Towards hydrogen
definitions basedon their emissions
intensity

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Towards hydrogen definitions based on their emissions intensity

Abstract

Abstract
Towards hydrogen definitions based on their emissions intensity is a new reportby the International Energy Agency, designed to inform policy makers, hydrogenproducers, investors and the research community in advance of the G7 Climate,
Energy and Environmental Ministerial meeting in April 2023. The report builds on
the analysis from the IEA’s Net Zero by 2050: A Roadmap for the Global Energy
Sector and continues the series of reports that the IEA has prepared for the G7
on the sectoral details of the roadmap, including the Achieving Net Zero Electricity
Sectors in G7 Members, Achieving Net Zero Heavy Industry Sectors in G7
Members and Emissions Measurement and Data Collection for a Net Zero Steel
Industry reports.

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This report assesses the greenhouse gas emissions intensity of the differenthydrogen production routes and reviews ways to use the emissions intensity ofhydrogen production in the development of regulation and certification schemes.
An internationally agreed emissions accounting framework is a way to move awayfrom the use of terminologies based on colours or other terms that have proved
impractical for the contracts that underpin investment. The adoption of such aframework can bring much-needed transparency, as well as facilitatinginteroperability and limiting market fragmentation, thus becoming a useful enablerof investments for the development of international hydrogen supply chains.

Towards hydrogen definitions based on their emissions intensity

Acknowledgements

Acknowledgements
Towards hydrogen definitions based on their emissions intensity was prepared by
the Energy Technology Policy (ETP) Division of the Directorate of Sustainability,
Technology and Outlooks (STO) of the International Energy Agency (IEA). The
project was designed and directed 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-ordinated the analysis
and production of the report.
The principal IEA authors and contributors were Simon Bennett, Stavroula
Evangelopoulou, Mathilde Fajardy, Carl Greenfield, Francesco Pavan and Amalia
Pizarro Alonso. Several colleagues across the agency contributed analytical input,
including Tomás de Oliveira Bredariol and Jérôme Hilaire. Laurent Antoni, fromthe International Partnership for Hydrogen and Fuel Cells in the Economy (IPHE)
was also a contributor and author of the report.
The following IEA colleagues contributed with valuable comments:
Keisuke Sadamori, Laura Cozzi, Dan Donner, Paolo Frankl, Tim Gould,
Ilkka Hannula, Christophe McGlade, Peter Levi and Tiffany Vass.
Lizzie Sayer edited the manuscript. Essential support throughout the process wasprovided by Caroline Abettan, Reka Koczka and Per-Anders Widell. Thanks
also to Poeli Bojorquez, Curtis Brainard, Astrid Dumond, Isabelle Nonain-Semelinof the Communications and Digital Office.
The work could not have been achieved without the financial support provided by
the Ministry of Economy, Trade and Industry, Japan.

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The report benefited from the insights gathered during a high-level expert
workshop on “Achieving scale-up of low-emission hydrogen and ammonia for net
zero in G7 countries” (held on 21 February 2023) and a series of consultations
with Jochen Bard and Dayana Granford Ruiz (Fraunhofer - Institut fürEnergiewirtschaft und Energiesystemtechnik, Germany); Herib Blanco; Timo
Bollerhey and Martin Erdmann (Hintco); Matthias Deutsch and Mauricio Belaunde(Agora Energiewende); Johanna Friese (Gesellschaft für Internationale
Zusammenarbeit, Germany); Céline Le Goazigo (World Business Council For
Sustainable Development); Noé van Hulst and Tim Karlsson (IPHE); Heino vonMeyer (International PtX Hub); Daria Nochevnik (Hydrogen Council); Andrei V.
Tchouvelev (Hydrogen Council, International Organization for Standardization);and Kirsten Westphal (German Association of Energy and Water Industries).

Towards hydrogen definitions based on their emissions intensity

Acknowledgements

Peer reviewers provided essential feedback to improve the quality of the report.
They include: Olumoye Ajao and Curtis Jenken (National Resources Canada);
Saood Mohamed Alnoori (Office of the Special Envoy for Climate Change,
United Arab Emirates); Chelsea Baldino (International Council on Clean
Transportation);
Ruta
Baltause(Directorate
GeneralforEnergy,European Commission); Jochen Bard (Fraunhofer - Institut für Energiewirtschaft
und Energiesystemtechnik, Germany); Herib Blanco; Trevor Brown (Ammonia
Energy Association); Anne-Sophie Corbeau (Center on Global Energy Policy,
Columbia University, United States); Harriet Culver, Katherine Davis and Liz
Wharmby (Department for Energy Security and Net Zero, United Kingdom);
Matthias Deutsch, Zaffar Hussain and Leandro Janke (Agora Energiewende);
Tudor Florea (Ministry of Energy Transition, France); Johanna Friese(Gesellschaft für Internationale Zusammenarbeit, Germany); Céline Le Goazigo(World Business Council for Sustainable Development); Yukari Hino and Masashi
Watanabe (Ministry of Economy, Trade and Industry, Japan); Yoshikazu
Kobayashi (The Institute of Energy Economics, Japan); Martin Lambert (Oxford
Institute for Energy Studies, United Kingdom); Rebecca Maserumule and Noé van
Hulst (IPHE); Jonas Moberg (Green Hydrogen Organisation); Pietro Moretto (Joint
Reserach Centre, European Commission); Jane Nakano (Center for Strategic andInternational Studies, United States); Alejandro Nuñez (ETH Zürich, Switzerland);Alloysius Joko Purwanto (Economic Research Institute for ASEAN and East Asia,
Indonesia); Stefano Raimondi, Marcello Capra and Roberto Cianella (Ministry ofEnvironment and Energy Security, Italy); Sunita Satyapal, Marc Melaina and Neha
Rustagi (Department of Energy, United States); Petra Schwager and Juan Pablo
Davila (United Nations Industrial Development Organization); Matthijs Soede(Directorate General for Research and Innovation, European Commission); Jan
Stelter (NOW GmbH); Koichi Uchida (State Department, United States); Kirsten
Westphal (German Association of Energy and Water Industries); and Xenia
Zwanziger (Federal Ministry for Economic Affairs and Climate Action, Germany).

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The individuals and organisations that contributed to this study are not responsible
for any opinions or judgements it contains. The views expressed in the study are
not necessarily views of the IEA’s member countries or of any particular funder orcollaborator. All errors and omissions are solely the responsibility of the IEA.

Towards hydrogen definitions based on their emissions intensity

Table of contents

Table of contents
Executive summary .................................................................................................................. 7
Introduction ............................................................................................................................. 11
Hydrogen and its derivatives in a net zero energy system ............................................... 13
Hydrogen today ..................................................................................................................... 14
The role of hydrogen, ammonia and hydrogen-based fuels in the transition to net zero ..... 15
Trade of hydrogen, ammonia and hydrogen-based fuels..................................................... 20
The cost of hydrogen supply ................................................................................................. 22
Accelerating deployment to meet ambitions ......................................................................... 28
Clear hydrogen definitions to address deployment barriers ................................................. 30
International co-operation to facilitate deployment ............................................................... 31
Defining hydrogen according to its emissions intensity ................................................... 33
Introduction ........................................................................................................................... 34
Elements of regulations and certification systems for hydrogen .......................................... 36
The emissions intensity of hydrogen production routes ....................................................... 38
Emissions intensity and costs of hydrogen production in IEA scenarios ............................. 52
Towards an international emissions accounting framework to define hydrogen .......... 59
Considerations for an international accounting framework .................................................. 60
Avenues for implementation ................................................................................................. 70
Practical considerations for effective implementation .......................................................... 76
Considerations for the G7 ..................................................................................................... 83
Annex ....................................................................................................................................... 86
Abbreviations and acronyms................................................................................................. 86

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Units of measure ................................................................................................................... 87

Towards hydrogen definitions based on their emissions intensity

Executive summary

Executive summary
A clear understanding of the emissions associated withhydrogen production can help enable investment andboost scale-up
Most large-scale projects for the production of low-emission hydrogen are
facing important bottlenecks. Only 4% of projects that have been thus far
announced are under construction or have taken a final investment decision.
Uncertainty about future demand, the lack of infrastructure available to deliverhydrogen to end users and the lack of clarity in regulatory frameworks andcertification schemes are preventing project developers from taking firm decisions
on investment.
Transparency on the emissions intensity of hydrogen production can bringmuch-needed clarity and facilitate investment. Using colours to refer todifferent production routes, or terms such as “sustainable”, “low-carbon” or “clean”
hydrogen, obscures many different levels of potential emissions. This terminology
has proved impractical as a basis for contracting decisions, deterring potential
investors. By agreeing to use the emissions intensity of hydrogen production in
the definition of national regulations about hydrogen, governments can facilitate
market and regulatory interoperability. This report aims to assist governments indoing so by assessing the emissions intensity of individual hydrogen production
routes, for governments to then decide which level aligns with their own
circumstances.

The production and use of hydrogen, ammonia andhydrogen-based fuels needs to scale up

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The G7 is a cornerstone of efforts to accelerate the scale-up of the
production and use of low-emission hydrogen, ammonia and hydrogenbased fuels. G7 members – Canada, France, Germany, Italy, Japan, the United
Kingdom, the United States and the European Union – account for around onequarter of today’s global hydrogen production and demand. At the same time, G7
members are frontrunners in decarbonising hydrogen production and technology
development for new hydrogen applications in end-use sectors. The G7 can use
its technological leadership and economic power to enable a greater increase in
the production and use of low-emission hydrogen. However, G7 members cannot
undertake this challenge alone. The development of an international hydrogenmarket will require the involvement of a wide range of other stakeholders, including
among emerging economies.

Towards hydrogen definitions based on their emissions intensity

Executive summary

Hydrogen, ammonia and hydrogen-based fuels have an important role toplay in the clean energy transition. Global hydrogen demand reached 94 million
tonnes in 2021, concentrated mainly in its use as a feedstock in refining andindustry. Meeting government climate ambitions requires a step-change indemand creation for low-emission hydrogen, particularly in new applications in
sectors where emissions are hard to abate, such as heavy industry and longdistance transport. At the same time, hydrogen production needs to be
decarbonised; today, low-emission hydrogen represents less than 1% of global
production.
The development of international supply chains can help to meet the needsof countries and regions with large demand and limited potential to produce
low-emission hydrogen. Regional cost differences and growing demand inregions with less potential to produce low-emission hydrogen, ammonia andhydrogen-based fuels could underpin the development of an internationalhydrogen market to trade these fuels, despite the additional costs arising fromconversion and transport. The global energy crisis has further strengthened
interest in low-emission hydrogen as a way to reduce dependency on fossil fuels
and enhance energy security, becoming a new driver for global trade in hydrogen.

Hydrogen definitions based on emissions intensity canform the basis for robust regulation
The emissions intensity of hydrogen production varies widely depending on
the production route. Today, hydrogen production is dominated by unabatedfossil fuels; emissions need to decrease significantly to meet climate ambitions.
The fuel and technology used, the rate at which CO2 capture and storage isapplied, and the level of upstream and midstream emissions all strongly influence
the emissions intensity of hydrogen production. For example, production based on
unabated fossil fuels can result in emissions of up to 27 kg CO2-eq/kg H2,depending on the level of upstream and midstream emissions. Conversely,
producing hydrogen from biomass with CO2 capture and storage can result innegative emissions, as a result of removing the captured biogenic carbon from thenatural carbon cycle. The average emissions intensity of global hydrogenproduction in 2021 was in the range of 12-13 kg CO2-eq/kg H2. In the IEA Net Zeroby 2050 Scenario, this average fleet emissions intensity reaches
6-7 kg CO2-eq/kg H2 by 2030 and falls below 1 kg CO2-eq/kg H2 by 2050.

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The emissions intensity of hydrogen produced with electrolysis isdetermined by the emissions from the electricity that is used. Using themethodology developed by the International Partnership for Hydrogen and Fuel

Towards hydrogen definitions based on their emissions intensity

Executive summary

Cells in the Economy (IPHE) 1, renewable electricity 2 generation has no associatedemissions, resulting in 0 kg CO2-eq/kg H2. In the case of grid electricity, theemissions intensity varies greatly between peak load and baseload hours,
depending on which technology is used to meet additional demand for theelectrolysers. To reduce emissions, it is therefore important to ensure that gridconnected electrolysers do not lead to an increase in fossil-based electricity
generation.
Carbon capture and storage technologies can reduce direct emissions fromfossil-based hydrogen production but measures to mitigate upstream andmidstream emissions are needed. Hydrogen production from unabated natural
gas results in an emissions intensity in the range of 10-14 kg CO2-eq/kg H2, with
upstream and midstream emissions of methane and CO2 in natural gas production
being responsible for 1-5 kg CO2-eq/kg H2. Retrofitting existing assets with
capture of CO2 from the feedstock-related use of natural gas (capture rate around60%) can bring the emissions intensity down to 5-8 kg CO2-eq/kg H2. Higher
capture rates (above 90%) can be achieved with advanced technologies, reducing
emissions intensity to 0.8-6 kg CO2-eq/kg H2, although no plants using thesetechnologies are in operation yet. At high capture rates, the emissions intensity ofhydrogen production is dominated by upstream and midstream emissions, which
account for 0.7-5 kg CO2-eq/kg H2, underscoring the importance of cutting
methane emissions from natural gas operations.
Governments should define roadmaps to decarbonise hydrogen production,
both domestic and imported, in accordance with their national
circumstances. This report therefore does not provide a generic acceptable
upper threshold for the emissions intensity of hydrogen production. However,
governments should take into account factors such as emissions intensity, supply
volumes and affordability to inform decision-making to scale up production anduse of low--emission hydrogen. The higher production cost of low--emissionhydrogen and the relatively young age of existing unabated fossil fuel-basedhydrogen production assets in the chemical sector are barriers to the uptake of
low-emission hydrogen. Retrofitting existing production assets with CO2 captureand storage can be a cost-effective near-term option to partially decarbonise
production. In regions with abundant renewable resources, the use of renewableelectricity to produce hydrogen is set to be the most cost-effective option, even
before 2030.

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1
The IPHE has developed a methodology for calculating the greenhouse gas emissions intensity of hydrogen production
and conditioning, and is due to complete the methodology for hydrogen transport. The IPHE methodology will serve as thebasis for the first international standard on this topic and can serve as a first step for the adoption of emissions intensity ofhydrogen production in regulations.
2
IPHE methodology assigns zero emissions to solar PV, wind, hydro- and geothermal power.

Towards hydrogen definitions based on their emissions intensity

Executive summary

Reference to the emissions intensity of hydrogenproduction in regulations can enable interoperability andlimit market fragmentation
Several certification systems or regulatory frameworks defining thesustainability attributes of hydrogen are currently being developed, butthere is a risk that lack of alignment may lead to market fragmentation.
Existing efforts have some commonalities in scope, system boundaries,
production pathways, models for chain of custody and emissions intensity levels.
But inconsistencies in approaches risk becoming a barrier for the development ofinternational hydrogen trade. Referring to the emissions intensity of hydrogenproduction, based on a joint understanding of the applied methodology used forregulation and certification, can be an important enabler of market development,
facilitating a minimum level of interoperatibility and enabling mutual recognition
rather than replacing or duplicating ongoing efforts.

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Regulation and certification that uses the emissions intensity of hydrogenproduction should also be able to accommodate additional sustainability
criteria. Governments and companies may wish to consider other potential
sustainability requirements when making decisions about the use of hydrogen asa clean fuel and feedstock. Criteria related to the origin of the energy source, landor water use, and socio-economic aspects such as working conditions are alreadyincorporated into some regulations and certification schemes. The use ofemissions intensity is a first step to enable interoperability, but should not preclude
governments and companies incorporating additional criteria. The use of “productpassports” can help to bring all these criteria together, as well as to standardise
processes, minimise costs and maximise transparency.

Towards hydrogen definitions based on their emissions intensity

Introduction

Introduction
Towards hydrogen definitions based on their emissions intensity is a new reportby the International Energy Agency, designed to inform policy makers, hydrogenproducers, investors and the research community in advance of the G7 Climate
and Energy Ministerial in April 2023. The report builds on the analysis from the
IEA’s Net Zero by 2050: A Roadmap for the Global Energy Sector and continues
the series of reports that the IEA has prepared for the G7 on the sectoral detailsof the roadmap, including Achieving Net Zero Electricity Sectors in G7 Members,
Achieving Net Zero Heavy Industry Sectors in G7 Members and Emissions
Measurement and Data Collection for a Net Zero Steel Industry.
Achieving net zero emissions by 2050 requires large-scale deployment of clean
energy technologies at an unprecedented speed. Low-emission hydrogen,ammonia and hydrogen-based fuels have an important role to play in the
decarbonisation of sectors with hard-to-abate emissions, such as heavy industry
and long-distance transport. However, the availability of these low-emission fuels
is today limited, and efforts are needed in the short term to scale up theirproduction and use. This would help to bring production costs down and to developinternational supply chains that can support the decarbonisation roadmap ofregions with limited potential to produce these fuels domestically to meet theirgrowing demand.
Momentum around hydrogen, ammonia and hydrogen-based fuels has been
growing over the past years. They are now widely recognised as an important tool
to support government climate ambitions and net zero greenhouse gas emissionscommitments announced in recent years. The global energy crisis sparked by
Russian Federation (hereafter, “Russia”)’s invasion of Ukraine has further
strengthened interest in low-emission hydrogen in particular, as a way to reduce
dependency on fossil fuels and enhance energy security.
Industry has responded to this call for action, and announcements of new projects
to produce low-emission hydrogen, ammonia and hydrogen-based fuels are
growing at a very impressive speed. However, only a small fraction of theseprojects have secured the investment required to begin construction. The lack ofclarity in regulatory frameworks and uncertainty around certification are importantfactors contributing to the slow progress in real-world implementation.

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The use of terminologies that are based on colours to describe different production
technologies (e.g. “grey” hydrogen for production based on unabated fossil fuels,“blue” hydrogen for production based on fossil fuels with carbon capture andstorage, or “green” hydrogen produced through use of renewable electricity inTowards hydrogen definitions based on their emissions intensity

Introduction

electrolysers), or on terms such as “sustainable”, “low-carbon” or “clean” hydrogenas a means to distinguish it from unabated fossil fuel-based production has proved
impractical for use in contracts that underpin investment. There is currently nointernational agreement on the use of these terms, which generates uncertainty
among the different players involved in the nascent hydrogen, ammonia andhydrogen-based fuels markets.
The uncertainty created by the lack of regulatory clarity is hindering the investment
required to scale up production and develop supply chains. Clarity on regulations
and certification processes needed to demonstrate regulatory compliance canreassure different market players, especially first movers. Defining hydrogenbased on the greenhouse gas (GHG) emissions intensity of its production can help
to provide clarity to project developers and investors on the emissions intensity of
their product and its compliance with regulatory and market requirements. In
addition, it can enable a certain level of interoperability of regulations acrossdifferent countries and allow mutual recognition of certification schemes, which
can minimise market fragmentation.
This report reviews ways for putting emissions intensity at the centre of regulationand certification. It applies the methodology developed by the International
Partnership for Hydrogen and Fuel Cells in the Economy (IPHE) to assess the
GHG emissions of hydrogen production in order to illustrate the range of emissions
associated with different hydrogen production routes. The report sets out a routeto implement an emissions accounting framework that can help governments tofacilitate interoperability and minimise market fragmentation in order to unlock
investment and speed up deployment.

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The G7 brings together some of the world’s largest advanced economies,
collectively accounting for about 40% of global GDP and roughly one-quarter ofglobal hydrogen production and demand. Moreover, G7 members are among theleading countries in the implementation of policies to support the scale-up of
production of low-emission hydrogen, ammonia and hydrogen-based fuels and thedevelopment of international supply chains. The G7 is also home to more than halfof the most advanced projects currently under development for the production of
low-emission hydrogen, ammonia and hydrogen-based fuels. The common use ofhydrogen production emissions intensity in regulations and certifications of G7
members would provide the necessary regulatory and certification clarity to help
developers and investors to move forward with their projects. This would help
unlock the level of deployment and scale-up required to set in motion thedevelopment of an international market for low-emission hydrogen, ammonia andhydrogen-based fuels in the G7.

Towards hydrogen definitions based on
their emissions intensity

Hydrogen and its derivatives
in a net zero energy system

Hydrogen and its derivatives in a
net zero energy systemHydrogen is an important part of today’s energy sector, with 94 Mt of demand in
2021 concentrated in refining and industrial applications. The G7 accounts foraround one-quarter of global demand. Demand in new applications that could
be key to fully decarbonising the entire energy system remained limited toaround 40 000 t in 2021.

Hydrogen, ammonia and hydrogen-based fuels can support the decarbonisationof the global energy system, particularly in heavy industry and long-distancetransport. This will require a step-change in demand creation, particularly in new
applications; in the IEA’s Net Zero Emissions by 2050 Scenario (NZE Scenario),
global demand from such applications reaches more than 300 Mt by 2050.



The production of hydrogen today is based predominantly on unabated fossil
fuels. Low-emission hydrogen production is more costly, but scale-up andtechnology innovation can make low-emission hydrogen competitive in the shortterm in regions with abundant renewable resources or access to cheap fossil
fuels and geological CO2 storage.

Regional cost differences and growing demand in regions with less potential toproduce low-emission hydrogen, including some G7 members, and the need todiversify fuel supply in the wake of the global energy crisis, could require thedevelopment of an international hydrogen market to trade hydrogen, ammonia
and hydrogen-based fuels, despite the additional costs arising from conversion
and transport processes.



The deployment of large-scale projects for the production of low-emissionhydrogen, ammonia and hydrogen-based fuels is facing important bottlenecks.
Only 4% of announced projects (with a total production capacity of almost 1 Mtof hydrogen) are under construction or have taken a final investment decision.
Lack of clarity in regulation and certification, lack of infrastructure to deliverhydrogen to end users, and uncertainty about future demand are important
impediments.



G7 members have a critical role to play in scaling up production and use of lowemission hydrogen, ammonia and hydrogen-based fuels globally, and in thedevelopment of international supply chains, given their economic power, climate
goals and leadership in technology innovation. Nonetheless, the successful
development of a global hydrogen market will require an inclusive dialogue withother stakeholders, including producer and emerging economies.

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Highlights

Towards hydrogen definitions based on
their emissions intensity

Hydrogen and its derivatives
in a net zero energy system

Hydrogen today
Hydrogen is an important element of today’s energy sector. Global hydrogen
demand reached more than 94 Mt of hydrogen (H2) in 2021 3 (Figure 1.1),
recovering to above pre-pandemic levels, when it had reached its previous
maximum at 91 Mt H2. Hydrogen demand is almost completely concentrated inindustrial applications (mainly in the chemical sector and in iron and steel
production) and refining, where it is used mainly as a feedstock. Beyond these
traditional industrial uses, hydrogen can be used as a fuel in other applications
where it can contribute to the decarbonisation ambitions of governments andindustry, such as in long-distance transport, the production of hydrogen-based
fuels (such as ammonia and synthetic hydrocarbons), high temperature heat inheavy industry and for power generation. However, demand in these applications
was limited to around 40 kt H2 in 2021 (about 0.04% of global hydrogen demand).
Global and G7 members’ hydrogen demand by sector and production bytechnology, 2021

IEA. CC BY 4.0.
Note: Mt H2 = million tonnes of hydrogen. CCUS = carbon capture, utilisation and storage. In the left figure, Other industry
includes small demands in industrial applications such as electronics or glassmaking; Other includes transport, buildings,
power generation sectors and production of hydrogen-based fuels and hydrogen blending. In the right figure, Other
includes hydrogen production from bioenergy.

Hydrogen demand today is met almost entirely by hydrogen production fromunabated fossil fuels and by-product hydrogen from industrial processes that also
use fossil fuels as feedstock, resulting in more than 900 Mt of direct CO2 emissions

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3This 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 hydrogen demand.

Towards hydrogen definitions based on
their emissions intensity

Hydrogen and its derivatives
in a net zero energy system

in 2021 4. The production of low-emission hydrogen, 5 was less than 1 Mt, almost
all from fossil fuels with carbon capture, utilisation and storage (CCUS) 6, with only
35 kt H2 from electricity via water electrolysis.
The G7 plays a significant role in the hydrogen sector today. Together, G7
members account for around one-quarter of global hydrogen demand, which islower than their share of global GDP (around 40%) but similar to their shares ofglobal energy demand (around 30%) and energy-related CO2 emissions (25%).
However, the distribution of demand is slightly different to the rest of the world.
Although the main applications are the same, within the G7 a larger share ofdemand is concentrated in refining (around 60% compared with 40% globally);
demand in industrial applications (chemicals and steel) is more concentrated in
China and the Middle East. New applications accounted for around 0.04% of
demand in the G7 in 2021, largely concentrated in road transport.
Unabated fossil fuels dominate hydrogen production in the G7, but the share of
low-emission hydrogen production is higher than at the global level, at more than
2% in 2021. The G7 accounts for more than 80% of global low-emission hydrogenproduction, demonstrating the leadership of G7 members in decarbonisinghydrogen production. The share is higher in the production of low-emissionhydrogen from fossil fuels with CCUS (nearly 90% of global production), with theUnited States and Canada spearheading developments. In the case ofelectrolysis, the G7 accounted for about 40% of global production, with China
responsible for about 30% of global production.

The role of hydrogen, ammonia andhydrogen-based fuels in the transition to net
zero
Achieving net zero emissions globally by 2050 will require an unprecedented
transformation of the energy system. Hydrogen, ammonia, and hydrogen-based
fuels can play an important role in this transformation, particularly in decarbonising
sectors where emissions are hard to abate, such as heavy industry and longdistance transport. These fuels can also facilitate integration of renewables andgrid balancing.

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4This includes 275 Mt CO2 emitted through the use of hydrogen-based products (e.g. urea and methanol) that capture carbon
only temporarily.
5
The term “low-emission hydrogen” used in this report includes both renewable and low-carbon hydrogen as defined in the2022 G7 Leaders’ Communiqué. The definition used by the IEA for analytical purposes in its reports is described in the 2021
edition of the Global Hydrogen Review.
6
In this report, CCUS includes carbon dioxide captured for use (CCU) as well as for storage (CCS), including CO2 that isboth used and stored, e.g. for enhanced oil recovery or building materials, if some or all of the CO2 is permanently stored.

Towards hydrogen definitions based on
their emissions intensity

Hydrogen and its derivatives
in a net zero energy system

In the IEA’s Stated Policies Scenario (STEPS), which shows how the energy
system evolves under current policy settings, global demand for hydrogen grows
slowly in the short and medium term, reaching 110 Mt by 2030 and 120 Mt by 2035
(Figure 1.2). Demand remains highly concentrated in sectors that are alreadyusing hydrogen today, with limited uptake in new applications (around 2.5% of
global hydrogen demand by 2035). The uptake of hydrogen-based fuels is verysmall and limited to the use of ammonia in power generation in projects in Japan.
Hydrogen and ammonia demand in the G7 and the rest of world by sector
and by scenario
Rest of world hydrogen
Mt H₂

Mt H₂

G7 hydrogen
90
80

180
160

70

140

60

120

50

100

40

80

30

60

20

40

10

20

0

2021

2030

2035

STEPS
Refining

2030

2035

APS
Chemicals

2030

0

2035

2030

2035

2030

STEPS

Iron and steel

Transport

2035

2030

APS
Power

H₂-based fuels

2035

NZE
Other

Rest of world ammonia demand
Mt NH₃

100
90
80

400
350
300

70

250

60
50

200

40

150

30

100

20

50

10
0

2021

NZE

G7 ammonia
Mt NH₃

200

2021

2030

2035

STEPS

2030

2035

APS

2030

0

2035

2021

2030

2035

STEPS

NZE
Chemicals

Shipping

2030

2035

APS

2030

2035

NZE

Power

IEA. CC BY 4.0.

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Note: Mt H2 = million tonnes of hydrogen; Mt NH3 = million tonnes of ammonia; APS = Announced Pledges Scenario; NZE= Net Zero Emissions by 2050 Scenario. STEPS = Stated Policies Scenario. Other includes generation of high temperature
heat in industry, small demands in industrial applications such as electronics or glassmaking, other industries and use inbuildings. H2-based fuels includes ammonia used as a fuel and synthetic hydrocarbons.

Towards hydrogen definitions based on
their emissions intensity

Hydrogen and its derivatives
in a net zero energy system

In the IEA’s Net Zero Emissions by 2050 (NZE) Scenario, global hydrogen
demand reaches 470 Mt by 2050. Getting on track with the NZE Scenario would
require a step-change in ambitions and policy implementation for demand creationin the short term, particularly in new applications. Hydrogen demand nearly
doubles between 2021 and 2030, and triples by 2035, with new applications
responsible for most of the growth in demand, particularly in electricity generation,
heavy industry, long-distance transport and the production of hydrogen-based
fuels. The production of hydrogen-based fuels alone accounts for 18% of globalhydrogen demand in 2035, the majority of which comes from the production ofammonia for use as a fuel in power generation and shipping. The use of ammonia
as fuel can play an important role in the transition to a net zero emissions system 7.
In the NZE Scenario, the demand for ammonia grows from 190 Mt NH3 in 2021,
all of it used as a chemical feedstock, to almost 450 Mt NH3 by 2035, 35% of which
is used as fuel for electricity generation and 20% for shipping.
Net zero targets and hydrogen strategies in G7 members and other major
economies
Government

Net zero target

Hydrogen strategy

Year

In law

AdoptedAnnounced

Brazil2050--

Canada

2050

2020

China
EuropeanCommission
France2060

No
Canadian Net-Zero Emissions
Accountability Act
No

2050

European Climate Law

2021

2050

Energy-Climate Act

2020

Germany

2045

Federal Climate Protection Act

2020*

Italy

2050

No

India

2070

No

2023

Indonesia

2060

No

-

-

Iran

-

-

-

Japan

2050

Saudi Arabia

2060

Korea

2050

Act on Promotion of Global WarmingCountermeasures
No
Carbon Neutrality Act (Framework Act on
Carbon Neutrality and GreenGrowth)

UnitedKingdom
United States

2050

Climate Change Act

2050

No

2022

2020**

2017
-

-

2019

-

2020
2022***

Note: G7 countries highlighted in bold.
* The German National Hydrogen Strategy is under revision and an update is expected in 2023.
** Italy published a draft hydrogen strategy in 2020 for public consultation but its final version has not yet been adopted by
the government.
*** A draft of the United States Department of Energy National Clean Hydrogen Strategy and Roadmap was released for
public consultation and an updated version will be released later in 2023

PAGE | 17

I EA. CC BY 4.0.

7
The use of ammonia in combustion systems can lead to the production of nitrogen oxides (NOx), indirect greenhouse gases,
and nitrous oxide (N2O), a greenhouse gas. However, there are technologies available that can limit the emissions of thesegases in gas turbines and remove them from the exhaust gases in combustion engines, limiting their environmental impact.

Towards hydrogen definitions based on
their emissions intensity

Hydrogen and its derivatives
in a net zero energy system

The G7 has a critical role in scaling up the production and use of low-emissionhydrogen, ammonia and hydrogen-based fuels within member countries andstimulating developments in the rest of the world. In the NZE Scenario, hydrogen
demand in the G7 grows more quickly than in the rest of the world, more thandoubling by 2030 and more than tripling by 2035. In addition, the uptake ofhydrogen as a fuel in new sectors is particularly strong, accounting for around halfof global demand in new hydrogen applications by 2030, compensating for the
decline in hydrogen demand in oil refining. In the IEA’s Announced Pledges
Scenario (APS), which takes into account all announced government climate
targets and assumes that they are met on time and in full, the role of the G7 in
scaling up global hydrogen demand is even larger than in the NZE Scenario. Thisis because all G7 members have net zero targets, most of which have alreadybeen adopted in national laws, and have adopted hydrogen strategies with
ambitious targets to boost production and demand (Table 1.1). The uptake ofhydrogen in new sectors to meet long‐term net zero targets means that, in the
APS, the G7 is responsible for nearly 80% of global hydrogen demand in new
applications by 2030, and nearly 70% by 2035.
The accelerated adoption of hydrogen in new applications in both the APS andNZE Scenario is due to the technological leadership of the G7. Today, theUnited States and Europe account for the majority of projects under development
for the use of hydrogen (either pure or blended with natural gas) in gas turbines.
EU member states account for more than 90% of projects aiming to use purehydrogen in direct reduction of iron. Japanese companies have spearheaded
efforts to develop ammonia turbines and co-firing ammonia and coal for electricity
generation, and Canadian and European companies are at the forefront oftechnology development for the use of hydrogen, ammonia and methanol inshipping.
Demand creation is only one piece of the puzzle: the other is cleaner production.
In the STEPS, global hydrogen production remains dominated by unabated fossil
fuels, with a slow adoption of low-emission hydrogen production technologies,
which account for only 6% of global hydrogen production by 2030 and 9% by 2035
(Figure 1.3). Faster deployment is hindered by lack of clarity around future
demand for low-emission hydrogen, as well as other factors that currently hinder
investment decisions. As in the case of demand generation, for hydrogen,ammonia and hydrogen-based fuels to play a role in the energy transition, there
is an urgent need for more ambitious action on policy implementation to enable a
rapid transformation in the way hydrogen is produced today.

PAGE | 18

I EA. CC BY 4.0.

In the NZE Scenario, such hurdles are overcome and there is fast adoption of lowemission hydrogen production technologies. By 2030, more than half of globalhydrogen is produced through electrolysis powered by low-emission electricity orTowards hydrogen definitions based on
their emissions intensity

Hydrogen and its derivatives
in a net zero energy system

by fossil fuels with CCUS, growing from less than 1 Mt in 2021 to more than
90 Mt H2 by 2030 and reaching 200 Mt H2 by 2035.

G7

100

Mt H₂

Mt H₂

Global and G7 members’ hydrogen production by technology by scenario

80

200

60

150

40

100

20

50

0

0

2021 2030 2035 2030 2035 2030 2035
STEPS
Fossil fuels

APS

Rest of world

250

2021 2030 2035 2030 2035 2030 2035
STEPS

NZE

Fossil fuels with CCUS

By-product

Electricity

APS
Other

NZE

Net imports

IEA. CC BY 4.0.
Note: APS = Announced Pledges Scenario; STEPS = Stated Policies Scenario; NZE = Net Zero Emissions by 2050
Scenario; CCUS = carbon capture, utilisation and storage. Other includes hydrogen production from bioenergy.

G7 members continue to be leading actors in the deployment of low-emissionhydrogen production technologies in the NZE Scenario. By 2030, the G7 is
responsible for around one-third of global low-emission hydrogen production in
the NZE Scenario. Low-emission hydrogen production in the G7 grows from lessthan 1 Mt H2 today to more than 30 Mt H2 by 2030 and more than 50 Mt H2 by2035, requiring a step-change in the speed of deployment of these technologies.
In the NZE Scenario, some G7 members become importers of hydrogen, ammonia
and hydrogen-based fuels due to their limited access to abundant renewable
resources or cheap fossil fuels and geological CO2 storage. Others become
exporters thanks to their much larger resources for low-emission hydrogenproduction (see section Trade of hydrogen, ammonia and hydrogen-based fuels).
However, imports outstrip exports, with the G7 needing to import around 8 Mt H2equivalent (eq) net by 2030 and 15 Mt H2-eq by 2035 to meet its demand. 8 Mostof the hydrogen, ammonia and other derivatives imported are produced using lowemission technologies, meaning that the G7 is a significant driver of the
deployment of low-emission hydrogen production capacities overseas.

PAGE | 19

I EA. CC BY 4.0.

8
The quantities of hydrogen, ammonia and hydrogen-based fuels traded are given in hydrogen equivalent terms, i.e. themass of hydrogen consumed to produce the hydrogen carrier. For example,180 kg of hydrogen are consumed to produce
1 000 kg of ammonia.

Towards hydrogen definitions based on
their emissions intensity

Hydrogen and its derivatives
in a net zero energy system

In the case of the APS, the deployment of low-emission hydrogen production
capacities is slower, both at the global level and in the G7. However, the G7
accounts for a larger share of global low-emission hydrogen production comparedto the NZE Scenario (60% by 2030 and nearly 50% by 2035) due to the 2030 andnet zero emissions targets adopted by its members.

Trade of hydrogen, ammonia and hydrogenbased fuels
The level of hydrogen trade is very low today and limited to sporadic shipments indemonstration projects. However, in the future, countries that have limited
opportunities to produce low-emission hydrogen domestically, either due to lackof abundant renewable resources or limited access to cheap fossil fuels andgeological CO2 storage potential, may have to rely on imports from other regionswith more favourable conditions for low-emission hydrogen production to meettheir hydrogen needs. In addition, the global energy crisis sparked by Russia’s
invasion of Ukraine in February 2022 has increased attention to the energy
security benefits that could be achieved through the development of a globalhydrogen market. Trade in hydrogen, ammonia and hydrogen-based fuels has
technical and cost challenges, but can help countries with insufficient domestic
resources to reach their climate pledges, and can simultaneously contribute toenhance energy security by diversifying the energy mix and the portfolio ofsuppliers. Hydrogen trade can also create export opportunities and revenues forcountries with abundant renewable potentials or access to low-cost fossil fuels
and CO2 storage.
Japan has led the development of international supply chains for hydrogen,ammonia and hydrogen-based fuels. Japan has completed three demonstration
shipments of liquefied hydrogen (from Australia, in 2022), ammonia (from Saudi
Arabia, in 2020) and liquid organic hydrogen carriers (from Brunei, in 2020). Other
countries have also started to increase efforts for the development of international
trade of hydrogen, ammonia and hydrogen-based fuels, notably in Europe, as away to reduce dependency on fossil fuels. Australia, Canada, and several
countries in South America, the Middle East and Africa are positioning themselves
as potential exporters – in readiness for the possible development of aninternational hydrogen market – by signing co-operation agreements with potential
future importers.

PAGE | 20

I EA. CC BY 4.0.

The existing strong industrial base in G7 members is set to require hydrogen
imports to meet demand; this, and the efforts to develop export capacity in others,
could make the trade of hydrogen, ammonia and hydrogen-based fuels an
increasingly important feature of the energy system over the next decades.
However, this is unlikely to occur in the near term with current policy settings. InTowards hydrogen definitions based on
their emissions intensity

Hydrogen and its derivatives
in a net zero energy system

the STEPS, international trade of hydrogen, ammonia and other derivatives
remains limited to 0.6 Mt H2-eq by 2030 and only reaches slightly more than
6 Mt H2-eq by 2050 (Figure 1.4). In energy terms, this is equivalent to less than
5% of liquefied natural gas (LNG) traded globally in 2021.

Mt H₂-eq

Global trade of hydrogen, ammonia and hydrogen-based fuels and share of
global imports in the G7 by scenario
80

80%

70

70%

60

60%

50

50%

40

40%

30

30%

20

20%

10

10%

0

2021

2030

2050
STEPS

2030

2050
APS

2030

2050

Other
derivatives
Ammonia
Gaseoushydrogen
LiquefiedhydrogenG7 share(right axis)

0%

NZE

IEA. CC BY 4.0.
Notes: STEPS = Stated Policies Scenario; APS = Announced Pledges Scenario; NZE = Net Zero Emissions by 2050
Scenario. Hydrogen includes both liquified hydrogen shipping and gaseous hydrogen trade via pipeline. The energy
content is based on the lower heating value (LHV) of each carrier.

Meeting decarbonisation objectives for the energy system is set to enable a muchquicker scale-up of international trade of hydrogen, ammonia and hydrogen-based
fuels, and the creation of the respective global market. In both the APS and the
NZE Scenario, the international trade of hydrogen, ammonia and hydrogen-based
fuels grows to almost 45 Mt H2-eq and more than 70 Mt H2-eq respectively by
2050. In energy terms, this would be equivalent to almost 30% and 45% of LNG
traded globally in 2021. G7 members are key players in the development andscale-up of international trade of hydrogen, ammonia and hydrogen-based fuels,
accounting for more than half of the global trade of these fuels by 2030 in the APS
and the NZE Scenario.

PAGE | 21

I EA. CC BY 4.0.

Imports of hydrogen, ammonia and hydrogen-based fuels represent an important
share of the demand for these fuels in the G7. In the NZE Scenario, imports ofhydrogen, ammonia and hydrogen-based fuels in the G7 reach 10 Mt H2-eq by
2030, meeting nearly one-fifth of their demand. By 2050, G7 imports grow up to
35 Mt H2-eq, meeting one-third of demand. In the APS, imports of hydrogen andammonia develop more slowly in the G7, reaching only around 2 Mt H2-eq or 5%of demand by 2030. However, by 2050, the situation in the APS is quite similar to
the NZE Scenario, with close to 30 Mt H2-eq of hydrogen, ammonia and hydrogenbased fuels being imported to meet more than one-quarter of demand.

Towards hydrogen definitions based on
their emissions intensity

Hydrogen and its derivatives
in a net zero energy system

The cost of hydrogen supply
The cost of hydrogen production depends on the technology and cost of theenergy source used, which usually has significant regional differences. Prior to theglobal energy crisis sparked by Russia’s invasion of Ukraine, the levelised cost ofhydrogen production from unabated fossil-based sources was in the range of
USD 1.0-3.0/kg H2 (Figure 1.5). In 2021, these production routes offered thecheapest option to produce hydrogen, compared to the use of fossil fuels with
CCUS (USD 1.5-3.2/kg H2) or the use of electrolysis with low-emission electricity(USD 3.1-9.0/kg H2).

USD/kg H₂

Levelised cost of hydrogen production by technology and by scenario,
2021 and 2030
10
8
6
4

Natural gas w/o
CCUS

Natural gas w/ Coal w/o CCUS Coal w/ CCUS
CCUS

Solar PVWind

2030 NZE

2030 APS

2021

2030 STEPS

2030 NZE

2030 APS

2030 STEPS

2021

2030 NZE

2030 APS

2021

2030 STEPS

2030 NZE

2030 APS

2030 STEPS

2021

2030 NZE

2030 APS

2021

2030 STEPS

2030 NZE

2030 APS

2030 STEPS

2021

2030 NZE

2030 APS

2030 STEPS

0

2021

2

Nuclear

IEA. CC BY 4.0.
Note: STEPS = Stated Policies Scenario; APS = Announced Pledges Scenario; NZE = Net Zero Emissions by 2050
Scenario; CCUS = carbon capture, utilisation and storage. Solar PV, wind and nuclear refer to the electricity supply topower the electrolysis process. Wind includes both offshore and onshore wind. The capital cost is USD 780/kW H2 for theunabated natural gas reforming system and USD 1470/kW H2 for the one equipped with CCUS; USD 1960/kW H2 forunabated coal gasification and USD 2040/kW H2 for the one equipped with CCUS; USD 1240-1500/kWe for electrolyser in
2021, USD 460-570/kWe in STEPS 2030, USD 340-390/kWe in APS 2030, USD 270-320/kWe in NZE Scenario by 2030.
The dashed area represents the CO2 price impact, based on USD 0-90/t CO2 for STEPS, USD 0-135/t CO2 for APS and
USD 15-140/t CO2 for NZE Scenario.

PAGE | 22

I EA. CC BY 4.0.

The large increase in fossil fuel prices observed during 2022, particularly fornatural gas, has significantly increased the cost of producing gas-based hydrogenin certain regions. For example, at prices of USD 25-45 per million British thermal
units (MBtu), such as those observed during June 2022 in gas markets in Europe,
the cost of producing hydrogen from unabated natural gas is USD 4.8-7.8/kg H2,
with natural gas alone being responsible for at least 80% of this cost. This is up to
three times the cost prior to the energy crisis. In the case of the production ofhydrogen from natural gas with CCUS, the levelised cost of hydrogen production
is USD 5.3-8.6/kg H2, of which more than 75% is attributable to natural gas prices.

Towards hydrogen definitions based on
their emissions intensity

Hydrogen and its derivatives
in a net zero energy system

At such natural gas prices, the cheapest option for producing hydrogen today inmany regions would be from electrolysis using renewable electricity, if production
capacity was available.
The record highs in gas prices have started to recede after the turmoil of last year.
With the gas prices observed in Europe the first quarter of 2023
(USD 15-20/MBtu), the cost of hydrogen production from unabated natural gas isaround USD 2.9-4.2/kg H2, and from natural gas with CCUS, in the range of
USD 3.3-4.7/kg H2. Moreover, not all markets have been as strongly affected as
Europe and see more affordable production of gas-based hydrogen. For example,
at gas prices typically observed for the Middle East (USD 1.5-4/MBtu), hydrogenproduction from unabated natural gas costs around USD 0.6-1.0/kg H2, and fromnatural gas with CCUS USD 1.0-1.4/kg H2. In the case of the United States (gasprices around USD 3/MBtu in the first quarter of 2023), where an operative
network for CO2 transport and storage is already in place, hydrogen production
from unabated natural gas costs around USD 0.8/kg H2, and from natural gas with
CCUS USD 1.3/kg H2.

10
9
8
7
6
5
4
3
2
1
0

Unabated natural gas
USD/kg H2

USD/kg H₂

Impact of natural gas and CO2 prices on the levelised cost of hydrogenproduction from natural gas

315
USD 150/t CO₂

26
38
50
Natural gas price [USD/MBtu]
USD 100/t CO₂

10
9
8
7
6
5
4
3
2
1
0

USD 50/t CO₂

Natural gas with CCUS3

15
USD 0/t CO₂

26
38
50
Natural gas price [USD/MBtu]
USD 150/t CO₂ with CCUS

IEA. CC BY 4.0.
Note: CCUS = carbon capture, utilisation and storage. The capital cost of the unabated natural gas reforming system is
USD 780/kW H2 and USD 1470/kW H2 for the one equipped with CCUS; the cost of CO2 transport and storage is
USD 30/t CO2 and the capture rate is 93%.

PAGE | 23

I EA. CC BY 4.0.

The cost of producing hydrogen from unabated fossil fuels will remain highly
influenced by the cost of the fossil fuels, but also by the potential adoption ofpolicies such as carbon pricing (Figure 1.6). For example, a carbon price of
USD 100/t CO2, i.e. slightly above the carbon prices observed in the EU and UK
Emissions Trading Systems since the end of 2021, would result in an additional
cost of USD 1/kg H2 in the production of hydrogen from unabated natural gas and
USD 2/kg H2 for unabated coal. In the case of the use of fossil fuels with CCUS,
the impact of CO2 prices would be very limited (less than USD 0.1/kg H2 for natural

Towards hydrogen definitions based on
their emissions intensity

Hydrogen and its derivatives
in a net zero energy system

gas at a carbon price of USD 100/t CO2). Moreover, as for renewable electrolysis,
the competitiveness of producing hydrogen from fossil fuels with CCUS can
improve with higher deployment, as shown in the APS and NZE Scenario.
Deployment in STEPS is very limited, and so, therefore, is the cost reduction. The
additional capital cost to enable CCUS is expected to decrease as a result of
scale-up and technology development, meaning the cost of producing hydrogenfrom fossil fuels with CCUS could become cheaper than from unabated fossil
fuels, depending on fossil fuel and CO2 prices.

USD/kg H₂

Levelised cost of hydrogen produced from renewable electricity by region
and by scenario, 2021 and 2030
1210Solar PV

8

Wind
2021

6

2030 STEPS
2030 APS

42030 NZE

20
UnitedStatesJapan

NW
EuropeAustralia

MiddleEast

North
Africa

China

India

Chile

IEA. CC BY 4.0.

The cost of hydrogen produced using electrolysis is driven by the capital cost ofelectrolysers and the cost of the electricity used to power the electrolyser. The
capital costs of electrolysers are set to decrease strongly in the short term thanks
to economies of scale and further technology innovation. The cost of renewableelectricity has already decreased sharply in the last decade (80% reduction in thecost of solar modules between 2010 and 2020), and is expected to continue todecline thanks to widespread deployment of renewables, which are projected to
become the largest source of global electricity generation by early 2025. The
recent increases in commodity prices may slow down further cost declines in thenear term but are unlikely to stop them altogether over the longer term. As thecapital cost of electrolysers goes down, the share of the cost of renewableelectricity in the cost of producing hydrogen from renewable resources becomes
more important. The cost of producing hydrogen from renewable electricity
therefore strongly depends on the location of production, resulting in a very wide
range of costs at a global level (Figure 1.7). If large-scale deployment takes place(as projected in all three IEA scenarios), the levelised cost of hydrogen could drop

PAGE | 24

I EA. CC BY 4.0.

Note: STEPS = Stated Policies Scenario; APS = Announced Pledges Scenario; NZE = Net Zero Emissions by 2050
Scenario; NW Europe = North-West Europe. Wind includes both offshore and onshore wind. The capital cost for an
installed electrolyser system is assumed at USD 1240-1500/kWe for electrolyser in 2021, USD 460-570/kWe in STEPS
2030, USD 340-390/kWe in APS 2030, USD 270-320/kWe in NZE Scenario by 2030.

Towards hydrogen definitions based on
their emissions intensity

Hydrogen and its derivatives
in a net zero energy systembelow USD 2/kg H2 by 2030 in countries and regions with excellent solar
irradiation, such as Africa, Australia, Chile, China and the Middle East. While solar
PV-based electrolysis could become the cheapest way to produce hydrogen by
the end of the decade, locations with excellent wind resources (offshore or
onshore) could also see a significant drop in the levelised cost of hydrogen,reaching values under USD 3/kg H2 in the North-West European region and under
USD 2/kg H2 in the United States. With these costs, the production of hydrogenusing electrolysis powered with renewable electricity can become competitive withfossil-based routes (both unabated and with CCUS). This is especially the case inlocations with access to cheap solar PV electricity.
Indicative production costs for hydrogen-based commodities produced via
electrolysis in the Announced Pledges Scenario, 2021 and 2030
Ammonia via electrolysis
Western Europe
Japan
United States
China
Current reference
0

1 000

2 000
Crude steel via H2-DRI

3 000
USD/tonne

Western Europe
Japan
United States
China
Current reference0
Recent grid electricity

500
VRE 2021

1 000
VRE APS - 2030

1 500
USD/tonne
Current reference
IEA. CC BY 4.0.

Notes: VRE = variable renewable energy; APS = Announced Pledges Scenario; H2-DRI = hydrogen-based direct reducediron. The VRE cost range represents electrolysis powered by solar PV, offshore wind or onshore wind. An additionalhydrogen storage cost to guarantee a minimum load of 80% is considered. ‘Current reference’ values show production
costs using the dominant incumbent means of production today with unabated fossil fuels. The cost of capital is assumed
at 5%, while the other techno-economic assumptions are sourced from the references below. Incentives from support
schemes such as the Inflation Reduction Act (IRA) have not been taken into account.
Source: IEA (2023), Energy Technology Perspectives 2023.

PAGE | 25

I EA. CC BY 4.0.

The considerable cross-region variations in the production costs of hydrogen canalso have an important effect on the production costs of certain end-products, suchas ammonia or steel, thereby affecting the competitiveness of the production ofthese products across differerent regions. Based on recent grid electricity prices,
producing ammonia and steel with hydrogen using grid-connected electrolysers
would cost around 50-170% more in Western Europe and Japan than in China,

Towards hydrogen definitions based on
their emissions intensity

Hydrogen and its derivatives
in a net zero energy system

and 40-100% more than in the United States (Figure 1.8). Western Europe
becomes much more competitive if the production costs that could be achieved
using low-cost variable renewable energy are considered, although cost still
remains higher than in China and the United States.
Substantially lower costs can be envisaged if countries are successful in
implementing their announced pledges and scaling up the deployment of
renewables and low-emission hydrogen production. Moreover, although costdifferences will persist, these differences would be less marked. In the APS, using
variable renewable energy to produce ammonia leads to costs in the range of
USD 480-1 500/t, and USD 520-980/t for crude steel in 2030. Competitiveness isa key consideration for governments in designing their industrial strategies andassessing those of their key suppliers. This can lead to different priorities in thedevelopment international supply chains of hydrogen, ammonia and otherderivatives.

The cost of transport and conversion processes
The production cost of hydrogen is only part of the final cost that consumers willneed to pay. Today, most hydrogen production is captive, meaning that hydrogenproduction and consumption are integrated processes for large centralised
industrial users. In this case, the production cost is the same as the cost faced by
the final user. However, the adoption of hydrogen, ammonia and hydrogen-based
fuels in new applications which are more distributed (such as in the transport
sector) will require the creation of domestic hydrogen transport and distribution
infrastructure. Moreover, significant regional differences in production costs andan increasing focus on diversifying supplies may lead to the creation ofinternational markets. In such markets, countries with limited potential to develop
low-emission hydrogen production capacities will rely on imports of hydrogen,ammonia and hydrogen-based fuels from regions with abundant renewable
resources or with access to cheap fossil fuels and CO2 storage potential.

PAGE | 26

I EA. CC BY 4.0.

The need for domestic and international trade infrastructure for hydrogen,including for conversion into other hydrogen carriers and potential reconversion
into hydrogen, are further cost elements in addition to production costs. In certain
cases, conversion and reconversion costs – if needed – as well as transport costs,
can be greater than the production costs. When shipped as liquefied hydrogenover long distances, the shipping cost represents the main cost component of thedelivered hydrogen. For example, the cost of transporting liquefied hydrogen from
Chile to Japan can account for 50% of the final delivered cost of hydrogen(Figure 1.9). Shipping liquified hydrogen is a very expensive option for shippinghydrogen and will remain so in the near future, but this cost can be expected todecrease significantly with scale-up. If ammonia is chosen as the transport carrier,the transport costs decrease, but the cost of converting hydrogen into ammonia

Towards hydrogen definitions based on
their emissions intensity

Hydrogen and its derivatives
in a net zero energy systemand the subsequent cost of cracking it back to hydrogen significantly affects thedelivered cost of hydrogen. However, in cases where ammonia can be directly
used without being reconverted to hydrogen, the reconversion costs can be
avoided. In the case of hydrogen shipping using liquid organic hydrogen carriers,
shipping costs are also expected to be lower than using liquified hydrogen, due tothe possibility of using existing tankers, although the energy required in theconversion and reconversion processes strongly affects the final cost of delivery.
Near-term levelised cost of delivered hydrogen and ammonia from solar PV,
by transport option, in selected trade routes

7

USD/t NH3

USD/kg H2

Chile to Japan
6
5
4

1 260
1 080
900
720

3

540

2

360

1

180

0

LH₂

LOHC

NH₃
Delivery as hydrogen

0

H₂
Domestic
production

NH₃

NH₃

Delivery as
ammonia

Domestic
production

NH₃

NH₃

Delivery as
ammonia

Domestic
production

7

USD/t NH3

USD/kg H2

North Africa to Germany

6
5
4

1 260
1 080
900
720

3

540

2

360

1

180

0

LH₂

NH₃

LOHC

Pipeline

Delivery as hydrogen
Production

0

H₂
Domestic
production

Conversion

Transport

Re-conversion
IEA. CC BY 4.0.

PAGE | 27

I EA. CC BY 4.0.

Note: LH2 = liquified hydrogen. NH3 = ammonia. Transport includes the cost associated with investment and operation ofstorage tanks at import and export shipping terminals assuming 20 annual shipments and shipping cost; in the case ofpipeline, it includes the cost related to the construction and operation of hydrogen pipelines. For liquified hydrogenshipping, the tanker size assumed is 160 000 m3; for ammonia shipping it is 76 000 m3. For pipeline, the dashed area
represents the cost variation in the case of a new or repurposed 48-inch pipeline operating between 25% and 75% of its
design capacity during 5 000 full load hours. For ammonia, an additional hydrogen storage cost is considered, to guarantee
a minimum load of the Haber-Bosch process of 80%. The levelised cost of hydrogen production from solar PV is assumed
to be USD 1.6/kg H2 in Chile and USD 2/kg H2 in North Africa; and the levelised cost of ammonia production from solar PV
is assumed to be USD 500/t of ammonia in Chile and USD 600/t of ammonia in North Africa.

Towards hydrogen definitions based on
their emissions intensity

Hydrogen and its derivatives
in a net zero energy system

In the case of shorter distances between the sites of production and demand (upto around 3 000 km), transporting compressed gaseous hydrogen via pipeline
may be the cheapest option. For example, compressing and transportinghydrogen between North Africa and Germany using newly built pipelines could
add around USD 0.5-0.9/kg H2 to the production cost, if a new pipeline is built.
This cost could fall to only USD 0.2/kg H2 if an existing natural gas pipeline isrepurposed to transport hydrogen, although this option presents some technicalchallenges that may limit its applicability.

Accelerating deployment to meet ambitions
There is a very large gap between the production of low-emission hydrogen today
and what is needed to put the world on track with the APS and the NZE Scenario.
However, a sizeable number of projects have been announced, aiming to develop
large capacities for the production of low-emission hydrogen. If all announced
projects are realised, the annual production of low-emission hydrogen could reach
24 Mt by 2030 (Figure 1.10). These projects are spread across the globe, although
G7 members account for roughly half of the potential production that could beachieved from all the projects under development.
The production of low-emission hydrogen from announced projects would beenough to meet 80% of the APS requirements but only around one-quarter of theneeds of the Net Zero Emissions by 2050 Scenario. How many of the announced
projects will become operational by 2030 is uncertain. With current policy settings,
most of these projects will not be realised due to barriers to deployment being
encountered by project developers today, including lack of demand, uncertainty
on regulation and certification, and lack of infrastructure to deliver hydrogen to end
users. In addition, emerging economies (which account for around one-quarter ofthe potential production from announced projects) face other important barriers,
such as difficulties in accessing finance and the need to develop a skilledworkforce. Without policy action to overcome these barriers, deployment willremain limited to 6 Mt, as projected in the STEPS.

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The maturity of the projects under development can provide a good indication of
the feasibility of reaching their full production potential by 2030. Currently, only 4%of the projects (in terms of their production output in 2030) are at advanced stagesof development, i.e. are under construction or have reached a final investment
decision (FID). About one-third of the potential production of low-emissionhydrogen corresponds to projects at the concept stage, meaning that they are atvery early stages of development (e.g. only a co-operation agreement among
stakeholders has been announced), while the remaining portion consists ofprojects undergoing feasibility and engineering studies.

Towards hydrogen definitions based on
their emissions intensity

Hydrogen and its derivatives
in a net zero energy system

Around 2% of the CCUS projects are at advanced stages of development,
representing 0.2 Mt of low-emission hydrogen production by 2030. In the case ofelectrolysis projects, only 5% are at advanced stages of development(representing around 0.7 Mt of low-emission hydrogen production), with the bulkof potential production coming from projects undergoing feasibility andengineering studies (58% of potential production) or at concept stage (37% of
potential production). This means that the vast majority of the projects are still far
from being realised. The construction and commissioning of hydrogen projects
can take from around two years (for electrolysis projects smaller than 100 MW) toaround a decade (in the case of large CCUS projects).

100

Production by technology

100%

Production by maturity status

10

Mt H₂

100%

40

40%

4

40%

20

20%

2

20%

0%

0

0%

2021

2030
2030
Announced STEPS
Projects

2030
APS

2030
NZE

Electrolysis

Other

G7 share (right axis)

Fossil fuels with CCUS

Concept

Fossil fuels with CCUS

Operational0Concept60%

Feasibiltiy
study

6

Advanced

60%

60

Operational

80%

80%

Feasibiltiy
study

8

80

Advanced

Mt H₂

Global low-emission hydrogen production and G7 share based on
announced projects and by scenario, 2021 and 2030

Electrolysis

IEA. IEA. CC BY 4.0.
Notes: STEPS = Stated Policies Scenario; APS = Announced Pledges Scenario; NZE = Net Zero Emissions by 2050
Scenario; CCUS = carbon capture, utilisation and storage. Other includes hydrogen production from biomass, with andwithout CCUS.
Source: IEA (2022), Hydrogen Projects Database (March 2023).

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In 2021, G7 members produced more than 80% of all hydrogen coming fromoperational projects using fossil fuels with CCUS, and 40% from operational
electrolysis projects. Moreover, almost half of the announced projects that are
currently under construction or have taken an FID and therefore could become
operational by 2030 are located in G7 members, representing nearly 0.5 Mt ofpotential low-emission hydrogen production. In addition, projects with a potential
production of 8.5 Mt of low-emission hydrogen by 2030 are undergoing feasibility
and engineering studies in G7 countries. This is 55% of all the projects in the world
at this development stage, highlighting the important role that the G7 can play inscaling up low-emission hydrogen production in the short term.

Towards hydrogen definitions based on
their emissions intensity

Hydrogen and its derivatives
in a net zero energy system

Clear hydrogen definitions to address
deployment barriers
Despite the strong momentum behind hydrogen and the growing interest shownby both governments and industry, progress in project implementation is still slow
and far from what would be needed for hydrogen to play its role in meeting climate
ambitions. This highlights the need to rapidly address several barriers contributing
to the slow pace of project deployment:The potential scale of demand for low-emission hydrogen in the near term isuncertain, and it is unclear how much of this demand will be specifically for lowemission hydrogen. Many governments have identified potential mechanisms tocreate this demand, such as such as auctions, mandates, quotas andrequirements in public procurement. However, the majority of these polices have
not yet been implemented. In the case of hydrogen produced using renewables
more specifically, uncertainty around the long-term development of energy prices
prevents FIDs being taken, despite the current competitiveness of renewablebased hydrogen in certain markets.



There is a need to develop the infrastructure required to deliver hydrogen from theproduction side to the end users. This is particularly necessary in the case of
distributed applications, or where large demand is situated far from locations thatare attractive for producing low-emission hydrogen at low cost. Today there isalmost no available infrastructure, and if developed it faces the risk ofunderutilisation due to the uncertain evolution of demand.



There is a lack of clarity in regulatory frameworks and certification schemes. The
scale-up of low-emission hydrogen production requires clear policy frameworks,
including agreed standards for environmental criteria and policies to incentivise
end users to commit to long‐term purchases and manage offtake risk. Standards
and certification for guaranteeing that hydrogen‐based commodities meetenvironmental criteria, either voluntary, set by regulatory obligations or linked togovernment and market incentives, have become a priority for project developers
to gain investors’ confidence. Achieving a certain level of compatibility among
these policy frameworks across borders will also be needed in order to facilitate
international trade.

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Governments have an important role in implementing measures to lower all ofthese barriers and facilitate deployment, and regulation is an area in whichgovernment action can have a large and immediate impact. Market players, andparticularly first movers, require clarity on regulations and the certification
processes needed to demonstrate regulatory compliance. This is particularly thecase for aspects related to hydrogen sustainability attributes.

Towards hydrogen definitions based on
their emissions intensity

Hydrogen and its derivatives
in a net zero energy system

International co-operation to facilitate
deployment
Governments need to enhance international co-operation in order to address
various barriers to the scale-up of hydrogen production and use, particularly for
aspects related to defining standards and certification systems for hydrogen.
Finding avenues for mutual recognition of regulations and certification schemes
can facilitate interoperability and minimise market fragmentation. This can helphydrogen producers to reach offtake agreements with multiple potential clients indifferent markets, without the need to certify their product individually for eachclient, region and regulatory authority. The G7 is an ideal forum to explore thesepotential avenues, drawing on the sizeable economic power and technologicalleadership of its members. The G7 is already taking action to enhancecollaboration in addressing some of the barriers that are preventing hydrogenscale-up. In 2021, the UK G7 Presidency and the United States initiated theG7 Industrial Decarbonisation Agenda to work on regulation, standards,
investment, procurement and joint research related to industrial decarbonisation,
which can indirectly trigger hydrogen demand in the industrial sector. In 2022 theG7 members launched the Hydrogen Action Pact, with the objective of joining
forces to accelerate the adoption of hydrogen and hydrogen-based fuels(especially ammonia), and streamlining the implementation of existing multilateral
initiatives.

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G7 members can benefit from being first movers and facilitating interoperability
among their regulatory frameworks in order to scale up both domestic production
and demand for hydrogen, ammonia and other derivatives, as well as facilitatinginternational trade. This would support the development of international hydrogen
trade in the near term. However, G7 members cannot undertake this challenge inisolation. The development of an international hydrogen market requires theinvolvement of as many stakeholders as possible, including producer andemerging economies. These countries have strong potential to produce affordable
low-emission hydrogen and want to benefit from the development of a globalhydrogen market in the form of economic growth, the creation of a skilledworkforce or avoided environmental harm and negative impacts in their local andindigenous communities. The G7 needs to foster an inclusive dialogue, ensuringthat the voices of all these potential partners are heard and their challenges arerecognised. The success of the development of a global hydrogen market will, toa large extent, depend on its inclusivity and the fair distribution of its benefits.

Hydrogen and its derivatives
in a net zero energy system

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Towards hydrogen definitions based on
their emissions intensity

Towards hydrogen definitions based on
their emissions intensity

Defining hydrogen according to
its emissions intensity

Defining hydrogen according to its
emissions intensity



Clear regulations and certification systems based on the emissions intensity ofhydrogen production can bring much-needed transparency and be a usefulenabler of investments in production and demand applications as well as
infrastructure for hydrogen trade. The colour scheme often used for hydrogen,such as “green” or “blue” hydrogen, suggests a characterisation of the
production route, but does not provide any quantification of its effect onemissions.



Several voluntary certification systems and regulations to define hydrogen using
the emissions intensity as key indicator already exist or are under development.
Many of them share common elements, such as emissions intensity as a key
indicator, or a focus on hydrogen production, but they differ in aspects such assystem boundaries or the emissions intensity levels imposed. A consistentmethodology to define hydrogen based on its emissions intensity will be criticalto ensure interoperability between regulatory frameworks and certification
systems. The analysis in this report is based on the methodology developed by
the International Partnership on Hydrogen and Fuel Cells in the Economy.

Emissions intensities vary widely among hydrogen production routes, from
10-13 kg CO2-eq/kg H2 from the use of unabated natural gas, to0.8-4.6 kg CO2-eq/kg H2 for partial oxidation of natural gas with carbon captureand storage (CCS) (with the ranges depending on the upstream and midstream
emissions of natural gas supply). For fossil-fuel based routes, in addition toincreasing the CO2 capture rate, minimising upstream and midstream emissionsof fossil fuel operations, in particular methane emissions, will be critical toachieve low intensities.



While hydrogen production from renewable electricity via electrolysis is
assumed to lead to zero emissions, achieving low emission levels using gridelectricity depends on the emissions intensity of the grid. For example, a gridelectricity intensity of 40 g CO2-eq/kWh yields hydrogen with an emissions
intensity of 2 kg CO2-eq/kg H2.

Global hydrogen production is today almost completely based on the use of
unabated fossil fuels, resulting in an emissions intensity of
12-13 kg CO2-eq/kg H2. In the Announced Pledges Scenario (APS), the global
average emissions intensity falls below 3 kg CO2-eq/kg H2 by 2050, while in the
Net Zero by 2050 Scenario the intensity reaches levels of under
1 kg CO2-eq/kg H2 by 2050.

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Highlights

Towards hydrogen definitions based on
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Defining hydrogen according to
its emissions intensity

Introduction
Various terms are currently used to describe the environmental attributes ofhydrogen. These either use colours to refer to different production routes (e.g.
“green” for hydrogen from renewable-powered electrolysis and “blue” forproduction from natural gas with carbon capture, utilisation and storage (CCUS))
or terms such as “sustainable”, “low-carbon” or “clean” hydrogen to distinguish itfrom unabated fossil-based production. However, there is no international
agreement on the use of these terms, and their existing definitions are generally
considered insufficient to be used as a reference in regulations or supply
contracts. For example, much existing electrolysis currently runs on grid electricity,
for which a colour has not been proposed. The terms “grey” and “blue” provide no
information about important factors such as upstream and midstream methane
emissions and carbon capture rate.
Clear definitions based on the greenhouse gas (GHG) emissions intensity 9 ofhydrogen production can bring much-needed transparency and be a usefulenabler of investments in hydrogen production, hydrogen demand applications,infrastructure and trade in hydrogen. Without such clarity on definitions,contracting parties lack criteria needed to comply with divergent regulations andcertification schemes around the world (Box 2.1). This could hinder thedevelopment of projects due to risks of non-compliance in the future, as well as
time and costs associated with multiple certification processes.
Developing definitions based on a common methodology or agreed standard todetermine the GHG intensity of hydrogen can simplify the certification process. A
common definition would allow for comparison of the emissions intensities
between different production pathways and producers, while still leaving
governments the possibility to define acceptable emissions intensity levels, taking
into account local circumstances and opportunities. Countries may set different
thresholds, but use of a common methodology to determine emissions intensity
would ensure interoperability between different countries.

9
Greenhouse gas (GHG) emissions refer here to the emissions of CO2, methane (CH4) and nitrous oxide (N2O). For the
supply of natural gas and coal and in hydrogen production processes, N2O emissions are relatively small and levels
uncertain, so N2O emissions are only include in the emissions of grid electricity, but not in the emissions of upstream
natural gas and coal supply. Hydrogen itself is an indirect GHG, but has been not considered in the analysis here, as
research on its global warming potential is still ongoing.

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This chapter starts with an overview of existing and proposed certification systems
and regulations for hydrogen and their attributes and criteria. This is followed byan analysis of the emissions intensity of different hydrogen production routes. The
analysis is based on the methodology developed by the International Partnershipon Hydrogen and Fuel Cells in the Economy (IPHE), using IEA data for theTowards hydrogen definitions based on
their emissions intensity

Defining hydrogen according to
its emissions intensity

production technologies and upstream and midstream emissions. This analysis isthen used as the basis of a proposal for defining hydrogen according to its
emissions intensity.

Box 2.1

Certification systems

A certification system provides evidence that methodologies and analyticalframeworks are applied according to a specified standard or set of requirements.
Certifications can help to provide credibility and transparency by demonstrating toconsumers that a product or service meets certain expectations. Issued byindependent bodies, certifications cover both the test methods to assess a certain
product or process and the criteria that the product or process must meet. They
undergo the necessary inspections and reviews to guarantee an objective
evaluation.
These systems can be either mandatory or voluntary. Mandatory certification
systems verify that market participants are adhering to specific criteria outlined inpolicies, regulations or contractual obligations. In contrast, voluntary certification
systems can be used for reporting and disclosure purposes.
Mutually recognised certifications enable the global interoperability of products anddevices. For example, WiFi certifications based on internationally recognised
standards guarantee that a variety of devices will be able to connect to wirelessnetworks around the world.



Governance: to establish the roles and responsibilities of the standards andcertification bodies.

Application: of the standard on which the product or process is being tested,
and any additional criteria.



Evaluation: of whether the product or process meets the standard or
qualification criteria, and the need for more information or a second review.



Enforcement and verification: that the product or process in the marketplace
continues to meet the qualification criteria, and of the steps to audit and verify
compliance.

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Certifications are found across all economic sectors, such as electronics,
telecommunications, and pharmaceuticals. In general, the main elements of a
successful certification system include:Towards hydrogen definitions based on
their emissions intensity

Defining hydrogen according to
its emissions intensity

Elements of regulations and certification
systems for hydrogen
No internationally agreed framework or standard on how to define the GHG
intensity of hydrogen production currently exists, though efforts are underway. The
IPHE has developed a methodology to calculate the GHG emissions for differenthydrogen production routes. This methodology is being used to establish an
International Organization for Standardization (ISO) standard. 10

Attributes and criteria of certification systems
Despite the nascent nature of hydrogen markets, several certification systems or
regulatory frameworks defining the emissions intensity of hydrogen have beendeveloped or are under development (Table 3.1). They can be characterised bydifferent attributes and criteria:

Purpose: Certification systems can be voluntary and used by market participants
for reporting and disclosure purposes, such as the Green Hydrogen Standard at
an international level, CertifHy in the European Union or TÜV SÜD CMS 70 inGermany. Certification can also be required for regulatory reasons to prove
compliance with specific legislative criteria in a country, or to benefit fromgovernment incentives, such as California’s Low-Carbon Fuel Standard or thehydrogen production tax credit of the Inflation Reduction Act in the United States.
Funding programmes, tenders or auctions can also require that certain
emissions intensity levels are met, such as the tenders for hydrogen purchaseagreements of H2Global.



System boundaries: Certification systems can be differentiated by the hydrogen
supply chain steps that they cover (Figure 2.1). Well-to-gate system boundaries
target the supply of the fuels used in the production process, while well-to-pointof delivery or well-to-tank boundaries also include the transport and possible
conversion and reconversion of hydrogen into other carriers (e.g. ammonia). Wellto-wheel system boundaries also include emissions associated with the use ofhydrogen. CertifHy is based on a well-to-gate system boundary, while H2Global
follows a well-to-point of delivery approach by taking into the account the transport
emissions to specified delivery points in Europe. 11 A well-to-wheel systemboundary is used for the definition of renewable hydrogen in the Renewable
Energy Directive II of the European Union.

Scope: Almost all existing and proposed certification systems cover directemissions (Scope 1) and indirect emissions associated with the generation ofelectricity, heating/cooling, or steam purchased for own consumption (Scope 2).
Most frameworks also include indirect emissions, such as in the case of hydrogen

The development of an ISO standard takes several years. To provide a reference in the interim, the ISO is developing a
Draft Technical Specification to measure the emissions intensity of hydrogen production, aiming for publication in 2024.
11
The impact of transport emissions is illustrated in Box 2.3.

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10

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Production pathways: Certification systems or regulatory frameworks may limit
the eligible technology and fuel options for hydrogen production. The Green
Hydrogen Standard, for example, requires electrolysis using renewable electricity,while the UK Low Carbon Hydrogen Standard lists electrolysis, natural gas with
CCUS and production from biomass and waste as production options. The French
certification scheme currently under development does not include constraints ontechnology choice.

Hydrogen products: Most certification systems to date consider only the
production of hydrogen (i.e. in form of H2). A few systems and regulations, suchas the EU Taxonomy or RED II, also include hydrogen-based fuels.



Demand sectors: In some cases, certification is linked to sector-specificregulation. The Low Carbon Fuel Standard in California and the UK Renewable
Transport Fuel Obligation are limited to the transport sector. Most of the existingand proposed systems, however, are not tied to a specific demand sector.

Chain of custody model: This determines the requirements for tracking andtracing product attributes along the supply chain. There are two types of chain ofcustody models commonly used in certification systems. In a book-and-claim
model, the producer delivers a product meeting certain environmental criteria to
the market, e.g. hydrogen below a certain emissions intensity threshold, and at
the same time, books an equivalent amount in a certificate platform. Buyers of the
product can acquire a certificate and thus claim that an equivalent amount of the
product purchased meets the environmental requirements. This model allows
certificates to be traded separately from the physical product, thus providing
flexibility, but does not ensure any physical tracking of the product. Examples are
CertifHy and the Low Carbon Fuel Standard in California. The mass balancing
model links the certificate to the respective physical delivery of the product. The
mass of the product is accounted for by tracking the mass at the input and output
sides of the delivery steps involved, which provides some traceability of thephysical product. Compliant and non-compliant products can be mixed, but
operators are required to monitor and record the inputs of compliant and non-

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production from natural gas, the upstream methane and CO2 emissions from gas
production, and midstream emissions from transporting and storing the naturalgas. The systems that cover the use of fossil fuels for hydrogen production also
generally include the emissions associated with transporting and storing thecaptured CO2 (e.g. indirect emissions from electricity use). Emissions from the
manufacture of machinery and equipment are typically not included (partial
Scope 3), which is also reflected in the IPHE methodology. While these embedded
emissions can affect the emissions intensity of hydrogen production, particularlyin the near term, indirect emissions from material production processes, such asaluminium, cement, copper or steel, are expected to decline in the medium andlong term with increasing efforts to decarbonise the energy system. As a result,the emissions impact of electricity generation from wind, solar photovoltaic,hydropower and geothermal energy in the emissions intensity of hydrogenproduction is assumed to be zero.

Towards hydrogen definitions based on
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Defining hydrogen according to
its emissions intensity

compliant inputs into their operation, so that equivalent parts of the outputs canbe regarded as compliant products. RED II refers to mass balancing as a tracking
model.



Emissions intensity levels: Most certification systems require the emissions
intensity level, i.e. the specific GHG emissions per unit of hydrogen, to fall below
certain levels to qualify for a label or to meet the requirements of a regulation.
Other schemes, such as the planned Guarantee of Origin certificate scheme,
certify the emissions intensity without any threshold levels.



Additional sustainability criteria considered: Certification systems can also
include further sustainability criteria, such as other environmental or social
aspects. The EU Taxonomy, for example, lists water impact, air pollution andbiodiversity as additional criteria.
Scope and system boundaries for emissions accounting schemes

IEA. CC BY 4.0.
Notes: LH2 = liquefied hydrogen; NH3 = ammonia; LOHC = liquid organic hydrogen carrier.

The emissions intensity of hydrogenproduction routes

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A common and robust methodology for determining the emissions intensity ofhydrogen, including common system boundaries and scope of emissions, iscritical to ensure comparability between intensity levels in different certification
systems and regulatory frameworks. The analysis and discussion in this reportapplies the IPHE methodology (Scope 1, 2 and partial Scope 3 emissions) andfocuses on the production of hydrogen by using a well-to-gate system boundary.
Other hydrogen supply chain steps, such as the conversion of hydrogen into otherhydrogen carriers, the transport of hydrogen and hydrogen carriers (as in the case

Towards hydrogen definitions based on
their emissions intensity

Defining hydrogen according to
its emissions intensityof international trade), and the reconversion of hydrogen carriers back intohydrogen are important steps that should be included to fully assess the GHG
impact of hydrogen supply chains. The analysis that follows focuses on production
to support the definition of a proposed international emissions accounting system
for the production of hydrogen. The IPHE has already developed a methodology
to assess the emission impact of hydrogen conditioning, i.e. conversion andreconversion. The methodology for assessing the emission impact of transportinghydrogen and hydrogen carriers is still under development by the IPHE. Some
information on the emission impact of ammonia production is provided in Box 2.3,
while Box 2.4 illustrates the potential impact of transporting hydrogen, ammonia
and hydrogen-based fuels by ship or pipeline. In the following text, the IPHE
methodology is used to illustrate the emissions intensity of different hydrogenproduction routes today and for 2030.

Overview of different hydrogen production routes
The emissions associated with the production of hydrogen can vary significantly
between production routes, depending on the fuel, technology and the rate at
which CCS 12 is applied (Figure 2.2). In addition to direct emissions occurring in
the production of hydrogen, indirect emissions from the production, conversion
and transport of the required input fuels, such as natural gas or electricity, canaffect the overall emissions associated with the production of hydrogen.
Natural gas is today the main source of hydrogen production globally, accountingfor 62% of production. The direct emissions of hydrogen production from natural
gas without CCS using steam methane reforming (SMR) are around
9 kg CO2-eq/kg H2. Further emissions occur in the production, processing andtransport of natural gas, either in the form of methane emissions 13 from venting or
leakages, or as CO2 emissions from flaring methane at gas fields or linked to theenergy being used to produce and transport natural gas (e.g. emissions linked tothe electricity for compressing natural gas).
Upstream and midstream emissions for natural gas can vary widely between
natural gas basins and countries, reflecting different production practices andemission mitigation efforts. The application of best practices to avoid emissions
from natural gas production, such as in Norway, limits the combined methane andCO2 emissions to 4.5 kilogramme CO2 equivalent per gigajoule of produced
natural gas (kg CO2-eq/GJNG), of which 0.8 kg CO2-eq/GJNG are methane
emissions and 3.7 kg CO2-eq/GJNG CO2 emissions, mainly from energy use during
gas production and transport. These upstream and midstream emissions are in

For the analysis in this chapter, only carbon capture and storage (CCS) has been considered. The IPHE methodology does
not consider carbon capture and utilisation due to lack of consensus between government and industry whether the CO2
emissions for the CO2 used should be allocated to the producer of hydrogen or transferred to the end user.
13
One tonne of methane is considered to be equivalent to 25 tonnes of CO2 based on the 100-year global warming potentialfrom the Intergovernmental Panel on Climate Change (IPCC) Fourth Assessment Report.

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12

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Defining hydrogen according to
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addition to the direct CO2 emissions of 56 kg CO2-eq/GJNG, created when burning
the natural gas without CCS. Upstream and midstream emissions from natural gas
supply can be much higher in other gas production regions in the world, reachingfor example 27 kg CO2-eq/GJNG in the Caspian region (around half of the directemissions of the unabated use of natural gas). More than three-quarters of these
upstream and midstream emissions are methane emissions from venting andleakages during gas production and transport. The global median upstream andmidstream emissions from gas production today are around 15 kg CO2-eq/GJNG.
Using this median value for the upstream and midstream emissions results inadditional emissions of 2.4 kg CO2-eq/kg H2, and in total emissions of 11 kg CO2eq/kg H2 for the SMR production route from natural gas without CCS. Applying
CCS to the various direct CO2 sources at the SMR hydrogen plant can reduce thedirect emissions to 0.7 kg CO2-eq/kg H2 (capture rate 93%); total emissions
increase to 1.5-6.2 kg CO2-eq/kg H2 when including the upper and lower end of
global upstream and midstream emissions for natural gas supply today.
Coal accounts for around a fifth of global hydrogen production today, mainly basedin China. Hydrogen production from coal gasification without CCS results in total
emissions of 22-26 kg CO2-eq/kg H2, depending on the upstream and midstream
emissions for coal mining, processing and transport, which range between 623 kg CO2-eq/GJcoal with a median of 8 kg CO2-eq/GJcoal. More than 80% of theemissions intensity of hydrogen production from coal is from direct emissions at
the production plant and less than 20% is linked to coal mining, processing andtransport. Applying CCS with a total capture rate of 93% reduces the emissions
intensity of the coal pathway to 2.6-6.3 kg CO2-eq/kg H2, a range similar to that ofnatural gas SMR with CCS.
The emissions from water electrolysis are determined by the upstream andmidstream emissions of electricity generation. Using the current average global
CO2 intensity of 460 g CO2-eq/kWh results in an emissions intensity for hydrogenof 24 kg CO2-eq/kg H2, similar to the emissions for hydrogen from unabated coal,
but can be as low as 0.5 kg CO2-eq/kg H2 in a country such as Sweden, which has
one of the lowest emission factors for grid electricity production in the world today(10 g CO2-eq/kWh).
Nuclear electricity can be another source for hydrogen production. Although thedirect emissions of a nuclear power plant are zero, the nuclear fuel cycle ofuranium mining, conversion, enrichment and fuel fabrication results in emissionsof 2.4-6.8 g CO2-eq/kWh. Taking into account these emissions, the emissions
intensity of hydrogen production from nuclear electricity is in the range of
0.1-0.3 kg CO2-eq/kg H2.

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Following the IPHE methodology, renewable electricity from wind, solar PV,
hydropower and geothermal energy has zero upstream and direct emissions, so
the resulting emissions for water electrolysers using these forms of renewableelectricity is also zero (Box 2.2).

Towards hydrogen definitions based on
their emissions intensity

Defining hydrogen according to
its emissions intensity

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

IEA. CC BY 4.0.

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Notes: BAT = best available technology; CCS = carbon capture and storage; SMR = steam methane reforming; POx =partial oxidation; Median upstr. emis. = global median value of upstream and midstream emissions in 2021; BAT upstr.
emis. = best available technology today to address upstream and midstream emissions.
Upstream and midstream emissions include CO2 and methane emissions occurring during the extraction, processing, andsupply of fuels (coal, natural gas) or production, processing, and transport of biomass. Error bars for natural gas and coal
represent the impact of the observed range of upstream and midstream emissions today on emissions intensities. For
natural gas, the lower bound corresponds to best available technology today (4.5 kg CO2-eq/GJ), and the upper bound to
the 95% percentile of the world range (28 kg CO2-eq/GJ). For coal, the lower bound corresponds to the 5% percentile(6 kg CO2-eq/GJ) and the upper bound to the 95% percentile (23 kg CO2-eq/GJ) of global upstream and midstream
emissions of coal supply. The 2021 world grid average is based on a generation-weighted global average of the gridelectricity intensity, with the error bars representing the 10% percentile (50 g CO2-eq/kWh) and 90% percentile(700 g CO2-eq/kWh) across countries. The grid electricity intensities include direct CO2, CH4 and N2O emissions at thepower plants, but not upstream and midstream emissions for the fuels used in the power plants. Dashed lines refer to theembedded emissions occurring during the production of onshore wind turbines (12 g CO2-eq/kWh) and solar PV systems(27 g CO2-eq/kWh). These embedded emissions are not included in the IPHE methodology and shown here only forillustrative purposes.
Electrolysis refers to low-temperature water electrolysis with an assumed overall electricity demand of 50 kWh/kg H2,
including compression to 30 bar.
Hydrogen production from natural gas via SMR is based on 44.5 kWh/kg H2 for natural gas in the case of no CO2 capture,on 45.0 kWh/kg H2 for natural gas in the case of 60% capture rate, and on 49 kWh/kg H2 for natural gas and 0.8 kWh/kg H2
for electricity in the case of a 93% capture rate. Hydrogen production from natural gas via POx is based on demands of
41 kWh/kg H2 for natural gas and 0.6 kWh/kg H2 for electricity in the case of a 99% capture rate.
Hydrogen production from coal is based on gasification, with demands for coal of 57 kWh/kg H2 and for electricity of
0.7 kWh/kg H2 in the case of no CO2 capture, demands for coal of 59 kWh/kg H2 for a CO2 capture rate of 93% anddemands for coal of 60 kWh/kg H2 for a CO2 capture rate of 98%.

Towards hydrogen definitions based on
their emissions intensity

Box 2.2

Defining hydrogen according to
its emissions intensity

Including lifecycle analysis in emissions intensity accounting

Most existing or proposed regulations and certification systems do not take into
account the emissions associated with the manufacturing of the technologies
involved in hydrogen production (e.g. the emissions for manufacturing theelectrolyser and the solar PV system in the case of electrolytic hydrogen produced
from solar PV electricity). The only exception is the French ordinance on hydrogenfrom February 2021 (Ordinance No. 2021-167), which includes lifecycle emissions
gathered in the French Agency for Ecological Transition (ADEME)’s greenhousegas database.
Nonetheless, emissions can arise from the manufacturing of renewable electricity
and hydrogen production technologies. Based on lifecycle analysis, the productionof solar PV modules, for example, is currently associated with emissions of
18-50 g CO2-eq/kWh*, which would result in an emissions intensity of hydrogenproduction of 0.9-2.5 kg CO2-eq/kg H2. In the case of onshore wind, embedded
emissions of 8-16 g CO2-eq/kWh would translate into an emissions intensity of
0.4-0.8 kg CO2-eq/kg H2. A full coverage of all emissions linked to the
manufacturing of technologies is not only limited to electricity generation
technologies, but should also include technologies such as electrolysers or steam
methane reformers. For electrolysers, lifecycle analysis studies indicated that the
impact is rather small, for example 0.13 kg CO2-eq/kg H2 for a proton exchange
membrane electrolyser running 3 000 hours in a year.
A comprehensive lifecycle analysis scope is desirable in principle, but the need toensure that the methodology can be applied in practice may favour a pragmatic
approach, in particular when introducing certification systems and regulatory
frameworks in today’s still nascent hydrogen markets. In addition, lifecycle
inventory data reflecting the actual emissions along the full technology supply
chain – from mining of minerals and material production, to processing andtechnology manufacturing – are not always easily available. This is especially thecase as technologies such as electrolysers, solar PV modules or wind turbine
components are traded between countries, making the analysis of the lifecycle
emissions more complex.
It is also important to note that emissions from material production and technology
manufacturing are likely to be lower in the future than today. The emissions datain lifecycle inventories for the production of materials (e.g. steel, aluminium) andfor the manufacturing processes are often based on today’s energy system.
Notably, this implies the use of today’s emission intensity of electricity generation,
which is set to decline according to IEA scenarios, meaning that in the future theimpact of the indirect emissions from the materials and manufacturing processes
needed for the technologies involved in hydrogen production could be much lower
and less relevant than today.

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*The emission range has been derived from an emission intensity of 42 g CO2-eq/kWh for the production of crystalline
silicon solar PV systems with an annual electricity generation of 975 kWh/kWp. The range is based on an annual
electricity generation of 810 kWh/kWp to 2 300 kWh/kWp, while the central value of 27 g CO2-eq/kWh used in Figure
2.2 is based on annual generation of 1 500 kWh/kWp.

Towards hydrogen definitions based on
their emissions intensity

Defining hydrogen according to
its emissions intensity

For hydrogen production from bioenergy, the direct emissions are also considered
to be zero. Emissions can, however, occur upstream in the bioenergy supply
chains. In the case of using wood chips, these emissions may be
4-18 kg CO2-eq/GJ, resulting in total emissions of 1.0-4.7 kg CO2-eq/kg H2 forhydrogen from biomass gasification. Combining such a gasification plant with CCS
and a capture rate of 95% then results in negative emissions of -16 to -21 kg CO2eq/kg H2 by removing the captured biogenic carbon in the biomass from thenatural carbon cycle.
Similar methods to calculate the emission intensity of hydrogen production canalso be developed for and applied to the production of hydrogen-based fuels suchas ammonia (Box 2.2). The IPHE has developed a methodology for hydrogenconditioning, i.e. the conversion of hydrogen into hydrogen carriers andreconversion back into hydrogen.

Box 2.3

Emissions intensity of ammonia production

Almost all ammonia produced today is used as a feedstock for industrial uses.
Around 70% of global ammonia demand is for the production of mineral nitrogen
fertilisers, while the remaining 30% is spread over a range of industrial
applications, including explosives, synthetic fibres and specialty materials.
Ammonia is produced from nitrogen and hydrogen. The nitrogen is sourced fromthe air, while the hydrogen is sourced from the feedstocks. Producing one tonneof ammonia requires around 180 kg of hydrogen, such that global total productionof ammonia of 190 Mt in 2021 represented approximately 34 Mt of hydrogen
demand.
Today virtually all ammonia is produced from unabated fossil fuels. Worldwide,
about 70% of ammonia is produced from natural gas, and most of the remaining
30% from coal, the latter mainly in China. The production of ammonia from natural
gas without CCS results in emissions of 10-15 kg CO2-eq/kg H2-eq 14, while theemissions intensity from coal is 20-27 kg CO2-eq/kg H2-eq, almost twice as high.
The ranges reflect upstream and midstream emissions of 4.5-28 kg CO2-eq/GJ for
natural gas and 6-23 kg CO2-eq/GJ for coal as well as of 50-700 g CO2-eq/kWh forgrid electricity).

For comparability with hydrogen, the emission intensity for ammonia is expressed here per kg of hydrogen equivalent(kg H2-eq), which corresponds to the hydrogen content of ammonia taking into account conversion losses, i.e. 1 kg NH3
contains 0.18 kg H2.

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Towards hydrogen definitions based on
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Emissions intensities of different ammonia production routes, 2021

IEA. CC BY 4.0.
Notes: CCS = carbon capture and storage. Ammonia production from coal is based on coal gasification, while thenatural gas route uses steam methane reforming (SMR). Coal with partial capture corresponds to a CO2 capture rate of
52%, while full results in a 93% capture rate. For natural gas, partial capture corresponds to 75% capture rate and full
capture to 94%. Error bars reflect range of upstream and midstream emissions for natural gas, coal and biomass
supply.

As for hydrogen production, substantial emissions intensity reductions forammonia can be achieved via electrolysis and the use of natural gas with CCS. In
the electrolytic production pathway, hydrogen produced from electrolysis andnitrogen are inputs to the Haber-Bosch synthesis process to produce ammonia. If
all the energy inputs for the hydrogen and nitrogen production, as well as in theammonia synthesis, are from renewable electricity, the overall emissions intensity
is zero (excluding potential direct emissions from the operation of some renewableenergy technologies as well as their embodied emissions).
Ammonia production from natural gas includes similar process steps to hydrogenproduction from natural gas. Steam methane reformers and a water gas shift
reactor are used to produce a syngas consisting of hydrogen, nitrogen and CO2.
After separating the feedstock CO2, the remaining syngas is used in a HaberBosch synthesis process to produce ammonia. Capturing the feedstock CO2
results in emissions intensities for ammonia production from natural gas with CCS
of 3.5-9.0 kg CO2-eq/kg H2-eq, which corresponds to a capture rate of 75%.
Capturing in addition the CO2 from the natural gas-fired steam boilers reduces theemissions intensity to 1.4-6.6 kg CO2-eq/kg H2-eq and results in an overall capture
rate of 94%.

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Coal gasification with CCS can be another production route for ammonia. Here theair separation unit provides both the oxygen for the coal gasification process andthe nitrogen for the Haber-Bosch synthesis. The emissions intensity of ammonia
production from coal with CCS is in the range of 3-11 kg CO2-eq/kg H2-eq(depending again on the upstream and midstream emissions for coal andelectricity supply).

Towards hydrogen definitions based on
their emissions intensity

Defining hydrogen according to
its emissions intensity

In addition to hydrogen production and conditioning, transport is a further supply
chain step that can impact the emission intensity of the delivered hydrogen. While
the focus of this report is on the emission intensity of hydrogen production, Box 2.4
illustrates the emissions of long-distance transport of hydrogen.

Box 2.4

Emissions from transporting hydrogen

The transport and distribution of hydrogen is an important step in the hydrogen
supply chain and affects the overall greenhouse gas footprint of hydrogen. The
emissions from hydrogen transport are largely linked to the fuel used fortransporting hydrogen and its associated direct and indirect emissions, such as
heavy fuel oil for tankers or electricity for pipeline compressors.
The emissions impact of hydrogen transport by pipeline depends on the emissions
intensity of the electricity used for compression. Transporting hydrogen through a
48-inch pipeline over a distance of 10 000 km requires 3.6 kWh/kg H2 of electricity
for compression, which results in emissions of 0.7 kg CO2-eq/kg H2 whenelectricity with an electricity intensity of 200 g CO2-eq/kWh is used.

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Hydrogen can also be transported by tanker in the form of liquefied hydrogen (LH2),
by converting hydrogen into ammonia or by storing hydrogen in a liquid organichydrogen carrier (LOHC). The transport emissions by tanker will depend on the
shipping fuel, but also on the energy needs and related emissions for theconversion of hydrogen into a carrier at the export port and the reconversion backinto hydrogen at the import port. For LH2, the emissions for liquefaction can be
relatively low, assuming that in case of hydrogen production from renewableelectricity, the renewable electricity can be also used for the liquefaction plant. The
boil-off gas from the LH2 storage cargo tanks can be used as a shipping fuel,meaning that the shipping emissions will depend on the emissions intensity of thetransported hydrogen. For an emissions intensity of 1 kg CO2-eq/kg H2,liquefaction and transport of LH2 over a distance of 10 000 km would result inemission of 0.3 kg CO2-eq/kg H2. Shipping hydrogen as ammonia or LOHC andusing marine fuel oil for the tanker would, for a shipping distance of 10 000 km,
result in emissions of 1.9 kg CO2-eq/kg H2 or 3.8 kg CO2-eq/kg H2 respectively,
including conversion and reconversion. For marine fuel oil, only the direct CO2
emissions from combusting the oil are considered here. If upstream and midstream
emissions for oil production and refining are included, the emissions could bearound 20% higher. In the case that part of the transported ammonia is used as ashipping fuel, the emissions intensity could fall to 1.1 kg CO2-eq/kg H2. For LOHC,
the emissions intensity could be 1.2 kg CO2-eq/kg H2, if a low-emission shipping
fuel with zero direct GHG emissions, such as biofuel, is used.

Towards hydrogen definitions based on
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Defining hydrogen according to
its emissions intensity

These examples illustrate that in addition to hydrogen production, the conditioning
and transport of hydrogen can have a significant impact on the overall emissions
intensity of hydrogen at the delivery point.
Illustrative analysis on emissions of hydrogen transport by tanker including
conversion and reconversion of hydrogen

IEA. CC BY 4.0.
Note: LH2 = liquefied hydrogen; NH3 = ammonia; LOHC = liquid organic hydrogen carrier. Cargo fuel refers to using theshipped cargo as fuel in the case of LH2 and ammonia. Carbon-neutral marine fuel represents a shipping fuel with zero
direct greenhouse gas emissions. For the use of marine fuel oil, the direct emissions are included, but not any
upstream and midstream emissions related to oil production and refining. Emissions include conditioning, i.e. theconversion of hydrogen into other carriers at the export port and the reconversion back into hydrogen at the import port,
but emissions from hydrogen production are not included. The illustrative analysis is based on an emission intensity ofhydrogen production of 1 kg CO2-eq/kg H2, an emission intensity of electricity of 20 g CO2-eq/kWh at the export port
and of 200 g CO2-eq/kWh at the import port.

Emissions of hydrogen from natural gas with CCS
SMR is the dominant technology route for producing hydrogen from natural gas.
Further technology routes are autothermal reforming (ATR) and, though lesswidely deployed and at a lower technology readiness level, partial oxidation (POx)and methane pyrolysis.

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In SMR, natural gas is used both as a fuel to provide steam for the reforming
process and as a feedstock for the hydrogen molecules. Overall, an SMR process
requires around 45 kWh of natural gas per kilogramme of hydrogen being
produced (kWh/kg H2). Capturing the CO2 from the feedstock-related use ofnatural gas is possible at relatively low capture costs, since separating thefeedstock CO2 from the hydrogen is part of the SMR process. This partial captureof the overall CO2 emissions results in an overall capture rate of 60% and inemissions of slightly above 6 kg CO2-eq/kg H2 (using median upstream andmidstream emissions for natural gas supply, Figure 2.3). For reference, theemission factor of natural gas excluding upstream emissions is 56 kg CO2/GJ,

Towards hydrogen definitions based on
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Defining hydrogen according to
its emissions intensity

which corresponds to 7 kg CO2-eq/kg H2. In other words, burning the same energy
amount of natural gas directly in a boiler or turbine would generate slightly more
emissions than burning hydrogen being generated from natural gas via SMR withpartial CO2 capture, assuming the same conversion efficiency for burninghydrogen and natural gas. In the near term, such technologies that allow a partial
reduction of the emissions footprint of existing unabated fossil hydrogenproduction with less than 7 kg CO2-eq/kg H2 can therefore provide emissions
benefits, contributing to CO2 emission reduction.
At an SMR plant, it is also possible to capture the CO2 resulting from the use ofnatural gas as fuel for steam production. The capture costs are higher comparedwith capturing the feedstock-related CO2, as the flue gas stream from using natural
gas as a fuel is more diluted. Capturing both sources of CO2 results in capture
rates of 93% for SMR and emissions of 1.5-6.2 kg CO2-eq/kg H2 (with the range
again depending on the upstream and midstream emissions of natural gas
supply).
Impact of capture rate and upstream and midstream emissions on theemissions intensity of hydrogen production from natural gas with carbon
capture and storage

IEA. CC BY 4.0.
Notes: SMR partial capture = steam methane reforming with a 60% capture rate; SMR full capture = steam methane
reforming with a 93% capture rate; POx = partial oxidation with a 99% capture rate; “Median 2021” = global median
upstream and midstream emissions for natural gas in 2021; “Range 2021” = global range of global upstream andmidstream emissions for natural gas in 2021; “Best available technology” = lowest level of upstream and midstream
emissions being achieved today; “Median 2030” = global median upstream and midstream emissions for natural gas in
2030, which are 50% lower than today by combining a 75% reduction in methane emissions with further mitigation efforts in
upstream and midstream CO2 emissions.See notes of Figure 2.2 for further assumptions.

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Autothermal reforming (ATR) is an alternative technology in which the required
heat is produced in the reformer itself. This means that all the CO2 is produced
inside the reactor. ATR uses oxygen instead of steam, which requires electricity(rather than steam) as its fuel input. In combination with CO2 capture, ATR
requires 47 kWh/kg H2 of natural gas and 3.7 kWh/kg H2 of electricity and canTowards hydrogen definitions based on
their emissions intensity

Defining hydrogen according to
its emissions intensity

achieve capture rates of 93-94%. ATR technology without CO2 capture is alreadyused today in the chemical industry, but no ATR plant with CCS is in operation
yet, though several projects are planned.
The POx technology has traditionally been deployed where it is possible to use
low-value waste products or heavy feedstocks to produce hydrogen 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 hydrogen from natural
gas with CCS. Several CCS projects based on POx are under development. The
relatively high CO2 concentration allows for capture of the CO2 from the synthesis
gas stream. The achieved capture rates can be up to 99%, higher than SMR,
where part of the CO2 is captured from more diluted flue gas streams. The POx
process requires around 41 kWh/kg H2 of natural gas and 0.6 kWh/kg H2 ofelectricity, which results in an emissions intensity of 0.8-4.6 kg CO2-eq/kg H2.
Given the 99% capture rate, the bulk of emissions is linked to upstream andmidstream emissions of natural gas supply.
Methane pyrolysis is the process of converting methane into gaseous hydrogenand solid carbon (e.g. carbon black, graphite), without creating any direct CO2
emissions. The reaction requires relatively high temperatures (>600°C), which canbe achieved through conventional means (e.g. electrical heaters) or using plasma.
Per unit of hydrogen produced, methane pyrolysis uses around three times lesselectricity than electrolysis; however, it requires more natural gas than SMR.
Depending on the technology variant, methane pyrolysis using plasma requires
62 kWh/kg H2 of natural gas and 14 kWh/kg H2 of electricity. This results inemissions of around 2-16 kg CO2-eq/kg H2 (depending on the upstream andmidstream emissions for natural gas and electricity supply).

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At high capture rates, the upstream and midstream emissions from natural gas
production, processing and transport become the dominant component of theremaining GHG emissions from hydrogen production from natural gas with CCS.
Assuming the global median upstream and midstream emissions intensity of
15 kg CO2-eq/GJNG and a capture rate of 93% corresponds to an emissions
intensity of hydrogen production from natural gas with CCS of
3.7 kg CO2-eq/kg H2, of which more than 70% is linked to the upstream andmidstream emissions of natural gas supply. The relatively low emissions of natural
gas production achieved in some countries today can serve as an example of how
much upstream and midstream emissions can be reduced using best available
technology (Figure 2.3). Combining such low upstream and midstream emissions(4.5 kg CO2-eq/GJNG) with high capture rates results in emissions of
1.5 kg CO2-eq/kg H2, less than half the level when assuming current mean global
upstream and midstream emissions, and even 75% below the level whenassuming the higher range of upstream and midstream emissions today(28 kg CO2-eq/GJNG).

Towards hydrogen definitions based on
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Defining hydrogen according to
its emissions intensity

Technologies and measures to reduce methane emissions from gas operations
are already available and have been deployed in multiple locations around theworld. Key examples include leak detection and repair campaigns, installingemissions control devices, and replacing components that emit methane in theirnormal operations. Many of the measures are already cost effective today,
because the costs of deployment are less than the market value of the methanethat is captured and can be sold. IEA analysis suggests that at the average gas
prices seen from 2017 to 2021, around 40% of the methane emissions from oil
and gas operations could be reduced at no net cost using existing technologies.
Reducing methane emissions is a widely recognised climate priority that is
supported by more than 150 countries under the Global Methane Pledge
announced at the United Nations Climate Change Conference (COP26) in 2021.
The Pledge aims to reduce global anthropogenic methane emissions by at least
30% from 2020 levels by 2030. Reducing methane emissions from fossil fueloperations by 75%, as envisioned in the IEA’s NZE Scenario, can meet asignificant part of the Global Methane Pledge. Combining the 75% reduction inmethane emissions with further mitigation efforts in upstream and midstream CO2
emissions results in a 50% overall reduction in the global upstream and midstream
emissions compared to today. Based on these reductions, the emissions intensityof hydrogen production from SMR with a 93% capture rate could be reduced bymore than 40% compared to the median today, resulting in 2.2 kg CO2-eq/kg H2.

Emissions of hydrogen from water electrolysis
A large number of water electrolyser projects has been announced so far,potentially resulting – if all projects are realised – in a globally installed capacity of
up to 240 GW by 2030. This is a very similar level of deployment as that required
to meet countries’ climate ambitions in the APS. Some of these projects are
directly connected to renewable electricity sources, others are connected to theelectricity grid or use a mixture of electricity from dedicated renewable electricity
plants and the grid.
In the case of using electricity from directly connected renewable plants, theemissions are assumed to be zero, while the emission impact of using electricity
from the grid depends on the technology and fuel mix in the electricity system andits operation (Figure 2.4). 15 If solely grid electricity is being used, reaching low

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15
In addition, the efficiency of the electrolyser influences the overall emission impact when using grid electricity. Alkaline
and proton exchange membrane electrolyser are the two main commercially available electrolyser technologies today. The
electricity consumption of the two electrolyser technologies is quite similar today, at around 52 kWh/kg H2. Additional
electricity is required to supply and purify the necessary water. These electricity needs are, however, very small, with up to
0.6 kWh/kg H2 in the case of using seawater desalination and pumping the water over a 500 km distance. Solid oxide
electrolysis is a third technology (which is however less mature and at demonstration stage) which operates at higher
temperatures than alkaline or proton exchange membrane electrolysers using steam as water input. As a consequence, theelectricity requirements are lower, with 40 kWh/kg H2, but additional energy in the form of steam of 10 kWh/kg H2 isrequired.

Towards hydrogen definitions based on
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Defining hydrogen according to
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emissions intensities for hydrogen also requires a low emissions intensity of theelectricity grid. Limiting, for example, the emissions of hydrogen production to
2 kg CO2-eq/kg H2 requires the emissions intensity of grid electricity to be
40 g CO2-eq/kWh or lower. Within the European Union, for example, only Sweden
currently has such a low emissions intensity of its electricity grid, with 10 g CO2eq/kWh. For 1 kg CO2-eq/kg H2, the threshold falls to 20 g CO2-eq/kWh, notreached by any of the G7 members (if not taking into account Sweden as part of
the European Union).
Impact of the emissions intensity of grid electricity and of the mix of gridand dedicated renewable electricity on the emissions intensity of hydrogen

IEA. CC BY 4.0.
Notes: APS = Announced Pledges Scenario; NZE = Net Zero Emissions by 2050 Scenario; SMR = steam methane
reforming. Based on electricity consumption for the electrolyser of 50 kWh/kg H2 or 67% conversion efficiency in lower
heating value terms. Intensities for individual countries refer to the year 2020.

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Using grid electricity during peak load hours could mean that the additional
electricity demand for hydrogen production is covered by natural gas-fired power
plants, resulting in emissions of 24-32 kg CO2-eq/kg H2 (depending on theTowards hydrogen definitions based on
their emissions intensity

Defining hydrogen according to
its emissions intensity

upstream and midstream emissions of natural gas supply), more than twice ashigh as the emissions from direct hydrogen production from natural gas without
CCS. If the electricity demand for water electrolysis is covered during baseload
hours, it could come from generation plants – depending on the design of theelectricity system – with almost zero direct emissions, such as hydro or nuclear
power, but also from plants with significant emissions, such as coal-fired power
plants with resulting emissions of 50-57 kg CO2-eq/kg H2. If electricity is used attimes when there is a surplus supply of electricity from solar PV or wind, the useof this otherwise curtailed electricity will result in zero direct emissions.
Given the very different outcomes of using grid electricity, many certification
systems and regulations include provisions to ensure that additional electricity
demand for hydrogen production does not lead to an increase in fossil-based
electricity generation or weaken the operation of the electricity system. This canbe achieved by additionality requirements, as well as imposing conditions related
to temporal and geographic correlation as part of the chain of custody:Additionality refers to the requirement that the electricity used for hydrogenproduction must come from new generation capacity, rather than relying on
renewable electricity from existing plants that is already being used to decarboniseelectricity consumption in other sectors. Power purchasing agreements can linkelectricity demand for hydrogen production to new renewable (or nuclear)electricity generation.

Temporal correlation or synchronisation between electricity use for hydrogenproduction and renewable (or nuclear) electricity generation can be achieved by
imposing further constraints to balance demand and generation over specified
time periods (e.g. hourly, monthly, quarters of a year).



Geographic correlation should avoid the creation of potential bottlenecks in theelectricity grid between supply and demand locations. For example, in the case ofpre-existing grid congestion, the renewable electricity unit and the hydrogenproduction plant should be located on the same side of potential bottlenecks.

In the amendments to the Renewable Energy Directive II as part of the Fit for 55
package, the European Union has detailed in a delegated act 16 requirements for
additionality, temporal and geographic correlation for electricity used in the
production of hydrogen and derived fuels. Other certification systems andregulations also include requirements for additionality, temporal or geographic
correlation (e.g. H2Global, UK Low Carbon Hydrogen Standard, Climate Bonds
Standard & Certification Scheme, GH2 Green Hydrogen Standard, TÜV SÜD
Standard CMS 70).

As of April 2023, the delegated act still needs to be approved by the European Parliament and the Council of the European
Union to enter into force.

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Emissions intensity and costs of hydrogenproduction in IEA scenarios
Hydrogen today is almost entirely produced from unabated fossil fuels, resulting
in direct CO2 emissions of more than 900 Mt CO2. Hydrogen production fromelectrolysers using renewable electricity and from fossil fuels in combination withCCS covers less than 1% of global production. The higher costs of low-emissionhydrogen production today compared to the production from unabated fossil fuels
is a key factor in this limited share of global production. With countries making
efforts to reach their climate pledges, however, this situation can change in the
future, leading to wider deployment of low-emission hydrogen production
technologies and a reduction in the emissions intensity of hydrogen. Policy
measures to support the uptake of low-emission hydrogen will also lead to further
cost reductions for low-emission hydrogen, driven, for example, by cost reductions
for electrolysers and renewable electricity. The following sections illustrate thesepotential developments of emission intensity and costs using the IEA scenarios.

Emissions intensity of hydrogen production
The average emissions intensity of global hydrogen production today is12-13 kg CO2-eq/kg H2, with the range reflecting different allocation methods forby-product hydrogen production in refineries (see Box 2.5). In the STEPS, theglobal average emissions intensity of hydrogen production declines slightly to
11-13 kg CO2-eq/kg H2 by 2030 and to 10-11 kg CO2-eq/kg H2 by 2050, thanks to
reductions in upstream and midstream emissions of natural gas supply and thedeployment of low-emission hydrogen technologies (Figure 2.5).

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In the APS, the global average emissions intensity falls by 2030 to around
9-10 kg CO2-eq/kg H2. By 2050, the emissions intensity falls to
2.7-3.0 kg CO2-eq/kg H2. In the NZE Scenario, the global average intensity
reaches 6-7 kg CO2-eq/kg H2 by 2030 and 0.8-0.9 kg CO2-eq/kg H2 by 2050. In allcases, these values are to be understood as average intensities of differenthydrogen production routes. The average of 0.8-0.9 kg CO2-eq/kg H2 by 2050 in
the NZE Scenario, for example, reflects the production-weighted average, whichis largely influenced by hydrogen being produced from electrolysis (which has azero emissions intensity in 2050), and the production of hydrogen from natural gas
with CCS with an average intensity of 1.8 kg CO2-eq/kg H2.

Towards hydrogen definitions based on
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Defining hydrogen according to
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Emissions intensity for hydrogen production by scenario, 2021-2050

IEA. CC BY 4.0.
Notes: NZE = Net Zero Emissions by 2050 Scenario; APS = Announced Pledges Scenario; STEPS = Stated Policies
Scenario, NG = natural gas; CCS = carbon capture and storage; SMR = steam methane reforming; POx = partial oxidation;
CR = capture rate. Ranges for scenario intensities reflect different emission allocation of by-product hydrogen production in
refineries (Box 2.5).

Box 2.5

Greenhouse gas emissions of by-product hydrogen

Most hydrogen demand today is met by dedicated hydrogen production, meaningthat production processes are designed specifically to produce hydrogen as a main
product to meet certain demand. However, around 18% of global hydrogen use
today is hydrogen that is produced as a by-product from industrial and refinery
processes, such as naphtha reforming, steam crackers and chlor-alkali
electrolysis.
Hydrogen is one of many outputs obtained in these processes. Therefore, there isa need to allocate emissions between hydrogen and the other co-products
obtained. Several methodologies have been proposed to calculate the emissions
intensity of hydrogen generated as a by-product from industrial processes:
Allocation based on the physical constants of the co-products, such asenergy content, mass or molar fractions. Allocation based on the energy
content of the products (normally their lower heating value) can be suitable forprocesses where all or most of the co-products contain energy, like in steam
crackers, but can be problematic for processes in which the other co-products
do not contain energy (like chlorine and oxygen in the chlor-alkali process).

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Allocation based on mass or molar fraction distributions can be less suitablefor hydrogen since it has a very high energy to mass ratio compared to theother co-products, resulting in a very extreme emissions intensity (too low formass allocation and too high for molar fraction allocation).


Allocation based on system expansion to include functions related to otherco-products. In this system, co-products are considered alternatives to otherproducts on the market and can be assigned the same environmental burden
as the products they replace. The application of this system requires a goodunderstanding of the market for the co-products and the products that they
replace, as well as the effects of this substitution in the industries affected. Thissystem can be easily applied if the co-products replace a limited number of
products, but can result in high variability if the co-products can replace a large
number of products.

Allocation based on the economic value of the products: this type ofallocation is commonly based on the revenue that can be obtained for each of
the co-products. An advantage of this methodology is that it can reflect theintention of operating a process and allocate varied amounts for the outputs
obtained based on their economic value. However, market prices tend to varyover time and between regions. Moreover, in the case of hydrogen, there are
currently no open markets, resulting in a lack of high-quality information about
its market price that could be used to apply this methodology.

Results of various emission allocation methods for hydrogen as by-productfrom the chlor-alkali industry
Allocation method

Chlor-alkali(kg CO2-eq/kg H2)

Steam cracking(kg CO2-eq/kg H2)

Energy-based (physical constants)

33.8

2.6

Mass-based (physical constants)

1.4

1.0-3.0

Molar-based (physical constants)

16.1

-

Substitution (system expansion)

6.8-16.1

8.5-10.0

Market-value based (economic value)

4.1-7.1

1.0-3.0

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The IPHE, in its methodology for determining the GHG emissions associated withthe production of hydrogen, provided a series of values for the emissions intensityof by-product hydrogen in the chlor-alkali process and steam crackers based on
all these allocation methods and examples from different national markets.

Towards hydrogen definitions based on
their emissions intensity

Defining hydrogen according to
its emissions intensity

Costs of hydrogen production
Today low-emission hydrogen production is still more expensive than fromunabated natural gas and coal (see chapter Hydrogen and its derivatives in a net
zero energy system). For example, producing hydrogen from natural gas without
CCS costs around USD 1-2.5/kg H2 (depending on the natural gas price), whilecosts for hydrogen production from renewable electricity at sites with good solar
PV or onshore wind resources are in the range of USD 3-4/kg H2. These higher
costs are a barrier for the uptake of low-emission hydrogen. The relatively young
age of existing hydrogen production plants in the chemical sector today, at around
10-15 years compared with a technical lifetime of 30 years, may further slow down
the uptake of low-emission hydrogen production technologies. However,retrofitting existing SMR plants with CCS can be a near-term option. Even if these
retrofits focus only on the high-concentration, process-related CO2 stream of an
SMR plant for cost reasons, they can reduce emissions by around 50% compared
to an unabated plant, while only increasing production costs by around 18%. Thispartial capture of CO2 emissions still results in emissions of 6 kg CO2-eq/kg H2,
but would allow for continued use of some of the younger existing plants in thetransition to a clean energy system.
By 2030, compared to hydrogen and ammonia produced from fossil fuels with
CCUS, steep declines in the cost of hydrogen and ammonia produced fromrenewables are expected due to further cost reductions in renewable electricity,
as well as technology and cost improvements for electrolysers. However, the costsof producing hydrogen and ammonia using renewable electricity will vary between
different regions and countries, depending on local renewable resource
characteristics and potential. The low-emission production and supply option forhydrogen and ammonia will depend on local circumstances and opportunities,
taking into account factors such as emissions intensity, supply volumes andaffordability.
The production of hydrogen with low-emission technologies can becomecompetitive with unabated routes in the short term in locations with abundant lowcost renewable electricity resources, or in regions with access to cheap fossil fuels
and CO2 storage to produce hydrogen from fossil fuels in combination with CCS.
In the IEA’s Stated Policies Scenario (STEPS), which reflects the policies thathave been adopted or announced to date, global hydrogen demand by 2030 is stilllargely covered by production from unabated fossil fuels (Figure 2.6). The uptakeof low-emission hydrogen production technologies remains limited, and where
they are deployed, they mainly replace existing unabated production in the refining
sector and the chemical industry.

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In the APS, which assumes that all of the climate pledges announced by eachcountry are met on time and in full, hydrogen demand from existing applications

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initially continues to be met by unabated fossil fuel-based production, which canachieve the lowest production costs in many regions (mostly outside of G7
members). Over time, however, the production of hydrogen with low-emission
technologies becomes cheaper than unabated fossil fuel-based production insome regions, as the cost of low-emission production falls, resulting in thereplacement of some emission-intensive production assets. In addition, lowemission hydrogen and ammonia satisfies rising demand in new uses, such as insteel production or long-distance transport. The uptake is even larger in the NZE
Scenario, driven by faster cost reductions in renewables and electrolysers andpolicies such as CO2 pricing. In the APS and NZE scenarios, hydrogen demandin new applications is almost exclusively met by hydrogen produced with lowemission technologies, driven by decarbonisation goals. Small fractions ofhydrogen demand are met with hydrogen produced via electrolysis powered withgrid electricity, which is used to complement the electricity supply from dedicatedrenewable electricity generation and to increase the operating hours and loadfactors of electrolysers.

Towards hydrogen definitions based on
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Global and G7 hydrogen production cost profile to meet hydrogen demandby scenario, 2021 and 2030

Towards hydrogen definitions based on
their emissions intensity

Defining hydrogen according to
its emissions intensity

IEA. CC BY 4.0.

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Notes: STEPS = Stated Policies Scenario; APS = Announced Pledges Scenario; NZE = Net Zero Emissions by 2050
Scenario; RoW = Rest of World; CCUS = carbon capture, utilisation and storage. The figure excludes by-product hydrogenproduced in refineries and petrochemical plants and used in oil refining. The x-axis refers to the production volumes in the
scenarios. The labels above the supply cost curves indicate the emissions intensity of hydrogen production in
kg CO2-eq/kg H2.

Towards hydrogen definitions based on
their emissions intensity

Towards an international emissions accounting
framework to define hydrogen

Towards an internationalemissions accounting framework
to define hydrogen
There is currently no globally agreed framework or standard to define hydrogenbased on the emissions associated with its production. An internationally agreed
emissions accounting framework that provides common definitions for hydrogenproduction can bring much-needed transparency to facilitate adoption and scaleup. A common framework can enable investment and trade by facilitating market
and regulatory interoperability. Without such a framework, producers andconsumers face challenges in assessing the technical criteria that allow theirproducts to meet regulatory requirements, which can increase investment risks
and lead to a fragmented market.
In this report, the IEA uses the International Partnership for Hydrogen and Fuel
Cells in the Economy (IPHE) methodology for calculating the greenhouse gas(GHG) emissions intensity of different hydrogen production routes. This state-ofthe-art methodology will serve as the basis for the first international standard to
calculate the GHG emissions of hydrogen supply. This is currently underdevelopment by the International Organization for Standardization (ISO), although
the methodology still needs to be finalised to incorporate elements related tohydrogen transport, and other methodological issues are likely to be consideredin future updates.

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There are two major benefits of using an internationally agreed methodology forcalculating emissions intensity. Firstly, terminologies that use colours or qualifiers(such as “sustainable”, “low-carbon” etc.) often mask a wide range of different
emissions intensities, depending, for example, on the source of electricity, the CO2
capture rate or the emissions associated with upstream fossil fuel production.
Numerical values that reflect emissions intensities and that can be calculated
directly for a specific production route are more transparent and allow project
developers to assess regulatory compliance efficiently. Secondly, the use of one
common methodology to calculate emissions intensities directly enables a certain
level of interoperability of different regulations. Countries may have differing
priorities in terms of production routes or other additional criteria, but the use of
one common methodology can bring transparency to the GHG emission
requirements for different countries.

Towards hydrogen definitions based on
their emissions intensity

Towards an international emissions accounting
framework to define hydrogen

Regulatory efforts to establish the expected emissions intensity of hydrogen are
already underway or established in many countries. Their scope and themethodologies used differ, which can create barriers for investors inunderstanding their interoperability. This chapter reviews the opportunity thatwould be created by establishing a common international accounting frameworkand explores the elements that would need to be addressed to enable smooth
implementation in regulatory frameworks and certification schemes.

Considerations for an international
accounting framework
Similarities and differences in existing certification
systems and regulations
Several certification systems and regulatory frameworks for hydrogen exist
already or are under development (Table 3.1). They have some commonalities,
but also significant divergences. The majority of the regulations and certification
systems focus on the production of hydrogen (i.e. hydrogen in the form of H2 andnot ammonia and hydrogen-based fuels) and emissions within well-to-gate systemboundaries. Systems and regulations that include the transport of hydrogen (wellto-point of delivery or well-to-wheel, such as H2Global or the Renewable Energy
Directive II) often also consider hydrogen-based fuels, which are particularly
attractive for long-distance transport and trade of hydrogen.
In most cases, direct and indirect emissions of electricity and heat generation, as
well as upstream and midstream emissions for fuel production and transport (e.g.
for coal, natural gas and biomass) are included, while indirect emissions
associated with the manufacturing of technologies and their embedded materials
are excluded (Scope 1, 2 and partial Scope 3). This emission scope is consistent
with that of the IPHE methodology. The only exception is the French ordinance onhydrogen from February 2021, which includes the emissions gathered in
ADEME’s carbon database.

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A comprehensive lifecycle analysis scope is desirable in principle, but the need toensure that the methodology can be applied in practice may favour a pragmatic
approach, in particular when introducing certification systems and regulatory
frameworks in today’s still nascent hydrogen markets. Some certification systems
and regulations require hydrogen produced from renewable electricity, but some,such as the UK Low Carbon Hydrogen Standard or the US Clean Hydrogen
Production Tax Credit, allow a broader portfolio of fuels and technologies for
producing hydrogen. The imposed emissions intensity levels for well-to-gate
system boundaries vary widely between certification systems and regulations,reflecting different regional circumstances. For systems with a well-to-gate

Towards hydrogen definitions based on
their emissions intensity

Towards an international emissions accounting
framework to define hydrogenboundary, the range goes from 0.45 kilogramme of CO2 equivalent per
kilogramme of hydrogen (kg CO2-equivalent (eq)/kg H2) in the US Clean Hydrogen
Production Tax Credit to 14.5 kg CO2-eq/kg H2 in China Hydrogen Alliance’s
standard. 17This variability in criteria, scope and methodologies increases regulatory andcertification barriers faced by project developers, who need to undertake ad-hoc
certification process for each country where they want to access the domestic
market, increasing transaction costs. This is likely to limit trade to that covered bybilateral agreements, thereby hampering the development of an international
market.
Governments should co-operate to enable a certain level of interoperability among
their regulatory frameworks. Governments that have not yet developed aregulation on hydrogen sustainability attributes can work with those that havealready introduced regulations in order to avoid larger divergences. Governmentswith existing regulations will need to find avenues for mutual recognition. Bilateralagreements, in which the government with less stringent criteria recognises
certificates issued in compliance with the regulation of the government with more
stringent criteria, can be a first step. However, a larger group of governments
agreeing to accommodate in their regulations a common emissions accounting
framework can benefit from pooling a larger share of the potential global hydrogenmarket, which would create more opportunities for project developers.
The IPHE methodology offers a robust point of departure for the establishment ofsuch an accounting framework. The methodology still needs to incorporate
elements related to hydrogen transport (currently under development) and there
are some additional methodological aspects that should be addressed, such as
the allocation of emissions among co-products in plants producing hydrogen andcarbon-containing derivatives or temporal and geographical correlation of
low-emission electricity. All these aspects can be considered by the IPHE
Hydrogen Production Analysis Task Force in the near future to improve themethodology, which could then be incorporated in future updated versions of thestandard developed by ISO.

The China Hydrogen Alliance’s standard reflects the circumstance that most of the hydrogen today in China is produced
from unabated coal, with the 14.5 kg CO2-eq/kg H2 intensity level still representing almost 50% reduction in the emissions
intensity to the unabated production from coal (21-27 kg CO2-eq/kg H2).

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17

Towards hydrogen definitions based on
their emissions intensity

Towards an international emissions accounting
framework to define hydrogen

Overview of existing and planned certification systems and regulatory frameworks for hydrogen, ammonia and otherhydrogen-based fuels
Name

Market /jurisdiction

Systemboundary

Regulatory

UK Low Carbon
HydrogenStandard; UK Low
Carbon Hydrogen
Certification
SchemeUnitedKingdom

Well-to-gate

HydrogenRegulatory

Renewable
Transport Fuel
Obligation

UnitedKingdom

Well-to-pointof delivery

HydrogenRegulatory

EU Taxonomy

European
Union

Well-to-gate

Hydrogen

Product

DemandsectorStatusChain ofcustody

Operational(certification
scheme underdevelopment)

Transport

OperationalMassbalancingOperational

Production
pathways

Emissions
intensity level(kg CO2-eq/kg H2)

Electrolysis, natural
gas with CCUS,
biomass and waste

2.4

Renewable energy
excluding bioenergy

4.0

All

3.0

Hydrogenbased
synthetic
fuels

Regulatory

Renewable Energy
Directive II

European
Union

Well-to-wheel

3.4

Hydrogen,hydrogenbased
synthetic
fuels

Under
development

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Massbalancing

Renewable
electricity; lowcarbon electricity(< 65 g CO2-eq/kWh)

3.4

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PurposePurpose

Regulatory

Regulatory

Regulatory

Name

Low-carbon fuelstandard (LCFS)

Clean Hydrogen
Production Tax
CreditClean Hydrogen
Investment Tax
CreditTowards an international emissions accounting
framework to define hydrogen

Market /jurisdiction

California(UnitedStates)United States

Systemboundary

Well-to-wheel

Product

HydrogenWell-to-gate

HydrogenWell-to-gate

Hydrogen

DemandsectorTransport

StatusOperational

Underdevelopment

Under
development

CanadaAmmonia

PAGE | 63

Chain ofcustodyBook-andclaim

Production
pathways

Emissions
intensity level(kg CO2-eq/kg H2)

Compressed H2 from
SMR w/o CCUS
using natural gas

14.1

Liquefied H2 from
SMR w/o CCUS
using natural gas

18.1

Compressed H2 from
SMR w/o CCUS
using biomethane

11.9

Liquefied H2 from
SMR w/o CCUS
using biomethane

15.5

Compressed H2 fromelectrolysis using gridelectricity

19.8

Compressed H2 fromelectrolysis using
solar or windelectricity

1.3

All

2.5-4
2.5-1.5
1.5-0.45<0.45Electrolysis, natural
gas with CCUS

2-4
0.75-2< 0.75<4
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Towards hydrogen definitions based on
their emissions intensity

Towards hydrogen definitions based on
their emissions intensity

PurposeName

Towards an international emissions accounting
framework to define hydrogen

Market /jurisdiction

Systemboundary

Product

DemandsectorStatusChain ofcustody

Production
pathways

Emissions
intensity level(kg CO2-eq/kg H2)
High-carbonhydrogen: > 3 H2regardless of energy
sourceRegulatory

France OrdinanceNo. 2021-167

FranceWell-to-gate
includingmanufacturingoftechnologies

HydrogenAll sectors

Underdevelopment

Book-andclaim andmassbalancingAll

Low-carbonhydrogen:≤ 3.38 H2,
regardless of energy
sourceInternational

Well-to-pointof delivery

Ammonia,
methanol,
synthetic
kerosene

OperationalMassbalancing

Renewable electricity

3.0

Zero Carbon
Certification
Scheme (Smart
Energy Council)

Australia

Well-to-gate

Hydrogen,ammonia,
steel

OperationalMassbalancing

Renewable electricity-

Guarantee of Origin
certificate scheme(AustralianGovernment)

Australia

Well-to-gate

Hydrogen,hydrogencarriers

Underdevelopment

Massbalancing

Renewable electricity-

Funding
programme

H2Global

Voluntary

Voluntary

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Renewablehydrogen:≤ 3.38 H2, fromrenewable sourcesPurpose

Name

Voluntary

Standard and
Evaluation of LowCarbon Hydrogen,
Clean Hydrogen
and Renewable
Hydrogen (China
Hydrogen Alliance)

Voluntary

CertifHy

Voluntary

Low-carbonhydrogencertification system(Aichi Prefecture)

Voluntary

Green Hydrogen
Standard (Green
Hydrogen
Organisation)

Voluntary

Climate Bonds
Standard &Certification
SchemeTowards an international emissions accounting
framework to define hydrogen

Market /jurisdiction

China

Systemboundary

Well-to-gate

European
Union

Well-to-gateJapan

Well-to-gate

International

International

Product

DemandsectorHydrogenOperational

HydrogenOperational

Chain ofcustody

Not specified

Book-andclaim

HydrogenOperational

Book-andclaim

HydrogenOperational

Not specified

Ammonia

Underdevelopment

Well-to-gateWell-to-gate

StatusHydrogenOperational

PAGE | 65

Production
pathways

Emissions
intensity level(kg CO2-eq/kg H2)

All

Low-carbonhydrogen: 14.5
Renewablehydrogen, cleanhydrogen: 4.9

Renewable electricity

Green hydrogen:4.4

Nuclear electricity,
fossil fuels with
CCUS

Low-carbonhydrogen: 4.4

Renewable
electricity, biogas-

1
Renewable electricity

Electrolysis, natural
gas and waste
biomass

0.3 kg CO2-eq/kg N
H3
2022: 3.0
2030: 1.5
2040: 0.6
2050: 0.0

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Towards hydrogen definitions based on
their emissions intensity

Towards hydrogen definitions based on
their emissions intensity

PurposeName

Towards an international emissions accounting
framework to define hydrogen

Market /jurisdiction

Systemboundary

Product

DemandsectorStatusChain ofcustody

Transport
Book-andclaim

Well-to-gate
Outsidetransport
VoluntaryTÜV SÜD CMS 70

European
Union

HydrogenOperational
Transport

Well-to-pointof delivery

Massbalancing
Outsidetranspor

Voluntary

Voluntary

Production
pathways

Emissions
intensity level(kg CO2-eq/kg H2)

Renewable electricity

1.1

Biomethane,
glycerine

2.3-3.4

Renewable electricity

1.1

Biomethane,
glycerine

2.1-3.2

Renewable electricity

2.8

Biomethane,
glycerine

4.5-5.6

Renewable electricity

2.7

Biomethane,
glycerine

4.3-5.4
Reduced-carbonhydrogen: 6

World BusinessCouncil of
Sustainable
Development

International

Ammonia Energy
Association

International

Well-to-gate

Hydrogen

Proposal

Not specified

All

Low-carbonhydrogen: 3
Ultra-low-carbonhydrogen: 1

Well-to-gate

Ammonia

All sectors

Underdevelopment

Not specified

All

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Notes: CCUS = carbon capture, utilisation and storage; SMR = steam methane reforming; H2 = hydrogen. The “Demand sector” column indicates whether the certification system or regulation islimited to using the hydrogen in a specific sector.

Towards hydrogen definitions based on
their emissions intensity

Towards an international emissions accounting
framework to define hydrogenWho would benefit from an international emissions
accounting framework?

Producers: project developers require clarity and consistency to be able tocomply with regulations and incentives, report on environmental performance andattract investment. For example, a project developer producing ammonia fromrenewable electricity for export may plan to benefit from low-emission tax credits
in the country of production and need to demonstrate regulatory compliance toaccess the market in the destination country. A recognised international
accounting framework for hydrogen production avoids the need to conduct two
separate certifications to comply with different regulatory requirements.

Consumers: hydrogen users need assurance that the product they arepurchasing is consistent with regulatory and/or environmental criteria. They
require sufficient detail to make informed comparisons of different offerings fromproducers located in different countries or operating under different regulatory
requirements or certification systems within the same country. Scale-up of lowemission hydrogen will be hampered and the market will fragment if, for example,
a buyer wishing to import ammonia finds that the destination country requires adifferent standard to the one used by the seller in the country of production, forexample to qualify for a tax credit.

Governments: regulators are grappling with how to ensure that hydrogenproduction and use result in environmental benefits. A common framework,
agreed between governments, simplifies the rule-making process. It provides arecognised means to quickly establish criteria for new support programmes. In
addition, a robust accounting framework for traded hydrogen can increase trust
between governments and avoid duplication in regulating all steps of the value
chain.



Traders: As the international hydrogen market scales up, prices can be expected
to fall if hydrogen-based products are interchangeable, i.e. supply and demandcan be readily balanced across regions. An international emissions accounting
framework is likely to be necessary to move from purely bilateral trade agreements
to a liquid marketplace where risks can be spread more evenly, creating efficiency
opportunities for traders.



Investors: Uncertainty about how different projects compare, and whether they
will be compatible with regulations, government incentives or buyers’ preferences
is a major risk facing investors. This slows down the pace of project construction
and increases the costs of hydrogen products. An international emissions

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An international emissions accounting framework can facilitate the deployment ofhydrogen by creating clarity about its emissions intensity, thus helping to reducerisks for ‘first movers’. Such a framework will be of value to a variety of key
stakeholder groups:

Towards hydrogen definitions based on
their emissions intensity

Towards an international emissions accounting
framework to define hydrogenaccounting framework would allow investors to easily compare projects against acommon benchmark and reduce the need for in-house or third-party assessment.

Certification bodies: An international emissions accounting framework will create
incentives for independent certifiers to offer high-quality, competitively priced
services to win market share and operate across borders. For small certification
bodies, for example in smaller economies, the barriers to entry should be lower
when private certificate schemes cannot become de facto monopolies.



General public: Technical claims and counter-claims about the sustainability
attributes of different hydrogen production pathways can make it difficult for thegeneral public to understand what is being proposed by firms and governments.
A common system for presenting emissions intensity can help demystify theemissions attributes of different hydrogen sources.

Some of these groups, such as investors, some final consumers of hydrogenbased products and the general public could also find value in a simple
presentation of this accounting framework, such as the system of emissions
intensity levels presented in Box 3.1.

Box 3.1

Grouping emissions intensity into a series of levels for
non-expert users

Transparency about the precise emissions intensity of traded hydrogen isappropriate for governments, regulatory authorities, certification bodies andmarket participants. But it is unlikely to be intuitive for all stakeholders. In particular,
investors, financial institutions, final consumers of hydrogen-based products or thegeneral public may struggle to interpret technical details or be able to immediately
assess the relative scale of emissions. The importance of communicating in simple
terms is already well evidenced by the extent to which the terms “blue” and “green”
hydrogen have gained traction in expert and non-expert discussions alike.
When shifting from hydrogen colours to a more accurate measure of emissions
intensity it is not necessary to entirely do away with the simplicity of distinguishing
between a small set of hydrogen archetypes. A system that groups the emissions
intensity into a smaller set of distinct levels could be a valuable complement, as a
powerful means of communicating to non-expert stakeholders who wish tounderstand the emissions implications.

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A possible avenue could be a set of nine distinct, technology-neutral levels,
ranging from emissions intensities below zero (level “A”) to an upper value of
7 kg CO2-eq/kg H2 (level “I”) (see chapter Defining hydrogen according to its
emissions intensity). The proposed levels reflect known hydrogen production
routes that can achieve lower emissions than unabated fossil-based routes, whileTowards hydrogen definitions based on
their emissions intensity

Towards an international emissions accounting
framework to define hydrogenalso considering potential for future improvement in the production technologies
and fuel supply chains, such as reductions in upstream and midstream methane
emissions in natural gas supply. Other potential systems could include a higher
upper limit, at 23 kg CO2-eq/kg H2 to also include unabated fossil-based routes, or
lower levels (in the range of 3-4 kg CO2-eq/kg H2) to reflect the ambitions bygovernments that have already set regulations in this respect.

kg CO2-eq/kg H2

Example of a potential quantitative system for emissions intensity levels ofhydrogen production
Median upstream
and midstream
emissions, 2021

7.0

Median upstream
and midstream
emissions, 2030

I

Best available technology
for upstream andmidstream emissions

NG SMR /w
CCS 60% CR

5.5
H
4.0
3.0
2.0
1.5
1.0
0.5
0.0

-19.0

G
F

Biomass w/o
CCS

E
D
C
B

Electrolysis
renewables

NG SMR /w
Coal /w CCS CCS 93% CR
NG POx /w CCS 93% CR
99% CR
Coal /w CCS,
98% CR

Electrolysis
nuclearA
Biomass /w
CCS, 93% CR

IEA. CC BY 4.0.

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Some stakeholders, such as the investment community and general public, mayappreciate the simplicity of quoting the aggregated “level” of emissions intensity.
For example, hydrogen on sale at refuelling stations could be presented by its level
to inform consumers of their environmental choices in a manner equivalent toenergy efficiency labelling of appliances and buildings. Other non-greenhouse gas
sustainability criteria (see The importance of compatibility with other sustainability
requirements) could, of course, also be shared. Investors would also benefit from
simple terminology for communicating what they are willing to finance (forexample, “hydrogen with a level no higher than level D”) and how it will vary overtime, including in IEA scenarios.

Towards hydrogen definitions based on
their emissions intensity

Towards an international emissions accounting
framework to define hydrogen

Avenues for implementation
Implementation of a common framework would not require the creation of an
entirely new system for standardisation and certification. Rather, it would use theexisting global system of trust and recognition within standards bodies andcertification schemes. This would provide familiarity, simplify the process forgovernments forming legislation, and empower companies with the language
needed to meet reporting requirements and attract investment. Ensuring that theimplementation process is robust and easy to understand will help facilitate
uptake.
Implementation will need to be flexible to accommodate different reporting criteria
from governments and companies. As the scope covers only hydrogen production
emissions there needs to be flexibility to allow for the inclusion of emissions
associated with the delivery and conversion of hydrogen. In addition, a growing
number of governments are beginning to include non-emissions criteria in theirenergy policies, such as human and labour rights, as well as land use and waterrequirements.

Adding value to an evolving international landscape ofstandardisation efforts and regulatory frameworks
There are several existing initiatives to create a market for hydrogen and facilitate
trade and compliance (Table 3.1). An accounting framework would not replace or
duplicate ongoing efforts, but rather support existing schemes by enabling mutual
recognition and facilitating interoperability (Figure 3.1).
To successfully implement an international emissions accounting framework forhydrogen production, there must first be an agreement on the underlying
methodology for determining the emissions intensity of hydrogen production,
including common system boundaries and scope of emissions. The IPHE
methodology offers one way to facilitate a common language with atechnology-neutral approach, and can allow governments and companies toselect the emissions intensities that best fit their decarbonisation objectives.

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Implementation of a common framework may differ depending on the scheme. For
instance, in mandatory schemes used for government compliance, regulations
could require specific emissions intensity ratings to meet their own requirements
and support net zero commitments. In voluntary schemes, companies may opt touse a labelling system that groups emissions intensity ratings into a smaller set of
distinct levels to provide clarity for disclosure and communication purposes (seeBox 3.1).

Towards hydrogen definitions based on
their emissions intensity

Towards an international emissions accounting
framework to define hydrogen

Use of an internationally agreed emissions accounting framework forhydrogen production to facilitate market interoperability
5 certificates and 5 ongoing monitoring and auditing systems
Region 1: Exporter

Region 4: Importer
4 kg CO2/kg H2

No local regulatory requirement

Tenders: ≤ 6 kg CO2 + labour standards

Region 2: Exports > Local use

Region 5: Imports < Local production

1.5 kg CO2/kg H2
Local financial support: ≤ 2 kg CO2

Local financial support: ≤ 2 kg CO2

Region 3: Exports < Local use

Region 6: Imports > Local production

1 kg CO2/kg H2
Local fuel standard: ≤ 3 kg CO2

Local fuel standard: ≤ 3 kg CO2

Full mutual recognition
Region 1: Exporter

Region 4: Importer
4 kg CO2/kg H2
Tenders: ≤ 6 kg CO2 + labour standards

No local regulatory requirement
Region 2: Exports > Local use
1.5 kg CO2/kg H2

International
accounting
framework

Need additional
renewables
guarantee

Region 5: Imports < Local production

2, 3Local financial support: ≤ 2 kg CO2

Local financial support: ≤ 2 kg CO2

Region 3: Exports < Local use

Region 6: Imports > Local production

1 kg CO2/kg H2
Local fuel standard: ≤ 3 kg CO2

Local fuel standard: ≤ 3 kg CO2

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IEA. CC BY 4.0.

Towards hydrogen definitions based on
their emissions intensity

Towards an international emissions accounting
framework to define hydrogen

Expanding an accounting framework to address all
emissions associated with hydrogen supply chains
For simplicity and to smooth the initial stages of implementation, an accounting
framework could start with a “well-to-gate” scope, meaning that direct emissions
from hydrogen production and indirect upstream and midstream emissions related
to the supply of the fuels and other inputs (e.g. heat, water, steam) for the
production process are included. However, hydrogen production is only one partof the supply chain. In the case of captive hydrogen production in industrial andrefining applications, a “well-to-gate” scope is enough to evaluate the emissions
related to the use of hydrogen. However, in the case of distributed uses or thecreation of an international market to facilitate hydrogen trade, conversion intohydrogen carriers, transport and reconversion back to hydrogen (when the carriercannot be used directly) can have a significant impact on the total emissions of
the hydrogen delivered to end users. These emissions should be considered toenhance comparability of the different products delivered to final users.
The expansion of an accounting framework should be based on agreed
methodologies, as should be the case for hydrogen production. Thesemethodologies should be rapidly available to avoid delays that could compromise
the development of international supply chains in the near term. The IPHE, in thesecond version of its guideline, has already developed methodologies to assess
the GHG emissions associated with the conversion of hydrogen into carriers andreconversion to hydrogen, and is developing methodologies for hydrogentransport.

The importance of compatibility with other sustainability
requirements
The sustainability attributes of hydrogen and the potential impacts of thedevelopment of hydrogen supply chains are not limited to GHG emissions. There
are several other potential sustainability requirements (Table 3.2) thatgovernments can take into account when making decisions about the use ofhydrogen as a clean fuel and feedstock, and its contribution to their long-termsustainability targets. Companies may also want to voluntarily certify theirproducts with additional sustainability criteria to highlight the sustainability
attributes of their product and inform consumer choices.

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Some governments and certification schemes have already taken a first step in
the adoption of sustainability criteria other than GHG emissions. Environmental
criteria related to the renewable origin of the energy source used for the productionof hydrogen and land or water use and socio-economic criteria related to working
conditions, living standards or food security are already incorporated in someregulations and certification schemes (Table 3.3). In addition, governments such

Towards hydrogen definitions based on
their emissions intensity

Towards an international emissions accounting
framework to define hydrogen

as Canada, Chile and Colombia are studying the possibility of adopting additionalsocio-economic sustainability criteria related to their particular situations withregards to indigenous communities or water access rights.
Selected sustainability criteria applicable to hydrogen supply
Within the scopeof this report

Available
methodology

Production

Yes

IPHE

Conversion

No

IPHE

Transport

No

Under
development**

Criteria

GHG
emissions

Environmental
criteria

Socioeconomic
criteria

Water useNo

Land useNo

Renewable origin

No

Air impacts

No

Waste management

No

Human and labour rights

No

Water use rights

No

Health and safety

No

Food security

No

Local and social
development

No

Available
standard
Under
development*
Underdevelopment*
Underdevelopment*

Methodologies and standards for theevaluation of some of theseenvironmental criteria exist, such as
ISO 14001:2015 for Environmental
management systems,
ISO 46001:2019 for Water efficiency
management systems and ISO 45001
for occupational health and safety, butthey are not specific to hydrogen* The ISO Technical Committee (TC) 197/SC1 aims to develop a Technical Specification by the end of 2023 (withpublication in 2024) and an International Standard by the end of 2024 (with publication in 2025).
** The IPHE methodology to determine GHG emissions for hydrogen transport technologies is expected in April 2023.

As the market matures, it can be expected that a wide range of additionalsustainability criteria arises and gets established under different regulations,
government incentives and certification schemes. Having such criteria is ultimately
important but the typically staggered approach to implementation can be a
problem for nascent markets. Lack of foresight on potentially increasingly stringent
environmental and socio-economic criteria, for example, can hinder investment by
first movers and slow down deployment. In addition, not all potential sustainability
criteria have standards or methodologies in place for their evaluation.

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Starting with an internationally agreed emissions accounting framework forhydrogen production that can provide regulatory and certification clarity to market
players can help unlock investment, enable scale-up and allow the market tomature. The experience gained as this happens can help with the subsequent
incorporation of additional sustainability elements. An internationally agreed
accounting framework is a first step focused exclusively on GHG emissions, but it
does not prevent the adoption of additional sustainability criteria in the future.

Towards hydrogen definitions based on
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Towards an international emissions accounting
framework to define hydrogen

Selected regulations and certification schemes incorporating sustainability
criteria other than greenhouse gas emissions
Regulation

PurposeEnvironmental criteria

European Commission
Delegated Act of theRenewable Energy
Directive*

Define rules forhydrogen production tocount towards the EU's
renewable energy
targetRenewable origin;
Additionality of electricity
source;Temporal correlation withelectricity source

US Clean Hydrogen
Production Tax Credit

Provide incentives for
producers of cleanhydrogen**

Certification schemeTÜV Süd CMS 70
standard

Socio-economic
criteria

Wage and labour
requirements

PurposeEnvironmental criteria

Voluntary certification of
biomass-basedhydrogen production

Indirect land-use change
in line with the EU
Renewable Energy
Directive

Socio-economic
criteria

Climate Bonds standard
and certification scheme

Provisions related tobiomass sustainability,
which cover indirect landuse change

Food security

Green Hydrogen
Organisation Green
Hydrogen Standard

Renewable origin;
Water use and quality;
Waste, noise and air
quality;
Biodiversity

Requirements on living
standards, resettlement,
indigenous
communities, labour andworking conditions

Voluntary certification ofhydrogen production* This Delegated Act still needs to be approved by the European Parliament and Council.
** The Act defines qualified clean hydrogen as hydrogen that is produced through a process that results in a lifecycle
greenhouse gas emissions rate no greater than 4 kg CO2-eq/Kg H2.

Buyers and regulators of hydrogen supplies will wish to ensure that their own
combinations of sustainability and other criteria are met. In some cases, a buyer
will need such guarantees from multiple producers and traders. In other cases, asingle producer may need to provide different combinations of guarantees todifferent buyers or regulators. So-called “product passports” can standardise theprocess, minimise costs and maximise transparency (Box 3.2).

Box 3.2

A hydrogen passport to integrate multiple criteria

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A “product passport” for a cargo of hydrogen or hydrogen-based fuels could beestablished in the form of a unique ID connected to a data repository accessible totrading partners and end users. The accessible data could include the emissions
intensity rating, a simplified emissions intensity level such as the one proposed inBox 3.1, as well as other certificates, assessments or information on environmental

Towards hydrogen definitions based on
their emissions intensity

Towards an international emissions accounting
framework to define hydrogenand socio-economic considerations. In each case, the associated standard,
regulation, institution or methodology would be included.
Product passports are not a new idea. Since 2000, as data and digital technology(including blockchain) have improved dramatically, they have been suggested fora variety of applications. The European Commission has advocated the transferralof product passports between owners of a traded good to document the resources
used in its production. Information in Digital Product Passports could be accessible
from a chip, or by scanning a watermark or quick response (QR) code. Building
Renovation Passports have been developed in the form of “logbooks” ofsuccessive renovations.
One of the most well-developed and global examples is the battery passport,
proposed by the Global Battery Alliance. The proposal is for a “digital twin” of anelectric vehicle’s physical battery components. By enabling transparent access to
key information about the origins of components, manufacturing history andsustainability, the Global Battery Alliance expects to raise consumer confidence
and enable industry-wide benchmarking. The intention is to start with voluntary
information about compliance with existing standards and legislation, but somejurisdictions are exploring how to make battery passports a legal requirement,
accompanied by agreed methodologies for calculating lifecycle data.
Hydrogen passports could face additional challenges compared to those fordiscrete physical products. Gaseous and liquid fuels are traded in many different
volumes and vessels. A single large seaborne cargo may contain hydrogen frommultiple sources and, by the time it reaches an end-consumer, be split into
numerous smaller volumes, each needing a unique ID. As each delivery ofhydrogen is used, it may be incorporated into different hydrogen-based fuels orother tertiary products whose buyers may, in turn, need the passport’s values. Thisissue is by no means insurmountable, and systems have been developed for foodand drink, and natural gas, by certifying all the output from a production facility or
supply chain for a set period. Allocation of emissions intensity to sub-units has
been codified for the transport sector.

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For an intermediate energy product like hydrogen, any passport system should be
developed in a manner that is compatible with products upstream and downstream
in the supply chain. As energy transitions unfold, it is likely that end users andregulators will wish to distinguish between many different energy products basedon their origin and credentials. This could include the renewable content ofelectricity, or the bioenergy, hydrogen or natural gas shares of pipeline gas, as wellas the upstream and midstream methane emissions associated with the natural
gas content. It may even extend to information about the inputs and equipmentused in the bioenergy and electricity supply chains. The general direction of policy
and trade is towards ever more differentiation between physically indistinguishable
and interrelated goods in the energy system.

Towards hydrogen definitions based on
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Towards an international emissions accounting
framework to define hydrogen

Graphical representation of the possible content of a product passport for a
traded hydrogen cargo

HYDROGEN PASSPORTWATER CONSUMPTIONLAND USEWASTE MANAGEMENTRENEWABLESADDITIONALITY

This passport certifies each
1 (one) kilogramme unit of hydrogenin consignment: AU358/1
PRODUCTION:

H2

1.32 kg CO2-eq/kg H2
CONDITIONING:

0 kg CO2-eq/kg H2

14001

TRANSPORT:

0.41 kg CO2-eq/kg H2
PRODUCTION GHG EMISSIONSRENEWABLE ORIGIN

SOCIO-ECONOMIC IMPACT

MINERAL INPUTSD
IEA. CC BY 4.0.

Practical considerations for effective
implementation
There are a number of prerequisites for a common framework to become widelyadopted and add value. Above all, recognition of the system by governments ascompliant with regulations is fundamentally important. There are also critical roles
for other stakeholders, including standardisation and certification bodies, and key
design considerations that must be taken into account to be robust in a changing
technical landscape.

Roles and responsibilities for key participants
The successful adoption of an international emissions accounting framework insuch a complex, technical and commercial arena relies on the active participationof many different and interconnected stakeholders. This includes building upon
the existing competences and activities of expert bodies (Table 3.4).

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Governments will need to take the lead in supporting the initial adoption of an
accounting framework and ensuring that it is integrated into national and regional
regulatory frameworks. Unless this is the case, there remains a risk that any
framework creates an additional burden for suppliers without reducing any existingones.

Towards hydrogen definitions based on
their emissions intensity

Towards an international emissions accounting
framework to define hydrogen

Roles and responsibilities for key participants to facilitate adoption of an international emissions accounting framework

Governments

Standardisation
organisations (national andinternational)

Role

Description

Recognise in legislation

For hydrogen certified under one standard to be eligible under that of another jurisdiction, aninternationally agreed emissions accounting framework would need to be codified in official
documentation relating to investment support; tax exemptions; obligation systems or
portfolio standards; tenders and auctions; or prohibitions of hydrogen with certain
characteristics.

Champion the framework

The most likely route to wide adoption is via a core group of committed governments that
represent a significant share of production, consumption or funding of traded low-emissionhydrogen products, as is the case of the G7.

Agree methodologies

Lifecycle boundaries, process descriptions, allocation methods, default values,
measurement protocols, conversion constants (such as for converting methane emissions
into CO2 equivalents), unit of certification (assets, fleets or cargoes), and time horizons overwhich certified emissions intensities are averaged must all be harmonised, as described by
IPHE.

Agree accounting principles

Different jurisdictions may wish to take different approaches to “chains of custody” – on a
book-and-claim or mass balance basis – depending on whether they implement acompliance market with tradeable certificates. Making these approaches interoperable willtake careful consideration if it is necessary.

Establish accreditation for certifiers

Governments will be responsible for establishing who can legally certify hydrogen cargoes.
This could include giving a mandate to a dedicated public institution, maintaining a list of
authorised bodies, or allowing certification by any party that complies with the rules. Aninternational framework would require mutual recognition of these certifiers.

Prioritise standard development

Standardisation follows defined timelines, usually including reviews and updates every five
years. The ISO Technical Committee 197 Sub Committee 1 has quickly responded to the
IPHE guidelines and aims to expand them into standards by 2025. While it is ambitious, thisshould be considered the minimum allowable timeframe.

Agree methodologies

International and national bodies should adopt the same underlying methodologies for theirstandards, as per the Vienna Agreement on technical co-operation to facilitate therecognition of ISO standards in European countries.

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Stakeholder

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Certification bodies

Role

Description

Adopt equivalent methodologies andaccounting principles

There is a precedent for the mutual recognition of certificates, with six voluntary systems tocertify sustainable biofuels that encompass mutual recognition of processes. All six arerecognised by the European Union under REDII.

Facilitate data availability

In addition to meeting the highest regulatory requirements for transparency and data
access, certification bodies operating within an international framework may need to useinteroperable data systems to ensure information is available and can be accumulated
throughout the value chain.

Consolidate the number of standards

Simplicity should be a core goal of an international emissions accounting framework, and it
will be enhanced by competition based on excellence of certification rather than competition
between standards offering conflicting criteria.

Co-operate with early adopters

Market participants’ incentives are broadly aligned with governments: successful
deployment depends on clarity on standards and definitions for the duration of prospective
investments, in addition to common approaches between regions without duplication ofcertification. To accelerate progress, first movers can work together to begin adopting the
IPHE methodology even before regulatory processes are fully concluded.

Champion transparency

Given the likelihood that various commercial and political interests will continue to contest
the environmental credentials of hydrogen, it is in the interest of all actors to reduce the riskthat the framework – and thus hydrogen – becomes devalued by secrecy, uncertainty andcounter-claims.

Producers, traders andbuyers of hydrogen, andhydrogen-based products

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Stakeholder

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framework to define hydrogen

Reporting, verification and auditing
The successful translation of an accounting framework into national and regionalframeworks requires that hydrogen production pathways are performing as
expected and reported emissions intensities continue to be accurate. Reporting of
key data, verification of that data, and the auditing of reported results is critical toproviding assurance.

Required information
Certification schemes may require detailed information to be reported to theregulator for assessment and validation before physical production, to trackcompliance. There are two main types of data required:•

Profile data, which is submitted when registering supply chain steps and which
describes the key attributes of each step, including emissions sources and how they
have been determined.

•

Batch data, which is specific to a certificate creation batch and is submitted at the
point of certification creation. It provides information on the specifics of a particularcertificate creation batch.

It is important to use existing adjacent schemes, wherever possible, to bridge data
gaps. For instance, if certification schemes require a specific source of electricity
used in part of the hydrogen production process, or proof of upstream andmidstream methane emissions for gas cargoes, utilising existing schemes todemonstrate this information (such as through Guarantees of Origin or methanecertifications) helps to increase the ease of implementation and reduce regulatoryburdens.

Frequency
Regulatory frameworks also need to establish the frequency of data reporting (e.g.
real-time, every 6 months, 12 months, 18 months, etc.). For instance, Australia iscurrently considering that data be reported over a 12-month period, stating that
this timeframe is typical for data collection for lifecycle assessments. However,data reporting and certification creation may need to operate on different
timeframes to provide flexibility for producers.

Verification and auditing

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Verification and auditing mechanisms should be in place to ensure that hydrogenor its derived products continue to be consistent with what is reported. A scheme
should outline the verification process and timeline and consider if any auditing
requirements should be put in place to ensure that the claimed emissions intensity

Towards hydrogen definitions based on
their emissions intensity

Towards an international emissions accounting
framework to define hydrogencontinues to meet the certified level. Consideration should be given to the auditing
process itself and who performs it (e.g. self-auditing, independent third parties,
digital mechanisms, etc.).
As an example, a producer could have been selling hydrogen at an emissions
intensity of 1.5 kg CO2-eq/kg H2 for several years, as certified by a certificationbody and verified by an independent organisation. However, changes to the
upstream and midstream fuel supplier have increased the emissions intensity of
the hydrogen to 2.5 kg CO2-eq/kg H2. Depending on the frequency of the reporting
requirements and the auditing process, the producer may have inadvertently soldits hydrogen at a different emissions intensity from originally thought. Further
complexity is added if that hydrogen is used for regulatory compliance or public
subsidy purposes.
Regulatory frameworks may need to consider mechanisms to “claw-back” anysubsidy linked to the produced hydrogen if the product is found to be at a different
emissions intensity than recorded previously. There is precedent for this in othersectors: under the 45Q tax credit for CCUS in the United States, a claw-backmechanism embedded in the regulation requires the company claiming the tax
credit to report any CO2 leakage into the atmosphere that has occurred from CO2that was thought to have been previously contained underground. If the amountof leakage exceeds the amount of stored CO2 for that given tax year, the company
must pay the difference to the tax authority.

Resiliency in an evolving data and regulatory landscape
The IPHE’s methodology for assessing emissions from hydrogen production,
conversion into carriers, and transport, is now being used by ISO to develop athree-part standard covering production, conditioning and transport. This process
can take several years, although given the urgency for the development ofregulatory frameworks, the aim is to develop a Technical Specification by the endof 2023 and an International Standard by the end of 2024. The long lead time todevelop standards can delay the scale-up of a hydrogen market. Governments
and certification bodies should therefore not delay existing efforts due to a lack of
an international standard, but rather should take a dynamic approach and allow
for the future incorporation of standards when they are ready (Box 3.3).

Box 3.3

Incorporating future standards into rule-making

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In the United States, the 45Q tax credit incentivises the deployment of CCUS
technologies by providing a credit for entities that capture and store CO2. In orderto claim the credit, companies must follow a methodology developed by theTowards hydrogen definitions based on
their emissions intensity

Towards an international emissions accounting
framework to define hydrogen

Environmental Protection Agency (EPA) or use the methodology outlined in a
relevant international standard. Although companies currently enjoy the choice
between the two options, this has not always been the case.
When the tax credit was introduced in 2008, there was no international standard
for CO2 storage or its use in enhanced oil recovery, prompting the EPA to develop
its own methodology. Then, in 2019, the ISO finalised ISO 27916 for CO2 storage
using enhanced oil recovery. Yet in order to claim the 45Q tax credit, companies
at the time still had to use the EPA’s methodology to demonstrate compliance.
Following the finalisation of the ISO standard, in 2021 the United States updated
its regulatory guidance to include the use of ISO 27916 as a potential compliancepathway. It determined that the ISO 27916 and EPA methodology were similar:
both used a mass balance approach and required assessment and monitoring.
Using the 45Q tax credit as an example, it is possible to see how rule-making canincorporate future international standards.

As the hydrogen sector grows, there will be learning experiences resulting in
updates and improvements to current methodologies and standards, andregulations should be able to accommodate these changes. There could be newsources of emissions that are not initially considered in methodologies andstandards, or for which there is not enough evidence on their impact. For example,
there is growing scientific evidence of the potential climate impacts of hydrogenas an indirect greenhouse gas. However, there is still uncertainty around its global
warming potential, a lack of information about hydrogen leakage rates, and limited
data about downstream emissions. In some cases, available information is limited
to a handful of demonstration projects. As projects are deployed, more data andevidence will be collected, helping to develop and improve the methodologies andstandards.

Adopting a full lifecycle analysis approach
In the future there may be a need to include sustainability criteria across the fullhydrogen lifecycle. Currently, the IPHE’s methodology retains commonly usedsystem boundaries, including Scope 1, Scope 2, and partial Scope 3 emissions. 18
The emissions from the construction, manufacturing, and decommissioning of thehydrogen production device, business travel, employee commuting, and upstream
and midstream leased assets are not considered.

Partial Scope 3 emissions include associated impacts from the raw material acquisition phase, raw material transportation
phase, hydrogen production and manufacture.

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18

Towards hydrogen definitions based on
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Towards an international emissions accounting
framework to define hydrogenTo fully reflect the GHG intensity of hydrogen, the IPHE methodology could be
extended to include a complete lifecycle assessment. In that case, this approachshould also be applied to other energy products (including electricity and biofuels),and not restricted only to hydrogen and hydrogen-based fuels, to ensure a levelplaying field.

Data quality and assurance
The availability of high-quality data is essential. The robustness of themethodology used to calculate emissions is critical, but the most robust
methodology may lead to misleading results if poor quality data is used. Using
incomplete or inaccurate data to calculate the emissions associated with ahydrogen production project can result in significant deviations from the actual
emissions of a project. For example, the contribution of upstream and midstream
methane emissions to the total emissions associated with the production ofhydrogen with natural gas and CCS can vary significantly depending on which, ifany, methane abatement technology is used. If no data is available on the
upstream and midstream emissions associated with the natural gas supply of thisproject, it could affect whether or not the project is compliant with regulations andsupport schemes.
Data availability does not always ensure high-quality data. Quality data should becomplete, timely, consistent and accurate to produce reliable results. For example,
an error of just 20 g CO2-eq/kWh in the reported electricity emissions intensity ofan electrolyser connected to the electric grid can lead to a deviation of more than
1 kg CO2-eq/kg H2 in the final emissions intensity.

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Such a difference between the real emissions of the project and the emissions
reported due to unavailable or bad quality data is misleading and can grantcompliance with regulations and support schemes where the project is actually
not compliant. If this occurs, it could discredit any internationally agreed emissions
accounting framework and create strong reputational damage. Stakeholders along
the hydrogen supply chain must commit to ensure that best practices and thehighest level of transparency are adopted to ensure credibility in the system. The
creation of open data repositories managed by credible independent bodies andverified by third parties could help to provide the necessary transparency to build
such confidence. This is particularly important for hydrogen and hydrogen-based
fuels, for which there is limited statistical information available today.

Towards hydrogen definitions based on
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Towards an international emissions accounting
framework to define hydrogen

Considerations for the G7
Each G7 member will adopt policies based on its social and political priorities andconstraints. But there are areas in which stronger co-operation between membersof the group can help establish the basis for the development of a functional global
market. Such co-operation should not be limited to G7 countries, as thedevelopment of a global hydrogen market will require the participation of
stakeholders beyond the G7, particularly from emerging economies that could also
benefit from the development of a global market for hydrogen, ammonia andhydrogen-based fuels.
The final section of this report presents recommendations for the G7 to spearheadaction on agreeing and implementing an international emissions accounting
framework for hydrogen and hydrogen-based fuels (Table 3.5).
Near-term priorities for collective G7 action
Priority

Near-term steps

Set clear, unified expectations••

Co-operate on the details

•

•

•

Work with partners•

Commit to work towards an international emissions accounting
framework for hydrogen and hydrogen-based fuels.
Communicate a timeline for putting a workable system in place,including milestones such as agreements on methodologies andaccounting principles.
Foster dialogue in the IPHE Hydrogen Production Analysis Task
Force to address any outstanding methodological or accounting
issues that are not resolved by the current IPHE guidance, forexample emissions allocation among co-products in hybrid
plants or temporal and geographical correlation of renewables.
Develop interim measures for the implementation of aframework to minimise the risk that near-term actions areincompatible or create friction with future systems.
Aim to harmonise approaches (such as common default values)
for calculating complete estimates of emissions intensities insituations where there is incomplete asset-level data.
Open a dialogue with other relevant countries, including but notlimited to major potential exporters and importers of hydrogenand hydrogen-based fuels. For example, countries planning tomeet large future demand for hydrogen via domestic sources
will nonetheless be key to developing global standards andbenchmarks.
Seek to have as many countries and country groupings as
possible sign up to a set of principles for a pathway to phase out
emissions associated with traded hydrogen products.

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•

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framework to define hydrogen

Priority

Near-term steps••

Clarify governance

Outline institutional requirements for an effective internationalemissions accounting framework, such as responsibilities forconvening dialogue, publishing documentation, promoting its
use and managing updates.
If individual countries enshrine a common approach in their local
rules, the need for a new governance body may be minimal. A
custodian of the framework could be housed within an existing
institution, such as the Hydrogen Trade Working Group of the
Clean Energy Ministerial Hydrogen Initiative (H2I) * or theHydrogen Trade Rules Task Force of the IPHE.

*The Hydrogen Initiative is a voluntary multi-governmental initiative that aims to advance policies, programmes and projects
that accelerate the commercialisation and deployment of hydrogen and fuel cell technologies across all areas of theeconomy. The IEA serves as the H2I co-ordinator to support member governments as they develop activities aligned with
the initiative.

In addition to collective action, individual countries and regions can take a numberof steps that will strengthen investor confidence and set in motion the developmentof an efficient commodity market for low-emission hydrogen. Some governments
are already advanced with some of these steps, and are well-placed to drive
forward harmonisation (Table 3.6).
Near-term priorities for policy action
Priority

Near-term steps•
Set expectations for howhydrogen from different
sources will bedifferentiated

•
•

•

•
Act to adopt and accelerateinternational standards andprocesses••

Enshrine emissions intensity in national and regional rules and add
additional criteria where necessary.
Take a unified approach to rules across measures including investment
support, tax exemptions, obligation systems or portfolio standards,
tenders and auctions, or prohibitions of hydrogen with certain
characteristics.
Issue guidelines for how regulations or eligibility for public support will
evolve over time to ensure consistency with net zero emissions by 2050.
Clarify how first mover investors will not be disadvantaged by possible
future changes in rules or standards, for example via time-limited
grandfathering of eligibility.
Work to define the preferred type of accounting framework (e.g. bookand-claim) and how it can be internationally interoperable.

Establish institutional competencies to co-operate swiftly withinternational partners (in the G7 and beyond) to develop the details of aninternational emissions accounting framework.
Empower standardisation development organisations to meet theirtimelines for developing international and national standards forharmonised emissions intensity assessments.
Develop interim measures to minimise the risk that near-term actions areincompatible or create friction with future systems.

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•

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Priority

Near-term steps

Elaborate nationally andregionally specificelements to ensureinteroperability andresilience••

Define which entities will be accredited to certify cargoes of hydrogen andhydrogen-based fuels, and their monitoring and auditing responsibilities.
Confirm that methodologies will evolve to include additional sources oflifecycle emissions that are consistent with policies for net zero emissions
and with policies governing adjacent parts of the energy system, to avoid
double-counting and perverse incentives.
Define how any remaining differences between methodologies can be
resolved to allow mutual recognition, for example by assigning default
values to add or subtract emissions values when converting between
systems.

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•

Towards hydrogen definitions based on their emissions intensity

Annex

Annex
Abbreviations and acronyms
The French Agency for Ecological Transition
Announced Pledges Scenario
autothermal reforming
best available technology
carbon capture and storage
carbon capture and utilisation
carbon capture, utilisation and storage
methanecarbon dioxidecarbon dioxide equivalentcapture rate
Environmental Protection Agency
European Union
final investment decisiongross domestic productgreenhouse gas
Green Hydrogen Standardhydrogenhydrogen equivalenthydrogen-based direct reduced iron
Clean Energy Ministerial Hydrogen Initiative
Identifier
Intergovernmental Panel on Climate ChangeInternational Partnership for Hydrogen and Fuel Cells in the Economy
Inflation Reduction Act
International Organization for Standardization
Low-carbon fuel standard
liquified hydrogen
lower heating valueliquefied natural gas
liquid organic hydrogen carrier
natural gas
nitrogen oxides
nitrous oxideammonia
Net Zero Emissions by 2050 Scenario
partial oxidation
photovoltaic

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ADEME
APS
ATR
BAT
CCS
CCU
CCUS
CH4
CO2
CO2-eq
CR
EPA
EU
FID
GDP
GHG
GH2
H2
H2-eq
H2-DRI
H2I
ID
IPCC
IPHE
IRA
ISO
LCFS
LH2
LHV
LNG
LOHC
NG
NOx
N2O
NH3
NZE
POx
PV

Towards hydrogen definitions based on their emissions intensity

QR
RED
RoW
SMR
STEPS
TC
USD
VRE

Annex

quick response
Renewable Energy Directive
rest of world
steam methane reforming
Stated Policies Scenario (IEA)
Technical Committee
United States dollar
variable renewable energy

Units of measurebar
grammegigajoulegigawatt
kilogrammekilometrekilotonne
kilowatt
kilowatt electrickilowatt-hourkilowatt peakmillion British thermal unit
million tonnes
megawatt
cubic metres
tonne

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bar
g
GJ
GW
kg
km
kt
kW
kWe
kWh
kWp
MBtu
Mt
MW
m3
t

International Energy Agency (IEA).
This work reflects the views of the IEA Secretariat but does notnecessarily reflect those of the IEA’s individual Member countries or ofany particular funder or collaborator. The work does not constituteprofessional advice on any specific issue or situation. The IEA makes norepresentation or warranty, express or implied, in respect of the work’s
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