, quotas, mandates andrequirements in public procurement. Most of these measures have
not yet entered into force. Their quick and widespread enactment
could unlock more projects to scale up hydrogen demand.

Hydrogen is a key pillar of decarbonisation for industry, althoughmost of the technologies that can contribute significantly are still
nascent. Major steps are being taken. The world’s first pilot projectfor producing carbon-free steel using low-carbon hydrogen began
operation this year in Sweden. In Spain, a pilot project for the use ofvariable renewables-based hydrogen for ammonia production will

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Executive summary

Global Hydrogen Review 2021

Low-carbon hydrogen can become competitive within
the next decade

Meeting climate pledges requires faster and moredecisive action

A key barrier for low-carbon hydrogen is the cost gap with hydrogenfrom unabated fossil fuels. At present, producing hydrogen from fossil
fuels is the cheapest option in most parts of the world. Depending on
regional gas prices, the levelised cost of hydrogen production fromnatural gas ranges from USD 0.5 to USD 1.7 per kilogramme (kg).
Using CCUS technologies to reduce the CO2 emissions fromhydrogen production increases the levelised cost of production toaround USD 1 to USD 2 per kg. Using renewable electricity to
produce hydrogen costs USD 3 to USD 8 per kg.

While the adoption of hydrogen as a clean fuel is accelerating, it still
falls short of what is required to help reach net zero emissions by
2050. If all the announced industrial plans are realised, by 2030:

There is significant scope for cutting production costs throughtechnology innovation and increased deployment. The potential isreflected in the IEA’s Net Zero Emissions by 2050 Scenario (NZE
Scenario) in which hydrogen from renewables falls to as low as
USD 1.3 per kg by 2030 in regions with excellent renewable
resources (range USD 1.3-3.5 per kg), comparable with the cost ofhydrogen from natural gas with CCUS. In the longer term, hydrogencosts from renewable electricity fall as low as USD 1 per kg (range
USD 1.0-3.0 per kg) in the NZE Scenario, making hydrogen fromsolar PV cost-competitive with hydrogen from natural gas even
without CCUS in several regions.



Total hydrogen demand could grow as high as 105 Mt – compared withmore than 200 Mt in the NZE Scenario

Low-carbon hydrogen production could reach more than 17 Mt – oneeighth of the production level required in the NZE Scenario

Electrolysis capacity could rise to 90 GW – well below the nearly
850 GW in the NZE ScenarioUp to 6 million FCEVs could be deployed – 40% of the level of
deployment in the NZE Scenario (15 million FCEVs)

Much faster adoption of low-carbon hydrogen is needed to put theworld on track for a sustainable energy system by 2050. Developinga global hydrogen market can help countries with limited domestic
supply potential while providing export opportunities for countries withlarge renewable or CO2 storage potential. There is also a need toaccelerate technology innovation efforts. Several critical hydrogentechnologies today are in early stages of development. We estimatethat USD 90 billion of public money needs to be channeled into clean
energy innovation worldwide as quickly as possible – with around halfof it dedicated to hydrogen-related technologies.

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Executive summary

Global Hydrogen Review 2021

Stronger international co-operation: a key lever for
success
International co-operation is critical to accelerate the adoption ofhydrogen. Japan has spearheaded developments through theHydrogen Energy Ministerial Meeting since 2018. Several bilateraland multilateral co-operation agreements and initiatives have since
been announced, including the Clean Energy Ministerial Hydrogen
Initiative, the Hydrogen Mission of Mission Innovation and the Global
Partnership for Hydrogen of the United Nations Industrial
Development Organization. These join the existing International
Partnership for Hydrogen and Fuel Cells in the Economy and the IEA
Hydrogen and Advanced Fuel Cells Technology Collaboration
Programme. Stronger coordination among such initiatives isimportant to avoid duplication of efforts and ensure efficient progress.

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Executive summary

Global Hydrogen Review 2021

IEA policy recommendations



Mobilise investment in production, infrastructure and factories: A
policy framework that stimulates demand can, in turn, prompt
investment in low-carbon production plants, infrastructure andmanufacturing capacity. However, without stronger policy action, thisprocess will not happen at the necessary pace to meet climate goals.
Providing tailor-made support to selected shovel-ready flagshipprojects can kick-start the scaling up of low-carbon hydrogen and thedevelopment of infrastructure to connect supply sources to demand
centres and manufacturing capacities from which later projects canbenefit. Adequate infrastructure planning is critical to avoid delays or
the creation of assets that can become stranded in the near or medium
term.



Provide strong innovation support to ensure critical technologies
reach commercialisation soon: Continuous innovation is essential todrive down costs and increase the competitiveness of hydrogentechnologies. Unlocking the full potential demand for hydrogen will
require strong demonstration efforts over the next decade. An increaseof R&D budgets and support for demonstration projects is urgently
needed to make sure key hydrogen technologies reachcommercialisation as soon as possible.

Establish appropriate certification, standardisation and regulation
regimes: The adoption of hydrogen will spawn new value chains. This
will require modifying current regulatory frameworks and defining new
standards and certification schemes to remove barriers preventing
widespread adoption. International agreement on methodology to
calculate the carbon footprint of hydrogen production is particularly
important to ensure that hydrogen production is truly low-carbon. It will
also play a fundamental role in developing a global hydrogen market.

Governments must take a lead in the energy transformation. In The
Future of Hydrogen, the IEA identified a series of recommendations
for near-term action. This report offers more detail about how policies
can accelerate the adoption of hydrogen as a clean fuel:

Develop strategies and roadmaps on the role of hydrogen inenergy systems: National hydrogen strategies and roadmaps withconcrete targets for deploying low-carbon production and, particularly,
stimulating significant demand are critical to build stakeholder
confidence about the potential market for low-carbon hydrogen. This isa vital first step to create momentum and trigger more investments toscale up and accelerate deployment.
Create incentives for using low-carbon hydrogen to displace
unabated fossil fuels: Demand creation is lagging behind what isneeded to help put the world on track to reach net-zero emissions by2030. It is critical to increase concrete measures on this front to tap intohydrogen’s full potential as a clean energy vector. Currently, lowcarbon hydrogen is more costly to use than unabated fossil-basedhydrogen in areas where hydrogen is already being employed – and it
is more costly to use than fossil fuels in areas where hydrogen could
eventually replace them. Some countries are already using carbon
pricing to close this cost gap but this is not enough. Wider adoption
combined with other policy instruments like auctions, mandates, quotas
and hydrogen requirements in public procurement can help de-risk
investments and improve the economic feasibility of low-carbonhydrogen.

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Introduction

Global Hydrogen Review 2021

Introduction

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Introduction

Global Hydrogen Review 2021

Overview
In the run-up to the 26th Conference of the Parties to the UN
Framework Convention on Climate Change (COP 26), a growing
number of countries are announcing targets to achieve net zero
GHG emissions over the next decades. In turn, more than 100
companies that consume large volumes of energy or produce
energy‐consuming goods have followed suit. As demonstrated in

deployment, and during the 6th Mission Innovation Ministerial, theClean Hydrogen Mission to reduce the cost of clean hydrogen wasannounced.
This Global Hydrogen Review is an output of H2I that is intended to
inform energy sector stakeholders on the current status and future
prospects of hydrogen and serve as an input to the discussions atthe HEM of Japan. It comprehensively examines what is needed toaddress climate change and compares actual progress with statedgovernment and industry ambitions and with key actions announced
in the Global Action Agenda launched in the HEM 2019. Focusing
on hydrogen’s usefulness in meeting climate goals, this Review
aims to help decision makers fine-tune strategies to attract
investment and facilitate deployment of hydrogen technologies
while also creating demand for hydrogen and hydrogen-based fuels.

the IEA Net zero by 2050 roadmap, achieving these targets will
require immediate action to turn the 2020s into a decade of massive
clean energy expansion.
Hydrogen will need to play an important role in the transition to
net zero emissions. Since the first Hydrogen Energy Ministerial(HEM) meeting in Japan in 2018, momentum has grown and anincreasing number of governments and companies are establishingvisions and plans for hydrogen.

This Review’s analysis comprises seven chapters. First, the chapter
on policy trends describes progress made by governments in
adopting hydrogen-related policies. Next, two comprehensive
chapters on global hydrogen demand and supply provide indepth analyses of recent advances in different sectors andtechnologies and explore how trends could evolve in the medium
and long term.

At the Osaka Summit in 2019, G20 leaders emphasised hydrogen’srole in enabling the clean energy transition. The IEA prepared thelandmark report The Future of Hydrogen for the summit, withdetailed analysis of the state of hydrogen technologies and theirpotential to contribute to energy system transformation, as well as
challenges that need to be overcome. In addition, during the 10th
Clean Energy Ministerial (CEM) meeting in Vancouver, theHydrogen Initiative (H2I) was launched to accelerate hydrogen

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Introduction

Global Hydrogen Review 2021

A chapter on infrastructure and hydrogen trade emphasises theneed to develop both these areas while ramping up demand andsupply. It also details the status and opportunities for deployinghydrogen infrastructure, as well as recent trends and the outlook forhydrogen trade.
Investments and innovation are combined into one chapter toreflect how they mutually underpin trends in the development anduptake of hydrogen technologies. Meanwhile, the chapter on
insights on selected regions recaps progress in regions andcountries where governments and industry are particularly active inadvancing hydrogen deployment.
The final chapter provides policy recommendations to accelerate
the adoption of hydrogen technologies in the next decade, with aview to ensuring it becomes economically and technically viable andsocially acceptable.

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Introduction

Global Hydrogen Review 2021

The Hydrogen Initiative
Developed under the CEM framework, H2I is a voluntary multigovernment initiative that aims to advance policies, programmes andprojects that accelerate the commercialisation and deployment ofhydrogen and fuel cell technologies across all areas of the economy.
Ultimately, it seeks to ensure hydrogen’s place as a key enabler inthe global clean energy transition.
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 andintergovernmental entities: Australia, Austria, Brazil, Canada, Chile,
the People’s Republic of China (hereafter China), Costa Rica, theEuropean Commission, Finland, Germany, India, Italy, Japan, theNetherlands, New Zealand, Norway, Portugal, the Republic of Korea(hereafter Korea), the Russian Federation (hereafter Russia), Saudi
Arabia, South Africa, the United Kingdom and the United States.
Canada, the European Commission, Japan, the Netherlands and theUnited States co-lead the initiative, while China and Italy areobservers.

H2I is also a platform to co-ordinate and facilitate co-operation among
governments, other international initiatives and the industry sector.
The Initiative has active partnerships with the Hydrogen Council, theInternational Partnership for Hydrogen and Fuel Cells in the Economy(IPHE), the International Renewable Energy Agency (IRENA),
Mission Innovation (MI), the World Economic Forum (WEF) and the
IEA’s Advanced Fuel Cells and Hydrogen Technology Collaboration
Programmes (TCPs), all of which are part of the H2I Advisory Group.
In addition, several industrial partners actively participate in the H2I
Advisory Group’s bi-annual meetings, including Ballard, Enel, Engie,
Nel Hydrogen, the Port of Rotterdam and Thyssenkrupp.

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Introduction

Global Hydrogen Review 2021

The Global Hydrogen Review
specific hydrogen technologies and offered insights on emerging
technologies and barriers that need to be overcome to facilitate theirdeployment. The Advanced Fuel Cells TCP contributed with its
annual tracking of fuel cell electric vehicles and infrastructure
deployment.

Following IEA recommendations in The Future of Hydrogen, thisGlobal Hydrogen Review aims to track progress in hydrogenproduction and demand, as well as in other areas of criticalimportance such as policy, regulation and infrastructuredevelopment. To do this effectively and comprehensively, the IEA
has established co-operative relationships with other relevant
institutions to provide sound analysis based on the best possible
data, and to create synergies among other international efforts,building on their respective strengths and experiences.

Types of hydrogen in the Global Hydrogen Review
Hydrogen is a very versatile fuel that can be produced using all typesof energy sources (coal, oil, natural gas, biomass, renewables andnuclear) through a very wide variety of technologies (reforming,
gasification, electrolysis, pyrolysis, water splitting and many others).
In recent years, colours have been used to refer to different hydrogenproduction routes (e.g. green for hydrogen from renewables and blue
for production from natural gas with carbon capture, utilisation andstorage [CCUS]), and specialised terms currently under discussion
include “safe”, “sustainable”, “low-carbon” and “clean”. There is nointernational agreement on the use of these terms as yet, nor havetheir meanings in this context been clearly defined.

The Hydrogen Council in particular shared critical information ontechnology costs and performance from its industry network, which
enriched IEA databases, modelling assumptions and technoeconomic parameters.
Meanwhile, the IPHE contributed inputs on the developmental statusof standards, codes and regulations. Leveraging its government
network and established process to collect data and work
collaboratively on regulatory issues, it also provided valuable
information on the technology deployment and policy targets of its
member governments.

Because of the various energy sources that can be used, theenvironmental impacts of each production route can varyconsiderably; plus, the geographic region and the process
configuration applied also influence impacts. For these reasons, theThe IEA TCPs and their networks of researchers and stakeholders
also provided valuable inputs. The Hydrogen TCP helped the IEA
update its latest assessment of the technology readiness levels of
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Introduction

Global Hydrogen Review 2021

IEA does not specifically espouse any of the above terms.
Recognising that the potential of hydrogen to reduce CO2 emissions
depends strongly on how it is produced, this report highlights the role
low-carbon hydrogen production routes can have in the clean energy
transition. Low-carbon hydrogen in this report includes hydrogenproduced from renewable and nuclear electricity, biomass, and fossil
fuels with CCUS. 1
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 associated with the production route, and if all CO2
is permanently stored to prevent its release into the atmosphere. The
same principle applies to low-carbon feedstocks and hydrogen-based
fuels made using low-carbon hydrogen and a sustainable carbon
source (of biogenic origin or directly captured from the atmosphere).
This report also highlights the importance of establishing standards
and certification to properly recognise the carbon footprints of thedifferent hydrogen production routes. Since no standards have beeninternationally agreed and adopted, the IEA continues to differentiate
the types of hydrogen by the technology used in their production, anduses this as the basis of its current definition of low-carbon hydrogen.
This may evolve as dialogue within the international hydrogen
community advances and more evidence and agreement emerge.

.

or all of the CO2 is permanently stored. When use of the CO2 ultimately leads to it being re-emitted
to the atmosphere (e.g. urea production), CCU is specified.

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 [EOR] or building materials) if some

1

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Introduction

Global Hydrogen Review 2021

Scenarios used in this Global
Hydrogen Review

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Introduction

Global Hydrogen Review 2021

Outlook for hydrogen production and use
This Global Hydrogen Review relies on three indicators to trackprogress on hydrogen production and use:

on-the-ground progress in hydrogen technology deployment

government ambitions to integrate hydrogen into long-term energy
strategiesgaps between on-the-ground progress, government ambitions andprojected energy transition requirements.

Pledges presented in this report include official targets (i.e. clear
goals of national hydrogen strategies and roadmaps) as well as
ambitions (i.e. plans communicated in consultations through the H2I
work stream, but for which governments have not yet made official
announcements or adopted a strategy or roadmap).
For the first time, the IEA’s May 2021 report Net zero by 2050 laysout in detail what is needed from the energy sector to reach net zeroCO2 emissions by 2050, in line with the Paris Agreement’s ambitious
target to limit global temperature rise to 1.5°C. Based on thesefindings, this Review compares actual implemented actions withclean energy transition needs using two IEA scenarios: the Net zero
Emissions by 2050 Scenario and the Announced Pledges Scenario.

In this report, the Projects Case reflects on-the-ground progress. It
takes all projects in the pipeline 2 into account as well as announced
industry stakeholder plans to deploy hydrogen technologies acrossthe entire value chain (from production to use in different end-use
sectors).

The Announced Pledges Scenario considers all national net zero
emissions pledges that governments have announced to date andassumes they are realised in full and on time. This scenario therebyshows how far full implementation of national net zero emissions
pledges would take the world towards reaching climate goals, and it
highlights the potential contributions of different technologies,
including hydrogen.

Government targets and ambitions related to deploying hydrogentechnologies are presented as hydrogen pledges. To gather relevant
information from governments around the world, a joint IEA–
European Commission work stream was established within theframework of the CEM Hydrogen Initiative, to consult governments
around the world about their hydrogen targets and ambitions.

2
In addition to projects already operational, this includes those currently under construction, thathave reached final investment decision (FID) and that are undergoing feasibility studies.

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Introduction

Global Hydrogen Review 2021

The role of hydrogen in the Net zero
Emissions by 2050 Scenario

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Introduction

Global Hydrogen Review 2021

Hydrogen is an important part of the Net zero Emissions Scenario, but is only one piece of the
puzzleSources of hydrogen production in the
NZE, 2020-2050

100%

600

80%

500

Mt H₂

Share of TFC (%)

Share of total final energy consumption by
fuel in the NZE, 2020-2050

60%

Other fuel shifts
5%
CCUS
11%

400

Behaviour andavoided demand
11%
Technology
performance
13%

300

40%

200

20%
0%

Cumulative emissions reduction by
mitigation measure in the NZE, 2021-2050

Electrification
19%

100

2020

2030

2050

Coal

Oil

Natural gas

Renewables

Electricty

HydrogenDistrict heat

0

2020

2030

2050

FossilBy-product

Fossil with CCUS

Electricity

Hydrogen6%
Renewables
35%

IEA. All rights reserved.
Notes: NZE = Net zero Emissions Scenario. TFC = total final energy consumption. CCUS = carbon capture, utilisation and storage. “Behaviour” refers to energy service demandchanges linked to user decisions (e.g. heating temperature changes). “Avoided demand” refers to energy service demand changes from technology developments (e.g. digitalisation).
“Other fuel shifts” refers to switching from coal and oil to natural gas, nuclear, hydropower, geothermal, concentrating solar power or marine energy. “Hydrogen” includes hydrogen andhydrogen-based fuels.
Source: IEA (2021), Net zero by 2050.

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Introduction

Global Hydrogen Review 2021

Achieving net zero emissions by 2050 will require a broad range oftechnologies to transform the energy system. The key pillars ofdecarbonising the global energy system are energy efficiency,
behavioural change, electrification, renewables, hydrogen andhydrogen‐based fuels, and CCUS. The importance of hydrogen in thereaches more than 200 Mt H2, 70% is produced using low-carbon
technologies (electrolysis or fossil fuels with CCUS). Hydrogenproduction then grows to over 500 Mt H2 by 2050, practically all
based on low-carbon technologies. Reaching these goals will requirethat installed electrolysis capacity increase from 0.3 GW today toclose to 850 GW by 2030 and almost 3 600 GW by 2050, while CO2
captured in hydrogen production must rise from 135 Mt today to
680 Mt in 2030 and 1 800 Mt in 2050.

Net zero Emissions Scenario is reflected in its increasing share in
total final energy consumption (TFC): in 2020, hydrogen andhydrogen-based fuels accounted for less than 0.1%, 3 but by 2030
they meet 2% of TFC and in 2050, 10%.

Strong hydrogen demand growth and the adoption of cleaner
technologies for its production thus enable hydrogen and hydrogenbased fuels to avoid up to 60 Gt CO2 emissions in 2021-2050 in the
Net zero Emissions Scenario, representing 6.5% of total cumulativeemissions reductions. Hydrogen fuel use is particularly critical for
reducing emissions in the hard-to-decarbonise sectors in which directelectrification is difficult to implement, i.e. heavy industry (particularly
steel manufacturing and chemical production), heavy-duty roadtransport, shipping and aviation. In the power sector, hydrogen canalso provide flexibility by helping to balance rising shares of variable
renewable energy generation and facilitating seasonal energy
storage.

Nevertheless, this demand increase alone is not enough to makehydrogen a key pillar of decarbonisation. Hydrogen production mustalso become much cleaner than it is today. For instance, of the~90 Mt H2 used in 2020, around 80% was produced from fossil fuels,
mostly unabated. Practically all the remainder came from residual
gases produced in refineries and the petrochemical industry. This
resulted in almost 900 Mt CO2 emitted in the production of hydrogen,equivalent to the CO2 emissions of Indonesia and the United
Kingdom combined.
In the Net zero Emissions Scenario, hydrogen production undergoes
an unparalleled transformation. By 2030, when total production

This excludes industry sector on-site hydrogen production and use, which consumes around 6%
of final energy consumption in industry today. Including on-site hydrogen production in industry,hydrogen and hydrogen-based fuels meet 1% of total final energy consumption today, 4% by 2030
and 13% by 2050 in the Net Zero Emissions Scenario.

3

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Policy trends

Global Hydrogen Review 2021

Policy trends across key
areas for hydrogen
deployment

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Policy trends

Global Hydrogen Review 2021

Progress in five key areas forhydrogen policymaking

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Policy trends

Global Hydrogen Review 2021

Introduction
The Global Hydrogen Review tracks and reports progress in theseareas with the aim of apprising governments and stakeholders of thepace of change in hydrogen policymaking. The Review highlights
new policies being adopted around the world, assesses their impacts
and identifies potential gaps. Its dual objectives are to help
governments adopt or adapt other countries’ successful experiences
and avoid repeating failures.

Integrating hydrogen as a new vector into energy systems is acomplex endeavour: without government intervention, it will not berealised at the pace required to meet climate ambitions. Many
governments are therefore already working with diverse stakeholders
to address key challenges and identify smart policies that canfacilitate this transformation. As needs differ for each country andindustry, policies and actions must be based on relevant priorities andconstraints, including resource availability and existing infrastructure.
In The Future of Hydrogen, the IEA identified five key areas forgovernments to define comprehensive policy frameworks to facilitatehydrogen adoption across the entire energy system:
1.

Establish targets and/or long-term policy signals.

2.

Support demand creation.

3.

Mitigate investment risks.

4.

Promote R&D, innovation, strategic demonstration projects andknowledge-sharing.

5.

Harmonise standards and removing barriers.

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Policy trends

Global Hydrogen Review 2021

1. Establish targets and/or long-term policy signals
In their long-term energy strategies, governments should determine
the most efficient way hydrogen can be used to support
decarbonisation efforts. They should then set policies that send
long-term signals about this role to boost stakeholder confidence indevelopment of a marketplace for hydrogen and related
technologies. Integrated actions can guide future expectations,unlock investments and facilitate co-operation among companies
and countries.

Columbia), China, France, Germany (Baden-Württemberg, Bavaria,
North Germany, North Rhine-Westphalia) and Spain (BasqueCountry).
Some governments have even taken the additional step of defininghydrogen’s role in other, overarching policy frameworks. Japan’sGreen Growth Strategy, for example, describes the country’s vision
for producing and using hydrogen and for developing international
supply chains.

When The Future of Hydrogen was released in June 2019, only
Japan and Korea had published national hydrogen strategies todefine the role of hydrogen in their energy systems, and France hadannounced a hydrogen deployment plan. Since then, 13 countries(Australia, Canada, Chile, the Czech Republic, France, Germany,
Hungary, the Netherlands, Norway, Portugal, Russia, Spain and theUnited Kingdom) have published hydrogen strategies, along with
the European Commission. Colombia announced the release of its
strategy for the end of September 2021.

A coherent picture of future-use cases for hydrogen
The strategies published to date show that, with slight differences,almost all countries hold broadly similar views of the role hydrogenshould play in their energy systems. Practically all the strategies (15of 16) highlight its vital importance in decarbonising the transport
and industry sectors.
In the case of transport, most governments emphasise medium- andheavy-duty transport, and Japan and Korea envisage an importantrole for cars. Several governments highlight the potential use ofhydrogen and ammonia in shipping, while a smaller number are
considering producing synthetic fuels (synfuels) to decarbonise
aviation (Germany recently released a power-to-liquids [PtL]
roadmap) or using hydrogen in rail transport. Japan has taken the

Two countries (Italy and Poland) have released their strategies for
public consultation and more than 20 others are actively developing
them. Several regional governments have also defined hydrogenstrategies and roadmaps, including in Australia (Queensland, South
Australia, Tasmania, Victoria and West Australia), Canada (British

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additional step of publishing an Interim Report of the Public-Private
Council on Fuel Ammonia Introduction on using ammonia inelectricity generation and shipping.

(Chile, Germany, Portugal and Spain), while others are less specificabout the origin of the electricity (France’s strategy mentions
renewable and low-carbon electricity).

In the industry sector, each country’s plans focus on the mainindustries: some target certain subsectors (chemicals in Chile andSpain; steel in Japan), while others take a more cross-sectoral
approach (Canada and Germany). Canada and Chile havehighlighted the role of hydrogen in decarbonising mining operations,and all countries with significant refining capacities prioritise this
sector as well.

While several governments (9 of 16) have set a significant role forthe production of hydrogen from fossil fuels with CCUS, others(including the European Union) consider this option for only theshort and medium term to reduce emissions from existing assets
while supporting the parallel uptake of renewable hydrogen. Canada
has taken a different approach; instead of prioritising any specificproduction pathway, it is focusing on the carbon intensity ofhydrogen production, with targets to drive it to zero over time. Somecountries (e.g. Canada and Korea) have flagged the potential use
of by-product hydrogen (from the chlor-alkali or petrochemicalindustries) to meet small shares of demand.

Other potential hydrogen uses that are mentioned in strategies but
have received less attention are electricity generation – including
energy storage and system balancing (11 of 16) – and heat inbuildings (7 of 16). Finally, if international hydrogen trade develops,
some countries have a clear plan to become exporters (Australia,
Canada, Chile and Portugal) while others have started exploring thepossibility of importing hydrogen if national production capacity
cannot meet future demand (the European Union, Germany, Japanand the Netherlands).

Finally, most strategies refer to the potential for emerging
technologies, such as methane pyrolysis or biomass-based routes.
As these technologies are still at early stages of development,
prospects are considered uncertain.

Intermediate milestones to anchor long-term targets

Different views on how to produce hydrogen

Almost all governments have adopted a phased approach tointegrate hydrogen into their energy systems. How they definephases varies, but strategies tend to recognise three stages: scaling
up and laying the market foundations (early 2020s); widespread

Countries that have adopted hydrogen strategies present quite
diverse visions on how it should be produced. Hydrogen production
from electricity is common to all strategies, in some cases being thepreferred route in the long term. Some prioritise renewable power
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adoption and market maturity (late 2020s to early 2030s); and full
implementation of hydrogen as a clean energy vector (post-2030).
Deployment targets, while not present in all strategies, are acommon feature to anchor expected progress within these phases.
In some cases, targets have been proposed as a vision or an
aspiration (Canada, Japan); in others, they convey a firm
commitment with the intent to send strong signals to industry about
the future marketplace for hydrogen. To date, practically none ofthese targets is legally binding.

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Governments with adopted national hydrogen strategies; announced targets; priorities for hydrogen and use; and committed funding
Buildings

Electricity

Exports

Industry

Industry (chemicals)

Shipping

Transport.

Industry (steel)

MiningRefining

Aviation

Uses

Public investmentcommitted

Country

Document, year

Deployment targets (2030)

Production

Australia

National Hydrogen
Strategy, 2019

None specified

Coal with CCUS
Electrolysis (renewable)
Natural gas with CCUS

AUD 1.3 bln(~USD 0.9 bln)

CAD 25 mln by 2026(1)(~USD 19 mln)

CanadaHydrogen Strategy for
Canada, 2020

Total use: 4 Mt H2/y
6.2% TFEC

Biomass
By-product H2Electrolysis
Natural gas with CCUS
Oil with CCUS

Chile

National Green Hydrogen
Strategy, 2020

25 GW electrolysis(2)Electrolysis (renewable)

USD 50 mln for 2021

Czech
Republic

Hydrogen Strategy, 2021

Low-carbon demand: 97 kt H2/yr

Electrolysisn.a.

EuropeanUnion

EU Hydrogen Strategy,
2020

40 GW electrolysis

Electrolysis (renewable)
Transitional role ofnatural gas with CCUS

EUR 3.77 bln by 2030(~USD 4.3 bln)

FranceHydrogen Deployment
Plan, 2018
National Strategy for
Decarbonised Hydrogen
Development, 2020

6.5 GW electrolysis
20-40% industrial H2 decarbonised (3)20 000-50 000 FC LDVs (3)800-2 000 FC HDVs (3)400-1 000 HRSs (3)Electrolysis

EUR 7.2 bln by 2030(~USD 8.2 bln)

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Production

Document, year

Deployment targets (2030)

Germany

National Hydrogen
Strategy, 2020

5 GW electrolysis

Hungary

National Hydrogen
Strategy, 2021

Production: 20 kt/yr of low-carbon H2
16 kt/yr of carbon-free H2
240 MW electrolysis
Use: 34 kt/yr of low-carbon H2
4 800 FCEVs
20 HRSs

Electrolysis
Fossil fuels with CCUS

n.a.

Japan

Strategic Roadmap for
Hydrogen and Fuel Cells,
2019Green Growth Strategy,
2020, 2021 (revised)

Total use: 3 Mt H2/yr
Supply: 420 kt low-carbon H2
800 000 FCEVs
1 200 FC buses
10 000 FC forklifts
900 HRSs
3 Mt NH3 fuel demand(4)Electrolysis
Fossil fuels with CCUS

JPY 699.6 bln by 2030(~USD 6.5 bln)

Korea

Hydrogen Economy
Roadmap, 2019

Total use: 1.94 Mt H2/yr
2.9 million FC cars (plus 3.3 million
exported)(5)
1 200 HRSs(5)80 000 FC taxis(5)40 000 FC buses(5)30 000 FC trucks(5)8 GW stationary FCs (plus 7 GW
exported)(5)2.1 GW of micro-cogeneration FCs(5)By-product H2Electrolysis
Natural gas with CCUS

KRW 2.6 tln in 2020(~USD 2.2 bln)

Netherlands

National Climate
Agreement, 2019
Government Strategy on
Hydrogen, 2020

3-4 GW electrolysis
300 000 FC cars
3 000 FC HDVs (6)Electrolysis (renewables)
Natural gas with CCUS

EUR 70 mln/yr(~USD 80 mln/yr)

NorwayGovernment Hydrogen
Strategy, 2020
Hydrogen Roadmap,
2021

n.a.(7)

Electrolysis (renewables)
Natural gas with CCUS

NOK 200 mln for 2021(~USD 21 mln)

Electrolysis (renewable)

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Uses

Public investmentcommitted

Country

EUR 9 bln by 2030(~USD 10.3 bln)

Policy trends

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Country

Uses

Public investmentcommitted

Document, year

Deployment targets (2030)

Production

Portugal

National Hydrogen
Strategy, 2020

2-2.5 GW electrolysis
1.5-2% TFEC
1-5% TFEC in road transport
2-5% TFEC in industry
10-15 vol% H2 in gas grid
3-5% TFEC in maritime transport
50-100 HRS

Electrolysis (renewables)

EUR 900 mln by 2030(~USD 1.0 bln)

RussiaHydrogen roadmap 2020

Exports: 2 Mt H2

Electrolysis
Natural gas with CCUS

n.a.

Spain

National Hydrogen
Roadmap, 2020

4 GW electrolysis
25% industrial H2 decarbonised
5 000-7 500 FC LDVs-HDVs
150-200 FC buses
100-150 HRSs

Electrolysis (renewables)

EUR 1.6 bln(~USD 1.8 bln)

UnitedKingdom

UK Hydrogen Strategy,
2021

5 GW low-carbon production capacity

Natural gas with CCUS
Electrolysis

GBP 1 bln(~USD 1.3 bln)

Note: TFEC = total final energy consumption. (1) In addition to CAD 25 mln, Canada has committed over CAD 10 bln to support clean energy technologies, including H2. (2) This target
refers to projects that at least have funding committed, not to capacity installed by 2030. (3) Target for 2028. (4) From the interim Ammonia Roadmap. (5) Target for 2040. (6) Target
for 2025 from the National Climate Agreement, 2019 (currently under revision). (7) Norway’s strategy defines targets for the competitiveness of hydrogen technologies and project
deployment.

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2. Support demand creation
Creating demand for low-carbon hydrogen is critical for its
widespread adoption. Policy support to “pull” investment across thevalue chain will be needed to make projects bankable and overcome
deployment hurdles. For technologies that use hydrogen and areready for commercialisation, policy support to close the price gap withincumbents can stimulate faster deployment and accelerate cost
reductions that result from scaling up and learning by doing. Progressis under way, but not enough policies have been implemented tosupport longer-term targets and create demand for low-carbonhydrogen.

China launched a new FCEV pilot cities programme in 2020 toenlarge FCEV industry supply chains. In contrast with vehicle
purchase subsidies, the scheme rewards clusters of cities based ona series of parameters. To be eligible for financial rewards, city
clusters must deploy more than 1 000 FCEVs that meet certain
technical standards; achieve a delivered hydrogen price at a
maximum of CNY 35.00/kg (~USD 5.00/kg); and provide at least 15
operational hydrogen refuelling stations (HRSs). Based on the planand how well objectives are met, a maximum of CNY 1.5 billion(~USD 220 million) will be transferred to each selected city cluster
between 2020 and 2023.

A dynamic situation in the transport sector

Hydrogen vehicles may also benefit from programmes to support
zero emission vehicles (ZEVs) and implementation of CO2 emissions
standards. Recent examples include California’s ZEV mandate; theDutch government’s announcement that ZEVs will make up all public
transport bus sales by 2025; and the EU CO2 emissions standards
for heavy-duty vehicles (HDVs). In 2018, Switzerland adopted the
LSVA road tax, which levies trucks weighing more than 3.5 tonnes
but waives the fee for ZEVs. This created an attractive business casefor hydrogen trucks, which are expected to reach about 200 by theend of 2021. While not specific to hydrogen vehicles, which have tocompete with alternatives such as battery electric vehicles (BEVs),
these policies can stimulate FCEV deployment.

National hydrogen strategies place great value on using hydrogen intransport. As fuel cell electric vehicles (FCEVs) are commerciallyavailable for passenger cars, light-duty vehicles (LDVs) and buses,
several countries have policies to support their deployment.
More than 20 countries offer specific purchase subsidies for FCEVs,
ranging from EUR 1 500 (~USD 1 700) per vehicle in Finland to morethan USD 30 000 in Korea. In fact, purchasers of fuel cell buses in
Korea receive KRW 300 million (~USD 250 000). Tax benefits are inplace in at least 20 countries, and at least 17 apply specific company
tax benefits to support FCEV adoption in professional fleets.

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Policies for other sectors still under discussion

Other policies that can support hydrogen uptake in transport are theCalifornia Low Carbon Fuel Standard, Canada’s Clean Fuel Standard
and the UK Renewable Transport Fuel Obligation, which can also
spur adoption of low-carbon hydrogen in biofuel production andrefining. Meanwhile, in 2020 the Norwegian government announced
that the country’s largest ferry connection (Bodø-Værøy-RøstMoskenes) will be fuelled by hydrogen and in March 2021 the Port ofTokyo stated that it will waive the entry fee for ships powered by LNG
or hydrogen. These are the first measures implemented to supporthydrogen or hydrogen-derived fuels in shipping, but as thetechnology has not yet reached the commercial level, it will take time
to realise the impact of these policies.

Little progress has been achieved on policies for low-carbonhydrogen adoption in other sectors. Despite its anticipatedimportance, few policies have been designed specifically to create
demand for low-carbon hydrogen in industry.
Also in its Fit for 55 package, in July 2021 the European Commission
proposed a modification of the Renewable Energy Directive toinclude a 50% renewable hydrogen consumption in industry by 2030.
Germany’s strategy includes the potential implementation of
obligatory quotas for selected clean products (e.g. hydrogen-based
steel) and aims to explore how to implement such solutions at thenational and European levels.

Policies to support hydrogen-derived synthetic fuel use in aviation
have attracted attention recently. As part of its Fit for 55 package, in
July 2021 the European Commission proposed the ReFuel Aviation
Initiative to mandate minimum synthetic fuel shares in aviation, risingfrom 0.7% in 2030 to 28% in 2050. This measure awaits European
Council and European Parliament approval. Germany’s strategy
mentions a minimum quota of 2% synthetic fuels in aviation by 2030,
which has now passed the parliamentary process and is legallybinding. In addition, Germany’s recently released power-to-liquids(PtL) roadmap targets 200 000 tonnes of hydrogen-basedsustainable aviation fuel in 2030. The Dutch government has alreadyexpressed interest in these types of measures.

India has also announced mandatory quotas for using renewablehydrogen in refining (10% of demand from 2023-24, increasing to
25% in the following five years) and fertiliser production (5% of
demand from 2023-24, increasing to 20% in the following five years),with potential extension to the steel industry in the near future. This
will spur India to replace part of its current capacity for hydrogenproduced from natural gas (typically imported) with hydrogen fromrenewables while also creating new demand for locally producedhydrogen.
Injecting hydrogen into the natural gas grid has also attracted
attention as another means of creating new hydrogen demand. While

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no measures have yet been adopted, some countries are taking
steps in this direction. For instance, Portugal’s national strategy
targets 10-15 vol% H2 blending by 2030 and Chile is preparing a bill
to mandate blending quotas.

Lack of targets and policies for demand creation canstall low-carbon supply expansion
Because most government targets and policies to date have been
focused exclusively on enlarging hydrogen supplies, low-carbonhydrogen production has outpaced demand growth. Strategic actionis therefore needed to avoid the value chain imbalances that can
result in inefficient policy support.
If hydrogen demand is not sufficiently stimulated, producers may not
be able to secure off-takers and the development of low-carbonhydrogen supply capacity may held back. This could result in lowcarbon hydrogen capacity replacing only certain parts of current
production in industrial applications, which would impede scale-up
and discourage cost reductions, and ultimately delay adoption ofhydrogen as a clean energy vector.

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3. Mitigate investment risks
Many projects currently under way face risks related to uncertain
demand, lack of experience and value chain complexity. Measures toaddress risks linked to capital and operational costs can help tip thebalance in favour of private investment in these first projects.

Interest (IPCEI) scheme, which allows projects validated by both
member states and the Commission to receive public support beyond
the usual boundaries of state aid rules. This is expected to unlock
significant project investment across the entire hydrogen value chain,stimulating scale-up in the next decade.

European countries are leading the way

Countries beyond Europe are also taking action. In June 2021,
Canada announced a new Clean Fuels Fund to help private investors
overcome the barrier of high upfront capital costs to construct new
clean fuel production capacity, and will provide support to a minimumof ten hydrogen projects.

European policymakers have been particularly active in implementing
measures to mitigate the risks of hydrogen-related project
developers. In its Climate Agreement (launched June 2020), theNetherlands proposed including hydrogen in the SDE++ scheme,
which offers incentives to develop CO2 reduction technologies andrenewable energy. This scheme recently triggered its intended
actions and in May 2021 the Dutch government committed EUR 2
billion for the Porthos project to bridge the gap between current rates
for CO2 emissions allowances and the costs involved in capturing,transporting and storing CO2 underground. This will facilitate
development of projects to produce hydrogen from fossil fuels with
CCUS.

Public financial institutions are getting involved
Financial institutions can be critical in mitigating the investment risksof first movers. While the European Investment Bank (EIB) provided
significant investments for R&D in hydrogen projects in the last
decade, it has now shifted its focus to offer financial support andtechnical assistance for the development of large-scale projects. The
EIB signed related collaboration agreements with France Hydrogène(2020) and the Portuguese government (2021).

In September 2020, the European Commission announced a call for
tenders for projects to build electrolysis plants at the 100-MW scale.
All proposals have been evaluated and some awarded projects havebeen announced. Perhaps more importantly, the Commission
included hydrogen in the Important Projects of Common European

In May 2020, the Australian government, through the Clean Energy
Finance Corporation, made AUD 300 million available through theAdvancing Hydrogen Fund, thereby taking the first steps to facilitate
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investments in hydrogen projects to scale up production and end
uses. In 2021, the government of Chile launched (through CORFO)
a USD 50-million call for funding to develop electrolysis projects.

The European Commission announced that it is also considering thecarbon contracts for difference (CCfD) concept. Recent priceincreases in the EU ETS – which nearly doubled in 2021 to more thanEUR 60/t CO2 – are expected to limit the public spending needed tobridge the cost gap in these schemes.

New policy instruments are coming into play
Governments are developing new and innovative policy instruments
to support investment in hydrogen projects. In June 2021, theGerman government announced the H2 Global programme, with theaim of ramping up the international market for hydrogen produced
from renewable electricity. The scheme will tender ten-year purchaseagreements on hydrogen-based products, providing certainty toinvestors on project bankability. With a total budget of
EUR 900 million, the scheme expects to leverage more than
EUR 1.5 billion in private investments.

Auctions are also a powerful policy instrument, and they have been
critical in ramping up other clean energy technologies, such as solar
PV and wind energy. They are now about to be applied to hydrogen,with India’s New and Renewable Energy Minister announcing (inJune 2021) auctions for the production of hydrogen from renewables.
The Netherlands’ national strategy also mentions the potential use of
combined auctions for offshore wind and hydrogen production.
In Chile, the government is holding regular public and open tenders
to develop large-scale projects for producing hydrogen fromrenewable energy sources on public land. As these projects requirelarge land areas, facilitating access to public land with good
renewable resources can reduce investment risks and accelerate
deployment.

In its national hydrogen strategy, Germany’s federal government alsoannounced that it will launch a new Carbon Contracts for Difference(CCfD) pilot programme to support the use of hydrogen fromrenewable energy sources in the steel and chemical industries. This
programme will pay the difference between the CO2 abatement costsof the project and the CO2 price in the EU Emissions Trading Scheme(EU ETS). If the EU ETS price rises above the project’s CO2
abatement costs, companies will have to repay the difference to thegovernment. If the pilot is completed successfully, the scheme may
be expanded to other industry subsectors.

Along with its Hydrogen Strategy, the United Kingdom launched apublic consultation on a business model for low-carbon hydrogen withthe aim of defining specific policy instruments to help project
developers overcome costs barriers.

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4. Promote R&D, innovation, strategic demonstration projects and knowledge-sharing
Hydrogen innovation requires a boost

The future success of hydrogen will hinge on innovation. Today, lowcarbon hydrogen is more costly than unabated fossil fuel-basedhydrogen, which undermines its uptake. Multiple end-use
technologies at early stages of development cannot compete in open
markets, in part because they have not yet realised the economies ofscale that come with maturity. Governments play a key role in setting
the research agenda and adopting policy tools that can incentivise
the private sector to innovate and bring technologies to the market.

Programmes to foster hydrogen innovation are not yet flourishing,although some positive signals are emerging and several
governments have launched hydrogen-specific programmes to fundR&D in technologies across the entire hydrogen value chain.
However, current public R&D spending on hydrogen is below levels
dedicated in the early 2000s during the last wave of support forhydrogen technologies (see Chapter Investments and Innovation).
Further, integrated efforts will be required to avoid bottlenecks along
the value chain.

Selected active hydrogen R&D programmes
Country

Programme

Funding and duration
AUD 22 mln (~USD 15 mln) – 5 yr
AUD 68 mln (~USD 47 mln) – 5 yr

European
Union

ARENA’s R&D Programme
CSIRO Hydrogen Mission
Clean Hydrogen for
EuropeFrancePEPR Hydrogène

EUR 80 mln (~USD 91 mln) – 8 yr

Germany

National Innovation
Programme for Hydrogenand Fuel Cell Technology

EUR >250 mln (~USD 285 mln) – 10 yr

Australia

Japan
Spain
UnitedKingdom
UnitedStatesEUR 1 bln (~USD 1. bln) – 10 yr

Wasserstoff-Leitprojekte
NEDO innovation
programmes

EUR 700 mln (~USD 800 mln) – n.a.

Misiones CDTIEUR 105 mln (~USD 120 mln) – 3 yr

Low Carbon Hydrogen
SupplyH2@Scale
M2FCT – H2New Consortia
DOE Hydrogen Program

Government and industry co-operation is critical to ensure theimplementation of robust innovation programmes. With more than
EUR 1 billion in funding provided since 2008, the Fuel Cells andHydrogen Joint Undertaking (FCH JU) is a prime example of a publicprivate partnership to support R&D and technology demonstration.
Building on its success, the European Commission will launch the
Clean Hydrogen for Europe Joint Undertaking at the end of 2021, withmatching budgets of EUR 1 billion from public funding and private
investment until 2027.

JPY 699 bln (~USD 6.5 bln) – 10 yr

The European Commission also initiated the European Clean
Hydrogen Alliance in July 2021 to bring together industry, national
and local public authorities, civil society and other stakeholders to

GBP 93 mln (~USD 119 mln) – n.a.
USD 104 mln – 2 yr
USD 100 mln – 5 yr
USD 285 m/yr

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establish an investment agenda for hydrogen. Similarly, the Chilean
Energy Sustainability Agency introduced a Green Hydrogen
Incubator in 2021 to co-ordinate stakeholders and provide consulting
services to facilitate the development of technology demonstration
projects. In Morocco, stakeholders from the private sector, academia
and the government established the Green Hydrogen Cluster tosupport the emerging renewable hydrogen sector. In the UnitedStates, the Department of Energy (DOE) launched the First Energy
Earthshot dedicated to hydrogen, bringing together stakeholders withthe target of slashing the cost of clean hydrogen by 80% (toUSD 1.00/kg H2) by 2030.

MI took another step to boost R&D in hydrogen technologies, with thegoal of reducing end-to-end clean hydrogen costs to USD 2.00/kg by2030. MI also aims to establish at least 100 hydrogen valleys, to befeatured on the Hydrogen Valley Platform.
In addition to the several bilateral agreements signed between
governments in recent years, international co-operation agreements
have been established between governments and the private sector(the MOUs between the Port of Rotterdam and the governments ofChile and South Australia is one example). All have the short- to
medium-term objective of co-operating to share knowledge, bestpractices and technology development to reduce costs. They also
share the long-term aim of laying the foundations for futureinternational hydrogen supply chains to ensure the development oftrade in hydrogen and hydrogen-derived fuels.

International co-operation is growing rapidly
Multilateral initiatives and projects can promote knowledge-sharing
and the development of best practices to connect a wider group of
stakeholders. For instance, Mission Innovation (MI), which works tocatalyse R&D action and investment, has engaged with the FCH JU
through the Hydrogen Valley Platform to facilitate collaboration andknowledge-sharing within more than 30 hydrogen valleys across theglobe. With the launch of the Clean Hydrogen Mission in June 2021,

In June 2020, the energy ministers of the Pentalateral Forum(Austria, Belgium, France, Germany, Luxembourg, the Netherlands
and Switzerland) signed a joint political declaration affirming theircommitment to strengthen co-operation on hydrogen.

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Selected bilateral agreements between governments to co-operate on hydrogen development, 2019-2021
Countries

Objective

Germany - Australia

Formulate new initiatives to accelerate development of a hydrogen industry, including a hydrogen supply chain between the twocountries. Focus on technology research and identification of barriers.

Germany - Canada

Form a partnership to integrate renewable energy sources, technological innovation and co-operation, with a focus on hydrogen.

Germany - Chile

Strengthen co-operation in renewable hydrogen and identify viable projects.

Germany - Morocco

Develop clean hydrogen production, research projects and investments across the entire supply chain (two projects have alreadybeen announced by the Moroccan agencies MASEN and IRESEN).

Germany - Saudi Arabia

Co-operate on the production, processing and transport of hydrogen from renewable energy sources.

Morocco - Portugal

Examine opportunities and actions needed to develop hydrogen from renewable energy sources.

Netherlands - Chile

Establish a structured dialogue on the development of import-export corridors for green hydrogen, aligning investment agendas
and facilitating collaboration among private parties.

Netherlands - Portugal

Co-operate to advance the strategic value chain for producing and transporting renewables-based hydrogen, connecting thehydrogen plans of the two countries.

Japan – United Arab Emirates

Co-operate on technology development, regulatory frameworks and standards to create an international hydrogen supply chain.

Japan - Argentina

Strengthen collaboration on the use of clean fuels and promote investments to deploy large-scale hydrogen production fromrenewable energy sources.

Japan - Australia

Issue a joint statement highlighting the commitment already in place between the two countries and recognising the importance of
co-operation on an international hydrogen supply chain.

Singapore - New Zealand

Boost collaboration on establishing supply chains for low-carbon hydrogen and its derivatives, and strengthen joint R&D, networks
and partnerships.

Singapore - Chile

Foster co-operation on projects and initiatives to advance hydrogen deployment through information exchange and theestablishment of supply chains and partnerships.

Australia - Korea

Develop joint hydrogen co-operation projects with specific action plans.

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5. Harmonise standards and removing barriers
Two broad issues have emerged regarding regulations, codes andstandards for hydrogen deployment. The first is the need to review
national regulations that define the roles of utilities and grid operators.
At present, certain aspects of market structure warrant regulatory
frameworks that keep these entities separate. If hydrogen
deployment is successful, however, it can concurrently become an
integral part of the gas network and support electricity grid resilienceand reliability of the electricity grid. Hydrogen will thereby facilitate
sector coupling between electricity and gas utilities, creating a newrole requiring specific regulation.

Survey results indicated broad regulatory needs, particularly as
industry activity increases and expands beyond road transportation.
Critical within the infrastructure area is the establishment of a legal
framework for injecting hydrogen into natural gas systems (at both
the distribution and transmission levels) and requirements for the
scale-up and public use of liquid hydrogen in refuelling infrastructure.
Concerning transportation/mobility, the most critical priority is toenable the use of hydrogen in non-road transport modes – i.e. rail,
shipping and aviation. The survey also determined that safety(including maintenance requirements, approvals and inspections) isa priority and improvements should be incorporated into efforts toaddress the other needs identified.

The second issue is the need to ensure that a standardisation
framework based on national or international norms is in place and isappropriately applicable to the use of hydrogen and its carriers. This
ongoing process involves numerous international organisations.

To remove barriers to hydrogen adoption, some countries have taken
the first steps to adapt their regulations. For instance, in 2020 the
Chinese National Energy Administration released a draft of the new
Energy Law in which hydrogen is classified, for the first time, as anenergy carrier. This means hydrogen will now be a freely tradable
energy asset and its transportation will be subject to less stringent
requirements than for hazardous substances (its previous
classification).

Regulations need to be adapted to remove barriers in
the near term
The IPHE’s Regulations, Codes, Standards and Safety Working
Group conducted a Regulatory Gaps Compendium survey among its
participating countries to determine regulatory needs in critical areas
for hydrogen and fuel cell deployment. Participants provided input on
focal areas within two topics: hydrogen infrastructure and hydrogenfor mobility/transportation.

Other countries, including Chile, Colombia, Korea and France, havemodified their energy legislation to facilitate the adoption of hydrogen
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as an energy carrier. As tax regulations can also create significant
barriers to hydrogen technology endorsement, several countries are
exploring options to reduce this impact. The European Commission
recently proposed revision of the Energy Taxation Directive to avoid
double taxation of energy products, including hydrogen, andGermany announced that hydrogen produced from renewableelectricity will not be subject to the levy used to fund support for clean
power.

Such a mutually recognised, international framework will avoid
mislabelling or double-counting environmental impacts and should
provide consensus on an approach to “certificates of origin”. The
methodology is based on principles of inclusiveness (methodologies
should not exclude any potential primary energy), flexibility(approaches must allow for unique circumstances and hence
flexibility), transparency (methodologies must be transparent inapproach and assumptions to build confidence), comparability (theapproach should be comparable with those used for other energy
vectors), and practicality (methodologies must be practical,
facilitating uptake by industry and use in the market).

A low-carbon hydrogen market requires carbon
accounting standards
International hydrogen trade could become a cornerstone of theclean energy transition, enabling the export of low-carbon hydrogenfrom regions with abundant access to renewable energy or low-cost
production of hydrogen from fossil fuels with CCUS. To facilitate
trade, however, relevant standardisation bodies will need to developinternational standards – based on a common definition of lowcarbon hydrogen – to remove and/or reduce regulatory barriers.

The methodology also describes the requirements and evaluation
methods applied from “well to gate” for the most-used hydrogenproduction pathways: electrolysis, steam methane reforming with
CCUS, by-product and coal gasification with CCUS. Over time, theTask Force intends to develop other methods and to potentially apply
the approach to different physical states of hydrogen, diverse energy
carriers and emissions arising during transport to the end user. In
addition to IPHE activities, some countries (e.g. Australia, France andthe United Kingdom) have started to develop certification schemes
for hydrogen’s carbon footprint.

During the 32nd IPHE Steering Committee, countries recognised thatdeveloping internationally agreed accounting standards for different
sources of hydrogen along the supply chain will be vital to create amarket for low-carbon hydrogen. To this end, a Hydrogen Production
Analysis Task Force was established to review and reach consensus
on a methodology and analytical framework for determining GHG
emissions related to one unit of produced hydrogen.

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Policy trends

Global Hydrogen Review 2021

Research to develop evidence-based safety standards
During its recent bi-annual Workshop on Research Priorities for
Hydrogen Safety, the International Association for Hydrogen Safety(HySafe) mapped state-of-the-art and recent progress in prenormative research to support standards development, including
identifying and ranking pending research needs. Ultimately, researchneeds were identified for five key safety areas: liquid hydrogen use;the compatibility of certain materials (metals and plastics) withhydrogen; hydrogen leak detection; hydrogen phenomena modelling;and electrolysis safety for unsteady-state operations. Despite recent
progress, a significant lack of understanding regarding the accidental
behaviour of liquid hydrogen was identified as an outstanding
challenge. At the engineering level, major research gaps exist for thenon-road transport subsectors.

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Hydrogen demand

Global Hydrogen Review 2021

Hydrogen demand

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Hydrogen demand

Global Hydrogen Review 2021

Overview and outlook

PAGE | 42

Hydrogen demand
Global Hydrogen Review 2021

Hydrogen demand has grown strongly since 2000, particularly in refining and industry
Global hydrogen demand was around 90 Mt H2 4 in 2020, havinggrown 50% since the turn of the millennium. Almost all this demandcomes from refining and industrial uses. Annually, refineries
consume close to 40 Mt H2 as feedstock and reagents or as a sourceof energy.

emissions. Although this has accelerated the adoption of hydrogenfor new applications, demand in this area remains minuscule. Intransport, for example, annual hydrogen demand is less than 20 kt H2– just 0.02% of total hydrogen demand. As shown in the IEA’s
Net zero by 2050 roadmap, achieving government decarbonisation
goals will require a step change in the pace of rolling out hydrogentechnologies across many parts of the energy sector.

Demand is somewhat higher (more than 50 Mt H2) in the industry
sector, mainly for feedstock. Chemical production accounts foraround 45 Mt H2 of demand, with roughly three-quarters directed toammonia production and one-quarter to methanol. The remaining
5 Mt H2 is consumed in the direct reduced iron (DRI) process forsteelmaking. This distribution has remained almost unchanged since
2000, apart from a slight increase in demand for DRI production.

Mt H₂

Hydrogen demand by sector, 2000-2020
100

Others80

Iron and steel

60

The adoption of hydrogen for new applications has been slow, withuptake limited to the last decade, when fuel cell electric vehicle(FCEV) deployment started and pilot projects began to injecthydrogen into gas grids and use it for electricity generation. Positive
results from these experiences prompted the development of somehydrogen technologies to the point of commercialisation.

40

Chemicals

200

Refining
2000

2005

2010

2015

2020
IEA. All rights reserved.

In parallel, concerns about climate change have increased andgovernments and industry are making strong commitments to reduce

Note: “Others” refers to small volumes of demand in industrial applications, transport,
grid injection and electricity generation.

This includes more than 70 Mt H2 used as pure hydrogen and less than 20 Mt H2 mixed withcarbon-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 as a hydrogen
demand.

4

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Hydrogen demand

Global Hydrogen Review 2021

Government pledges suggest greater hydrogen use, but not nearly enough to the level neededto achieve net zero energy system emissions by 2050
Hydrogen demand by sector in the Announced Pledges and Net zero Emissions scenarios, 2020-2050

Net Zero Emissions by 2050

600

Mt H₂

Mt H₂

Announced Pledges Scenario
600

500

500

400

400

300

300

200

200

100

100

0

0

2020

2025

Refining

2030

2035

Industry

2040

2045

Transport

2050

2020

Power

NH₃ - fuel2025

Synfuels

2030

2035

Buildings

2040

2045

2050

Grid injection
IEA. All rights reserved.

Notes: “NH3 - fuel” refers to the use of hydrogen to produce ammonia for its use as a fuel. The use of hydrogen to produce ammonia as a feedstock in the chemical subsector is
included within industry demand.
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Hydrogen demand

Global Hydrogen Review 2021

Hydrogen-based fuel use must expand to meet ambitious climate and energy goals
The pathway to net zero emissions by 2050 requires substantiallywider hydrogen use in existing applications (e.g. the chemicalindustry) and a significant uptake of hydrogen and hydrogen-based
fuels for new uses in heavy industry, heavy-duty road transport,
shipping and aviation.

as ammonia, synthetic kerosene and synthetic methane. Ammonia
use expands beyond existing applications (primarily nitrogen
fertilisers) to be adopted for use as a fuel.
As ammonia has advantages over the direct use of hydrogen for
long-distance shipping, in the Net zero Emissions Scenario it meetsaround 45% of global shipping fuel demand. To reduce CO2

In the Net zero Emissions Scenario, hydrogen demand multiplies
almost sixfold to reach 530 Mt H2 by 2050, with half of this demandin industry and transport. In fact, industry demand nearly triples fromaround 50 Mt H2 in 2020 to around 140 Mt H2 in 2050. Transportdemand soars from less than 20 kt H2 to more than 100 Mt H2 in
2050, owing to the volumes that small shares of hydrogen canachieve in certain segments.

emissions in power generation, ammonia is also increasingly co‐
fired in existing coal plants, with some former coal-fired units being
fully retrofitted to use 100% ammonia to provide low-carbon
dispatchable power.
Synthetic fuels (synfuels) manufactured from hydrogen and CO2
captured from biomass applications (bioenergy‐fired power orPower sector penetration also increases significantly as hydrogen’s

biofuel production) or from the atmosphere (direct air capture [DAC])
are also used in energy applications in the Net zero Emissions
Scenario. Synthetic kerosene in particular meets around one‐third

use in gas‐fired power plants and stationary fuel cells helps tobalance increasing generation from variable renewables; integrate
larger shares of solar PV and wind; and provide seasonal energy
storage. Hydrogen use in buildings also increases, although its
penetration is very limited to certain situations in which other clean
and more efficient technologies cannot be adopted and/or it isneeded to increase electricity grid flexibility.

of global aviation fuel demand while synthetic methane meetsaround 10% of demand for grid gas use in buildings, industry andtransport.

By 2050, around one-third of hydrogen demand in the Net zero
Emissions Scenario is used to produce hydrogen‐based fuels such
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Hydrogen demand

Global Hydrogen Review 2021

synfuels in the Announced Pledges than in the Net zero Emissions
Scenario, and close to 70% less for ammonia production.

Overall, hydrogen and hydrogen‐based fuels meet 10% of global
final energy demand in 2050 .
5Furthermore, a slower rate of renewables deployment meanselectricity systems require less balancing of generation andseasonal storage in the Announced Pledges than in the Net zero
Emissions Scenario; as a result, hydrogen demand for electricity
generation in the Announced Pledges Scenario is about one-quarter
that of the Net zero Emissions.

Refining is the only application for which hydrogen demanddecreases in the Net zero Emissions Scenario – from close to
40 Mt H2 in 2020 to 10 Mt H2 in 2050: the reason is simply that theneed to refine oil drops sharply as clean fuels and technologies
replace oil-derived products.
Although recent government net zero commitments create
momentum for adopting hydrogen-based fuels across the energy
system, volumes are insufficient to achieve net zero emissions by
2050. While in the Announced Pledges Scenario hydrogen demandnearly triples to over 250 Mt H2 by 2050, this is less than half theamount modelled in the Net zero Emissions Scenario.

In the case of industry, as the largest single use of hydrogen is forfeedstock, demand growth is robust in both scenarios, although it is
30% less in the Announced Pledges than in the Net zero Emissions.

Demand in the Announced Pledges Scenario is lower in almost all
sectors, with refining being the exception as the rate of replacing oilbased fuels is lower. This strongly impacts hydrogen and hydrogenbased fuel uptake in transport applications, with hydrogen use intransport 55% lower in the Announced Pledges than in the Net zero
Emissions Scenario. The difference in demand for hydrogen to
produce hydrogen-based fuels is the largest, at 80% less for5This excludes onsite hydrogen production and use in the industry sector. Including on-sitehydrogen production in industry, hydrogen and hydrogen-based fuels meet 13% of global final
energy demand by 2050 in the NZE.

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Hydrogen demand

Global Hydrogen Review 2021

The next decade will be decisive in for laying the foundation for hydrogen’s role in the clean
energy transition
Increasing the use of hydrogen as a new energy vector is a long-term
endeavour, as it can take decades for a new fuel to significantly
penetrate the energy mix. Immediate action is therefore required tofacilitate the scaling-up process and create the conditions needed by2030 to ensure that hydrogen technologies can be widely diffused tosecure their long-term usefulness in the clean energy transition.

to support implementation, including strong demand-side measuresthat create clearly identifiable markets.

Mt H₂

Hydrogen demand in the Projects case, Announced Pledges andNet zero Emissions scenarios, 2030

Despite recent strong momentum, projects currently underdevelopment indicate that anticipated hydrogen technology
deployment in demand sectors does not yet align with the Net zero
Emissions Scenario’s ambitions. Present government focus on
decarbonising hydrogen production is stronger than on stimulating
demand for new applications. Apart from notable exceptions for
deploying different vehicle types of FCEVs in China, Korea, Japanand some EU countries, few government targets seek to accelerate
the adoption of hydrogen-based fuels in end-use sectors.

250

5%

200

4%

Grid injection
Buildings
SynfuelMoreover, current country ambitions to stimulate hydrogen use for
new applications is not sufficient to meet their net zero pledges.
Using target-setting on its own as a long-term signal is not effective
enough to create the market dynamics needed to unlock private
sector investments and stimulate deployment of hydrogentechnologies. Targets need to be accompanied by concrete policies

150

3%

100

2%

50

1%

0

0%

Projects

APS

NZE

NH₃ - fuelPower
Transport
Industry
Refining
Share TFC (right axis)

IEA. All rights reserved.
Notes: APS = Announced Pledges Scenario. NZE = Net zero Emissions Scenario. TFC= total final energy consumption. “Share TFC” excludes on-site hydrogen production
and use in the industry sector. Including it, hydrogen and hydrogen-based fuels meetless than 2% of total final energy consumption today, 2% in the APS and 4% in the
NZE by 2030. “NH3 fuel” refers to the use of hydrogen to produce ammonia for its use
as a fuel.

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Hydrogen demand

Global Hydrogen Review 2021

Governments need to act quickly and decisively from now until 2030
to trigger this transformation. Implementing quotas or mandates toinject hydrogen into the gas grid can create dependable hydrogen
demand in this early deployment phase, which can help building up
new low-carbon hydrogen production capacity while governments
decide, plan and develop hydrogen-specific infrastructure. Once
new infrastructure is ready, low-carbon hydrogen production
capacity developed in the early deployment phase can migrate fromthe natural gas grid to supply hydrogen directly to end users in new
applications, several of which should be demonstrated and scaled
up in upcoming years.

adoption of hydrogen fuel cells for light-duty vehicles (LDVs) andbuses could boost hydrogen and fuel cell demand as well as
infrastructure expansion, ultimately reducing the cost of fuel cell
trucks and encouraging their adoption.
Similarly, demonstrating hydrogen and ammonia as fuels forshipping, setting quotas for synfuels in aviation, and deploying thecorresponding refuelling infrastructure at ports and airports would
support hydrogen and hydrogen-based fuel uptake in these sectors
in which emissions are hard to abate.
Demonstration of specific end-use technologies, such as hydrogenbased DRI in steelmaking or high-temperature heating applications,will be critical to unleash significant demand growth in industry. In
buildings, all sales of natural gas equipment (when it is preferredover electric heat pumps) should be compatible with hydrogen to
allow eventual switching. Demonstration and pilot projects for fuelcells and other hydrogen equipment for domestic applications areneeded to raise consumer confidence in hydrogen technologies’
operational safety and reduce financial risk.

Adopting hydrogen in transport will require support to deploy FCEVs
and fuelling infrastructure. In particular, early demonstration andscaled-up hydrogen use in heavy-duty trucks, for operations inwhich hydrogen may have advantages over battery electric
powertrains (e.g. for certain long-haul operations 6), and theinstallation of high-throughput, high-pressure refuelling stations
along key road freight corridors are important foundations forhydrogen use in road transport.

In the power sector, gas turbine manufacturers are confident they
can provide gas turbines that run on pure hydrogen by 2030. To
incentivise the use of low-carbon hydrogen to reduce emissions
from existing gas-fired plants and provide electricity system

While BEVs are expected to dominate the transition to net zero
emissions in light-duty road transport owing to their higher efficiency
and lower total cost of ownership (TCO), support for near-term

For a comparison of distance-based total cost of ownership (TCO) see Figure 5.7 of Energy
Technology Perspectives 2020.
6

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Hydrogen demand

Global Hydrogen Review 2021

flexibility, strong government support and measures will be needed
to close the cost gap between natural gas and low-carbon hydrogen.
Co-firing of ammonia in coal-fired power plants has beensuccessfully demonstrated at low co-firing shares, but more RD&D
is needed in using pure ammonia directly as fuel in steam or gas
turbines.

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Hydrogen demand

Global Hydrogen Review 2021

Refining

PAGE | 50

Hydrogen demand

Global Hydrogen Review 2021

Hydrogen demand in refining declines as climate ambitions increase, but synfuels offer newopportunities
Hydrogen demand in refining and synthetic fuels production in
the Announced Pledges and Net zero Emissions scenarios,
2020-2050

Refining
Mt H₂

Mt H₂

100
80

100

60

40

40

20

20
0
2020 2030 2050 2030 2050
APS

NZE

Synfuels

80

60

0

Around-half of refining demand is met with by-product hydrogen fromother processes in the refinery (e.g. catalytic naphtha reforming) orfrom other petrochemical processes integrated into certain refineries(e.g. steam crackers). The remainder is met by dedicated on-site
production or merchant hydrogen sourced externally. The majority of
on-site production is based on natural gas reforming, with some
exceptions such as the use of coal gasification, which makes up
almost 20% of dedicated hydrogen production at refineries in China.
In 2020, hydrogen production to meet refining demand was
responsible for close to 200 Mt CO2 emissions. However, someongoing efforts to reduce these emissions are already operative: six
plants with facilities retrofitted with CO2 capture and two others using
electrolysers to produce hydrogen. At least another 30 projects areunder development to retrofit current fossil-based hydrogenproduction with CCUS; develop new capacities based on advanced
reforming technologies coupled with CCUS; or deploy electrolysis
capacities. In the short term, refineries can offer anchor demand forthe development of low-carbon hydrogen supplies.

2020 2030 2050 2030 2050
APS

NZE

IEA. All rights reserved.
Notes: APS = Announced Pledges Scenario. NZE = Net zero Emissions Scenario.

Oil refining was the single largest consumer of hydrogen in 2020(close to 40 Mt H2). Refineries use hydrogen to remove impurities(especially sulphur) and to upgrade heavy oil fractions into lighter
products. China is the largest consumer of hydrogen for refining(close to 9 Mt H2/yr), followed by the United States (more than
7 Mt H2/yr) and the Middle East (close to 4 Mt H2/yr). Together, thesethree regions account for more than half of global demand.

Oil refining is the only sector that shows declining hydrogen demandin the Announced Pledges and Net zero Emissions scenarios. As
climate ambitions increase, oil refining activity declines more sharply

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Hydrogen demand

Global Hydrogen Review 2021

as oil demand declines, especially after 2030. In the Announced
Pledges Scenario, hydrogen demand increases to more than
40 Mt H2 to then drop to around 30 Mt H2 in 2050. The Net zero
Emissions shows 25 Mt H2 in 2030 and 10 Mt H2 in 2050. Dropping
oil demand will create a dilemma for refinery operators, as investingin decarbonising current hydrogen production can be difficult to justify
if falling demand entails the risk of stranded assets.

in applications for which direct electrification is challenging.
Refineries can also use established supply chains to deliver synfuels
to end users, serving today’s users of oil-derived fuels. Convertinghydrogen into synfuels is very costly, however, which could be a
primary impediment to their widespread use (see Chapter Hydrogen
supply). The expertise and skills of refinery operators will be criticalto develop innovative, efficient and cost-effective solutions.

However, the emergence of new sources of hydrogen demand could
bolster the business case for such investments by offering theopportunity to supply developing hydrogen markets and meetdemand in new sectors (e.g. transport, other industry applications
and electricity generation), such as those covered in the Announced
Pledges and the Net zero Emissions scenarios. Using low-carbonhydrogen could be an option to decarbonise high-temperature-heat
operations in refineries, helping meet the net zero targets of oil andgas companies. Producing low-carbon synthetic hydrocarbon fuels(synfuels) is another significant opportunity. Synfuels are “drop-in”
fuels, meaning they can directly replace fuels that are currently oilderived and make use of existing distribution infrastructure and enduse technologies without modifications.

By 2030 in the Announced Pledges Scenario, hydrogen demand for
synfuels reaches 1 Mt H2. By 2050, it climbs to over 15 Mt H2, morethan making up for the more than 5 Mt H2 drop in refining demand. In
the Net zero Emissions Scenario, hydrogen demand for synfuels
climbs to more than 7 Mt H2 by 2030, compensating for nearly twothirds of the more than 10-Mt H2 drop in refining demand. By 2050, it
reaches close to 100 Mt H2, not only replacing the 26 Mt H2 drop in
refining demand but more than doubling current demand – andrepresenting a significant investment opportunity.
If all projects currently in the pipeline materialise (including thosealready operational; under construction; having reached final
investment decision; and undergoing feasibility studies), around0.25 Mt H2 7 could be used in synfuel production by 2030, meeting
one-fifth of Announced Pledges Scenario requirements but just 3%of the Net zero Emissions Scenario’s.

Demand for such fuels grows in both the Announced Pledges andNet zero Emissions scenarios as they replace incumbent fossil fuels

7This could increase to 0.5 Mt H2 if projects at very early stages of development are included (aco-operation agreement among stakeholders has just been announced).

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Hydrogen demand

Global Hydrogen Review 2021

Selected projects operative and under development to decarbonise hydrogen production in refining
Status

Project

LocationStart-up dateTechnology

Size

Horizon Oil Sands

Canada2009

Oil + CCUS

438 kt CO2/yr

Port Arthur *

US

2013

Natural gas + CCUS

Port Jerome *France2015

Natural gas + CCUS

100 kt CO2/yr – 39 kt H2/yr

Quest
H&R Ölwerke HamburgNeuhof
North West Sturgeon refinery

Canada2015

Natural gas + CCUS

1 000 kt CO2/yr – 300 kt H2/yr

2018Electrolysis (PEM)

5 MW

Operational

Germany
CanadaPernis refinery (gasification)

Netherlands

Refhyne (2 phases)

Germany

HySynergy (3 phases)

Denmark

Multiphly

Netherlands

Prince George refinery

CanadaOMV Schwechat Refinery

Austria

Westkuste 100 (2 phases)

Germany

H24AllGela biorefinery

CCU project – Operational
CCUS project – Feasibility studies
Phase 1 – Operational
Phase 2 – Feasibility studies
Phase 1 – Under construction
Phases 2/3 – Feasibility studies
Under construction

2020
2005
2024
2021
2025
2022
2025-30

Bitumen gasification + CCUS
Heavy residue gasification with CCU(CCUS from 2024)
Electrolysis (PEM)
Electrolysis (PEM)

900 kt CO2/yr – 118 kt H2/yr

1 200 kt CO2/yr
400 kt CO2/yr – 1 000 kt H2/yr
1 000 kt CO2/yr – 1 000 kt H2/yr
10 MW
100 MW
20 MW
300 MW / 1 000 MW

2022

Electrolysis (SOEC)

2023

Electrolysis (Unknown)

2023

Electrolysis (PEM)

10 MW

2023-28

Electrolysis (Alkaline)

30 MW / 300 MW

Spain

2025

Electrolysis (Alkaline)

100 MW

Italy

2023

Electrolysis (PEM)

20 MW

Taranto Sustainable refinery

Italy

2023

Electrolysis (PEM)

10 MW

Castellon refinery

Spain

2023

Electrolysis (Unknown)

20 MW

Pernis refinery (electrolysis)

Netherlands

2023

Electrolysis (Unknown)

200 MW

Saras Sardinia refinery

Italy

2024

Electrolysis (Unknown)

20 MW

Stanlow refinery

United Kingdom

2025

Natural gas + CCUS

90 kt H2/yr

H2.50

Netherlands

2025Electrolysis (Unknown)

250 MW

Preem CCS

Sweden2025

Natural gas + CCUS

500 kt CO2/yr

Grupa Lotos refinery

Poland2025

Electrolysis (Unknown)

100 MW

Zeeland refinery

Netherlands

Electrolysis (Unknown)

Lingen refinery (2 phases)

Germany

Deltaurus 1 (2 phases)

Netherlands

2026
2024
n.a.
2024
n.a.

150 MW
50 MW
500 MW
150 MW
1 000 MW

FID
Phase 1 – FID
Phase 2 – Feasibility studies

Feasibility studies

Phase 1 – Feasibility studies
Phase 2 – Early stages

Electrolysis (Unknown)
Electrolysis (Unknown)* These plants produce merchant hydrogen to supply refineries.
Notes: Size expressed in captured CO2 for projects using CCUS and in electrolysis installed capacity for projects using electrolysis.
PAGE | 53

2.6 MWn.a.

Hydrogen demand

Global Hydrogen Review 2021

Industry

PAGE | 54

Hydrogen demand

Global Hydrogen Review 2021

Hydrogen technologies are key to industry decarbonisation
Accounting for 38% of total final energy demand, industry is thelargest end-use sector and accounts for 26% of global energy system
CO2 emissions. Across industry, 6% of total energy demand is used
to produce hydrogen, which serves primarily as a feedstock forchemical production and a reducing agent in iron and steel
manufacturing. Industry demand for hydrogen is 51 Mt annually.

however it is produced. The pursuit of net zero goals for energy
systems will drive changes in supply for current uses and initiate newuses, impacting existing assets. Industrial hydrogen demand in the
Announced Pledges Scenario therefore rises to 65 Mt by 2030, a
30% increase over current figures, with new uses accounting for 5%.
By 2050, demand doubles from today, with the share of new uses
rising to 26%.

Hydrogen demand in industry, 2020

IEA. All rights reserved.

In the context of clean energy transitions, a major shift to low-carbonhydrogen – produced via electrolysis or through the continued use offossil fuel technologies equipped with CCUS – displaces current
reliance on fossil fuels in hydrogen production. In 2020, industry
produced 0.3 Mt of low-carbon hydrogen, mostly through a handful oflarge-scale CCUS projects, small electrolysis projects in the chemical
subsector, and one CCUS project in the iron and steel subsector. By
2030 in the Announced Pledges Scenario, low-carbon hydrogenconsumption in industry reaches 7 Mt H2, growing by a factor ofalmost 25 to make up 10% of total industry hydrogen demand.

Economic development and population growth will require greater
output from the key industry sectors that currently use hydrogen,However, analysis of the current pipeline of low-carbon hydrogenprojects suggests that around 55% of global demand projected in the
Announced Pledges Scenario in 2030 will be met. 8 CCUS-equipped

DRI
10%

Other industrial uses
<1%

Methanol25%

Ammonia65%

Note: DRI = direct reduced iron.

8This could increase to almost 70% if projects at very early stages of development are included (aco-operation agreement among stakeholders has just been announced).

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Hydrogen demand

Global Hydrogen Review 2021

Chemicals

projects producing low-carbon hydrogen are close to projected
deployment: with the current CCUS pipeline expected to produce
1.0 Mt of low-carbon hydrogen, they fall just 7% short of theAnnounced Pledges Scenario’s demand of 1.1 Mt H2. In sharp
contrast, electrolytic hydrogen – a key source of low-carbon hydrogenneeded to reach climate goals in industry – lags far behind.
Announced electrolytic projects expected to be operational by 2030
account for only one-third of required demand in the Announced
Pledges Scenario (close to 6 Mt H2).

With demand of 46 Mt H2 in 2020, ammonia and methanol production– together with other smaller-scale chemical processes – account for
the vast majority of industrial use of hydrogen.
Ammonia, predominantly used to produce nitrogen fertilisers,
accounts for 2% of global final energy demand and around 1% ofenergy-related and process CO2 emissions from the energy sector.
Aside from fertiliser 9 applications (70% of total demand), ammonia isused for industrial applications in explosives, synthetic fibres andother specialty materials. As producing 1 tonne of ammonia requires
180 kg of hydrogen, total production of 185 Mt in 2020 required
33 Mt H2 as feedstock, i.e. 65% of total industry hydrogen demand.

Reaching net zero emissions by 2050 requires even higher hydrogen
deployment. Relative to the Announced Pledges Scenario, Net zero
Emissions shows total hydrogen demand from industry 11% higher
in 2030 and 32% higher in 2050 – almost three times greater thancurrent demand. Low-carbon hydrogen plays an even larger role,amounting to 21 Mt H2 by 2030 (more than three times higher than in
the Announced Pledges Scenario). As early as 2030, electrolytichydrogen consumption is almost triple that of the Announced Pledges
Scenario while CCUS-equipped production is more than five times
higher.

Methanol production is the second-largest consumer of hydrogen inindustry, requiring 130 kg H2/t produced commercially from fossil
fuels. Its largest-volume derivative is formaldehyde, but several fuelapplications, either directly or after conversion, are also important(e.g. methyl-tert-butyl ether). The 100 Mt of methanol produced
globally accounts for 28% of hydrogen demand in the chemical
subsector and one-quarter of total industry hydrogen demand. In
China, methanol serves as an intermediate in the production of
olefins (key chemical precursors for making plastics) from coal, an

9Specific decarbonisation opportunities for this subsector are explored in the IEA’s forthcoming
Nitrogen Fertiliser Technology Roadmap.

PAGE | 56

Hydrogen demand

Global Hydrogen Review 2021

alternative to conventional oil-based routes. Producing methanol
generates, on average, 2.2 t CO2 per tonne of end product.

established; similar projects are also operational in Canada andChina. Based on the size of the capture installation and assumptions
on capture rate and the energy intensity of the process, in aggregate
these projects produce around 0.2 Mt of low-carbon hydrogenannually for ammonia production.

Demand for hydrogen in the chemical subsector is expected to grow,particularly because of rising demand for ammonia and methanol. In
the Announced Pledges Scenario, it increases nearly 25% by 2030
and close to 50% by 2050. As current methods to produce bothchemicals require hydrogen (irrespective of how it is generated), by
2050 total hydrogen demand from chemicals is roughly the same in
the Net zero Emissions Scenario.

Using electrolytic hydrogen for ammonia production, particularly withvariable renewable electricity, is at an early stage of development.
Nevertheless, several demonstration projects (1-4 kt H2/yr) are
advancing quickly, including a project by Fertiberia and Iberdrola(Spain) to blend hydrogen produced by solar PV-powered
electrolysis, expected to become operational at the end of 2021; a
CF Industries electrolyser project (United States); the Western
Jutland Green ammonia project (Denmark); and green fertiliser
projects with Yara (in the Netherlands, Norway and Australia). In
addition, some recently announced projects – extensions of the
Fertiberia and Iberdrola partnership, Australian projects in Dyno
Nobel’s Moranbah plant, and the Origin Energy development in
Tasmania’s Bell Bay – are aiming to scale up this concept to30-140 kt H2/yr.

New demand comes mostly from new applications in which hydrogen
displaces fossil fuels for generating the high-temperature heatrequired for producing chemicals. Thus, converting to low-carbonhydrogen, rather than expanding the use of hydrogen, is the main
challenge for the chemical subsector. Opportunities to obtain lowcost, low-carbon hydrogen may spark chemical production in new
regions that have access to low-cost renewable electricity but not
fossil fuels.
CO2 capture is already a mature process technology in specificchemical industry applications. During ammonia production, core
process equipment separates CO2 from hydrogen, and the CO2 isthen used for industrial-scale urea production (note: this leaves asignificant portion of generated emissions unabated).

For methanol production, most projects currently sourcing low-carbonhydrogen are related to electrolytic hydrogen. Volumes are very small
to date, with pilot plants operating at 1 MW in Germany and 0.25 MW
in Denmark, for example. Together with pre-commercial plants in
Iceland and China, electrolytic hydrogen amounts to about 2 kt/yr of
low-carbon hydrogen. Several projects aiming to demonstrate theIn the United States, the practice of using CO2 captured fromammonia production for enhanced oil recovery (EOR) is well
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Hydrogen demand

Global Hydrogen Review 2021

use of electrolytic hydrogen for methanol production at scales in therange of 1-10 kt H2/yr include e-Thor and Djewels (the Netherlands),
North-C-Methanol (Belgium), and LiquidWind (Sweden).

Producing chemical products without carbon fuels could also create
opportunities to find new sources of carbon, including CCUS and
DAC. Overall, the chemical subsector’s project pipeline represents
only 2.3 Mt of low-carbon hydrogen through 2030, 10 short of targetsof 4 Mt in the Announced Pledges Scenario and 7 Mt in Net zero
Emissions. Clearly, a redoubling of efforts is required over the nextten years.

Although only small projects capturing CO2 emissions from methanol
production are operating, projects currently under development areabout to grow in size. Two demonstration projects capturing CO2 for
EOR are under way in China, another is to start in the United Statesin 2025, and one is under consideration for Canada by 2025.
Together, they can add more than 0.3 Mt/yr of low-carbon hydrogen.

Iron and steel
The iron and steel subsector accounts for 10% of industry hydrogen
demand, stemming specifically from use in the DRI-EAF steelmaking
process route, which accounts for 7% of total crude steel production
globally. In the DRI process, hydrogen is produced as a componentof a synthesis gas, which together with carbon monoxide reduces ironore to sponge iron. The synthetic gas is a mixture of carbon monoxideand hydrogen, depending on the energy source used in DRI
production. On average, around 40 kg H2 is needed per tonne ofsponge iron. The traditional DRI mixture can contain 0-70%
hydrogen.

New applications in chemicals include the use of hydrogen for
producing high-value chemicals (via either methanol or synfuel usedin steam crackers) or for providing high-temperature process heat indownstream chemical production. By 2030, such uses trigger
additional low-carbon hydrogen demand of 1.0 Mt in the Announced
Pledges Scenario and 2.1 Mt in the Net zero Emissions.
While hydrogen demand per tonne of ammonia and methanol is
expected to remain stable, rising demand for chemical products,
along with the possibility of sourcing hydrogen from renewableelectricity and of using additional hydrogen for heat to produce otherchemicals in addition to ammonia and methanol, could revolutionise
the sector.

10

The most common steel production route today (the integrated route,a sequence of blast and basic oxygen furnaces) does not requirehydrogen as an input, as it uses carbon monoxide-rich gases for

3.1 Mt H2 if projects at very early stages of development are included
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Hydrogen demand

Global Hydrogen Review 2021

iron ore reduction. However, a small amount of hydrogen is still
generated within the blast furnace as an intermediate and as a byproduct in the process off-gases.

Hydrogen can also be used to generate heat for ancillary units,
including rolling and other finishing processes, despite being lessattractive than induction technology. By 2030, these new uses
amount to 2 Mt H2 or 17% of hydrogen use in iron and steel in the
Announced Pledges Scenario and 9 Mt H2 in Net zero Emissions.
Most of these uses of hydrogen are still at pilot or demonstration
scale; to meet deployment levels outlined in the Announced Pledges
and Net zero Emissions scenarios, rapid action is needed in the next
five years for their full commercialisation.

As a result of announced policies and projects as well as increased
steel production through the DRI-EAF process, hydrogen demand
from iron and steel almost doubles by 2030 in the Announced
Pledges Scenario and increases more than fivefold by 2050. In sharp
contrast to small differences in scenario projections in the chemical
subsector, Net zero Emissions shows hydrogen demand from ironand steel 85% higher than in the Announced Pledges Scenario by
2030 and 70% higher by 2050. New uses for hydrogen form a key
decarbonisation strategy for the iron and steel subsector; in turn, highdecarbonisation ambition will spur required levels of deployment.

Projects in the pipeline amount to 0.5 Mt 11 of low-carbon hydrogenuse. These include the longest-standing low-carbon hydrogen project– a DRI plant equipped with CCUS in United Arab Emirates, which
captures CO2 for use in nearby EOR. In Germany, the Carbon2Chem
project uses CO2 captured from blast furnace gas for methanol
production; using some of the carbon entering the blast furnace twice
lowers emissions overall relative to a counterfactual in whichmethanol is produced from fossil fuels (by far, the most widespreadpractice today). Opportunities to convert gases arising from iron andsteelmaking into other chemicals are also under development.

Multiple new applications present novel opportunities for the future ofhydrogen in iron and steel production, with potential volumes ofdemand in a hydrogen-based DRI-EAF route being the mostimportant. While commercial-scale production for 100% hydrogenbased DRI is not expected until the early 2030s, this route opens anavenue for extensive hydrogen use in the sector. Blending purehydrogen in DRI and blast furnaces to substitute for a portion of coaland gas, as is currently being trialled, is an incremental step towards
the near zero emissions production of crude steel.

11

Multiple EU projects are also trialling hydrogen injection into DRI andblast furnaces. The SALCOS (Germany) and H2FUTURE (Austria)
projects are operating trials that substitute electrolytic hydrogen to
reduce natural gas consumption, amounting together to over

0.8 Mt H2 if projects at very early stages of development are included.
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Hydrogen demand

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1 kt H2/yr. Thyssenkrupp has successfully trialled the substitution ofcoal by hydrogen in one tuyere of one of its blast furnaces in Germany
and is currently testing higher blending rates. ArcelorMittal (Spain)
has also committed to build a DRI unit using hydrogen produced
directly from renewable sources.
Aside from blending hydrogen in existing DRI and blast furnaces,high blending shares (up to 100%) in hydrogen-based DRI facilities
offer an opportunity to produce steel with very limited use of fossil
fuels. As early as the 1990s, a 0.5 Mt full hydrogen-based plant was
already operational in Trinidad and Tobago (it is no longer active).
The HYBRIT project, developed by SSAB, LKAB and Vattenfall –which will produce sponge iron using 100% hydrogen in combination
with biomass – is working towards transitioning from a pilot to largescale (~1 Mt of DRI) operation by 2025 in Sweden. In June 2021,
Volvo Cars signed a collaboration agreement with SSAB to be an offtaker of the fossil-free steel produced in this project.

.

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Hydrogen demand

Global Hydrogen Review 2021

Low-carbon hydrogen use, 2030, and total hydrogen demand in industry in the Projects case, Announced Pledges and Net zero
Emissions scenarios, 2020-2050
Total hydrogen demand

25

Mt H2

Mt H2

Low-carbon hydrogen production and use

20

160
120

15

80

10

40

5
0

0
Projects

Early stages
Iron and steel

APS 2030

MethanolOther

NZE 2030

2020 2030 2050 2030 2050 2030 2050
Projects

New uses:
Chemicals
Existing uses:
Chemicals

Ammonia

APS

NZE

Iron and steel

Other

Iron and steel

Other
IEA. All rights reserved.

Notes: APS = Announced Pledges Scenario. NZE = Net zero Emissions Scenario. Other applications include hydrogen use for ceramics production, nickel refining and industrial
heating.
Source: IEA (2021), Hydrogen Projects Database.

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Hydrogen demand

Global Hydrogen Review 2021

Selected projects that can increase the use of low-carbon hydrogen in industry
Project

Location

StatusStart-up
dateTechnology

Size

Ammonia
Coffeyville fertiliser

United States

PCS Nitrogen

United States

2013

CO2 capture from oil-based ammonia production; used for EOR

1 Mt CO2/yr

2013

CO2 capture from gas-based ammonia production; used for EOR

0.7 Mt CO2/yr

Nutrien fertiliser

CanadaOlive Creek

United States

Under construction

2020

CO2 capture from gas-based ammonia production; used for EOR

0.3 Mt CO2/yr

2021

Ammonia production via methane pyrolysis

Fertiberia/Iberdrola

Spain

Phase 1 –Under construction
Phases 2-4 –Feasibility studies

n.a.

Phase 1 –2021
Phases 2-4– 2027

Hydrogen production from solar PV for ammonia production

Phase 1 –20 MW
Phases 2-4 –810 MW

Western Jutland Green ammonia

Denmark

2023

Electrolytic ammonia production from renewables

10 MW

CF industries

United States

Green fertiliser project Porsgrunn

Norway2023

Electrolytic ammonia production using electricity from the grid

20 MW

2023

Electrolytic ammonia production using electricity from the grid

Up to 25 MW

Engie - Yara Pilbara

Australia

2023

Electrolytic ammonia production from renewables

10 MW

HyEx

Chile

2024

Electrolytic ammonia production form solar PV

50 MW

Yara Sluiskil

Netherlands

2025Electrolytic ammonia production from renewables

100 MW

Barents blue ammonia

Norway2025

CO2 capture and stored from gas-based ammonia production

1 Mt NH3/yr

Esbjerg green ammonia

Denmark

2027

Electrolytic ammonia production from offshore wind

1 GW

CF Fertilisers Ince

United Kingdom

n.a.

CO2 capture and stored from gas-based ammonia production

0.3 Mt CO2/yr

Operational

FID

Feasibility studies

MethanolCommercial Plant Svartsengi

Iceland2011

Electrolytic methanol production from dedicated renewables

6 MW

Karamay Dunhua Oil Technology
CCUS EOR

China

2015

CO2 capture and stored from methanol production; used for EOR

0.1 Mt CO2/yr

MEFCO2Germany

2019

Electrolytic methanol production

1 MW

Power2Met

Denmark

2020

Electrolytic methanol production

0.25 MW

Fine Chemical Industry Park ofLanzhou

China

2020

Electrolytic methanol production from dedicated renewables

4.5 MW

Green lab skive

Denmark

2022

Electrolytic methanol production from dedicated renewables

12 MW

DJEWELS Chemiepark

Netherlands

2022Electrolytic methanol production from dedicated renewables

20 MW

2025

Production of hydrogen and methanol from petcoke gasification with
CCUS

4.2 Mt CO2/yr

Lake Charles Methanol

United States

Operational

Under construction
Feasibility studies

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Hydrogen demand

Global Hydrogen Review 2021

Start-up
dateTechnology

2024
2028

Electrolytic methanol production from dedicated renewables

Phase 1 –63 MW
Phase 2 –300 MW

2023
n.a.

Electrolytic methanol production from dedicated renewables

10 MW
100MW

2016

CCUS plant applied on DRI; captured CO2 used for EOR

0.8 Mt CO2/yr

2018

Use of blast furnace gases for methanol production

2 MW

2019

Feeding hydrogen via the coke gas pipeline into resource-optimised
blast furnaces

6 MW

Germany

2020

Use of waste heat from integrated steelworks for H2 production

0.72 MWGermany

2021

Blending of hydrogen into natural gas-based DRI

2.5 MW

Phase 1 –2021
Phase 2 –2025

100% hydrogen-based steelmaking currently operating at pilot scale;plan to move to demonstration plant by 2025

Phase 1 –4.5 MW
Phase 2 – n.a.

2022
2025

Hydrogen injection into blast furnaces

100 MW
400 MW

2025

Use of hydrogen produced from solar PV electrolysis in DRI

n.a.

Project

Location

StatusNorth-C-Methanol

Belgium

Power-to-Methanol

BelgiumPhase 1 – Feasibility
studies
Phase 2 – Early
stagesAl Reyadah CCUS

United ArabEmirates

Carbon2Chem

Germany

H2FUTURE

Austria

GrInHy2.0
SALCOS

Size

Iron and steel

Operational

Phase 1 –Operational
Phase 2 –Under construction

HYBRIT

SwedenThyssenkrupp steel plant

Germany

ArcelorMittal

Spain

H2 Green Steel

Sweden2030

100% hydrogen-based steelmaking using dedicated renewables

1.5 GW

HBIS

China

n.a.

Using high levels of hydrogen together with coke oven gas in DRI

n.a.

Early stages

Other applications
Sun Metals Zinc Refinery

Australia

BHP Nickel West Green Hydrogen

Australia

ORANGE.BAT Castellon

Spain

Grange Resources Renewable
HydrogenAustralia

GREENH2KER

Spain

FID

Early stages

2022

Replacement of natural gas in zinc refinery process

1 MW

2023

Use of electrolytic hydrogen for nickel refining

10 MW

2024

Use of green hydrogen for ceramic production

100 MWn.a.

Use of hydrogen to replace natural gas for industrial heating inpelletising facilities

100 MWn.a.

Use of green hydrogen for ceramic productionn.a.

Source: IEA (2021), Hydrogen Projects Database.

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Hydrogen demand

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Regional insights for hydrogen in industry
The Asia-Pacific region currently accounts for half of global industrialhydrogen demand, with China alone taking a major portion (17 Mt H2)for ammonia and methanol production. India is the region’s secondhighest consumer (4 Mt H2) for coal-based DRI and ammonia andmethanol production. This region remains the front runner in 2030 in
the Announced Pledges Scenario, with total demand reaching
32 Mt H2, used to produce 65 Mt of steel (through fossil andhydrogen-based DRI), 95 Mt of ammonia and 80 Mt of methanol.
With growth across all sectors, China accounts for almost two-thirds
of Announced Pledges Scenario hydrogen demand. Demand in India
rises by 50%, driven mainly by the iron and steel subsector. In theabsence of a stated net zero target, growth in India (in the Announced
Pledges Scenario) comes largely from coal-based DRI production.

as that of maturing developing regions – which require materials tobuild their infrastructure – increases.
Central and South America show the largest relative growth to 2030:
from a low starting point of 2.3 Mt H2, expanding ammonia andmethanol production and rising steel output via DRI-EAF routes boosthydrogen demand by 60%.

Hydrogen demand in industry by sector and region in the
Announced Pledges Scenario, 2020-2030

The Middle East is the second-highest hydrogen-consuming region(7 Mt H2 in 2020), mainly for ammonia and methanol production. By
2030, demand in the Announced Pledges Scenario rises to 9 Mt,
prompted by increased chemical production.

10

48

8

36

6

24

4

12

2

0

2020

APS 2030

Middle East
Central and South America
Other Asia-Pacific
China

Hydrogen consumption remains largely stable in North America,
Europe and Eurasia, each rising from 4-5 Mt H2 currently to around6 Mt H2 by 2030 in the Announced Pledges Scenario, mainly due toincreased demand from the iron and steel subsector. This is basedon the assumption of developed countries maintaining current
production levels, even though their share in global output declines

Hydrogen in iron and steel
Mt H2

Mt H2

Hydrogen in chemicals
60

AfricaEurasia
Japan

0

2020

APS 2030
North America
EuropeIndia

IEA. All rights reserved.
Note: APS = Announced Pledges Scenario.

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Hydrogen demand

Global Hydrogen Review 2021

Cost considerations

These electricity price ranges correspond to high capacity factors(95%) and are very low compared with those for typical industrial
consumers in many parts of the world or expected electricity prices in
the fully decarbonised grids of the future. Ongoing development in
the direct use of variable renewable electricity in electricity-intensive
processes (including the use of hydrogen buffer storage andenhanced process flexibility) and declining core equipment(particularly electrolyser) costs are likely to make these methods
more competitive as the realised cost of electricity and subsequenthydrogen costs approach these ranges.

Today, fossil fuels are the lowest-cost source of industry feedstocks,
reduction agents and high-temperature heat for industry in virtually
all regions. With carbon prices rising in several markets and the costof generating electricity from renewables falling rapidly, methods forusing low-carbon hydrogen to produce iron and steel as well as
chemicals are approaching the competitiveness threshold, withcommercial routes currently deployed.
The cost-competitiveness of a low-carbon hydrogen application inindustry is determined primarily by capital expenditures and energy
costs (particularly for natural gas and electricity). For both ammonia
and DRI-EAF steelmaking, low-carbon hydrogen can be produced
using either natural gas or electricity. In ammonia production, at 2030
costs for capital equipment (electrolysers and other core processequipment) and natural gas prices of USD 2-10/MBtu with no carbon
price, the electrolysis pathway competes with the natural gas with
CCUS route at electricity costs of USD 20-40/MWh. For thehydrogen-based DRI-EAF route, the electricity cost range at which it
is competitive with natural gas with CCUS is similar, i.e. around
USD 30/MWh, when considering natural gas prices of USD 6/MBtu.

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Hydrogen demand

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Ammonia

1 200

Steel
Levelised cost of steel (USD/t)

Levelised cost of ammonia (USD/t)

Cost sensitivities for ammonia and steel production

900
600
300
0

800

600

400

200

0

18

36

54

72

Electricity cost (USD/MWh)Natural gas (SMR, unabated) - highNatural gas (SMR, unabated) - low

Natural gas (ATR) with CCUS - highNatural gas (ATR) with CCUS - low

Electrolysis (2030)

Electrolysis (today)

0

12

24

36

60
48
Electricity cost (USD/MWh)Commercial gas-based DRI-EAF
Commercial gas-based DRI-EAF with CCUS
100% H₂ DRI-EAF (today)
100% H₂ DRI-EAF (2030)

IEA. All rights reserved.
Notes: SMR = steam methane reforming. ATR = autothermal reforming. DRI-EAF = direct reduced iron - electric arc furnace. CCUS = carbon capture, utilisation and storage. Technoeconomic assumptions available in the Annex.

PAGE | 66

Hydrogen demand

Global Hydrogen Review 2021

Transport

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Hydrogen demand

Global Hydrogen Review 2021

Greater hydrogen use is necessary to decarbonise transport
The transport sector is responsible for over 20% of global GHG
emissions and one-quarter of final energy demand, with oil products
supplying 90% of the energy it consumes. To date, hydrogen use in
the sector has been limited, representing less than 0.01% of energy
consumed. Nevertheless, hydrogen and hydrogen-based fuels canoffer emissions reduction opportunities, especially in hard-to-electrifytransport segments (e.g. long-haul, heavy-duty trucking, shipping andaviation).

In the Net zero Emissions Scenario, hydrogen and hydrogen-based
fuel deployment is accelerated and demand reaches 2.7 EJ in 2030,
representing 2.6% of transport energy demand. As in the Announced
Pledges Scenario, the greatest share of demand (over 45%) is forroad vehicles. In shipping, hydrogen accounts for almost 2% andammonia almost 8% of fuel consumption in 2030. Synthetic fuels
make up 1.6% of aviation fuel consumption in 2030 in the Net zero
Emissions Scenario. By 2050, hydrogen and hydrogen-based fuels
meet over one-quarter of total transport energy demand in this
scenario.

In the Announced Pledges Scenario, hydrogen and hydrogen-based
fuel consumption in transport climbs to 520 PJ or 0.4% of transportenergy demand in 2030. Almost 60% of this demand is for roadvehicles, as fuel cell vehicle stock expands to over 6 million. Shipping
represents almost one-fifth of the demand, with hydrogen andammonia constituting 1% of shipping fuel consumption in 2030.
Similarly, hydrogen and synthetic fuels account for almost 1% of rail
energy consumption. In aviation, hydrogen-based synthetic fuel use
remains low, making up less than 1% of consumption. By 2050,
demand for hydrogen and hydrogen-based fuels across all transport
end-uses is over 15 times higher than in 2030, meeting 6% of thesector’s energy demand.

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Status of hydrogen and fuel cells for transport
Road transport

FCEV stock. Almost 95% are in China, which has also led
deployment of fuel cell trucks, with >3 100 in operation in 2020.

More than 40 000 FCEVs were on the road globally by the end ofJune 2021. 12 Stocks grew an average 70% annually from 2017 to2020, but in 2020 stock growth fell to only 40% and new fuel cell car
registrations decreased 15% (<10 000 new vehicles), mirroring
contraction of the car market overall due to the Covid-19 pandemic.
However, more than 8 000 FCEVs were sold in the first half of 2021,
with record-high monthly sales recorded in California (759 in March)and Korea (1 265 in April).

Fuel cell electric vehicle stock by segment and region,

FCEVs (thousand)2017-June 2021

Global FCEV deployment has been concentrated largely on
passenger light-duty vehicles (PLDVs), constituting 74% of registered
FCEVs in 2020. Three commercial fuel cell PLDV models are on themarket 13 (Hyundai NEXO, Honda Clarity 14 and second-generation
Toyota Mirai), with other original equipment manufacturers (OEMs)announcing plans to launch models over the next few years.

13

50

40

40

30

30

20

20

10

10

Total

2017

2018

Cars

Buses

2019

2020

June
2021

Commercial vehicles

2017

Korea
Japan

2018

2019

US
Europe

2020

June
2021

China
RoW

IEA. All rights reserved.
Notes: FCEV = fuel cell electric vehicle. RoW = rest of world.
Sources: AFC TCP provided data on stocks from 2017-2020; 2021 new registrations
are based on IPHE Country Surveys, Korea Ministry of Trade, Industry and Energy,
and the California Fuel Cell Partnership.

Buses, despite being deployed earlier and offering a greater numberof fuel cell models (12 according to Calstart’s Zero-Emission
Technology Inventory tool), currently represent only 16% of total

12

50

Only 5 fuel cell truck models are currently available, but 11 are
expected by 2023. Daimler Truck AG and Volvo Group announced ajoint venture, cellcentric, to develop, produce and commercialise fuelFor comparison, EV stock totalled 11 million at the end of 2020.
350 EV models were available in 2020.

Honda announced discontinuation of the Clarity series (both plug-in hybrid and fuel cell models)
as of August 2021, though the Clarity fuel cell will remain available for lease through 2022.
14

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Hydrogen demand

Global Hydrogen Review 2021

cell systems for long-haul trucking, among other applications. Alongwith IVECO, OMV and Shell, both companies also signed theH2Accelerate agreement to collaborate on large-scale hydrogentruck deployment in Europe.

At an average year-on-year increase of almost 20% during 20172020, the number of hydrogen refuelling stations (HRSs) is growing
more slowly than that of FCEVs. The ratio of FCEVs to HRSs 15 isthus increasing, particularly in countries with the highest FCEV sales.
In 2020, this ratio reached almost 200:1 in Korea and 150:1 in the
United States, compared with just 30:1 in Japan. 16 This reflects, inpart, excess HRS capacity, as stations are built anticipating FCEV
growth.

Some OEMs, such as Cummins and MAN, are building and testing
prototype hydrogen-fuelled internal combustion engines forcommercial vehicle applications, which are at a lower technology
readiness level than hydrogen fuel cells.

Recent stations tend to have higher capacities than initial stations. In
2020, California unveiled a 1 200 kg/day station and allocatedfunding to construct stations of up to 1 620 kg/day; this is 2.5-3.5
times the average station size funded since 2012. In July 2021, thelargest hydrogen station to date opened in Beijing, with a capacity of
4 800 kg/day.

600

240

Korea

500
400

200
US

160

300

120

200

80

100

40
2017

2018

2019

2020

FCEVs-to-HRSs

HRSs

Hydrogen refuelling stations by region and ratio of hydrogen
refuelling stations to fuel cell electric vehicles, 2017-2020
RoW
EuropeJapan
China

Station refuelling pressure varies according to the vehicle market
served. In most countries, the majority of stations dispense hydrogenat 700 bar to serve fuel cell cars. In China, most stations dispense at
350 bar to serve bus and truck fleets. Work is ongoing on station andcomponent design and on fuelling protocols to enable highthroughput dispensing for trucks with 700-bar onboard storage, which
will support a range of ~800 km – almost double that of current fuelcell trucks (~400 km). Some stakeholders, including Daimler, Hyzon

US
Korea
Global average
Maximum

IEA. All rights reserved.
Notes: HRS = hydrogen refuelling station. FCEV = fuel cell electric vehicle. RoW = restof world.
Source: AFC TCP Deployment Status of Fuel Cells in Road Transport: 2021

Update.

15
In the absence of complete data on station capacity and dispensing, this ratio aims to provide
some indication of station utilisation.

16

PAGE | 70

For reference, the gas/diesel vehicle to station ratio in the United States is about 1 800:1.

Hydrogen demand

Global Hydrogen Review 2021

Shipping

and Chart Industries, are exploring onboard liquid hydrogen storage
and refuelling to enable truck ranges of >1 000 km.

Hydrogen and fuel cell technologies have been demonstrated in railapplications, including mining locomotives, switchers and trams,
since the early 2000s. In 2018, the first commercial service of ahydrogen fuel cell passenger train (developed by Alstom) began a
100-km route in Germany. Two Alstom trains in Germany have since
driven >180 000 km, and more countries have started testing andadopting fuel cell trains.

Hydrogen fuel cells have been demonstrated on several coastal andshort-distance vessels since the early 2000s. None are yetcommercially available, but the commercial operation of fuel cellferries is expected to begin in 2021 in the United States and Norway.
Most hydrogen-fuelled vessels currently under demonstration orplanned for deployment in the next few years are passenger ships,
ferries, roll-on/roll-off ships and tug boats, typically with fuel cell
power ratings of 600 kW to 3 MW. Furthermore, a recent EU
partnership aims to build a hydrogen ferry with 23 MW of fuel cell
power.

In 2020, a hydrogen train entered regular passenger service inAustria, and trials began in the United Kingdom and the Netherlands.
In Europe, France, Italy and the United Kingdom have all placedorders for hydrogen fuel cell trains, while the largest fleet – 27hydrogen trains – is slated to begin permanent, regular operations inGermany in 2022.

Past and ongoing projects span both gaseous and liquid onboardhydrogen storage. Due to the low volumetric density of hydrogen(whether in gaseous or liquid form), direct use of hydrogen will belimited to short- and medium-range vessels, especially those withhigh power requirements that cannot be met through battery
electrification.

Countries such as China, Korea, Japan, Canada and the UnitedStates are also showing interest in hydrogen fuel cell trains. In
addition to passenger trains, hydrogen trams, line-haul and switching
locomotives are in various stages of development and deployment.
Where direct electrification of lines is difficult or too costly, deploying
fuel cell rail applications can help decarbonise the sector.

Hydrogen-based fuels are also attracting attention for use as
maritime fuels for large oceangoing vessels. Green ammonia inparticular can be used in internal combustion engines to eliminate
vessel CO2 emissions. Major industry stakeholders have announcedplans to make 100% ammonia-fuelled maritime engines available as
early as 2023 and to offer ammonia retrofit packages for existing
vessels from 2025.

Rail

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Methanol has also been demonstrated as a fuel for the maritime
sector and is relatively more mature than hydrogen and ammonia.
Given its compatibility with existing maritime engines, methanol could
be a near-term solution to reduce shipping emissions, but ultimately
ammonia offers deeper decarbonisation potential. 17

The CEM Global Ports Hydrogen Coalition
Launched at the 12th Clean Energy Ministerial (1 June 2021), the
CEM Global Ports Hydrogen Coalition aims to strengthen
collaboration between government policymakers and port
representatives to scale up low-carbon hydrogen use.
The IEA’s The Future of Hydrogen identifies ports and coastal
industrial hubs (where much of the refining and chemical
production that currently uses hydrogen is concentrated) as
opportune places to support the near-term scale-up of lowcarbon hydrogen production and use. The shift from fossil-based
to low-carbon hydrogen by industries in these clusters would
boost hydrogen fuel demand by ships and trucks serving theports as well as by nearby industrial facilities (e.g. steel plants),
which would drive down costs.

AviationInterest in using hydrogen for aviation has also been growing. The
industry group ATAG sees a role for hydrogen fuel cells for flights of
up to 1 600 km, and hydrogen combustion for short flights andpotentially for medium-haul ones. Assuming the technology isdeveloped successfully, hydrogen fuel cells could be used in 75% ofcommercial flights but account for only ~30% of aviation fuel.

To enlarge dialogue on hydrogen potential for port operations,the Coalition convenes numerous ports and stakeholders,
including the International Association of Ports and Harbours andthe World Ports Climate Action Program as well as regional
associations (e.g. the European Sea Ports Organisation). The
Hydrogen Council, the world’s leading industry initiative, will also
participate in Coalition activities along with other industry
stakeholders.

Technically, hydrogen combustion could be used for longer flights,
potentially covering almost 95% of flights and 55% of fuelconsumption, but equipment would be needed to mitigate NOx
emissions. 18 Sustainable drop-in aviation fuels, including hydrogenbased fuels and biofuels, will be needed to decarbonise at least
longer-haul flights, although means to mitigate non-CO2 climatewarming effects may be required.

17
However, ammonia combustion results in N2O and NOx emissions that may require additional
equipment to mitigate climate and air pollution impacts.

A recent McKinsey & Company study prepared for the Clean Sky 2 JU and FCH JU is more
optimistic about hydrogen use in aviation and provides a comparison of its climate impacts withthose of synthetic fuels.
18

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Global Hydrogen Review 2021

Flight and fuel shares

Hydrogen potential, by share of flights and fuel use incommercial passenger aviation

Boeing recently partnered with Australia’s Commonwealth Scientificand Industrial Research Organisation (CSIRO) to publish a roadmap
for hydrogen in the aviation industry that considers opportunities forhydrogen use in aircrafts and airport applications (buses, stationary
power, ground support equipment, taxis, trains and freight trucks).
Remaining technical challenges include light-weighting cryogenic
storage tanks (with minimal boil-off) and developing hydrogen
infrastructure for delivery (likely pipelines with near- or on-siteliquefaction) and high-flowrate liquid refuelling.

100%
Flights

90%
80%

Aviation fuel

70%
60%

Fuel cells (fuel)50%

Fuel cells (flights)

40%
30%

Combustion (fuel)20%

Combustion (flights)

10%
0%

0

2 000

4 000

6 000 8 000 10 000 12 000
Flight distance (km)

IEA. All rights reserved.
Note: Shading indicates shares of aviation fuel use (solid) and flights (transparent) that
could theoretically be offset by hydrogen aircraft, given successful technology
development to meet industry targets.
Source: IEA analysis based on OAG flight database.

Whether used with fuel cells or directly combusted, using hydrogen
will require new aircraft system designs. Airbus is exploring varioushydrogen aircraft concepts, focused on a capacity of up to 200
passengers and a 3 700-km range, with the goal of having acommercial aircraft available by 2035. Smaller companies working onhydrogen aircraft solutions include ZeroAvia, which targets the firstcommercial offering of a hydrogen plane with a 900-km range in
2024, and Universal Hydrogen, which aims to develop hydrogenstorage solutions and conversion kits for commercial aircraft.

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Deployment of hydrogen in other mobile applications
Material handling equipment

Mining and agricultural equipment

Deploying zero-emissions material handling equipment, which
includes forklifts and other machinery, is particularly importantfor indoor operations. Quick refuelling (~2 minutes) is cited as abenefit of fuel cells: in contrast with battery electric equipment,
which forces drivers to return to a central location during a shift
to swap out batteries, hydrogen refuelling can be situated morestrategically throughout a warehouse. Fuel cells also performparticularly well in refrigerated environments, whereas cold
temperatures degrade batteries.

Hydrogen fuel cells may also be used to help decarbonise heavy
off-road applications such as mining and agricultural equipment.
As part of its national decarbonisation policy and Green Mining
Plan, Chile supports projects to investigate and develophydrogen-fuelled mining trucks, and the mining industry ingeneral is investing in hydrogen technologies for mining
equipment.
Anglo American expects to begin testing the first fuel cell mining
truck in the second half of 2021 at a platinum group metal mine inSouth Africa. Komatsu, the Japanese construction equipment
maker, plans to develop a fuel cell mining dump truck, aiming tocommercialise it by 2030. While electric mining trucks powered

Forklifts have proven to be an early commercial application forfuel cells. The United States currently has >40 000 hydrogen
forklifts, with Plug Power being the major provider. Japan targets
10 000 by 2030, an ambitious scale-up from its current 330, andBelgium, Canada, France and Germany also each have fuel cellmaterial handling equipment numbering in the hundreds. In

by catenary lines already exist, fuel cell trucks offer
decarbonisation potential for routes that power lines do not reach.
Agricultural equipment company New Holland, which showcaseda fuel cell tractor in 2011, has now developed (as a transitional
technology) a dual-fuel tractor that runs on a hydrogen-diesel
blend. Other companies such as H2X and H2Trac are also
developing fuel cell tractors.

Chile, Walmart has announced plans to convert 150 battery
forklifts to fuel cell, powered by green hydrogen.

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Insights into regional strategies for hydrogen fuels in transport
China

In non-road applications, China has developed a hydrogen tram andhybrid locomotive. An ammonia fuel-ready tanker now being built
could become the first maritime vessel to operate on this fuel.

China currently has the third-largest FCEV stock. Unlike othercountries, it has focused on deploying fuel cell buses and trucks, andit now has the highest number in the world. Owing to a previous
subsidy scheme, which set the fuel cell requirement at just 30 kW toqualify, fuel cells have been used mainly as range extenders. A new
rewards-based policy framework aims to accelerate hydrogendemonstration at the regional (or city-cluster) level and focuses on
the FCEV operation and supply chain, including hydrogen production
and vehicle hydrogen consumption.

At the end of 2020, over 2 600 FCEVs were operating in Europe, withmore than 1 000 in Germany. More than 90% of Europe’s FCEVs arelight-duty, and about 130 are fuel cell buses. Germany also leads inthe number of HRSs, with 90 operating at the end of 2020 (of190 across Europe). 19

China has not yet approved type-IV hydrogen tanks used for 700-bar
onboard storage, which partially explains its past emphasis on
deploying mainly buses and trucks. While trucks and buses are
expected to dominate FCEV sales in the next few years, regulatory
approval and deployment of fuel cell cars will likely be needed toreach targets outlined in China’s Technology Roadmap 2.0. The
SocietyofAutomotive
Engineersisaimingfor
50 000-100 000 FCEVs in 2025 and 1 million between 2030 and
2035.

The Fuel Cell and Hydrogen Joint Undertaking (FCH JU) has
supported a wide variety of FCEV demonstration and deployment
projects, including taxis, delivery vans, buses and refuse trucks. As aresult, the deployment of fuel cell taxis in Europe has been relatively
high, most notably in Paris (100), the Hague (~40), Copenhagen(~10) and London (>50). Madrid has announced plans to deploy
1 000. Several European countries (the Czech Republic, France, theNetherlands, Portugal and Spain) have set FCEV targets, together
aiming for ~415 000 FCEVs by 2030.

EuropeThe European Commission’s Fit for 55 package’s revisions to the Alternative Fuels Infrastructure
Directive aims to ensure the HRS network is dense enough to “allow for seamless travel” of FCEVs,
with an emphasis on heavy-duty vehicles.
19

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Europe has been a leader in commercialising fuel cell trains.
Additionally, the European Union has funded demonstrations of fuelcell-powered
maritime
vessels,
including
EUR 5 million

HEAVEN project, aimed at developing and integrating a high-power
fuel cell and cryogenic hydrogen storage system into an existingsmall aircraft.

(~USD 5.9 million) for the FLAGSHIPS project, which is deploying aJapanhydrogen cargo transport vessel in France and a hydrogenpassenger/car ferry in Norway, and EUR 10 million (~USD

At the end of 2020, Japan had 4 100 fuel cell cars and 100 fuel cellbuses, and by mid-2021 the total had surpassed 5 500. With 137
HRSs at the end of 2020, Japan currently has the most in the world.
Future (2030) targets include 800 000 PLDVs, 1 200 buses, 10 000
forklifts and ~1 000 HRSs (recently revised upwards from 900 as partof Japan’s Green Growth Strategy).

11.8 million) for the ShipFC project, which will install a 2-MW
ammonia fuel cell on an offshore vessel.
In July 2021 the European Commission presented the ReFuelEU
Aviation proposal, which would require a minimum share ofsustainable aviation fuel at all EU airports, including a continually
increasing minimum share of synthetic aviation fuel. It aims toincrease the share of synthetic aviation fuel from 0.7% in 2030 to 28%
in 2050.

To support targeted level of FCEV adoption, Japan aims to makethem price-competitive with comparable hybrid EVs, particularly by
reducing the cost of fuel cells and hydrogen storage systems. Japanis also targeting HRS cost reductions; 20 to date, prescriptive
regulations have contributed to stations costing twice that in otherparts of the world. Current HRS development and operations arefinancially supported through Japan Hydrogen Mobility (JHyM), a
consortium of 26 private companies, financial institutions and thegovernment.

Additionally, the German government recently released a power-toliquids (PtL) roadmap targeting the consumption of 200 000 tonnesof hydrogen-based sustainable aviation fuel in 2030. Meanwhile, aspart of its Plan de relance aéronautique (a programme to help theaerospace industry recover from Covid-19 impacts), the Frenchgovernment has granted EUR 800 000 for development of a small(two-seat) hybrid hydrogen aircraft. The FCH JU has also funded the20
HRS cost reduction targets include reducing capital expenses from JPY 350 million(~USD 3.2 million) in 2016 to JPY 200 million (~USD 1.8 million) around 2025.

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The East Japan Railway Company, partnering with Hitachi andToyota, has announced plans to develop a hydrogen train, withtesting to begin in 2022. To meet International Maritime
Organisation (IMO) standards on GHG emissions for international
shipping, Japan is also investigating hydrogen- and ammoniafuelled vessels. In 2020, the government published the Roadmap to
Zero Emissions in International Shipping, which targets introductionof a first-generation zero emissions ship by 2028.

According to Korea’s hydrogen roadmap, the government plans to
expand its focus to include hydrogen ships, trains and drones once
the road vehicle market has matured. In fact, the government
recently provided funding (USD 13 million) to the Korean Railroad
Research Institute to develop the world’s first liquefied hydrogenbased locomotive, slated for testing at the end of 2022.

United States
The United States currently has the second-largest FCEV fleet, with
>9 200 at the end of 2020. Most are in California, where the state
government has supported HRS construction with funding of
USD 166 million. At the end of 2020, there were 45 retail stations
open in California and a total of 63 public and private HRSs acrossthe country.

Korea
Korea took the lead in FCEVs in 2020, with >10 000 cars and >50
buses on the road. Its FCEV stock doubled from 2019 to2020, andby the end of June 2021 an additional 4 400 fuel cell cars had beenregistered. Purchase subsidies from central and local governments
cover about half of the purchase price of the popular, domestically
produced Hyundai NEXO. In the Hydrogen Economy Roadmap,
FCEV targets are set at 2.9 million cars, 80 000 taxis, 40 000 busesand 30 000 trucks by 2040. In the 2020 New Deal, the government
set an interim target of 200 000 FCEVs in 2025.

The California Energy Commission estimates the state will have
179 HRSs by 2027 with capacity to support 200 000 FCEVs, though
this would miss the target of 200 HRS by 2025. Despite industry
plans to expand the FCEV market to the north-eastern US states,
regulatory barriers in some states are impeding deployment.

Korea had 52 operational HRSs at the end of 2020, and thegovernment is targeting 310 by 2022 and 1 200 by 2040. The
Hydrogen Energy Network (HyNet) was therefore established in2019 with an investment of USD 119 million to build ~100 HRSs by
2022.

To date, the US government has not established federal targets for
FCEV deployment. However, the California Fuel Cell Partnership,
an industry and government collaboration, has announced its
ambition to have 1 million FCEVs and 1 000 HRSs in the state by
2030.

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To guide R&D efforts, the US Department of Energy has set costand performance targets for fuel cells for light- and heavy-duty
vehicles. In 2019, the DOE published heavy-duty long-haul truck
targets, including reducing the cost of the fuel cell system to
USD 60/kW and increasing its durability (i.e. lifetime) to 30 000
hours. To support R&D to meet these targets, the DOE establishedand funded the Million Mile Fuel Cell Truck Consortium.
California government agencies have also supported vehicle
deployments, including the first fuel cell ferry (launch expected in2021), development of a hydrogen fuel cell switching locomotive
and the deployment of heavy-duty hydrogen trucks.

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Outlook for hydrogen in transport
Road transport

Similarly, fuel cell buses reach the highest sales share (6.1%) in 2030
in the Net zero Emissions Scenario. In addition, rapid technology andinfrastructure development is assumed to support fuel cell truck
deployment, which reaches a sales share of 4.7% in 2030. Use of
synfuels for road transport is limited due to a higher TCO than forother zero- or low-emission alternatives.

Road vehicles account for the highest share of hydrogen andhydrogen-based fuel consumption in transport in 2030 under both theAnnounced Pledges (58%) and Net zero Emissions scenarios (45%).
FCEV stock, across all modes, reaches >6 million in the Announced
Pledges Scenario and >15 million in Net zero Emissions, with mostbeing LDVs. The share of cars within the total FCEV stock remains
at about 75% from 2020 to 2030 in the Announced Pledges Scenario,
but decreases to 70% in the Net zero Emissions Scenario.

In 2019, the Hydrogen Energy Ministerial published the Global Action
Agenda targeting 10 million fuel cell-powered systems (including
road vehicles, trains, ships and forklifts) by 2030. Annual fuel cell
production capacity doubled from 2019 to 2020, but FCEV
deployment in 2020 was ~20% lower than in 2019 – and well below
the annual average needed to achieve the target. Even including the
deployment of material handling equipment such as forklifts (~10 000
in 2020), accelerated scale-up is needed (likely beyond Announced
Pledges projections) to achieve such an ambitious target.

Generally, EVs are expected to be the dominant zero emissions
vehicle powertrain in road transport, reflecting higher efficiency anda lower TCO in most cases. FCEV sales in 2030 reach 1% in the
Announced Pledges Scenario (compared with 29% for EVs) and 3%
in the Net zero Emissions Scenario (against almost 60%) owing tosupportive government policies and subsidies, as well as consumer
preference for non-cost factors (e.g. refuelling or charging time).

Announced annual fuel cell manufacturing capacity by 2030(~1.3 million systems/yr) could meet 75% of required fuel cell
production for road vehicle sales in the Announced Pledges Scenario
but would satisfy only less than one-third of Net zero Emissions
sales. Notably, announced capacity exceeds the FCEV stock targets
and ambitions stated by governments and other groups (e.g. theChina Society of Automotive Engineers and the California Fuel Cell
Partnership).

In the Announced Pledges Scenario in 2030, the sales share of fuelcell buses (3.7%) is the highest of all road transport modes, mainly
because they offer advantages over battery electric technology forintercity buses. Fuel cells can also compete in the long-haul-trucking
sector, as their range, refuelling time and payload capacity canenable performance and operations similar to current diesel trucks.
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FCEV stock (million)

FCEV stock in the Announced Pledges and Net zero Emissions
scenarios in 2030 vs current and announced cumulative fuel cellmanufacturing capacity and FCEV deployment targets
18

In the Net zero Emissions Scenario, installed station capacity
reaches >50 kt/day in 2030, compared with <20 kt/day in the
Announced Pledges Scenario.

Trucks

16
14

Buses

12

LCVs

10

PLDVs

8

Non-road transport
Shipping becomes the second-largest consumer of hydrogen andhydrogen-based fuels among transport modes in 2030 in both theAnnounced Pledges and Net zero Emissions scenarios. Demand forhydrogen and ammonia in shipping remains limited in the Announced
Pledges Scenario, together meeting about 1% of fuel demand. In the
Net zero Emissions Scenario, ammonia meets 8% of total shipping
fuel demand and hydrogen meets 2%.

Official government targets

6

Ambitions

4

Announced capacity

2

Existing capacity
Projects

PledgesAPS

NZE

To enable hydrogen and ammonia fuel use in shipping, ports willneed to build corresponding bunkering infrastructure. It is expectedthat ports with hydrogen bunkering infrastructure will remain fairly
limited until 2030, with most being “first movers” such as thesignatories of the Global Ports Hydrogen Coalition and others thathave already begun investigating and testing hydrogen solutions(e.g. the Port of Valencia, Port of Honolulu, Ports of Auckland, Portof Los Angeles and Port of Antwerp).

IEA. All rights reserved.
Notes: FCEV = fuel cell electric vehicle. LCV = light commercial vehicle. PLDV =passenger light-duty vehicle. APS = Announced Pledges Scenario. NZE = Net zero
Emissions Scenario. FCEV ambitions include non-government targets such as fromthe China Society of Automotive Engineers and the California Fuel Cell Partnership.
Sources: IEA Mobility Model (projections); E4tech (fuel cell projects).

To support FCEV deployment in 2030, an estimated 27 000 HRSs
would be needed in the Announced Pledges Scenario and 18 000 in
the Net zero Emissions. These estimates are highly sensitive tostation capacity and utilisation assumptions. As station size andutilisation are expected to grow more slowly in the Announced
Pledges than in the Net zero Emissions Scenario, the former requires
a higher number of HRSs despite a lower number of vehicles.

As hydrogen continues to displace fossil fuels in relatively shortrange vessels (especially when battery electrification is difficult), in
the long term every port serving ferries, cruise ships and inland andcoastal vessels will likely need hydrogen infrastructure. In the
Net zero Emissions Scenario, about ten ports are projected to be first
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movers in providing ammonia bunkering services (fewer in the
Announced Pledges Scenario), all having high maritime cargothroughput and either existing ammonia bunkering or plans tointegrate new fuels. Included in the first movers are the ports ofRotterdam and Singapore (both ranking in the top ten by container
throughput), as well as the Keihin ports along Japan’s Tokyo Bay.
In rail, hydrogen is expected to mainly replace current diesel linesthat are expensive to electrify due to relatively low utilisation. 21
Hydrogen constitutes 0.7% of rail energy consumption in 2030 in the
Announced Pledges Scenario and 2% in the Net zero Emissions.
Passenger aircraft, for commercial aviation, designed to usehydrogen directly are not expected to be commercially available until
the mid-2030s or later. Use of hydrogen-based synfuels (or powerto-liquids [PtL]), which can be dropped into an existing aircraft, could
make inroads by 2030. In the Announced Pledges Scenario, PtL
meets <0.6% of aviation fuel demand in 2030, but this share almost
triples to >1.6% in the Net zero Emissions Scenario.
Given the limited availability of sustainably sourced carbon, the bulkof synfuels are consumed in the aviation sector where battery
electrification and direct use of hydrogen are restricted to relatively
short flights, especially in the near to medium term.

21

See The Future of Rail for further analysis.
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Transport industry announcements for FCEVs
CompanyBMW

TargetLimited-series fuel cell SUV releaseTarget year
2022

Vehicle category
PLDV

Jaguar Land RoverPrototype testing of fuel cell SUV

End of 2021

PLDV

Great Wall Motor

Fuel cell SUV release

2021

PLDV

Toyota Motor Corp.

Deployment of 600 FCEV taxis in greater Paris region

End of 2024

PLDV

Riversimple

Production target of 5 000 fuel cell coupes/yr

2023

PLDV

Riversimple

Light goods vehicle model release

2023

LCV

Stellantis

Fuel cell van models release

2021

LCV

Renault and Plug PowerLight commercial vehicle models release

2021

LCV

Symbio and Safra

Availability of 1 500 buses

2021

Bus

Symbio and Safra

Construction of largest EU fuel cell plant (60 000 units/yr)

Unspecified*Bus

H2Bus Consortium

Deployment of 600 fuel cell buses

2023

Bus

Daimler

Testing of GenH2 truck with liquid hydrogen onboard storage

2021

Truck

Air Products and Cummins

Conversion of ~2 000-truck fleet to hydrogen fuel cells

2022+

Truck

NikolaPurchase order of up to 800 fuel cell trucks to US Anheauser-Busch

2023+

Truck

MAN

2024

Truck

2024

Truck

Hyundai

Deployment of hydrogen fuel cell demonstration fleet
Purchase orders for 1 500 fuel cell trucks to Hiringa Energy in New Zealand; 20 to
Jan Baaker and Millenaar & van Schaik in the Netherlands; and 70 to
JuVE/MPREIS in Austria
Purchase order of 1 600 fuel cell trucks to Switzerland

By 2025

Truck

Daimler and Volvo

Large-scale series production of fuel cell trucks

2025+

Truck

Industry Coalition

Deployment of 100 000 heavy-duty fuel cell trucks in Europe

From 2030

Truck

Hyzon

* Although plant construction has already begun, the target date for operations is unspecified.
Notes: PLDV = passenger light-duty vehicle. LCV = light commercial vehicle.

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Cost and supply chain analysis
reduce costs while maintaining or improving efficiency. Key areas for
R&D include the fuel cell catalyst, currently based on platinum groupmetals; membranes and electrolytes; and bipolar plates.

Fuel cells
The cost of automotive fuels cells has fallen ~70% since 2008.
Depending on the vehicle segment, current system costs are
USD 250-400/kW, but further reductions are needed to make FCEVs
cost-competitive with internal combustion engine vehicles and otherlow- or zero emission vehicles. Analysis suggests that scaling up
manufacturing capacity from 1 000 to 100 000 systems/yr would
slash costs by >70%, but significant investment is needed to boost
manufacturing throughput and capacity.

Thousand systems/yr

Announced annual automotive fuel cell manufacturing capacity,
2020-2030

To this end, new and incumbent fuel cell manufacturers haveannounced expansion plans. Global fuel cell manufacturing capacity
is expected to reach >200 000 systems/yr by the end of 2021, with
supply spread among over 40 manufacturers. Toyota can currently
produce 30 000 systems/yr, and Hyundai is building a second plant
to bring capacity to >40 000 systems/yr in 2022 and aims reach
500 000
systems/yr
by2030.
Manufacturing
capacity
announcements for 2030 total 1.3 million systems/yr, with anestimated annual production potential of 90 GW.

1 400

Fujian Snowman

1 200
Symbio

1 000
800

Wuhan HydraV Fuel
Cell Technologies

600

Toyota

400

2030

2029

2028

2027

2026

2025

2024

2023

Other

2022

0

2021

Hyundai

2020

200

IEA. All rights reserved.
Source: E4tech.

Since 2008, average platinum loading in fuel cells has decreased
30%. Toyota reports reducing platinum loading in the Mirai fuel cellby about one-third from first- to second-generation models.

Technological advances are needed to improve fuel cell durability(which is particularly vital for heavy-duty transport applications) and

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In addition to lowering costs, reducing platinum loading mitigates
potential supply chain risks associated with highly geographicallyconcentrated supplies, as more than 70% of platinum group metals
are sourced from South Africa.

serving both vehicle types will require more equipment to fuel at
different pressures or flowrates.
The number of suppliers for key HRS components is currently
limited, which can restrict station roll-out and prevent the cost
reductions that come with market competition. For example, just twocompanies (WEH and Walther) dominate the HRS nozzle market.

According to the IEA’s critical minerals report, global demand forplatinum group metals is expected to grow as FCEVs displace
conventional vehicles, though this is mitigated by lower palladium
required for ICEV catalytic converters. Overall platinum demand is
expected to increase despite further reductions in the platinumloading of automotive fuel cells.

Novel component designs (including for high-throughput
compressors, cryogenic hydrogen pumps, hoses and nozzles) andrefuelling protocols are needed for fast fuelling of heavy-duty trucks,
marine vessels and aircraft.

Hydrogen refuelling stations

Total cost of ownership

While economies of scale in station component manufacturing areexpected to reduce the delivered cost of hydrogen for vehicles,
HRSs with higher capacities will also have a lower levelised cost ofdispensed hydrogen. Increasing station size from 350 kg/d to
1 000 kg/d could cut the cost of dispensed hydrogen by over 30%,
according to US DOE analysis. As both station capacity and vehicle
demand increase, pipeline delivery will become more profitable andcould further reduce the overall cost of dispensed hydrogen.

Adoption of FCEVs, especially buses and commercial vehicles, will
be determined by how their TCO compares with other vehicle andfuel technologies. The main TCO factors for FCEVs are thedelivered hydrogen and fuel cells costs, and station utilisation. In
comparison with BEVs, daily range is another key consideration.
For long-haul HDVs, enabling a sufficient driving range may require
additional battery capacity; however, the associated weight could
limit payload and add to BEV cost. Fuel cell trucks begin to have a
TCO advantage over battery electric at a range of 400-500 km, as
shown in the IEA’s Energy Technology Perspectives 2020.

Station utilisation is another important factor. While utilisation tends
to align with vehicle deployment, early FCEV fleet deployment canhelp ensure a certain level of utilisation, lowering hydrogen prices.
Stations designed to serve both LDVs and HDVs may be able toincrease utilisation and reduce overall capital expenditures, though
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Current and future total cost of ownership of fuel/powertrain
alternatives for heavy-duty trucks.

USD/kmThe TCO for fuel cell heavy-duty trucks is currently 10-45% higher
than for internal combustion diesel trucks. In the Announced
Pledges Scenario, as the manufacturing of fuel cells, station
components and hydrogen production technologies scales up –while station utilisation also increases – the TCO of fuel cell heavyduty trucks drops 30-40% by 2030 and 50-60% by 2050.

1.6

Synthetic fuels(PV+DAC)

1.4

Synthetic fuels(lowest cost)

1.2
1.0

Comparing decarbonisation options for this sector, the TCOs of both
battery electric and fuel cell trucks are expected to be lower than forhybrid electric trucks running on synthetic diesel. In the medium
term, fuel cell and battery electric trucks have comparable TCOs at
a 500-km driving range, depending on refuelling or charging
infrastructure utilisation. By 2050 in the Announced Pledges
Scenario, fuel cell electric trucks are expected to be the lower-cost
option at that range.

Low utilisation infrastructure

0.8
0.6

Refuelling / charging
infrastructure

0.4Electricity / fuelCurrent

2030 (APS)BEV(500 km)

FCEV

BEV(500 km)Syndiesel
HEV

FCEV

BEV
(500 km)Syndiesel
HEV

FCEV

0.0

Diesel ICE

0.2

2050 (APS)

Operations andmaintenance
ICE engine / battery /fuel cell
Base vehicle + minor
components

IEA. All rights reserved.
Notes: APS = Announced Pledges Scenario. ICE = internal combustion engine. FCEV
= fuel cell electric vehicle. BEV = battery electric vehicle. HEV = hybrid electric vehicle.
PV = photovoltaic (solar electricity for synthetic fuel production). DAC = direct air
capture. Techno-economic assumptions available in the Annex.
Source: Based on input from McKinsey & Company and the Hydrogen Council.

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Buildings

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Hydrogen and fuel cell opportunities are limited in buildings but worth exploring
With consumption of almost 70 EJ, space and water heating inbuildings accounts for nearly 55% of energy use in buildings globallyand 4.3 Gt CO2 of emissions. In very cold areas such as in Russia,
the Caspian region and Iceland, heating can make up >80% of totalenergy demand in buildings. Improving the thermal performance ofbuilding envelopes and integrating clean, efficient low-temperature
equipment are priorities to decarbonise heating in buildings. Several
options for efficient heating are currently available, including heatpumps and clean district energy.

space availability, energy system layout and overall building
performance, in addition to logistical and economic costs for building
occupants.

Primary energy factor

Primary energy factors of heat production by equipment and fuel,2020

Prospects for deploying hydrogen in this sector remain limited,reflecting the high efficiency of electricity-based solutions and theenergy losses that result from converting and transporting hydrogen.
For instance, PV-powered heat pumps require 5-6 times lesselectricity than a boiler running on electrolytic hydrogen to provide thesame amount of heating. Furthermore, ensuring safe operations andconverting gas infrastructure are both capital-intensive and sociallychallenging.

5
4
3
2
1
0

Resistance
Heat

Heat
pump

Electricity
Typical range

BoilerHeat
pump

Natural gas

Stove

BoilerModernbiomass

HybridFuel cellheat pump
HydrogenGlobal average

IEA. All rights reserved.
Notes: Hybrid heat pumps are assumed to use 25% hydrogen. Heat refers to district
heating. Assumptions available in the Annex

The heating sector is difficult to decarbonise, with existing (old) multifamily buildings and very cold climates being particularly challenging
because integrating efficient low-temperature solutions depends on

Nevertheless, since hydrogen equipment can be compatible withexisting buildings’ energy systems, 22 localised hydrogen applications

In terms of deliverable temperature range and operational schedules, but pipework, metering andverification interventions are required.

22

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could support decarbonisation in very specific contexts where gas
infrastructure already exists. Co-existence of hydrogen and otherheat production technologies can also add flexibility to the electricity
grid to facilitate demand-side response, particularly in very cold
regions where BEVs and other storage devices would likely fall short.

Deployment of hydrogen equipment needs to be specifically targeted
to applications where it is cost-effective compared with switching toother options, and it takes roughly five days to adapt a building’s
energy system.
Four main groups of technologies can operate on hydrogen at thebuilding level:

Hydrogen can be blended with or replace a portion of natural gas,
which currently meets 35% of global energy demand for heating.
Depending on the region, such blending (at volumes of 5-20%) canleverage current natural gas infrastructure without requiring major
network modifications.
Blending hydrogen at 20% would reduce carbon intensity by 7% at
most – well short of the level needed for long-term buildings sector
decarbonisation. It would also affect gas prices for end users. Whiledecarbonising established hydrogen use remains a priority, blending
options could help guarantee demand for low-carbon hydrogen.
In the longer term, hydrogen-specific infrastructure could be
expanded (by building up dedicated networks or retrofitting existingones) to further displace natural gas. Space and water heating
equipment will also need to be upgraded or replaced, then verified as
operational.

23

Co-generation refers to the combined production of heat and power, also known as CHP.
PAGE | 88Hydrogen boilers can be practical where gas networks exist because
consumers will be familiar with the basic technology and its upfront
capital costs. From a lifecycle perspective, however, higher fuelconsumption than more efficient technologies makes this option lessattractive overall for most buildings.

Fuel cells that co-generate 23 heat and electricity include solid oxide
fuel cells (SOFCs) and polymer electrolyte membrane fuel cells(PEMFCs). SOFCs require a high temperature but also provide highelectrical efficiency and a more stable load compared with PEM cells,
which work at a lower temperature (60-80°C) on intermittent load
schedules but offer lower electrical efficiency. As SOFC efficiency
typically declines when operated with pure hydrogen, optimising thesystem layout to address this issue is a key research focus. Natural gas
field testing in Europe shows micro-cogeneration unit electricalefficiencies of 35-60% for SOFCs and 35-38% for PEMFCs, withcorresponding cogeneration system efficiencies of 80-95% (SOFCs)
and 85-90% (PEMFCs).

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Hybrid heat pumps combine a boiler with an electric heat pump. The
boiler operates only when the heat pump cannot meet heating demand.
Hybrid heat pumps are an interesting option in cold climates wherehydrogen can be used to cover peak demand during very cold periods,
but they have additional capital costs and require both electricity andhydrogen connections.



Gas-driven heat pumps have a gas engine that produces electricity
to run a heat pump. Thousands of units are already operating in Asia
and Europe, primarily in non-residential buildings.

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Status of hydrogen and fuel cells for buildings
In 2020, hydrogen’s share in heating energy demand was extremely
limited (at less than 0.005%) even though countries began supporting
demonstration projects and programmes to deploy hydrogencompatible technologies, spark market adoption and reduce upfront
consumer costs as early as the 2000s. Largely focused on stationary
fuel cells, these programmes have tended to rely on natural gas, but
their lessons are applicable to the use of pure hydrogen. These
projects are sited in countries that together cover ~40% of global heat
demand, with significant heating seasonality and where natural gas
covers a large share of heat production in buildings.

or backup power, or co-generation. Most run on natural gas. Fuelcells for residential applications are mostly PEM and tend to berelatively small (0.7-1.5 kWe but also up to 5 kWe), with several
governments offering financial incentives to support theirdeployment.
Homeowners in the United States can qualify for federal tax credits(>USD 3 300/kWe) when installing residential units of >0.5 kWe. Other
government schemes offer subsidies for fuel cell technologies, suchas New Jersey’s Clean Energy Program for micro-cogeneration
technologies. Korea is among the countries using renewable energy
certificates and subsidies. Support generally covers the upfront costs
of installation, or rewards power generation rather than heatproduction.

Stationary fuel cells
Deployment of micro-cogeneration stationary fuels cells (<1 kW ofelectrical output [kWe] for residential applications, and up to 5 kWe)
has been greatest in Japan (more than 350 000 units operating) andEurope, especially in Germany (15 000), Belgium and France. Korea
has 15.7 MWe (units of <100 kWe) installed in buildings (CEM H2I
surveys), while US installations are primarily industrial-scale units(>100 kWe).

Hydrogen blending and pure hydrogen applications
There are a number of projects around the world at various stages
for exploring the impact of hydrogen blending in existing gas
networks. Frontrunner, launched in 2007 on the Dutch island of
Ameland, tested injection volumes of up to 20% for heating andcooking using standard appliances. More recently in France (June2018 to March 2021), the GRHYD project tested injection (max. 20%)for >100 dwellings, while the three-phase UK HyDeploy project aims

Fuel cells have been deployed in almost all building types – fromresidential to commercial/public building applications, including
military installations, hospitals and data centres – to provide primary
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to prove the safety of blending up to 20%. The first phase, concluded
in 2021, involved a live demonstration in the Keele gas network toassess what level of blending is safe with existing domestic
appliances.

project is also assessing the first home (in Low Thornley, Gateshead)
to be entirely fuelled by hydrogen, from boilers to cookers.
The WaterstofWijk Wagenborgen project (in the Netherlands) is apilot that will connect 1970s buildings to a hydrogen network.
Wagerborgen hybrid heat pumps will be installed in each house,running as much as possible on electricity and switching to hydrogen
during cold periods only; houses will also be equipped with solar
panels and induction cooking.

Other initiatives aiming to demonstrate hydrogen use in dedicatednetworks in a few hundred dwellings are now under development,
particularly in north-western Europe. These include H100 Fife (300households starting in 2022) in the United Kingdom and Hoogeveen
and Stad aan 't Haringvliet (600 households from 2025) in the
Netherlands. Larger projects, such as the United Kingdom’s H21, areat early stages of development.
The UK government also supports the Hy4Heat project to assess thetechnical, economic and safety aspects of replacing natural gas withhydrogen in residential and commercial buildings and in gas
applications. Under this programme, a Worcester Bosch 100%hydrogen-ready prototype boiler – which can be converted to run onhydrogen by modifying just two or three components – won Best
Heating Innovation in the 2021 Green Home Awards.
In a first trial in single-family, semi-detached and terraced houses, theproject found that 100% hydrogen use is as safe as natural gas forheating and cooking. More research is needed to assess safety inmulti-family homes and houses with limited natural ventilation, and to
determine the safety of supplying homes through gas networks. The

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Natural gas use in the buildings sector and selected key projects, initiatives, programmes, announcements for deploying hydrogen orhydrogen-compatible equipment by country or region, 2020
RegionShare of global
heating
consumption(%)

Share of water
heating in heating
consumption (%)

Share of natural gas in:
Heating (%)

Cooking (%)

UnitedStates

17

19

65

60

UnitedKingdom

2.5

21

70

50

Korea

1.5

22

48

63

European
Union

15

20

40

32

Initiative details

New Jersey’s Clean Energy Program provides financial
incentives for co-generation and fuel cell installations.
HyDeploy for hydrogen blending applications. H21 Leeds
City Gate and H21 Network innovation for 100% hydrogen
application. Hy4Heat project.
Announced intentions to create three hydrogen power cities
by 2022, in line with hydrogen roadmap goal of providing
households and other buildings 2.1 GW of power from fuelcells.
Ene.field project, Europe-wide field trials for residential fuelcells, concluded in 2017.
PACE (Pathway to a Competitive European Fuel Cell microCogeneration Market), ends in 2021.
ComSos, (Commercial-scale SOFC systems), ends in 2022.
National innovation Programme for hydrogen and fuel cell
technology (Germany), 2007-16.
KfW433 (Germany), dedicated fuel cell programme since
2016;
overall impact: >15 000 fuel cells deployed in EU.
GRHYD (France): power-to-gas testing with hydrogen
blending rates of up to 20% per volume, 2018-21.
WaterstofWijk Wagenborgen planned project (Netherlands):
demonstration project for hybrid heat pumps for 40 residents.

Japan

3

35

32

39

Ene.Farm project, >350 000 commercial fuel cells deployed.

Notes: Listed projects include concluded as well as ongoing and announced initiatives related to buildings. Heating consumption includes space and water heating.

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Regional insights on hydrogen in buildings
Japan

Korea

With more than 350 000 units installed as of March 2021, Japanleads global deployment of micro-cogeneration fuel cells inbuildings. The ENE-FARM programme is the main contributor to
uptake, recently reporting sales of 40 000 units/yr. Models on themarket are mostly fuelled by natural gas; most are PEMFC units,
but SOFCs have also emerged recently. ENE-FARM subsidies were
eliminated in FY2019 for PEMFCs as they reached maturity, but
SOFCs remained eligible for subsidies until FY2020 (March 2021).

The Korean Ministry of Trade, Industry and Energy is currently
subsidising fuel cells (as well as solar power and heat, andgeothermal and wind energy) to power residential and commercial
buildings, with subsidies covering up to 80% of equipment
installation costs. As further incentive, the government reduced theprice of grid gas used in fuel cells by 6.5% from typical consumer
prices, both in buildings and at utility scale.
Total installed stationary fuel cell capacity within buildings was
15.7 MWe in 2021 according to CEM H2I surveys, largely PEMFC
units with capacities ranging from 600 W to 10 kW for residential
and commercial buildings. Doosan and S-FuelCell dominate themarket, and market attention is shifting towards SOFC units and theuse of fuel cells (equivalent to battery power) to boost flexibility inthe electricity grid. The Hydrogen Economy Roadmap of Korea
targets the cumulative installation of at least 2.1 GWe of stationary
fuel cells by 2040.

In 2020, to support the next phase of subsidiary projects and showthat fuel cells can be a source for Japan’s electricity market, 300 kW
of domestic fuel cells were successfully tested to generate electricity
at prices similar to those of the electricity retailer. Decarbonisingbuildings will require a fuel shift for fuel cells, from natural gas to
low-carbon gases (such as hydrogen or synthetic methane
produced with CO2 from sustainable sources). Already Panasonic is
deploying pure hydrogen fuel cell generators to power streetlights
and air conditioning units at the HARUMI FLAG residential complex
in Tokyo.

EuropeIn both the Announced Pledges and Net zero Emissions scenarios,
fuel cells in the Japanese market operating on pure hydrogen reach~1 million installed units by 2030, requiring the development ofhydrogen infrastructure.

Several European countries are testing fuel cell applications andexploring the technical feasibility of hydrogen blending or purehydrogen for buildings sector applications. Demonstration projects

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are ongoing to verify the technology and gain the technicalexperience necessary to build a regulatory framework.

according to CEM H2I. Of the >1 000 units demonstrated by theEne.field project, >750 were installed in Germany.

To date, stationary fuel cell deployment for buildings has been
concentrated primarily in domestic units (commercial and industrial
systems are less common). The market for fuel cells for residential
applications has been supported mainly by projects co-funded by
the FCH JU and the European Union, and by the German KfW 433
programme, which aims to enable manufacturers to eventuallyindustrialise this technology.

Fuel cell ramp-up was spurred by Germany’s KfW 433 programme,
launched in 2016 by the Federal Ministry for Economics and Energy
and still ongoing. The programme provides a combination of grants
and output-related subsidies of up to USD 3 400 for units with acapacity of 250 W to 5 KWe, in both new and existing residential andnon-residential buildings.

The Netherlands

The ene.field project (concluded in 2017) deployed >1 000 small
fuel cell applications (~1.15 MWe operating on natural gas) in ten
countries, in different climates and dwelling types. The subsequent
PACE (Pathway to a Competitive European Fuel Cell microCogeneration Market) project aims to deploy >2 800 fuels cells by
2021. In the framework of this project, nearly 740 units were
installed in Belgium and more than 710 in Germany.

Although the Netherlands has traditionally relied heavily on natural
gas for residential heat, in 2018 the Gas Act was amended to ban
gas connections for new homes and buildings. Subsequently, theNatural Gas-Free Districts Programme was implemented to help thecountry become natural gas-free by 2050. Forty-six municipalities
are currently participating as test sites and to map how the transition
can be scaled up, with a total of 1.5 million homes to shift fromnatural gas to low-carbon heating by 2030.

Commercial-scale units (10-60 kW) are currently being
demonstrated through the EU-funded ComSos project, which
focuses solely on SOFC units and aims to install 25 in nonresidential buildings such as supermarkets.

The Netherlands’ Government Strategy on Hydrogen and GreenGas Roadmap aim to accelerate large-scale production and use of
low-carbon hydrogen and biogas, with the government supporting
pilot projects to demonstrate hydrogen. Meanwhile, the Green Deal
H2 Neighbourhoods project aims to improve understanding of thetechno-economic, safety, social, legal and administrative aspects ofusing existing gas infrastructure for hydrogen distribution.

GermanyWith >15 000 units operating, Germany has been the mostsuccessful market for stationary fuel cell installations in Europe,
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Pilot projects in Hoogeven (100 new buildings and 427 existinghouseholds converted to run on hydrogen for heating) and Stad aan't Haringvliet (600 existing buildings disconnected from natural gas
by 2025) will help identify barriers and operational needs to scale
up hydrogen use in buildings.

is transported to Orkney, where it is used to demonstrate several
end-use applications, including heating in buildings. The project isfunded by the FCH JU and involves 12 partners from the United
Kingdom, Italy, France, Denmark, Spain and Malta.

United Kingdom
Driving low-carbon hydrogen growth is part of the UK government’s
Ten Point Plan for a Green Industrial Revolution. To support thebuildings sector, it proposes a timescale to have hydrogen heating
trials in a neighbourhood by 2023 and to launch larger village trials
by 2025, which could lead to a hydrogen town by the end of thedecade. Completion of testing to support up to 20% hydrogen
injection in the gas network for all homes by 2023 is among the
project’s target milestones.
In addition to the Hy4Heat and H21 projects (see above), the H100
Fife project (Scotland) intends to deliver an end-to-end 100%hydrogen demonstration using the gas network, to prove its
technical viability. Initially, some 300 domestic properties aretargeted to be connected and operational for 4.5 years (i.e. until
2027), with each provided with boilers, cookers and hobs.
Another demonstration, the BIG HIT project (Building Innovative
Green Hydrogen Systems in Isolated Territories, 2016-2022), isunder way in the Orkney Islands (Scotland). Hydrogen produced
from local curtailed renewable energy generation on smaller islands
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Outlook for hydrogen in building applications
At present, the main markets for fuel cell deployment in buildings are
Japan, Europe and Korea, the last having a target of 2.1 GWe
installed by 2040 and focusing mostly on fuel cells for power
applications. In these markets, fuel cell deployment is not focused
explicitly on hydrogen but more broadly on scaling up and reducing
the capital costs of these systems.

range might be broader than for electric heat pumps due to the wide
variability of efficiencies and capital cost of hydrogen equipment.

Hydrogen uptake in buildings will depend on many factors, including
equipment, infrastructure and hydrogen production costs.
Competition among direct electrification, hydrogen and district
heating affects other factors such as the retrofit potential of buildings;
building footprints and heat demand densities; hydrogen andelectricity prices in relation to equipment costs; consumer
preferences; the potential to supply hydrogen; and requirements forrenewable capacity. The flexibility and demand-response potentialthat hydrogen could provide to energy systems are also key
considerations.

4

2000

Hydrogen equipment

2

1000

Average annual cost (USD/yr)

Hydrogen price (USD/kg)

Potential spread of competitive hydrogen prices and annual cost
per household of running heating equipment in selected regionsin the Announced Pledges Scenario, 2030

Electric heat pumps

0

North America

UK

Korea

EU

Japan

0

Price competitive with electric heat pumps (left axis)

In the Announced Pledges Scenario, in major markets hydrogen
would need to be priced at USD 0.9-3.5/kg in 2030 to compete withelectric heat pumps in buildings. Assuming these price ranges andconsidering the capital costs of equipment and of using hydrogenequipment in existing buildings, the cost to heat a home of 100 m2
could range from USD 350/yr to USD 2 000/yr in those markets. This

Annual cost, heat pumps (right axis)
Annual cost, hydrogen equipment (right axis)

IEA. All rights reserved.
Note: Techno-economic assumptions available in the Annex.

Demonstration projects over the next decade will be vital to definecost uncertainties and better understand the implications of using
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hydrogen in buildings, ultimately helping to shape solutions for the
direct use of pure hydrogen. Testing in dense urban centres will beneeded to understand potential barriers, overcome operational
constraints, address consumer safety concerns and train operators.

Scenario – as larger economies of scale, higher efficiency rates andmore developed electricity demand management options are
deployed.
In the Net zero Emissions Scenario, hydrogen accounts for 3.5% of
final energy use for heating in 2030. Due to its lower efficiency,
however, hydrogen meets slightly more than 5% of global heatingneeds in 2050.

In the Announced Pledges Scenario, heating demand in 2030 is 20%
lower than in 2020 thanks to better building envelopes and enhanced
equipment efficiency. In parallel, hydrogen demand grows to morethan 2 Mt H2 (around 0.5% of global heat demand) but remains
limited as planned actions are not strong enough to accelerate
blending in gas networks.

Mt H₂

With pure hydrogen applications making inroads post-2030, thisshare jumps to 5% by 2050. Almost all installations are in existingbuildings and are largely aligned with retrofits to ensure that replacing
conventional fossil fuel-fired equipment with heat-driven units has
minimal impact on building structure and heating distribution
systems.
Hydrogen blending rates ramp up much more rapidly by 2050 in the
Net zero Emissions than in the Announced Pledges Scenario. Due to
its limited decarbonisation potential, blended hydrogen volumes ingas networks decrease after 2030 at the same time as most gas
furnaces and boilers are phased out.

20

10%

16

8%

12

6%

8

4%

4

2%

0

APS
2020

Pure hydrogen

NZE
2030

Blended hydrogen

APS

NZE

Share of heat demand (%)

Hydrogen use in buildings and shares of heat demand in the
Announced Pledges and Net zero Emissions scenarios,
2020-2050

0%

2050

Share of heat demand
IEA. All rights reserved.

Notes: APS = Announced Pledges Scenario. NZE = Net zero Emissions Scenario.

In 2050, pure hydrogen makes up 95% of hydrogen demand inbuildings – in absolute value lower than in the Announced Pledges

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Electricity generation

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Greater hydrogen penetration can help expand renewable electricity generation
drive up NOx emissions, requiring a larger or more efficient selective
catalytic reduction (SCR) system to avoid them. Dry, low-emission
combustion systems are an alternative to minimise NOx emissions
from hydrogen in gas turbines, and systems with up to 50% hydrogen
blends have been demonstrated.

Current uses of hydrogen in the power sector
Hydrogen use in power generation is negligible at present. It
accounts for less than 0.2% of the electricity supply, linked mostly tothe use of mixed gases with high hydrogen content from the steel
industry, petrochemical plants and refineries, and to the use of byproduct pure hydrogen from the chlorine-alkali industry. 24

Fuel cells can convert hydrogen into electricity and heat, producing
water but no direct emissions. Fuel cell systems can achieve highelectrical efficiencies (over 60%) and can maintain high efficiency
even operating at part load, making them particularly attractive forflexible operations such as load balancing.

Hydrogen can be used as fuel in reciprocating gas engines and gas
turbines. Today’s reciprocating gas engines can handle gases with ahydrogen content of up to 70% (on a volumetric basis), and various
manufacturers have demonstrated engines using 100% hydrogenthat should be commercially available in upcoming years.

The main fuel cell technologies for electricity and heat generation are:Gas turbines can also run on hydrogen-rich gases. In Korea, a45-MW gas turbine at a refinery has been operating on gases of up
to 95% hydrogen for 20 years. Manufacturers are therefore confident
of delivering standard gas turbines that can run on pure hydrogen by
2030.
A key consideration, however, is that as hydrogen generates a higher
combustion temperature than natural gas, its use in gas turbines canThough mentioned here, the hydrogen content of mixed gases and by-product hydrogen from thechlorine-alkali industry are generally not included in hydrogen supply and demand presented in thisreport.

24

PAGE | 99

Polymer electrolyte membrane fuel cells (PEMFCs), which operate
at low temperatures and are used as micro-cogeneration units.

Phosphoric acid fuel cells (PAFCs), used as stationary power
generators with outputs in the range of 100-400 kW.

Molten carbonate fuel cells (MCFCs) and solid oxide fuel cells(SOFCs), which operate at higher temperatures (600°C and800-1 000°C, respectively) and can be used for heating and cooling inbuildings and industry.

Hydrogen demand

Global Hydrogen Review 2021



Alkaline fuel cells (AFCs), which operate at low temperatures and canbe used in stationary applications, although very few units have been
deployed to date.

Global installed capacity of stationary fuel cells has grown rapidly
over the past ten years, reaching ~2.2 GW in 2020. At present, only
150 MW use hydrogen as fuel; most run on natural gas. Of the468 000 units installed globally, micro-cogeneration systems
dominate. Japan’s ENE-FARM initiative accounts for the majority,with 350 000 such systems.

Ammonia could also become a low-carbon fuel option for the power
sector, either through imports to countries with limited options for lowcarbon dispatchable generation or by being used as a medium tostore electricity over longer periods to balance seasonal variations inrenewable electricity supplies or electricity demand. Ammonia can beconverted to hydrogen for use in gas turbines, used directly in internal
combustion engines or fuel cells (AFCs and SOFCs), or fed into coal
power plants in a co-firing arrangement.

MW

Stationary fuel cell capacity deployment, 2016-2023
1 000

RoW

800

EU
US

600

Japan

400

Korea
Planned200
02016 2017 2018 2019 2020 2021 2022 2023
IEA. All rights reserved.

Notes: EU = European Union; RoW = rest of world: US = United States. Data for 2020
estimated based on Q1-Q3 information. Planned capacity (2021-23) based on capacity
increases and historic trends.
Source: E4tech.

Stationary fuel cells can also provide backup power (e.g. for data
centres and hospitals) and off-grid electricity, applications thatcurrently rely on diesel generators. As switching to fuel cells can
reduce local air pollution and eliminate the need to potentially importdiesel, many countries use fuel cells with a capacity of a few kW,
fuelled by methanol, liquefied petroleum gas (LPG) or ammonia, as
backup or off-grid electricity for radio and telecom towers. In 2020,
Ballard Power was awarded a contract for 500 fuel cell systems for
digital radio towers in Germany to ensure backup power for 72 hours.

Co-firing a 1% share of ammonia was successfully demonstrated by
Chugoku Electric Power Corporation (Japan) at a commercial coalfired power station in 2017. JERA, Japan’s largest utility company,
has started work on demonstrating a 20% co-firing share of ammonia
at a 1-GW coal-fired unit, with the aim of completing tests by 2025.
To date, the direct use of ammonia has been successfully
demonstrated only in micro gas turbines (up to 300 kW capacity). Its

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low combustion speed and flame stability issues have been identified
as barriers to using ammonia in larger gas turbines (along withincreased NOx emissions). However, Mitsubishi Power recently
announced plans to commercialise a 40-MW gas turbine directly
combusting 100% ammonia by around 2025.

hydrogen and then into ammonia for storage. The stored ammonia
was later burned in an internal combustion engine as needed to
produce electricity.

Hydrogen and hydrogen-based fuels (such as ammonia and liquidorganic hydrogen carriers) also offer seasonal and large-scalestorage options for the power sector. While being immensely morecost-effective, these options have low round-trip efficiencies (around40%) compared with batteries (around 85%), limiting their use forstoring energy over longer periods.

Very few countries have explicit targets for using hydrogen orhydrogen-based fuels in the power sector. Japan is one of the
exceptions: it aims to use 0.3 Mt H2/yr in electricity generation by
2030, corresponding to 1 GW of power capacity, rising to
5-10 Mt H2/yr (15-30 GW) in the longer term. Meanwhile, Korea’shydrogen roadmap targets 1.5 GW of installed fuel cell capacity inthe power sector by 2022 and 8 GW by 2040.

Salt caverns, being well sealed and having low contamination risk,
are already used to store pure hydrogen underground (seeChapter Infrastructure and trade). Alternately, hydrogen-based fuels(e.g. ammonia) can be used for storage in regions lacking access tosalt caverns – i.e. surplus electricity can be converted to ammonia,
which can be burned in power plants when solar PV and wind
generation drop.

Several countries recognise hydrogen’s potential as a low-carbon
option for co-generation and for providing flexibility as they reach highshares of variable renewable power. Germany’s National Hydrogen
Council’s action plan envisions 0.6 Mt H2 of power sector hydrogen
demand by 2030, increasing to 9 Mt H2 by 2040.

Another option is the large, refrigerated liquid ammonia tanks (e.g.
50-m diameter and 30-m height) typically used in the fertiliser
industry, which can store 150 GWh of energy, comparable to theannual electricity consumption of a city of 100 000. Siemens
demonstrated the use of ammonia for electricity storage in 2018 in
the United Kingdom, using electrolysis to convert wind electricity into

Future hydrogen trends

Co‐firing with hydrogen and ammonia can be a means to reduce theemissions of existing gas- and coal-fired power plants in the nearterm. In the longer term, as variable renewable energy shares
increase, hydrogen- and ammonia-fired power plants can be a lowcarbon flexibility option.
Capacity linked to hydrogen-based fuels reaches 30 GW by 2030 and
480 GW by 2050 in the Announced Pledges Scenario, and 140 GW

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(by 2030) and 1 850 GW (by 2050) in the Net zero Emissions
Scenario. Still, in 2050, hydrogen-based fuels account for only 1-2%of total global generation in the two scenarios. With modest additional
investments (but relatively high fuel costs), co-firing of hydrogenbased fuels is targeted towards reinforcing power system stability andflexibility rather than providing bulk power.

.

Hydrogen- and ammonia-fired electricity generation capacity in the Announced Pledges and Net zero Emissions scenarios, 2020-2050

IEA. All rights reserved.
Notes: APS = Announced Pledges Scenario. NZE = Net zero Emissions Scenario.

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Hydrogen demand

Global Hydrogen Review 2021

Economic analysis of co-firing hydrogen and ammonia in fossil fuel power plants
Break-even ammonia price for an existing coal power plant, 2030

2.0

400

1.8

USD/tonne NH3

USD/kg H₂

Break-even hydrogen price for an existing natural gas power
plant, 2030

350

1.6

300

1.4

250

1.2
1.0

200

0.8
0.6
0.4
0.2
0.0
10%

150
CO₂ price USD 130/tCO₂
CO₂ price USD 80/tCO₂
20%
30%
40%
50%
60%
Existing NGCC plant capacity factor

100

CO₂ price USD 130/tCO₂

50

CO₂ price USD 80/tCO₂

0
10%

70%

20%
30%
40%
50%
60%
Existing coal plant capacity factor

70%

IEA. All rights reserved.
Notes: NGCC = natural gas combined cycle. Techno-economic assumptions available in the Annex.

PAGE | 103

Hydrogen demand

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In some cases, fuel transport costs also affect overall co-firing costs
significantly. This is especially the case for waterborne transport ofhydrogen, which is currently at a low technology readiness level andrequires expensive preparation (e.g. liquefaction). Similar cost
impacts are associated with transporting natural gas as liquefied
natural gas (LNG), although they are moderated somewhat by thewider availability of large-scale LNG tankers and the higher
liquefaction temperature of natural gas (compared with hydrogen),which requires less energy.
Ammonia (compared with hydrogen and natural gas) has the highest
vaporisation temperature, and the commercial availability ofammonia ship carriers makes transport costs lower. Althoughconverting hydrogen to ammonia incurs thermal losses and greater
capital investment, if marine transport is required, the higher levelised
cost of ammonia (compared with hydrogen) can be offset (in part or
fully) by lower transportation costs.
Despite the costliness of low-carbon hydrogen and ammonia, highcarbon prices can largely counterbalance the additional cost of
co-firing by reducing CO2 emissions and associated carbon pricepenalties. This is especially the case for existing coal-fired plants.
The IEA’s forthcoming report The Role of Low-Carbon Fuels in Clean
Energy Transitions of the Power Sector will provide more details on
the potential use of hydrogen and ammonia in electricity generation.

Existing thermal power plants’ levelised cost of energy withco-firing, 2030
USD/MWhA basic condition must be met to make switching to low-carbon fueleconomically attractive for existing thermal power plants: thecombined cost of required plant modifications and of low-carbon fuelmust be lower than the combined cost of the fossil fuel and any
penalties for CO2 emissions from combustion. Due to coal’s higher
carbon content, coal plants are more sensitive to carbon prices thannatural gas plants, but both cases would require very high carbon
prices and/or cheap low-carbon fuels to incentivise a switch. Whilerelatively small modifications are required to enable co-firing ofhydrogen or ammonia in existing gas or coal power plants, the costof such modifications is more consequential if power plants operate
at low capacity factors. However, the value of the energy produced
can be much higher when operations are similar to peaking plants,
which can compensate for the increased costs.

250

USD 130/tCO₂

200

USD 80/tCO₂

150

Modification

100

OPEX
Shipping

50
0Liquefaction

100% LNG

60% H₂
60% H₂(USD 1.5/kg)(USD 2.5/kg)

Existing gas power plant, CF 15%

Coal

60% NH₃
60% NH₃(USD 300/t) (USD 500/t)

Existing coal power plant, CF 15%

Low-C fuelFossil fuelIEA. All rights reserved.
Notes: LNG = liquefied natural gas. CF = capacity factor. Low-C fuel = low-carbon fuel.
Techno-economic assumptions available in the Annex.

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Electricity sector hydrogen projects under development
Power plant/project

LocationStart-up date

Capacity (MW)Daesan Green
Energy

Korea

2020

50

PAFCs fuelled by by-product hydrogen frompetrochemical industry

Long Ridge Energy
Terminal

US

2021

485

Initially blending 15-20% hydrogen with natural gas at new
CCGT; moving to 100% hydrogen in next 10 years

Netherlands

2023

440

Conversion of existing natural gas-fired CCGT; hydrogenfrom natural gas + CCUS; currently on hold

United Kingdom

2030

1 800

Being developed together with Keadby 3, a natural gasfired power plant + CCUS

JERA-Hekinan

Japan

2024

200

20% co-firing of ammonia in 1-GW Unit 4 of coal-fired
Hekinan power plant

Air Products’
Net zero Hydrogen
Energy Complex

Canadan.a.

n.a.

Hydrogen produced from natural gas-fuelled ATR + CCUS

Ulsan

Korea

2027

270

Conversion of CCGT from natural gas to hydrogen

Hyflexpower

France2023

12

Combining hydrogen production from renewables,hydrogen storage and electricity generation fromhydrogen in a gas turbine

United States

2025

840

Conversion of a 1.8-GW coal power plant into 840-MW
CCGT with gradually increasing hydrogen co-firing, from
30% in 2030 to 100% by 2045

MagnumKeadby Hydrogen

Intermountain Power
Project

Notes: ATR = autothermal reformer. CCGT = combined-cycle gas turbine.

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Description

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Hydrogen supply

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Overview and outlook

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Hydrogen production in 2020
Global hydrogen demand of 90 Mt in 2020 was met almost entirely
by fossil fuel-based hydrogen, with 72 Mt H2 (79%) coming fromdedicated hydrogen production plants. The remainder (21%) was byproduct hydrogen produced in facilities designed primarily for otherproducts, mainly refineries in which the reformation of naphtha into
gasoline results in hydrogen. Pure hydrogen demand, mainly forammonia production and oil refining, accounted for 72 Mt H2, while
18 Mt H2 was mixed with other gases and used for methanol
production and DRI steel production.

of Indonesia and the United Kingdom combined. For a clean energy
transition, emissions from hydrogen production must be reduced.

Sources of hydrogen production, 2020

By-product21%

Natural gas is the main fuel for hydrogen production, with steam
methane reformation being the dominant method in the ammonia andmethanol industries, as well as in refineries. Using 240 bcm (6% of
global demand in 2020), natural gas accounted for 60% of annual
global hydrogen production, while 115 Mtce of coal (2% of global
demand) accounted for 19% of hydrogen production, reflecting its
dominant role in China. Oil and electricity fuelled the remainder ofdedicated production.
The dominance of fossil fuels made hydrogen production responsible
for almost 900 Mt of direct CO2 emissions in 2020 25 (2.5% of global
CO2 emissions in energy and industry), equivalent to the emissions

90 Mt H2Coal
19%

Natural gas w/o CCUS
59%

Oil
0.6%
Fossil fuels w/ CCUS
0.7%

IEA. All rights reserved.
Note: CCUS = carbon capture, utilisation and storage.

25

This includes 265 Mt CO2 emitted through the use of hydrogen-derived products(e.g. urea and methanol) that capture carbon only temporarily.
PAGE | 108

Hydrogen supply

Global Hydrogen Review 2021

Various technology options exist to produce low-carbon hydrogen:from water and electricity via electrolysis; from fossil fuels with carbon
capture, utilisation and storage (CCUS); and from bioenergy via
biomass gasification. However, they account for very small shares ofglobal production: at 30 kt H2, water electrolysis made up ~0.03%,
and 16 fossil fuel with CCUS plants produced just 0.7 Mt H2 (0.7%).26
Water demand for hydrogen production
In addition to energy, hydrogen production requires water. Water
electrolysis has the smallest water footprint, using about 9 kg ofwater per kg of hydrogen. Production from natural gas with
CCUS pushes water use to 13-18 kg H2O/kg H2, while coalgasification jumps to 40-85 kg H2O/kg H2, depending on water
consumption for coal mining.
In the Net zero Emissions Scenario, global water demand forhydrogen production reaches 5 800 mcm, corresponding to 12%of the energy sector’s current water consumption. While total
water demand for hydrogen production is rather low, individual
large-scale hydrogen production plants can be significant
consumers of fresh water at the local level, especially in waterstressed regions.
Using seawater could become an alternative in coastal areas.
While reverse osmosis for desalination requires 3-4 kWh of

These include facilities that produce pure hydrogen and capture CO2 for geological storage or
sale; CO2 captured from ammonia plants for use in urea manufacturing is excluded.

26

PAGE | 109

electricity per m3 of water, costing around USD 0.70-2.50 per m3,
this has only a minor impact on the total cost of water electrolysis,
increasing total hydrogen production costs by just
USD 0.01-0.02/kg H2. As the direct use of seawater inelectrolysis currently corrodes equipment and produces chlorine,
various research projects are investigating ways to make it easier
to use seawater in electrolysis in the future.

Hydrogen supply

Global Hydrogen Review 2021

Low-carbon hydrogen production projects are multiplying rapidly, but fall short of climate
ambitionsElectrolysis and fossil fuel + CCUS hydrogen production in the
Projects case, Announced Pledges and Net zero Emissions
scenarios, 2030

Although production from electrolysers falls far short of the 12 Mt H2
needed in the Announced Pledges Scenario in 2030, the 9 Mt H2from natural gas with CCUS is on target. Together, however,expected production from planned projects is only two-thirds of whatis needed. This gap widens significantly in the Net zero Emissions
Scenario, which requires electrolytic hydrogen production of
80 Mt H2 and 60 Mt H2 from natural gas with CCUS in 2030.
Nevertheless, more projects are likely to be developed in upcoming
years, reducing shortcomings of the current project pipeline.

Mt H₂

Judging by projects under construction or planned, low-carbonhydrogen production could grow rapidly to 2030. 27 Some 350
projects could push electrolytic hydrogen production to 5 Mt H2,
while 56 projects for fossil fuels with CCUS could reach 9 Mt H2(including the 16 existing plants). Taking into account another 40
projects at an early development stage, electrolytic hydrogenproduction could reach 8 Mt H2 by 2030.

140

80%

120

70%

100

60%

Electrolysis

50%

80

40%

60

30%

40

Fossil with CCUS

20%

20

10%

0

0%

Projects

APS
2030

NZE

Share of electrolysis
and fossil fuels with
CCUS in total
production (right axis)
IEA. All rights reserved.

Notes: APS = Announced Pledges Scenario. NZE = Net zero Emissions Scenario.
CCUS = carbon capture, utilisation and storage. Hydrogen from fossil fuels with CCUS
does not include production that uses the CO2 to produce urea; this production totals
13 Mt H2 in 2030 in both the APS and NZE.

27
If not otherwise specified, planned projects are those for which a final investment decision (FID)
has been taken or a feasibility study is in progress.

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Hydrogen supply

Global Hydrogen Review 2021

By 2050, global hydrogen production reaches 250 Mt H2 in the
Announced Pledges Scenario, with 51% provided by electrolysis,
15% by fossil fuels with CCUS and the remainder by fossil fuels
without CCUS. This corresponds to global electrolyser capacity of
1 350 GW and the capture of 0.4 Gt CO2/yr.
In the Net zero Emissions Scenario, global production doubles
compared to the Announced Pledges Scenario, with shares of 60%
from electrolysis and 36% from fossil fuels with CCUS as installed
electrolyser capacity reaches 3 600 GW and the capture rate climbs
to 1.5 Gt CO2/yr. Notably, this corresponds to electricity consumptionof almost 15 000 TWh (20% of global generation) and 925 bcm ofnatural gas (50% of global natural gas demand).

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Decarbonising hydrogen production will require rapid electrolysis and CCUS roll-out

APS - Hydrogen production

500

400

300

300

200

200

100

100
2020

2025

2030

2035

2040

2045

4 000

FossilAPS - Electrolyser capacity

3 000

0

2050
Fossil with CCU

GW

GW

By-product in refineries

4 000

1 000

1 000

2 000

2025

2030

2035

2040

2045

1 500

0

2050

APS - CO2 captured and stored

500

500
2025

2030

2035

2040

2045

0

2050

2030

2035

Electrolysis

2040

2045

2050

Biomass

2025

2030

2035

2040

2045

2050

NZE - CO2 captured and stored

1 500
1 000

2020

2020

2 000

1 000

0

2025

NZE - Electrolyser capacity

3 000
2 000

2020

2020

Fossil with CCS

2 000

0

NZE - Hydrogen production

500

400

0

Mt CO2

600

Mt H₂

600

Mt CO2Mt H₂Global hydrogen production, installed electrolysis capacity and CO2 captured and stored in the Announced Pledges and Net zero
Emissions scenarios

2020

2025

2030

2035

2040

2045

2050

IEA. All rights reserved.
Notes: APS = Announced Pledges Scenario. NZE = Net zero Emissions Scenario. CCS = carbon capture and storage; CCU = carbon capture and use. Hydrogen production from fossil
fuels with CCU refers to ammonia production in which captured CO2 is used to produce urea fertiliser. When urea fertiliser is applied to soil, it breaks down again into ammonia andCO2, with the latter released into the atmosphere.
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The cost challenge of low-carbon hydrogen
Levelised cost of hydrogen production by technology in 2020,
and in the Net zero Emissions Scenario, 2030 and 2050

As both renewable electricity and electrolyser costs fall, however, theprice gap between production methods is expected to shrink quickly.
Pricing CO2 emissions (e.g. through carbon prices) could further
narrow the gap by pushing up the cost of hydrogen produced fromfossil fuels. For example, a carbon price of USD 100/t CO2
corresponds to a cost increase of USD 0.90/kg H2 for natural gasbased production without CCUS, or USD 2.00/kg H2 for coalgasification without CCUS.
At high capture rates (90-95%), the impact of CO2 prices on hydrogenproduction costs from fossil fuels with CCUS can be drasticallyreduced. Depending on gas prices, natural gas with CCUS entails a
production cost of USD 1.00-2.00/kg H2 – about USD 0.50/kg H2higher than without CCUS. A CO2 price of USD 70/t CO2 would
therefore be needed to close this cost gap.

USD/kg H₂

In most parts of the world, producing hydrogen from fossil fuels iscurrently the lowest-cost option. Depending on regional gas prices,
the levelised cost of hydrogen produced from natural gas is in therange of USD 0.50-1.70/kg H2. Using renewables is much costlier inmost places, at USD 3.00-8.00/kg H2. In fact, renewable electricity
costs can make up 50-90% of total production expenses, depending
on both electricity costs and the full-load hours of the renewableelectricity supply.

9
8
7
6
5
4
3
2
1
0

2020

2030

2050

Natural gas w/o
CCUS

2020

2030

2050

Natural gas w/ CCUS

2020

2030

2050

Coal w/o CCUS

2020

2030

2050

Coal w/ CCUS

2020

2030

2050

Renewables

IEA. All rights reserved.
Notes: CCUS = carbon capture, utilisation and storage. Ranges of production costestimates reflect regional variations in costs and renewable resource conditions.
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).

Meanwhile, reducing the cost of low-carbon electricity will be criticalto bring down the expense of producing hydrogen from electrolysis.
Hydrogen production costs of USD 1.00/kg H2 – the 2030 goal of the
US Hydrogen Earthshot initiative – translate into electricity prices of
USD 20/MWh, without any CAPEX or fixed OPEX (at 70% efficiency,
lower heating value). To reach this targeted hydrogen production
cost, electricity prices must therefore be sufficiently below
USD 20/MWh to allow for additional CAPEX and OPEX costs.

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Global Hydrogen Review 2021

In regions with good solar resources – and thus relatively high fullload hours for the electrolyser – solar PV can fall below this costthreshold. In fact, tenders for utility-scale solar PV in the Middle East
in 2019 and 2020 secured bids of USD 14-17/MWh (though theseprices are very market-specific and reflect favourable financing
conditions).
Furthermore, technology improvements to boost electrolyser
efficiency moderate how electricity costs affect hydrogen production
costs. Efficiency improvements are not limited to the electrolyser
itself; optimising components such as rectifiers and inverters for
anticipated operation at part load (i.e. not nominal load) is vital if
variable renewables are the main electricity source. The projected
cost of hydrogen production after 2030 is therefore very uncertain
and will depend on the impacts of scaling up, learning by doing andother technological progress.

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Electrolysis

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Electrolysis deployment is expanding quickly
Global installed electrolysis capacity by region and technology,
2015-2020

Water electrolysis is an electrochemical process that uses electricity
to split water (H2O) into hydrogen (H2) and oxygen (O2). In 2020, thisprocess accounted for ~0.03% of hydrogen production for energy andchemical feedstocks. 28 Of installed global electrolyser capacity of
290 MW, more than 40% is based in Europe with the next-largest
capacity shares in Canada (9%) and China (8%).
Four main electrolyser technologies exist today: alkaline; proton
exchange membrane (PEM); solid oxide electrolysis cells (SOECs);
and anion exchange membranes (AEMs) (see Emerging
Technologies below for more on SOECs and AEMs). Alkaline
electrolysers dominate with 61% of installed capacity in 2020, while
PEMs have a 31% share. The remaining capacity is of unspecified
electrolyser technology and SOECs (installed capacity of 0.8 MW).
Used since the 1920s for hydrogen production in the fertiliser andchlorine industries, alkaline electrolysis is a mature commercial
technology. The operating range of alkaline electrolysers covers aminimum load of 10% to full design capacity. As they do not requireprecious materials, capital costs are relatively low compared withother electrolyser technologies.

IEA. All rights reserved.
Notes: PEM = proton exchange membrane; SOEC = solid oxide electrolysis cell.
Source: IEA (2021), Hydrogen Projects Database.

The area requirements of PEM electrolyser systems are relatively
small, making them potentially more attractive than alkaline
electrolysers in dense urban or industrial areas. Current materials forelectrode catalysts (platinum, iridium), bipolar plates (titanium) andmembrane materials are expensive, however, so overall costs for28
If not otherwise specified, electrolysis refers to water electrolysis, i.e. excluding chlor-alkali
electrolysis.

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New installed electrolyser capacity based on projects underconstruction or planned, 2021-2030

PEMs (USD 1 750/kW) are higher than for alkaline electrolysers(USD 1 000-1 400/kW). Additionally, PEM systems currently have ashorter lifespan.
By 2030, global installed electrolyser capacity could climb to 54 GW,
given capacity under construction and planned. If all projects at thevery early planning stages are counted, capacity could even reach
91 GW by 2030. Geographically, Europe and Australia lead with
22 GW 29 and 21 GW of projects under construction or planned,
followed by Latin America (5 GW) and the Middle East (3 GW).
Many projects are linked to renewables as a dedicated electricity
source, and around a dozen demonstration projects (combined
electrolyser capacity of 250 MW) explore using nuclear power forhydrogen production (Canada, China, Russia, the United Kingdom
and the United States). Not all these projects will be realised,however. So far, only 4 GW (7%) are linked to projects underconstruction or with a final investment decision, leaving 50 GW still at
various earlier stages of development (e.g. at the front-end
engineering design, feasibility study and concept phases).

IEA. All rights reserved.
Notes: Based on ~350 projects under construction or planned. Only projects with aknown start year of operation are considered.
Source: IEA (2021), Hydrogen Projects Database.

As global electrolyser capacity scales up, the average project size
increases. Notably, the average of 0.6 MW in 2020 includes thelargest alkaline electrolyser plant in operation (the 25-MW Industrial
Cachimayo plant in Peru, which is connected to the electricity grid)and the largest PEM electrolyser plant in operation using dedicatedrenewables (20 MW using hydropower, inaugurated in 2020 by Air
Liquide in Bécancour, Canada).

29
For Europe, some projects with unknown completion dates (e.g. the 67-GW HyDeal project) are
not included. If realised, they could push electrolyser capacity well beyond 23 GW by 2030.

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Global Hydrogen Review 2021

Some 80 projects under construction or being planned havecapacities of >100 MW, and 11 projects reach ≥1 GW. The plannedWestern Green Energy Hub (Australia) is in the GW scale: with asolar PV and wind capacity of up to 50 GW, it will produce
3.5 Mt H2/yr for conversion into 20 Mt of ammonia for export. As theaverage project size increases to 230 MW by 2030, economies ofscale and learning effects are expected to bring down electrolyser
costs.

Size of electrolyser projects (existing, under construction and planned), 2010-2030

MW

Plants of less than 1 GW

Plants of more than 1 GW
14 0001 000
900

12 000800
700

10 000

600

8 000

500

6 000

400
300

4 000

200

2 000

100
0
2010

2015

2020

2025

2030

0
2024 2025 2026 2027 2028 2029 2030
IEA. All rights reserved.

Note: Years refer to the planned start of operations; only projects with a known start year are considered.
Source: IEA (2021), Hydrogen Projects Database.
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Global Hydrogen Review 2021

Deployment must accelerate further to meet climate targets
Several countries, as well as the European Union, include
electrolyser capacity deployment goals in their hydrogen strategies.
Together, these pledges could result in installed capacity of 75 GW
by 2030, with the majority linked to the targets of the European Union(40 GW) and Chile (25 GW). However, planned projects do notnecessarily match national or regional targets. In the EU case, only
22 GW are currently under construction or planned – barely half ofthe targeted 40 GW by 2030.
In the Announced Pledges Scenario, global installed electrolyser
capacity increases to 180 GW by 2030, twice as much as nationaltargets and three times the projects under construction and planned,
and still 70% higher when including in the Projects case also projects
at earlier development stages.
In the Net zero Emissions Scenario, capacity requirements in 2030
are 850 GW, some nine times the project pipeline when including
projects at early development stages. Despite such significant gaps,
current efforts are a good basis from which to expand and accelerate
deployment, raising ambition as new projects are developed andmore countries build hydrogen into their national strategies.

PAGE | 119

Electrolysis capacity in the Announced Pledges and Net zero
Emissions scenarios in 2030 compared with the current projectpipeline and government deployment pledges

IEA. All rights reserved.

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Global Hydrogen Review 2021

Greater electrolyser deployment will speed cost declines
Projections for hydrogen costs reflect the IEA cost database, recently
updated with input from a range of industry participants under theHydrogen Council and through collaborations with researchers in
China. In 2020, costs fell within the range of USD 1 000-1 750/kW(including electric equipment, gas treatment, plant balancing, andengineering, procurement and construction [EPC]), with the lower
cost applying to alkaline electrolysers produced in China and theupper representing PEM electrolysers.
The cost of alkaline electrolysers in China – USD 750-1 300/kW, withsome sources reporting as low as USD 500/kW 30 – falls well below
the average of USD 1 400/kW in the rest of the world. Althoughconcerns over the reliability and durability of Chinese electrolysers
have been raised in the past, manufacturing is improving quickly. As
recently as a few years ago, Chinese manufacturers had to importseveral components, limiting their ability to reduce costs throughindustrial clustering and economies of scale. Local component
manufacturing is expanding, however, so cost savings should be
realised soon.

approach was used to analyse future electrolyser costs as a functionof cumulative capacity deployment. Based on a literature review, alearning rate of 15% is assumed for the electrolyser stack, which also
takes account of learning rates for fuel cells that rely on the same
electrochemical processes.

Evolution of electrolyser capital costs under the Projects case,Announced Pledges and Net zero Emissions scenarios

IEA. All rights reserved.
Notes: APS = Announced Pledges Scenario. NZE = Net Zero Emissions Scenario.
Sources: Based on data from McKinsey & Company and the Hydrogen Council.

Learning effects in manufacturing and economies of scale will also
drive down electrolyser costs. A component-wise learning-curve

Based on CAPEX for the electrolyser system itself of USD 200/kW (China EV100, 2020; MOST,
2021). Including inverter and EPC the overall CAPEX increases to USD 500/kW.
30)

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The cumulative capacity deployment of projects under construction
and planned would reduce capital expenses by almost 60% by 2030.
With capacity deployment in the Announced Pledges Scenario being
almost triple the current project pipeline, costs may be 65% lower in
2030 than in 2020. This is not very different from the Net zero
Emissions Scenario, for which larger capacity deployment could bring
capital expenses down almost 70% from 2020, to USD 400-440/kW.

A dedicated industrialised supply chain and a corresponding
industrial supplier landscape will be essential to meet capacity
demands to 2030 and beyond. If available soon, this manufacturing
capacity could meet the deployment needs of the current pipeline ofprojects and government pledges (an average of 6-8 GW/y from 2022
to 2030) and approach Announced Pledges Scenario needs(20 GW/yr). But projections still show a shortfall in meeting Net zero
Emissions requirements (>90 GW/yr).

Shortfalls in electrolysis manufacturing capacity could impede
deployment of all projects currently under development, which could
derail long-term government climate ambitions (those reflected in the
Announced Pledges Scenario) and the Net zero Emissions Scenario.
Global electrolysis manufacturing capacity was ~3 GW/yr in 2020,
with alkaline designs accounting for 85% and PEMs for less than
15%, plus some very small, artisanal manufacturing of SOECs and
AEMs.

Increased electrolyser production will affect demand for minerals,particularly nickel and platinum group metals (depending on thetechnology type). While alkaline electrolysis does not requireprecious metals, current designs use 800-1 000 t/MW of nickel. Even
if alkaline electrolysis dominates the market by 2030, in the Net zero
Emissions Scenario this would entail nickel demand of 72 Mt (whichis actually much lower than the amount needed for batteries).

The largest shares of manufacturing capacity are in Europe (60%)
and China (35%). Interest in the technology is growing among major
companies such as Thyssenkrupp, Nel Hydrogen, ITM, McPhy,
Cummins and John Cockerill, all of which have announced plans to
expand their manufacturing capacities. If all announced expansions
are realised, manufacturing capacity could reach ~20 GW/yr, withprocess automation or improved procurement driving down
manufacturing costs.

The catalysts in PEM electrolysers require 300 kg of platinum and
700 kg of iridium per GW. Therefore, if PEMs supplied all electrolyser
production in 2030 in the Net zero Emissions Scenario, demand for
iridium would skyrocket to 63 kt, nine times current global production.
Experts believe, however, that demand for both iridium and platinum
can be reduced by a factor of ten in the coming decade. Recycling
PEM electrolyser cells can further reduce primary demand for these
metals and should be a core element of cell design.

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Meanwhile, SOEC production requires nickel (150-200 t/GW),
zirconium (40 t/GW), lanthanum (20 t/GW) and yttrium (<5 t/GW).
Better design in the next decade is expected to halve each of thesequantities, with technical potential to drop nickel content to below
10 t/GW. Due to the higher electrical efficiency of SOECs, thesemineral requirements are not directly comparable with alkaline andPEM electrolysers.

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Low-cost electricity can boost electrolysed hydrogen production
Of the various technical and economic factors that determine howmuch it costs to produce hydrogen from water electrolysis, the most
pertinent are electricity costs, capital expenses, conversion efficiency
and annual operating hours.

the dominant source for hydrogen projects currently underconstruction or being planned.

Hydrogen production costs in the Net zero Emissions Scenario
as a function of renewable electricity costs for solar PV andonshore and offshore wind, 2020, 2030 and 2050

With shares of variable renewables increasing, surplus grid electricity
may be available at low cost to produce hydrogen and to store it forlater use. Unfortunately, even if surplus electricity were available atzero cost for 750 hrs/yr, the hydrogen cost would remain at
USD 3.00/kg H2 (CAPEX of USD 500/kW). Running an electrolyser
solely on surplus grid electricity therefore may not be an economical
way to produce hydrogen and may fail to provide the volumes needed
for some demand cases.
However, co-locating hydrogen production with dedicated electricity
generation from renewables or nuclear power often avoids or
minimises electricity transmission costs. Renewable electricity is thus

USD/kg H2

Electricity costs are the most important consideration, as theyaccount for 50-90% of the overall levelised cost of hydrogenproduction. Using grid electricity is often rather expensive, withelectricity prices of USD 50-100/MWh resulting in hydrogenproduction costs of USD 3.00-5.00/kg H2 (at an electrolyser capacity
factor of 90% and CAPEX of USD 500/kW).

8
7
Onshore wind

6

Offshore wind

5

Solar PV
2020

4

2030

3

2050

2
1
0

0

20

40

60

80

100

120

140

USD/MWh

IEA. All rights reserved.
Notes: Points represent electricity and hydrogen production costs for different regions
around the world, taking local renewable resource conditions into account.
Sources: Based on data from McKinsey & Company and the Hydrogen Council; IRENA(2020).

Solar PV has become one of the most affordable energy sources forelectricity generation. In locations with excellent solar conditions (i.e.
relatively high capacity factors such as the Middle East), solar PV
generation costs can be USD 20/MWh or lower, corresponding to

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Global Hydrogen Review 2021

Levelised cost of hydrogen production from renewables bytechnology and region in the Net zero Emissions Scenario, 2020
and 2050

With solar PV and electrolyser costs declining in the Net zero
Emissions Scenario, hydrogen produced from solar PV in the Middle
East at USD 17/MWh could cost less than USD 1.50/kg H2 in 2030
(at a CAPEX of USD 320/kW), a level comparable to production fromnatural gas with CCUS. By 2050, with a solar PV cost of
USD 12/MWh, hydrogen costs could fall to USD 1.00/kg H2 (CAPEX
of USD 250/kW), making hydrogen from solar PV cost-competitive
with natural gas even without CCUS.

USD/kg H₂hydrogen production costs of USD 3.00/kg H2 (at an electrolyser
capacity factor of 32% and CAPEX of USD 1 000/kW).

12
10
8Solar PV
6

Wind offshore
Wind onshore

4

2020
2050

2
0
Australia

Several projects in Europe target offshore wind as an electricity
source for hydrogen production. In fact, producing hydrogen offshore
and transporting it to shore by pipeline is an alternative to the rather
expensive use of electricity cables. Several current and planned pilot
and demonstration projects (e.g. the Oyster project in Denmark) are
therefore exploring this approach, and the Dutch NorthH2 project
aims to reach 4 GW of offshore electrolysis by 2030 while Germany’s
AquaVentus targets 10 GW by 2035.
Opportunities exist to further reduce costs by repurposing oil and gas
assets, for instance by using platforms for electrolyser installations or
oil and gas pipelines for hydrogen transport. There are still someuncertainties, however, about the suitability of using certain oil andgas assets for these purposes and the challenges of simultaneously
phasing out oil and gas activities while ramping up electrolysis.

China

Chile

Europe

India

Japan

MiddleEast

North
AfricaUnitedStatesIEA. All rights reserved.
Notes: Higher values of the ranges correspond to 2020, lower values to 2050.
Sources: Based on data from McKinsey & Company and the Hydrogen Council; IRENA(2020).

At USD 60/MWh, electricity generation from offshore wind was
relatively costly in 2020, resulting in hydrogen costs of
USD 4.50/kg H2 (at a 50% capacity factor). With declining costs foroffshore electricity generation (USD 30/MWh) and larger turbines
resulting in higher capacity factors (57%), hydrogen production costsin the North Sea in the Net zero Emissions Scenario could fall to
USD 2.00/kg H2 by 2030 and to below USD 1.50/kg H2 by 2050
(based on electricity costing USD 25/MWh and a capacity factor of
60%).

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While production costs using offshore wind in Europe remain higher
than for solar PV in the Middle East or North Africa, accounting forhydrogen transport costs could make sourcing domestic supplies
from offshore wind a more economically feasible option for someparts of Europe.
However, considering solely the levelised cost ignores three otherimportant factors: the number of hours the electrolyser operates; thevolume of hydrogen produced throughout the year; and costs that
may arise from needing to smooth out renewable hydrogen supply
fluctuations (daily or seasonal). While electrolysers can operate quite
flexibly to accommodate the variability of renewable electricity
supplies, downstream hydrogen users (whether consuming it directlyor converting it into other fuels and feedstocks) generally require
supply stability. In such cases, hydrogen storage is likely needed toensure supply constancy.
For the production of hydrogen-based fuels, however, it may be more
economical – despite higher hydrogen production costs and fewer
full-load hours – to choose a renewable electricity supply withvariability patterns that requires less storage, e.g. solar PV (which
typically requires daily storage) over wind power (which often
requires capacity for several days or weeks of storage). Combining
renewable resources in a hybrid plant (e.g. solar PV and onshorewind) may be a cost-effective way to stabilise the hydrogen supply
and achieve higher full-load hours, minimising the volume ofhydrogen storage needed.
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Hydrogen from electrolysis starts to compete with hydrogen from natural gas with CCUS by2030
Hydrogen production cost from hybrid solar PV and wind systems in 2030

IEA. All rights reserved.
Notes: This map is without prejudice to the status of or sovereignty over any territory, to the delimitation of international frontiers and boundaries and to the name of any territory, city or
area. For each location, production were derived by optimising the mix of solar PV, onshore wind and electrolyser capacities, resulting in the lowest costs and including the option tocurtail electricity generation.
Sources: Based on hourly wind data from Copernicus Climate Change Service and hourly solar data from Renewables.ninja.

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Fossil fuels with carbon capture

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Hydrogen production from fossil fuels, and current CCUS status and adoption
Hydrogen produced from natural gas using reforming processes andfrom coal using gasification are well-established technologies. As
noted earlier, these methods dominate hydrogen production and are
the sector’s primary source of CO2 emissions.
CCUS is important in the production of low-carbon hydrogen fromfossil fuels for two reasons. First, it can reduce emissions fromexisting hydrogen plants in the refining and chemical sectors, which
account for 2.5% of global emissions; and second, it is a low-cost
option to scale up production for new hydrogen demand in countries
where the conditions are conducive.
CCUS refers to a suite of diverse technologies expected to beimportant in helping countries meet their energy and climate goals. In
its first stage, CCUS involves the capture of CO2 from large point
sources (including power generation or industrial facilities that use
fossil fuels or biomass for fuel) or directly from the atmosphere.
Many opportunities exist to use CO2 captured through CCUS
technologies. Urea synthesis with CO2 captured at ammonia plants(>130 MtCO2/yr in 2020) is currently the only large-scale application,
but its anticipated future uses include cement and synthetic fuelproduction.

Storage refers the practice of injecting captured CO2 into deep
geological formations (typically depleted oil and gas reservoirs or
saline formations) where it will be permanently absorbed into therock. If not being used at the capture site, CO2 can be compressed
and transported to other facilities by pipeline, ship, rail or truck – foreither use or storage.
Current large-scale CO2 capture capacity for injection into geologicalformations (for dedicated storage and use in enhanced oil recovery)is in the order of 40 MtCO2/yr. Around two-thirds of this capacity is innatural gas processing facilities, with the remainder distributed inroughly equal shares in power generation, synthetic fuel, ammonia
and hydrogen applications, with smaller quantities captured frombioethanol and steel production.
In natural gas-based hydrogen production, steam methane reforming(SMR), the leading production route, creates direct CO2 emissions of
9 kg CO2/kg H2 while upstream methane emissions from natural gas
production and transport can add another 1.9-5.2 kg CO2eq/kg H2(global average of 2.7 kg CO2eq/kg H2), reflecting regionalvariations. Efforts need to be taken to address them. Technologies toreduce upstream methane emissions are already available and areoften cost-effective without additional support.

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Among direct emissions of the SMR process, 30-40% arise fromusing natural gas as the fuel to produce steam and heat, giving rise
to a “diluted” CO2 stream. The rest of the natural gas used in thisprocess is split (with the help of the steam) into hydrogen and moreconcentrated “process” CO2. While capturing CO2 from theconcentrated process stream can reduce overall emissions by 60%,
capturing the more diluted gas stream can boost overall emissions
reductions to 90% or higher. The cost of capturing both combined is
USD 50-70/t CO2.
Autothermal reforming (ATR) is an alternative technology in which theprocess itself produces the required heat. This means that all related
CO2 is produced inside the reactor, resulting in a more concentrated
flue gas stream that, when compared with the SMR process, allows
for higher CO2 capture rates (95% or higher) or for the same capture
rate at lower capture costs.

Traditionally, the process has been deployed where it is possible touse low-value waste products or heavy feedstocks to producehydrogen or syngas (e.g. in refineries).
The technology is available at commercial scale but has been
modified only recently with the express aim of producing hydrogenfrom natural gas with CCUS. Several projects based on POx are
under development and show CO2 capture rates of up to 100%. A
POx hydrogen plant at a Dutch refinery (using oil residues) that has
been operating since 1997 began capturing CO2 in 2005 for use ingreenhouses (at a rate of 0.4 MtCO2/yr, not fully utilising the installed
capture capacity of 1 Mt CO2/yr, which may be exploited by the
Porthos project).

ATR uses oxygen instead of steam, which requires electricity (rather
than methane) as its fuel input. A large share of global ammonia andmethanol production already uses ATR technology, though without
CCUS. Two projects in the United Kingdom – HyNet and H2H Saltend– plan to combine ATR with CCUS.

Meanwhile, coal gasification is a mature technology used mainly inthe chemical industry to produce ammonia, particularly in China. At
20 t CO2/t H2, unabated hydrogen production from coal is very
emissions-intensive. Though some technical challenges remain to be
overcome, coal gasification can be combined with CCUS. However,since gas separation technologies focus on either hydrogen or CO2
removal, few can produce both high-purity hydrogen and CO2 pureenough for other uses or storage.

Partial oxidation (POx) is a technology option that supports hydrogenproduction from gaseous or liquid fuels. The process does not requirea catalyst (unlike ATR) and can accept feedstock impurities. POx
uses oxygen (similar to ATR), requiring electricity as the energy input.

The choice and design of capture technology therefore depends on
the hydrogen end-use and production costs. With the aim of
producing hydrogen for export to Japan, the planned Hydrogen
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Levelised hydrogen production costs from natural gas and coalby region in 2020 and in the Net zero Emissions Scenario in
2050

brown coal using gasification, with CO2 being transported and stored
via the CarbonNet project.
Sixteen projects are currently generating hydrogen from fossil fuelswith CCUS; with annual combined production of just over 0.7 Mt H2,they also capture close to 10 Mt CO2. Ten are commercial-scale
plants with CO2 capture capacity above 0.4 Mt CO2/yr: four are at oil
refineries and three are at fertiliser plants. 31 Notably, six are retrofits
of existing sites, with scales ranging from <100 MWH2 to >1 GWH2,
with 1 GWH2 corresponding to annual production of 0.25 Mt H2.
Planned projects reach a capacity of up to 20 GWH2.
In regions with low-cost domestic coal and natural gas, where CO2
storage is available – e.g. the Middle East, North Africa, Russia andthe United States – the use of fossil fuels with CCUS is currently themost affordable option to produce low-carbon hydrogen andammonia. Depending on local gas prices, costs for producing
hydrogen from natural gas with CCUS were in the range of
USD 1.00-2.00/kg H2 in 2020 – about USD 0.50/kg H2 higher than for
natural gas without CCUS, due to CO2 capture, transport and storage
costs. As the CO2 price penalty on uncaptured CO2 emissions (510%) rises over time, production costs from fossil fuels with CCUS
will increase slightly.

IEA. All rights reserved.
Notes: The lower values of the ranges correspond to 2020, higher values to 2050.
Sources: Based on data from McKinsey & Company and the Hydrogen Council; IEA
GHG (2014); IEA GHG (2017); E4Tech (2015); Kawasaki Heavy Industries;
and Element Energy (2018).

These include facilities that produce pure hydrogen and capture CO2 for geological storage orsale. CO2 captured from ammonia plants for use in urea manufacturing is excluded.

31

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Hydrogen production from fossil fuels with CCUS is gaining momentum
Projects for producing hydrogen from fossil fuels with CCUS, operational or under development

IEA. All rights reserved.
Notes: This map is without prejudice to the status of or sovereignty over any territory, to the delimitation of international frontiers and boundaries and to the name of any territory, city or
area. Mature projects are projects under construction or for which a final investment decision has been taken.
Source: IEA (2021), Hydrogen Projects Database.

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Outlook for hydrogen production with CCUS
Hydrogen production from fossil fuels with CCUS in the
Announced Pledges and Net zero Emissions scenarios,
compared with the project pipeline and government pledges,
2030

Globally, 40 projects for producing hydrogen with CCUS are underdevelopment, with a total of four currently under construction in China
and the United States. Of these, 35 rely on natural gas with CCUS,
four are linked to coal and one to oil. Geographically, Europe hosts
19 projects (largely in the Netherlands and the United Kingdom),
while North America hosts 7 and China has 2.
Based on planned projects and existing plants, global hydrogenproduction from fossil fuels with CCUS could reach 9 Mt by 2030.
While several national strategies and roadmaps consider this a lowcarbon hydrogen production option, almost none define deployment
targets for hydrogen with CCUS, in contrast to electrolysis.
Exceptions are the United Kingdom, with a technology-neutral targetof domestic low-carbon production capacity of 5 GWH2 by 2030, andthe low-carbon supply targets of Japan (420 kt H2) and the Czech
Republic (10 kt H2). Assuming these targets were fulfilled solely byhydrogen production with CCUS, it would correspond to 1.7 Mt H2annually.
Estimated production of 9 Mt H2 in 2030 from planned and existing
plants aligns with the Announced Pledges Scenario. The jump to58 Mt H2 from fossil fuels with CCUS in the Net zero Emissions
Scenario is around seven times the project pipeline, implying that –by 2030 – some 230 hydrogen plants with capacity of 1 GWH2 need
to be newly built or retrofitted with CCUS. While this number may
seem huge, it corresponds to roughly 80% of current unabatedproduction capacity from fossil fuels.

IEA. All rights reserved.
Source: IEA (2021), Hydrogen Projects Database.

Industrial ports – where a large share of unabated fossil hydrogenproduction plants for refining and the petrochemical industry is
located – could become hubs for scaling up hydrogen production. In
addition to offering offshore storage potential, they could share CO2transport and storage infrastructure across different industries,
benefitting from economies of scale that could reduce investment
risks. Active examples are the Port of Rotterdam (Porthos) project

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inthe Netherlands, the Zero Carbon Humber project in the United
Kingdom, and CarbonNet in Australia.

low-carbon hydrogen and biofuels, refining, and LNG; several arelinked to development of regional CCUS and/or hydrogen hubs.

Growing momentum for CCUS
Interest in CCUS is expanding globally, as strengthened climate
commitments – including ambitious net zero targets – fromgovernments and industry drive renewed momentum. In the firsteight months of 2021, more than 40 new commercial projects
were announced, reflecting an improved investment
environment. A variety of CCUS projects are operating or inplanning across several sectors:Industry: CO2 capture is already an integral part of urea
manufacturing and other industrial processes. Deployment is
expanding to chemical products, the steel sector (with onecommercial plant operating) and the cement sector (construction to
retrofit a plant in Norway has commenced).

Electricity and heat: Two coal-fired power plants equipped with
CCUS (in Canada and the United States) have a capture capacityof 2.4 Mt CO2/yr. Globally, plans exist to equip around 30 coal, gas,biomass or hydrogen power facilities with CCUS.



Direct air capture: A number of small pilot and demonstration DAC
plants are currently operating around the world, including some incommercial operation to provide CO2 for beverage carbonation andgreenhouses, and a large-scale (1 Mt/yr) facility is in developmentin the United States.

CCUS technologies and applications are at various stages ofdevelopment. Several capture technologies, such as chemical
absorption of CO2 during hydrogen production in ammonia
plants, are mature and have high (85-90%) average capture
rates (e.g. of CO2 in the gas stream). Boosting capture rates to99%, which would substantially decrease residual emissions
from CCUS operations, is technically possible with minimal
additional cost, but requires incentives such as sufficiently highCO2 prices or low-carbon standards.
As urea applied on soils breaks back down into ammonia andCO2 and synthetic fuels are combusted to extract embedded
energy, it must be noted that CO2 used for urea production or forsynthetic fuels will eventually be released into the atmosphere.
For hydrogen to be considered low-carbon, CO2 captured during

Fuel supply: Most existing commercial CCUS facilities are linked
to natural gas processing, which has relatively low capture costs;
collectively, they currently capture almost 30 Mt CO2/yr. A wide
range of CCUS projects are planned, associated with production of

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production would need to be permanently stored (rather thanused).
A well-selected and well-managed geological storage site canretain stored CO2 for more than 1 000 years, with minimal risk ofleakage. Theoretically, global CO2 storage resources are vast;
however, some reservoirs will not be suitable or accessible. In
many regions, detailed site characterisation is still needed toassess the feasibility and scope of permanent CO2 storage. At
present, a relatively low share of captured CO2 – only 20% the
40 Mt quoted above – is directed into permanent geologicalstorage (80% is used for EOR).

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Hydrogen-based fuels

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Hydrogen-based fuels are often compatible with existing infrastructure, but cost more
New projects to produce hydrogen-based fuels from electrolytichydrogen, by start year

Hydrogen produced through the methods described above has a low
volumetric energy density, which makes it more challenging to store
and transport than fossil fuels. It can, however, be converted intohydrogen-based fuels and feedstocks (e.g. synthetic methane,synthetic liquid fuels and ammonia) that can be transported, stored
and distributed through existing infrastructure for fossil fuels. In fact,some synthetic hydrocarbons from hydrogen can directly substitutefor fossil equivalents. The potential benefits and opportunities ofthese fuels and feedstocks must be weighed against additional
conversion losses and related costs.
In 2020, 81 pilot or demonstration projects were in operation,
converting electrolytic hydrogen into synthetic methane (59),synthetic methanol (7), synthetic diesel or kerosene (7) and ammonia(8).. Geographically, most are in Europe, and most are at a relatively
small scale to demonstrate technologies and supply chains.
Besides hydrogen, synthetic hydrocarbon fuel production requires
CO2 as an input. Initially, the CO2 may be sourced from hard-to-abate
emissions sources. But to ensure the CO2 neutrality of the produced
fuel in the long term, CO2 supplies should be captured at bioenergy
conversion plants or directly from the atmosphere. The Power2Met
project (Denmark) uses CO2 from biogas upgrading, while the Troia
plant (Italy) uses DAC for CO2 to produce synthetic methane.

IEA. All rights reserved.
Notes: FT = Fischer-Tropsch. Figure includes eight synthetic methane and five FT fuelprojects decommissioned before 2020. Ammonia includes projects in the chemicalindustry, where ammonia is used as a feedstock.
Source: IEA (2021), Hydrogen Projects Database.

Several projects planned for upcoming years are expected toadvance to the commercial scale. With an electrolyser capacity of
2 GW, the Haru Oni project for methanol (Chile) has a planned final
production capacity of 550 million litres per year (by 2026). The
Helios Green Fuels project (Saudi Arabia), based on electrolyser
capacity of 1.5-2.0 GW, has a planned annual production capacity of
235 kt hydrogen and 1.2 Mt ammonia.

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In parallel, the focus of projects under construction or planned shifts
from synthetic methane to synthetic liquid fuels (ammonia, methanol
and Fischer-Tropsch fuels), with the last accounting for >90% of
future projects. This may reflect that using hydrogen-based liquid
fuels is an important pathway to decarbonise long-distance transport,
particularly aviation and shipping. In the Net zero Emissions Scenario
in 2050, ammonia covers 45% of global shipping fuel demand while
synthetic kerosene accounts for one-third of global aviation fuelconsumption.
The economics of producing clean ammonia and synthetichydrocarbon fuels depend on various factors, the cost of hydrogen
being key. Fossil fuel and CO2 storage prices will affect the cost of
producing hydrogen using CCUS, whereas for the electrolytichydrogen route, the availability of low-cost and low-carbon electricity
is critical.

USD 120-330/bbl by 2050 in the Net zero Emissions Scenario, whichis still much more expensive than conventional fossil liquid fuels. The
situation for synthetic methane is similar.
To support use of these fuels in parts of the energy system withlimited low-carbon options (e.g. long-distance transport in aviation orshipping), policy measures are needed to close the cost gap by either
pushing up the cost of using of fossil fuels (e.g. CO2 prices) or
incentivising low-carbon fuel use (e.g. clean fuel standards). To closethe cost gap with fossil kerosene at USD 25/bbl, a CO2 price of
USD 230-750/t CO2 would be needed to deliver synthetic liquidhydrocarbon fuels at USD 120-330/bbl.

Levelised cost of ammonia, synthetic methane and synthetic
liquid fuels for electricity-based pathways in the Net zero
Emissions Scenario, 2020, 2030 and 2050

In the case of synthetic hydrocarbon fuels, the availability and cost of
CO2 feedstocks is another important factor. CO2 costs currently
range from USD 30/t CO2 from ethanol plants to USD 150-450/t CO2
from DAC (but as DAC technology is at an early stage ofdevelopment, costs could fall to USD 70-240/t CO2 by 2050). With
CO2 feedstock costs at USD 30-150/t CO2, production costs forsynthetic liquid fuels fall in the range of USD 15-75/bbl.
Current production costs for synthetic liquid hydrocarbon fuels fromelectrolytic hydrogen are in the range of USD 300-700/bbl. With costdeclines for renewable electricity, electrolysers and DAC, they fall to

IEA. All rights reserved.
Sources: Based on data from McKinsey & Company and the Hydrogen Council;
IRENA (2020); Agora (2018); Danish Energy Agency (2021); IFA (2021).

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Emerging technologies

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Hydrogen production technologies of the future hold promise
Solid oxide electrolyser cells (SOECs)
SOECs use steam instead of water for hydrogen production, a key
departure from alkaline and PEM electrolysers. Additionally, as theyuse ceramics as the electrolyte, SOECs have low material costs.
While they operate at high temperatures and with high electricalefficiencies of 79-84% (LHV), they require a heat source to produce
steam. Therefore, if SOEC hydrogen were used to produce synthetichydrocarbons (power-to-liquid [PtL] and power-to-gas [PtG]), it would
be possible to recover waste heat from these synthesis processes(e.g. Fischer-Tropsch synthesis, methanation) to produce steam forfurther SOEC electrolysis. Nuclear power, solar thermal andgeothermal heat systems, as well as industrial waste heat, could also
be heat sources for SOECs.
SOEC electrolysers can also be operated in reverse mode as fuelcells to convert hydrogen back into electricity, another feature that is
distinct from alkaline and PEM electrolysers. Combined withhydrogen storage facilities, they could provide balancing services tothe power grid, increasing the overall utilisation rate of equipment.
SOEC electrolysers can also be used for co-electrolysis of steam andCO2, thereby creating a syngas mixture (carbon monoxide andhydrogen) for subsequent conversion into a synthetic fuel.
SOECs are still in the demonstration phase for large-scale
applications (TRL 6-7 32). Operational systems, often linked to the
production of synthetic hydrocarbon fuels, currently have capacitiesof <1 MW. The largest system in operation (720 kW capacity) uses
renewable electricity and waste heat to produce hydrogen for a DRI
steel plant. However, a 2.6-MW SOEC system is being developed in
Rotterdam, and several companies (e.g. Bloom, Sunfire) aremanufacturing SOEC systems, mainly in Europe. Denmark plans tolaunch a manufacturing plant with an annual capacity of 500 MW by2023.

Methane pyrolysis
Methane pyrolysis (also known as methane splitting, cracking or
decomposition) is the process of converting methane into gaseoushydrogen and solid carbon (e.g. carbon black, graphite), without
creating any direct CO2 emissions. The reaction requires relatively
high temperatures (>800°C), which can be achieved throughconventional means (e.g. electrical heaters) or using plasma. Per unit

32
A technology’s technology readiness level indicates its current maturity within a defined scale,ranging from the definition of basic principles (TRL 1) to full commercial operation in a relativeenvironment (TRL 9). See https://www.iea.org/articles/etp-clean-energy-technology-guide.

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of hydrogen produced, methane pyrolysis uses three to five times
less electricity than electrolysis; however, it requires more natural gas
than steam methane reforming.
The overall energy conversion efficiency of methane and electricity
combined into hydrogen is 40-45%. Notably, the process could create
additional revenue streams from the sale of carbon black for use inrubber, tyres, printers and plastics, though the market potential islikely limited, with global demand for carbon in 2020 being 16 Mt ofcarbon black, which corresponds to hydrogen production frompyrolysis of 5 Mt H2. Carbon from pyrolysis could be used in otherapplications such as construction materials or to replace coke insteelmaking.
Several methane pyrolysis technology designs under development
show TRLs of 3 to 6. Monolith Materials (in the United States) uses
thermal plasma to create the high temperatures required. After
operating a pilot plant for four years, the company launched anindustrial plant in 2020 (in Nebraska) and is planning a commercialscale plant for ammonia production. To convert biogas into hydrogenand graphite, Hazer Group (Australia) is building a demonstration
plant for its catalytic-assisted fluidised bed reactor technology, andBASF (Germany) is developing an electrically heated moving-bed
reactor process. Together with RWE, in 2021 the company
announced a project to use electricity from offshore wind to producehydrogen from electrolysis and for a methane pyrolysis plant.
Gazprom (Russia) is developing a plasma-based process formethane pyrolysis. The start-up C-Zero (United States) is working on
an electrically heated molten-metal reactor for methane pyrolysis.

Anion exchange membranes (AEMs)
AEM electrolysis combines some of the benefits of alkaline and PEM
electrolysis. Using a transition metal catalyst (CeO2-La2O), it does not
require platinum (unlike PEM electrolysis). A key advantage is thatthe anion exchange membrane itself serves as solid electrolyte,
avoiding the corrosive electrolytes used in AEL. AEM technology is
still at an early stage of development (TRL 4-5), but Enapter(Germany) is developing kW-scale AEM electrolyser systems thatcan be combined to form MW-scale systems.

Electrified steam methane reforming (ESMR)
SMR is a widely used process to produce hydrogen from natural gas,
and it can be combined with CCUS to reduce CO2 emissions. To
achieve capture rates of 90% or higher, CO2 capture needs to be
applied to two gas streams: the synthesis gas stream after the steam
methane reformer (characterised by relatively high CO2
concentrations) and a more diluted flue gas stream caused by steam
production from natural gas. Because the latter has a lower CO2
concentration, capture requires more energy.
An alternative to capturing CO2 from flue gas, which accounts for 40%
of CO2 emissions from natural gas SMR, is to use an alternative heatsource to produce the steam. Haldor Topsoe (Denmark) is using lowcarbon electricity (hence SMR becomes ESMR) at a level of
8 kWh/kg H2. The technology has been demonstrated at only thelaboratory scale (TRL 4) to date, but a pilot plant is under construction
to use biogas as a feedstock in ESMR to produce hydrogen andcarbon monoxide, which will then be converted into methanol.

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Infrastructure

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Efficient development of hydrogen infrastructure requires analysis at the system level
Large-scale hydrogen deployment will need to be underpinned by aneffective and cost-efficient system for storage and transport,
strategically designed to connect supply sources to demand centres
and thereby establish a deep liquid market. While there is generally
consensus on the need to expand the penetration of hydrogen in theenergy system to decarbonise certain hard-to-abate sectors,
uncertainty remains about how its production, consumption andgeographical distribution will evolve.
This uncertainty in turn influences how infrastructure for hydrogenstorage and transport is developed. Efficient infrastructure design will
depend on several aspects, including demand volumes; the locationof infrastructure relative to resources for producing low-carbonhydrogen (renewables and CO2 storage sites); technologies used for
production; and existing natural gas and electricity networks, as wellas their future development. In some cases, transporting electricity
for decentralised electrolytic hydrogen production may be the mosteconomical choice, but under different circumstances, centralised
production relying on hydrogen transport can be preferable.

product (for use in transport or high-temperature heating) and its
transport as pure hydrogen (gaseous or liquefied) or using ahydrogen carrier (ammonia or a liquid organic hydrogen carrier[LOHC]) would depend on the total cost of transport (including
conversion/reconversion, storage and transport).
Although hydrogen’s high versatility makes a wide range ofpossibilities and solutions available across diverse sectors,
inadequate planning could result in the construction of inefficient andcostly infrastructure. Thus, integrated analysis at the system level isneeded to design efficient infrastructure for producing hydrogen andtransporting it to end users.

The final use of hydrogen can also dictate how it is transported. In
certain cases, hydrogen could be used locally to produce end
products (chemical products, fertiliser or steel) or to produce otherfuels (ammonia or synthetic fuels) that could be transported morecost-efficiently. In other cases, pure hydrogen would be the final
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More pipeline transport is needed to reach hydrogen targets
Hydrogen can be transported either in gaseous form by pipelines andtube trailers or in liquefied form in cryogenic tanks. IEA analysis
indicates that pipeline is generally the most cost-efficient option for
distances of <1 500-3 000 km, depending on pipeline capacity. For
longer distances, alternatives such as transporting liquefiedhydrogen, ammonia or LOHCs by ship could be more attractive (seealso Hydrogen Trade below).
Transmitting hydrogen by pipeline is a mature technology. The firsthydrogen pipeline system was commissioned in the Rhine-Ruhr
metropolitan area (Germany) in 1938 and remains operational.
Historically, carbon steel or stainless steel have been used forhydrogen-line pipes, as higher grades (>100 ksi) present a higher riskof hydrogen embrittlement. Hydrogen pipelines currently cover morethan 5 000 km, with >90% located in Europe and the United States.
Most are closed systems owned by large merchant hydrogenproducers and are concentrated near industrial consumer centres(such as petroleum refineries and chemical plants).
Similar to natural gas pipeline systems, hydrogen pipelines arecapital-intensive projects that have high upfront investment costs.
Due to the inflexible and durable nature of these assets, investments
become sunk as soon as the pipeline is laid. High initial capital costs
and associated investment risks can therefore impede hydrogenpipeline system development significantly, especially when demandis nascent and regulatory frameworks have not been established.
Moreover, because thicker pipeline walls are required at larger
diameters, construction costs for new-build hydrogen pipelines are
typically higher than for natural gas pipelines. At a similar diameter,
the CAPEX of hydrogen-specific steel pipelines is 10-50% higher
than for natural gas.
Reaching the targets set in hydrogen strategies will necessitate much
faster hydrogen transmission development. IEA analysis shows thatby 2030, the total length of hydrogen pipelines globally will need to
double to 10 000 km in the Announced Pledges Scenario andquadruple to >20 000 km in the Net zero Emissions Scenario.
Fortunately, existing natural gas infrastructure can act as a catalyst
to scale up hydrogen transportation. In the short to medium term,
blending hydrogen into natural gas can facilitate the initialdevelopment of trade, while repurposing gas pipelines cansignificantly reduce the cost of establishing national and regionalhydrogen networks.

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Hydrogen blending can be a transitionary solution
By providing a temporary solution until dedicated hydrogen transportsystems are developed, blending hydrogen in gas networks can
support initial deployment of low-carbon hydrogen and trigger cost
reductions for low-carbon hydrogen production technologies. While
several pilot projects have been launched in recent years, blending
still faces several technical and regulatory barriers. Parameters
related to natural gas quality (composition, calorific value and Wobbe
index) – as regulated in different countries – can limit (or completely
prevent) injection of hydrogen into gas grids.
The hydrogen purity requirements of certain end users, including
industrial clients, can further constrain blending. In addition, resulting
changes in the physical characteristics of the gas can affect certain
operations, such as metering. To avoid interoperability issues arisingfrom the changing quality of gas, hydrogen blending will require thatadjacent gas markets co-operate more closely.
Hydrogen can be injected into gas networks either directly in its pureform or as “premix” with natural gas. Due to its chemical properties,
however, it can cause embrittlement of steel pipelines, i.e. reactions
between hydrogen and steel can create fissures in pipelines.
Depending on the characteristics of the gas transmission system,

33

hydrogen can be blended at rates of 2-10 vol%H2 33 without
substantial retrofitting of the pipeline system. The hydrogen toleranceof polymer-based distribution networks is typically greater, potentiallyallowing blending of up to 20 vol%H2 with minimal or possibly no
modifications to the grid infrastructure.
The injection of low-carbon hydrogen into gas grids has grownsevenfold since 2013, but volumes remain low. In 2020, ~3.5 kt H2
were blended, almost all in Europe and mainly in Germany, which
accounted for close to 60% of injected volumes. In France, the
GRHYD demonstration project is testing injection of up to 20 vol%H2
into the natural gas distribution grid of Cappelle-la-Grand (nearDunkirk). In Italy, the Snam project demonstrated the feasibility of
blending up to 10% hydrogen in its transmission grid, while in the
United Kingdom, the HyDeploy demonstration project tested injectionof up to 20 vol%H2 into Keele University’s existing natural gas
network (the project became fully operational in early 2020).
Interest in blending is growing in other regions as well. In Australia,
pipeline network operators are developing demonstration projects
allowing 5-10% volH2 blend injections starting in 2021 or 2022.
Australia Gas Infrastructure Group (AGIG) launched the country’s

The energy density of hydrogen is about one-third that of natural gas.
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first hydrogen blending pilot project (Hyp SA) in May 2021. Under thisproject, AGIG will blend about 5 vol% green hydrogen into South
Australia’s gas distribution network, supported by a 1.25-MW
electrolyser operating on solar and wind energy.

Consequently, in terms of climate change action, blending is atransitionary solution than can help build up stable sources for lowcarbon hydrogen demand until a dedicated hydrogen transportsystem is developed.

In the United States, a first demonstration project on polymer-based
distribution pipelines is expected to be launched in California in 2021,
with its initial blend level of 1 vol% potentially rising to 20 vol%H2. In
Canada, a hydrogen demonstration project in Ontario is set to start in
2021, allowing for a maximum hydrogen blended content of up to 2%of the natural gas supplied.
Based on projects that have reached final investment decision (FID)or are under construction, hydrogen blending could increase by afactor of 1.3 by 2030 (>4 kt H2). However, if all proposed gridconnected hydrogen projects are realised, it could rise by over 700
times to >2 Mt H2. Still, this falls massively short of the 53 Mt H2 thatneed to be blended into gas grids globally in 2030 in the Net zero
Emissions Scenario.
Supportive policies and regulatory mechanisms, including blend
certificates and/or guarantees of origin, could spur hydrogen tradingand pipeline transport development. While the costs associated withhydrogen blending are relatively low, emissions savings are rather
limited, with only a ~10% CO2 reduction at a blending rate of 30%.

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Estimated low-carbon hydrogen injected into gas networks,
2010-2020

Low-carbon hydrogen injected into gas networks in the
Projects case and Net Zero Emissions Scenario, 2020-2030

IEA. All rights reserved.
Note: NZE = Net zero Emissions Scenario.
Source: IEA (2021), Hydrogen Projects Database.

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Old but gold: Repurposing gas infrastructure can catalyse hydrogen network development
Compared with building new hydrogen pipelines, repurposing
existing natural gas pipeline systems as dedicated hydrogen
networks can be substantially less costly and the lead times can bemuch shorter. Ultimately, this could translate into lower transport
tariffs and improve the cost-competitiveness of hydrogen.

carry hydrogen in the 1970s and 1990s. The first conversion of anatural gas pipeline for full hydrogen service in the Netherlands was
put into commercial service in November 2018 by Gasunie (12 km
with throughput capacity of 4 kt H2/yr). Repurposing took six to sevenmonths.

Pipeline repurposing can range from simple measures (e.g. replacing
valves, meters and other components) to more complex solutions,
including replacing/recoating pipeline segments (which entails pipe
excavation). Also, considering that hydrogen has a higher leakage
rate and an ignition range about seven times wider than that ofmethane, it may be necessary to upgrade leak detection and flow
control systems.

In Germany, as part of its H2HoWi R&D project, E.ON announced
the conversion of a natural gas pipeline with an investment cost of
EUR 1 million (works started at the end of 2020). In addition, GRTgaz
and Creos Deutschland launched the MosaHYc project to convert
two existing natural gas pipelines into a 70-km pure hydrogen
infrastructure along the border where Germany, France andLuxembourg intersect (FID expected by 2022). In Australia, APA
announced the repurposing of 43 km of its Parmelia pipeline inWestern Australia as a demonstration project, with testing to becompleted by the end of 2022.

Based on technical analysis of Germany’s gas transmission system,
Siemens estimates that compressor stations can generally be usedwithout major changes up to 10 vol%H2; beyond 40 vol%H2, they
have to be replaced, driving up initial investment costs. Notably, thecompressor power required per unit of hydrogen transportation isabout three times higher than for natural gas, resulting in higher
operating expenses. The amount of total compressor power required
will ultimately depend on market demand for hydrogen.
Practical experience of gas-to-hydrogen pipeline conversion is rather
limited, with several crude oil and product pipelines repurposed to

The cost benefits of gas pipeline repurposing can be substantial. The
European Hydrogen Backbone (EHB) study suggests conversion
costs are 21-33% the cost of a new hydrogen pipeline. Of an
expected ~40 000 km of hydrogen pipelines in Europe by 2040, thestudy estimates 75% will be repurposed. The latest draft network
development plan of Germany’s Transmission System Operator(TSO) Association estimates new-build hydrogen pipeline costs to bealmost nine times higher than for gas pipeline conversion.

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Most recently, the pre-feasibility study for a Danish-German
Hydrogen Network estimated repurposing costs to be just 25% of
those for new construction. Furthermore, the HyWay27 study,
published in the Netherlands (June 2021), estimates that reusing
existing natural gas pipelines is four times more cost-effective thanlaying new hydrogen pipelines. Lower construction costs would
translate into more cost-competitive transport tariffs, further
supporting deployment of low-carbon hydrogen.
Therefore, of the >1 200 km of hydrogen pipelines foreseen by 2030
in the German TSO Association’s Ten-Year Network Development
Plan (2020-2030), >90% is repurposed natural gas pipelines. At theend of June 2021, Gasunie announced that the Netherlands’ State
Secretary for Energy and Climate had requested it to develop a rollout plan for a national hydrogen transport infrastructure by 2027.
Project costs are estimated at EUR 1.5 billion with a throughput
capacity of 10 GW, and the hydrogen network would consist ofaround 85% repurposed natural gas pipes. In September 2021, theDutch government announced an investment of EUR 750 million (aspart of a wider EUR 6.8 billion package on climate measures) toconvert parts of the existing gas network into hydrogen transport
infrastructure.

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Construction cost comparison of repurposing natural gas
pipelines vs building new hydrogen pipelines (%)

Estimated transport costs per unit of hydrogen via different
types of transport

IEA. All rights reserved.

* Including compressor station CAPEX costs.
Notes: FNB = Vereinigung der Fernleitungsnetzbetreiber (TSO Association of Germany). LH2 = liquefied hydrogen. In the right graph, the lower limit for pipeline costs
corresponds to repurposing existing pipelines, the upper one to building new pipelines. Truck transport costs are based on a capacity of 10 t H2/d; in the case ofliquefied hydrogen and ammonia, they include conversion and reconversion costs.
Sources: Based on FNB (2020), Netzentwicklungsplan 2020; Gas For Climate (2021), European Hydrogen Backbone 2021; Gasunie-Energinet (2021), Pre-feasibility
Study for a Danish-German Hydrogen Network.

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Underground hydrogen storage in salt caverns and other geological formations
Availability of hydrogen as an energy vector could, like natural gas,enhance overall energy system flexibility by balancing short-term
supply variability and meeting seasonal demand swings, thereby
improving energy supply security. To fulfil this role, low-carbonhydrogen deployment will need to be coupled with development of
cost-effective, large-scale and long-term storage solutions.
Global gas storage totalled >400 bcm in 2020 (10% of total
consumption), with porous reservoirs (depleted fields and aquifers)
accounting for >90% of storage capacity and the rest located in salt
and rock caverns. Assuming global hydrogen demand reaches
530 Mt and a similar storage-to-consumption ratio, hydrogen storage
requirements in the Net zero Emissions Scenario could amount to~50 Mt (~550 bcm) by 2050.
Used by the petrochemical industry since the early 1970s, storinghydrogen underground in salt caverns is a proven technology.
Because salt caverns support high injection and withdrawal rates,
storing hydrogen there can provide short-term energy system
flexibility. Their development, however, depends on geologicalconditions, i.e. the availability of salt formations. In addition, theinjection-withdrawal periodicity of the petrochemical industry’s use ofunderground hydrogen storage may differ from that of otherapplications, which could require faster cycles.

Four hydrogen salt caverns sites are currently operational. The firstwas commissioned in in 1972 at Teesside (United Kingdom) by Sabic
Petrochemicals, and three are operational in Texas, including
Spindletop (commissioned in 2016), the world’s largest hydrogenstorage facility.
Several pilot projects are under development in Europe: in the
Netherlands, testing of hydrogen storage in the borehole of a future
cavern in Zuidwending began in August 2021, with the first cavern tobe operational in 2026. In Germany, EWE began building a smallerscale salt cavern storage site at Rüdersdorf at the beginning of 2021,
with first test results expected by mid-2022. In Sweden, a rock cavernhydrogen storage facility is under construction, with pilot operations
expected to start in 2022. Several pilot projects are also in various
stages of development in France and the United Kingdom.
In the United States, the proposed large-scale Advanced Clean
Energy Storage (Utah) is targeting start-up in the mid-2020s. While
there is no practical experience in repurposing methane caverns forhydrogen service, it is estimated that such an approach would require
about the same amount of time as developing a new salt cavern.
While experience storing hydrogen in porous reservoirs such as
depleted fields or aquifers is limited, demonstration projects in Austria(the Underground Sun Storage project) and Argentina (HyChico)

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show it is feasible to store a blend of 10% hydrogen and 90%
methane in depleted fields without adversely affecting the reservoirs
or equipment. Water aquifers are the least mature of the threegeological storage options, and evidence of their suitability is mixed.
The feasibility and cost of storing pure hydrogen in depleted
reservoirs and aquifers still must be proven, requiring further
research.
Another potential barrier is public opposition due to concerns aboutsubsidence and induced seismicity, which should be investigated in
depth to minimise risks. In parallel, adequate and transparent
communication should address public concerns before large-scalestorage site development begins. The IEA Hydrogen TCP isestablishing a new task for underground hydrogen storage that will
focus on research and innovation to prove its technical, economic
and societal viability.

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Global Hydrogen Review 2021

Infrastructure and trade

Existing hydrogen storage facilities and planned projects
Project start
year

Name

Country

Teeside

United Kingdom

1972

Sabic

Clemens Dome

United States

1983

Moss Bluff

United States

Spindletop

Working storage
(GWh)

Type

Status27

Salt cavern

Operational

Conoco Philips

82

Salt cavern

Operational

2007

Praxair

125

Salt cavern

Operational

United States

2016

Air Liquide

278

Salt cavern

Operational

Underground Sun Storage

Austria

2016

RAG

10% H2 blend

Depleted field

Demo

HyChicoArgentina

2016

HyChico, BRGM

10% H2 blend

Depleted field

Demo

HyStock

The Netherlands

2021

-

Salt cavern

Pilot

HYBRIT

Sweden2022

EnergyStock
Vattenfall
SSAB, LKAB-

Rock cavern

Pilot

Rüdersdorf

Germany

2022

EWE

0.2

Salt cavern

Under construction

HyPsterFrance2023

Storengy

0.07-1.5

Salt cavern

Engineering study

HyGéo

France2024

HDF, Teréga

1.5

Salt cavern

HySecure

United Kingdom

Storengy, Inovvn

40

Salt cavern

Feasibility study
Phase 1 feasibility
study

Energiepark Bad
Lauchstädt Storage

Germany

150

Salt cavern

Feasibility study

Advanced Clean Energy
Storage

United States

150

Salt cavern

Proposed

mid-2020s
mid-2020s

Operator/ developer

Uniper, VNG
ONTRAS, DBI
Terrawatt
Mitsubishi Power
Americas
Magnum Development

IEA. All rights reserved

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Hydrogen trade

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First steps under way to develop supply chains for international hydrogen trade
With the transition to sustainable energy systems boosting demandfor hydrogen and hydrogen-based fuels, international trade inhydrogen will be an important part of the hydrogen supply chain.
Countries that have limited domestic capabilities to produce lowcarbon hydrogen from renewables, nuclear energy or fossil fuels with
CCUS – or that find these processes too expensive – can benefit fromimporting more affordable low-carbon hydrogen.
For countries with excellent renewable resources, international trade
in hydrogen can provide an opportunity to export renewable
resources that otherwise may not be exploited. Similarly, gas- or coalproducing countries could join the market by exporting hydrogenproduced from fossil fuels with CCUS. In the Net zero Emissions
Scenario, international trade in hydrogen and hydrogen-based fuels
covers ~15% of global demand for these fuels in 2030.
Transporting energy over long distances is typically easier in the formof molecules (i.e. liquid, gaseous or synthetic fuels) than as electricity
because fuels are characterised by high (volumetric) energy densities
and lower transport losses. Most natural gas is moved worldwide inlarge-scale pipelines or as LNG via ships, and similar methods could
be employed for hydrogen and hydrogen carriers. Hydrogen can also
be transported in storage tanks by trucks, which is currently the main
option to distribute it at the local level, but it is generally very
expensive. For longer distances, pipelines and seaborne

transportation are more economical, with the best option dependent
on distance and volume (among other factors).
At present, hydrogen is generally stored as a compressed gas or inliquefied form in tanks for small-scale local use. However, a muchwider variety of storage operations will be required to achieve
uninterrupted international hydrogen trading. At import terminals,
hydrogen storage is likely necessary as a contingency measure incase of supply disruptions, similar to the approach for LNG.
Various solutions are being explored for long- or short-distanceseaborne hydrogen transport. One option is to transport it in liquefied
form, which is drastically more dense than the gaseous state.
However, as hydrogen liquefaction requires a temperature of -253°C(i.e. 90°C lower than for LNG), it is energy-intensive. Plus, current
liquefaction processes have a relatively low efficiency and consume
about one-third of the energy contained in the hydrogen. Some
reports indicate that scaling up liquefier capacity could cut energy
requirements to around one-fifth.
Another option for high-density transport is to convert hydrogen intoanother molecule such as ammonia or LOHC. Ammonia is alreadytraded internationally as a chemical product, but as it is toxic,
increased transport and use may raise safety and public acceptanceissues, restricting its handling to professionally trained operators.

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Converting hydrogen into ammonia and reconverting it back tohydrogen after transport is possible, but additional energy andpurification steps will be required for some end uses. Still, theadvantage of ammonia is that it liquefies at -33°C (at ambientpressure), a much higher temperature than hydrogen, resulting in alower energy needs.
LOHCs have properties similar to crude oil and oil products, and their
key advantage is that they can be transported without liquefaction.
As with ammonia, conversion/reconversion and purification
processes are costly, and depending on an LOHC’s basic molecular
makeup, toxicity issues could be a consideration. Furthermore, an
LOHC’s carrier molecules are often expensive and, after being used
to transport hydrogen to its destination, need to be shipped back totheir place of origin.

shipping, for use as a gas turbine fuel. Meanwhile, Saudi Aramco andthe Institute of Energy and Economic of Japan collaborated to import
40 t of ammonia produced in Saudi Arabia from natural gas with
CCUS to Japan for direct use as an electricity generation fuel. Forliquefied hydrogen (LH2), the first planned shipment from Australia toJapan in the Hydrogen Energy Supply Chain (HESC) pilot project
was postponed to the first quarter of 2022 due to the Covid-19
pandemic. Still, the import terminal and hydrogen production plant
were commissioned, and the hydrogen was successfully produced
and liquefied in Australia.

Costs of delivering GH2 by pipeline and LH2, LOHC andammonia by ship, 2030

The high cost of hydrogen transmission and distribution for many
trade routes means it may cost less to produce low-carbon hydrogendomestically than to import it – i.e. the higher cost of clean hydrogenproduction could still be less than the supply costs incurred forimports. This depends heavily on local conditions. Countries withconstrained CO2 storage or limited renewable resources will be more
dependent on imports to meet hydrogen demand.
In 2020, significant progress was made in demonstrating internationalhydrogen trade. The Advanced Hydrogen Energy Chain Association
for Technology Development successfully produced and tradedhydrogen by LOHC technology from Brunei to Japan using container

IEA. All rights reserved.

Notes: GH2 = gaseous hydrogen. LH2 = liquefied hydrogen. LOHC = liquidorganic hydrogen carrier. tpd = tonnes per day. Includes conversion, export
terminal, shipping, import terminal and reconversion costs for each carriersystem. Storage costs are included in import and export terminal expenses.
The pipeline cost assumes construction of a new pipeline.
Sources: Based on IAE (2016); Baufumé (2013).

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Governments and private companies have also announced several
other international collaborations and projects for hydrogen trade.
Germany, which stated the importance of importing hydrogen in its
national strategy, signed an agreement for a joint feasibility study with
Australia and Chile. Meanwhile, the Netherlands signed an MOU with
Portugal, the Port of Rotterdam signed one with Chile, and Japansigned a memorandum of collaboration (MOC) with the United ArabEmirates. Around 60 international hydrogen trade projects have beenannounced and feasibility studies are under way for half of them. The
total reported volume of these projects is 2.7 Mt H2/yr.

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Selected international hydrogen trade projects
VolumeCarrier

Expected firstshipping year

Map
Reference

225 540 tpa

LH2

2030

1

TBD

TBD

TBD

2

Japan

280 000 tpa

LH2

2026

3

Saudi Arabia

TBD

650 tpd

Ammonia2025

4

H2GateTBD

Netherlands

1 000 000 tpa

LOHC

TBD

5

ADNOC - TA’ZIZ industrial hub

United ArabEmirates

TBD

175 000 tpa

Ammonia

2025

Asian Renewable Energy HubAustralia

Japan or Korea

TBD

LH2 or ammonia

2028

7

Murchison

Australia

TBD

TBD

TBD

TBD

8

Crystal Brook Energy Park

Australia

TBD

25 tpd

TBD

TBD

9

Pacific Solar Hydrogen

Australia

TBD

200 000 tpa

TBD

TBD

10

Origin Energy - Kawasaki Heavy
Industries Townsville project

AustraliaJapan

36 000 tpa

LH2

2025

KBR SE Asia feasibility study

Southeast Asia

TBD

TBD

TBD

TBD

12

Eyre Gateway

Australia

Japan or Asia

7 000 tpa

Ammonia

TBD

13

UnnamedTBD

Singapore

TBD

LH2

TBD

14

UnnamedTBD

Singapore

TBD

LOHC

TBD

15

Project Geri

Australia

TBD

175 000 tpa

Ammonia

TBD

16

Green Mega Fuels Project

Oman

TBD

175 000 tpa

Ammonia2032

17

Western Green Energy HubAustralia

TBD

34 000tpa

Ammonia

TBC

18

Project

Export country

Import country

Hydrogen Energy Supply Chain

AustraliaJapan

H2 Sines

Portugal

Netherlands

Stanwell - Iwatani Gladstone project

Australia

Helios Green Fuels

6

11

Notes: LH2 = liquefied hydrogen. LOHC = liquid organic hydrogen carrier. SE Asia = Southeast Asia. TBD = to be determined. tpa = tonnes per annum. tpd = tonnes
per day.

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Most hydrogen trade projects under development are in Asia-Pacific

IEA. All rights reserved.
Notes: This map is without prejudice to the status of or sovereignty over any territory, to the delimitation of international frontiers and boundaries and to the name of any territory, city or
area.

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Infrastructure and trade

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As part of its JPY 2-trillion (about USD 18.7-billion) Green Innovation
Fund, the Japanese government has allocated JPY 255 billion (about
USD 2.4 billion) to establish the first commercial internationalhydrogen trade. Its intent is to support LH2 and LOHC supply chain
development to reduce costs and improve the maturity of thetechnologies involved.

USD 1.80/kg H2 for these trade links, which would be competitive. In
the long term, further efficiency improvements and processoptimisation could reduce transport and thus total supply costs for all
carriers. In some regions, this could eventually make imports more
attractive than domestic production, potentially boosting international
trade after 2030.

Any country deciding whether to produce hydrogen domestically or
import must consider all delivery costs across the entire supply chain,from production and transport to end-use application. The IEA
estimates that by 2030, importing hydrogen produced from solar PV
in Australia into Japan (<USD 4.20/kg H2) will cost slightly less than
producing it domestically from renewables (USD 4.50/kg H2). While
producing natural gas-derived hydrogen with CCUS in Japan could
cost even less (USD 1.85/kg H2), access to CO2 storage may be alimiting factor.

Projected costs of delivering LH2, LOHC and ammonia inselected regions, 2030

In the case of exporting hydrogen from the Middle East to Europe,
imported hydrogen (USD 2.60-3.80/kg H2) is unlikely to becompetitive with domestic production (USD 2.30/kg H2) in 2030.
However, if ammonia can be used directly (e.g. in the chemicalindustry or as a shipping or power sector fuel), reconversion losses
can be avoided and the supply cost could be reduced to

IEA. All rights reserved.
Notes: LH2 = liquefied hydrogen. LOHC = liquid organic hydrogen carrier. Assumes
distribution of 1 000 t H2/d. Storage costs are included in import and export terminal
expenses. Hydrogen is produced from electrolysis using renewable electricity.
Source: Based on IAE (2016).

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Long-term potential of international hydrogen trade
In the Announced Pledges Scenario in 2050, trade in hydrogen andhydrogen-based fuels accounts for 20% of global demand, with 8%of hydrogen demand being traded, 50% of ammonia and 40% of
liquid synfuels. This reflects the comparatively lower transport costsof ammonia and synfuels. While several countries (e.g. China and theUnited States) manage to cover growing demand for low-carbonhydrogen and hydrogen-based fuels domestically, others (e.g. Japan,
Korea and parts of Europe) rely on imports, at least in part. By 2050
in the Announced Pledges Scenario, Japan and Korea are importing
each around 60% of their domestic demand for hydrogen andhydrogen-based fuels.

However, many of these major future exporters do not yet havenet zero pledges in place, so importing countries will need to engage
with trading partners to encourage and guarantee relevant supply
investments if they want their hydrogen imports to be low‐carbon.

Australia, Chile, the Middle East and North Africa emerge as key
exporting regions in the Announced Pledges Scenario, benefittingfrom the low cost of producing hydrogen from renewables or fromnatural gas with CCS. By 2050, North Africa, the Middle East andChile export ~600 PJ of hydrogen and hydrogen-based fuels to
Europe. For Asia, the important hydrogen suppliers are the Middle
East, Australia and Chile. By 2050, these exporters meet 1 800 PJ of
Asian demand for hydrogen and hydrogen-based fuels in the
Announced Pledges Scenario.

PAGE | 161

Announced Pledges Scenario hydrogen and hydrogen-based
fuel demand and production in selected regions, 2050

IEA. All rights reserved.

Infrastructure and trade

Global Hydrogen Review 2021

Hydrogen trade flows to Japan and Korea in the Announced Pledges Scenario in 2050

IEA. All rights reserved.

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Investments and innovation

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Investments and innovation

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Hydrogen investments rising despite Covid-19 pandemic, with unprecedented private
fundraising, mostly for manufacturing and to meet project demand
Hydrogen has proven remarkably resilient during the economic
slowdown induced by the global pandemic. Companies specialised
in producing, distributing and using hydrogen raised almost
USD 11 billion in equity between January 2019 and mid-2021 – aconsiderable increase from prior years – and contracts funded bygovernment recovery packages are expected to raise project
investments substantially. Nevertheless, funding is grossly
insufficient to accelerate innovation to the level required to realisehydrogen’s 60 Gt of CO2 emissions reduction potential modelled in
the Net zero Emissions Scenario.

Overview of recent company fundraising
Most new funding for hydrogen in 2020 and 2021 was raised bycompanies already listed on a stock exchange. They issued newshares to investors, primarily to secure capital for expanding
manufacturing facilities to meet expected or contracted demand forelectrolysers and fuel cells. Investor confidence in hydrogencompanies continued into the first half of 2021, partly in anticipationof contracts to be supported by government recovery packages.
Having sold USD 4.8 billion in new shares since 2019, the largest
fundraiser was Plug Power, a US company (est. 1997) that makes
electrolysers, fuel cells and refuelling equipment. Other electrolyser

manufacturers – including Nel, ITM Power, McPhy Energy, Green
Hydrogen Systems and Sunfire – collectively raised USD 1.5 billion.
Nikola, a company developing a fuel cell truck, raised
USD 250 million in 2019, then listed on the Nasdaq in 2020, raising
USD 700 million. In November 2020, however, a deal to sell 11% of
its shares to GM for USD 2 billion fell through. Investors have since
become increasingly concerned about Nikola’s ability to meet its
development schedule.
Two notable acquisitions occurred in this period. US engine
manufacturer Cummins bought the Canadian electrolyser company
Hydrogenics for USD 290 million. In Germany, engine manufacturer
MAN Energy Solutions acquired the PEM electrolyser maker H-Tec
for an undisclosed sum.
Several investment funds targeting hydrogen were launched in 2021.
The most recent, HydrogenOne Capital Growth Fund, raised
USD 150 million in an initial public offering including USD 35 million
from the petrochemical company INEOS. Other funds establishedsince 2018 include Ascent, FiveT, H-Mobility, Klima and Mirai. In
China, Shanxi Hydrogen Energy Industrial Fund, a governmentguided fund, was launched in 2021.

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Hydrogen company fundraising by stage of funding, January
2019 to mid-July 2021
Post-IPO

The fact that start-ups providing project development and integration
services for hydrogen projects are securing funding indicates amaturing sector. In May 2021, H2 Green Steel raised over
USD 100 million, the first major deal for a project developer forhydrogen use in the steel industry. Aiming to start production by2024, the Swedish company plans follow-up funding of
USD 2.5 billion in mixed debt and equity within the next year. HTEC,
an early-stage Canadian integration services firm, raised
USD 170 million in September 2021.

2019

Late-stage
PE and M&A

2020

Growthequity2021

Early-stage
VC
0

2

4

6

8
USD billion (2019)

IEA. All rights reserved.
Notes: PE = private equity. M&A = mergers and acquisitions. VC = venture capital. PostIPO includes private investment in public equity (PIPE) transactions and other new sharesales. Early-stage VC includes seed, Series A and Series B. Only deals with disclosed
values are included, which notably excludes certain M&A deals with undisclosed values.
Sources: Calculations based on Cleantech Group (2021) and Prequin (2021).

Investment in riskier early-stage hydrogen start-ups is also on therise. In contrast to the clean energy venture capital (VC) boom around2010, which involved few hydrogen companies, the current
investment surge delivered record amounts in 2019 and 2020, withthese sums surpassed in just the first six months of 2021. Aselectrolyser companies become more established in the market,
start-up activity is shifting to focus on newer non-electrolysis routes,
such as pyrolysis for extracting hydrogen from methane. Transform
Materials and Syzygy Plasmonics have raised USD 50 million since2019, while Monolith Materials raised USD 100 million in 2021 inlater-stage financing.

Regionally, many start-ups in these newer areas are European. For
the first time, in fact, European hydrogen start-ups are expected toraise more early-stage funds in 2020 and 2021 than their US
counterparts. China has also emerged as a source of hydrogentechnology start-ups and venture capital for scale-up. In 2019,
Jiangsu Guofu Hydrogen Technology’s fundraise of USD 60 million
was the main early-stage deal in China, with the money coming froma state-backed Shanghai fund.

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More early-stage capital flowing to start-ups, especially in Europe; fastest growth in companies
offering project development services or non-electrolysis supply solutions

Electrolysers and components
Fuel cells and components
Vehicles and refuelling
Non-electrolysis H2 production
H2 storage and infrastructure
Other end-use technology
Project development and services
Hydrogen-based fuels

2021*

2020

2019

2018

2017

2016

2015

2014

2013

2012

2011

2010

0%

2021*

0

2020

2%

2019

100

2018

4%

2017

200

2016

6%

2015

300

2014

8%

2013

400

2012

10%

2011

500

2010

USD million (2019)

Early-stage venture capital deals for hydrogen-related start-ups by technology area and region, 2010-2021

Rest of world
CanadaChina
EuropeUnited States
Share of early-stage energy VC (right)
IEA. All rights reserved.

Notes: 2021* data up to mid-June. H2 = hydrogen. Early-stage VC includes seed, Series A and Series B. The share of early-stage energy VC excludes outlier deals above
USD 150 million that distort trends (no such deal was recorded for hydrogen start-ups). Other end-use technology includes stationary turbines and non-transport mobile applications
that do not involve proprietary fuel cell stacks.
Source: Calculations based in part on Cleantech Group (2021).

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Evolution of investment in technology deployment
Investment in hydrogen technology deployment is also increasing.
Despite near-term uncertainty about market-led uptake, hydrogenprospects look stronger than before the Covid-19 pandemic. Projects
expected to deploy electrolysis capacity in 2021 raised more than
USD 400 million in 2020, nearly four times the investments in 2018.
In mobility, 2020 funding decreased slightly from 2019, likely
reflecting impacts of the pandemic; investment is more thanrecovering in 2021, however, and deployments up to June point to a
new record year.

USD million (2019)

Annual investments in electrolysers and FCEVs, 2016-2020
400

Electrolysers

400

300

300

200

200

100

100

0

2016 2017 2018 2019 2020

strategies – is spurring the strong momentum behind hydrogen
investment. Public investment is expected to leverage much higher
private spending, which could further accelerate hydrogentechnology deployment. For example, as part of its national hydrogenstrategy, Germany announced a EUR 9-billion package, which theGerman government expects to trigger an additional EUR 33 billion
of private investment. Globally, the industry sector is responding with
an impressive investment appetite: according to the Hydrogen
Council, the private sector has announced more than USD 300 billionof investments through 2030, although funding of only USD 80 billion
has been committed.

Investment outlook for the Announced Pledges andNet zero Emissions scenarios

FCEV2016 2017 2018 2019 2020
IEA. All rights reserved.

Note: FCEV = fuel cell electric vehicle.
Sources: Based on IEA Hydrogen Project Database and annual data submissions of
the AFC TCP to the IEA Secretariat.

Clearly, government action – including funding in Covid-19 recovery
plans and long-term signals embedded in national hydrogen

While recent hydrogen investments are encouraging, realising
government climate ambitions will require significant ramp-ups
across the entire production, end-use and infrastructure value chains.
The Announced Pledges Scenario models investments totalling
USD 250 billion for 2020-2030, leading to an accumulated
investment of USD 3.2 trillion in 2050. This is lower than announced
industry stakeholder investments to 2030, but significantly larger thanthose for which funding has already been committed.
Investments over the next decade could be critical in determining
long-term outcomes. Every year until 2030, investments of
USD 7 billion in electrolysers will be required (30 times recent record
investments) and USD 4 billion in FCEV deployment will be needed(14 times record investments). To achieve net zero emissions by

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2050, global cumulative investments must increase to USD 1.2 trillion
by 2030 and USD 10 trillion by 2050.
Building up low-carbon hydrogen production capacity accounts for
25% of global cumulative investments to 2050 in the Announced
Pledges Scenario and 27% in the Net zero Emissions. The need to
deploy capacity for both new production and to decarbonise existinguses (which requires limited investments in end uses andinfrastructure) means the share of investments in hydrogenproduction must be higher before 2030 than after. Although
investment in production capacity continues to grow to 2050, its sharedeclines as investments in new end-uses and infrastructuredevelopment increase.
End-use technologies account for about 60% of global cumulative
investments to 2050 in both the Announced Pledges and Net zero
Emissions scenarios, with the share increasing continuously.
Investments in end-use technologies are already considerable in2020-2030, projected at USD 8 billion/yr in the Announced Pledges
Scenario and USD 30 billion in the Net zero Emissions. After 2030,
several end-use technologies advance from early-stage development
to commercialisation and deployment at scale, unlocking newhydrogen demand, particularly in the transport sector. Consequently,
investments increase substantially to USD 90 billion/yr to 2050 in the
Announced Pledges Scenario and to USD 270 billion/yr in the
Net zero Emissions.

storage and import/export terminals). In fact, infrastructure accounts
for 18% of global cumulative investments to 2050 in the Announced
Pledges Scenario (USD 575 billion) and 14% in the Net zero
Emissions (USD 1 400billion).
Although modelling shows this share increasing nearly fivefold after
2030 in the Announced Pledges Scenario and more than twofold in
the Net zero Emissions, this does not mean that infrastructuredevelopment can be delayed another decade. Rather, developinghydrogen storage capacity will be critical to ensure supply security inthe short term and to provide balancing for the integration ofrenewable energy in the longer term. In parallel, progress can bemade by blending hydrogen in the gas grid and repurposing natural
gas pipelines. As hydrogen demand grows, greater investments in
new pipeline infrastructure may be required, depending on regional
conditions. Furthermore, the development of international hydrogen
supply chains can spur investment in import/export terminals andhydrogen transport vessels.
Notable opportunities may exist to minimise expenditures by
repurposing current infrastructure. With minimal modification,
infrastructure for oil-derived products could be used to import/export
liquid synfuels, while some parts of LNG and LPG infrastructure could
be upgraded to import/export hydrogen and ammonia.

To distribute hydrogen to end users, significant investments are also
required to develop infrastructure (i.e. refuelling stations, pipelines,

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Investment on hydrogen must increase to USD 1.2 trillion by 2030 to put the world on track tomeet net zero emissions by 2050
Global annual hydrogen investment needs by sector in the Announced Pledges and Net zero Emissions scenarios

APS

NZE

2021-30H₂2021-30H₂2031-40NH₃2031-40NH₃2041-50

Synfuels

2041-50

Synfuels

0

100

200

300

400

0
Imports/exports

2021-30

HRSs

2031-40

100

200

300

200

300

Storage

100

200

300

400
PG
Industry
Transport

2041-50

Buildings

100

Transport

2031-40

Transport

0HRSs

2021-30

Industry2041-50

Imports/exports

0PG

2031-40400

2021-30400

2021-30300

2041-50

Storage02002031-40

Transport

2041-50

100

Buildings

0

400

100

200

300

USD billion (2019)400
USD billion (2019)
IEA. All rights reserved.

Notes: APS = Announced Pledges Scenario. NZE = Net zero Emissions Scenario. HRSs = hydrogen refuelling stations. PG = power generation.

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Investments and innovation

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Several hydrogen technologies not yet commercially available
Technology readiness levels of key hydrogen production, storage and distribution technologies

IEA. All rights reserved.
Notes: AEM = anion exchange membrane. ALK = alkaline. ATR = autothermal reformer. CCUS = carbon capture, utilisation and storage. GHR = gas-heated reformer. LOHC = liquidorganic hydrogen carrier. PEM = polymer electrolyte membrane. SOEC = solid oxide electrolyser cell. Biomass refers to both biomass and waste. For technologies in the CCUS
category, the technology readiness level (TRL) refers to the overall concept of coupling these technologies with CCUS. TRL classification based on Clean Energy Innovation (2020),
p. 67.
Source: IEA (2020), ETP Clean Energy Technology Guide.
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Investments and innovation

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Technology readiness levels of key hydrogen end-use technologies

IEA. All rights reserved.
Notes: BF = blast furnace. DRI = direct iron reduction. FC = fuel cell. HRS = hydrogen refuelling station. HD = heavy-duty. HT = high throughput. ICE = internal combustion engine. LD= light-duty. MeOH = methanol. MTO = methanol to olefins. PEM FC = polymer electrolyte membrane fuel cell. SOFC = solid oxide fuel cell. VRE = variable renewable electricity.
Co-generation refers to the combined production of heat and power. Technology readiness levels based on Clean Energy Innovation (2020), p. 67.
Source: IEA (2020), ETP Clean Energy Technology Guide.

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Innovation in hydrogen technology is lagging
Except for well-established technologies for fossil-based production
and conventional uses in industry and refining, much of the hydrogenvalue chain is yet to be fully developed at commercial scale. It istherefore vital that innovation efforts for all hydrogen technologies be
stepped up to avoid bottlenecks in using them as a key lever for
decarbonisation. In its Net zero by 2050 roadmap, the IEA estimatesthat USD 90 billion of public money needs to be mobilised globally as
quickly as possible, with around half dedicated to hydrogen-related
technologies.

USD million (2019)

R&D spending in hydrogen technologies, 2005-2020
1 600

8%

1 400

7%

1 200

6%

1 000

5%

800

4%

600

3%

400

2%

200

1%

0

2005

2010

2015

2020

0%

China
(2015-19)
Other Asia

US

EuropeShare oftotal clean
energy R&D

IEA. All rights reserved.
Source: Based on IEA and Mission Innovation data. 2020 data for China not available.

Government support for hydrogen R&D was strong in the late 2000s.
In fact, it accounted for 6% of all clean energy R&D, with most funding

directed towards electrolyser technology and Japan being the largest
funder. While a slump in R&D expenditures during 2010-2015reflected lower overall interest in this technology family, the recent
resurgence (since 2015) has focused on other hydrogen productionand end-use technologies, in line with the relative maturity of fuel cell
technologies. Of particular note is that the Government of China’s
R&D expenditures on hydrogen technologies increased sixfold in2019.
While the technology readiness levels (TRLs) of low-carbonhydrogen production technologies vary widely, analysis reveals that
innovation gaps are concentrated in novel end-use industrial
applications, heavy road transport, shipping and aviation. Amongthese technologies, the most advanced are in the early adoption
stage, meaning they are ready for commercial applications but have
not yet obtained significant market shares. Storage and distribution,use in buildings and light-duty road transport are all sufficiently
developed for initial hydrogen use.
International patent family counts are a good proxy to measure
innovation activity in any given technology. The 676 patent families
registered for hydrogen production, storage and distribution
technologies in 2019 reflect a 52% increase since 2010. In 2019, thehighest shares of new patents were in Europe (30%) and Japan(25%).

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Patent applications by sector and region, 2010-2019

At present, patents for fuel cell technologies outnumber those forhydrogen production, storage and distribution by a ratio of nearly 3:1,
likely reflecting a higher TRL for the former as well the fact that fuelcell patent applicants include large companies (such as car
manufacturers) with large R&D budgets. Japan has a clear
technological lead in fuel cells, holding 39% of all patents, and thenumber of patent applications has been roughly constant over the
past decade. Electrolyser manufacturers, in comparison, tend to besmaller companies with lower R&D budgets. Their technologies can,however, benefit from progress in fuel cells, particularly in areas suchas materials or catalysts.

Fuel cells
2 000

2 000

1 500

1 500

1 000

1 000

500

500

0

0
2010

Europe

2012

2014
US

2016

2018
Japan

Korea

H₂ production, distribution andstorage

2010

2012

2014

China

2016

2018
Other

IEA. All rights reserved.

As public funding has been shared roughly equally between fuel cells
and other applications, one can infer that the private sector has driven
most of the innovation activity for fuel cells. A forthcoming study about
patenting activity in hydrogen, developed jointly by the IEA and theEuropean Patent Office, will be released in early 2022.

Source: Based on European Patent Office data.

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Innovation and demonstration urgently needed to unlock emissions reduction potential ofhydrogen technologies
Other key technologies, such as using hydrogen-based DRI for steel
manufacturing, are at even earlier stages of development. Theirinnovation cycle to reach demonstration and commercialisation
should be completed as soon as possible so that they can begin
effectuating CO2 emissions reductions in the early 2030s.

Ultimately, only 12% of cumulative emissions reductions to 2050
come from technologies that are ready to enter the market and scale
up production (e.g. light commercial vehicles). Most emissions
reductions come from critical technologies still being developed andrequiring demonstration to reach commercialisation, including cofiring ammonia and hydrogen in coal and natural gas power plants;
producing chemicals using electrolytic hydrogen; using hydrogen inheavy-duty vehicles; and using hydrogen and ammonia in shipping.
In the Net zero Emissions Scenario, these technologies startdelivering important CO2 emissions reductions as early as the 2020s.
While several ongoing initiatives aim to demonstrate thesetechnologies, innovation efforts should be stepped up to ensure theyreach commercialisation soon.

Global CO2 emissions reductions from hydrogen-based fuels bytechnology maturity in the Net zero Emissions Scenario,
2020-2050
Gt CO2Of the 60 Gt of CO2 emissions that hydrogen-based fuels can avoid
in the Net zero Emissions Scenario, 55 Gt are achieved after 2030,
reflecting that most end-use technologies for such fuels are not yet
commercially available. Assessing TRLs across the entire hydrogen
supply chain and in end-use sectors confirms the need to ramp up
innovation to stay on track with this scenario.

40

30

Small prototype
Large prototype

20

Demonstration
Market scale-up

10

Mature2020-30

2031-40

2041-50
IEA. All rights reserved.

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Regional insights

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United States: Stepping up efforts to develop hydrogen technologies
Owing to its large refining and chemical sectors, the United States isalready one of the largest producers and consumers of hydrogen.
With more than 11 Mt H2/yr of consumption, the United Statesaccounts for 13% of global demand: two-thirds is used in refining withmost of the rest going into ammonia production. Around 80% of US
hydrogen production is based on natural gas reforming; practically all
the remainder is met with by-product hydrogen in refineries and thepetrochemical industry.
The United States has been a traditional supporter of hydrogen as anenergy vector and a main advocate for the adoption of hydrogentechnologies in previous waves of interest. In the early 2000s, the US
government strongly promoted R&D on hydrogen and fuel cells, withfederal funding peaking at USD 330 million in 2007.
After a period of lower activity, the government again stepped up
efforts, and in 2016 the US Department of Energy introduced its
H2@Scale initiative to enable affordable and clean hydrogen across
end-use sectors (transport, metal refining, electricity generation,
heating, ammonia and fertilisers, etc.) from diverse domestic
resources, including renewables, nuclear energy and fossil fuels.

Instead of setting deployment targets, this programme focuses on
cost and performance targets that can enable the adoption ofhydrogen technologies. In 2020, the DOE Hydrogen Program Planestablished a framework to encourage R&D on hydrogen-related
technologies and eliminate institutional and market barriers to
adoption across multiple applications and sectors.
More recently (June 2021), the DOE announced Hydrogen Energy
Earthshot, an ambitious initiative to slash the cost of clean hydrogenby 80% – to USD 1.00/kg H2 – by 2030. By doing this, the US
government expects to unlock a fivefold increase in demand for cleanhydrogen. Previous economic analysis from the National Renewable
Energy Laboratory (NREL) shows detailed scenarios for expanding
the US hydrogen market size to 22-41 Mt – i.e. doubling or even morethan tripling current demand – even with prices of more than
USD 1.00/kg H2.
In June 2021, 17 MW of electrolysis for dedicated hydrogenproduction was operative in the United States, 34 with 1.4 GW ofcapacity in the project pipeline (300 MW under construction or withfunding committed) and another 120 MW at earlier stages of

The US DOE publishes regular updates on PEM electrolysers installed and under developmentin the United States.
34

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Global Hydrogen Review 2021

development which could become online by 2030. 35 The US DOE
estimates a potential deployment up to 13.5 GW based on company
proposals and projections. These numbers fall short of what isneeded to meet net zero goals.

60

3.0

40

2.0

20

1.0

0

Projects

APS

Electrolysis

Projects

APS

0.0

for enhanced oil recovery. In 2021, annual US production from fossil
fuels with CCUS was 0.23 Mt H2, around one-third of global
production capacity.
The largest project currently under construction in the world (Wabash
Valley Resources) is in the United States and expected to become
operational in 2022, which could push production capacity to over
0.3 Mt. To align with the Announced Pledges Scenario, however,capacity should expand to more than 2.5 Mt by 2030.

Mt H₂

GW

US electrolysis capacity and hydrogen production from fossil
fuels with CCUS in the Projects case and the Announced
Pledges Scenario, 2030

USD 50/t CO2 for geological storage of CO2 or USD 35/t CO2 if used

Pipeline
Early stages

Fossil w/ CCUS
IEA. All rights reserved.

Note: APS = Announced Pledges Scenario.
Source: IEA (2021), Hydrogen Projects Database.

In the Announced Pledges Scenario, 44 GW of electrolysis capacity
is deployed by 2030. US progress on deploying capacity to producehydrogen from fossil fuels with CCUS is accelerating in response to
the 45Q tax credit, which rewards CCUS projects at rates of35
Projects in the pipeline includes, in addition to projects already operational, projects currently
under construction, that have reached final investment decision (FID) or that are undergoing

The United States led global deployment of FCEVs until 2020, when
Korea pulled ahead. At the end of 2020, of the 9 200 FCEVs in the
country, most were in California, which has been supporting
deployment for almost a decade through the Clean Vehicle Rebate
Project and by funding construction of hydrogen refuelling stations(HRSs).
In 2013, Assembly Bill 8 (AB8) required establishment of at least 100
HRSs; this target was doubled in 2018 to 200 HRSs by 2025. The
main support mechanisms are grants (up to USD 115.7 million
offered in GFO-19-602) and credits under the Low Carbon FuelStandard Hydrogen Refuelling Infrastructure, which incentivise bothfeasibility studies. Projects for which there has just been an announcement or a cooperationagreement signed among stakeholders are considered projects at early stages of development.

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renewable hydrogen (33-40%) and high-capacity HRSs. To support
FCEV deployment, Air Liquide is building a 30-tpd renewable liquidhydrogen plant to supply HRS infrastructure in California.

1.5

Low-carbon hydrogen demand in the US industry sector in the
Announced Pledges Scenario, 2020-2030

Current stock
1.0
Ambitions
0.5
Projections

0.009
0.0

Pledges
2020

kt H2

FCEV stock (million)

FCEV deployment in the United States in the Announced
Pledges Scenario, 2020-2030

Opportunities to use low-carbon hydrogen in industry in the UnitedStates are mainly in the chemical sector. Low-carbon hydrogen isalready produced in facilities incorporating CCUS, particularly forammonia production. Since 2013, 1.7 Mt CO2 have been captured
every year at two fertiliser plants (Coffeyville and PCS Nitrogen),where captured CO2 is used for EOR.

2000
Iron and steel - electrolysis

1500

APS

Methanol - electrolysis
Methanol - CCUS

1000

2030

Ammonia - pyrolysis
Ammonia - electrolysis

IEA. All rights reserved.

Ammonia - CCUS

500

Merchant hydrogen

Notes: FCEV = fuel cell electric vehicle. APS = Announced Pledges Scenario.
“Ambitions” refers to the California Fuel Cell Partnership target.
Source: AFC TCP.

0

In addition to FCEVs, a successful DOE programme has triggeredcommercialisation of hydrogen fuel cells for material handlingequipment: in 2021, roughly 115 HRSs served over 40 000 fuel cellmaterial handling vehicles. While the US government has not set an
official federal target for FCEV deployment, the California Fuel Cell
Partnership aims for 1 million FCEVs in the state by 2030. In the APS,
national FCEV deployment slightly exceeds this target, reaching
1.1 million in 2030.

Projects
2020

APS
2030

IEA. All rights reserved.
Notes: APS = Announced Pledges Scenario. CCUS = carbon capture, utilisation andstorage.
Source: IEA (2021), Hydrogen Projects Database.

A small number of projects for the production of hydrogen from fossil
fuels with CCUS are currently in the pipeline in the United States. If
all these projects become fully operational, the production capacity
will meet 40% of the Announced Pledges requirement of 1.1 Mt H2

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Global Hydrogen Review 2021

produced from fossil fuels with CCUS in 2030. For electrolytichydrogen use, current announced projects fall far short of the 2030
Announced Pledges level of around 85 kt H2 for ammonia andmethanol production – i.e. 25 times the capacity of the single
ammonia project currently under development.
Interest is growing in the ways hydrogen can provide energy storage
and be used as a means of generating on-demand electricity tobalance the power grid as variable renewable generation increases.
The Advanced Clean Energy Storage Project (ACES), underdevelopment in Utah by Mitsubishi Power Americas and Magnum
Development, aims to pair 1 GW of electrolysers with large salt
caverns to store 150 GWh of dispatchable energy. The hydrogen will
be used in an 840-MW plant currently running on coal, which will
initially be converted to run on natural gas and hydrogen blends, theneventually modified to operate on 100% hydrogen. While this is oneof the largest project of its kind in the world, it would meet less than
12% of the nearly 1.4 Mt H2 needed for electricity generation by 2030
(according to the Announced Pledges Scenario) to keep the UnitedStates on track with its net zero target for 2050.
The significant hydrogen uptake projected in the Announced Pledges
Scenario, especially for new applications such as electricity
generation and transport, would require rapid deployment ofhydrogen infrastructure to facilitate delivery to end users. With morethan 2 600 km of hydrogen pipelines currently in commercial
operation, the United States accounts for over half of global hydrogenpipelines. Most are owned by merchant hydrogen producers and arelocated mainly in the Gulf Coast region where US refining capacity isconcentrated.
The Hydrogen Strategy, published by the DOE in July 2020,
considers blending an option to deliver pure hydrogen to downstream
markets, using separation and purification technologies near the
point of end-use. To help determine acceptable blending limits andmaterial compatibility, in 2020 the DOE, together with industry andnational laboratories, launched the HyBlend initiative.
In California, a first demonstration project using polymer-based
distribution pipelines is expected to launch in 2021, with an initialhydrogen blend level of 1 vol% H2, potentially rising to 20 vol% H2.
Meanwhile, Dominion Energy started a pilot project (spring 2021) toblend 5% hydrogen into a test gas distribution system. Kinder
Morgan, one of North America’s largest gas pipeline operators,
estimates that hydrogen in 5-10% blends could be transported
through natural gas transmission pipelines with little to nomodification.
At present, three of the four hydrogen salt caverns storage sites
operating globally are in the United States (all in Texas), including theworld’s largest facility in Spindletop (commissioned in 2016).

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Japan: Announcement of a 2050 net zero target triggers new push for hydrogen technologies
up to JPY 300 billion (~USD 2.8 billion) to develop international
supply chains (using liquefied hydrogen and liquid organic hydrogen
carriers) and to demonstrate co-firing or pure combustion of hydrogenin fossil-based electricity generation plants. In addition, JPY 330
billion (~USD 3.1 billion) have been allocated to innovation projects
for hydrogen applications in aviation, shipping, steelmaking,ammonia production and CO2 utilisation.

Japan has been spearheading efforts to adopt hydrogentechnologies. It was the first country to release a hydrogen strategy(December 2017) and has been leading international co-operation
since 2018 through its annual Hydrogen Energy Ministerial meetings.
The country considers hydrogen technologies as practical options todecarbonise significant parts of its energy and industry sectors andto boost energy security.

Current stock and 2030 target for FCEV deployment in Japan

Therefore, although Japan has yet to publish details on its plans toachieve the 2050 climate pledge announced by Prime Minister Suga
(October 2020), hydrogen is likely to be an important part of its
programme. The government’s Green Growth Strategy (announced
in June 2021) includes a target to expand hydrogen use to 3 Mt in
2030. To support this goal, the government announced a public
investment plan of JPY 700 billion (~USD 6.6 billion) to develophydrogen supply chains in Japan.
The plan includes up to JPY 70 billion (~USD 0.7 billion) for domestichydrogen production capacity based on dedicated renewables and

FCEV stock (million)

Hydrogen demand in Japan was close to 2 Mt H2 in 2020. Refining is
responsible for close to 90% of demand, with a small amount ofdomestic ammonia production making up the rest. Natural gas-based
production accounts for more than 50% of the country’s hydrogen
supply, and another 45% is by-product hydrogen from refineries andthe petrochemical industry and a small coal-based production
meeting the remainder.

1.0

0.5

0.004
0.0

Current stock
2020

Pledges
2030

IEA. All rights reserved.
Note: FCEV = fuel cell electric vehicle.
Source: AFC TCP, Strategic Roadmap for Hydrogen and Fuel Cells.

Japan has been a first mover in the use of hydrogen in transport, with
Honda offering the first commercial FCEV in 2008. With around 5 600
FCEVs (including cars and buses) on the road in April 2021, Japanis the fourth-largest market in the world and has ambitious targets for
FCEV deployment – 200 000 by 2025 and 800 000 by 2030. Toyota

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recently expanded fuel cell manufacturing capacity to 30 000 units/yr,
though capacity will need to expand further if domestic original
equipment manufacturers are to be relied upon to achieve
government targets.
Japan has shown interest in using hydrogen to decarbonise energy
demand in buildings. The ENE-FARM programme has subsidised
installation of more than 350 000 micro-cogeneration 36 fuel cells,
most fuelled by natural gas. Although ENE-FARM subsidies stopped
in FY2019 for PEM fuel cells, more than 40 000 micro-cogeneration
units were installed in 2020, similar to the number deployed annuallywhile the programme was active. Subsidies remain in place for
SOFCs until FY2020.
On the supply side, in 2020 a 10-MW solar-powered electrolysis
project was inaugurated in Fukushima, the world’s largest at the time.
To date, Japanese stakeholders have not announced plans to deploy
significant electrolysis capacity for dedicated hydrogen production;
only some small projects (<5 MW) have been announced forupcoming years. This outlook may change following the government
announcement of a budget of JPY 70 billion 70 (~USD 0.7 billion) toscale up and modularise electrolysers with the aim of decreasing
manufacturing costs.
Regarding hydrogen production from fossil fuels with CCUS, theTomakomai demonstration project was operational until 2019, and no
projects for the near future have been announced. Low-carbon

36hydrogen production needs to be accelerated and internationalhydrogen supply chains must be developed to meet Japan’s strategy
target of 420 kt of low-carbon hydrogen by 2030. Japan is currently
updating its strategy to align with its revised climate target, but it islikely that achieving the new targets will require substantial volumesof low-carbon hydrogen, with a significant portion having to beimported.
Japan has also targeted the use of ammonia as a fuel. In February
2021, the government released an Interim Report of the PublicPrivate Council on Fuel Ammonia Introduction highlighting its
potential use in shipping and for co-firing in coal power plants to
reduce their carbon intensity and avoid decommissioning them, as
they are critical to Japan’s electricity supply security. The concept
was demonstrated at small scale by Chugoku Electric Power
Corporation, and now JERA is scaling up the concept to demonstrate
a 20% co-firing share of ammonia at a 1-GW coal-fired unit by 2024.
Using 100% ammonia in electricity generation is also gaining traction:
Mitsubishi Power announced it is developing a 40-MW gas turbine
able to run on ammonia, aiming to commercialise it in 2025. By 2030
in the Announced Pledges Scenario, Japan consumes close to
3 Mt NH3 as fuel, mostly for co-firing in coal plants but also 0.25 Mt
as fuel for maritime transport and. In addition, 0.7 Mt is used as
feedstock in the chemical industry.

Co-generation refers to the combined production of heat and power
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Low-carbon hydrogen and fuel ammonia demand in Japan in the
Announced Pledges Scenario, 2030

commercial supply chain between Australia and Japan would require
ships with much larger capacity, estimated by HESC project
developers at four tanks, each with 40 000 m3 of capacity. Ships ofsimilar size to Suiso Frontier could be used for shorter distances.

Ammonia demand

Low-carbon H₂ demand

4.0

Domestic
production
36%
Imports64%

Mt NH₃

3.0
2.0
1.0
0.0

Total

Expected
demandPower

APSShipping

IEA. All rights reserved.
Notes: APS = Announced Pledges Scenario. “Expected demand” represents the
proposal of the Interim Report of Public-Private Council on Fuel Ammonia Introduction.

Japan has been very active in developing international hydrogen
trade: various projects are ongoing with Australia, Brunei, Indonesia,
Saudi Arabia and the United Arab Emirates. Most noteworthy is theHydrogen Energy Supply Chain (HESC) project, led by the Hydrogen
Energy Supply-chain Technology Research Association (HySTRA),
which aims to establish a hydrogen supply chain between Australia
and Japan. As part of this project, in 2020 Kawasaki Heavy Industries
presented its Suiso Frontier, the world's first liquefied hydrogen
carrier; the first demonstration shipments will take place will takeplace during the first quarter of 2022. The Suiso Frontier has one tankwith a capacity of 1 250 m3, which can store 75 t H2. A future

Japan has also spearheaded development of international fuelammonia trade. In September 2020, the world’s first shipment ofammonia produced from fossil fuels with CCUS (40 t NH3) took place
between Saudi Arabia and Japan. Plus, the Japan Oil, Gas andMetals National Corporation (JOGMEC) recently launched several
initiatives with partners in Japan and around the world. With the aimof supplying low-carbon ammonia to Japan, JOGMEC, Mitsubishi
Corporation, the Bandung Institute of Technology and PT Panca
Amara Utama (PAU) agreed (March 2021) to conduct a joint study on
producing ammonia from natural gas with CCUS in a PAU plant inCentral Sulawesi (Indonesia).
Additionally, in July 2021 JOGMEC, INPEX Corporation and JERA
announced a joint study agreement with the Abu Dhabi National Oil
Company (ADNOC) to explore the commercial potential of lowcarbon ammonia production in the United Arab Emirates and toprovide a platform for ADNOC and its partners to explore supplying
Japanese utility companies. Also in July 2021, JOGMEC signed ajoint research agreement with Woodside Energy, Marubeni
Corporation, Hokuriku Electric Power Company and Kansai ElectricPower to develop a supply chain from Australia to Japan for fuelammonia produced from natural gas with CCUS.

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European Union: EU Hydrogen Strategy set the foundation in 2020, but meeting net zero targets
will require ambitious action in next decade
Close to 7 Mt H2 were produced and used in the European Union in
2020. Refining (3.7 Mt H2) and the chemicals sector (3.0 Mt H2) werethe main consumers of hydrogen, which was produced mainly fromunabated natural gas (two-thirds of total production) and as a byproduct in refineries and the petrochemical sector (30%).
In November 2018, the European Commission set out its vision forreaching net zero emissions by 2050, followed in March 2020 by the
proposal for the first European Climate Law, which was adopted by
the European Council in June 2021. To date, most decarbonisation
efforts have focused on electricity generation, but adoption of the
net zero target widened the scope beyond the power sector to include
industry, transport, agriculture and heating in the built environment.
In turn, interest in hydrogen has grown exponentially, with launch of
the EU Hydrogen Strategy (July 2020) and the European Clean
Hydrogen Alliance (November 2020) being major milestones. The
strategy emphasises use of hydrogen in industry and heavy transport
as well as its balancing role in the integration of variable renewables(particularly offshore wind in the northwest region and solar PV in thesouth). The Alliance brings together industry, national and local publicauthorities, civil society and other stakeholders to implement thestrategy.

On the supply side, electrolytic hydrogen from renewable sources is
considered the main route for hydrogen production, although the roleof other low-carbon technologies in the near term is recognised as
the hydrogen market develops and scales up and the cost ofelectrolytic hydrogen decreases. Beyond decarbonising hydrogenproduction, the European Union sees electrolysis as a strategic
opportunity to export technology: EU countries currently hold morethan 60% of global electrolysis manufacturing capacity. With the aimof creating market rules for hydrogen deployment, the Hydrogen
Strategy also announced a review of the legislative framework forgases.
The strategy envisages three phases for hydrogen adoption. The firstphase (until 2024) focuses on scale-up, with an interim target of 6 GWof renewable energy-powered electrolysis to decarbonise current
production capacities and trigger uptake in some new uses (e.g.
heavy-duty transport). In the second phase (2025-2030), hydrogenshould become an intrinsic part of an integrated energy system while
renewable hydrogen becomes cost-competitive and reaches new
applications (steelmaking or shipping). By 2030, 40 GW of renewableenergy-powered electrolysis should be installed. In the third phase

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(post-2030), renewable hydrogen technologies should reach maturity
and be deployed at large scale to reach all hard-to-decarbonise
sectors.

technologies to prioritise. Practically all have deployment targets forelectrolysis by 2030, amounting more than 20 GW by 2030 (withanother 7 GW in the planned strategies of Italy and Poland).

In December 2020, the European Commission adopted a proposal torevise the EU rules on Trans-European Networks for Energy (theTEN-E Regulation) to end support for natural gas pipelines, instead
including cross-border hydrogen networks as infrastructure eligible
for EU support as Projects of Common Interest. The proposal covers
both new and repurposed assets for dedicated hydrogen transportand large-scale electrolyser projects linked to cross-border energy
networks.

Hydrogen-related targets proposed by the European Commission
in the Fit for 55 package

A significant step taken by the European Commission in adopting
low-carbon hydrogen technologies came from proposals to modify
directives and regulations announced in July 2021 as part of the Fit
for 55 package. If approved by the EU Council and the EU
Parliament, these proposals will incorporate into EU legislation
several targets for using hydrogen and hydrogen-based fuels inindustry and transport, and for developing required infrastructure.
Some EU countries have also released national hydrogen strategies(the Czech Republic, France, Germany, Hungary, the Netherlands,
Portugal, and Spain); others are under public consultation (Italy and
Poland) or expected to be released soon (Austria). While focusing oneach country’s strengths, these strategies are very aligned with eachother and with the EU Hydrogen Strategy in terms of sectors andProposalTargetRenewable Energy
Directive modification

50% renewable hydrogen consumption in industry by
2030

Renewable Energy
Directive modification

At least 2.6% share of renewable fuels of nonbiological origin in 2030*

ReFuelEU Aviation

0.7% share of synfuels in aviation by 2030
5% by 2035
8% by 2040
11% by 2045
28% by 2050

Regulation on
deployment ofalternative fuels
infrastructure

1 HRS (>2 t H2/day of capacity and 700-bar
dispenser) every 150 km along major routes
1 HRS with liquid hydrogen every 450 km* Renewable fuels of non-biological origin include hydrogen and hydrogen-based fuels

produced from renewable electricity.

The European Union has registered progress in adopting hydrogentechnologies. The Fuel Cells and Hydrogen Joint Undertaking(FCH JU) has played a fundamental role with its programmes tosupport research, innovation and demonstration. More than 140 MWof electrolysis for dedicated hydrogen production have been installed,accounting for more than 40% of global capacity. The strong signals
sent by government strategies have created momentum for additional
deployment, with the pipeline of projects currently under development

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accounting for more than 20 GW by 2030 (11 GW more from projects
at very early stages of development), although initial assessment by
the Clean Hydrogen Alliance suggests that total electrolysis capacity
at different stages of development could be larger.

GW

Electrolysis capacity deployment in the EU in 2030 in the
Projects case and the Announced Pledges Scenario comparedwith national and EU targets
60

EU total
Italy
PolandSpain
Portugal
Netherlands
Hungary
Germany
France

50
40
30
20
10
0

Projects

PledgesAPS

capacity deployment needed to meet the EU pledge of net zero
emissions by 2050. The Announced Pledges Scenario shows morethan 50 GW of electrolysis deployed in EU countries by 2030.
Progress in deploying hydrogen production from fossil fuels with
CCUS has been slower, despite its envisaged near-term importance.
Two projects are already operational in the European Union, although
in both cases for hydrogen production from fossil fuels and CCU: theShell gasification project at the Pernis refinery (the Netherlands) and
Air Liquide’s Port Jerome project (France).
The Netherlands is the most active country in developing hydrogenproduction from fossil fuels with CCUS. Through its SDE++ scheme,
the Dutch government recently committed EUR 2 billion to fundPorthos, a project to develop CO2 transport and storage infrastructurein the Port of Rotterdam, which will store 2.5 Mt CO2 annually, with asignificant share coming from hydrogen production.

Early stages
Pipeline
IEA. All rights reserved.

Note: APS = Announced Pledges Scenario.
Sources: IEA (2021), Hydrogen Projects Database; National Strategies, CEM H2I
consultation.

Of the more than 20 GW in the pipeline, more than 1 GW is alreadyunder construction or has funding committed. While the current
project slate may not meet the EU target, the number of projects is
growing quickly and the gap is shrinking. However, both the current
project pipeline and the EU target may fall short of the electrolysis

The current pipeline of projects for producing hydrogen from fossil
fuels with CCUS will more than meet EU net zero ambitions. While in
the Announced Pledges Scenario 3 Mt CO2 are captured fromhydrogen production in the European Union by 2030, currently the
project pipeline amounts to more than 7 Mt CO2 captured (plus close
to 3 Mt CO2 more from projects at early stages of development),
although this figure could be significantly lower. Several projects arelarge CCUS hubs that will involve activities beyond hydrogen

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production and, as such, it is difficult to estimate how much of the
projected capture capacity would be linked to hydrogen production.
In transport, some 2 200 FCEVs were on the road in EU countries by
the end of 2020 (mostly passenger cars) and around 165 HRSs werein operation. Germany has the largest number of both, but the Czech
Republic, France, the Netherlands, Portugal and Spain have FCEV
targets that, if achieved, would result in about 415 000 FCEVs by2030. In the Announced Pledges Scenario, FCEV deployment
reaches 1.5 million by this date.

FCEV stock (million)

FCEV deployment the European Union in the Announced
Pledges Scenario, 2020-2030
2.0

Projections

1.5

Ambitions

1.0

Official government
targets

0.5

Current stock

0.002
0.0

Pledges
2020

APS
2030
IEA. All rights reserved.

Notes: FCEV = fuel cell electric vehicle. APS = Announced Pledges Scenario. FCEV
ambitions include unpublished government targets from Italy and Slovakia.
Sources: AFC TCP; National Strategies; CEM H2I consultation.

In the industry sector, EU stakeholders have been active in recent
years and some significant developments are taking place. As part of
the REFHYNE project, in July 2021 ITM and Shell put a 10- MW PEM
electrolyser in the Rhineland Refinery (Germany) into operation. In
steel manufacturing, Thyssenkrup has demonstrated using hydrogento partially replace pulverised coal in one of the tuyeres of a blast
furnace – and is working to extend this practice to other blast
furnaces.
Since 2019, the H2FUTURE project has been feeding hydrogenproduced in a 6 MW PEM electrolyser via the coke gas pipeline to a
blast furnace of the steel works (Linz, Austria). Meanwhile, the
HYBRIT project – the first attempt to produce steel from DRI using
pure hydrogen – is currently at the pilot stage (4.5 MW of electrolysis
capacity) but is expected to advance to a demonstration facility by
2025. Also in steel manufacturing, the largest SOEC electrolyser inthe world (0.72 MW, manufactured by Sunfire) became operational in
the GrinHy2.0 project.
In the chemical sector, Fertiberia and Iberdrola in Spain are building
the world’s largest demo project (20 MW) to produce electrolyticammonia, expected to become operational at the end of 2021. The
GreenLab Skive (Denmark) is building a 12 MW demonstrator formethanol production, to start operations in 2022. These proposed
projects will not meet Announced Pledges goals for 2030, however.

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Projects currently under development account for 1.1 Mt of
low-carbon hydrogen use by 2030 (0.3 Mt more if early-stage projects
are realised), whereas required Announced Pledges consumption is
10% higher.

kt H2

Low-carbon hydrogen demand in EU industry in the Announced
Pledges Scenario, 2020-2030
2000
1500

Early stages
Iron and steel - electrolysis
Methanol - electrolysis

1000

Methanol - CCUS
Ammonia - electrolysis

500

Merchant hydrogen

0

Projects
2020

APS
2030

IEA. All rights reserved.
Notes: APS = Announced Pledges Scenario. CCUS = carbon capture, utilisation andstorage.
Source: IEA (2021), Hydrogen Projects Database.

The first steps to develop hydrogen-specific infrastructure for delivery
to end users have already been taken. Europe has more than
1 600 km of hydrogen pipelines, mostly owned and operated byindustrial producers and users, but large-scale deployment of lowcarbon hydrogen will require additional transmission and distribution
systems.

A consortium of gas grid operators therefore presented a European
Hydrogen Backbone (EHB) initiative proposal in 2020 (updated in2021). Across 21 countries (including non-EU countries such as
Switzerland and the United Kingdom), the EHB envisions 39 700 kmof pipelines by 2040 – with 69% being repurposed natural gas
networks and 31% newly built hydrogen pipelines. The first natural
gas pipeline, 12 km with throughput capacity of 4 kt H2/yr, has been
converted and put into commercial service (November 2018) by
Gasunie in the Netherlands.
In June 2021, Gasunie also announced that it had been asked by theState Secretary for Energy and Climate to develop a national
infrastructure for hydrogen transport by 2027, of which 85% will be
repurposed natural gas pipelines. In September 2021, the Dutch
government announced an investment of EUR 750 million (as part ofa wider EUR 6.8 billion package on climate measure) to convert partsof the existing gas network into hydrogen transport infrastructure.
Furthermore, based on project submissions, the latest Ten-Year
Network Development Plan of the European Network ofTransmission System Operators for Gas assessed that roughly
1 100 km of gas pipelines could be converted to hydrogen by 2030,
but FIDs have not yet been secured for these projects.
Several EU countries are also undertaking pilot blending projects,
including France, Germany, the Netherlands and Portugal. In May
2021, the Government of Germany announced that 62 large-scalehydrogen projects, including pipeline transport, have been selected
for further assessment for funding of up to EUR 8 billion under the
Important Projects of Common European Interest (IPCEI) scheme.

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China: Hydrogen development focused on transport, but carbon-neutrality pledge will offer
opportunities for other applications, particularly in industry
FCEV deployment in China in the Announced Pledges Scenario,
2020-2030
FCEV stock (million)

With annual consumption of more than 25 Mt, China is the world’s
largest hydrogen user, mainly in refining (9 Mt H2) and the chemical
sector (16.5 Mt H2). This demand is met by domestic production
based on fossil fuels, with coal accounting for 60% and natural gas
for 25%. The remaining 15% is by-product hydrogen from refineries
and the petrochemical industry.
In 2020, China announced its ambition to reach carbon neutrality by
2060. Hydrogen use will be important, especially in the country’s vast
industry sector, which accounts for 60% of final energy demand.
Using hydrogen as an alternative to fossil fuels received attention
even before China’s net zero pledge, as it was seen as a means toaddress air quality concerns in cities.

1.5

Projections

1.0

Ambitions

0.5

Official government
targets
Current stock

0.008
0.0

Pledges
2020

APS
2030
IEA. All rights reserved.

As such, practically all developments around hydrogen adoption for
new uses have focused on transport. Initial projects were based onusing by-product hydrogen from coke ovens and petrochemical
processes, which facilitated access to low-cost hydrogen in industrial
hubs, and deploying fuel cell truck and bus fleets which maximise
utilisation rates of HRSs. Thanks to these strategies and government
support schemes, China has now the world’s third-largest FCEV
stock and leads in fuel cell truck and bus deployments. At the end of
2020, 8 400 FCEVs had been deployed, of which two-thirds werebuses and one-third trucks.

Notes: FCEV = fuel cell electric vehicle. APS = Announced Pledges Scenario. Official
government targets include city and provincial targets; ambitions refer to additional
FCEV deployment needed to achieve the China Society of Automotive Engineers
target.
Source: AFC TCP.

Although the government does not have an official target for FCEV
adoption, the China Society of Automotive Engineers targets 1 million
FCEVs by 2030. In response to China’s recent pilot cities
programme, which rewards city clusters for FCEV deployment andsupply chain development, several city- and province-level targets
have been set. Beijing and Shanghai each aim for 10 000 FCEVs by

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More recently, China has recognised how important hydrogen can bein transforming the energy system, and interest is growing beyond
transport, particularly in industrial applications. China is the largest
producer of methanol, ammonia and steel, three subsectors in which
low-carbon hydrogen use could play a significant in the future.
Beyond its traditional production and use in industry, low-carbonhydrogen adoption is in the early stages in China, with first steps fordemonstrating new applications forthcoming.

These demonstration projects could lay the groundwork for lowcarbon hydrogen adoption in China’s industry sector. Althoughprojects currently under development could result in 45 kt of lowcarbon hydrogen production and use in industry by 2030, this is wellshort of the Announced Pledges projection of 2.2 Mt, produced
mostly through electrolysis.

Industry hydrogen demand in China in the Announced Pledges
Scenario, 2020-2030
Mt H₂

2025, and Guangzhou envisions 100 000 by 2030. In the Announced
Pledges Scenario, China’s FCEV stock reaches 750 000 in 2030.

20

In the chemical sector, Ningxia Baofeng Energy Group is building theworld’s largest electrolysis plant for dedicated production of hydrogento provide some of the feedstock for making the methanol used in its
coal-to-olefins project in Ningxia Province. The company has alreadyinstalled a 30-MW electrolyser and intends to add 70 MW ofelectrolysis capacity by the end of 2021.
Baosteel, the country’s largest steel producer, has pledged to reachnet zero emissions by 2050, relying in part on developing hydrogenbased DRI production at scale by 2035. Meanwhile, Hebei Iron andSteel Group (HBIS), the second-largest producer, has taken the firststep towards hydrogen steelmaking, developing a small but
commercial-scale DRI project to blend 70% hydrogen (with 30% cokeoven gas) for ironmaking.

25

Electrolysis
Merchant hydrogen

15

Fossil with CCUS
Fossil

10
5
0

2020

2030 APS

IEA. All rights reserved.
Notes: APS = Announced Pledges Scenario. CCUS = carbon capture, utilisation andstorage.

China’s greatest challenge is to decarbonise existing hydrogenproduction while deploying new production capacity to meet demand
from new applications. At present, hydrogen production creates direct

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emissions of 475 Mt CO2/yr. 37 Therefore, to stay on track with longterm climate ambitions, low-carbon hydrogen production technology
deployment needs to accelerate in the next decade. By 2030 in the
Announced Pledges Scenario, more than 20 GW of electrolysis is
deployed in China, most of it in industrial facilities for producing
methanol and ammonia. Plus, the first plant for manufacturing steel
through DRI using hydrogen sequestered from coke oven gas should
start operating by the end of 2021, and second-phase expansion andconversion towards electrolytic hydrogen should then begin.

potential is considerable but energy demand is fairly low. The
resulting electricity grid congestion has forced some regional
governments to limit the amount of power that can be loaded intotransmission grids. Electrolysis can minimise curtailment andstore energy for local use or for transport to regions with lower
renewable energy potential and large energy needs.



The cost of alkaline electrolysers in China is low –USD 750-1 300/kW including electrical equipment, gas treatment,
plant balancing, and engineering, procurement and construction(EPC), with some sources reporting as low as USD 500/kW 38 –compared with the average of USD 1 400/kW in the rest of theworld. Other factors, such as electrolyser reliability and durability,
differ among regions and could strongly affect hydrogenproduction costs over a plant’s lifetime.
China has also deployed a huge amount of renewable energy
generation capacity in recent years, especially in regions where

37
This includes 115 Mt CO2 emitted through the use of hydrogen-derived products (e.g. urea andmethanol) that capture carbon only temporarily.

GW

25

1.0

20

0.8

15

0.6

10

0.4

5

0.2

0

0.0

Projects

APS

Electrolysis

Projects

APS

Mt H₂

Electrolysis capacity and hydrogen production from fossil fuelswith CCUS in China in the Projects case and the Announced
Pledges Scenario, 2030

Compared with other regions, China was slow to deploy electrolysis
for dedicated hydrogen production; as a result, projects underdevelopment are insufficient to reach China’s goals for 2030.
However, several factors have triggered significant acceleration in
the last two years:


China accounts for one-third of global electrolyser manufacturing
capacity. In response to anticipated domestic market growth, allmajor manufacturers have announced plans to expand their
manufacturing capacity.

Pipeline
Early stages

Fossil w/ CCUS
IEA. All rights reserved.

Notes: APS = Announced Pledges Scenario. CCUS = carbon capture, utilisation andstorage.
Source: IEA (2021), Hydrogen Projects Database.

Based on CAPEX for the electrolyser system itself of USD 200/kW (China EV100, 2020; MOST,
2021). Including electrical equipment, gas treatment as well as EPC increases the overall CAPEX
to USD 500/Kw.
38

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The use of carbon capture to decarbonise current fossil fuel-basedhydrogen production will also need to ramp up. This could beparticularly beneficial for the chemical industry in China’s northwestern regions, where a very young fleet of plants currently uses
coal to produce hydrogen-based ammonia and methanol. In the
Announced Pledges Scenario, production capacity of 0.7 Mt H2 in thechemical industry is retrofitted with CCUS by 2030.

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Canada: Hydrogen to play a critical role in net zero ambitions and economic growth throughexports
In 2020, Canada produced and used around 3 Mt H2, almost equally
split between refining and the industry sector. Around 80% of
production is based on natural gas, and the remainder is by-productgas from refineries.

exporter of hydrogen-based fuels. As it is home to some of thesector’s major technology developers (e.g. Ballard and Hydrogenics,
recently acquired by Cummins), the potential to export hydrogentechnologies is also high.

In December 2020, Canada released its strengthened climate plan,
which lays the foundation to reach net zero emissions by 2050.
Hydrogen and other clean fuels feature prominently in this plan. Alsoat the end of 2020, Canada released its Hydrogen Strategy with a callfor action to promote investments and partnerships among national
stakeholders,
sub-national
governments
andindigenousorganisations, as well as at the international level, to seize theeconomic and environmental opportunities that hydrogen can offer.
The strategy shows that, in a net zero future, Canada's economy will
be mobilised by two equally important pathways: clean power andclean fuels, with hydrogen making up to 30% of the energy mix.

The Canadian government has already established a series of clean
energy support programmes to enable the development of businesscases for hydrogen technologies. In June 2021, Natural Resources
Canada announced the Clean Fuels Fund, providing CAD 1.5 billion(~USD 1.1 billion) to help private investors with upfront capital costs
to construct new clean fuel production capacity, including support fordeveloping at least ten hydrogen projects. In addition, the Net zero
Accelerator initiative will provide up to CAD 8 billion (~USD 6.0 billion)
for projects that reduce domestic GHG emissions, including
decarbonisation of large industrial emitters, fuel switching tohydrogen in industrial processes, and development of CCUS
capacities for hydrogen production in heavy industries already usinghydrogen.

The Canadian strategy addresses the role of hydrogen across a very
wide range of end-use sectors, including industry, refining, transport,
power and buildings. It also sees the variety of domestic energy
resources available as a great opportunity to diversify the mix oftechnologies to produce hydrogen. This mix includes oil and gas
reserves (coupled with CCUS) in Alberta, Saskatchewan, British
Columbia and the East Coast, an 80% non-emitting power grid,
nuclear capacity, and large renewable capacity. Based on these vast
resources, Canada has an ambitious goal to become a major

Even before the national hydrogen strategy and related programmes
were launched, Canadian stakeholders had been very active. With
four operative projects capturing and storing around 3 Mt CO2/yr,
Canada is the second-largest producer of hydrogen from fossil fuelswith CCUS. Another four projects are under development, aiming tocapture an additional 5.0 Mt CO2/yr (1.8 Mt CO2/yr if early-stage

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However, projects under development aim to produce merchanthydrogen for diverse applications rather than decarbonise existinghydrogen production capacity in the chemical sector. Consequently,
almost 200 kt H2 (0.5 Mt H2/yr with early-development projects) in
fossil fuel with CCUS production capacity for industrial applications
could be reached by 2030 – almost reaching the capacity in the
Announced Pledges. Initiatives such as the Net zero Accelerator can
speed deployment of low-carbon hydrogen capacity in industrial
processes to better align with the Announced Pledges Scenario.
Concerning electrolysis, in January 2021 Air Liquide put into
operation the world’s largest PEM electrolysis plant at Bécancour.
The project, which includes a 20 MW electrolyser running onhydropower, doubled the site’s hydrogen production capacity.
Currently, close to 100 MW of electrolysis projects are at different
stages of development; if all are realised, total installed electrolysis
capacity for dedicated hydrogen production could reach around
120 MW. In the Announced Pledges Scenario, electrolysis capacity
in Canada reaches more than close to 4 GW by 2030, 40 times morethan the capacity currently under development.

GW

6.0

1.5

4.0

1.0

2.0

0.5

0.0

Projects

APS

Electrolysis

Projects

APS

0.0

MtH₂

Electrolysis capacity and hydrogen production from fossil fuelswith CCUS in Canada in the Projects case and the Announced
Pledges Scenario, 2030

projects are included). If all are realised, total hydrogen production
from fossil fuels with CCUS could reach close to 1 Mt H2/yr in 2030
(0.2 Mt H2/yr with early-development projects) – around 70% higher
than in the Announced Pledges Scenario.

Pipeline
Early stages

Fossil w/ CCUS
IEA. All rights reserved.

Notes: APS = Announced Pledges Scenario. CCUS = carbon capture, utilisation andstorage.
Source: IEA (2021), Hydrogen Projects Database.

In the transport sector, Canada had a stock of around 130 FCEVs atthe end of 2020. In the Announced Pledges Scenario, FCEV stock
reaches close to 50 000 in 2030. Recent measures can facilitate thisdeployment: for instance, in December 2020 the government
announced a new Clean Fuel Standard that will require liquid fuelsuppliers to gradually reduce the carbon intensity of the fuels they
produce and sell for use in Canada (final regulations will be publishedat the end of 2021). In June 2021, the government committed to a
mandatory 100% ZEV sales target by 2035, followed by theannouncement in August 2021 of a CAD 2.75 billion (~USD 2.1
billion) Zero Emission Transit Fund to support the purchase ofzero emission public transit and school buses and associatedinfrastructure.

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Other regions: Hydrogen momentum is building as more countries get on board
AfricaOf Africa’s annual close to 3 Mt H2 consumption, 70% is used in thechemical sector, mainly to produce nitrogen fertilisers that boost crop
yields and replenish soil nutrients and are thus a critical componentof food security across the continent. Without synthetic nitrogen
fertilisers (together with other macro-nutrients), soil fertility would besignificantly lower and land required for farming significantly higher.
Africa is one of the few places in the world where fertiliser use is
projected to grow strongly in upcoming years, even as care is taken
to apply it efficiently and judiciously, identifying the right fertiliser
source, applying it at the right rate, at the right time and in the rightplace (CITE). In turn, ammonia production (the starting point of allsynthetic nitrogen fertilisers) for existing agricultural and industrial
uses increases 40% by 2030 in the Announced Pledges Scenario(see the IEA’s forthcoming Ammonia Technology Roadmap).
Virtually all hydrogen production in Africa is currently based on fossil
fuels, including the portion used to produce nitrogen fertilisers. The
ability to produce hydrogen from renewables is therefore a great
opportunity for African countries to replace fossil fuel-based
production, which in many cases depends on imports. This isparticularly important for landlocked countries that face additional
challenges in distributing fertiliser and/or securing the natural gas
needed to produce it.

Africa’s potential to generate low-cost renewable electricity to
produce low-carbon hydrogen is considerable. As electrolyser andrenewable electricity generation costs continue to decline, cost parity
with fossil fuel-based generation is a genuine prospect in the medium
to long term in locations with the best renewable resources. In areas
where the necessary transport and storage infrastructure is practicaland scalable, low-cost natural gas equipped with CCUS is anotheroption to produce low-carbon hydrogen for ammonia synthesis.
Having an indigenous supply of nitrogen fertilisers made using lowcarbon hydrogen would reduce CO2 emissions from this energyintensive industry while also boosting food security by reducing
dependence on food imports.
Developing projects to produce renewable hydrogen for fertiliser
manufacturing can also create high-quality jobs and spur economic
growth, although project realisation will hinge on innovation andscale-up to close the cost gap with conventional production methods.
Due to unfavourable economics, two large electrolysers (of 100 MW
in Zimbabwe and 165 MW in Egypt) producing ammonia using
renewable electricity from hydropower installations closed or
switched to natural gas in the last decade, highlighting the challenges
facing this technology option.
Similarly, ultra-low-cost electricity at a high capacity factor, or variable
renewable electricity combined with hydrogen storage, is required for

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electrolysis-based ammonia production to become competitive withnatural gas, even when equipped with CCUS. Given the practicalease and relatively low cost of shipping nitrogen fertiliser products(e.g. urea produced in the Middle East), cost reductions in the
production process are required to make electrolysis a viable option
for a price-sensitive market segment and region.
On-site production, storage and use of renewable hydrogen in minigrids to generate electricity in remote areas is another hydrogen
application attracting great interest. In fact, this concept has alreadybeen demonstrated. Hydrogen South Africa (HySA) has been
operating a hydrogen-based mini-grid installed at a high school in
Goedgevonden since April 2018, and Tiger Power is developing a
project to power 3 000 rural households and businesses in Kyenjojo(Uganda). This application is cost-competitive with the traditional useof diesel for remote power generation, thus facilitating electricity
access while decreasing CO2 emissions.
Some countries in the region have taken the first steps to seize theopportunities hydrogen can offer. Morocco is leading the way with its
Green Hydrogen Cluster, established by the government to promotecollaboration among private and academic stakeholders to support
the emerging renewable hydrogen sector. With the dual objectives ofcollaborating in technology development and positioning Morocco asa potential exporting hub, the government has been building
international partnerships with countries such as Germany andPortugal.

Some activity is also well under way in South Africa, ledpredominantly by the private sector. Anglo American is building a
3.5-MW electrolyser at its mine in Mogalakwena to produce hydrogenon site to fuel a hydrogen-powered fuel cell electric haul truck.
Expected to become operational in 2021, the project will be a first
demonstrator to gain operational knowledge and experience, andthus support replication at other mines around the world.

Australia
In November 2019, Australia launched its National Hydrogen
Strategy. It explores potential for clean hydrogen production, outlines
a plan for quick scale-up and details the necessary co-ordinatedactions for governments, industry and communities. As part of thisplan, the government has invested over AUD 1.3 billion (~USD 1.0
billion) to accelerate domestic hydrogen industry growth. The
strategy also highlights the significant opportunity offered byhydrogen exports, which the government is fostering by developing
international partnerships with Singapore, Germany, Japan, Korea
and, more recently, the United Kingdom.
Current hydrogen demand in Australia is very small, practically all
used in refining and ammonia production; moreover, growth indomestic demand is generally seen as limited. However, the country
has tremendous potential to affordably produce low-carbonhydrogen, which can decarbonise production for both domestic use
and export. Recognising this opportunity, the government has

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invested in seven hydrogen hubs that centralise
geographically, thereby minimising infrastructure costs.

users

Australia’s potential to produce hydrogen from renewables is
considerable. Currently, nine projects with a capacity >1 GW are
under development or at early stages. These include some of theworld’s largest projects: the Western Green Energy Hub (20 Mt
NH3/yr, equivalent to >20 GW of electrolysis capacity); the Asian
Renewable Energy Hub (14 GW); HyEnergy Zero Carbon Hydrogen(8 GW); and the Murchison Project (5 GW). If all projects underdevelopment are deployed, electrolysis capacity in Australia willreach nearly 20 GW by 2030 (33 GW including early-stage ones), thevast majority aiming to export hydrogen and ammonia. However, theAsian Renewable Energy Hub recently encountered government
pushback; in June 2021 its application was rejected due to potential
adverse impacts on habitats and native species.
Australia has also significant fossil fuel resources, particularly
Victoria’s brown coal reserves. Combined with CCUS, they could be
another energy source for low-carbon hydrogen production. The first
facility for producing hydrogen from coal started operation (in the
Latrobe Valley) in March 2021 as part of the HESC project lead by
HySTRA. The facility is not incorporating CCUS in its first phase, but
it will be retrofitted with CCUS capabilities by 2030, subject tosuccessful demonstration of the economic viability of transporting
liquid hydrogen from Australia to Kobe in Japan.

India
More than 7 Mt H2 was used in India in 2020, with 45% used forrefining, 35% for chemicals and almost 20% for iron and steel. Indiais the world’s largest producer of steel using the DRI route,consuming one-quarter of global hydrogen demand for this end use.
Practically all hydrogen demand is met through domestic production
based on fossil fuels, with natural gas accounting for three-quarters,
coal for more than 15% and by-product from refineries making up therest.
Irrespective of the scenario context, hydrogen use in India is
expected to rise substantially in the next decade as population growthand greater prosperity necessitate increased food production(requiring ammonia) and new infrastructure (requiring steel). In the
Announced Pledges Scenario, hydrogen demand grows to close to
11 Mt H2 by 2030, with DRI-based steelmaking accounting for around
30% of this increase.
India’s enormous potential to expand hydrogen demand and its
considerable renewable energy possibilities offer an extraordinary
opportunity to decarbonise the industry sector while also reducing
fossil fuel import dependency. If electrolysis were deployed at scale
and the potential for cost reductions materialised, India could be oneof the regions with the lowest costs for producing hydrogen fromrenewables.

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As early as 2030, hydrogen production from renewables could costjust USD 1.4-3.7/kg H2, competitive with production throughunabated fossil fuel methods. Low production costs for renewablehydrogen could enable the export of low-carbon hydrogen andhydrogen-based fuels, particularly to other Asia-Pacific economies
that are likely to require imports to meet national hydrogen demand(e.g. Japan and Korea).
The Indian government has taken the first steps to seize the energy
sector decarbonisation opportunities hydrogen can offer. Early in
2021, it launched the National Hydrogen Mission (NHM) to articulate
the government’s vision, intent and direction for hydrogen and tooutline a strategy. The NHM will also explore policy action to support
the use of hydrogen as an energy vector and develop India into a
global hub for hydrogen and fuel cell technology manufacturing.
The first policy actions are under way, with the government having
announced the adoption of auctions (in 2021) for producing hydrogenfrom renewables and mandatory quotas for using renewablehydrogen in refining and ammonia production. According to the
proposal, starting in 2023/24 refineries will have to meet 10% of theirhydrogen demand with renewable hydrogen, increasing to 25% in thefollowing five years. Fertiliser producers will need to meet 5% of
demand with renewable hydrogen in 2023/24, increasing to 20%.
This proposal is expected to be extended to the steel industry in thenear future.

The Indian government also announced plans for new developments
in gas grid infrastructure, connecting major demand centres withports to help the latter become major import/export hubs. The
industry sector has also become involved, with some major
companies (e.g. Adani, Arcelor Mittal, the Indian Oil Corporation,
NTPC, Reliance Industries and the Solar Energy Corporation ofIndia) announcing ambitious plans to develop projects for low-carbonhydrogen production.

Korea
More than 1.8 Mt H2 were produced and used in Korea in 2020, withpractically all demand coming from refining and petrochemical
processes. Around 60% of the hydrogen used is obtained as byproduct from various sources, with the remaining 40% produced fromnatural gas. Korea is among the most active countries in adoptinghydrogen technologies. In 2019 the government launched its
Hydrogen Economy Roadmap, which outlines a vision for the role ofhydrogen in the energy sector. The roadmap highlights two priorities:
creation of a hydrogen market; and the development of hydrogenutilising industries to create the world’s largest market for fuel cells
for transport and electricity generation.
In transport, Korea became the leader in FCEV deployment in 2020,
with over 10 000 FCEVs on the road. In its 2020 New Deal, thegovernment increased the 2025 FCEV target from 100 000 (set in the2019 hydrogen roadmap) to 200 000, and for 2040 it is targeting

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close to 3 million FCEVs, including 2.9 million domesticallymanufactured fuel cell cars, 30 000 fuel cell trucks and 40 000 fuelcell buses.
Furthermore, interest in using hydrogen in transport extends beyond
decarbonising domestic transport. As fuel cell development is also
considered an important technology export opportunity, the roadmap
established targets for exporting 3.3 million FCEVs by 2040.
Hyundai’s announced fuel cell manufacturing capacity of 500 000
units/yr in 2030 largely aligns with the production target of 6.2 million
fuel cell cars by 2040.

FCEV stock (million)

FCEV deployment in Korea in the Announced Pledges Scenario,
2020-2040
4.0
Projections
3.0

1.0

0.0

Current stock
0.010
2020

Pledges
APS
2025

Pledges
APS
2040
IEA. All rights reserved.

Notes: FCEV = fuel cell electric vehicle. APS = Announced Pledges Scenario. Source:
AFC TCP; Korea 2020 New Deal; Hydrogen Economy Roadmap.

By 2040 in the Announced Pledges Scenario, Korea consumes
1.9 Mt H2 to generate 33 TWh of power. This will require an installedcapacity of 18 GW – far more than the Korean government’s targetof 8 GW. This 18 GW also includes other hydrogen technologies forelectricity generation, such as co-firing hydrogen with natural gas ingas turbines. The Korean government also considers stationary fuelcells a technology export opportunity, so the Hydrogen Economy
Roadmap targets 7 GW of stationary fuel cell exports by 2040.
Korea is also giving considerable attention to producing low-carbonhydrogen and developing hydrogen infrastructure. So far, hydrogen
demand for fuel cell applications has been met with by-producthydrogen or unabated natural gas-based production. In the transition
to 2040, the Hydrogen Economy Roadmap prescribes greaterhydrogen production from water electrolysis and from natural gas
with CCUS, and more hydrogen imports.

Official government
targets

2.0

Regarding stationary fuel cells, Korea currently has 620 MW of
installed capacity – almost double what it had at the end of 2018,according to its Hydrogen Economy Roadmap. Most of this capacity
is used for electricity generation (605 MW), but a small fraction(15 MW) is used in buildings. Practically all this capacity is fuelled bynatural gas, but stakeholders are taking steps to operate fuel cellswith 100% hydrogen.

The first projects to develop low-carbon hydrogen production are
already under way: in 2021, SK E&S and Hyundai Oilbank

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announced plans to develop two projects for hydrogen production
from natural gas with CCUS, for a combined production capacity of
350 kt H2/yr. Plus, the Korea National Oil Corporation and Korea
East-West Power have announced the potential incorporation of a
100-MW electrolysis plant into the Donghae 1 offshore wind project,
expected to be completed by 2025. On the infrastructure side, Lindeand Hyosung partnered in 2021 to build Asia’s largest hydrogenliquefaction plant (30 t H2/day) to supply hydrogen for use intransport.

Latin America
Latin American countries consumed 3.5 Mt H2 in 2020, of which
2.5 Mt H2 was used in industry and the rest in refining. The vast
majority of the production (90%) was based on natural gas, with byproduct hydrogen from refineries making up the rest.
A combination of factors has spurred increased interest in hydrogenin the region. The major economies (Argentina, Brazil, Chile,
Colombia and Mexico) already produce large volumes from unabatedfossil fuels for use in oil refineries and in the chemical and iron andsteel industries, and Trinidad and Tobago is among the world’s
largest producers of ammonia and methanol.
Latin America also has one of the world’s highest shares ofrenewables in electricity generation, with Costa Rica, Paraguay and
Uruguay producing practically all their electricity from renewables.

Plus, the region has significant oil and gas resources, particularly in
Venezuela, Brazil and Mexico.
This combination of factors can create complementarities andsynergies across the region. Establishing effective co-operation
among the countries could therefore help the region meet thechallenges of adopting hydrogen as a clean fuel while generating
economic growth.
Chile has taken the lead in announcing hydrogen developments.
Having enormous renewable energy potential – well exceeding its
energy demand – it can produce renewable hydrogen at costs thatare among the lowest in the world. The government published its
Green Hydrogen Strategy in November 2020 with the ambition of
becoming the top destination in Latin America for renewablehydrogen investment by 2025 and one of the world’s largest
exporters of hydrogen-based fuels by 2030. The strategy also targets
25 GW of electrolysis operational or under development by 2030.
Chile’s private sector has responded to the government’s call for
action by launching some major initiatives. For instance, the Haru Oni
project, led by HIF, aims to demonstrate synthetic methanol
production using hydrogen produced by wind-powered electrolysis in
Magallanes. The first phase is expected to be operational by 2022,
and if successfully demonstrated, the project will be expanded insubsequent phases to produce 550 million litres of synthetic fuels

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annually by 2026 (with 2 GW of installed electrolysis capacity). The
objective is to export these hydrogen-based fuels.

the governments of Panama, Paraguay, Trinidad and Tobago, andUruguay are also developing hydrogen strategies and roadmaps.

Meanwhile, in 2020 ENAEX and Engie announced the HyEx project
to deploy up to 780 MW of electrolysis by 2030 to produce ammonia
in Antofagasta, starting with a pilot of 50 MW of electrolyser capacity
to be implemented by 2024. ENAEX, a company that produces
explosives for the mining sector, imports 350 kt of fossil fuel-basedammonia annually, subject to high price volatility. The company
therefore aims to secure and internalise its ammonia feedstock
supply while also reducing its CO2 emissions.

In turn, the private sector is taking action to leverage hydrogen
opportunities. For example, in early 2021 Energix announced theBase One project to deploy around 3.4 GW of electrolysis capacity
powered by renewable energy (at Ceará, north-eastern Brazil). All
hydrogen produced will be exported from the Port of Pecem (afounding member of the Global Ports Hydrogen Coalition).

Chile’s national hydrogen strategy also highlights the usefulness ofelectrolysis in decarbonising existing uses (in the chemical industry
and refining), and especially heavy road transport. In a noteworthy
activity in the mining sector, a major contributor to the economy,
stakeholders are developing as many as 13 different initiatives forusing hydrogen in mining, particularly for trucks used at mines.
The release of the Chile’s strategy stimulated hydrogen-related policy
discussions across the region. In Argentina, an inter-ministerial group
was created to develop a hydrogen roadmap and update existinglaws to promote hydrogen, and in February 2021, Brazil’s Energy
Research Office (EPE) released its first technical document laying
the foundation for a national hydrogen strategy. Colombia announced
the launch of its national strategy at the end of September 2021 andIn 2017, Costa Rica was the first country in the region to deploy a fuelcell bus and four FCEVs. The government, in collaboration with theprivate sector, presented an institutional plan to facilitate the use ofhydrogen in transport in 2018 and is currently developing a national
strategy. Meanwhile, Panama’s strategic location at the crossroadsof major shipping routes makes it a global hub for maritime transport
and a centre for regional trade. While current hydrogen production
and use are very limited, in 2021 the government presented its vision
for Panama to become a logistics and distribution centre for lowcarbon hydrogen-based fuels, initially focusing on the maritime
shipping industry.
More details about hydrogen’s status and opportunities in Latin
America can be found in the IEA’s August 2021 report Hydrogen in
Latin America.

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Middle East
Countries in the Middle East consumed around 11 Mt H2 in 2020,
using close to 4 Mt H2 in refining, more than 5 Mt H2 in the chemicalindustry and 1.5 Mt H2 in steel production. Natural gas accounts for
close to 90% of production, with by-product hydrogen from refineries
making up the remainder.
The Middle Eastern region has a formidable combination of oil andgas reserves and tremendous renewable energy potential(particularly solar) that can enable low-carbon hydrogen production
at significantly lower cost than in most parts of the world. Plus, Middle
Eastern countries have considerable experience in exporting LNG.
Owing to all these factors, the countries aim to become majorinternational suppliers of low-carbon hydrogen. Oman, Saudi Arabia
and the United Arab Emirates have been the most active to date,having several projects under development and participating invarious international co-operations.
In Saudi Arabia, Air Products, Acwa Power and Neom signed anagreement in 2020 to develop a USD 5-billion project to produce
650 t H2/day using electrolysis powered by 4 GW of solar PV andwind. Part of the hydrogen produced will be transformed into
ammonia for export to Air Products clients globally. The project has
already reached FID and the design and early work are now underway, with the expectation that it will be operational in 2025.
Thyssenkrupp and Haldor Topsoe are involved as technology
providers.

Saudi Arabia has been quite active in the international sphere,
seeking to develop potential supply chains through which it could
become a major exporter, particularly to Europe and Japan. In
September 2020, Saudi Aramco, the Institute of Energy Economics,
Japan and SABIC successfully carried out the world’s first shipmentof ammonia produced from fossil fuels with CCUS, shipping 40 t ofammonia from Saudi Arabia to Japan for use in electricity generation
while captured CO2 was used in EOR and chemical production in
Saudi Arabia. In March 2021, the Saudi government signed acollaboration agreement with Germany to lay the groundwork fordeveloping an international hydrogen (or ammonia) supply chain.
In 2020, DEME announced the first initiative to develop a large-scale
electrolysis plant (250-500 MW) in Oman. The number and size of
projects announced has since grown significantly. For instance, a
USD 2.5-billion collaboration between ACME Solar and the Oman
Company for the Development of Special Economic Zone willproduce 2 400 t/day of green ammonia. Furthermore, in May 2021 aninternational consortium of companies announced plans to develop
the Green Fuels Mega Project, a 14-GW electrolysis project poweredby 25 GW of wind and solar PV, with construction planned to start in
2028 and full operations expected by 2038. As most of these projects
aim to produce low-carbon hydrogen or ammonia for export, the Portof Duqm (a founding member of the Global Ports Hydrogen Coalition)
is a cornerstone of the initiatives being developed in Oman.

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In the United Arab Emirates, Emirates Steel has been operating the
Al Reyadah CCUS Project since 2016, capturing 800 kt CO2/yr from
DRI-based steel production. In 2021, DEWA and Siemens
inaugurated Expo 2020 Dubai (delayed because of the Covid-19
pandemic), the region’s first renewable energy-powered electrolysis
project.
In addition, by signing an agreement with Japan to collaborate onhydrogen production technologies and create an international supply
chain, the Emirates have taken the first steps to becoming hydrogen
exporters. ADNOC announced a joint study agreement with two
Japanese companies (INPEX, JERA) and a government agency(JOGMEC) to investigate the potential of producing ammonia fromfossil fuels with CCUS to supply Japanese utilities. ADNOC is alreadydeveloping a large-scale low-carbon ammonia production facility(capacity of 1 Mt NH3/yr) at the TA’ZIZ Industrial Chemicals Zone andexploring opportunities to commercialise this product.
Kuwait and Qatar have also taken the first steps in developing theirhydrogen strategies, in preparation to capture opportunities to exploit
their natural resources to produce hydrogen.

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Policy recommendations

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Attaining climate goals will require ambitious, decisive action in the next decade
The IEA’s Net zero by 2050 roadmap shows that achieving net zerotargets will require immediate action to make the 2020s the decadeof clean energy expansion through massive deployment of available
low-carbon technologies and accelerated innovation of those still
under development. Hydrogen technologies are a key example, witha considerably higher pace of progress and deployment required
from now until 2030. The three overarching goals are to significantly
expand hydrogen use while bringing new technologies onto themarket; make hydrogen production much cleaner (i.e. shift away fromunabated fossil fuel-based routes); and reduce the costs oftechnologies for hydrogen production and use.
To inform decision-making, this report presents a series of milestones
that need to be reached by 2030 to unlock hydrogen’s potential toaddress climate change. These markers cover the entire hydrogenvalue chain, including its production, infrastructure requirements,
transformation into other fuels and end uses. Ultimately, themilestones are a call for action to governments. The implementationof policies to support their achievement can help build confidence
among investors, industry, citizens and other countries, in turnprompting collaboration to trigger uptake of hydrogen as a newenergy vector.

PAGE | 204

Key milestones to stay on track with the Net zero Emissions
scenarios by 2030
2020

NZE
2030

Development status

90

212

-

0.3

850

Mature10410

Mature

0.035

15.3

Market scale-up

0.54

18

Market scale-up

047

Demonstration

043

Demonstration

0.1

5.7

Demonstration

Synfuel demand in aviation(mb/y)

038

Prototype

Export terminals(number of terminals)

060

Prototype

Total H2 demand(Mt H2)
Electrolysis capacity(GW)
CO2 captured and stored in H2
production(Mt CO2)
Total road FCEVs(million vehicles)
HRSs(1 000s of stations)
NH3 demand in shipping(Mt NH3)H2 demand in electricity
generation(Mt H2)
Low carbon H2 demand in DRI(Mt H2)

Policy recommendations

Global Hydrogen Review 2021

Near-term policy recommendations to enable the required transformation
To achieve the Net zero Emissions milestones, governments musttake a lead role in facilitating the clean energy transition by
establishing policy frameworks that stimulate integrated action. In
The Future of Hydrogen, the IEA identified a series ofrecommendations for near-term policy action. Here, this Global
Hydrogen Review expands on these policies and explains how they
can facilitate attainment of the milestones.
Policies should centre on the need to:Develop strategies and roadmaps on hydrogen’s role in energy
systems.



Create strong incentives for using low-carbon hydrogen to displacefossil fuels.

Mobilise investment in production assets, infrastructure and factories.



Provide strong innovation support to ensure critical technologies reachcommercialisation quickly.

Establish appropriate certification, standardisation and regulation
regimes.

As all these policies are interconnected, implementation of one will
impact the potential outcomes of the others. Some are natural firststeps, such as defining the role of hydrogen in national energy
strategies. However, it is unlikely this role can be realised without
sufficient stimulus measures to create demand and mobilise
investments for the infrastructure needed to connect hydrogenproducers and users in the initial adoption stages. Developing suchinfrastructure requires planning among diverse stakeholders, with local
authorities playing a key role as co-ordinators. Co-ordination of efforts
can be facilitated if the roles of the different stakeholders are clearlyand properly defined in hydrogen strategies and roadmaps.
In turn, the extent to which demand can be created will depend on
increased effort in two main areas: support for innovation to ensuretechnologies are developed and become competitive; andestablishment of standards and certification schemes to ensure theinteroperability of these technologies globally and provide certainty to
end users about the products they are acquiring on the market. Market
development will also depend on adequate regulation to guarantee faircompetition.
Ultimately, these features all work together like gears in one system:
they all need to be in place and function in a co-ordinated fashion toensure the effective adoption of hydrogen technologies at the required
levels, within the next decade. The success of these policies will also
depend on other measures, such as the development of training
programmes to create a skilled workforce, ready to deploy and operate
novel hydrogen technologies.
In the long term, consumer demand will drive investment in low-carbonhydrogen value chains. In the short term, however, it is up to
policymakers to pull various levers to attract capital to the right places
to create such demand.

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How policy and regulatory interventions can amplify and steer incentives across hydrogen value chains

IEA. All rights reserved.

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Develop strategies and roadmaps on hydrogen’s role inenergy systems
National hydrogen strategies and roadmaps with concrete milestones
for implementation and specific targets for producing and usinghydrogen are essential to signal government commitment toexpanding hydrogen supply and use. Ideally, they should be part ofwider government strategies to achieve climate targets, thereby
anchoring hydrogen as part of the expected energy future.
Developing strategies and roadmaps is thus critical to build
stakeholder confidence in the potential marketplace of low-carbonhydrogen and related technologies.
More and more countries have taken the vital first step of establishingnational strategies in the last couple of years, creating momentum forthe hydrogen industry and triggering new investments. Nevertheless,
IEA analysis of stated targets detects a widening supply-demand gap
due to strong policy focus on expanding low-carbon hydrogen
supplies and relatively little action designed to increase market
demand.
Clearly, emphasising the “push” for low-carbon hydrogen byincreasing production capacity without creating sufficient market“pull” for the end product can create imbalances – and evenbottlenecks – in the hydrogen value chain. Lack of demand can
impede the emergence of supply projects, making it more difficult toachieve government targets for low-carbon hydrogen production.

Scenario analysis in this report suggests a growing need for more
ambition to boost demand for low-carbon hydrogen, to both replacecurrent demand for fossil fuel-based hydrogen (in refining andindustry) and create demand for new applications such as heavy-dutytransport, energy storage, new industrial applications, shipping andaviation.
Specific targets must therefore be adopted for using low-carbonhydrogen in existing applications and for deploying new hydrogen
applications within this decade. Endorsing these aims at the national
level can facilitate co-ordinated global action to achieve themilestones for 2030 proposed in this report.
Including hydrogen demand and production as well as hydrogentechnology deployment in national energy statistics and reporting is
also advisable. Tracking demand by sector, production throughdifferent routes, and other parameters related to hydrogentechnology deployment (e.g. the number of HRSs, installed
electrolysis capacity and the number of FCEVs on the roads by
vehicle type) is critical to assess progress in meeting strategy androadmap targets.
The IEA is ready to apply its analytical capabilities to help
governments around the world define the role hydrogen can play inmeet their climate goals and advance their strategies androadmapping efforts.

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Create strong incentives for using low-carbon hydrogento displace fossil fuels

Mandates/quotas. Gradually rising mandatory quotas for low-carbon
technologies, both for existing hydrogen uses (e.g. refineries andfertiliser production) and new-use sectors, can be a powerful
instrument to stimulate the adoption of low-carbon hydrogen-based
fuels in some jurisdictions (e.g. California’s Zero-Emission Vehicle[ZEV] mandate). Such demand-pull policies can strengthen thebusiness cases of hydrogen projects without expending significant
public funds. For example, demand for low-carbon hydrogen can be
stimulated through mandates for ZEVs; blending quotas for low-carbon
gases in natural gas grids or low-carbon fuels in power generation; andmandates for synfuel use in aviation. Mandates can also be reinforced
by relevant disincentives, such as a ban on the sale of internal
combustion engine vehicles; sunset clauses for conventional industrial
equipment; and regulations for deploying combustion equipment (e.g.
domestic appliances and industrial boilers and turbines) compatible
with low-carbon fuels.

Public procurement. All levels of government and public agencies canhelp create demand for low-carbon hydrogen by modifying public
procurement contracts to require its use for public transport, taxi
services, waste collection, trucks, ferries and barges, and by stipulating
the use of low-carbon steel and cement in infrastructure projects. For
example, the Norwegian government recently decided that the largest
ferry connection in the country (Bodø-Værøy-Røst-Moskenes) should
be fuelled by hydrogen. In some countries, governments have direct
influence on the strategies and investment allocations of state-owned
companies.

Demand creation is a key lever to stimulate adoption of hydrogen asa clean energy vector. However, using low-carbon hydrogen is morecostly than employing incumbent technologies, whether one
compares with fossil-based hydrogen in traditional uses or the
combustion of fossil fuels in potential new hydrogen applications.
Although an increasing number of countries now impose carbon
pricing or taxation, current carbon prices are not high enough to closethe cost gap between low-carbon hydrogen and fossil-basedalternatives. Carbon prices are expected to rise in some countries
and jurisdictions (e.g. Canada, Norway and the European Union), but
this can take many years and, while helpful, may not drive
transformation at the speed required.
To help industry de-risk investments and improve the bankability of
projects, governments should design policy frameworks and financial
support schemes that are transparent and predictable. Three key
policy instruments already show strong potential for this purpose:

Carbon contracts for difference. Already proposed by the European
Union and Germany, this is a new policy instrument to bridge the gap
between current carbon prices and the price needed to trigger fuelswitching in target industries (e.g. refining, iron and steel, andchemicals). Using auctions to support the most competitive projects
can be an effective way to hasten low-carbon hydrogen adoption(particularly for traditional refining and industrial applications).

International engagement will help extend the impact of such policies.
Some governments will be first movers, reaping the positive
outcomes these policies can deliver while also learning lessons about

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their inherent challenges. Recognising that the scale of the challenge
requires co-ordinated global action and the positive effects ofreplicating success are multiple. The CEM Hydrogen Initiative hascreated an unparalleled platform for sharing knowledge and bestpractices with this purpose.

Mobilise investment in production assets, infrastructureand factories
A policy framework that effectively stimulates demand can in turntrigger investment in low-carbon production plants, infrastructure
deployment and manufacturing capacity. Meeting ambitious climate
goals will require additional policy action to accelerate the use ofelectrolysers and carbon capture in hydrogen production, develophydrogen-specific infrastructure and ramp up manufacturing capacity
for key hydrogen technologies (e.g. fuel cells and electrolysers).
On the production side, the pipeline of sizeable low-carbon hydrogenprojects is impressive, with private companies and investors
committing considerable investments. These projects areencountering a bottleneck, however, as governments still need todesign and implement support schemes and relevant regulations,risking the loss of valuable time.
Providing tailor-made support for selected, shovel-ready flagshipprojects through grants, loans and tax breaks (ensuring due diligenceto guarantee fair competition), while establishing the support
schemes and regulations that will be needed later, can kick-start low-

carbon hydrogen expansion. Tailored support for flagship projects
can also unlock significant funding to scale up manufacturing
capacity for key hydrogen technologies as well as prompt
infrastructure development, from which later projects in the region
can benefit. This requires flexible regulations that can help de-risk
investment, for example through public-private partnerships
designed to fit specific projects.
It can be expected that the hydrogen market will initially develop as
integrated supply chains from producer to customer, as in the earlydays of LNG. Transitioning quickly to a liquid market that supports
scale-up and widespread hydrogen adoption will require timely
development of hydrogen-specific infrastructure, which implies
adequate planning and mobilisation of sufficient investment.
Governments face the challenge of balancing rapid development – toensure that lack of infrastructure does not impede creation of new
demand – with the risk of deploying infrastructure too quickly andhaving it under-utilised or even stranded if demand does not develop
sufficiently, particularly for new applications. To avoid such a
scenario, infrastructure development should begin withinterconnection of major industrial clusters – a low-regret option,
since the hydrogen demand of such hubs is more certain thanpotential demand from new applications. These hubs are also natural
locations for establishing hydrogen valleys, where new demand canbe developed.

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As these hubs typically have natural gas infrastructure in place,
repurposing gas pipelines to serve as dedicated hydrogen pipelines
is a low-cost option to initiate hydrogen infrastructure development(in fact, timely gas pipeline can accelerate hydrogen systemestablishment). Then, beyond these initial deployments to support
transmission and distribution, governments should begin planning thedevelopment of future hydrogen infrastructure, including storage.

Provide strong innovation support to ensure criticaltechnologies reach commercialisation quickly
While key hydrogen technologies are ready to start scaling up,
continuous innovation is critical to drive down costs and increase
competitiveness. Strong efforts are therefore needed in the near term
to demonstrate several emerging technologies at scale to ensure thatthey reach commercialisation early this decade and unlock the fullpotential of hydrogen demand. Pertinent demonstration projects
include using hydrogen in the DRI process for iron- and steelmaking;producing ammonia and methanol using electrolytic hydrogenproduced from variable renewable energy; using hydrogen in heavyduty transport; and using ammonia in shipping.
Governments should also take policy action now to stimulate fundingfor (and incentivise development of) next-generation technologies,
such as use of hydrogen in shipping; transform hydrogen into
synfuels; and use hydrogen to provide high-temperature heat inindustrial processes (e.g. in cement kilns). Robust R&D andinnovation programmes are necessary to ensure these technologies
mature enough in the upcoming decade to be ready for deployment
at scale in 2030.
In reality, public budgets for R&D and innovation in low-carbonhydrogen technologies do not offer the support needed to ensure thedevelopment pace required to meet long-term climate goals.
Governments therefore need to take decisive action against thesebudget shortfalls.
In its Net zero by 2050 roadmap, the IEA estimates that USD 90
billion of public money needs to be mobilised globally as quickly as
possible, with around half dedicated to hydrogen-related
technologies. This could reduce investment risks for the private
sector and help attract private capital for innovation. Furthermore, it
is important for government departments managing R&D portfolios towork closely with national hydrogen research labs and other research
centres, as well as with industry, to recognise and respond to theneeds of the private sector.
International co-operation will be critical in this area. Implementing
the agreed doubling of public R&D within the Mission Innovation
initiative can be a first step. In parallel, the convening power of the
IEA Hydrogen and Advanced Fuel Cells Technology Collaboration
Programmes should be leveraged to facilitate international R&D andinformation exchange.

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Establish appropriate certification, standardisation andregulation regimes
Since adopting hydrogen as a clean fuel is expected to stimulate thedevelopment of new markets and value chains, regulatory
frameworks, certification schemes and standards will be required toreduce barriers for stakeholders.
In the short term, it is particularly important to develop standards inthree domains:




39

International trade. Standards are required in several areas to develop
a global low-carbon hydrogen market. International agreement on amethodology for calculating the carbon footprint of hydrogen production
is critical, as it is the basis from which a global certificates market could
develop. Importing countries, regions and companies would then beable to decide what carbon footprint threshold they deem acceptable forimported clean hydrogen, although a commonly agreed international
standard is vital to avoid future impediments to cross-border trade inhydrogen.
Safety. Safety is a critical topic for low-carbon hydrogen and hydrogenbased fuels. Industry has been able to produce and use hydrogen safely
over several decades, but as its use is now expected to expand beyond
industry to reach domestic consumers in their vehicles and homes,
ensuring safety across all levels is essential. Gaining public acceptancewill require the establishment of high safety standards throughinternational co-operation and harmonisation.

Technology adoption. New applications for hydrogen use will result in
deployment of new technologies to operate refuelling stations, storagesites and combustion appliances. Internationally harmonised standards
for nozzles, valves, burners and storage tanks are therefore necessary
to ensure consistent operability around the world.

The IPHE has been leading international efforts in these areas formany years. Governments and industry should thus leverage its
progress and collaborate to ensure all required standards aredeveloped quickly enough to prevent the lack of them becoming abarrier to hydrogen adoption. For example, an internationally agreed
standard to measure the carbon footprint of hydrogen production ona lifecycle basis will be needed to account for the emissions of thewhole hydrogen supply chain, including from electricity generation(where applicable) and fossil fuel production. 39
Certification is the natural follow-on step after the development ofstandards. Certification schemes aim to ensure that manufacturers
comply with standards adopted internationally to inspire confidence
among low-carbon hydrogen users. Furthermore, low-carbon
premium markets that rely on product certification can help create
demand, mobilise investments and stimulate innovation.
For instance, a car certified to have been manufactured with lowcarbon steel (i.e. steel produced in a factory where low-carbonhydrogen has replaced fossil fuel inputs) may have a small priceSee the IEA Methane Tracker for estimates on methane emissions from fossil production."
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premium over a standard car, which can make it an attractive option
for a significant number of consumers across diverse income levels.
The same may apply to other consumer products manufactured with
low-carbon commodities, such as fertilisers, cement and solvents. For
a low-carbon premium market to function effectively, however, it mustbe founded on a dedicated and reliable system of certificates andlabels to provide certainty to consumers about the low-carbon
attributes of products they are acquiring.
In addition, a clear, transparent and supportive regulatory framework
is necessary to enable development of a robust hydrogen market. As
demand rises and suppliers respond, and entirely new value chainsand partnerships emerge, regulatory systems will need to be flexible
to adapt to market evolution without jeopardising the solidity ofbusiness cases needed to attract investment in production assets andinfrastructure.
Clear rules for regulated assets and to ensure third-party access will
also be needed to avoid new monopolies and market fragmentation in
low-carbon hydrogen. However, given the embryonic stage ofhydrogen market development, it is premature to apply rigid regulatory
principles that work in other mature markets, since they could create aserious risk of regulatory failure or regulatory disconnect. Rather, agradual and dynamic regulation approach, carefully calibrated toperiodic market monitoring (as suggested by the Council of European
Energy Regulators and the Agency for the Cooperation of Energy
Regulators) can help minimise the risk of failure.

Governments should also consider ways to align other regulatory
aspects and policy domains not directly linked to hydrogen markets butthat can affect the business case to ensure that, at the very least, they
do not render hydrogen projects unappealing. Some examples are:

Grid fees and levies, which are often developed independently forelectricity and gas and can hamper sector coupling.

State aid rules, which are of critical importance to ensure faircompetition. In some jurisdictions, they may need to be adjusted tofacilitate initial deployment of low-carbon hydrogen technologies.



Spatial planning and licensing, which in some countries can be a longand cumbersome process. Current planning and approval processes
do not yet include hydrogen and may need to be revised. Governments
and local authorities can help co-ordinate infrastructure planning
processes among public agencies, industry and citizens.

Possible tariff and non-tariff trade barriers, which can hamper hydrogen
trade. A strong case exists for striving for uninhibited and smooth global
trade in hydrogen, facilitated by early identification of potential barriers
and, where necessary, undertaking international efforts to harmonise
and tackle them.

Energy taxation, which ideally should follow the “polluter pays principle”
and systematically favour zero-/low-carbon solutions over fossil fuelalternatives.



Fossil fuel subsidies, which still exist in several countries and candistort the developing hydrogen market. The IEA has long been
recommending timely phase out of such subsidies.

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Global Hydrogen Review 2021

Finally, financial market regulations for sustainable financing andinitiatives for environmental, social and corporate governance –both national and international – are increasingly helpful to nudge
investors towards clean energy, including low-carbon hydrogen.
Governments should actively encourage these trends (e.g. bymandating that multilateral banks help fund hydrogen scale-up) toleverage their own public investments.

PAGE | 213

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Abbreviations and acronyms
AEM

anion exchange membrane

DAC

direct air captureAFCalkaline fuel cells

DRI

direct reduced iron

AFC TCP

Advanced Fuel
Programme

DRI-EAF

direct reduced iron - electric arc furnace

EHB

European hydrogen backbone

EIB

European Investment Bank

EOR

enhanced oil recovery

EPC

engineering, procurement and construction

ESMR

electrified steam methane reforming

EU

European Union

EU ETS

EU Emissions Trading Scheme

EUR

Euro

EV

electric vehicleFC

fuel cell

FCEV

fuel cell electric vehicle

FCH JU

Fuel Cells and Hydrogen Joint Undertaking

FID

final investment decision

FT

Fischer-Tropsch

GBP

British pound sterling

GH2

gaseous hydrogen

GHG

greenhouse gases

GHR

gas-heated reformer

Cell

Technology

Collaboration

ALK

alkaline

APS

Announced Pledges Scenario

ATR

autothermal reforming

AUD

Australian dollar

BEVbattery electric vehicle

BF

blast furnace

CAD

Canadian dollar

CAPEX

capital expenditure

CCfD

carbon contracts for difference

CCGT

combined-cycle gas turbine

CCS

carbon capture and storage

CCU

carbon capture and use

CCUS

carbon capture, utilisation and storage

CEM H2I

Clean Energy Ministerial Hydrogen Initiative

CNY

Chinese yuan

CO2carbon dioxide

CSIRO

Commonwealth Scientific and Industrial Research
Organisation

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Global Hydrogen Review 2021

H2

hydrogen

LNG

liquefied natural gas

HDV

heavy-duty vehicle

LOHC

liquid organic hydrogen carrier

HEM

Hydrogen Energy Ministerial

LPG

liquefied petroleum gas

HEVhybrid electric vehicle

LNG

liquefied natural gas

HRS

hydrogen refuelling station

M&A

mergers and acquisitions

HThigh throughput

MCFC

molten carbonate fuel cell

IAE

Institute of Applied Energy

MeOH

methanolICE

internal combustion engine

MI

Mission Innovation

IEA

International Energy Agency

MOC

memorandum of collaboration

IEA GHGIEA Greenhouse Gas R&D ProgrammeMOUmemorandum of understanding

IFA

International Fertilizer Industry Association

MTO

methanol to olefin

IMO

International Maritime Organization

NH3

ammonia

IPCEI

Important Projects of Common European Interest

NOK

Norwegian krone

IPHE

International Partnership for Hydrogen and Fuel Cells in
the Economy

NOxnitrogen oxides

NREL

National Renewable Energy Laboratory

NZE

Net zero Emission ScenarioOEM

original equipment manufacturer

OPEX

operating expenditure

PAFC

phosphoric acid fuel cellPEprivate equity

PEM

proton exchange membrane

PEMFC

proton exchange membrane fuel cell

PIPE

private investment in public equity

PLDV

passenger light-duty vehicle

IRENA

International Renewable Energy Agency

IPCEI

Important Projects of Common European Interest

JHyM

Japan Hydrogen Mobility

JPY

Japanese yen

KRW

Korean won

LCVlight commercial vehicle

LDV

light-duty vehicle

LH2

liquid hydrogen

LHV

lower heating value

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Global Hydrogen Review 2021

POx

partial oxidation

PtG

power-to-gas

PtL

power-to-liquidsPVphotovoltaic

R&D

research and development

RD&D

research, development and demonstration

SCR

selective catalytic reduction

SMR

steam methane reforming

SOEC

solid oxide electrolysis cell

SOFCsolid oxide fuel cell

SUV

sport utility vehicle

TCO

total cost of ownership

TCP

Technology Collaboration Programme

TRL

technology readiness level

TSO

transmission system operator

UK

United Kingdom

UN

United Nations

US

United States

USD

United States dollar

VC

venture capital

VRE

variable renewable energy

WEF

World Economic ForumZEVzero emissions vehicle

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Units of measure°C

degree Celsius

bbl

barrelbcm

billion cubic metres

EJ

exajouleGt

gigatonnes

Gt CO2gigatonnes of carbon dioxide

GW

gigawatt

GWh

gigawatt-hourkgkilogrammekg H2kilogramme of hydrogen

kg CO2eq

kilogrammes of carbon-dioxide equivalentktkilotonnes

kt H2

kilotonnes of hydrogenkWkilowattkWhkilowatt-hourmcm

million cubic metres

MBtu

million British thermal units

MJ

megajoule
PAGE | 218

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Global Hydrogen Review 2021

Acknowledgements
The Global Hydrogen Review was prepared by the Energy
Technology Policy (ETP) Division of the Directorate of
Sustainability, Technology and Outlooks (STO) of theInternational Energy Agency (IEA). The study was designed anddirected by Timur Gül, Head of the Energy Technology Policy
Division. Uwe Remme (Head of the Hydrogen and Alternative
Fuels Unit) and Jose Miguel Bermudez Menendez co-ordinatedthe analysis and production of the report.
The principal IEA authors and contributors were (in alphabeticalorder): Thibaut Abergel (buildings), Julien Armijo (supply),
Praveen Bains (supply), Simon Bennett (investments andinnovation), Niels Berghout (CCUS), Ekta Meena Bibra(transport), Sara Budinis (CCUS), Elizabeth Connelly(transport), Chiara Delmastro (buildings), Araceli Fernandez
Pales (end-use sectors and innovation), Alexandre Gouy
(industry), Ilkka Hannula (power), Taku Hasegawa (supply andtrade), Jean-Baptiste Le Marois (investments and innovation),
Olivier Lelouch (refining), Peter Levi (industry), Raimund
Malischek (CCUS), Hana Mandova (industry), Gergely Molnár(infrastructure),
Leonardo
Paoli(innovation),
FaidonPapadimoulis (data management and modelling), Francesco
Pavan (supply), Kristine Petrosyan (refining), Maxwell Pisciotta

PAGE | 219(CCUS), Amalia Pizarro Alonso (infrastructure), Jacopo Tattini(transport), Jacob Teter (transport), Tiffany Vass (industry) and
Per-Anders Widell (CEM H2I).
Noé van Hulst, chair of the International Partnership for
Hydrogen and Fuel Cells in the Economy (IPHE) and Hydrogen
Advisor at the IEA, provided valuable, strategic guidance during
the report’s development process.
The development of this report benefitted from contributions
provided by the following IEA colleagues: Adam Baylin-Stern,
Mariano Berkenwald, Paolo Frankl, Javier Jorquera Copier,Tae-Yoon Kim, Samantha McCulloch and Rachael Moore. Reka
Koczka, Diana Louis and Per-Anders Widell provided essential
support.
Thanks also to the IEA’s Communications and Digital Office for
their help in producing the report, particularly to Astrid Dumond,
Jethro Mullen, Isabelle Nonain-Semelin, Gregory Viscusi and
Therese Walsh. Marilyn Smith and Kristine Douaud edited themanuscript.
The work could not have been achieved without the financial
support provided by the Governments of Germany (Federal
Ministry for Economic Affairs and Energy), Japan (Ministry ofForeign Affairs as well as Ministry of Economy, Trade andAnnexes

Global Hydrogen Review 2021

Industry) and the United States (Department of Energy). The
following governments have also contributed to the reportthrough their voluntary contribution to the CEM Hydrogen
Initiative: Australia, Austria, Canada, the European
Commission, the Netherlands, and Norway.
Special thanks go to the following organisations for theirvaluable contributions: Advanced Fuel Cells TCP, Hydrogen
Council, Hydrogen TCP, International Partnership for Hydrogenand Fuel Cells in the Economy (IPHE).
Peer reviewers provided essential feedback to improve thequality of the report. They include: Evrim Akar (Ministry of
Infrastructure and Water Management, the Netherlands),
Adbdullah Alabri (EJAAD), Laurent Antoni (CEA), Alessandro
Arrigoni (European Commission, Joint Research Centre),
Florian Ausfelder (DECHEMA), RB Balaji (World Bank), Claudia
Bassano (ENEA), Amar A. Bhardwaj (Columbia University), Bart
Biebuyck (Fuel Cells and Hydrogen Joint Undertaking), Herib
Blanco (IRENA), Joß Bracker (Federal Ministry for Economic
Affairs and Energy, Germany), Paula Brunetto (Enel), Tyler
Bryant (Fortis BC), Cosmas Chiteme (National Department of
Science and Innovation, South Africa), Bjørn Christian Enger(Sintef), Tudor Constantinescu (European Commission),
Cameron Davies (Department for Business, Energy andIndustrial Strategy, United Kingdom), Jonathan Davies(European Commission, Joint Research Centre), Carl de Maré

PAGE | 220(ArcelorMittal), Fernando Sisternes (World Bank), Guillaume De
Smedt (Air Liquide), Denis Deryushkin (Russian Energy
Agency), Martine Espeland Sørlie (Ministry of Petroleum andEnergy, Norway), Beatriz Fidalgo (BP), Alan Finkel (Special
Adviser to the Australian Government), Gniewomir Flis (Agora
Energiewende), Alexandru Floristean (Hydrogen Europe), Sam
French (Johnson Matthey), Marius Fuglerud (Ministry ofPetroleum and Energy, Norway), Ryosuke Fujioka (METI),
Hiroyuki Fukui (Toyota), Marta Gandiglio (Politecnico di Torino),
Diego García (Tecnalia), Bastian Gillesen (Jülich ResearchCentre), Stefan Gossens (Schaeffler), Konstantin Grebennik(Russian Energy Agency), Thomas Grube (Jülich ResearchCentre), Augustijn Haasteren (European Commission), David
Hart (E4tech), Masao Hayakawa (METI), Heidi Heinrichs (Jülich
Research Centre), Thorsten Herbert (Nel Hydrogen), Yukari
Hino (METI), Yuta Hirakawa (METI), Marina Holgado (Hydrogen
Technology Collaboration Programme), Aaron Hoskin (Natural
Resources Canada), Uyigue Idahosa (World Bank), Andreas
Indinger (Austrian Energy Agency), Shunsuke Kageyama(METI), François Kalaydijan (IFPEN), Tim Karlsson (IPHE),
Miklos Kaspar (European Commission), Ruud Kempener(European Commission), Mikio Kizaki (Toyota), Ralph
Kleinschmidt (Thyssenkrupp), Agnes Koh (Energy Market
Authority, Singapore), Volker Kraayvanger (Uniper), Gijs Kreeft(Ministry of Infrastructure and Water Management, theNetherlands), Martin Lambert (Oxford Institute for Energy

Annexes

Global Hydrogen Review 2021

Studies), Angel Landa Ugarte (Iberdrola), Pharoah Le Feuvre(Enagás), Eric Lecomte (European Commission), Jabbe
Leeuwen (Ekinetix), Franz Lehner (NOW GmbH), Andy Lewis(Cadent), Jochen Linßen (Jülich Research Centre), Eirik Velle
Wegner Lonning (European Commission), Asuka Maeda(METI), Benjamin Maluenda Philippi (Ministry of Energy, Chile),
Paulo Martins (Directorate-General of Energy and Geology,
Portugal), Akiteru Maruta (Technova), Rebecca Maserumule(National Department of Science and Innovation, South Africa),
David Mason (Department for Business, Energy and Industrial
Strategy, United Kingdom), Cyriac Massué (Federal Ministry for
Economic Affairs and Energy, Germany), Mikako Miki (METI),
Jongsoo Mok (Hyundai), Steffen Moller-Holst (Sintef), Pietro
Moretto (European Commission, Joint Research Centre), Matus
Muron (Hydrogen Europe), Atsuhito Nara (METI), Petter Nekså
(Sintef), Motohiko Nishimura (Kawasaki Heavy Industry),
Christoph Noeres (Thyssenkrupp), Koichi Numata (Toyota),
Misa Okano (METI), Paulo Partidário (Directorate-General ofEnergy and Geology, Portugal), Grzegorz Pawelec (Hydrogen
Europe), Cédric Philibert (IFRI (retired)), Rodrigo Pinto
Scholtbach (Ministry of Economic Affairs and Climate Policy, theNetherlands), Joris Proost (UCLouvain), Ireneusz Pyc(Siemens), Gunhild Reigstad (Sintef), Carla Robledo (Ministry of

PAGE | 221

Economic Affairs and Climate Policy, the Netherlands), Roland
Roesch (IRENA), Justin Rosing (European Commission), MarkRuth (NREL), Kostis Sakellaris (Fuel Cells and Hydrogen Joint
Undertaking),
Juan
Sánchez-Peñuela
(Permanent
Representation of Spain to the European Commission), Sunita
Satyapal (US Department of Energy), Laura Savoldi (Politecnico
di Torino), Dirk Schaap (Ministry of Infrastructure and Water
Management, the Netherlands), Manfred Schuckert (Daimler),
Yoshiaki Shibata (The Institute of Energy Economics, Japan),
Ryota Shiromizu (METI), Matthijs Soede (European
Commission), Markus Steinhäusler (Voestalpine), Zsuzsanna
Szeles (European Commission), Emanuele Taibi (IRENA), Kai
Tateda (METI), Michael Turley (Shell), Naoya Uehara (METI),
Ari Ugayama (METI), Nico van den Berg (Ministry of
Infrastructure and Water Management, the Netherlands), Wilcovan der Lans (Port of Rotterdam Authority), Augustijn van
Haasteren (European Commission), Ad van Wijk (Delft
University of Technology), Julius von der Ohe (NOW GmbH),
Kota Watanabe (METI), Masashi Watanabe (METI), Eveline
Weidner (European Commission, Joint Research Centre),
Derek Wissmiller (Gas Technology Institute), Hergen Thore Wolf
(Sunfire), Makoto Yasui (Chiyoda Corporation), Rudolf Zauner(Verbund), Robert Zeller (Occidental Petroleum).

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