JUNE 2021

EUROPEAN HYDROGEN BACKBONE

Analysing future demand,
supply, and transportof hydrogen
A cooperation with

Creos, DESFA, Elering, Enagás, Energinet, Eustream, FGSZ, Fluxys Belgium, Gas Connect
Austria, Gasgrid Finland, Gasunie, Gaz-System, Gas Networks Ireland, GRTgaz, National Grid,
NET4GAS, Nordion Energi, OGE, ONTRAS, Plinovodi, Snam, TAG, TerégaImprint
Supported by:
Guidehouse

Authors:
Anthony Wang, Jaro Jens, David Mavins,
Marissa Moultak, Matthias Schimmel, Kees vander Leun, Daan Peters, Maud Buseman
ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
2

Date:
June 2021
Contact:
Guidehouse
Stadsplateau 15, 3521 AZ Utrecht
The Netherlands+31 30 662 3300
guidehouse.com

Picture credits:
Title motif based on a map of ENTSOG(see https://transparency.entsog.eu/)
Design:Meike Naumann Visuelle Kommunikation

Tableof contents
4. Hydrogen Transport
Infrastructure70

4.1. Hydrogen Transport by Pipeline7054.2. Hydrogen Transport by Ship74

1. Introduction

76

94.3. Comparison of Hydrogen Transport Methods
and Supply Routes

2. Hydrogen Demand11

2.1. Industry
2.1.1. Iron & steel
2.1.2. Ammonia for fertilizers
2.1.3. High value chemicals
2.1.4. Fuel production
2.1.5. Industrial process heat

12
17
20
23
27
29

2.2. Transport
2.2.1. Road transport
2.2.2. Aviation
2.2.3. Shipping
2.2.4. Transport conclusions

31
31
34
36
37

2.3. Power38

2.4. Buildings

42

2.5. Conclusions on hydrogen demand51

3. Hydrogen Supply

53

3.1. Introduction

54

3.2. Green Hydrogen3.2.1. Renewable energy supply potential
3.2.2. Green hydrogen supply potential
3.2.3. Green hydrogen production costs
3.2.4. Green hydrogen and electrolysis innational hydrogen strategies
3.2.5. Summary

54
55
57
59
62

3.3. Blue Hydrogen64

3.4. Imports of green and blue hydrogen

67

Unit conversions

4

List of abbreviations and acronyms

4

Executive summary

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
3

63

4.4. Comparison of Electricity and Hydrogen
Infrastructure
4.4.1. Transport cost comparison between
pipeline and power line
4.4.2. Energy storage, system integration,and societal acceptance80

Appendix A.
Hydrogen Demand – Methodology

85

A.1. Industry

85

A.2. Transport

88

A.3. Power

91

A.4. Buildings

94

Appendix B.
Hydrogen Supply – Methodology

97

B.1. Green Hydrogen97

B.2. Blue Hydrogen

106

Appendix C.
Hydrogen Transport
Infrastructure – Methodology

107

C.1. Hydrogen Transport by Pipeline

107

C.2. Hydrogen Transport by Ship

109

C.3. Comparison of Hydrogen Transport

111

80
82

Methods and Supply Routes
C.4. Comparison of Electricity and Hydrogen
Infrastructure

112Unit conversions
1 kg H₂ = 11.1 m³ H₂ (0 °C, 1 bar)
1 kg H₂ = 33.3 kWh (LHV)
1 kg H₂ = 120.1 MJ (LHV)

List of abbreviations
and acronyms
ASHP
ATR
BECCS
BF
BNEF
BOF
CAPEX
CCS
CCU
CCUS
CNG
CO₂
DAC
DR
DRI
DSO
Scrap-EAFEC
EHBEU ETS
EUR
FCHJU
GHG
GW
HBI
HP
HVAC
HVC
HVDC
IEA
JRC

Air-Source Heat Pump
Auto Thermal Reformer
Bio Energy Carbon Capture and Sequestration
Blast Furnace
BloombergNEF
Basic Oxygen Furnace
Capital Cost
Carbon Capture and Storage
Carbon Capture and Utilisation
Carbon Capture, Utilisation and Storage
Compressed Natural Gas
Carbon Dioxide
Direct Air Capture
Direct Reduction
Direct Reduced Iron
Distribution System Operator
Scrap-Electric Arc Furnace
European Commission
European Hydrogen Backbone
European Union Emissions Trading System
Euro
Fuel Cells and Hydrogen Joint Undertakings
Greenhouse Gas
Gigawatt
Hot Briquetted Iron
Heat Pump
High Voltage Alternating Current
High Value Chemicals
High Voltage Direct Current
International Energy Agency
Joint Research Centre

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
4

kg
km
kW
kWh
LH₂
LHV
LNG
LOHC
MENA
MGO
MtO
MVA
MW
MWh
NECP
NIMBY
NOx
NUTS
OPEX
PCI
PV
R&D
RES
SAF
SMR
SOx
TSO
TWh
TYNDP
UK
VLSFO

Kilogramme
Kilometre
Kilowatt
Kilowatt-Hour
Liquid Hydrogen
Lower Heating Value
Liquefied Natural Gas
Liquid Organic Hydrogen Carriers
Middle East and North Africa
Marine Gasoil
Methanol to Olefins
Megavolt-Ampere
Megawatt
Megawatt-Hour
National Energy and Climate Plan
Not in My Backyard
Nitrogen Oxides
Nomenclature of Territorial Units
Operating Costs
Pulverised coal injection
Photovoltaic
Research and Development
Renewable Energy Source
Sustainable Aviation Fuel
Steam Methane Reforming
Sulphur Oxides
Transmission System Operator
Terawatt-Hour
Ten-Year Network Development Plan
United Kingdom
Very Low Sulphur Fuel OilExecutive
summary

Hydrogen is crucial to Europe’s transformation into a climate-neutral
continent by mid-century. This study concludes that the European
Union (EU) and UK could see a hydrogen demand of 2,300 TWh(2,150-2,750 TWh) by 2050. This corresponds to 20-25% of EU
and UK final energy consumption by 2050. Achieving this futurerole of hydrogen depends on many factors including market
frameworks, legislation, technology readiness and consumer
choice.
Green and blue hydrogen are crucial for our industrial decarbonisation pathway.
It is particularly relevant for chemicals (ammonia and high-value chemicals), iron andsteel, and fuel production where hydrogen is primarily used as feedstock. Greenand blue hydrogen replaces the current use of grey hydrogen in ammonia and fuelproduction and is a main input for the production of low-carbon fuels used in aviation
or as feedstock for the production of high-value chemicals. Hydrogen-based steel
making is considered the main decarbonisation option for primary steel making. About
1,200 TWh of annual hydrogen demand in industry can be expected, including justover 200 TWh for medium and high temperature industrial process heat.
Around 650 TWh of annual hydrogen demand can be expected to be requiredin dispatchable electricity production. The value of hydrogen over most other flexible
power options is that it can be supplied and stored in large quantities at relatively
cheaper investment costs, making it appealing for longer duration storage.
In transport, next to electrification and biofuels, there is a clear role for about 300
TWh per year of hydrogen as a fuel. Additional hydrogen will be needed to producehydrogen-derived synthetic fuels in aviation.¹
Heating in buildings will be decarbonised using a range of technologies withsignificant regional variations. The hydrogen demand depends on renovation rates,
the relative shares of biomethane and hydrogen, and the mix of heating technologies.
This study assumes Europe-wide accelerated renovation rates and hybrid heating
systems in existing homes with a gas connection and in 30% of district heating. Suchhybrid systems use electricity (in a heat pump) and renewable or low-carbon gas. Thisapproach reduces energy system costs, enabling lower cost to consumers and fasteremission reduction. As the hybrid heating systems mainly use gas as peak energy
supply, gas demand is lower than in gas-only solutions like hydrogen boilers and fuelcells considered in other studies. Under this study’s assumptions, annual renewable
and low-carbon gas demand in buildings will be around 600 TWh in 2050. All of this
could be hydrogen, yet assuming a scale-up of biomethane as in previous Gas for
Climate studies, annual hydrogen demand would be around 150 TWh.

Domestic European green and blue hydrogen supply potential
is vast and exceeds what would be needed to meet projected
European hydrogen demand in all sectors

1This additional hydrogen demand, mainly
for synthetic fuels, is included in the industry
demand segment.

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
5

Domestic green hydrogen supply potential in the EU and UK from dedicatedrenewables is estimated to be 450 TWh in 2030, 2,100 TWh in 2040, and
4,000 TWh in 2050. This potential already takes into account the growing needfor renewable electricity for direct consumption, land availability, environmental
considerations and installation rates. Realising this potential will likely require a
rapid, vast expansion of wind and solar capacity, beyond what is needed for directelectricity demand and corresponding to cumulative installed capacities of 1,900
GW in 2030, 3,200 GW in 2040, and 4,500 GW in 2050. The 2030 installedcapacity figure represents a more than doubling of current cumulative National

Energy and Climate Plan targets.
From 2040, green hydrogen supply potential in Europe can be sufficient to meetprojected European hydrogen demand in all sectors at lower cost levels comparedto grey hydrogen and other fossil alternatives plus the CO₂ price. By 2050, almost
all of the potential 4,000 TWh of green hydrogen can be produced for less than 2.0€/kg, of which up to 2,500 TWh can be produced below 1.5 €/kg and around 600
TWh produced at 1.0 €/kg or less. Supplying the entire projected 2,150-2,750 TWhhydrogen demand in 2050 would require around 2,900-3,800 TWh of dedicatedrenewable electricity.
However, producing such quantities of green hydrogen within the EU and UK
is subject to public acceptance of an accelerated expansion of renewable installedcapacity even beyond currently planned expansion.
In addition to green hydrogen, Europe also has a large potential to produce
blue hydrogen. Supply is virtually unlimited as natural gas supply and CO₂¬ storage
potential exceed the total foreseen hydrogen demand. Blue hydrogen production
costs are expected to be 1.4-2.0 €/kg at moderate natural gas and CO₂-prices² , but
could rise up to 1.6-2.3 €/kg during the 2030s and 2040s when CO₂-prices further
increase. Natural gas producing countries could benefit from lower natural gas costs
to produce blue hydrogen at 1 €/kg. Blue hydrogen can quickly drive emission
reductions and accelerate the pace of the transition, especially in the market’s rampup phase (2030), when green hydrogen supply potential from dedicated renewables
alone will be insufficient to meet local and regional demand in absence of a fullyinterconnected European hydrogen backbone. Although EU and UK greenfield andbrownfield blue hydrogen supply potential is almost unlimited, projects announced
to date add up to 230 TWh by 2030 and 380 TWh by 2035 and onwards – with
70% of announced project volumes stemming from the UK and the Netherlands.
Beyond 2030, deployment of new blue hydrogen projects will face increasing
competition from green hydrogen (domestic and import), as this becomes more
widely available at lower costs. However, there will still be a role for (by then) existing
blue hydrogen projects—which have a lifespan of 25 years—to continue producing
as the marginal supply option and to contribute to system integration and balancing
of variable green hydrogen through firm, baseload hydrogen production.

A European Hydrogen Backbone is essential to ensure thecreation of an EU hydrogen market, to reconcile substantial
regional differences in hydrogen supply and demand, and toconnect Europe to neighbouring regions with abundant and costcompetitive hydrogen supply potential.
Repurposed existing gas infrastructure plays a crucial role in connectinghydrogen supply and demand locations and in providing security of demand forsupply project investors, as well as security of supply and competition for futureofftakers.
By 2030, even under modest flows, countries with low domestic hydrogen supply
potential compared to their expected demand (like Germany and Belgium) will needto import hydrogen to meet national requirements. This import need creates a clear
role for the emerging hydrogen backbone. These regional differences in hydrogen
2

Assuming natural gas prices of 20€/MWh andCO₂ transport and storage costs of 50 €/tCO₂.

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
6

supply and demand will increase over time as the market develops.
Hydrogen pipelines are the most cost-efficient option for long-distance, highvolume transport at €0.11-0.21/kg (€3.3-6.3/MWh) per 1,000 km, outcompetingtransport by ship for all reasonable distances within Europe and neighbouring
regions. All shipping methods – ammonia, LOHC, and LH₂ – have high upfront
costs, related to conversion and reconversion installations and in the case of LOHC
the carrier chemical costs. Ship-transport is three to five times more expensive
compared to pipeline transport when looking at north-Africa and Saudi Arabia.
For imports from Australia pipelines are not an option and ship-transport costs are
estimated to be around 1.0 €/kg of H₂.
Hydrogen infrastructure and electricity networks each possess theircomplementary strengths when it comes to long-distance transport of decarbonised
energy carriers. The cost-optimal energy transport option depends on factors suchas the desired end-use energy carrier, availability and cost of storage, renewableenergy supply characteristics, and network topology. For high-volume transport ofenergy when the desired end-product is hydrogen, pipelines – both newly built andrepurposed ones– are 2 to 4 times more cost-effective than overhead power lines
delivering the same amount of energy. This comparison excludes storage costs forelectricity and hydrogen. In addition, the consideration between gas and electricity
transport is not only an economic question but also one of societal acceptance.
A 48-inch underground hydrogen pipeline (the size as it is used today for naturalgas) can transport the same amount of energy as 7 overhead transmission lines.

In addition to domestic EU and UK supply, abundant natural
resources and physical proximity drive the favourable economicsof pipeline imports from neighbouring regions (such as North
Africa and Ukraine), making these regions attractive partners for
future hydrogen trade.
Neighbouring regions have significant hydrogen supply potential at competitive
costs, which can become available to consumers through the European Hydrogen
Backbone. By 2040, with expected levelised costs of green hydrogen productionof 1.0-2.0 €/kg for onshore wind and solar PV, producers in Ukraine and North
Africa could benefit from a mature backbone at levelised transport costs of
0.2-0.5 €/kg. This makes green hydrogen imports of 1.5-2.5 €/kg an attractive
complement to domestic supply options in parts of Europe – especially considering
more challenging conditions around land availability and public acceptance of
renewables in European countries.
For regions with abundant natural resources such as Ukraine, North Africa,
Norway, and potentially the Middle East and Russia, some of which are labelled as‘priority partners’ in the EU Hydrogen Strategy, hydrogen imports by pipeline seemthe most cost-effective option. Imports from further away could take place by ship,
which will have higher costs, mainly due to (re)conversion losses. Given their higher
costs, these imports are better suited to decarbonise sectors where they can beused directly as a fuel or feedstock, without reconversion. It should be ensured thatimported hydrogen is produced sustainably with high greenhouse gas savings.

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
7

FIGURE 1
Overview of hydrogen supply potential and hydrogen demand in 2050

At a glance: European hydrogen Backbone
Analysing future demand, supply, and transport of hydrogen
150 (0-600) TWh
Covering all of this withhydrogen would leadto a total of 2,750 TWh

1,200
TWh

2,300

650
TWh

(2,150-2,750)

TWh

300
TWh

Hydrogen will be crucial toensure that Europe becomes a
climate-neutral continent

A European Hydrogen Backbone willbe essential to facilitate the creationof a European hydrogen market

The EU and UK could see a hydrogen demand ofaround 2,300 TWh by 2050:– About 1,200 TWh of hydrogen in industry canbe expected, including just over 200 TWh of hightemperature industrial heat.
– Some 650 TWh of hydrogen in dispatchable
electricity production.
– Alongside other options such as electrification
and biofuels, some 300 TWh of hydrogen andhydrogen-derived carriers can help to decarbonisetransport.
– Under an accelerated renovation scenario, gas
demand in the building stock will be around
600 TWh. This demand could be met withbiomethane and hydrogen. Under the assumptionsof this study around 150 TWh of hydrogen would
be used in buildings.

– Repurposed existing gas infrastructure plays a crucial rolein connecting hydrogen supply and demand locations– Hydrogen pipeline infrastructure is the most cost-efficient
option for long-distance, high-volume transport at€0.11-0.21/kg/1,000 km, outcompeting transport by ship
for all reasonable distances within Europe andneighbouring regions.
– To transport volumes of energy
corresponding to a single 48-inchhydrogen pipeline (up to 16.9 GW)
through power transmission would
require the equivalent of 7 overheadtransmission lines.
– In addition to domestic EU+UK
supply, favourable economicsof pipeline transport allow costcompetitive imports from regions
such as North Africa, Norway
and Ukraine.

Domestic European hydrogen
supply potential exceeds what
would be needed to meetprojected demand– EU and UK green hydrogen supply potential fromdedicated renewables—considering the needs ofthe electricity market, land availability, environmental
regulations, and installation rates—is estimated to be
450 TWh in 2030, 2,100 TWh in 2040, and 4,000
TWh in 2050.
– Europe also can also produce large quantities ofblue hydrogen, which can enable a quick start tothe use of hydrogen to drive emission reductions
and accelerate the pace of the transition
Supply

*
480

+380

730

1,070

*

-340

900
Green hydrogen supply
potential from dedicatedrenewables*

Blue hydrogen supply potential
Hydrogen demand
Difference between supply
potential and demand
Additional blue hydrogen
supply potential available

380

260

*

+520

195
+65

1,100

*
205

+895

DemandFigures in infographic are expressed in terawatt-hour per year in 2050. Note that as a result of the chosen methodology, demand
figures represented in this Infographic may differ from other (national) decarbonisation scenarios. Source: Guidehouse analysis.

100

EU countries and UK are grouped into 6 regions based on geographical and supply/demand characteristics:
North Sea, Baltic Sea, Central & Eastern Europe, South East Europe, Portugal & Spain, and France.

410

300
+110

1. Introduction

The European Hydrogen Backbone (EHB) initiative is a group of European gas
Transmission System Operators (TSOs) that has published a proposal for a dedicatedEuropean hydrogen pipeline infrastructure, to a large extent based on repurposed
natural gas pipelines in order to connect hydrogen demand clusters and regionswith high renewable energy potentials in a cost-efficient way. The initiative published
an initial vision paper in July 2020, with maps covering nine EU Member States
plus Switzerland, home to the eleven TSOs participating at that time. Since then,the EHB initiative has grown to 23 European gas TSOs with gas networks covering
19 EU Member States plus the United Kingdom and Switzerland. An updated reportcontaining a geographically extended vision for a dedicated hydrogen infrastructure
stretching across 21 European countries was presented in April 2021.³
This report presents the analyses, assumptions, and insights with regards to the
future European hydrogen market—in terms of demand, supply, and infrastructure—
to support the vision of the EHB initiative. It complements the publication of theextended European Hydrogen Backbone maps and explores the role of the European
Hydrogen Backbone in facilitating the creation of a liquid, competitive hydrogenmarket in Europe with access to a vast market for potential supply developers andsecurity of supply and freedom of choice by future offtakers.
This study explores the future role of green and blue hydrogen in enabling
Europe to become a climate-neutral continent. In Europe, most hydrogen today is
produced from natural gas in steam methane reforming without Carbon Capture andStorage (CCS); this type of hydrogen is called grey hydrogen. Adding CCS to greyhydrogen production, either by steam methane reforming or autothermal reforming(which allows for higher CO₂ capture rates), results in blue hydrogen. Another formof blue hydrogen is turquoise hydrogen, from natural gas in a relatively new, hightemperature process called pyrolysis, which produces hydrogen with solid carbon
as by product, instead of carbon dioxide.
Hydrogen can also be produced using electricity, by electrolysis of water, withpure oxygen as by-product. When nuclear electricity is used this results in yellow(sometimes also called pink or red) hydrogen. Using renewable electricity, such as
wind and solar power, produces green hydrogen. This study focuses on green andblue hydrogen, the two most prominent forms.
Starting with a thorough own assessment of the demand for hydrogen, Chapter
2 presents an overview of the latest insights regarding hydrogen consumption in
the industry, transport, power, and buildings sectors whilst also drawing on insightsfrom prior studies commissioned by the Gas for Climate consortium, most notably‘Gas for Climate. The optimal role for gas in a net zero emissions energy system’,published in 2019 and ‘Gas decarbonisation pathways 2020-2050’, published in
2020⁴. Hydrogen demand projections per sector are estimated at NUTS 2 andcountry-level and aggregated to EU and UK wide level. This is carried out througha combination of bottom-up, geography- and sector-specific analyses, alongside
top-down estimations whereby homogeneous assumptions are applied across theanalysed countries.

34

https://gasforclimate2050.eu/ehb/
https://gasforclimate2050.eu/publications/

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
9

Note: As a result of the chosen methodology and assumptions, demand figures
represented in this report may differ from other (national) decarbonisation scenarios. In
each of the relevant demand sub-chapters (industry, transport, power, and buildings),
we identify key input assumptions—which for the sake of the analysis have been
homogeneously applied across the analysed countries—that could have a substantial
impact on hydrogen volumes in individual countries, and how differences in theseassumptions explain potential discrepancies between projections in other scenarios.

Adding to the understanding of where major volumes of hydrogen will beneeded, Chapter 3 investigates where this hydrogen can come from. Morespecifically, the question is how much hydrogen can be produced, at what cost,where – considering both green and blue hydrogen production technologies andregions. Finally, Chapter 4 compares the different methods of connecting thesehydrogen sources and sinks. This Chapter builds on the pipeline transport cost
analysis previously conducted by TSOs for the April 2021 vision paper⁵ and adds
a quantitative assessment of hydrogen transport by ship, as well as a qualitative
discussion about the role of hydrogen infrastructure in complementing the powersystem to integrate renewables.
Although the EHB initiative recognises the importance of hydrogen storage andthe benefits it provides in the context of renewable energy integration, security ofsupply, and connectivity and costs of the wider system, this paper does not analysehydrogen storage in a quantitative manner. Similarly, modelling of hydrogen andnatural gas flows is out of scope in the present report. Nonetheless, the supply,
demand, topology, and infrastructure cost figures presented in this and previous
EHB publications can serve as starting points for such a modelling study.

5

https://gasforclimate2050.eu/ehb/

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
10

Key messages

2. Hydrogen
DemandIndustry– Green and blue hydrogen are crucial for our industrial decarbonisation pathway.
This is particularly relevant for iron & steel, ammonia, and fuels (including highvalue chemicals HVC) productions where hydrogen is primarily used as feedstock.
Green and blue hydrogen demand in these sectors can be expected to increase to
238 TWh in 2030, 692 TWh in 2040 and 983 TWh in 2050.
– An additional demand could come from medium- and high-temperature industrial
heat processes where hydrogen can partially substitute the current use of natural
gas leading to at least 56 TWh in 2030, 165 TWh in 2040 and 217 TWh of demandin 2050.
– In comparison to the 2019 Gas for Climate study, we see an increased hydrogen
demand in the steel sector and for fuel production, while biomass and recycling
reduce hydrogen demand in parts of the chemical sector.
Transport– In transport, next to electrification and biofuels, there is a clear role for about
300 TWh per year of hydrogen as a fuel. Additional hydrogen will be needed
to produce synthetic fuels in aviation⁶. In 2050, hydrogen is forecasted to power
55% of trucks, 25% of buses, and 10% of airplanes. The demand for directhydrogen in the transport sector in 2050 can be expected to be 285 TWh, with
68 TWh in aviation and 217 TWh in heavy road transport. Direct hydrogen is
forecasted to account for 12% of total transport energy demand in 2050.
Power– The value of hydrogen over most other flexible power options is that it can besupplied and stored in large quantities at relatively cheaper investment costs,
making it particularly appealing for long-duration storage. Hydrogen can costeffectively integrate and provide resilience to the highly electrified net-zeroenergy system (and economy) of the future.
– Hydrogen demand in the power sector is estimated to be 12 TWh in 2030, 301
TWh in 2040, and 626 TWh in 2050, accounting for 1%, 3%, and 7% of total EU
and UK electricity demand in 2030, 2040, and 2050 respectively.
– Hydrogen generated electricity is forecast to comprise up to 17% of theelectricity generation per country, with Poland, Ireland, Italy, Germany, andBelgium expected to have the highest shares of hydrogen generated electricity
in 2050.
– Countries with high shares of gas-powered electricity generation (e.g. Belgium,
Germany, Ireland, Italy, Poland and the UK) are expected to have high sharesof hydrogen demand. Gas-fired power plants can transition from natural gas
to hydrogen, making use of existing infrastructure and reducing necessary
investment costs for the decarbonisation of dispatchable generators.

6

Only direct hydrogen use in heavy roadtransport and aviation is included in thetransport section. Hydrogen demand to
produce fuels is included in the industry
section of the report.

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
11

Buildings– Heating in buildings will be decarbonised using a range of technologies withsignificant regional variations. The hydrogen demand depends on renovation
rates, the relative shares of biomethane and hydrogen, and the mix of heating
technologies.
– This study assumes Europe-wide accelerated renovation rates and hybrid heating
systems in existing homes with a gas connection and in 30% of district heating.
Such hybrid systems use electricity (in a heat pump) and renewable or lowcarbon gas. This approach reduces energy system costs, enabling lower cost to
consumers and faster emission reduction. As the hybrid heating systems mainly
use gas as peak energy supply, gas demand is lower than in gas-only solutions
like hydrogen boilers and fuel cells considered in other studies. Under thisstudy’s assumptions, annual renewable and low-carbon gas demand in buildings
will be around 600 TWh in 2050. All of this could be hydrogen, yet assuming ascale-up of biomethane as in previous Gas for Climate studies, annual hydrogen
demand would be around 150 TWh.

2.1. Industry“European industry needs
a liquid, pan-European,competitive, secure, hydrogenmarket by 2030 to ensure
its decarbonisation andcompetitiveness globally - thisrequires clear market signals
such as the availability ofa pan-European hydrogen
backbone. In Duisburg, we will
already need around 20 TWh/year of hydrogen by 2030.”
Dr. Markus Schöffel
Manager Sustainable Production
ThyssenKrupp Steel Europe AG

7

Gas for Climate. The optimal role for gas
in a net zero emissions energy system’
https://gasforclimate2050.eu/wp-content/
uploads/2020/03/Navigant-Gas-for-ClimateThe-optimal-role-for-gas-in-a-net-zeroemissions-energy-system-March-2019.pdf

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
12

In line with the EU’s climate target, Europe´s industry should achieve net zero GHG
emissions by 2050. While decarbonising industry is a significant challenge, there
are multiple options for industry to achieve climate neutrality. Electricity consumed
in industrial processes can be decarbonised by switching to renewable electricity
generation. Processes that require heat can sometimes be electrified, however
this becomes more challenging with increasing temperature requirements. To
decarbonise these processes, post-combustion carbon capture and storage (CCS)or renewable and low-carbon fuels such as green and blue hydrogen or biomethane
can be used. Biomethane in combination with CCS has the ability to create negativeemissions, which is significant as almost all authoritative climate change scenarios
show that the world needs substantial negative emissions to achieve net-zero GHG
emissions and keep global temperature increase well below 2°C. If the process
requires carbon-based feedstocks, biomass or synthetic feedstocks can replace thecurrently used fossil equivalent. Lastly, recycling and efficiency measures can further
reduce the need for primary energy and feedstocks.
The analysis in this chapter describes the role for hydrogen in industry, inparticular for ammonia, high-value chemicals, iron & steel and fuel production, inachieving net zero emissions. It follows the earlier study ‘Gas for Climate. The optimalrole for gas in a net zero emissions energy system’ ⁷, published in 2019, whichanalysed the use of hydrogen and biomethane in providing energy and feedstock toheavy industry. In the 2019 report, the focus was on the energy intensive industries
ammonia, methanol (for high value chemical), iron & steel and cement and lime.
Green or blue hydrogen was assumed to be the main decarbonisation option forammonia and methanol while for steel it was CCS. For cement and lime, it wasbiomass and CCS. The present analysis forms an update of that earlier study, basedon the latest insights on expected hydrogen demand in industrial sectors.

8

9
10
11

https://www.eea.europa.eu/data-and-maps/
daviz/ghg-emissions-by-aggregated-sector5#tab-dashboard-02
https://www.eea.europa.eu/publications/trends-and-drivers-of-eu-ghg
Only installations currently covered by the EUETS are included.
Nomenclature of Territorial Units for Statistics
or NUTS (French: Nomenclature des unités
territoriales statistiques) is a geocode
standard for referencing the subdivisions ofcountries for statistical purposes. The current
NUTS classification, dated 21 November
2016 and effective from 1 January 2018 (nowupdated to current members as of 2020), lists
92 regions at NUTS 1, 244 regions at NUTS 2,
1215 regions at NUTS 3 level.

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
13

Industrial processes are often highly energy intensive. As a result, the industrial
sector accounts for around 20% of GHG emissions in the EU today, emitting
877 Mt of CO₂eq in 2017.⁸ Within the industry sector, the largest emitters are
chemicals & petrochemicals (including fuel production), iron & steel and non-metallic
minerals (e.g. cement). Much of the emissions come from the combustion of oil,natural gas, and solid fuels to generate heat (e.g. for steam or melting processes).
Process emissions occur during the production of the product, however they comefrom chemical or physical processes other than combustion. For example, chemical
crackers convert hydrocarbons into ethylene and propylene to be later converted
into plastics. In addition, (primary) energy carriers are sometimes used as feedstocks
for industrial processes. Feedstock emissions occur when the final product, e.g.
fertilisers, is used.
As a result of energy efficiency improvements, a switch to low-carbon energy
carriers and the displacement of some emission-intensive processes, the industry
sector has seen a 35% GHG emissions reduction from 1990 to 2018⁹. However,to further accelerate emissions reduction in line with long-term decarbonisation
goals, a rapid scale-up of renewable- and low-carbon energy carriers alongside
implementation of breakthrough technologies is needed. Here, green and bluehydrogen can play a key role. Today, industry is the largest user of hydrogen, inparticular in the chemical (e.g. ammonia) and petrochemical sectors. However, almost
all of it is grey hydrogen leading to substantial GHG emissions. Green and bluehydrogen can replace the existing use of grey hydrogen and be a promising enablerof decarbonisation in other industry sectors. The steel industry could significantly
reduce emissions by switching to hydrogen-based steelmaking. Hydrogen can also
replace the existing use of fossil energy carriers in medium- and high-temperatureprocesses (e.g. in glass, cement and pulp and paper) and replace fossil feedstocks
in the chemical sector (e.g. high value chemicals).
In the following industry sections the use of hydrogen for the production ofammonia, high value chemicals, iron & steel and fuels is analysed. In these sectors
hydrogen, primarily used as feedstock, is crucial for decarbonisation. By 2050,
these sectors could make up around 80% of hydrogen demand in industry with theremaining hydrogen demand coming from industrial heat. To better understand whereand by when hydrogen is required in those energy-intensive industries installationspecific¹⁰ decarbonisation roadmaps were created. The bottom-up pathways are
informed by company announcements, sector decarbonisation roadmaps andinterviews with relevant stakeholders. Although there is a risk of relocation, bothwithin and outside of Europe, due to high costs for decarbonisation, we assume
that policy measures are put in place that prevent relocation and carbon leakage.
At the same time,relocation of fuel or steel production within Europe, for instanceto renewable energy abundant regions in Spain or the Nordics, is also possible.
However, in case of an EHB, hydrogen can be transported at low cost acrossEurope to the benefit of industrial sites located in regions with little renewables
potential. This study assumes that in these cases the hydrogen could be transported
instead of relocating the industry.. Each installation is associated with a certain NUTS
2 region¹¹. If an installation starts using green or blue hydrogen, demand in therespective NUTS 2 region for hydrogen increases.

Apart from hydrogen demand in the focus sectors, mainly as feedstock,
additional demand can arise in the remaining industry, for industrial heat. Section
2.1.5 analyses demand for hydrogen in low-, medium- and high-temperature industrial
processes. While full electrification is expected for low-temperature heat due to theavailability of suitable technologies and the associated efficiency gains compared to
combustion processes, hydrogen will play a larger role in decarbonising mediumand especially high-temperature processes.
The following figures show the demand for green and blue hydrogen demand
per NUTS 2 region (grey hydrogen demand is not shown). As displayed in Figure  2,
there is already significant hydrogen demand in 2030 (293 TWh) mostly comingfrom fuel/HVC production. It is important to note that hydrogen demand for HVC
is located at the fuel production installation (see section 2.1.3). There are alreadypronounced hydrogen demand hubs, most notably in Northwest Europe and partsof Southern Italy, Spain and France. Further, limited, hydrogen demand is scatteredacross Europe. As these maps are based on current production locations, newindustrial hydrogen hubs such as around steel production in North Sweden witha potential hydrogen demand of 30-40 TWh/year¹², or e-fuels production in theNordics are not portrayed in these maps.

FIGURE 2
Expected industrial green and bluehydrogen demand 2030 based on industry
decarbonisation roadmaps of existing
installations(in TWh/year)

Green and Blue hydrogen
demand in industry 2030
Ammonia<1

Fuel production and HVC

1–5

Steel

> 5–15

Industrial process heat

> 15

56

7

55
175

Source: Guidehouse analysis

12

Based on 48 TWh/y of electricity demand forhydrogen production taken from Fossil Free
Sweden (2020) p.26: https://fossilfrittsverige.se

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
14

By 2040, hydrogen demand in fuel/HVC production, iron & steel, ammonia andindustrial process heat is expected to grow exponentially to 836 TWh per year (seeFigure 3). Northwest Europe and parts of Southern Spain, Italy and France continue
be the largest demand region. There is also a growing hydrogen demand in Eastern
Europe, e.g., in Romania.

FIGURE 3
Expected industrial green and bluehydrogen demand 2040 based. on
industry decarbonisation roadmaps ofexisting installations(in TWh/year)

Green and Blue hydrogen
demand in industry 2040
Ammonia<1

Fuel production and HVC

1–5

Steel

> 5–15

Industrial process heat

> 15

165

53

144
495

Source: Guidehouse analysis

FIGURE 4
Expected industrial green and bluehydrogen demand 2050 based on industry
decarbonisation roadmaps of existing
installations(in TWh/year)

Green and Blue hydrogen
demand in industry 2050
Ammonia<1

Fuel production and HVC

1–5

Steel

> 5–15

Industrial process heat

> 15

217

113

179

691

Source: Guidehouse analysis

By 2050, hydrogen demand in industry grows further and is expected to
be spread across Europe (see Figure 3) and total demand is estimated to reach
1,200 TWh per year.
Figure 5 summarises the forecasted industrial hydrogen demand per country byeach industrial sector in 2030, 2040, and 2050.
ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
15

Figure 5

Ammonia
Fuel and HVCs

Summary of industrial green and bluehydrogen demand in 2030, 2040, 2050 bycountry based on current install ¹³

Steel
Industrial process heat

AT
2030
BE

2040
2050

BG
CZ
DE
DK
EE
EL
ES
FI
FR
HR
HU
IE
IT
LT
LU
LV
NL
PL
PT
RO
SE
SI
SK

13

Countries with no projected industrialhydrogen demand are not shown

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
16

250
TWh

200

150

100

50

0

UK

Source: Guidehouse analysis

2.1.1. Iron & steel
Key messages– This study has performed an installation-specific bottom-up analysis to estimatehydrogen demand in steelmaking. A combination of the widely available andoften detailed decarbonisation strategies of Europe’s steelmakers, interviews
with the steelmakers and inhouse expertise were used to determine a specifictransformation pathway up to 2050 for every primary steel plant in the EU+UK.
– Direct reduction of iron ore using hydrogen (DRI) is foreseen as the solution to
decarbonise primary steelmaking, next to an increase in secondary steelmaking
using recycled steel (scrap). By 2050, a 50/50 split between primary andsecondary steelmaking is expected, where in primary steel making hydrogen
DRI will become the main production method. In the intermediate period, otherdecarbonisation routes such as CCUS and using natural gas in DRI are assumed
to play a role when hydrogen is not yet available at the large scale required(~7 TWh/year of hydrogen for the average primary steel plant).
– Hydrogen demand in steel making is forecasted to be 55 TWh/year by 2030 andhereafter almost triple to 143 TWh/year by 2040. By 2050, hydrogen demandin fully decarbonised steel sector in the EU+UK is foreseen to be 179 TWh/year.
The steel sector today is the largest industrial emitter of CO₂ in Europe, emitting
22% of industrial GHG emissions and 4% of Europe’s total emissions.¹⁴ Today’s steel
production in EU+UK is split up in primary (59%) and secondary (41%) steel making.
For primary steelmaking in Europe the predominant production method is
integrated steel making or Blast Furnace/Basic Oxygen Furnace (BF/BOF), using ironore as feedstock next to coke and coal, which are also the main energy carriers.
In the EU+UK, around 30 larger BF/BOF steel making plants produced on average
100 million tonnes of steel per year between 2010 and 2018. These large plants havean average production capacity of 3.75 Mt/year, the largest being ThyssenKrupp
Steel's plant in Duisburg, Germany and ILVA in Taranto, Italy – both can produce
around 11.5 Mt/y of crude steel.
In secondary steelmaking the main route is Scrap-Electric Arc Furnace (ScrapEAF), which uses scrap (recycled steel) as feedstock and electricity as main energy
carrier, while also needing a limited amount of natural gas or coal for its carbon
content. The more dispersed ~130 Scrap-EAF plants in EU+UK produced around65-70 Mt/y between 2010- 2018 and are significantly smaller in size; the average
production capacity of a Scrap-EAF plant in the EU+UK is around 0.615 Mt/year¹⁵.
Decarbonisation options

14

15
16

17

Roland Berger (2020) available at https://www.rolandberger.com/en/Insights/
Publications/Europe's-steel-industry-at-acrossroads.html
https://www.eurofer.eu/assets/Uploads/
European-Steel-in-Figures-2020.pdf
Removing oxygen chemically from asubstance is called reduction. The industrial
production of iron involves reducing iron oxide
in a Blast Furnace. Most of the iron oxide is
reduced using carbon monoxide gas. This gas
is a reducing agent which takes the oxygenaway from iron oxide.
Taken from company websites.

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
17

Primary steel making: The decarbonisation of primary steel involves replacing
the energy carrier and reducing agent¹⁶ in the process, coke/coal, with a fossilfree alternative and to fully decarbonise also the process itself needs to completelytransform, moving away from the BF-BOF route. Direct reduction of iron (DRI)with hydrogen is seen as the prime solution to decarbonise primary steel making,confirmed by major steelmakers in Europe such as SSAB, Voestalpine, Thyssenkrupp
steel, Salzgitter and Liberty Steel¹⁷.
In hydrogen-based steel making, hydrogen is used to directly reduce iron in a
direct reduction (DR) plant to produce sponge iron, which in turn can be melted in
an EAF to produce steel. To facilitate transportation, it can also be compacted into
hot briquetted iron (HBI). This production route requires 1.88 MWh (56.3 kg) ofhydrogen per ton of crude steel. Assuming an average primary steel plant of 3.75
Mt/y, this would lead to a substantial hydrogen demand of 7.05 TWh/year for the
average European primary steel plant.

However, on the road to decarbonisation by 2050 via DRI with hydrogendifferent alternatives provide for intermediate solutions, as the hydrogen DRI process
would be dependent on the availability of large amounts of cheap hydrogen.
In the intermediary period, (1) natural gas or biomethane can be used insteadof hydrogen in a DR plant, or on the other hand (2) a first step could be to injecthydrogen in the Blast Furnace to replace part of the coal or coke. An alternative(3) would be to capture and store the CO₂ (CCS) or use it in the production ofsynthetic fuels or chemicals (CCU). The production of synthetic products using
carbon captured from the Blast Furnace flue gases, as for instance ThyssenKrupp
steel’s Carbon2Chem¹⁸ project, would require a substantial amount of hydrogen,5.05 MWh (151.5 kg)¹⁹ of hydrogen per ton of crude steel.
Next to hydrogen-based steelmaking, an increase of secondary steel making is
expected, increasing its share from 40% now to 50% by 2050, still being limited by
the availability of scrap.
Secondary steel making: The decarbonisation of secondary steel does notcome with a complete transformation of the process, but merely with switching to
renewable electricity, while additionally the limited amount of natural gas needed in
the EAF could be replaced with biomethane or synthetic methane which would leadto additional hydrogen demand.²⁰
Pathway towards 2050

18

19

20

21

22

23
24

ThyssenKrupp (2020) available at https://www.thyssenkrupp.com/en/newsroom/
content-page-162.html
For the CCU route it is assumed to be always
combined with hydrogen injection into theblast furnace, as the route complement one
another in terms of efficiency
The potential for additional hydrogen demand
for synthetic methane to replace natural gas
in secondary steelmaking is not considered inthis analysis.
Available at https://www.eurofer.eu/aboutsteel/learn-about-steel/where-is-steel-madein-europe/
https://www.eurofer.eu/assets/Uploads/
EUROFER-Low-Carbon-Roadmap-Pathwaysto-a-CO2-neutral-European-Steel-Industry.pdf
GrInHy2.0 project. Available at https://www.
green-industrial-hydrogen.com/
Available at https://www.thyssenkrupp-steel.
com/en/company/sustainability/climatestrategy/climate-strategy.html

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
18

This study has performed an installation-specific bottom-up analysis to estimate hydrogen
demand in steelmaking. A combination of the widely available and often detailed
decarbonisation strategies of Europe’s steelmakers, interviews with the steelmakers
and inhouse expertise were used to determine a specific transformation pathway up to2050, for every primary steel plant in the EU+UK. Below some illustrative examples ofthe decarbonisation pathways of exemplary plants are described. Additionally, some
general assumptions were made and applied to all plants. The production capacitiesof the steel plants were taken from the European steel association EUROFER²¹ andan 80% utilisation rate is assumed. The change in European steel production is takenfrom Material Economics’ modelling based on EUROFER, which yields a ~0.6% yearly
increase in the steel stock/capacity up to the 2040s, when it stabilises at 193 million
tonnes per year, up from 170 million tonnes per year today. At the same time, theshare of secondary steel production is expected to increase to 50%, as less scrap will
be exported out of Europe to now serve decarbonisation of steel production in theEuropean market.²² In this study the increase of scrap use is incorporated by downsizing
the DR plant compared to the EAF with ~8% of capacity, for every steel plant switching
to DRI-EAF steel making. Below some illustrative examples of the decarbonisation
pathways of exemplary plants are described. Another notable example not mentioned
below would be Salzgitter in east Germany which intheir gradual switchtswitch tohydrogen DRI steelmaking also showcases the use of waste heat from steel production
inwith high temperature electrolysis to reach electrolyser from Sunfire reaching highelectrical efficiency of up to 84% (LHV)²³.
– Thyssenkrupp Steel Europe Duisburg (Germany)²⁴: Europe’s largest plant interms of production with a capacity of 11.5 Mt/year of steel has set out to fully
decarbonise by 2050. The strategy here is to introduce CCU (Carbon2Chem)
while at the same time changing the four blast furnaces to (hydrogen operated)
DR plants. The DR plants will also be able to partially or totally use natural gas
in the transition period, if hydrogen is not available at the required scale. Thistransition is forecasted to lead to a hydrogen demand of 8 TWh/year alreadyby 2030, 15 TWh/year by 2040 and 18 TWh/year by 2050, using the generalassumptions as stated above. Note that the scale up of the Carbon2Chem
project would lead to additional hydrogen demand of ~10 TWh/year from 2030
onwards, to avoid double counting we assume this hydrogen demand to be
included in the fuel production section of this study.

25 Available at https://www.ssab.com/company/
sustainability/sustainable-operations/hybrit
26 Available at https://automotive.arcelormittal.
com/news_and_stories/news/2020Oct_
EuropeGreenSteel
27 AD Little (2020) Available at https://www.
smartdeltaresources.com/sites/default/files/
inline-files/200911_SDR_%201%20GW%20
Electrolyzer_FINALReport_vEXTERNAL_1.pdf
28 https://www.futurenetzero.com/2020/11/12/
liberty-steel-launches-tender-for-greenfurnaces-at-ostrava/
29 https://www.metalbulletin.com/
Article/3936788/Liberty-Steel-to-installEAFs-DRI-module-to-make-Galati-plant-inRomania-carbon-neutral-by-2030.html– SSAB Luleå, Oxelösund (Sweden) and Raahe (Finland)²⁵: SSAB, which has threeplants in the Nordics with a total production capacity of 6 Mt/year of steel, isplanning to be carbon neutral already by 2045, which would reduce Swedish
CO₂ emissions by 10% and Finnish by 7%. Working together with energy
company Vattenfall and iron ore producer LKAB, it is currently building the pilotof hydrogen-based reduction and smelting plants, called “HYBRIT”, and plans
to transform all the BFs to EAFs in the three locations between 2030-2040. This
would lead to hydrogen demand of 5 TWh/year by 2030 and 10 TWh/year by2040 and onwards in the model.
– ArcelorMittal Ghent (Belgium)²⁶, ²⁷: ArcelorMittal wants to be carbon neutral
by 2050. In its 5 Mt/year plant in Ghent it plans to use CCU (‘smart carbon’)converting carbon containing gas to produce Ethanol or “Steelanol”, while
also transporting waste gases (CO/CO₂) to Dow Chemical in Terneuzen (theNetherlands), where it is used in the production of synthetic naphtha. Next tothis, ArcelorMittal also replaces coal in the blast furnace with biomass. This study
assumes that the CCU route is temporary and considering the investment cyclewith the only recently relined blast furnaces; a (full) switch to the DRI-EAF routeis only expected by 2050. Leading to a 4 TWh/year hydrogen demand in 2030
and 2040 which increases to 8 TWh/year by 2050, in the model.
– Liberty Steel Ostrava (Czech Republic)²⁸ and Galati (Romania)²⁹: The two Liberty
Steel plants in Czechia and Romania, with 3.6 and 3.2 Mt/year of capacity, are
set to become carbon neutral by 2030, following Liberty Steel’s ambitious 2030
carbon neutrality target. The plant in Ostrava will completely switch to secondary
steelmaking. Hereby, Liberty Steel will transform the integrated steelmaking plants
into hybrid plants allowing a gradual switch to use scrap as the only feedstock,leading to an emissions reduction of 60% by 2023 and 100% by 2030. The plant
in Galati aims to replace the BOF with one 2.5 Mt/year DRI plant and two EAFs,
also already by 2030 leading to a hydrogen demand of over 3 TWh/year, in themodel. At the time of writing, Liberty Steel was experiencing serious financial
problems, with an unknown impact on its emission reduction plans.
Figure 6 shows the annual energy demand for steel in TWh up to 2050. An overall
decrease in energy demand despite growing steel production results from the moreenergy-efficient scrap-EAF and hydrogen DRI-EAF processes. Hydrogen demandin steel making is forecasted to be 55 TWh/year by 2030 and 143 TWh/year by
2040. By 2050, hydrogen demand in fully decarbonised steel sector in the EU+UK isforeseen to be 180 TWh/year. A small share of natural gas and PCI (pulverized coal
injection) is still needed for the carbon in the steel, both would come from biogenic
sources.
700

FIGURE 6600

Expected development of annual
energy demand in steelmaking
from 2020-2050

500
400
300
200

Electricity
Coking Coal100

PCI Coal
Bio-Methane/Natural Gas
Hydrogen

0
2020

2030

2040

2050

Source: Guidehouse own analysis with installation specific pathways based on company announcements
ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
19

This analysis is bottom-up and does not consider two potential threats to steel
production in Europe: (1) partial relocation and (2) the increase of steel imports.
Since the decarbonisation of steel requires vast amounts of hydrogen and electricity(in the case of green hydrogen), production might shift to locations with morefavourable conditions for renewable energy, inside or outside of Europe. An
example are the plans in north Sweden, where a new player in the steel market, H₂
Green steel³⁰, plans to produce 5 million tons of hydrogen-based steel before 2030
using Sweden’s excellent wind conditions.
In hydrogen-based steelmaking the production could even be split up, where
the DR plant would be relocated to RES abundant countries, as the HBI which it
produces is solid and relatively easily transported and then further melted in an
EAF elsewhere. When decoupling the DR plant from the EAF plant, the loss of this‘hot connection’ would cause some efficiency losses, but these losses could becompensated by the cheaper hydrogen. An example once more in north Sweden,
where LKAB plans to at large scale produce and export sponge iron, instead of theiron ore it exports today³¹. This could lead substantial additional hydrogen demandof 30-40 TWh/year of hydrogen demand in north Sweden³².
However, the European Hydrogen Backbone could provide an alternative torelocation by transporting the hydrogen instead of the end-product, in this case steel
or sponge iron. Moreover, steel plants in Europe are often integrated into larger
industrial clusters (e.g. the ThyssenKrupp steel site in Duisburg is integrated in the
Ruhr cluster, one of the largest industrial clusters in Europe) and (partial) relocation
would have a severe impact on integrated value chains, while also the impact on
employment in these regions would need to be considered.

2.1.2. Ammonia for fertilisers
Key messages– In the absence of information on installation specific decarbonisation routes,
we assumed steam methane reforming (SMR) with CCS, water electrolysis,
and biomethane as the main decarbonisation options and estimated theirimplementation based on projected readiness of technology, cost competitivenessand attitude towards CCS.
– Production capacity of ammonia is projected to remain constant at 19.1 Mt/y,translating to 113 TWh/year of hydrogen. The existing production of grey hydrogen
will gradually be replaced with blue hydrogen, especially in the short-term, whilegreen hydrogen and biomethane will play a larger role in the mid- to long-term.
Demand for green and blue hydrogen is expected to be 7 TWh/year in 2030,
53 TWh/year in 2040 and 113 TWh/year in 2050.
– Provided technological advances occur, ammonia could become a fuel for the
maritime sector, which would increase demand. Furthermore, there is alreadyan established ammonia trade, so ammonia imports from regions with low-costhydrogen production could threaten European ammonia production.
30 https://www.H₂greensteel.com/home
31 https://www.lkab.com/en/news-room/pressreleases/historic-transformation-plan-forlkab-the-biggest-thing-we-in-sweden-can-dofor-the-climate/
32 Hydrogen_strategy_for-_fossil_free_competitiveness_ENG.pdf (fossilfrittsverige.se)

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
20

Ammonia is a foundational chemical of the fertiliser industry, used both as afertiliser itself and as a building block for other fertiliser chemicals, such as ammonium
nitrate. Roughly 90% of global ammonia production is for the fertiliser industry.
Ammonia is produced via the Haber-Bosch process, in which nitrogen is reactedwith hydrogen. The nitrogen feedstock is extracted from the air. The hydrogen is
traditionally produced from fossil fuels by SMR, producing CO₂ in the process.

Ammonia is produced in many countries across Europe (19,132 kt/y total in2019), with the largest production in Germany (3,130 kt/y), Poland (2,520 kt/y),
the Netherlands (2,140 kt/y), Romania (2,020 kt/y), and the UK (1,595 kt/y). Mostof Europe’s ammonia trade is conducted within Europe, with imports and exports
nearly equal.³³ Some fertiliser chemicals, namely urea and its derivatives, containcarbon. Urea is produced by reacting ammonia with CO₂ produced by the SMR.
Therefore, in order to continue to produce urea, producers must either produce
ammonia in a way that also produces CO₂ or source CO₂ from elsewhere. Urea andits derivatives account for approximately 35% of fertiliser production in Europe.³⁴
Current ammonia production generates 1.83 tonnes of CO₂ per tonne of ammonia
on average, and 1.3% of total CO₂ emissions in the EU³⁵. Two thirds of emissions
are process emissions from the upstream hydrogen production from SMR, and theremaining emissions are from the combustion of fuels for heat and compression.
Decarbonisation options

33 https://oec.world/en/profile/hs92/
ammonia?redirect=true
34 https://www.fertilizerseurope.com/uploads/
media/Industry_Facts_and_Figures_2019.pdf
35 Material Economics – Industrial
Transformation 2050
36 https://www.sciencedirect.com/science/
article/pii/S1364032114005450
37 https://www.noble.org/news/publications/ag-news-and-views/2006/july/weigh-proscons-when-choosing-summer-nitrogensource/#:~:text=Urea%20has%20several%20
advantages%2C%20including,to%20
ammonium%20carbonate%20by%20urease.

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
21

Today, fossil hydrogen produced via SMR is the industry standard feedstock forammonia production. In our analysis, we identified three decarbonisation options
for the ammonia industry, all focused on the upstream hydrogen production step inammonia production where the bulk of emissions occur.
Carbon capture: CCS can be applied to SMR to switch from fossil to bluehydrogen production in order to reduce emissions from ammonia production by up
to 95%. While the first 60-65% is relatively inexpensive to capture (since it relates
to pure CO₂ from the SMR process) the additional 30-35% is less economical.³⁶
Carbon capture leads to additional electricity consumption because the captured
CO₂ needs to be compressed, transported, and stored.
Water electrolysis: Green hydrogen can be produced via electrolysis to replace
the SMR. Electrolysis of water consumes about 10.8 MWh of electricity per tonne ofammonia, and if renewable electricity is used to power all equipment, this pathway
reduces total emissions to zero.
Biomethane: Without any changes to the process itself, the natural gas feed
used for SMR is replaced by biomethane, resulting in carbon neutrality. Furthermore
digestate, the by-product of biomethane production, can be used to produce
agricultural fertilisers. Since electrolysis does not produce CO₂ and Europe’s energy
system will shift away from fossil fuels, using biomethane may be the only acceptablelong-term urea production pathway. Note that CO₂ is required for urea production
only, not ammonia production.
Installations that produce blue hydrogen using CCS may later use biomethane
instead of fossil methane (bio energy CCS (BECSS)) as feedstock, leading to negativeemissions or climate-positive hydrogen. It is important to note that biomethane will
typically be sourced from agricultural regions and much of the blue hydrogenproduction will be located near natural gas deposits. Assuming the continued
existence of a natural gas grid, methane reforming operators can circumvent this bypurchasing green certificates for biomethane injected elsewhere.
Urea is a popular fertiliser in part because of its low cost.³⁷ As the industry isdecarbonised, urea may become more expensive to produce as biogenic CO₂
will need to be sourced to produce it without generating emissions. Therefore,
production and usage may decrease.

Pathway towards 2050

38 CEFIC/DECHEMA (2019): Low carbon
energy and feedstock for the European
chemical industry, https://cefic.org/app/
uploads/2019/01/Low-carbon-energyand-feedstock-for-the-chemical-industryDECHEMA_Report-energy_climate.
pdf; VCI (2019): Auf dem Weg zu einer
treibhausgasneutralen chemischen
Industrie in Deutschland, https://www.vci.
de/vci/downloads-vci/publikation/201910-09-studie-roadmap-chemie-2050treibhausgasneutralitaet.pdf; VNCI (2018):
Roadmap for the Dutch Chemical Industry
towards 2050, https://vnci.nl/Content/Files/
file/Downloads/VNCI_Routekaart-2050.pdf
39 NUTS (Nomenclature of territorial units
for statistics) is a system for dividing the
economic territory of the EU and UK forstatistical purposes

While there are limited company announcements on decarbonisation pathways,
national and European chemical associations have identified blue hydrogenproduction via SMR with CCS or water electrolysis as the primary decarbonisation
options.³⁸ For the purposes of this analysis we categorised countries based onwhether or not they are likely to be an early adopter of decarbonisation technologies,
and whether or not they are likely to implement blue hydrogen. For example, it isassumed that CCS in Germany is reserved for unavoidable process emission (e.g.
from cement) due to the Government’s critical attitude towards carbon storage andnot needed in Spain for blue hydrogen production due to the possibility to produce
green hydrogen at large scale relatively cheaply.
Europe’s ammonia production for fertilisers is assumed to be constant at roughly
19.1 Mt/year until 2050. Ammonia is also considered as a promising fuel forshipping, but this is not included in this section and further discussed in the fuelproduction (see 2.1.4) and transport sections (see 2.2.3).
For the decarbonisation pathways we then assumed a breakdown of traditional
SMR, SMR with CCS, water electrolysis, and biomethane use in 2030, 2040, and2050 for each category of country based on the projected readiness of technology
and cost competitiveness. In the absence of installation level announcements, therelevant split was applied to each installation based on the country it is located in.
For example, all Belgian installations in 2040 are assumed to produce their ammonia
from 20% SMR without CCS, 20% SMR with CCS, 50% electrolysis, and 10%
biomethane. In reality, each installation will likely only use one pathway, however
applying a specific pathway to each installation would be arbitrary and would
skew the analysis of energy carrier demand on a NUTS 2 level.³⁹ SMR is graduallyreplaced mostly by electrolysis. SMR with CCS using natural gas is used in 2030
and 2040, however by 2050 it is replaced by electrolysis and biomethane to meetthe long-term goal of a climate neutral European energy system.
Figure 7 shows the projected annual demand for each energy carrier forammonia production through 2050 in TWh/year. Total hydrogen demand forammonia production remains constant at 113 TWh/year. Grey hydrogen is graduallyreplaced by green and blue hydrogen starting in 2030 due to decreasing costs ofdecarbonisation technologies and increasing CO₂ prices.

120

FIGURE 7
Development of the European
annual hydrogen demand in ammonia
production from 2020-2050

100
80
60
40

Green and blue hydrogen
Grey hydrogen02020
Source: Guidehouse analysis

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
22

2030

2040

2050

TWh

20

While there is a strong push by national governments and the EU to support
the net-zero transition of the chemical industry, for ammonia there is a real risk ofrelocation. Ammonia is already widely traded internationally and is generating interest
as a potential zero-carbon fuel, which would increase the scale of production andtrade. Therefore, European ammonia production could relocate to areas outside ofEurope with cheap renewables. For the purpose of this analysis we did not examine
global costs of ammonia production and transport. We assumed that European
production will remain competitive with imports due to a favourable regulatoryenvironment and because transport will increase the cost of imported ammonia.

2.1.3. High value chemicals
Key messages“To achieve the politicallydefined decarbonisation goalby 2050, the hydrogen demandof the chemical industry will
increase significantly in the
future. Considerable long-term
reinvestments in production
plants and infrastructure are
required over the next few
decades, if we want to keep
our chemical industry base inEurope. For that we need aninvestment-friendly framework
alongside the confidenceof the industry in a secured
availability of sufficientquantities of competitively
priced hydrogen. The EHB
contributes significantly inproviding that.”
Detlev Wösten
Chairman VCI Nord

– There is still a lot of uncertainty around the decarbonisation of High Value
Chemicals (HVCs) – mainly used in plastics production. Therefore, ahomogenous approach is applied to all existing HVC production sites. In reality,
different locations will choose different pathways for the process and feedstock
decarbonisation, very much dependent on the available feedstocks such ashydrogen and biomass.
– This study therefore assumes an end-state in 2050 with an even three-way split
between the process decarbonisation options (cracking, methanol-to-olefins andconventional steam cracking with a decarbonised energy carrier) and the threenaphtha or methanol feedstock decarbonisation options (synthetic, bio-based andchemically recycled). Hydrogen demand is forecasted at 67 TWh in 2030, 164
TWh in 2040 and 291 TWh. The hydrogen demand for the feedstock is assumed
to be located at fuel production sites, as it is today and thus it is included in thefuel production section (see 2.1.4).
HVCs in the EU+UK are produced in steam crackers, where long-chainhydrocarbons are cracked into short-chain hydrocarbons. The main HVCs are
ethylene, propylene, butadiene (also referred to as olefins), benzene (representative
for the aromatics), while also hydrogen and methane are produced in the cracking
process. The main feedstocks used in steam cracking in the EU+UK are naphtha(70%), gas oil (10%), and gasses like ethane, butane and propane (17%). These
feedstocks are also used as energy carrier, roughly 30% of their energy content isburned in the energy-intensive cracking process (700-900°C). The HVCs which areproduced, mostly ethylene and propylene, are widely traded products and used to
produce plastics, and a range of other products.
The EU+UK currently counts ~55 steam crackers, with an average production
capacity of just under 0.5 Mt/y per installation. One of the largest steam crackers
in the EU+UK is currently being constructed by Ineos Antwerp, with an ethylene
capacity of 1.25 Mt/y⁴⁰, after which the Antwerp/Rotterdam region will have 23%of the EU+UK cracking capacity in terms of ethylene. In Northwestern Europe, thesteam crackers are usually integrated in large industrial/petrochemical clusters.
Germany, Netherlands and Belgium together account for 42% of the EU+UK ethylene
production capacity.
Decarbonisation options

40 http://www.mrcplast.com/news-news_open382294.html
41 https://ec.europa.eu/clima/sites/clima/files/
ets/allowances/docs/bm_study-chemicals_
en.pdfANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
23

The production of HVC in the EU+UK accounts for about 18% of Europe’s chemical
GHG emissions⁴¹ and the decarbonisation pathways per company or specificinstallation are largely unknown. This study structures the decarbonisation twofold –into the process and the feedstock:Process: Three options exist for the cracking process to decarbonise:– Change of feedstock (in the cracking process): The first would not need
any alterations to the cracker or process but merely change its fossil feedstock(naphtha, gas oil, ethane, butane etc.) into a decarbonised fuel, e.g., bio- orsynthetic naphtha or a chemically recycled feedstock (pyrolysis oil).
– Electrifying the cracking process: It would provide a less resource-intensive
decarbonisation option for the cracking process. However, electric crackers do
not yet exist, although the world’s largest petrochemical companies are currently
developing this technology (BASF/Linde/SABIC⁴² and Shell/DOW⁴³).
– Complete transformation of the process and feedstock to produce HVCs
(MtO): This means to convert methanol to ethylene, propylene and butadiene,a process which is called Methanol-to-Olefins (MtO). This process is alreadyapplied at scale with fossil-based methanol in for instance China⁴⁴. But in thiscase, the methanol feedstock would need to be decarbonised too.

42 https://www.basf.com/global/en/
who-we-are/sustainability/whats-new/sustainability-news/2021/basf-sabic-andlinde-join-forces-to-realize-wolds-firstelectrically-heated-steam-cracker-furnace.
html
43 https://www.shell.com/business-customers/
chemicals/media-releases/2020-mediareleases/dow-and-shell-team-up-to-developelectric-cracking-technology.html
44 https://www.methanolmsa.com/mto/
45 https://energy.nl/wp-content/
uploads/2020/09/Pyrolysis-oil-productionfrom-plastic-waste_28-09-2020.pdf
46 https://enerkem.com/news-release/w2crotterdam-project-welcomes-shell-aspartner/#:~:text=Enerkem%20produces%20
advanced%20biofuels%20and,and%20
other%20widely%2Dused%20chemicals.
47 https://greenchemicalsblog.com/2012/11/08/
neste-oil-expands-in-bio-naptha/
48 https://www.climate-kic.org/wp-content/
uploads/2019/04/Material-EconomicsIndustrial-Transformation-2050.pdf
49 http://www.steelanol.eu/en
50 https://dspace.library.uu.nl/bitstream/
handle/1874/32318/ren.pdf?sequence=2

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
24

Feedstock: The feedstocks to produce HVCs, naphtha, gas oil and gases likeethane, butane and propane, are not easy to decarbonise as they need to containcarbon, which ends up in the HVCs and final products, such as plastics. Three main
options exist for both (1) the feedstock in the cracking process, as well as (2) the
methanol in MtO:
– Chemical recycling: The first and least resource-intensive option is chemicallyrecycled feedstock, where pyrolysis oil from non-recyclable plastic waste is turned
into feedstock for the cracking process, trialled by SABIC in the Netherlands⁴⁵.
Methanol for MtO can also be produced from non-recyclable plastic waste, aprocess referred to as waste-to-methanol, trialled by among others Shell andEnerkem in Rotterdam⁴⁶. Other residue waste flows could also provide an option
here, although plastic waste would be the most obvious and circular one.
– Bio-based: The second option would be to use biomass to produce naphthaor methanol. Bio-naphtha would be made by severe hydrocracking, as done by
Neste⁴⁷, while bio-methanol can be produced using gasification or anaerobic
digestion⁴⁸.
– Synthetic: The third option considered is to use electricity as basis to produce
synthetic naphtha or methanol. This process requires a lot of energy while asource of carbon is also needed. The “Steelanol” project from ArcelorMittal and
Dow Chemical around Ghent⁴⁹ uses the carbon from steel production, but in the
future this process would need a biogenic source or direct air capture (DAC) of
CO₂ to be carbon neutral.
Table 1 shows the hydrogen demand for the different feedstock decarbonisationroutes. For simplicity reasons only naphtha is considered as input for the electricand steam cracker. The substantial range in hydrogen demand per ton of HVCs,
from 0 to 15.75 MWh, shows the large possible impact on hydrogen demandof HVCs production. The decisive factors in assessing the future role for eachof the different routes are the costs and availability of resources for the three
feedstock routes (chemical recycling, bio-based, synthetic). These resources aremainly (non-recyclable) plastic waste for chemical recycling, biomass for the biobased route for the biogenic routes and hydrogen and biogenic or direct air
capture (DAC) CO₂ for the synthetic route. In cracking, hydrogen is also produced
as by-product in the process, at around 1% on a weight basis per ton of HVC for
naphtha cracking⁵⁰.

TABLE 1

Feedstock for

Range of Hydrogen demand fromdifferent feedstocks for HVCs
production

HVC production

Hydrogen demand

Hydrogen demand

MWh/ton ofnaphtha or methanol

MWh/per ton
of HVCs

Bio naphtha⁵¹

0.78

1.30

Synthetic naphtha

5.85

9.75

Naphtha like pyrolysis oil⁵²

0.00

0.00

Bio methanol⁵³

2.00

5.00

Synthetic methanol

6.30

15.75

Waste to methanol

3.33

8.33

Source: Material Economics (2020), Ren (2006), RoyalHaskoning DHV (2018) and own analysis

Pathways towards 2050

51

52

53

54

55
56

57

In the cracking process hydrogen is also
produced as by product (0.56 MWh per tonof Naphtha input); this is subtracted from thehydrogen demand for all routes using naphtha
The hydrogen demand for naphtha likepyrolysis oil is unknown and therefore assumed
to be equal to the hydrogen production, thus
leading to no hydrogen demand – similar as
material economics (2020)
The Bio methanol route is based on two
representative routes from Material Economics(2020), page 127: Gasification and Anaerobic
Digestion (50% each). The routes represent
the range of potential feedstocks and uses,with the Anaerobic Digestion using ~10 MWhof hydrogen per ton of HVCs and Gasificationnone, while Gasification route would need
3.5 tonnes of dry biomass and Anaerobic
Digestion route only 1.9 tonnes per ton of HVCs.
The anaerobic digestion route to methanol interms of process is coming close to synthetic
methanol with biogenic CO₂ and could
therefore also be categorized as such. However,in this study this route is used to illustrate therange of feedstocks which can be used.
https://www.ogj.com/refining-processing/petrochemicals/article/17237013/internationalsurvey-of-ethylene-from-steam-crackers-2015https://dspace.library.uu.nl/bitstream/
handle/1874/32318/ren.pdf?sequence=2
https://www.climate-kic.org/wp-content/
uploads/2019/04/Material-EconomicsIndustrial-Transformation-2050.pdf
VNCI Routekaart Ecofys (2018) available
at https://www.vnci.nl/Content/Files/file/
Downloads/VNCI_Routekaart-2050.pdf

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
25

The decarbonisation pathway of HVC production in the EU+UK is uncertain, thepathway of the specific installations even more so. Little site-specific information
is available, especially in comparison to for instance the steel plants (see 2.1.1).
Therefore, this study assumes a homogeneous route for all the different plants, thus
assuming the same decarbonisation routes for every plant.
From the production capacities in ethylene and current fossil feedstocks (mostly
Naphtha)⁵⁴ per steam cracker, the total HVC production is determined, using
the conversion factors of table 2-2 from Ren (2006)⁵⁵, as the output of the steam
cracker depends on the feedstock it uses. HVC production could be expected toincrease slightly by 2050 due to higher demand for plastics. However, this increaseis assumed to be completely compensated by a higher share of mechanical recyclingof plastics.⁵⁶ Hence, we assume a constant production capacity of HVCs of 53 million
tonnes per year, calculated from 27 million tonnes of ethylene per year.
Given the breadth of decarbonisation options and the absence of installationspecific information on decarbonisation strategies, an even split between the three
options is assumed by 2050, thus leading to one-third conventional steam cracking
with a decarbonised feedstock, one-third electric cracking and one-third MtO by
2050. We assume that electric cracking will take off later than MtO due to its lower
TRL, when compared to MtO.
All three feedstock options (bio, chemically recycled and synthetic) seem equallyfeasible and no clear direction has been chosen by the industry, so for the time being
we assume an equal split between the options. Although the chemical recycling
route is the preferred route in terms of resource intensity, the route is limited by theavailability of plastic waste, and e.g. the Dutch chemical association (VNCI) reported
the long-term potential in the Netherlands at around 30%⁵⁷. Seeing the preference forthis route, it already has a relatively large share of 30% by 2040, when the technology
has matured. The share of synthetic feedstock is expected to be limited and comeup later in the 2040s due to its energy intensity and dependence on the still immature
DAC technology, or limited available biogenic sources of CO₂.

Figure 8 below shows the transformation of the feedstock for HVCs with the early
adoption of bio-based plastics, with chemical recycling taking off in the 2030s when
the technology matured and synthetic methanol and naphtha in the 2040s, whenmore renewable electricity would be available, and DAC has matured.

100 %FIGURE 8
HVC feedstock transformationfrom 2020-2050

80 %

60 %

20 %

Chemically recycled
Synthetic
Bio0%

Fossil

2020

2030

2040

Feedstock Share %

40 %

2050

Source: Guidehouse own analysis based on industry roadmaps and Material Economics (2020)

Production location
Today, the naphtha and other fossil-based feedstocks for the steam crackers areproduced at refineries either outside or within Europe, and the refineries are also
in some cases integrated with the steam crackers in an industrial cluster. This study
assumes that, similar as today, in the future the feedstocks for HVC production are(by) produced at refineries.
This assumption represents one scenario with of course significant degrees of
freedom. In the future, the decarbonised feedstocks can come from new bio, waste
product, or synthetic fuel refineries, of which the location has yet to be determined,
while importing is also an option. The locations will depend on the availability andcosts of feedstocks and energy carriers and proximity to the HVC plant. This can fore.g. synthetic fuels production mean a relocation to cheap RES abundant regions.
However, there are several reasons why this might not be the case and the scenario
this study assumes is in fact realistic:– Current refineries are mostly well-located in industrial clusters and/or port areas
which provide opportunities for industrial symbiosis and the option to import
feedstocks/energy carriers. Thus, although the production of the decarbonised
feedstocks are mostly new processes needing new installations, the strategic
location is still of importance.
– The European Hydrogen Backbone could provide a cheap transportation
option for the large amounts of low-carbon energy needed - in the form ofhydrogen - at a constant supply. Thus, transporting the hydrogen to refineries
instead of relocating the fuel production to RES-abundant regions andtransporting the naphtha/methanol. A green source of carbon would be neededat the same sites.
– Refineries today are integrated with the steam cracker, providing flexibility andability to use the other plant’s by-products. In the future, these advantages
remain.

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
26

These reasons provide the background for the assumption that all feedstocks for
HVC production will be produced at current refining locations. The capacity andfollowing hydrogen demand per refinery location is, similar to the fuels production
in section 2.1.4 determined using the current production capacity per refinerycompared to the total current oil refining capacity in the EU+UK. The dispersedhydrogen demand to produce the feedstocks for HVCs production totals 67 TWhin 2030, 164 TWh in 2040 and 291 TWh in 2050. This is substantially lower thanprevious Gas for Climate reports, as in this study chemical recycling and bio-based
feedstocks are considered for HVC production, instead of only MtO with synthetic
methanol. The hydrogen demand is thus accounted for in the fuel production
analysis (see section 1.1.4).

2.1.4. Fuel production
Key messages:– Fuel production is assumed to remain at the same refining location as today
in the EU+UK, where the EHB could play a vital role in transporting the large
amounts of hydrogen to fuel production locations. Relocation of fuel production
within or outside Europe would also be an option and it is reasonable to expect
the eventual end state to fall somewhere in between.
– Hydrogen demand for fuel production is forecasted at 175 TWh by 2030,
495 TWh by 2040 and 691 TWh by 2050. Hydrogen demand from fuelproduction in this study includes hydrogenation of fossil fuels, upgrading to bio
kerosene, synthetic kerosene and fuels for HVCs.

58 https://www.woodmac.com/news/opinion/
european-refining-at-the-rubicon-again-which-assets-will-make-it-over/

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
27

Today fuel production takes place in the EU+UK in about 85 refineries, whichhave a total capacity of 14.5 million barrels of oil per day and an average production
capacity of 175 thousand barrels per day. WoodMackenzie states that almost 10% ofrefining capacity in Europe is under threat to close before 2023⁵⁸, partly also due tothe corona virus pandemic.
Future fuels production in the form of bio-, recycled- or synthetic fuels would
not reach the levels of current refining capacity. Synthetic fuel production could
be relocated to where its main resources, green hydrogen and thus electricity andCO₂, are abundant and cheap. If the CO₂ would come from DAC it does not needa specific location, although the spatial footprint of DAC is substantial. Hereby,
Europe’s potential and competitiveness to produce synthetic fuels could be limited,
due to the substantial amounts of renewable electricity and land required. Still, it
can be argued that, next to the land and permitting, there are more reasons tolocate synfuel production at current refinery locations, which were partly alreadymentioned in the HVCs section.
– Current refineries are mostly well-located in industrial clusters and/or port areas
which provide opportunities for industrial symbiosis and the option to import
feedstocks/energy carriers. Thus, although the production of the synfuels aremostly new processes needing new installations, the strategic location is still ofimportance.
– The European Hydrogen Backbone could provide a cheap transportation
option for the large amounts of low-carbon energy needed - in the form ofhydrogen - at a constant supply. Thus, transporting hydrogen instead of
relocating fuel production to RES-abundant regions and transporting thenaphtha/methanol.

59 https://www.portofrotterdam.com/en/
doing-business/port-of-the-future/energytransition/hydrogen-in-rotterdam
60 https://www.neste.com/releases-and-news/
renewable-solutions/neste-selects-rotterdamlocation-its-possible-next-world-scalerenewable-products-refinery
61 Splash 247 (2020) https://splasH₂47.com/
finnish-firms-set-out-to-lead-e-fuel-race/
62 https://baltictransportjournal.com/index.
php?id=1160
63 https://www.airproducts.com/newscenter/2020/07/0707-air-productsagreement-for-green-ammonia-productionfacility-for-export-to-hydrogen-market
64 https://www.spglobal.com/platts/en/marketinsights/latest-news/petrochemicals/050421interview-worlds-largest-green-hydrogenproject-eyes-australian-ammonia-exports
65 https://asianrehub.com/
66 https://www.fchobservatory.eu/observatory/
technology-and-market/hydrogen-demand
67 Average of 3 technologies from Ricardo (2019)
Quantifying future hydrogen demand for
upgrading biofuels (page 22). Available athttps://cdn.ricardo.com/ee/media/assets/hydrogen-demand-for-upgrading-biofuelsfinal-report_v2-(002).pdf
68 Agora (2021) https://static.agoraenergiewende.de/fileadmin/
Projekte/2021/2021_02_EU_H₂Grid/AEW_203_No-regret-hydrogen_WEB.pdf
69 1 ton = 11.94 MWh for kerosene (LHV)

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
28

An example is the port of Rotterdam, home to five refineries with in total 8%of EU+UK’s current refining capacity, which has ambitious plans for hydrogenand renewable fuels to play a similar role as oil does today with an import andconversion terminal for hydrogen⁵⁹. Rotterdam also has been chosen by Neste for
their new “renewable products refinery” due to its resource availability and proximity
to renewable aviation, polymers and chemicals markets⁶⁰. On the other hand, newe-fuel projects have been announced in countries with already a high share of
renewable energy, where the availability of biogenic sources of CO₂ could also
play an important role. An example are the Nordics, where for instance in Finland⁶¹
and Denmark⁶² companies are partnering up to kickstart e-fuel production int thesecountries.
This study assumes that imports are limited to green ammonia production forshipping, as early signs show already large-scale green ammonia projects emerging
outside Europe in the MENA region (e.g. NEOM⁶³), Australia⁶⁴, and Asia⁶⁵. Enabledby the mature technique of nitrogen air separation, the production can move toareas with abundant solar and wind resources and land availability. The remaining
carbon-based synfuels production, in this study only synthetic jet-fuel, are spreadout over the EU+UK based on current refinery locations and capacities, adding to
the fuels used for HVCs production. The synthetic jet fuel demand is taken from theaviation section 2.2.2.
Next to this, hydrogen is also needed in refineries as a feedstock to hydrogenate
fossil fuels, which makes refineries actually the main user of hydrogen today⁶⁶. The
demand for refining fossil fuels, however, is expected to decrease to zero overtime with the phasing out of liquid fossil fuels. The remaining demand, today served
by grey hydrogen, is expected to transition to 100% blue and green hydrogen by2040.
In biofuel refineries biomass also needs to be upgraded using hydrogen,especially in the case of bio jet fuel due to the high energy density required foraviation fuels. The hydrogen demand for upgrading is dependent on the type ofbiomass, fuel and the process, while at the same time it also produces bio byproducts such as (bio) heavy fuel oil or (bio)naphtha. In this study, considering thescope of the transport section, only hydrogen demand for upgrading to bio kerosene
is considered, which as mentioned before is also the fuel which needs the mostupgrading. The hydrogen demand for upgrading to bio kerosene is dependent on
the production method and type of biomass and can range from 0.08 to 0.52 MWh
per MWh of bio-kerosene. Here, we assume the average of three technologies usedin Ricardo (2019)⁶⁷. The use of hydrogen directly as a fuel is an option, especially inaviation and shipping, but this is not included here in the fuel production section but
covered in the transport analysis (see section 2.2).
Hydrogen demand– For hydrogenation of fossil fuels the hydrogen demand today is 138 TWh/yearof grey hydrogen, but by 2030 is expected to have a 35% share (40 TWh) of
which is green or blue (of the decreased 115 TWh total) and 100% by 2040 (ofthe further decreased 15 TWh total), while in 2050 no liquid fossil fuels will need
to be hydrogenated in the EU+UK⁶⁸.
– Upgrading/Hydrogenation to bio kerosene is assumed to require 0.15 MWhof hydrogen per MWh of bio kerosene⁶⁷, ⁶⁹. Demand for bio kerosene is takenfrom the aviation section 2.2.2 at 51 TWh in 2030, 235 TWh in 2040, and
295 TWh in 2050. Hydrogen demand for upgrading to bio kerosene then comesto 8 TWh by 2030, 35 TWh by 2040 and 44 TWh by 2050.

– Synthetic kerosene requires 14 MWh (430 kg) of hydrogen per ton or 1.2 TWh
per TWh of syn-kerosene⁶⁹, and demand for synthetic kerosene is taken from theaviation section 2.2.2 at 51 TWh in 2030, 235 TWh in 2040, and 295 TWh in
2050. Hydrogen demand to produce synthetic kerosene is in turn forecasted to
be 6167 TWh in 2030, 282 TWh in 2040 and 355TWh in 2050.
– For fuels for HVCs production the hydrogen demand is calculated in section
2.1.3, at 67 TWh in 2030, 164 TWh in 2040 and 291 TWh in 2050.
Figure 9 below shows the forecasted hydrogen demand from fuel production,
at 175 TWh by 2030, 495 TWh by 2040 and 691 TWh by 2050. This hydrogen
demand is, as mentioned before, assumed to be located at the refineries andspread out based on the current capacity in barrels per day relative to the total sumof capacity for the EU+UK.

700

FIGURE 9
Expected development of annual
green and blue hydrogen demand forfuel production between 2020-2050

600
500
400
300
200

Fuels for production of HVCs
Synthetic jet fuel production

0

Hydrogenation of fossil fuels

2020

2030

2040

TWh

100

Upgrading to bio kerosene

2050

Source: Guidehouse wanalysis

2.1.5. Industrial process heat
The previous industrial sections focused on the demand for hydrogen as afeedstock. In this section, the future use of hydrogen for industrial process heatis analysed. Industrial process heat is defined as thermal energy used directly inthe preparation or treatment of materials used to produce manufactured goods anddoes not included spatial heating (covered in section 2.4). While heating needs
for buildings are fairly standard, industrial heat encompasses a wide variety oftemperature levels for diverse processes and end-uses. For instance, cement kilns
require high-temperature, while drying or washing applications in the food industry
operate at lower temperatures. Industrial heat can be categorised in three groups
differentiated by temperature requirements:– Low-temperature heat below 100°C, e.g., machinery, transport equipment orwood and wood Products– Medium-temperature heat between 100-500°C, e.g., pulp and paper, food,beverages and tobacco or Textile, Leather, and clothing– High-temperature heat above 500°C, e.g., glass, cement, ceramics or nonferrous metals

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
29

Today, natural gas, amongst other fossil energy carriers, is largely used toprovide industrial heat (see Appendix A). To decarbonise industrial heat, a switch torenewable or low-carbon energy is needed. For low-temperature heat, heat pumps
and direct electrification are the preferred option because of its increased efficiency
compared to gas-based options. In contrast to the buildings sector where fullelectrification of heat would require a massive build-up of infrastructure to also coverpeak demand (e.g. during cold spells), energy demand in industry is more constantand predictable limiting the build-up of infrastructure. For many medium- to hightemperature processes, green and blue hydrogen can be a suitable decarbonisation
pathway due to the difficulties associated with direct electrification (e.g. material
degradation)
To estimate the future demand for green- and blue hydrogen, we assume certain
green- and blue hydrogen shares per temperature level in 2030, 2040 and 2050.
For low-temperature heat, we assume fossil energy carriers can be fully replaced byelectrification. For medium-temperature heat, we estimate that 5% of today's natural
gas for industrial heat will be replaced by 2030 with green and blue hydrogen, 20%
by 2040 and 30% by 2050. For high-temperature heat, 15% of natural gas will be
replaced with green and blue hydrogen by 2030, 40% by 2040 and 50% by 2050.
In addition it should be noted that green and blue hydrogen could also replace
other fossil energy carriers. In reality, the penetration of green and blue hydrogen
will vary significantly by region - hydrogen could e.g. take up a more substantial
share of industrial heat demand in countries such as Spain where biomass and CCS
constraints are more prominent. Remaining fossil fuel uses could be replaced withelectricity or other renewable and low-carbon gas such as biomethane.
Figure 10 shows the development of hydrogen demand for industrial process
heat. While there is no expected hydrogen demand for low-temperature heat,hydrogen demand for medium and, in particular, high-temperature heat is significant.
By 2030, we expected 56 TWh/year for industrial process heat tripling to 165 TWh/year in 2040 and 217 TWh/year in 2050.

FIGURE 10250

Expected annual green and blue hydrogen
demand for industrial process heat basedon current production(based on FFE data)⁷⁰

200

100

50
High

0

Medium2020
Source: Guidehouse analysis

70 https://extremos.ffe.de/#what_if

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
30

2030

2040

2050

Hydrogen (TWh/year)1502.2. Transport

71

Eurostat (2020). Greenhouse gas emission
statistics – emission inventories. https://
ec.europa.eu/eurostat/statistics-explained/
index.php?title=Greenhouse_gas_emission_
statistics_-_emission_inventories#Trends_in_
greenhouse_gas_emissions
72 European Environment Agency (2020).
Greenhouse gas emissions from transport
in Europe. https://www.eea.europa.eu/dataand-maps/indicators/transport-emissions-ofgreenhouse-gases-7/assessment
73 Gas for Climate (2019). The optimal role forgas in a net-zero emissions energy system.
https://gasforclimate2050.eu/wp-content/
uploads/2020/03/Navigant-Gas-for-ClimateThe-optimal-role-for-gas-in-a-net-zeroemissions-energy-system-March-2019.pdf
74 IEA (2021). The IEA Mobility Model. https://www.iea.org/areas-of-work/programmesand-partnerships/the-iea-mobility-model
75 The decarbonisation pathway for shipping
is assumed to follow the Gas for Climate
2019 study ‘The optimal role for gas in a
net-zero emissions energy system’. The study
found that by 2050 all EU shipping would
be powered by electricity or bio-LNG andtherefore, the demand for hydrogen in the
shipping sector is assumed to be zero. Moreinformation can be found in section 1.2.3.

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
31

Transport accounted for 25% of total EU+UK- greenhouse gas emission in 2018⁷¹,
making it the second largest emitting sector and an essential component in the
decarbonisation of the energy system. While the overall greenhouse gas emissions
in the EU and in the UK have experienced a reduction over recent years, emissions
from the transport sector have increased by 33% since 1990.⁷² In 2019 alone, the EU
transport sector emissions, excluding shipping, increased by 0.8%.⁷² The transport
sector can be decarbonised through a combination of low-carbon fuels, technology
innovations, and behavioural changes. The difficulty of decarbonising transportvaries per segment. Passenger cars and light-duty road vehicles, for instance, areeasy to decarbonise by electrification due to their lighter load and shorter travel
distances. Modes of transport that carry heavy loads and travel long distanceswith few opportunities for refuelling require fuels with high energy density and fastrecharging times. Therefore these fuels are the most challenging to decarbonise.
This chapter describes the role for hydrogen in the transport sector. Hydrogenand hydrogen-derived fuels can be expected to play an essential role in the
decarbonisation of the transport sector, especially in hard to electrify modes oftransport, such as aviation and heavy-duty road transport. The following analysis
builds upon the study ‘Gas for Climate. The optimal role for gas in a net zero emissions
energy system’ published in 2019⁷³. The analysis examines the total hydrogen
demand in aviation and heavy-duty road transport from 2020-2050 and finds a total
direct hydrogen demand of 22 TWh in 2030, 140 TWh in 2040, and 285 TWh in
2050 (0 TWh, 9 TWh, 68 TWh of hydrogen demand from aviation and 22 TWh,
131 TWh, 217 TWh of hydrogen demand from heavy road transport in 2030, 2040,
and 2050 respectively). The hydrogen demand for each relevant transport sector
is determined at a country level for each country in the EU+UK. The data for total
distance travelled per sector from 2020-2050 are from the IEA MoMo model⁷⁴. The
decarbonisation pathways are based on company announcements, decarbonisation
roadmaps, and stakeholder interviews. The following sections give an overview
of the forecasts for road transport, aviation, and shipping⁷⁵ and decarbonisation
pathways of heavy-duty road transport and aviation to 2050. The analysed sectors
are assumed to be fully decarbonised by 2050.

2.2.1. Road transport
Key messages– Hydrogen is a promising option to decarbonise heavy road transport, especiallylong-range vehicles, heavy road transport. Hydrogen fuel cells are forecasted to
power 5%, 30%, and 55% of trucks and 4%, 21%, and 25% of buses in 2030,
2040, and 2050, respectively.
– The forecasted demand for direct hydrogen in heavy road transport in the EU+UK
is 21 TWh, 131 TWh, and 217 TWh, accounting for 3%, 25%, and 58% of total
heavy road transport energy demand in 2030, 2040, and 2050, respectively.
– Biomethane is expected to play an important transitionary role in the
decarbonisation of heavy road transport, with the majority of heavy road transport
being powered by hydrogen and electricity in the long run. The decarbonisation
pathway for heavy road transport implies that in the short-term, the gas grid willneed to support the role out of a gas truck refuelling infrastructure to supply
biomethane to trucks. Over time, as hydrogen trucks enter the fleet, the stations
will need to convert to supplying both hydrogen and biomethane; the hydrogen
infrastructure will need to be in place to supply these stations.

Road transport is responsible for the majority of transport emissions in the
EU. In 2017, road transport accounted for 72% of total EU transport greenhousegas emissions (including international aviation and international shipping).⁷⁶
Decarbonisation of road transport is essential to achieving overall European climate
goals. Electrification is a key component to the decarbonisation of road transport
and will be deployed in all possible segments.
Decarbonisation options

76

77

78

79

80

81

European Environmental Agency (2021).
Greenhouse gas emissions from transport
in Europe. https://www.eea.europa.eu/dataand-maps/indicators/transport-emissions-ofgreenhouse-gases/transport-emissions-ofgreenhouse-gases-12
European Environment Agency (2020). Carbon
dioxide emissions from Europe’s heavy-duty
vehicles. https://www.eea.europa.eu/themes/
transport/heavy-duty-vehicles
IEA (2019). Reducing CO₂ emissions fromheavy duty vehicles. https://www.iea.org/
policies/8789-regulation-eu-20191242reducing-co2-emissions-from-heavy-dutyvehicles
Renault (2020). Renault trucks starts serial
production of its electric trucks. https://www.renault-trucks.com/en/newsroom/press-releases/renault-trucks-starts-serialproduction-its-electric-trucks
ACEA (2020). All new trucks sold must be
fossil free by 2040, agree truck makers andclimate researchers. https://www.acea.be/press-releases/article/all-new-trucks-soldmust-be-fossil-free-by-2040-agree-truckmakers-and-clim
Gilbert-d’Halluin, A; Harrison, P (2018). Trucking
into a greener future. https://europeanclimate.
org/wp-content/uploads/2019/11/6-09-2019trucking-into-a-greener-future-summaryreport.pdf

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
32

Passenger cars and light duty vehicles that travel shorter distances and carry lighterloads are relatively easy to decarbonise through electrification To decarbonise,
the electrification of such vehicles is favourable due to the high efficiency of theelectric motor and drivetrain. With increasing production volumes and declining
battery costs, overall electric vehicles production costs are decreasing. Reduced
costs, increased charging infrastructure, and improved battery technology will help
to further increase the uptake of electric light-duty vehicles. Due to the benefits ofthe electric motor and the increasing penetration of electric vehicles in the global
vehicle stock, by 2050, we assume the majority of passenger cars and light-duty
vehicles to be battery electric. Hydrogen fuel cell passenger vehicles are currently
available (i.e. Toyota Mirai, Hyundai Nexo, and Honda Clarity) and other car
manufactures have hydrogen incorporated in their company strategies (i.e. BMW,
Jaguar Land Rover are currently developing hydrogen fuel cell vehicles). The shortrefuelling times and long driving ranges of hydrogen fuel cell passenger cars andlight-duty vehicles can make them appealing for particular applications. However,as the vast majority of passenger cars and light-duty vehicles are forecasted to bebattery electric, the analysis focuses purely on heavy road transport.
Although the decarbonisation of passenger vehicles is under way, thedecarbonisation of heavy road transport still faces challenges. In 2018, heavy-duty
vehicles were responsible for 27% of road transport CO₂ emissions and about 5%of total EU greenhouse gas emissions.⁷⁷ Road freight is deemed to be a particulardifficult sector to decarbonise. Despite improvements in fuel consumption efficiency,
the carbon dioxide emissions from heavy-duty vehicles have increased by 25% since1990 and are still rising, resulting from the increase in road freight traffic.⁷⁷
Heavy-duty vehicles need to comply with the EU-wide CO₂ emission standards,
adopted in 2019, to reduce CO₂ emission by 15% by 2025 and 30% by 2030.⁷⁸
Stricter emissions limitations will be implemented from 2030 onwards with the goalto achieve full decarbonisation by 2050. The regulation also incentivises the uptakeof zero- and low-emission vehicles in a technology-neutral manner. These new, firstever heavy road vehicle emission standards increase the need for zero-emission
vehicles. Zero-emission vehicle technology has been a topic of conversation in theautomotive industry, with companies like Renault beginning serial production of its
electric truck and announcing that by 2025, 10% of its truck sales will be electric.⁷⁹
Europe’s truck manufacturers have agreed that by 2040, all new trucks sold willneed to be fossil-free in order to achieve carbon-neutrality by 2050.⁸⁰
Aside from technology and energy costs, the level of taxes, refuelling
infrastructure, incentives, and consumer preferences will affect the future deploymentof low- and zero-emission vehicles.⁸¹ Development of refuelling infrastructure is key
to the penetration of different technologies. For zero-emission heavy road vehicles,
four options exist:– battery electric trucks,– fuel cell trucks,– biomethane (bio-CNG/bio-LNG) trucks, and– electric road systems (i.e. catenary systems).

82 European Commission (2020). Heavy-duty
vehicles CO₂ emissions: EU policy context.
https://ec.europa.eu/jrc/sites/jrcsh/files/dg_
clima_ze-hdv-jrc-webinar-2810020_public.pdf
83 ICCT (2020). Vision2050. https://theicct.
org/sites/default/files/publications/ICCT_
Vision2050_sept2020.pdf
84 ACEA (2011). Modal Shift Target for FreightTransport Above 300 km: An Assessment.
https://www.acea.be/uploads/publications/
SAG_17.pdf
85 Gas for Climate (2020). Gas decarbonisation
pathways study. https://gasforclimate2050.eu/
sdm_downloads/2020-gas-decarbonisationpathways-study/
86 Element Energy (2021). The Future Role of Gas
in Transport. https://documents.cadentgas.
com/view/957927673/10/
87 Gilbert-d’Halluin, A; Harrison, P (2018). Trucking
into a greener future. https://europeanclimate.
org/wp-content/uploads/2019/11/6-09-2019trucking-into-a-greener-future-summaryreport.pdf
88 Gas for Climate (2019). The optimal role forgas in a net-zero emissions energy system.
https://gasforclimate2050.eu/wp-content/
uploads/2020/03/Navigant-Gas-for-ClimateThe-optimal-role-for-gas-in-a-net-zeroemissions-energy-system-March-2019.pdf

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
33

The decarbonisation of the heavy road transport sector is expected to utilise a
combination of technologies, with green hydrogen playing a crucial role⁸². Battery
electric vehicles are expected to play a larger role in the small and short-haul truck
segments and fuel cells are expected to play a more prominent role in decarbonising
the large long-haul truck segment.⁸³ As 56% of tonne-kilometre freight is covered bytrucks traveling distances of ~300km or more⁸⁴, the majority of trucks need fast
fuelling times and high-density fuels.
Liquid fuels (biofuels and hydrogen) will be important for the decarbonisation ofheavy road transport, particularly heavy-duty long-distance trips. LNG is expected
to play a transitionary role with hydrogen, electricity, and bio-LNG being the energy
sources for long-term decarbonisation. The fast refuelling times and high energy
density make hydrogen and biomethane viable options for long-distance heavy roadtransport. However, by 2050, the majority of biomethane is expected to be used inother sectors where it has a higher societal value, such as in the heating of buildings
and as an industrial feedstock.⁸⁵ As gas trucks are currently commercially available,
biomethane can be used in the short to medium term to achieve emission reduction
targets while zero emission alternatives (i.e. battery electric, hydrogen fuel cell) reachnecessary scale.⁸⁶ Therefore, natural gas and biomethane can play a transitionaryrole with some biomethane remaining in 2050, but to reach a decarbonised energy
system in 2050, the majority of heavy road transport will be powered by hydrogenand electricity. The decarbonisation pathway for heavy road transport implies thatthe gas grid will need to support the roll out of a gas truck refuelling infrastructure
to supply biomethane to trucks. Over time, as hydrogen trucks enter the fleet, thestations will need to convert to supplying both hydrogen and biomethane.⁸⁶
It is important to note that fuel cells used in fuel cell electric vehicles arehighly sensitive to the hydrogen fuel quality. Impurities can cause significant issues
for fuel cells, such as catalyst poisoning. Therefore, the hydrogen quality of thedelivery system, including pipelines, would need to deliver hydrogen at fuel cellhydrogen purity levels or utilise purification technologies at the offtake of pipelines
to allow direct utilisation of hydrogen. As most industrial or residential applications
will not require fuel cell grade hydrogen, hydrogen purification and compression
at the interface of the pipeline system and the fuel station distribution system may
be a favourable option to reach the hydrogen fuel quality necessary for fuel cellapplications.
Pathway towards 2050
By 2050, it is forecasted that a combination of technologies will be used to bestsatisfy various uses in heavy road transport.⁸⁷ Based on the Gas for Climate 2019
report⁸⁸, the new heavy road transport EU emission standards, and company
statements, we assume that by 2050, 35% of heavy road freight will be electric, 55%
will be powered by hydrogen, and 10% will be powered by biomethane. In addition,
75% of busing is assumed to be electric and 25% hydrogen fuel cell. Figure 11 below
shows the energy demand pathway for heavy road transport from 2020 to 2050. In
2030, electricity accounts for 2% of the heavy road energy demand, hydrogen 3%,
natural gas 29%, and diesel 66%. By 2050, electricity accounts for 28% of the heavyroad energy demand, hydrogen 55%, biomethane 17%, and diesel 0%.

1000

FIGURE 11
Pathway of European energy
demand in heavy road transport
from 2020-2050

800

400

200

Diesel(bio)-LNG/CNG
Hydrogen0Electricity

2020

2025

2030

2035

2040

2045

Energy consumed (TWh / year)

600

2050

Source: Guidehouse analysis

In addition to the combination of technologies, Figure 11 shows that totalenergy demand for the heavy road transport sector in 2050 is forecasted to beapproximately half of the energy demand in 2030, primarily due to improvements infuel economy of heavy road vehicles. Battery electric and hydrogen fuel cell heavy
duty vehicles are assumed to consume approximately 35% and 60% of the energyof a conventional diesel heavy duty vehicles, respectively. Therefore, the transition
to these alternative vehicle technologies leads to a sustainable reduction in energy
consumption. In addition, fuel economy improvements can result from a numberof additional factors including improvements in heavy duty vehicle aerodynamics,
engine mechanics, transmission technologies, and tires, weight reduction, andchanges to driving behaviour.Also, a forecasted reduction in distance travelledby medium and heavy freight trucks until 2050 contributes to the reduced energy
consumption.⁸⁹ Hydrogen demand in heavy road transport is 21 TWh in 2030,
increasing to 131 TWh in 2040 and 217 TWh in 2050.

2.2.2. Aviation
Key Takeaways:

89 IEA (2020). The IEA Mobility Model. https://www.iea.org/areas-of-work/programmesand-partnerships/the-iea-mobility-model
90 Hydrogen demand to produce fuels areincluded in Industry in this report. Values anddetails of the hydrogen demand for fuels canbe found in Section 2.1.4.
91 European Commission (2020). Reducing
emissions from aviation. https://ec.europa.eu/
clima/policies/transport/aviation_en

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
34– Hydrogen and hydrogen-derived fuels are identified as promising options todecarbonise aviation. The largest source of hydrogen in aviation is anticipated tobe from fuel production. Synthetic and bio kerosene are each forecast to power
7%, 33%, and 40% of aircrafts, equalling 50 TWh, 235 TWh, and 296 TWh ofsynthetic and 50 TWh, 235 TWh, and 296 TWh of bio kerosene in 2030, 2040,
and 2050.⁹⁰– Current research and development, company announcements, and policy
indicate that hydrogen aircrafts can take to the air over the coming decades, withthe potential of hydrogen powering short-range aircrafts. Hydrogen is forecasted
to power 0%, 1%, and 10% of airplanes in the EU+UK in 2030, 2040, and 2050,
respectively.
– The forecasted demand for direct hydrogen in aviation in the EU+UK is 0 TWh,
9 TWh, and 68 TWh, accounting for 0%, 1%, and 9% of total aviation energy
demand in 2030, 2040, and 2050, respectively.
In 2017, direct emissions from aviation accounted for 3.8% of total CO₂ emissions
in the EU.⁹¹ Aviation, responsible for 13.9% of transport GHG emissions, is the second
largest source of transport emissions after road transport. Significant fuel efficiency
improvements have been achieved in aviation over recent years. The fuel burned
per passenger-kilometre dropped by 24% between 2005 and 2017.⁹¹ Despite fuelefficiency improvements, growth in air traffic has caused aviation’s absolute CO₂
emissions to continue to rise. Aviation is a particularly difficult sector to decarbonise.

Decarbonisation options

92 NLR – Royal Netherlands Aerospace
Centre (2021). Destination 2050. https://www.destination2050.eu/wp-content/
uploads/2021/02/Destination2050_Report.
pdf
93 EURACTIV (2021). EU planning staggered
increase in use of green jet fuel. https://www.
euractiv.com/section/alternative-renewablefuels/news/eu-planning-staggered-increasein-use-of-green-jet-fuel/94 IATA (2020). Developing Sustainable Aviation
Fuels. https://www.iata.org/en/programs/
environment/sustainable-aviation-fuels/
95 Gas for Climate (2020). Gas decarbonisation
pathways study. https://gasforclimate2050.eu/
sdm_downloads/2020-gas-decarbonisationpathways-study/
96 Gas for Climate (2019). The optimal role forgas in a net-zero emissions energy system.
https://gasforclimate2050.eu/wp-content/
uploads/2020/03/Navigant-Gas-for-ClimateThe-optimal-role-for-gas-in-a-net-zeroemissions-energy-system-March-2019.pdf
97 ATGA (2020). WayPoint 2050. https://aviationbenefits.org/media/167187/w2050_full.
pdf
98 Airbus (2020). Airbus reveals new zeroemission concept aircraft. https://www.airbus.
com/newsroom/press-releases/en/2020/09/
airbus-reveals-new-zeroemission-conceptaircraft.html
99 Airbus (2020). Hydrogen in aviation: how close
is it? https://www.airbus.com/newsroom/
stories/hydrogen-aviation-understandingchallenges-to-widespread-adoption.html
100 FCH (2020). Hydrogen-powered aviation.
https://www.fch.europa.eu/sites/default/
files/FCH%20Docs/20200507_Hydrogen%20
Powered%20Aviation%20report_FINAL%20
web%20%28ID%208706035%29.pdf
101 European Commission (2020). Sustainable andSmart Mobility Strategy. https://ec.europa.eu/
transport/sites/transport/files/legislation/com20200789.pdf

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
35

There are two options for the decarbonisation of aviation, (1) sustainable aviation
fuels (SAFs) (i.e. biofuels or synfuels) and (2) new propulsion technologies (i.e.
battery- and turbo-electric technologies and electric motors powered by fuel cells).
Over the coming decades, new propulsion technologies are expected to only playa role in short distance, regional and short-haul air transport due to the relatively low
energy densities of hydrogen and batteries.
SAFs are expected to become a major contributor to the decarbonisationof aviation.⁹² Currently there is a discussion of an EU blending mandate of 2%
sustainable aviation fuels in 2025 to 63% in 2050 to help cut aviation emissions.⁹³
SAFs can be drop-in fuels, benefiting from the use of existing aircraft engines andexisting fuelling infrastructure at airports. The ease of drop-in fuels makes them anappealing and currently viable option to reduce emissions. SAFs are already in use
and are expected to grow significantly over the coming decades. Since 2016, over
300,000 flights have used SAFs.⁹⁴ By 2050, we expect 80% of all aircrafts to be
powered by SAFs, 10% to be hydrogen powered, and 10% to be battery electric.
Given the difficulty to decarbonise, aviation is considered a priority sector forbiomass feedstocks⁹⁵. Based on the Gas for Climate 2019 study, half of SAFs areis expected to be bio-jet fuel and half are is expected to be synthetic kerosene.⁹⁶
Therefore, since 80% of aircrafts in 2050 are forecasted to be powered by SAFs,
bio-jet fuel and synthetic kerosene are each expected to power 40% of air travelin 2050.
Over the past couple of years, there has been increased interest and researchand development into battery-electric and hydrogen fuel cell aircrafts. Small
electric aircrafts up to 9 seats are already performing test flights, with regional
aircrafts expected in the 2030s.⁹⁷ Interest in hydrogen aircrafts has increased
dramatically over the past two years. Airbus has shifted their zero-emission aircraft
focus from battery-electric to hydrogen and has released concepts for the world’s
first zero-emission commercial aircrafts. The three aircraft concepts are basedon hydrogen as the primary power source and could enter service by 2035.⁹⁸
In addition, Airbus has recently stated that “hydrogen is increasingly considered
as one of the most promising zero-emission technologies for future aircrafts”.⁹⁹
An independent study, commissioned by the Clean Sky 2 and Fuel Cells andHydrogen Joint Undertakings (FCHJU), found that hydrogen burned in a jet engine,used in fuel cells, or used to create synthetic liquid fuels could play a central roleto the decarbonisation of aviation.¹⁰⁰
In the Destination 2050 report, five airline manufacturers, airlines, andairports developed a route to decarbonise European Aviation and identified that
improvements to aircraft and engine technology and fleet replacement have thelargest promise for decarbonising aviation in Europe in the 2050 timeframe.⁹² To
decarbonise by 2050, the analysis includes the introduction of a hydrogen-powered
single-aisle aircraft on intra-EU routes in 2035. The progression to zero-emission
aircrafts is in line with the European Commission’s goal to have a market-ready zeroemission aircraft by 2035.¹⁰¹ Due to the novelty of battery electric and hydrogenfuel cell aircrafts the penetration of both technologies is heavily dependent ontechnology advancements over the coming years. Electric powered aircrafts are notexpected to significantly enter the aircraft fleet until 2035, and due to the longaircraft lifespans, they are expected to propagate slowly through the aviation fleet.
The transition to battery-electric and hydrogen fuel cell aircrafts is heavily dependent
upon technology advancements and governmental policy but is expected to play arole in aviation from 2035 onwards.

Pathway towards 2050
In the Gas for Climate 2019 study, energy demand in aviation in 2050 was estimatedto be supplied by 50% bio jet fuel and 50% synthetic kerosene. Due to the increased
development, research, and industry statements, our updated pathway includes
battery-electric and hydrogen powered aircrafts. Both bio jet fuel and synthetic
kerosene have their challenges in feedstock supply, resp. biomass and CO₂ frombiogenic origin or from Direct Air Capture (DAC).
The updated air travel pathway in this report is composed of 10% battery
electric, 10% hydrogen powered, 40% bio-jet fuel, and 40% synthetic kerosene
in 2050. The new addition of battery electric and hydrogen powered aircrafts inthe pathway compared to the Gas for Climate 2020 Pathways study is due to theincreased research, developments, company announcements, and policy targets fora zero-emission aircraft in the 2035 timeframe in Europe. This leads to 68 TWh of
direct hydrogen demand in aviation in 2050. However, the production of synthetic
kerosene from hydrogen, as described in section 2.1.4 is still expected to represent
the largest share of hydrogen demand in the aviation sector. The decarbonisation
pathway for the aviation sector is shown in Figure 12 below.

800

FIGURE 12700

Pathway of energy demand in aviationfrom 2020-2050(in TWh)

600

400
300
Bio Jet fuel200

Synthetic Kerosene
Hydrogen100

Electricity
Jet Fuel

0
2020

2025

2030

2035

2040

2045

Energy consumption (TWh )

500

2050

Source: Guidehouse analysis

Total air traffic is forecasted to nearly double over the coming decades, while atthe same time, airplane efficiency is expected to improve by 1.5% per year.¹⁰², ¹⁰³
These two opposing factors lead to a slight increase in total energy demand till
2050, as can be seen in Figure 12. The direct hydrogen demand in the aviation
sector is 0 TWh in 2030, 9 TWh in 2040, and 68 TWh in 2050.¹⁰⁴

2.2.3. Shipping
102 IEA (2020). The IEA Mobility Model. https://www.iea.org/areas-of-work/programmesand-partnerships/the-iea-mobility-model
IATA (2021).
103 Fuel Efficiency. https://www.iata.org/en/
programs/ops-infra/fuel/fuel-efficiency/
104 Hydrogen demand for the production of SAFs
is included in the Industry chapter in the Fuel
Production subsection (2.1.4).

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
36

In the Gas for Climate 2019 report, an analysis on the decarbonisation of theshipping sector was performed and found that by 2050, under the optimal gas
scenario, domestic shipping is forecasted to be powered by 100% electricity, intraEU by 50% electricity and 50% bio-LNG, and outbound EU by 100% bio-LNG. This
analysis assumes the same shipping decarbonisation pathway as the Gas for Climate
2019 report and therefore forecasts no direct hydrogen or hydrogen derived fuelsin the shipping sector.

105 European Parliament (2020). Decarbonising
maritime transport: The EU perspective.
https://www.europarl.europa.eu/RegData/
etudes/BRIE/2020/659296/EPRS_
BRI(2020)659296_EN.pdf
106 Port of Rotterdam (2020). LNG becoming
increasingly popular in the shipping sector.
https://www.portofrotterdam.com/en/
news-and-press-releases/lng-becomingincreasingly-popular-in-the-shipping-sector
107 DNV GL (2020). Maritime Forecast
to 2050. https://eto.dnv.com/2020/
Maritime/#maritime-top
108 World Bank (2021). Charting a Course
for Decarbonizing Maritime Transport.
https://www.worldbank.org/en/news/
feature/2021/04/15/charting-a-course-fordecarbonizing-maritime-transport
109 The hydrogen demand for synthetic aviation
fuels is covered in the refinery section of theindustry chapter (section 2.1.4). It is assumed
that the production of synthetic fuels would
take place at current day refinery locations
and therefore, the hydrogen demand would
be at these locations, not the locations of
the fuel use. Only direct hydrogen use isconsidered in the transport section.

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
37

The full electrification of domestic shipping and half of intra-EU shipping
is driven by electricity being the most cost-optimal shipping fuel due to its highefficiency. The forecasted uptake of electric ships is in line with the development
and deployment of electric ships, with electric ships leading the transition of shortroute ships in Europe. An example of this can be seen by Norway’s electrificationof its ferry sector. As of 2020, there are 450 battery-powered ships in operationor on order in Europe.¹⁰⁵ The low energy density of batteries limits electric ships toshorter routes and smaller ships.
The transition to bio-LNG in long distance, heavier shipping applications isbased on a pathway that first transitions to LNG ships, followed by bio-LNG, as
bio-LNG can be directly used in the gas engine and existing LNG infrastructure.
Currently there are three commercially available engine and fuel systems for large
bulk carrier ships: mono-fuel diesel engine running on Heavy Fuel Oil with ascrubber, a mono-fuel diesel engine running on Very Low Sulphur Fuel oil (VLSFO)or Marine Gasoil (MGO), and a dual-fuel LNG engine that can be powered by LNG
or VLSFO/MGO.¹⁰⁵ LNG is the cleanest fossil fuel, has the necessary infrastructure
in place, is available at scale, and generates no NOx or SOx emissions. With the
EU promoting the introduction of LNG infrastructure in its ports, LNG ships meeting
the IMO 2020 sulphur standards, LNG ships being currently commercially available,
and the possibility of gas engines and LNG infrastructure being used for alternative
fuels in the future, LNG is a possible transition fuel. As of January 2020, there
were 175 LNG-powered sea-faring ships in service worldwide with another 200
LNG-powered ships on order.¹⁰⁶ As LNG does not contribute much to shipping
decarbonisation, a switch to bio-LNG is anticipated. However, the transition to bioLNG is a topic of discussion due to bioavailability and methane slippage.
Ammonia and methanol have been gaining favour in the shipping sector due
to their potential zero carbon emissions, availability, and relatively high energy
density compared to hydrogen and batteries. These fuels offer potential for the
decarbonisation of the shipping sector, but the use of these alternative fuels needs
further research and development to overcome technical and safety challenges.¹⁰⁷
The World Bank has identified “green fuels”, including ammonia and hydrogen, as
the most promising zero-emission shipping fuels and states that LNG is expected
to play a limited role in the decarbonisation of shipping.¹⁰⁸ Currently, there is nota clear view on how the shipping sector will transition over the coming years.
However, recent research, development, and company announcements into green
fuels suggest that ammonia, methanol, and hydrogen will play a prominent role in the
future shipping sector. We propose that the shipping analysis performed in the 2019‘Gas for Climate: The optimal role for gas in a net zero emissions energy system.’should be reviewed and updated over the coming years.

2.2.4. Transport conclusions
The demand for direct hydrogen in Europe in 2030, 2040, and 2050 is forecasted
to be 21 TWh, 131 TWh, and 217 TWh, respectively for heavy road transport,
approximately 3%, 25%, and 60% of the total heavy road energy demand and
0 TWh, 9 TWh, and 68 TWh for aviation, approximately 0%, 1%, and 9% of aviationenergy demand. The hydrogen demand for the production of synthetic aviation fuels
is covered in the Industry chapter of this report.¹⁰⁹
Hydrogen is expected to play an important role in the future transport sector.
The extent of the role that hydrogen will play is dependent on the developmentof technology, infrastructure, and competitiveness of alternative fuels. Hydrogenand hydrogen-derived synfuels are forecasted to account for 2% of the total energy
demand in the transport sector in 2030, 13% in 2040, and 25% in 2050.

The country level breakdown of energy consumption in the aviation sector isbased on historical values for per country yearly freight tonnage per kilometre¹¹⁰
for freight air travel and yearly total passengers carried for passenger air travel.
The country level breakdown of the heavy road transport is based on historical per
country heavy road transport vehicle stock.¹¹¹ Figure 13 shows the direct transporthydrogen demand for each country in the EU+UK for 2030, 2040, and 2050.
FIGURE 13
Direct hydrogen demand from thetransport sector per country for 2030,
2040, and 2050 (in TWh)

2030

2040

2050

45
40
35
30
25

15
10
5

Hydrogen demand for synthetic fuels used in transport are not included in this graph.

UK

SK

SI

SE

RO

PT

PL

NL

MT

LV

LU

LT

IT

IE

HU

HR

FR

FI

ES

EL

EE

DK

DE

CY

CZ

BG

BE

0
AT

Hydrogen demand (TWh)20

Source: Guidehouse analysis

2.3. Power“Harnessing the power of North
Sea offshore wind requires
us to look at the area as awhole, and to comprehensively
rethink the energy systemsof all of North-West Europe.
This includes integrating
different energy sectors andenergy carriers. The European
Hydrogen Backbone presents
a valuable vision on thenecessary complementary
onshore hydrogen
infrastructure.”.
Michiel Müller, programme director
North Sea Wind Power Hub

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
38

The European power sector is rapidly evolving to achieve GHG emission reduction
targets while providing a stable supply of electricity. Moreover, the demand forelectric power is expected to furtherly increase in the coming decades. The European
GHG emission intensity for electricity generation was 45% lower in 2018 compared
to 1990.¹¹² The reduction in GHG emissions largely stems from the increasing shareof renewable produced electricity and the phase-out of coal fired power generation.
Since 2015, renewable generated electricity has almost doubled while coal-fired
electricity generation has been reduced by half.¹¹³ Renewable energy sources madeup 38% of EU electricity consumption in 2020, up from 32% in 2018.¹¹⁴ In 2019, thewind capacity installed in the EU+UK was 185 GW and the solar capacity was 103
GW.¹¹⁴
In 2018, 21% of total European final energy demand was met with electricity.¹¹⁵
The electrification rate is expected to significantly increase over the coming decades
in industry, transport, and buildings, taking advantage of the efficiency benefits ofelectricity use and the increasing supply of renewable generated electricity.

110 World Bank (2020). Air transport, freight.
https://data.worldbank.org/indicator/IS.AIR.
PSGR?view=chart https://data.worldbank.org/
indicator/IS.AIR.PSGR?view=chart
111 European Commission (2017). Statistical
pocketbook 2017. https://ec.europa.eu/
transport/facts-fundings/statistics/
pocketbook-2017_en
112 European Environment Agency (2020).
Greenhouse gas emission intensity ofelectricity generation in Europe. https://www.
eea.europa.eu/data-and-maps/indicators/
overview-of-the-electricity-production-3/
assessment
113 Agora (2021). Renewables overtake gas andcoal in EU electricity generation. https://www.
agora-energiewende.de/en/press/newsarchive/renewables-overtake-gas-and-coaland-coal-in-eu-electricity-generation-1/
114 Eurostat (2020). Electricity production
capacities. https://ec.europa.eu/eurostat/databrowser/view/NRG_INF_EPC__
custom_922715/default/table?lang=en
115 European Commission (2020). Share of energy
products in total final energy consumption.
https://ec.europa.eu/eurostat/cache/infographs/energy/bloc-3a.html
116 Gas for Climate (2020). Gas decarbonisation
pathways study. https://gasforclimate2050.eu/
sdm_downloads/2020-gas-decarbonisationpathways-study/

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
39

Variable renewable energy sources (wind and solar), are essential to decarbonise
the power system and achieve GHG emission reduction targets. The increasing
shares of wind and solar electricity, paired with the phase-out of fossil sources
and partial nuclear power creates a challenge for balancing electricity supply anddemand, requiring a highly integrated, smart energy system with storage to ensure
security of supply. Hydrogen has the potential to provide large-scale and longterm storage of renewable energy and can balance loads in electricity networks.
This section explores the role of hydrogen in the European power sector anddetermines the country level power sector hydrogen demand for 2030, 2040,
and 2050.
Compared to the power generation mix today, the dispatchable power
technologies in a highly electrified and renewable power system will need to caterfor higher demand peaks and longer periods of under- and over-supply due toweather variations. Consequently, the average capacity factor of these plants will be
low. This means gas-fired units have two main advantages: low cost per kW andhigh technical flexibility to follow residual loads. In the short-term, hydrogen can be
blended with natural gas in gas-fired turbines. Over time, gas turbines can transition
to being powered by 100% hydrogen. In addition, in the medium to long-term fuelcells can potentially also play a role in hydrogen powered electricity generation
depending on cost of fuel cells.
The additional value of hydrogen over most other flexible power options is that it
can be an efficient and cost-effective means for storing large shares of energy
over long periods of times (i.e. seasons), in comparison to other options (i.e.
batteries, interconnection, and demand response). Hydrogen can cost-effectively
integrate and provide resilience to the highly-electrified net-zero power system (andeconomy) of the future. When integrated with the power system, it can provide longterm storage to manage the variation in power supply from wind and solar, reduce
curtailment of fluctuating renewable energy sources, and provide grid balancing
services. In addition, hydrogen can be used to transport renewable energy overlong distances and as a feedstock in other industries, helping form an integrated
energy system.
Stepwise approach is taken to determine the hydrogen demand on EU andbottom-down to the national level:
The future European electricity generation mix will be composed of highshares of wind and solar, hydro power, and some remaining nuclear power plants.
Based on the Gas for Climate 2020 ‘Gas Decarbonisation pathways study’, in 2030,
the total electricity generation in the EU+UK is forecasted to be 3,700 TWh, 4,200
TWh in 2040, and 4,600 TWh in 2050¹¹⁶, excluding electricity generation forhydrogen production.
ENTSO’s Network Development Plan TYNDP 2020 Scenario provides
generation and capacity forecasts for each country in Europe for 2030 and 2040.
Using the data from the Global Ambition scenario, generation per technology andper country in the power sector is forecasted for 2030, 2040, and 2050. The
generation forecasts are scaled to total electricity generation from the Gas for
Climate 2020 ‘Gas Decarbonisation pathways study’ listed above and are used
to determine the total amount of needed gas generation for 2030 and 2040. The
analysis leads to a total gas generation in the EU+UK of 496 TWh in 2030 and 436
TWh in 2040. For 2050, the TYNDP 2030 and 2040 generation forecasts are
smartly extrapolated to determine the needed gas generation in 2050, considering
increases in renewables and each country’s share of remaining dispatchable
generators (nuclear, biomass, and hydro power). Therefore, the hydrogen
demand per country is determined in relation to each country’s nuclear, hydropower, biomass, solar, and wind forecasted generation quantities. The portion of

117 Although it is not considered in this analysis,hydrogen production for use in other sectors
can help integrate solar and wind generation.
At times when the solar and wind generation
exceed the electricity demand, the excess,cheap electricity can be used to producehydrogen, minimising the curtailment of VRE
and taking advantage of the low electricity
prices. Hydrogen can help increase sector
coupling and provide resilience to a highly
electrified energy system.
118 Hydrogen demand in the power sector
includes hydrogen used in gas fired turbines(both blended with natural gas and pure)and in fuel cells. In this analysis, we do not
distinguish between the two, we assumehydrogen will be a percentage of final gas
demand in the power sector and assume allgas to power applications have an efficiencyof 50%.

hydrogen generation of the forecasted total gas generation is based on the Gas
for Climate study, “Gas Decarbonisation Pathways 2020-2050’and is forecasted
to be 1%, 35%, and 70% of the total gas generation in 2030, 2040, and 2050,
respectively. A base assumption for the analysis is that electricity demand for greenhydrogen generation for 2030-2050 is provided with dedicated renewables, i.e.
the renewable generation sources used in the production of hydrogen are notconnected to the power grid. Therefore, additional electricity generation is needed
to produce green hydrogen.¹¹⁷
Extrapolated from the ENTSO’s Ten-Year (TYNDP 2020 Scenario), we assume
the EU electricity system in 2050 will be powered by 6% nuclear power and 84%
renewable sources, out of which 15% solar, 50% wind, 13% hydro power, and
6% other renewables. This leaves 10% to be supplied using flexible, dispatchable
generation technologies, including renewable gas turbines, and fuel cells.
To decarbonise the 10% of final European electricity demand, we assume
that gas-based technologies can be decarbonised by using renewable or low-carbon
gases, such as biomethane and hydrogen. Due to biomethane supply constraints
and the high costs for carbon capture and sequestration at low capacity factors,
hydrogen is expected to play a dominant role in the power sector. Biomethane is
expected to be of higher value in other sectors, such as hard-to-electrify transportmodes, in hybrid heat pumps for buildings, and as feedstock for specific industry
applications (i.e. steel and ammonia production).
The analysis finds that the total European hydrogen demand¹¹⁸ in the power
sector is 12 TWh in 2030, 301 TWh in 2040, and 626 TWh in 2050. with thehydrogen demand concentrated in Germany, Italy, Poland, and the United Kingdom.
The country level hydrogen demand is shown in Figure 14 below.

FIGURE 14
Hydrogen demand for power sector
generation in 2030, 2040, and 2050
per country

2030

2040

2050

200

150

50

UK

SK

SI

SE

RO

PT

PL

NL

MT

LV

LU

LT

IT

IE

HU

HR

FR

FI

ES

EL

EE

DK

DE

CY

CZ

BG

BE

0
AT

Hydrogen demand (TWh)100

Source: Guidehouse analysis

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
40

Hydrogen-generated electricity is forecasted to account for 0.2% of the total
European electricity generation in 2030, 4% in 2040, and 7% in 2050. Figure
15 provides a visual representation of hydrogen generated electricity of the total
electricity generation per country in 2050. In 2050, hydrogen generated electricity
is below 18% of total power generation for all countries in the EU+UK. As can beseen from the map, Poland has the greatest share of hydrogen produced electricity,with approximately 17% of the generated electricity coming from hydrogen.

FIGURE 15

17%

Hydrogen generated electricity
fraction of total country electricity
generation in 2050 (in %)

0%

2%

0%

3%

4%

15%
12%

7%

7%
15%

17%

14%
1%

0%
2%

4%
6% 1%

3%

4%

5%

3%
3%
5%

15%

4%
2%

13%

9%

Countries with high shares of gas generation in TYNDP’s 2030 and 2040
generation forecasts (e.g. Belgium, Germany, Ireland, Italy, Poland and the UK)
are forecasted to need relatively high shares of hydrogen. Hydrogen can be a
replacement for existing natural-gas-fired power plants, providing the necessary
dispatchable generation in a carbon-neutral manner. Natural-gas-fired turbines canbe transitioned to hydrogen-fired gas turbines, utilizing existing infrastructure tocost-effectively decarbonise dispatchable generation. The countries with the highest
share of gas demand in 2030 and 2040 in the TYNDP 2020 scenarios are Belgium,
Germany, Ireland, Italy, Poland, and the United Kingdom. These are the six countries
with the highest shares of hydrogen demand in 2050 in this analysis.
Countries with high shares of hydro-power-generated electricity are forecasted
to have low needed shares of hydrogen-generated electricity due to hydro power’s
storage capabilities and dispatchable nature. In addition, nuclear power, a baseload
power plant, can help provide stable electricity supply. Therefore, countries withANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
41

forecasted remaining nuclear power in 2030, 2040, and 2050 are forecasted totypically need relatively lower dispatchable capacity, resulting in lower hydrogen
demands, as can be seen in France, Bulgaria, Finland, and the Czech Republic.
However, as can be seen in the case of the United Kingdom, remaining nuclear
power does not necessarily indicate relatively lower shares of hydrogen demand,as hydrogen demand is dependent on numerous factors, including forecasted
electricity generation from gas, solar, wind, hydro power, and biomass.
In the Gas for Climate 2020 Pathways study¹¹⁹ the 2050 hydrogen demand in
the power sector was forecasted to be 786 TWh. The analysis was performed forall of Europe, using a single-node dispatch model. This current study finds a 2050
hydrogen demand in the power sector of 630 TWh resulting from lower forecasted
gas generation compared to the Gas for Climate 2020 Pathways study¹¹⁹. The Gas for
Climate 2020 Pathways study finds that 12% of total 2050 electricity demand would
be supplied by renewable gases, whereas the current analysis finds that 10% of the2050 electricity demand will be supplied by renewable gases. The main reason forthis difference is that the previous Gas for Climate study performed an aggregateddispatch model for all of Europe. In comparison, to get country-level hydrogen values
for 2030, 2040, and 2050 in the current analysis, extrapolations were performed
using ENTSO’s TYNDP 2020 Scenario¹²⁰. The different methodology can explain the
difference between the two studies.

2.4. Buildings

119 Gas for Climate (2020). Gas decarbonisation
pathways study. https://gasforclimate2050.eu/
sdm_downloads/2020-gas-decarbonisationpathways-study/
120 TYNDP (2020). TYNDP 2020 Scenario Report.
https://2020.entsos-tyndp-scenarios.eu/
121 European Commission, Communication‘A Renovation Wave for Europe’. https://
ec.europa.eu/energy/sites/ener/files/eu_
renovation_wave_strategy.pdf
122 https://heatroadmap.eu/wp-content/
uploads/2018/09/STRATEGO-WP2Background-Report-4-Heat-Cold-Demands.
pdf, https://ec.europa.eu/energy/eu-buildingsdatamapper_en

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
42

Overall, buildings are responsible for about 40% of the EU’s total energy
consumption, and for 36% of its greenhouse gas emissions from energy.¹²¹ Thesefigures refer to the use and operation of buildings, including indirect emissions in
the power and heat sector.
The EU and UK together have over 300 million buildings, with a total floor
space of 25 billion m², or 25,000 km². The vast majority (77%) of that floor spaceis in residential buildings, with the remaining 23% in use for all kinds of services,
including offices, hospitals, shops, logistics, etc.¹²²
In general, reducing emissions from the heating of buildings will be a
combination of reducing their heat demand by reducing heat losses through thebuilding envelope (insulation) and through ventilation and reducing the emissions
per unit of heat provided. The latter can e.g. be achieved by electric heat pumps
using renewable electricity, by boilers using renewable or low-carbon gases, or by
district heating using heat from renewable or low-carbon sources. The mix between
insulation, installation and energy source will be determined by factors such as costeffectiveness, acceptance, security of supply, and resilience. There will be variationsin technology choices across different countries and regions due to significant
differences both in terms of existing infrastructure as well as building stock andpolicy discussion.
Today, the buildings sector is the single largest natural gas using sector in the EU
and UK, representing some 40% of overall natural gas consumption. Looking at theclimate-neutral energy system by 2050, the Gas for Climate 2019 study concluded
that it makes sense that all buildings with existing gas connections will continue to use
gas in a cost-optimal climate-neutral energy system, albeit at significantly reduced
volumes and with natural gas being replaced by biomethane and hydrogen. The
Gas for Climate study concluded that hybrid heat pumps have an important role toplay in buildings with an existing gas connection, and biomethane is in principle thepreferred gas for their gas-fired boiler part, because it allows for an easy transition:– No issues with distribution grid to the buildings (same molecule as natural gas)
– No new meters required– Existing gas-fired boilers can be upgraded to hybrid heat pump, by adding aheat pump and a control

– No simultaneous change of gas required for entire housing district– No new safety procedures, measures, and training required.
Starting points for new analysis
Since the publication of the Gas for Climate study, various stakeholders have shared
feedback on this assumption and market development has progressed:– Some (gas) DSOs see hydrogen as an option for heating of buildings, including
100% hydrogen boilers, e.g. in the UK (H₂1 North of England¹²³), the Netherlands(Stad aan ’t Haringvliet¹²⁴), and Germany (H₂vorOrt¹²⁵). In some areas, a choicefor hydrogen could mean that biomethane cannot be offered anymore.
– Regional biomethane availability may be an issue, e.g. in northern UK. Hence,hydrogen can be an alternative if the massive scale-up of biomethane does notmaterialise as foreseen in Gas for Climate.
– Policy makers often aim for a strong increase in renovation rates; the EC’s
Renovation Wave communication e.g. aims to “at least double the annual energy
renovation rate of residential and non-residential buildings by 2030 and to foster
deep energy renovations”¹²⁶. If the increase is less than policy makers assume,
energy demand for heating will be higher than expected. This may subsequently
lead to more demand for biomethane and hydrogen.
– Pure hydrogen boilers and fuel cells to supply heat and electricity have beendeveloped and are increasingly available in the market today.
Decarbonisation options

123 https://www.h21.green/about/
124 https://www.installatie.nl/nieuws/miljoenenvoor-waterstofwoningen/
125 https://www.dvgw.de/themen/energiewende/
wasserstoff-und-energiewende/h2vorort
126 https://ec.europa.eu/energy/topics/energyefficiency/energy-efficient-buildings/
renovation-wave_en
127 Hybrid Heating Europe, vision paper(2021), Unlocking the hybrid heating
potential in European buildings: https://
hybridheatingeurope.eu/?wpdmdl=2534

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
43

In the future zero-emission energy supply of buildings in our scenario, hydrogen canplay a role in three places:– Hybrid heat pumps. As a renewable gas, biomethane has some advantages
over hydrogen here, since its composition (methane) is the same as that ofnatural gas: no modifications are needed to the distribution grid and to gas
meters, the current gas-fired boiler can become part of the future hybrid heatpump, and it is not necessary to change the homes and buildings in an entire
district over to another gas at once. In an earlier Gas for Climate analysis, we
assumed that 80% of the gas used in hybrid heat pumps could be biomethane
requiring a substantial increase of current production. The role of green or bluehydrogen depends on the availability of biomethane within these assumptions,e.g. in regions with a limited availability of biomethane and/or where natural gas
distribution grids would be converted to hydrogen distribution grids. Hydrogenfired boilers are already available, and there are plans for 1-on-1 replacementsof natural-gas-fired boilers as well; we have not considered that option here,
because of the advantages of hybrid heat pumps in an energy system with highshares of variable renewables.¹²⁷– District heating. In some countries, district heating is seen as an important part ofthe decarbonisation of buildings. Existing district heating systems, serving roughly
10% of the building floor space in EU+UK, often still run on heat from fossil fuelthermal power plants and industries. As the share of wind and solar in the powersystem grows, the capacity factors of thermal power plants will become low
and changing industrial processes will not always produce the same amounts ofheat as the current one either. So, the big challenge in district heating is finding
renewable sources of heat for those (heat pumps, biomass, geothermal). Here,renewable and low-carbon gases can play a role too, and hydrogen does nothave the disadvantages compared to biomethane that it has in heating individual
homes: District heating systems have only one gas connection, so there are noissues with adapting many connections and meters, and changing over large
numbers of homes at one moment. An efficient hydrogen-hybrid solution,
applicable at all scales of district heating, would be a combination of:– One or more electric heat pumps, to operate when (renewable) electricity isabundant and cheap and– A hydrogen-fired CHP (gas engine or, in future, a fuel cell), to operate when(renewable) electricity is scarce and expensive)
This hybrid solution for district heating is mentioned by IEA as well¹²⁸. While themix of renewable heat sources may vary by country, we have assumed a market
share of 30% for such hybrid solutions for all countries, and within that a 50%
share for hydrogen, and 50% for biomethane.
– Hydrogen-ready and pure Hydrogen Boilers. Hydrogen-ready boilers canoperate on natural gas and, after a simple conversion, on hydrogen as well.
They can be deployed in districts where it is expected that the gas in the
distribution grid will be replaced by hydrogen within the lifetime of a boiler. In
the application of hybrid heat pumps assumed in this study, this means that they
could become part of a hydrogen hybrid heat pump once this replacement takes
place. Pure hydrogen boilers can also be used as a 1-on-1 replacement of natural
gas-fired boilers; this option is not part of our analysis, but it is considered insome countries.
Pathway towards 2050
In this study, we focus on transport of 100% hydrogen by gas infrastructurecompanies. Blending in combination with deblending of a limited volume
percentage (5-20%),%, which is equivalent to 1.7-6.7% in terms of energy content
and achievable emission reduction) can play a role in an early stage of the transition,e.g. to add scale to hydrogen supply volumes, but soon, higher CO₂ reductions
will be demanded in the built environment. The -55% scenarios in the EC’s Impact
Assessment on Stepping up Europe’s 2030 climate ambition¹²⁹ even show emissions
reductions for residential buildings of 61.0-63.6% between 2015 and 2030.
Our analysis is based on data, follows a transparent approach, implying
simplification, and treats countries as homogeneously as possible, with clear
argumentation for possible differences. Given that in reality there are quite substantial
differences between countries and regions, both in terms of existing infrastructure
as well as building stock and policy discussion, working with ranges for demand iswarranted to compensate to some extent the simplified model approach.
Evolution of the building stock

128 IEA, The Future of Hydrogen (2019), https://www.iea.org/reports/the-future-of-hydrogen
129 European Commission. Impact Assessment forCommunication “Stepping up Europe’s 2030
Climate Ambition” https://ec.europa.eu/clima/sites/clima/files/eu-climate-action/docs/
impact_en.pdf

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
44

Data on the building stock and its energy situation is relatively scarce. There are over
300 million buildings in EU+UK, with an enormous diversity, and large differences
between countries, in composition of the building stock, energy systems, and inreporting. Any analysis therefore needs a significant simplification. Table 1 shows thesources of the data that we have used for our analysis.
The building floor area per country over time is calculated as follows:– Proportional to population growth, combined with,– 1% annual growth of floor space (both residential and services) per inhabitant
From this, the new built floor area is derived adding in a demolition rate of
0.1% per year for residential floor space and 0.5% per year for non-residential
floor space.

TABLE 1
Data and sources for residential andnon-residential buildings

#

Data

Sources / calculations

1

EU + UK Building stock

Stratego (EU Project), Eurostat, Hotmaps (open source mapping and planning
tool for heating and cooling)

2

Energy intensitity, current fuelshares, technology mix

Hotmaps (www.hotmaps.eu)

2Current renovation rates andimpact on energy demand

Earlier Navigant / Guidehouse analysis for the European Commission

4

Population forecast 202-2050

Eurostat, UN

5

Building area forecast

Own calculation, based on population forecast and incrase of area per inhabitant6

New floor space area

Own calculation, derived from building area forecast and assumed demolition rate

A crucial factor in energy and emissions scenarios for buildings is the ‘renovation
rate’. In the Renovation Wave communication, the EC concluded that the current
weighted annual energy renovation rate is low at around 1%. This estimate stems froma report by Ipsos and Navigant (now Guidehouse)¹³⁰, based on 30,000 consumer
interviews and thousands of interviews of architects, contractors and installers. The
impact of energy renovations on energy demand was calculated based on information
on which measures were taken. Renovations were categorised in three bins:– Light, with primary energy savings of 3-30%, current rate 4.1% of building stock
each year– Medium, with savings of 30-60%, current rate 1.4% per year
– Deep, with savings of 60% or more, current rate 0.2% per year.
In the Renovation Wave communication, the EC set the objective to “at least
double the annual energy renovation rate of residential and non-residential buildings
by 2030 and to foster deep energy renovations.”
We modelled this by taking three renovation scenarios:
1. Renovation-as-usual: We keep the annual renovations as they are now, for the
EU+UK: 4.1% for light, 1.4% for medium, and 0.2% for deep renovations.
2. Simple Doubled Renovation: we doubled the annual renovation rates across theboard, taking the EU+UK weighted average to 8.2% for light, 2.8% for medium,and 0.4% for deep renovations.
3. Intensified Deep Renovation: We multiplied all current rates of deep renovations
by 5, to achieve 1% per year, leaving the light and medium renovation rates attheir current values, taking the EU+UK weighted average to 4.1% for light, 1.4%
for medium, and 1.0% for deep renovations.

130 Ipsos/Navigant. Comprehensive study ofbuilding energy renovation activities and theuptake of nearly zero-energy buildings in the
EU (2019). https://ec.europa.eu/energy/sites/
ener/files/documents/1.final_report.pdf

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
45

Both the Simple Doubled Renovation and the Intensified Deep Renovation
increase the annual energy renovation rate (reduction of heat demand per m² offloor area) by approximately 45%. Given the current renovation rates, all buildings
have undergone some renovation by 2050, but the number that has undergone a
deep renovation by then is very limited under Renovation-as-usual (30 years at 0.2%
= 6%) and even under the Simple Doubling scenario (12%). Only in the Intensified
Deep Renovation Scenario, this reaches 30% of all building stock. This means thatmany buildings still have at best a moderate level of insulation, even by 2050, whichkeeps hybrid heating solutions relevant in the long run as well.
Both renovation scenarios will require a strong policy effort; so far, few successful
examples exist of drastically increasing renovation rates at national scale. Such
scenarios will highly depend on e.g. a sufficient number of craftsman to do the job,
and the ability of homeowners to make the substantial investments required for deep
renovations. We are disregarding those factors in our analysis but lower realised
renovation rates will obviously correspond to a higher demand for biomethane andhydrogen.
Choice of heating technology and fuelWhile renovation reduces heat demand and, as a consequence, final energy
demand, latest by 2050, the energy to produce the heat will have to be zeroemission. In 2014, final EU+UK energy use for space and water heating was around
3,250 TWh/year¹³¹, out of which 44% (1,440 TWh/year) was natural gas.
The fuel mix for space heating only as a share of total useful floor space,according to the Hotmaps Project¹³², is given in Figure 16:

FIGURE 16

Oil
District heating

10%

EU+UK fuel mix for space heating asa share of residential and commercial
floor space year

Wood / solar thermal

19%

Natural gas
Electricity

19%
7%

25,415 Mm²45%
131 EU Buildings Database, https://ec.europa.eu/
energy/eu-buildings-database_en
132 Hotmaps Project, D2.3 WP2 Report – Open
Data Set for the EU28, 2018. Simon Pezzutto,
Stefano Zambotti, Silvia Croce, Pietro Zambelli,
Giulia Garegnani, Chiara Scaramuzzino,
Ramón Pascual Pascuas, Alyona Zubaryeva,
Franziska Haas, Dagmar Exner (EURAC),
Andreas Müller (e‐think), Michael Hartner(TUW), Tobias Fleiter, Anna‐Lena Klingler,
Matthias Kühnbach, Pia Manz, Simon Marwitz,
Matthias Rehfeldt, Jan Steinbach, Eftim
Popovski (Fraunhofer ISI) Reviewed by Lukas
Kranzl, Sara Fritz (TUW). www.hotmapsproject.eu

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
46

Source: Hotmaps ProjectIn the current technology mix, condensing and non-condensing boilers dominate,using natural gas and oil as a fuel. Most of the electricity is still used in electricradiators, while wood (pellets) are used in stoves.
For this exploratory analysis of potential hydrogen demand in buildings, we havefollowed the reasoning in Gas for Climate reports that homes with a gas connection(currently using a gas-fired boiler) will over time switch to a hybrid heat pump.
Pure hydrogen boilers, currently introduced to the market by manufacturers, andhydrogen fuel cells, with which experience has been gained in Japan, have not beentaken into consideration, in view of the system benefits of hybrid heat pumps.

Our assumptions by current heating technology in existing buildings are thefollowing:– All existing buildings with district heating [DH] will keep that district heating but
switch to zero-emission sources of heat.
– Buildings with gas-fired heating will get a hybrid heat pump, using biomethane orhydrogen in combination with electricity. The share of the heat demand provided
by gas decreases with better insulation; for deeply renovated buildings, thebiomethane or hydrogen will only provide peak demand. Hence demand issignificantly reduced compared to a pure gas heating.
– All electrically heated buildings will get electric heat pumps [ASHP].
– Buildings now heated with oil will get a hybrid heat pump consisting of a
combination of an oil-fired boiler and a heat pump; the reduced oil demand will
be replaced by zero-emission liquid fuels over time.
– New buildings: 50% will get district heating, 50% an electric heat pump.
These assumptions are summarised in Table 2 below. In reality, more technology
switches will of course happen, but in a time frame of 20-30 years a lot of
infrastructure will also remain the same.
For the three renovation scenarios, we have calculated the development of
the floor space that has undergone light, medium, and deep renovation, by the
years 2030, 2040 and 2050, as defined above. The remainder was categorized as‘untouched’.
For the three renovation scenarios, we have calculated the development of thefloor space that has undergone light, medium, and deep renovation, by the years
2030, 2040 and 2050, labelling the remainder as ‘untouched’.
TABLE 2
Assumptions for replacement of existingbuilding heating systems (rows) under therenovation levels achieved (columns) in acertain year

Untouched

Shallow

MediumDeep

New

District heating

Zero-emission DH

Zero-emission DH

Zero-emission DH

Zero-emission DH

n/a

Gas

Hybrid heat pump
(G/E 70/30)

Hybrid heat pump
(G/E 60/40)

Hybrid heat pump
(G/E 40/60)

Hybrid heat pump
(G/E 20/80)

n/a

Renewables

Renewables

Renewables

Renewables

Renewables

n/aElectric

ASHP

ASHP

ASHP

ASHP

n/a

Other (oil)Hybrid heat pump(oil/E 70/30)

Hybrid heat pump(oil/E 60/40)

Hybrid heat pump(oil/E 40/60)

Hybrid heat pump(oil/E 20/80)

n/a

New

n/a

n/a

n/a

n/a

50% district
heating, 50% HP

DH = district heating, ASHP = Air-source heat pump, HP = heat pump

Subsequently, we have calculated the heat demand for the residential andservices floor space, divided into the two categories where hydrogen can play a role
(Hybrid Heat Pumps and District Heating) and a third category “Other”, containing
the floor space heated by all other solutions shown in Table 2. Overall, the heat
demand per m² of floor space in the pre-2020 buildings is reduced by 25% in the
Renovation-As-Usual scenario, and by 36% in both the Simple Doubled Renovation
and Intensified Deep Renovation scenarios.

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
47

Finally, we have assessed the potential low-carbon and renewable gas
development for hybrid heat pumps and district heating. It is assumed that hydrogenbased solutions are introduced gradually over time, given constraints on installation
rates and hydrogen infrastructure. We have assumed that the following hydrogenshares can be realised, as a fraction of the total floor space where hydrogen canplay a role:– 2030: 5%– 2040: 50%– 2050: 100%
Under the Renovation-as-usual scenario in Figure 17, most of the pre-2020
building floor space only reaches light or medium renovation level even by 2050,
while a small share of deeply renovated buildings and a larger amount of newbuildings have a much lower heating demand. The increasing penetration of lowcarbon and renewable gas the (potential) Hybrid Heat Pump and District Heating
segments of residential and services buildings leads to a renewable gas demand of
790 TWh in EU and UK by 2050.

35,000FIGURE 17

30,000Results buildings sector in
Renovation as usual scenario

25,00020,000Floor space

15,000New
Medium

5,000

light

0

Untouched

2020

2030

2040

million m²

10,000

Deep

2050
3,500

Heat demand

3,000

Other, services

2,500

Gas boiler –> HHP, services
District heat, services

2,000

Other, residential
Gas boiler –> HHP, residential

1,500

District heat, residential

Other = Wood / solar thermal + electric + oil.
Next to hydrogen, this scenario results in 510 TWhof biomethane demand in buildings by 2050.

500
0
2020

2030

2040

TWh/year

1,000

2050

Source: Guidehouse analysis

Under the second, the Simple Doubled Renovation scenario in Figure 18, thedominant renovation grade of the pre-2020 building stock is Medium. While theaddressable floor area is the same as in the Renovation-As-Usual scenario, the lowcarbon and renewable gas demand in the building sector is reduced to 580 TWh
by 2050.

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
48

35,000

FIGURE 18

30,000Results buildings sector simple
doubled renovation scenario

25,00020,000Floor space

15,000New
Medium

5,000

light
Untouched

0
2020

2030

2040

million m²

10,000

Deep

2050
3,500

Heat demand

3,000

Other, services

2,500

Gas boiler –> HHP, services
District heat, services

2,000

Other, residential
Gas boiler –> HHP, residential

1,500

District heat, residential

Other = Wood / solar thermal + electric + oil.
Next to hydrogen, this scenario results in 388 TWhof biomethane demand in buildings by 2050.

500
0
2020

2030

2040

TWh/year

1,000

2050

Source: Guidehouse analysis

Under the third, the Intensified Deep Renovation scenario in Figure 19, the shareof deeply renovated buildings increases to around 20% of the remaining pre-2020
building floor area. In combination with light and medium renovation rates at theircurrent levels, this leads to a low-carbon and renewable gas demand in buildings of
615 TWh/year by 2050.
35,000FIGURE 19

30,000Results buildings sector Intensified
deep renovation scenario

25,00020,000Floor space

15,000New
Medium

5,000

light
Untouched

0
2020

2030

2040

million m²

10,000

Deep

2050
3,500

Heat demand

3,000

Other, services

2,500

Gas boiler –> HHP, services
District heat, services

2,000

Other, residential
Gas boiler –> HHP, residential

1,500

District heat, residential

Other = Wood / solar thermal + electric + oil.
Next to hydrogen, this scenario results in 407 TWhof biomethane demand in buildings by 2050.

500
0
2020
Source: Guidehouse analysis

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
49

2030

2040

2050

TWh/year

1,000

The total demand for renewable and low-carbon gases in buildings is
580 TWh/year in Simple Doubled Renovation and 615 TWh/year in Intensified
Deep Renovation, compared to—for reference—790 TWh/year in the RenovationAs-Usual scenario.
Whether or not this demand can be met with biomethane depends on a
successful scale-up and its regional availability. In the optimistic case, basedon a prior Gas for Climate study wherein biomethane supply was estimated at
1,170 TWh/year, this study assumes that biomethane could be available to supply
80% of that demand, as shown in Figure 20 below.

FIGURE 20

Simple Doubled Renovation

Intensified Deep Renovation

Hydrogen and renewable andlow-carbon gas demand for heatingof buildings in EU and UK(in TWh/year)
615

580

Hydrogen demand estimate in this study
Total renewable and low-carbon gas demand

53

11
2030

2040

Source: Guidehouse analysis

150
2050

13
Total
renewable
and lowcarbon gas
demand

2030

56
2040

160
2050

Total
renewable
and lowcarbon gas
demandIn case these biomethane potentials do not materialise or in the event very
competitive hydrogen supplies were available, hydrogen could be used to meeta bigger share of this demand. This results in a range for the hydrogen demand inbuildings reaching from 0 to around 600 TWh/year depending on the achievable
renovation rate and developments of future renewable and low-carbon gas. In reality
the split between hydrogen and biomethane will vary significantly by region – withhydrogen likely taking up a more substantial share of demand in countries suchas the UK, Germany, and Luxembourg – where biomethane constraints are more
prominent and where discussions regarding the role of hydrogen in the buildings
sector are more prominent.
Sensitivity
The buildings sector has hundreds of millions of decision makers, and – as mentioned
above - a big diversity both between countries (climate, energy infrastructure, policy)
and within them (urban/rural areas, multi/single family homes, wide variety of nonresidential building uses). Applying a more or less homogeneous approach, as
attempted in this section is necessary to gain overall insights, but also challenging
because of this complexity.
When looking at the choices made here, those with the biggest impact on theoutcome are:
– Applying hybrid heat pumps to all existing buildings with a gas connection. The
advantages of this solution to the energy system, by ‘system integration behindthe meter’, are large, which should in the end also result in a cost advantage forbuilding users. However, in reality, other solutions will be chosen as well. For
example, in Germany, the UK, and Czech Republic, hydrogen boilers, fuel cells,
and micro-CHP plants are currently being considered for decarbonizing buildings
at very low costs (assuming a high availability of competitively priced hydrogen).
ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
50

– Assuming a high share of biomethane (80%) as the gas of choice for hybrid heatpumps, and a medium share of biomethane (50%) in renewable gas-fired CHPs
used for district heating. Development of sustainable biomethane supply is stillin its early stages, and most biogas is so far used in decentral cogeneration
plants. The easier transition from natural gas to biomethane makes the latterwell-positioned to speed up renewable and low-carbon gas volumes, but where
biomethane supply does not materialize, hydrogen can take a bigger share.
– The renovation rate. Here we have assumed that policies like the EU Renovation
Wave and national equivalents achieve their goals of significantly acceleratingenergy renovations. If this does not fully materialize, the demand for hydrogen inbuildings may go up moderately.
In specific regions or countries, the impact of other choices and developments
may be very large. If e.g. in the UK, the choice is made to use hydrogen boilers
instead of hybrid heat pumps, and a strong increase in energy renovations is
discarded, the resulting hydrogen demand in buildings can be as much as a factorof 10 higher than estimated here.
Overall, the existing gas grid, with its high capacity, and its ability to transition
from carrying natural gas to biomethane (gradually) and hydrogen (stepwise, after
a potential initial blending/deblending phase), can act as safety net and turns out tobe the most cost-optimal solution in the energy transition of the built environment.
The challenges connected to the full decarbonisation of buildings, which sees in the
deep renovation rate a hard-to-solve barrier which goes well beyond just achieving
energy savings and lowering the thermal consumption, may find in a combination of
biomethane and hydrogen heating technologies the potential solution to overcome
the aforementioned barriers. Technological developments will play a key role indriving the degree of adoption of the different options. Both at longer time scales,e.g. if it turns out to be costly and hard to achieve the desired acceleration in building
renovation, and at short time scales, e.g. by temporarily shifting electricity use to theuse of renewable and low-carbon gases, during ‘windless winter weeks’.

2.5. Conclusions on hydrogen demand
For the decarbonisation of industry, hydrogen will be a crucial feedstock in
multiple sectors. It is particularly relevant for ammonia, high value chemicals (HVC),
iron and steel, and bio and synthetic kerosene production, where electrification is
not an option. In these sectors, hydrogen is primarily used as feedstock, while
in industrial heat hydrogen demand is forecasted for mostly high temperatureprocesses. The bottom-up pathways for industry, enabling NUTS 2 level granularityof the demand estimations, are informed by company announcements, sector
decarbonisation roadmaps and interviews with relevant stakeholders. This analysis
therefore assumes a scenario where industry does not relocate within or outside ofEurope. Instead, the European Hydrogen Backbone enables the required transportof large amounts of clean energy in the form of hydrogen to the current industrial
locations.
In the transport sector electrification, where possible, is a promising option
for a range of transport modes, but there is still a clear role for hydrogen witha demand of about 300 TWh of hydrogen as a fuel in heavy-duty trucking andaviation, by 2050. Hydrogen-derived carriers such as synthetic kerosene in willplay an important role in decarbonising the aviation as well.

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
51

A quantity of approximately 650 TWh of hydrogen can be expected indispatchable electricity production in 2050, in a system with large shares ofwind and solar. The value of hydrogen, over most other flexible power options
such as batteries and demand response, is that it can be supplied and stored inlarge quantities at relatively low investment costs, making it particularly appealing
for longer duration storage.
Heating in buildings will be decarbonised using a range of technologies
with significant regional variations. The hydrogen demand depends on renovation
rates, the relative shares of biomethane and hydrogen, and the mix of heating
technologies. This study assumes Europe-wide accelerated renovation rates andhybrid heating systems in existing homes with a gas connection and in 30% of
district heating. Such hybrid systems use electricity (in a heat pump) and renewable
or low-carbon gas. This approach reduces energy system costs, enabling lower
cost to consumers and faster emission reduction. As the hybrid heating systems
mainly use gas as peak energy supply, gas demand is lower than in gas-only
solutions like hydrogen boilers and fuel cells considered in other studies. Under
this study’s assumptions, annual renewable and low-carbon gas demand inbuildings will be around 600 TWh in 2050. All of this could be hydrogen, yetassuming a scale-up of biomethane as in previous Gas for Climate studies, annualhydrogen demand would be around 150 TWh.
Expected EU+UK hydrogen demand by 2050 equals 2,300 TWh, consistingof 1,200 TWh in industry, 300 TWh in heavy transport, 650 TWh in power, and
150 TWh in buildings. Figure 21 below shows how these 2050 demand figurescompare with results from other recent EU decarbonisation studies. Note that thisstudy categorises hydrogen demand for synfuels under ‘Industry (feedstock &energy), rather than under transport as is done in the other scenarios.

3,500

FIGURE 21
3,102

Four scenarios on green and bluehydrogen demand by 2050 according torecent EU decarbonisation studies

3,000
2,607
2,300

2,178
1,023

2,000

528
1,200

1,782

792

1,155

300

Industry (feedstock & energy)

792Transport
Power

429

660

2,500

650

Buildings

1,500

1,000

500

0
EU EC - Impact
assessment SWD(2020) 176 - MIX

EU EC JRC LCEO Net ZeroFCH JU Roadmap Ambitious scenario

TWh H₂ (LHV)

528

Guidehouse European
Hydrogen Backbone

Note that this study (Guidehouse – European Hydrogen Backbone) categorises hydrogen demand for synfuels
under ‘Industry (feedstock & energy) rather than under transport, as is done in the other scenarios.

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
52

Key messages

3. Hydrogen
SupplyANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
53– Domestic green hydrogen supply potential in the EU and UK from dedicatedrenewables—considering the needs of the electricity market, land availability,
environmental regulations, and installation rates—is estimated to be 450 TWh in
2030, 2,100 TWh in 2040, and 4,000 TWh in 2050. This potential already takes
into account the growing need for renewable electricity for direct consumption,
land availability, environmental considerations and installation rates. Realising thispotential will likely require a rapid, vast expansion of wind and solar capacity,
beyond what is needed for direct electricity demand and corresponding tocumulative installed capacities of 1,900 GW in 2030, 3,200 GW in 2040, and4,500 GW in 2050. The 2030 installed capacity figure represents a more thandoubling of current cumulative National Energy and Climate Plan targets.
– From 2040, there can be sufficient green hydrogen supply available in Europe,
subject to public acceptance of an accelerated deployment of renewableinstalled capacities, to meet projected European hydrogen demand in all sectors
at lower cost levels compared to grey hydrogen and other fossil alternatives
plus the CO₂ price. By 2050, almost all of the potential 4,000 TWh of greenhydrogen can be produced for less than 2.0 €/kg, of which up to 2,500 TWh
can be produced below 1.5 €/kg and around 600 TWh can be produced at
1.0 €/kg. Supplying the entire projected 2,150-2,750 TWh hydrogen demand in
2050 using domestic EU and UK renewables would require around 2,900-3,800
TWh of dedicated renewable electricity. However, producing such quantities ofgreen hydrogen within the EU and UK is subject to public acceptance of anaccelerated expansion of renewable installed capacity even beyond currently
planned expansion.
– Europe also has a large potential to produce blue hydrogen. Supply is virtuallyunlimited as natural gas supply and CO₂¬ storage potential exceed the total
foreseen hydrogen demand. Blue hydrogen production costs are expected tobe 1.4-2.0 €/kg at moderate natural gas and CO₂-prices¹, but could rise up to
1.6-2.3 €/kg during the 2030s and 2040s when CO₂-prices further increase.
Natural gas producing countries could benefit from lower natural gas costs to
produce blue hydrogen at 1.0 €/kg. Blue hydrogen can quickly drive emission
reductions and accelerate the pace of the transition, especially in the market’s
ramp-up phase (2030), when green hydrogen supply potential from dedicatedrenewables alone will be insufficient to meet local and regional demand inabsence of a fully interconnected European hydrogen backbone. Although EU
and UK greenfield and brownfield blue hydrogen supply potential is almost
unlimited, projects announced to date add up to 230 TWh by 2030 and 380
TWh by 2035 and onwards – with 70% of announced project volumes stemmingfrom the UK and the Netherlands.
– Beyond 2030, deployment of new blue hydrogen projects will face increasing
competition from green hydrogen (domestic and import), as this becomes more
widely available at lower costs. However, there will still be a role for (by then)existing blue hydrogen projects—which have a lifespan of 25 years—to continue
producing as the marginal supply option and to contribute to system integration
and balancing of variable green hydrogen through firm, baseload hydrogenproduction.
– In addition to domestic EU and UK supply, abundant natural resources andphysical proximity drive the favourable economics of pipeline imports fromneighbouring regions such as North Africa and Ukraine, making these regions
attractive partners for future hydrogen trade. In the near-term, pipeline imports
will remain modest as these neighbouring regions focus on electrifying andmeeting the needs of their own growing economies. By 2040 and 2050,
pipeline imports become increasingly attractive, with estimated long-distancepipeline transport costs of 0.09-0.16 €/kg/1000km for 48-inch pipelines, which
only weigh marginally on the final delivery cost of hydrogen when considering
production costs of 1.0 €/kg or less.

3.1. Introduction
Different EU+UK decarbonisation scenarios conclude that renewable and bluehydrogen demand will grow significantly. The studies¹³³ in which these scenarios
are reported generally agree that expected volumes of hydrogen could technicallybe produced within the EU but point out that this would mean a substantial
acceleration in the deployment of additional wind and solar PV capacity. The further
development of an integrated, liquid, and competitive hydrogen market requires
a better understanding of the installed capacities of wind and solar needed forgreen hydrogen as well as potential capacities of blue hydrogen production, with anindication of the parts of Europe where new capacities could be built. In addition,
there remains a question around the extent to which hydrogen imports can play arole in complementing domestic, EU+UK hydrogen production.
This Chapter aims at presenting well-founded figures on the installed capacities
and costs of renewable and blue hydrogen required to implement Europe’s
decarbonisation ambitions. Sections [3.2] and [3.3] assess the European supply
potential and production cost of green and blue hydrogen, respectively. Section[3.4] provides an overview on the potential role of hydrogen imports, with anemphasis on Ukraine and North Africa, two regions identified as strategic partners
by the EC.

3.2. Green Hydrogen“There will be enoughelectrolyser manufacturing
capacity to meet European
demand. ITM Power is readyto facilitate the scale up ofhydrogen. Our new gigafactory
has a production capacity of 1
GW electrolysers per year and
we raised capital to build asecond Gigafactory to increase
annual capacity to 2.5GW peryear.”
Dr. Graham Cooley
Chief Executive Officer
ITM Power

133 Including, but not limited to: EU EC’s Impact
Assessment SWD(2020) 176; EU EC JRC –Towards net-zero emissions in the EU energy
system by 2050; FCH JU Roadmap.
134 Navigant (now Guidehouse), 2020, for North
Sea Wind Power Hub. Integration routes
for North Sea offshore wind 2050, https://northseawindpowerhub.eu/knowledge/
integration-routes-north-sea-offshorewind-2050

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
54

When it comes to assessing the supply potential of green hydrogen—and byextension, renewable energy—many studies start from the perspective of demand.
The question is often framed in the form of: “given a certain volume of expected
future demand, what would be the most practical and cost-effective way to supply
it, considering the supply options available?”. However, by constraining supply
requirements and solutions to best estimates of demand and existing supply
technologies, demand-driven approaches could miss important insights and possibly
underestimate the impact of new technological and commercial innovations on the
supply side.
a fully decarbonised power grid. In this case, green hydrogen supply would beconstrained by practical issues related to connecting renewable energy projects
to the power grid today, such as interconnection limits, permitting constraints, andpower grid congestion. In systems where a high share of wind and solar supplies theelectricity, hydrogen produced in periods of oversupply can be used to generate
dispatchable power in days and weeks with undersupply, as has been demonstrated
by modelling for 180 GW of offshore wind on the North Sea.¹³⁴
At the same time, connecting electrolysers directly to renewable energy projects
through “dedicated” green hydrogen plants offers benefits that allow these projects
to be developed under circumstances where conventional grid-connected projects
might not be practically feasible or economically viable. For example:a) In regions where the potential for green hydrogen production is large, andelectricity demand is already largely being covered by wind and solar, highadditional capacities of wind and solar can be directly connected to electrolysers,
saving on grid connections costs that would only be of use for a small percentageof the time.

b) Hydrogen can be stored cost-effectively over long periods of times, providing
longer term storage and the ability to balance the electricity grid. This can improvethe economics of renewable projects in areas where low renewable capture
prices would have otherwise made the economics of projects unattractive; andc) Hydrogen can be transported over long distances cost-efficiently, particularly
when large scale repurposed existing pipeline infrastructure is used. Again, greenhydrogen can help relieve pressure of the increasingly congested electricity gridwith high penetration of intermittent renewables.
These examples, although subject to the presence of an adequate hydrogendelivery system, demonstrate the nuanced aspects of creating an integrated energy
system, and highlight the importance of considering all solutions when assessing thehydrogen supply perspective. This section aims to make an objective assessment of
the green hydrogen supply potential.

3.2.1. Renewable energy supply potential

135 Throughout this study, ‘domestic’ strictly
covers the EU+UK countries. Although thisterm is sometimes used interchangeably with‘European’, non-EU countries are not included
within the ‘domestic’ umbrella.
136 ENSPRESO – an open data, EU-27+UK wide,
transparent and coherent database of wind,solar and biomass energy potentials. https://
ec.europa.eu/jrc/en/publication/enspresoopen-data-eu-28-wide-transparent-andcoherent-database-wind-solar-and-biomassenergy.
137 All land areas excluding urban, industry,
forests, transitional woodland-shrub, newenergy crops, natural land, infrastructure,
wetlands, water bodies, urban green leisure,and other natural land areas – as defined by
the Land-Use based Integrated Sustainability
Assessment (LUISA) classification.
138 World Bank. https://data.worldbank.org/
indicator/AG.LND.TOTL.K2?locations=EU

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
55

The basis for domestic green hydrogen supply is the renewable energy supply
potential in the EU+UK.¹³⁵ This renewable energy potential is defined as the technicalenergy potential from natural solar and wind resources (onshore and offshore) –adjusted for land availability, environmental regulations, turbine spacing constraints,
public acceptance, and technology deployment rates.
According to the European Commission’s Joint Research Centre (JRC), thetechnical renewable energy potential from solar and wind in the EU+UK isover 490,000 TWh per year.¹³⁶ Starting from this technical potential, practicalconstraints—per technology and per country—are applied to obtain a realistic
renewable energy supply potential, estimated to be around 11,100 TWh per
year, corresponding to approximately 5,600 GW (5.6 TW) of cumulative renewableinstalled capacity. The translation of the technical renewable energy potential of
490,000 TWh per year to the realistic renewable energy potential of 11,100 TWh
per year is shown in Figure 22.
– For solar PV, the main issue is land availability. This study assumes that the shareof non-artificial land area¹³⁷ available for ground-mount solar PV ranges between
0.1-2.0%, compared to the universal 3% assumed in the JRC’s ENSPRESOs
reference scenario.¹³⁶ In this analysis, we use national population density
as a proxy to refine the 0.1-2.0% land availability bracket for each country. In
general, it is assumed that countries with higher population densities face morecompetition for land—from built-up environment including industrial estates
and agriculture—and are able to dedicate less land to solar PV. In total, theland considered to be realistically available for ground-mount solar PV adds
up to around 45,000 km², or 1.1% of the total EU and UK land area of about
4,000,000 km².¹³⁸ Rooftop PV potential is also included.
– For onshore wind, a key constraining factor is the minimal distance required
between turbines and settlements. This study starts with ENSPRESO’s “EU-widehigh restrictions” scenario, which describes a scenario in which the exclusionof surfaces for wind energy is high across all countries. Surfaces that do notmeet country-specific minimum allowed setback distances from settlements are
excluded, as are regions with legislations that explicitly forbid wind projects
based on rotor diameter, hub height, or acceptable noise levels. Distance fromsettlements is set to 1200 m for small turbines and 2000 m for big turbines. In
addition, we apply a minimal capacity factor constraint by only considering sites
with capacity factors of 25% or higher, further narrowing the pool of potential
wind projects across Europe.
– For offshore wind, we adopt the country figures of Wind Europe’s “Our Energy,
Our Future” scenario, which estimates realistic offshore wind potential, including
floating offshore technology, in the North, Baltic, and Mediterranean Seas in linewith the European Commission’s 300 GW by 2050 target.

495,300

FIGURE 22

450,000

From technical to realistic renewableenergy potential in EU and UK(in TWh/year)

10,70023,500
11,100

5,700

3,500

Solar PV
Wind onshore

1,900Wind offshore

Technical
potential

Land availability
and surface
restrictions

Turbine spacing,minimum
capacity factors

Offshore
Realistic
regulations
potential(fishing zones, ships)

Source: Guidehouse analysis based on JRC’s ENSPRESO database for solar PV and wind potential

139 Share of RES in gross electricity consumption,
2019. https://ec.europa.eu/eurostat/web/energy/data/shares. https://ec.europa.eu/
eurostat/web/energy/data/shares. https://
ec.europa.eu/eurostat/web/energy/data/
shares.

To estimate the share of the EU+UK realistic potential of 5,600 GW—producing
11,100 TWh annually—that can be deployed over time, country-specific installation
rates are assumed based on several sources.
For onshore wind and solar PV, installation rates are assumed to gradually reach
80% of the realistic installed capacity of 5,600 GW by 2050. As individual countries
have different starting points and trajectories to reach this 2050 point, we use
current shares of renewable sources in gross electricity consumption as a proxyto capture these differences.¹³⁹ For offshore wind, the installation rate is taken fromWind Europe’s “Our energy, our future” report, which cites an operational capacityof 100 GW by 2030 and 260 GW by 2040, or 22% and 60% of the 2050 target,
respectively.
These installation rates lead to an estimated renewable energy supply potential
for EU+UK of around 3,300 TWh by 2030, 6,100 TWh by 2040, and 8,700 TWh by
2050. The corresponding cumulative installed capacities of solar PV, onshore wind,and offshore wind are 1,900 GW by 2030, 3,200 GW by 2040, and 4,500 GW by
2050, as shown in Figure 23.

FIGURE 23
Renewable energy potential (in TWh)with corresponding cumulative capacities(GW) in Europe in 2030, 2040, and 2050
TWh, electricity

GW, installed capacity
10,000

5,000

4,500

8,700
8,000
6,200

3,300
1,800
1,050
2030 realisable

4,500

3,200

4,000
3,200

6,000
1,900

4,000
2,700

1,900
1,100

1,500

2040 realisable

2050 realisable

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
56

3,000

3,200

2,000

2,240

1,390

2,000
345

410

0
2019

2030 realisable

700

950

721

1,000

341

Wind: onshore

02040 realisable

2050 realisable

Solar PV
Wind: offshore

Current 2030
NECP target

The cumulative target currently announced across EU+UK National Energy andClimate Plans (NECP) for 2030 is added for reference.
Source: Guidehouse analysis based on JRC’s ENSPRESO database, Wind Europe (2020): “Our Energy, our Future”

These estimations, while based on well-founded external sources, are not intended
to serve as a prediction how renewable energy deployment will or should happen.
There are many reasons why deployment of renewables could diverge from the
trajectory suggested by the above figures, many of which are highly region-specific.
For example, public acceptance considerations already hamper the development ofonshore wind and land-based solar-PV today, even in countries with a relatively low
population density such as Sweden. Scaling up domestic renewables within EU+UK
to the potential mentioned above will surely meet significant societal opposition. This
could be one further reason to import green hydrogen from less densely populatedareas along the European borders, as is explored in Section 3.4.

3.2.2. Green hydrogen supply potential

140 TYNDP (2020). TYNDP 2020 Scenario Report.
https://2020.entsos-tyndp-scenarios.eu/.
Includes geothermal, tidal, hydro, municipal
solid waste, biogas, solid biomass, nuclear,fossil gas, fossil oil, coal. Similar to the final
electricity demand scenario, for a selectnumber of countries national figures wereadapted to better align with national plans.
141 Gas for Cimate (2020). Gas Decarbonisation
Pathways 2020-2050. For a select number ofcountries national figures were adapted tobetter align with national plans.
142 BNEF, Hydrogen Project Valuation (H2Val)
Model.

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
57

To translate the renewable energy potential in 2030, 2040, and 2050 into the greenhydrogen supply potential for EU+UK, several factors are considered.
– First, net supply for electricity is adjusted for by adding the production
volumes that can be expected from all non-solar PV and wind power
generation technologies, including but not limited to nuclear, hydropower,
bioenergy, and fossil fuels. To ensure that the generation mix used to estimate
this share of ‘other power generation’ is aligned with decarbonisation targets,
we base the assumed future power mix on TYNDP’s 2020 Global Ambition
scenario, extrapolated out to 2050, leading to 1,040 TWh in 2030, 590 TWh
in 2030, and 470 TWh non-solar PV and wind generation in the EU+UK in
2050.¹⁴⁰– Second, as renewable electricity should be used as “electricity first—if
possible”, a widespread electrification of end-use technologies is expected.
Starting from the total supply potential, we subtract final electricity demandas estimated by Gas for Climate in its Accelerated Decarbonisation scenario:
3,700 TWh in 2030, 4,100 TWh in 2040, and 4,500 TWh in 2050.¹⁴¹– Third, the impact of hydrogen use for dispatchable power – amounting to
12 TWh in 2030, 301 TWh in 2040, and 626 TWh in 2050 as describedin Section 2.3 – is accounted for by adding the dispatchable renewableelectricity that results from the hydrogen-to-power installation that contributes tomeeting final electricity demand. Herein we assume that hydrogen-to-power has
a conversion efficiency of 50%, leading to hydrogen-to-power contributions ofaround 5 TWh in 2030, 150 TWh in 2040, and 320 TWh in 2050. Electrolyser
efficiencies are assumed to be 71% in 2030, 76% in 2040, and 80% in 2050.¹⁴²– What remains is considered as the renewable electricity supply potential
which can be made available for dedicated green hydrogen projects.
That is, potential solar PV and wind energy developments which have not beenaccounted for in power network planning and which are assumed to add limited
incremental value to the power grid – economically and from a decarbonisation
trajectory perspective. This renewable electricity supply potential adds up to 645
TWh in 2030, 2,740 in TWh in 2040, and 4,990 TWh in 2050.
– Finally, conversion losses from electrolysis are factored in, using the same
efficiency assumptions mentioned above, to obtain the green hydrogen potentialof around 450 TWh in 2030, 2,100 TWh in 2040, and 4,000 TWh in 2050.

Aggregated EU and UK level results are illustrated in Figure 24. Again, it isimportant to note that these estimates only consider dedicated green hydrogen
supply and exclude green hydrogen produced from grid-integrated electrolysis.¹⁴³This is an important simplifying assumption as grid-integrated electrolysis, whencombined with adequate market design and regulatory requirements¹⁴⁴, could playa key role in driving the creation of a liquid hydrogen market in the initial ramp-up
years.
Initially, electrolysers will mainly be deployed in industrial clusters close tohydrogen demand using electricity from the grid at high utilisation factors. Ashydrogen demand increases and electrolyser installation costs decline, electrolysers
move to renewable energy sources and hydrogen pipelines connect supply anddemand. Longer term, local, demand-sited electrolysers may remain to provide
flexibility to the electricity grid alongside batteries and other dispatchable
technologies. They may also be justified if electricity grid expansions are too difficultfor economic or practical reasons. Electricity and gas TSOs alike are already today
exploring hybrid, cross-sectoral solutions to integrate large volumes of variable
renewable energy into the European energy system cost-optimally—without
overdesigning the power grid.¹⁴⁵

143 For example, Germany’s national hydrogenstrategy has set a 5 GW electrolyser capacity
target for 2030, with an additional 5 GW until
2035 (latest 2040).
144 For example, additionality of renewables,
temporal correlation with electricity prices orgrid emission factors.
145 See for example: North Sea Wind PowerHub (2021). Towards the first hub-and-spoke
project. https://northseawindpowerhub.eu/
node/178.

5

FIGURE 24
3,300
2030

Translating renewable energy
supply potential to green hydrogen
supply potential – taking into
account the needs for electricity
and conversion losses – in 2030,
2040, and 2050

1,040
-3,700

1,800

-195

1,050

450

645

590

150

-4,100

2040

3,100

-660

1,900
2,740

2,080

1,100

8,700

470

320

-4,500

Solar PV
Wind: onshore

4,500

Wind: offshore
H₂-to-power
Final electricity demand
Renewable energy potential
for dedicated green H₂

2050

Hydro, nuclear, fossil-1,000
2,700

4,990

Conversion losses

3,990Green hydrogen

1,500
Source: Guidehouse analysis basedon Gas for Climate and TYNDP futureenergy scenarios

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
58

Power
generation
potentialfromrenewableenergyPower
generationfrom hydro,
nuclear, fossil,other non-PV
and windgenerationPowergenerationfromhydrogenFinalelectricity
demandTWh,electricity

Renewable
electricity
potential for
dedicated green
H₂

Conversion
lossesGreen
H₂potential

TWh,hydrogenEven after considering the needs for electricity, Figure 24 shows that there
remains a substantial volume surplus of renewable energy that can generate greenhydrogen in Europe: around 450 TWh in 2030, 2,100 TWh in 2040, and 4,000
TWh in 2050.
Although the needs for electricity as analysed above are a major driver of thegreen hydrogen supply potential, other direct and indirect factors along the supply
chain must also be carefully managed to ensure reliable, sustainable, and affordable
supply, including:146 IEA (2021), The Role of Critical Minerals in
Clean Energy Transitions, IEA, Paris https://www.iea.org/reports/the-role-of-criticalminerals-in-clean-energy-transitions.
147 IRENA (2020), Green Hydrogen Cost
Reduction – scaling up electrolysers tomeet the 1.5C climate coal. https://irena.
org/-/media/Files/IRENA/Agency/
Publication/2020/Dec/IRENA_Green_hydrogen_cost_2020.pdf.
148 European Environment Agency (2021). Use of
freshwater resources in Europe. https://www.
eea.europa.eu/data-and-maps/indicators/
use-of-freshwater-resources-3.
149 Electrolyser capex figures are selectedfollowing a literature review of several studies,including BNEF: Hydrogen Project Valuation(H2Val) Model; Agora-AFRY: No-regrethydrogen; Florence School of Regulation:
Clean Hydrogen Costs in 2030 and 2050.
Additional techno-economic parameters(capex, opex, efficiency, discount rate) are
specified in Appendix B.

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
59– Critical minerals: While not exclusively related to green hydrogen, the rapid
deployment of clean energy technologies such as solar PV, wind, batteries,and electrolysers as part of energy transitions implies a significant increase indemand for minerals. Until recently, the energy sector represented a small part of
total demand for minerals. However, in a scenario that meets the Paris Agreement
goals, their share of total demand rises significantly over the next two decades toover 40% for copper and rare earth elements, 60-70% for nickel and cobalt, andalmost 90% for lithium.¹³⁶ The rapid growth of hydrogen as an energy carrier also
underpins major growth in demand for nickel and zirconium for electrolysers, andfor platinum-group metals for fuel cells. Today’s mineral supply and investment
plans are geared to a world of more gradual action on climate change and must
be revisited to support accelerated energy transitions. According to the IEA’s
report “The Role of Critical Minerals in Clean Energy Transitions”, these risks to
the reliability, affordability, and sustainability of mineral supply are manageable,
but will require action from policy makers to ensure adequate investment in
new sources of supply, recycling, supply chain resilience, and strengthened
international collaboration between producers and consumers.¹⁴⁶– Water use: Hydrogen production through electrolysis requires water as amain input. From a purely stoichiometric approach, in order to produce 1 kg ofhydrogen 9 kg of water is needed. However, after taking process inefficiencies
and the process of water demineralisation into consideration, the typicalwater consumption amounts to between 18 - 24 kg of water per kilogram ofhydrogen.¹⁴⁷ For reference, if the entire projected EU+UK demand in 2050,
consisting of 2,250 TWh or 68 million tonnes, were supplied with fresh water,
total water consumption would be around 1,400 million tonnes or 1,400 cubic
hectometres. By comparison, the EU agriculture sector uses around 98,000 cubic
hectometres of water today.¹⁴⁸ Against the backdrop of rising temperatures andchanging precipitation, existing and expected regional water supplies must be
analysed carefully to ensure that local water supplies are not depleted for waterelectrolysis, particularly in hot and dry areas where solar PV resource is moreabundant. If feasible, seawater desalination plants can be used with limited costand efficiency impacts, and multipurpose desalination facilities can potentially be
implemented to provide local benefits.¹⁴⁷

3.2.3. Green hydrogen production costs
Levelised production costs of green hydrogen, expressed in €/kg, are determinedat country-level assuming hydrogen is produced from dedicated solar PV, onshorewind, or offshore wind projects. Herein we model renewable energy projects pairedwith alkaline electrolysers assumed to cost 270 €/kW in 2030, 200 €/kW in 2040,
and 135 €/kW in 2050, plus operating expenses. Solar PV and wind capacity
factors per country are taken from the ENSPRESO database and explain the variancein cost levels between countries.¹⁴⁹

For each country, green hydrogen production costs per technology are plottedagainst green hydrogen supply potentials (excluding hydrogen for power) as
estimated using the methodology detailed in Section 3.2.2. Results, displayed in
Figure 25 show that a substantial share of the green hydrogen potential can besupplied at cost-competitive levels, especially in 2040 and 2050:– By 2030, up to 150 TWh of green hydrogen can be produced at 2.0 €/kg orless and around 10-15 TWh around 1.5 €/kg. The remaining ~300 TWh would
cost more than 2.0 €/kg.
– By 2040, up to 1,600 TWh of green hydrogen can be produced at 2.0 €/kg orless of which up to 500 TWh around 1.5 €/kg. The remaining ~500 TWh would
cost more than 2.0 €/kg.
– By 2050, almost all of the potential 4,000 TWh of green hydrogen can beproduced for less than 2.0 €/kg, of which up to 2,500 TWh below 1.5 €/kg andaround ~600 TWh at 1.0 €/kg. The remaining ~900 TWh would cost between
1.5 €/kg and 2.0 €/kg.
For reference, green hydrogen delivered at 2.0 €/kg can compete with greyhydrogen at a CO₂ price of around 100 €/tCO₂. At 1.5 €/kg, the break-even CO₂
price is around 50 €/tCO₂, and green hydrogen delivered at 1.0 €/kg outcompetes
grey hydrogen outright, even without a CO₂ price. However, this does not consider
that grey hydrogen is currently produced on-site at constant supply. Electrolysisbased hydrogen using grid electricity can achieve a similar baseload output, but
only at smaller scale and with a carbon footprint dependent on the grid that feeds
it. Dedicated green hydrogen projects from variable renewable energy can bedelivered at large scale with a constant supply. However, this requires a dedicatedhydrogen pipeline and storage delivery system to “firm” the variable production
profile which comes at additional cost not captured in the production costs shownin Figure 25.

Note: Green hydrogen “firming” requirements, i.e. shaping variable supply to match
off-takers’ consumption profiles, vary depending on the supply technology and enduse sector. This process will make use of dedicated gas storage facilities combinedwith smart grid operation, as is done to provide secure and baseload natural gas
supply to consumers today.

150 IEA (2019). The Future of Hydrogen. https://www.iea.org/reports/the-future-of-hydrogenhttps://www.iea.org/reports/the-future-ofhydrogen
151 BNEF, Hydrogen Project Valuation (H2Val)
Model.
152 Clean Hydrogen costs in 2030 and 2050:
a review of the known and the unknown.
https://www.europeanfiles.eu/energy/cleanhydrogen-costs-in-2030-and-2050-a-reviewof-the-known-and-the-unknown.
153 IRENA (2019) A renewable energy perspective
https://www.irena.org/publications/2019/Sep/
Hydrogen-A-renewable-energy-perspective
154 IRENA (2020) Green hydrogen cost reduction
https://irena.org/publications/2020/Dec/
Green-hydrogen-cost-reduction and IEA(2021) net-zero by 2050 https://www.iea.org/
reports/net-zero-by-2050

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
60

These expected production costs assume a significant decline compared to
today’s costs between 2.5 and 6.2 €/kg according to IEA.¹⁵⁰ Achieving such cost
reductions will be subject to improvements in electrolyser design and construction,
economies of scale, and greater efficiency and flexibility in operations, undercontinued policy support driven by ambitious European and national climate
mitigation goals.
Note that future green hydrogen production cost estimates vary widely amongst
literature studies: BloombergNEF (BNEF) estimates that green hydrogen can beproduced well below 2.0 $/kg (1.65 €/kg) by 2030 and well below 1.0 €/kg
(0.83 €/kg) by 2050 in most markets¹⁵¹; and a study by the Florence School ofRegulation forecasts a range of 0.9-2.3 €/kg for solar PV and 1.7-2.8 €/kg foroffshore wind by 2030 and 0.6-1.7 €/kg for solar PV and 1.4-2.1 €/kg for offshore
wind by 2050.¹⁵² In these forecasts, the lower end of the cost range assumes
more aggressive electrolyser capex reductions, increased utilisation factors, ora combination of both, than in this study. Other reports, such as IEA's Future of
Hydrogen¹⁵⁰ and IRENA's Green Hydrogen Cost Reduction¹⁵⁴ cite somewhat
higher costs for green hydrogen of between 1.1 and 3.4 €/kg by 2030.

FIGURE 25
Supply-production cost curves ofEuropean (EU+UK) green hydrogen supply
potential from dedicated renewables in
2030, 2040, and 2050

Wind onshore
Wind offshore

2030

3.5

Expected renewable and blue hydrogen
demand in 2030: ~340 TWh

3.0
2.5
2.0 €/kg

2.0

1.5 €/kg

1.5
1.0
0.5
0.0

2,000

2,500

3,000

3,500

4,000

2040

3.5
Expected renewable andblue hydrogen demand in 2040: ~1,350
TWh

3.0
2.5
2.0 €/kg

2.0

1.5 €/kg

1.5
1.0
0.5
0.0

0

500

1,000

1,500

2,000

2,500

3,000

3,500

Levelised cost of dedicatedgreen hydrogen production, €/kg H₂

0
500
1,000
1,500
TWh dedicated green hydrogen potential in Europe

Levelised cost of dedicatedgreen hydrogen production, €/kg H₂Solar PV

4,000

2050

3.5

Expected renewable andblue hydrogen demand in 2050: ~2,300
TWh

3.0
2.5

2.0 €/kg

2.0

1.5 €/kg

1.5
1.0
0.5
0.0

0
500
1,000
1,500
TWh dedicated green hydrogen potential in Europe
Source: Guidehouse analysis assuming electrolyser
costs as reported by BNEF and RES-E capacity
factors from JRC’s ENSPRESO database

2,000

2,500

3,000

3,500

Levelised cost of dedicatedgreen hydrogen production, €/kg H₂

TWh dedicated green hydrogen potential in Europe

4,000

Each volume ‘slice’ on the x-axis represents green hydrogen production potential—after considering the needsof the electricity market—in a specific country.

The hydrogen supply-cost estimates in Figure 25 show that, by 2040 and 2050,
there can be sufficient green hydrogen supply available in Europe to meet projected
European demand in all sectors at cost levels competitive with grey hydrogen andother fossil alternatives in the different end-use sectors. By 2030, taking into accountfinal electricity demand, land availability, environmental regulations, and technology
deployment rates, the estimated green hydrogen supply potential does not exceed
the projected 340 TWh demand. This means that especially during the initial rampANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
61

up phase—although not exclusively during this time—other renewable and blue
supply sources including domestic blue hydrogen and green hydrogen imports
from neighbouring regions will be needed to enable a quick start to the use ofhydrogen to drive emission reductions.

3.2.4. Green hydrogen and electrolysis innational hydrogen strategies

155 Assuming electrolysers are operated at 4000
full load hours and 70% conversion efficiency.
156 According to The EC’s Delegated Regulation:
Criteria for Sustainable Hydrogen Activities
approved on 21 April 2021, hydrogen will beconsidered to contribute substantially to climatechange mitigation if it complies with the life
cycle greenhouse gas emissions savings
requirement of 73.4% resulting in 3tCO₂eq/
tH2. https://www.lexology.com/library/detail.aspx?g=a2943c48-e8b7-4ac2-bdc4872d25362427

FIGURE 26
National hydrogen strategies andelectrolysis targets by 2030

Policy support will play a crucial role to scale green hydrogen up to 2030. In A
hydrogen strategy for a climate-neutral Europe, the European Commission announced
a strategic objective to “install at least 40 GW of green hydrogen electrolysers by
2030 and the production of up to 10 million tonnes of green hydrogen in the EU”.
The first of these two objectives—deploying 40 GW of electrolysers by 2030 in
the EU, if met—can be expected to produce around 110 TWh of hydrogen fromelectrolysis¹⁵⁵ National hydrogen strategies announced to date already foreseearound 37 GW of cumulative installed capacity by 2030, and a number of countries(Austria, Czech Republic, Denmark, Slovakia, Hungary, Bulgaria, Greece) are stilldeveloping their strategies.
At the same time, these announced targets are non-binding and in some cases
ambiguity exists regarding the inclusion of blue hydrogen. In the UK it is also unclear
whether the announced target includes Scotland or if Scotland has set its own
5 GW target. Importantly, as a share of the planned electrolyser capacity will be gridconnected, the extent to which these volumes can be classified as green hydrogen
will depend on how this will be defined in the EU Taxonomy for sustainable activities
and other relevant regulations.¹⁵⁶

H₂ strategy adopted
H₂ strategy in development

3 GWC

0.2-0.5 GW
3-4 GW
5 GW
5 GW

2 GW

6.5 GW
A

B
C

Spanish and Italian figures refer to mobilised
investments while German and French figuresrefer to spent public funds.
Figures according to National Hydrogen
Strategy Preliminary Guidelines.
3GW given for Sweden is suggested in thegovernmental initiative Fossil Free Swedenhydrogen strategy as planning goal for 2030.
The official hydrogen strategy for Sweden isstill under development by the Swedish Energy
Agency, to be presented in Nov 2021.

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
62

2-2.5 GW

4 GWA

5 GWA, B

Source: Guidehouse analysis based on European countries’ National hydrogen strategies

Nonetheless, if these national ambitions and non-binding targets can be translated
into adequate regulatory and financial incentives through further policy support andmarket design, it is reasonable to posit that the 40 GW by 2030 European hydrogentarget could be met. Europe would then work towards the European Commission’s
second, much more aspiring, (‘up to’) 10 Mt of green hydrogen by 2030 ambition,
which corresponds to 330 TWh hydrogen. However, given the virtually non-existentmarket for green hydrogen today and an estimated green hydrogen supply potential of
260 TWh, achieving this volume target seems unlikely without incentives for additionalsources of market supply, including for blue hydrogen and imports.

3.2.5. Summary

157 Assuming a natural gas price of 20 €/MWh. Seeblue hydrogen production costs in Figure 29.

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
63

In summary, an analysis of the green hydrogen supply potential in Europe—taking
into account final electricity demand, land availability, environmental regulations, andtechnology deployment rates—shows that by 2040, there can be sufficient greenhydrogen supply available in Europe to meet projected demand in all sectors. In the
ramp-up phase to 2030, additional supply sources including domestic blue hydrogenand green hydrogen imports from neighbouring regions will be needed to meet
local and regional demand in absence of a fully interconnected European hydrogen
backbone and enable a quick start to the use of hydrogen to drive emission reductions.
By 2040 and 2050, European supply potential for hydrogen could exceed final
demand quite substantially. Even then, supplying hydrogen entirely from within Europe
might not be optimal in all circumstances due to a range of practical, economic, andpolitical reasons.
First, reaching the potential is subject to a step-change in ambition as it requires
more than 2 times more renewable energy capacity to be built by 2030 compared towhat is targeted in existing national climate and energy plans. As shown in Figure 23,
total Europe-wide NECP installed capacity targets for solar PV and wind by 2030 add
up to around 720 GW, whereas reaching the potential outlined in this study would
require almost 1,700 GW to be deployed by 2030, and 4,500 GW by 2050.
Second, not all domestic green hydrogen supply potential will—excluding policy
support—be cost-competitive with alternative decarbonised options such as bluehydrogen, especially in the early 2030s, and green hydrogen imports, towards thelate 2030s and 2040s. At production costs above 2.0 €/kg, green hydrogen without
subsidies will be outcompeted by large-scale greenfield blue hydrogen projects and
CCS-retrofitted steam methane reformers, which can reach production costs of around2.0 €/kg at CO₂ prices of 50 €/tCO₂.¹⁵⁷ Furthermore, green hydrogen production
might face additional costs due to the intermittency of renewable electricity, whichhave not yet been included in the calculations.
Third, the supply-demand picture is highly country-specific. The fact that Europe
has enough supply potential to meet demand on aggregate does not mean that this is
the case for each member state. Some countries have the potential to be in a renewableenergy surplus whereas others are likely to find themselves in a deficit. Accordingly,
some countries can become net exporters of renewable energy – as electricity,hydrogen, or both – whereas others will likely need to import. These internationalenergy flows will be driven by economics as well as energy politics and, dependingon the country, can include production from within and from outside Europe.
Fourth, NIMBY-ism (“Not In My BackYard”) already hampers the development ofonshore wind and land-based solar-PV today, even in countries with a relatively low
population density such as Sweden. Scaling up domestic renewables within EU and
UK to the potential will surely meet significant societal opposition. This could be one
further reason to import green hydrogen from less densely populated areas along theEuropean borders whilst also providing an income to these neighbouring countries.
For these reasons, complementing domestic production with hydrogen imports bypipeline from neighbouring regions can be a viable strategy for the EU, even though
European supply potential is sufficient. This will be explored in Section 3.4.

FIGURE 27
Green hydrogen supply potential fromdedicated renewables per major EU and
UK region in 2030, 2040, and 2050
(in TWh)

10
2030

180

600

2030

2040

60

390

2030

2040

90
2040

60

270

2030

2040

480
2050

730
2050

260
2050

110

490

2030

2040

900
2050

1,100
2050

40
2030

210
2040

410
2050

Green hydrogen
Source: Guidehouse analysis

3.3. Blue Hydrogen

158 Gas for Climate (2019)
159 H-Vision (2020) annex to main report.
160 https://www.klimaatakkoord.nl/binaries/klimaatakkoord/documenten/
publicaties/2019/06/28/kliimaatakkoordhoofdstuk-industrie/klimaatakkoordc3+Industrie.pdf

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
64

Assuming sufficient natural gas is available, also in view of the expected decrease indemand for its direct use, the technical potential of blue hydrogen production is intheory only limited by CO₂ storage. Onshore and offshore aquifers and hydrocarbon
fields together add up to over 100 Gt CO₂ storage potential in the European
Union and the UK.¹⁵⁸ Assuming an emission factor of 0.018 tCO₂ per MWh of bluehydrogen under a high, 94% capture rate for Auto Thermal Reforming technology,¹⁵⁹
this would mean that technical blue hydrogen potential is virtually unlimited at over
360,000 TWh of hydrogen.
As with green hydrogen, the very large European potential for blue hydrogenis limited by various factors. Blue hydrogen today faces regulatory and politicalacceptance constraints. The Gas for Climate 2019 study¹⁵⁸ explored, in Appendix E(see in particular Table 36 on page 129) the public acceptance and legal possibilities
and barriers of CO₂ storage across Europe. In the Netherlands for example, politicalacceptance of blue hydrogen is high compared to other European countries: The
Dutch government now stimulates CCS via its SDE++ support scheme,¹⁶⁰ albeit notbeyond 2035 and limited to 50% of the necessary emission reduction in industry
and power generation by 2050. The 2019 Gas for Climate study also highlighted thenecessity to minimise methane leakage of natural gas during both exploration andtransport. Gas TSOs are working to address this issue, but action by gas producing
countries will be required as well.

Future costs of blue hydrogen are very much dependent on the technology,
scale, and proximity to CO₂ storage options, as well as the price of the natural gas
feedstock. This study considers two blue hydrogen production use-cases with a high(95%) and low (60-70%) capture rate scenario for 2030 and onwards:– Greenfield ATR: a large-scale (> GW size) newly built Auto Thermal Reformer(ATR)¹⁶¹ + Carbon Capture and Storage (CCS) with high 95% capture rate
– Brownfield SMR: adding CCS to an existing Steam Methane Reformer (SMR),
onsite with 60-70% capture rate

161 ATR is considered as the best suitedtechnology (large-scale) blue hydrogenproduction, mainly for the high CO₂ capture
rate of ~95% that it enables, but also several
other reasons such as operational flexibility
and economies of scale, more details found in
H-Vision (2020) and H21 (2018)
162 H-Vision (2020), Gas for Climate (2019), IEA(2019), GH expertise
163 EC Impact Assessment (2020) https://
ec.europa.eu/clima/sites/clima/files/euclimate-action/docs/impact_en.pdf
164 Bloomberg (2021) https://www.bloomberg.
com/news/articles/2021-04-01/the-eus-carbon-market-is-about-to-enter-itsturbulent-20s
165 Osorio et al (2021) available at https://www.sciencedirect.com/science/article/pii/
S0306261921003962
166 Main assumptions: CAPEX and capture rate:
Brownfield SMR= 375-1,175 €/kW and 60-66%,
Greenfield ATR= 800-1,000 €/kW and 94%.
Further assumptions found in appendix, Table
24.Table 23.

In Figure 28, for both cases, levelised production costs are shown under
different input cost ranges. The main differences between the high and low cases
include CO₂ transport and storage costs – ranging between 20 and 50 €/tCO₂¹⁶²– and the assumed depreciation levels of the existing SMR units. Three scenarios
are included for CO₂ price in the EU ETS for 2030, from 50-150 €/tCO₂. This
represents the uncertainty and different views on the CO₂ price development,
which already reached 50 €/tCO₂ today. The estimates for 2030 differ: theEuropean Commission estimates a price of 60 €/tCO₂¹⁶³ by 2030, BNEF estimates100€/tCO₂¹⁶⁴, while another recent study even forecasted 129€/tCO₂¹⁶⁵ by
2030. The natural gas price is an important cost factor too and is assumed to be
20€/MWh and constant. It should be noted that future natural gas prices in a net
zero energy system can fall well below 20 €/MWh, translating into blue hydrogencosts as low as 1 €/kg - less than the low estimate shown in Figure 28.
The cost advantage of brownfield SMR blue hydrogen projects compared togreenfield ATRs decreases during the 2030s due to rising CO₂ prices and thelower capture rate. Taking into account also the fact that many brownfield SMR
projects would be geographically distanced from potential CO₂ storage sites, thisstudy assumes that 50% of the 270 TWh/year existing SMR fleet can be retrofittedwith CCS to produce blue hydrogen. The retrofitting is assumed to be graduallydeployed up to 2035. The other 50%, which can technically be retrofitted with
CCS, but at a cost that makes them economically uncompetitive, are assumed tocease operation over time.

FIGURE 28
Costs of blue hydrogen production
under different CO₂ prices and capex
assumptions by 2030¹⁶⁶
2.42
2.22
High estimate

2.03
0.60

1.97

1.94
0.37

0.64

0.69

2.00
0.37

0.37

Low estimate

1.57

1.43

Retrofitted SMR(brownfield)

New ATR(greenfield)

CO₂ price= 50 €/tCO₂

1.58

Retrofitted SMR(brownfield)

1.60

New ATR(greenfield)

CO₂ price= 100 €/tCO₂

1.73

Retrofitted SMR(brownfield)

1.63

New ATR(greenfield)

CO₂ price= 150 €/tCO₂

Natural gas feedstock prices are assumed to be 20 €/MWh across all cases.¹⁶⁵
Source: Guidehouse analysis with input assumptions taken from the H-Vision project in Port of Rotterdam

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
65

167 https://www.globalccsinstitute.com/archive/
hub/publications/119811/costs-co2-transportpost-demonstration-ccs-eu.pdf
168 The H21 project wants to deploy 12.15 GW of
new ATR capacity in 9 1.35 GW units and thisstudy projects 2 to materialize by 2030 andthe other 7 by 2035. H21 (2020) available athttps://www.northerngasnetworks.co.uk/wpcontent/uploads/2018/11/H21-Meeting-UKClimate-Change-Obligations.pdf
169 https://www.gov.scot/news/building-a-newenergy-sector/
170 https://www.globalccsinstitute.com/newsmedia/press-room/media-releases/ukgovernment-set-to-fund-four-ccs-hubs-andclusters/
171 Assuming the reference scenario of 3.2 GW
installed ATR capacity.
172 https://www.equinor.com/en/news/20210218join-forces-engie-hydrogen.html

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
66

Greenfield ATR projects can reach high CO₂ capture rates of 94% and are
therefore almost unaffected by the rising CO₂ price. These larger blue hydrogenprojects are also expected to be relatively close to the (subsea) CO₂ storage sites,
for instance at the ports of Rotterdam in the Netherlands and Teesside in the UK,
limiting CO₂ transport costs. This could mean that their production cost could becloser to the lower end of the range shown in the figure, i.e. 1.4-1.6 €/kg.
With greenfield blue hydrogen production costs of 1.6-2.0 €/kg, generally nearhydrogen demand hubs, greenfield blue hydrogen production in Europe can enable
a quick start of the use of hydrogen to drive emission reductions. By doing so,blue hydrogen could serve as an accelerator of hydrogen developments on the
demand and infrastructure side. Blue hydrogen could also complement the variablesupply of green hydrogen which is dependent on the daily and seasonal profiles ofrenewables.
Beyond 2030, deployment of new blue hydrogen projects will face increasing
competition from green hydrogen, as this becomes more widely available at lower
costs. The costs of green hydrogen will come down over time with rapidly decreasing
electrolyser and renewable electricity costs, and more widely available as Europe’shydrogen pipeline infrastructure grows, while the costs of greenfield blue hydrogenare expected to remain constant with potentially increasing operating cost. At the sametime, there will still be a role for (by then) existing ATRs—which have a lifespan of
25 years—to continue producing as the marginal supply option and to contribute tosystem integration and balancing of variable green hydrogen through firm, baseloadhydrogen production.
In countries where CCS acceptance is low or where limited geological storage
opportunities exist, CO₂ would have to be transported over substantial distances by
pipeline or by ship, which would add approximately 0.1 €/kg H₂ to the cost of the
project.¹⁶⁷
Below the announced greenfield blue hydrogen projects are described andaccumulated, which are limited to a few countries. In reality more projects might
emerge before 2040, which are not accounted for in this study.
The majority of the announced greenfield blue hydrogen projects are in theUK, accounting for 102 TWh/year by 2030 (Acorn CCS, H₂1¹⁶⁸, H2H Saltend, H2
Teesside, HyNet North West, project Cavendish and Humber zero). The total capacityof all announced projects grows to 179 TWh/year by 2035, when the large H21
project aims to fully materialise. This would account for more than the UK nationaltarget of 5 GW installed hydrogen production capacity by 2030, which assuming
8,000 load hours per year would come to 40 TWh in 2030. There are however
uncertainties about this 5 GW target, for instance seeing that Scotland also separately
set a 5 GW target by 2030¹⁶⁹. The substantial capacities reflect the UK’s large CCUS
ambition which includes the goal to establish four CCUS hubs and clusters by 2030,
with €1.15 billion of funding announced¹⁷⁰. Additionally, in the UK blue hydrogen is
anticipated to play a substantial and widespread role in decarbonising sectors supplied
by natural gas today, including heating of residential and commercial buildings, while
also blending hydrogen in the natural gas network is anticipated at large scale.
Outside the UK, mainly due to political and/or regulatory uncertainty, only a
few greenfield blue hydrogen projects have been proposed or announced. In the
Netherlands, H-Vision¹⁷¹ and Aramis together plan to produce around 33 TWh/year of greenfield blue hydrogen by 2030 and in Germany, the H2morrow projectis assumed to add another 9 TWh/year. In Italy, the Adriatic Blue CCS project is
expected to have a capacity of 23 TWh/year by 2030. In other EU countries such as
France¹⁷², no capacities have been announced or projected, so no greenfield bluehydrogen is assumed other than the above-mentioned projects.
In total, greenfield blue hydrogen supply potential in the EU+UK, as per
projects announced today, account for 167 TWh/year by 2030 and 244 TWh/yearby 2035, with 70% being in the UK in 2035. Adding brownfield blue hydrogenproduction to this number leads to a total of 234 TWh/year by 2030 and 378 TWh/year by 2035 and onwards.

3.4. Imports of green and blue hydrogen“We are excited to partner with
the European Commission andleverage Ukraine's excellent
natural resources to support
decarbonisation of Europe
through accelerating theexport of green hydrogenfrom Ukraine to Europe.”
Oleksander Riepkin
President
Ukrainian Hydrogen Council

173 A hydrogen strategy for a climate-neutral
Europe. https://ec.europa.eu/energy/sites/
ener/files/hydrogen_strategy.pdf.
174 For example, Hydrogen Europe’s “A 2x40
GW initiative” contains a Roadmap to40 GW electrolyser capacity in NorthAfrica and Ukraine by 2030. https://www.
hydrogen4climateaction.eu/2x40gw-initiative.
175 Blue’s the colour: Equinor and Gassco set
sights on huge Norway hydrogen export
pipeline. https://www.upstreamonline.com/
energy-transition/blues-the-colour-equinorand-gassco-set-sights-on-huge-norwayhydrogen-export-pipeline/2-1-964408. https://www.upstreamonline.com/energy-transition/
blues-the-colour-equinor-and-gassco-setsights-on-huge-norway-hydrogen-exportpipeline/2-1-964408.
176 https://www.gazprom.com/press/news/2021/
march/article525372/
177 Including BNEF: Hydrogen Project Valuation(H2Val) Model; Agora-AFRY: No-regrethydrogen; Florence School of Regulation:
Clean Hydrogen Costs in 2030 and 2050;
IRENA (2020), Green hydrogen cost reduction.

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
67

Major potential green hydrogen supply regions outside of the EU27+UK include
North Africa and Ukraine. Taking into account natural resources, physicalinterconnections, and technological developments, both regions have been
identified as priority partners for cooperation on clean hydrogen in the European
Commission’s EU Hydrogen Strategy¹⁷³ and are frequently mentioned in discussion
papers published by industry.¹⁷⁴
In addition, the thinking and strategising about possible green hydrogen imports,shipped as ammonia or methanol, from overseas regions with export ambitions suchas the Middle East, Chile, and Australia, is gaining traction. However, because of
the high conversion and reconversion costs of ship transport, these projects tend to
focus on decarbonising demand sectors where hydrogen-derived carriers such as
ammonia and methanol can be consumed directly, e.g. in shipping.
Blue hydrogen imports from natural gas producing countries like Norway andRussia are also an option. Concepts and studies on this subject have been announced,
including for example a proposed blue hydrogen export pipeline from Norway tocontinental Europe by Equinor and Norway’s gas system operator Gassco,¹⁷⁵ twoorganisations involved in natural gas exports to Europe today. Similarly, Russianstate-owned company Gazprom has announced plans to further develop its own
technological competencies. Gazprom’s focus areas include “the production ofhydrogen from methane with zero CO₂ emissions and the development of hydrogentransport methods, inter alia, for the purpose of export”.¹⁷⁶ Russia, in theory, also hasa large renewable energy potential in the form of solar, wind, hydro, and biomass.
Even though it would represent a remarkable change in strategic direction, tapping
into this renewable energy potential using repurposed existing natural gas pipeline
infrastructure could offer Europe with an additional source of large-scale greenhydrogen.
In Russia and Norway blue hydrogen could be produced using natural gas at
exploration and production costs of below 5€/MWh, which would lead to bluehydrogen production costs of around 1 €/kg by 2030 if produced at large scaleusing greenfield ATRs. This is lower than the estimates in Figure 28, which assume
natural gas prices as delivered in locations where the majority of blue hydrogenprojects today are being planned.
At the same time, the benefit of lower blue hydrogen production costs in thesepotential export regions needs to be weighed against the alternative of importing
natural gas and producing blue hydrogen within the EU+UK. Factors to consider
here include the location of and public support for CCS, CO₂ transport and storage
costs, pipeline repurposing costs and availability, and methane leakage. Over time,
blue hydrogen is also expected to face increasing cost-competition from greenhydrogen assuming that electrolyser and renewable energy technology costs
develop as shown in Figure 25 and as forecasted by other recent studies mentioned
previously.¹⁷⁷
This green hydrogen could be produced domestically, as analysed in Section
3.2, or it could be imported from European neighbouring regions. Given theirproximity and renewable resource abundance, imports from solar PV-poweredhydrogen produced in North Africa (e.g. Morocco and Algeria) and hydrogen fromsolar PV and onshore wind in Ukraine could be an attractive option.
Applying a simplified supply potential analysis using the same methodology
as previously done for the EU+UK in Section 3.2, we estimate how much greenhydrogen can be produced from dedicated renewables in Ukraine, Morocco, andAlgeria, also considering local final electricity demand. The main assumptions areshown in Table 3 below and the supply-cost curves are displayed in Figure 29.

TABLE 3

RegionRenewable energy production andelectricity consumption assumptions for
Ukraine and North Africa

UkraineMorocco& Algeria

Parameter

Assumptions

Solar PV

– Technical potential: 800 GW ¹⁷⁸– Capacity factor: 19% ¹⁷⁹– Deployment rate: 10% in 2030, 20% in 2040, 50% in 2050¹⁸⁰

Onshore wind

– Technical potential: 320 GW ¹⁸¹– Capacity factor: 35% ¹⁷⁹– Deployment rate: 10% in 2030, 25% in 2040, 60% in 2050¹⁸⁰

Final electricity
demand– 170 TWh in 2030, 193 TWh in 2040, 210 TWh in 2050¹⁸²

Solar PV

– Technical potential: 1000 GW ¹⁸³– Capacity factor: 30% ¹⁷⁹– Deployment rate: 10% in 2030, 25% in 2040, 60% in 2050¹⁸⁰

Final electricity
demand– 102 TWh in 2030, 134 TWh in 2040, 165 TWh in 2050 ¹⁸²

As shown in Figure 29, we estimate that:– By 2030, up to 60 TWh of dedicated green hydrogen can be produced in
North Africa and Ukraine at production costs of 2.0 €/kg or less, of whicharound 45 TWh from North African solar PV available at production costs of
1.35 €/kg.
– By 2040, North Africa and Ukraine have the potential to produce and export
more than 500 TWh of green hydrogen, at average production costs well below
2.0 €/kg. This includes around 330 TWh from dedicated solar PV plants inNorth Africa at costs of 1.0 €/kg and 170 TWh of hydrogen from Ukrainian solar
PV and wind.
– By 2050, green hydrogen export potential in North Africa and Ukraine increases
to around 1,700 TWh. Almost all of this volume can be produced at costs
below 1.5 €/kg, with up to 1,000 TWh of export potential from solar PV-basedhydrogen from North Africa available at production costs of 0.80 €/kg.

178 SolarPower Europe, 100% Renewable
Europe. https://www.solarpowereurope.org/
wp-content/uploads/2020/05/SolarPowerEurope-LUT_100-percent-Renewable-Europe_
Summary-for-Policymakers_mr.pdf.
179 https://www.renewables.ninja/.
180 Guidehouse assumption.
181 IRENA (2017). Cost-competitive renewable
power generation: Potential across South
East Europe. https://www.irena.org/
publications/2017/Jan/Cost-competitiverenewable-power-generation-Potentialacross-South-East-Europe.
182 International Energy Agency for current
demand, extrapolation assumption by
Guidehouse.
183 Fraunhofer Institute for Solar Energy
Systems (2016). Supergrid – Approach for the
integration of renewable energy in Europe andNorth Africa.

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
68

As with domestic (European) green hydrogen production, a range of factors
need to be considered in addition to the production costs presented above. In
the case of Morocco and Algeria, these countries will need to first and foremost
address the needs of their growing populations and economies. In “Towards acomprehensive Strategy with Africa”, the European Commission notes that Africa
as whole will need to double its energy supply by 2040 while ensuring access toelectricity for its 600 million inhabitants. This means putting the focus on resilient
infrastructure, cleaner, more sustainable and secure energy access, maximising
renewable energy sources, energy transition and efficiency across all value chains,
as well as regional integration for energy security. Although North Africa can bea potential supplier of cost-competitive green hydrogen to the EU, this should notcome at the expense of other priority policy objectives.
Furthermore, as discussed previously in Section 3.2, regional freshwater
availability must be analysed to ensure that local water supplies are not depleted forelectrolysis. Where needed, costs of desalination facilities, as a possible source forfreshwater, need to be taken into account in the full delivery price of hydrogen from
North Africa. Finally, the above estimates do not yet include costs for long-distancehydrogen transport, nor do they include the costs of storage for firming variable
renewable energy generation.

FIGURE 29
Supply-cost curve of green hydrogen
supply potential from outside Europe in
2030, 2040, and 2050

Wind onshore

2030

3.0
2.5
2.0 €/kg

2.0

1.5 €/kg

1.5
1.0
0.5
0.0

750

1,000

1,250

1,500

1,750

2040

3.0
2.5
2.0 €/kg

2.0

1.5 €/kg

1.5
1.0
0.5
0.0

0
250
500
TWh dedicated green hydrogen potential

750

1,000

1,250

1,500

Levelised cost of dedicatedgreen hydrogen production, €/kg H₂

0
250
500
TWh dedicated green hydrogen potential

Levelised cost of dedicatedgreen hydrogen production, €/kg H₂Solar PV

1,750

3.0
2.5
2.0 €/kg

2.0

1.5 €/kg

1.5
1.0
0.5
0.0

0
250
500
TWh dedicated green hydrogen potential
Source: Guidehouse analysis

750

1,000

1,250

1,500

Levelised cost of dedicatedgreen hydrogen production, €/kg H₂

2050

1,750

Each volume ‘slice’ on the x-axis represents green hydrogen production potential—after considering the needsof the electricity market—in Ukraine and North Africa.

In spite of these factors, the favourable economics of pipeline imports from theseneighbouring regions, driven by abundant natural resources and physical proximity,
make them attractive partners for future hydrogen trade. With long-distance pipelinetransport costs estimated at 0.09-0.16 €/kg/1000km for 48-inch pipelines as shownin Figure 30 in Section 4.1, the transport component only weighs marginally on the
final delivery cost of hydrogen when considering production costs of 1.0 €/kg or
less. This means that importing hydrogen by pipeline presents a viable strategy tocomplement domestic EU+UK production, in particular in 2040 and 2050 and to alesser extent in 2030.
ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
69

Key messages

4. Hydrogen
Transport
Infrastructure– Hydrogen pipelines are the most cost-efficient option for long-distance, highvolume transport of hydrogen to connect hydrogen supply regions with demandclusters within the EU+ UK. The EHB is estimated to cost €0.11-€0.21/kg/1,000
km on average, outcompeting transport by ship for all reasonable distances within
Europe and between Europe and potential neighbouring export regions.
– Cost-efficient hydrogen transport by pipeline enables hydrogen imports fromneighbouring regions such as North Africa, Ukraine, Norway, and potentially the
Middle East – where renewable energy is abundant and cheap – to complement
domestic hydrogen production and to support the security of European supply.
– All shipping methods – ammonia, LOHC, and LH₂ – have high upfront costs,
related to conversion and reconversion installations and in the case of LOHC
the carrier chemical costs. Ship-transport is three to five times more expensive
compared to pipeline transport when looking at north-Africa and Saudi Arabia.
For imports from Australia pipelines are not an option and ship-transport costs are
estimated to be around €1/kg of H₂.
– Hydrogen pipelines and electricity networks each possess their complementarystrengths when it comes to long-distance transport of decarbonised energy
carriers. The cost-optimal energy transport option depends on factors such as thedesired end-use energy carrier, availability and cost of storage, renewable energy
supply characteristics, and network topology. For high-volume transport of energy
when the desired end-product is hydrogen, pipelines – both newly built andrepurposed ones – are 2 to 4 times more cost-effective than power lines. This
comparison excludes storage costs for electricity and hydrogen.
– The consideration between gas and electricity transport is not only an economic
question but also one of societal acceptance. Whereas a 48-inch hydrogenpipeline can have a throughput capacity of up to 16.9 GW, power lines typicallypossess throughput capacities in the range of 2 to 3 GW each. This means that, totransport volumes of energy corresponding to a 48-inch pipeline (the size that isused today with natural gas) using power lines would require the equivalent of 5 to
9 overhead transmission lines.

4.1. Hydrogen Transport by Pipeline
A hydrogen pipeline network would be comprised of essentially the same
components as natural gas pipelines are operated today, assuming hydrogenstorage will be as widely available as natural gas storage is today. Gas pipelines
have various diameters, typically 20-48 inch at the transmission level, depending on
the market characteristics of the region being served by the pipeline. Transmission
pipelines are operated at different pressures, typically between 50-80 bar. Larger
diameters and higher pressures allow pipelines to provide higher throughputs.

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
70

Hydrogen has different properties than natural gas that must be taken into
account when designing or repurposing a pipeline network. At high pressures,hydrogen can over time cause localized embrittlement when in contact with baresteel. But oxide layers prevent contact between hydrogen and steel. Minimizing
fluctuations in operating pressure can also prevent hydrogen embrittlement.
Hydrogen is also a smaller molecule than methane and is more prone to leakage
and permeation. Hence, repurposing existing natural gas pipelines into dedicatedhydrogen pipelines requires integrity assessments to be conducted concerning
the potential presence of crack-like defects and tightness-related modifications ofvalves and fittings. Depending on the state of the existing infrastructure, repurposed
pipelines may need to be operated at lower pressures to ensure compliance withexisting engineering codes. Furthermore, different driver and compressor designs
will likely be required for hydrogen, meaning existing compressors cannot be
repurposed. This is because hydrogen’s low molecular weight would require mostexisting centrifugal compressors to rotate three times as fast in order to achieve thesame level of compression.¹⁸⁴,¹⁸⁵ Repurposing natural gas infrastructure for use withhydrogen is technically feasible, at a modest cost compared to the construction of
new pipelines, although exact costs of repurposing are subject to more detailed
engineering studies and – where compression is needed – replacement ofcompressors and potentially drivers will be required.
The major cost components of a gas pipeline are the pipeline CAPEX, compressor
CAPEX, and the electricity required to power the compressors. European gas TSOs
conducted hydraulic simulations to determine the throughput and compression
power for the following three common natural gas pipeline configurations in Europe:– 48-inch and 80 bar, 36-inch and 50 bar, and 20-inch and 50 bar. Simulations were
performed for 100%, 75%, and 25% of the theoretical maximum throughput capacity
to determine how compression needs vary with throughput. Table 4 summarises thethroughputs corresponding to each modelled pipeline scenario.
TABLE 4

Pipeline Diameter

Maximum theoretical throughput ofpipelines at different % capacities¹⁸⁶

and Pressure

184 https://www.energy.gov/eere/fuelcells/
gaseous-hydrogen-compression
185 More detailed cost assumptions can be foundin Appendix C.1. Hydrogen Transport by
Pipeline
186 Dynamic operation of pipelines required
to balance the energy system cansignificantly decrease throughput in practice.
Available at https://gasforclimate2050.eu/
sdm_downloads/extending-the-europeanhydrogen-backbone/
187 Full load hours vary depending on geography
due to country-specific network factors.
188 More detailed cost assumptions can be foundin Appendix C.1. Hydrogen Transport by
Pipeline

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
71

100% Capacity

75% Capacity

25% Capacity

48-inch, 80 bar

16.9 GW

12.7 GW

4.2 GW

36-inch, 50 bar

4.7 GW

3.6 GW

1.2 GW

20-inch, 50 bar

1.2 GW

0.9 GW

0.3 GW

The hydraulic simulations were then used to estimate the levelised cost oftransport for new and repurposed pipelines. The analysis assumes all pipelines
operate 5,000 full load hours, which is a typical average for natural gas
transmission pipelines¹⁸⁷. Note that in practice load factor is a product of manyfactors such as fluctuations in demand, use of storage, and network configuration.
Furthermore, intermittent load profiles from electrolysers will require hydrogenpipelines to have dynamic capacities. Figure 30, Figure 31, and Figure 32 show
the levelised transport cost breakdown for 48-inch, 36-inch, and 20-inch pipelines
respectively at 100%, 75%, and 25% utilisation.¹⁸⁸ Note that 25% utilisation factor
is below the typical operational range for pipelines, however results are included
here to illustrate the impact on costs during early stages of network development
before expected flows are reached. Levelised costs for 20-inch pipelines are in€/kg/200 km because they are typically used for shorter distances than larger
diameter pipelines due to their low throughput and higher levelised cost.

0.35 €FIGURE 30
Breakdown of levelized cost of new andrepurposed 48-inch pipelines operating
at 100% capacity, 75% capacity, and
25% capacity

0.30 €

0.02

0.20 €
0.07

0.15 €

0.29
0.10

Pipe CAPEX (€/kg/1000 km)
Compressor OPEX (€/kg/1000 km)
Compressor CAPEX (€/kg/1000 km)

0.10 €

0.07
0.04
48-inch,16.9 GW

0.07
0.04

0.04

0.02
48-inch,12.7 GW

48-inch,4.2 GW

48-inch,16.9 GW

New

0.02
0.04
0.02
48-inch,12.7 GW

0.02
0.05
48-inch,4.2 GW

0.05 €
0.00 €

Repurposed

1.00 €FIGURE 31
0.06

Breakdown of levelized cost of new andrepurposed 36-inch pipelines operating
at 100% capacity, 75% capacity, and 25%
capacity

0.80 €

0.60 €

0.84

Pipe OPEX (€/kg/1000 km)
Pipe CAPEX (€/kg/1000 km)
Compressor OPEX (€/kg/1000 km)
Compressor CAPEX (€/kg/1000 km)

0.21

0.40 €

0.07

0.27
0.06

0.05
36-inch,4.7 GW

36-inch,4.7 GW

36-inch,1.2 GW

36-inch,4.7 GW

New

FIGURE 32

36-inch,3.6 GW

0.20 €

0.17
36-inch,3.6 GW

0.00 €

Levelized Cost (€/kg/1000 km)

Pipe OPEX (€/kg/1000 km)

Levelized Cost (€/kg/1000 km)

0.25 €

Repurposed

0.50 €

0.03

Breakdown of levelized cost of new andrepurposed 20-inch pipelines operating
at 100% capacity, 75% capacity, and 25%
capacity

0.40 €

0.46

Pipe OPEX (€/kg/200 km)
Pipe CAPEX (€/kg/200 km)

0.12

0.20 €

0.15

0.03

Compressor OPEX (€/kg/200 km)

0.03

0.08

20-inch,1.2 GW

20-inch,289 MW

Compressor CAPEX (€/kg/200 km)

20-inch,1.2 GW

20-inch,883 MW
New

Source: Guidehouse analysis

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
72

20-inch,883 MW

20-inch,1.2 GW

Repurposed

0.10 €

0.00 €

Levelized Cost (€/kg/200 km)

0.30 €

“Beginning of 2021 more than
30 European energy players
launched "HyDeal Ambition"with the aim of delivering
100% green hydrogen fromsolar power on the Iberian
Peninsula and in Northern
Africa at €1.5/kg before 2030.
As DH2 Energy, a developerof mass-scale solar projects
dedicated to hydrogenproduction we are part of thisinitiative. Our goal requires ahydrogen transmission andstorage network that connects
green hydrogen producedin Southern Europe (andother potential sources) withcustomers across Europe. The
European Hydrogen Backbone
is a key enabler for us.”Thierry Lepercq
President and Co-founder
DH2 Energy

189 Guidehouse (2021): Extending The European
Hydrogen Backbone. Available at https://
gasforclimate2050.eu/sdm_downloads/
extending-the-european-hydrogenbackbone/

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
73

Smaller diameter pipelines have lower unit capital costs than larger diameter
pipelines, however they have higher costs per kg transported due to their lower
throughput. Large, high-pressure pipelines, while more affordable from a levelised
cost perspective, require larger safety distances from civilization, which may
complicate routing. Several factors must be considered when planning pipeline
routes and associated diameters and pressures. For new 48-inch pipelines at
80 bar and repurposed 36-inch pipelines at 50 bar, compressor power is a significant
expense, and operating the pipeline at 75% capacity lowers the compressor power
sufficiently to lower the overall levelized cost. Further cost optimisation can likely be
performed to maximize throughput while lowering compressor power to determine
the optimal capacity to operate these pipelines at. Repurposed 48-inch pipelines
are cheaper to operate at 25% than 75% capacity. This presents a cost-effective
transport option in early years when hydrogen flows are modest and infrastructure is
gradually developed. However, in later years after the industry has scaled, it is likelythat operating a pipeline at such a low capacity would require building additional
pipeline capacity to meet demand. As hydrogen flows ramp up, throughput canbe increased to a more appropriate level by constructing additional compression
capacity. For new 36-inch pipelines at 50 bar and new and repurposed 20-inch
pipelines at 50 bar, pipeline CAPEX is a much larger cost than compressor OPEX
per unit of hydrogen transported, so operating at maximum throughput is optimal
from a levelized cost perspective.
It is important to note that hydraulic simulations performed for this cost analysis
modelled a 1,000 km pipeline stretch with no branching or off-takers. They do notincorporate a scenario-based simulation of a full-scale network as is commonly
done for network development planning. In reality, the backbone will be a complex,
meshed pipeline grid with many branches, off-takers, and changes in pipeline
diameter and pressure, and these differences will influence the overall cost of
the backbone and lead to locational differences in levelised costs. Furthermore,
required hydrogen capacity and load factor are expected to shift over time as aresult of changing market dynamics, having both positive and negative impacts on
the cost estimate. However, by taking an infrastructure-driven view (as opposed todesigning for a specific system demand) and by selecting a generic network designfor the analysis, the resulting parameters and cost ranges are deemed representativeof the EU+UK average.
In creating the EHB maps, participating gas TSOs were consulted to determine
the lengths and diameters of pipelines in their country’s proposed hydrogen
network. The backbone will consist of a wide variety of diameters, pressures, andwill consist of new pipelines and repurposed natural gas pipelines. Pipelines weregrouped into large, medium, and small pipelines. The 2040 backbone is comprisedof 46% large pipelines, 42% medium pipelines, and 12% small pipelines¹⁸⁹.
Furthermore, 69% of the backbone is repurposed. When estimating the total cost,large pipelines were modelled as 48-inch pipelines at 80 bar, medium pipelines as
36-inch pipelines at 50 bar, and small pipelines as 20-inch at 50 bar. The averagelevelised cost of the backbone was determined to be €0.11-€0.21/kg/1,000 km(€3.6-€7.0/kWh/1,000 km) by weighting the length and capacity of each pipelinesize, new and repurposed.

4.2. Hydrogen Transport by Ship
Hydrogen has a low energy density, which makes it challenging to transporteconomically by ship. However, several methods of shipping are being investigated,
and this study examines three of the most promising:
1. liquid hydrogen,2. liquid organic hydrogen carriers (LOHCs)
3. ammonia.

190 Al-Breiki and Bicer (2020). Comparative costassessment of sustainable energy carriers
produced from natural gas accounting forboil-off gas and social cost of carbon. https://www.sciencedirect.com/science/article/pii/
S2352484720312312.
191 Hurskainen and Ihonen (2020): Technoeconomic feasibility of road transport ofhydrogen using liquid organic hydrogen
carriers. https://www.sciencedirect.com/
science/article/pii/S0360319920332134

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
74

All three shipping methods involve converting gaseous hydrogen into a moreenergy dense liquid so that more energy can be transported. The shipping process
can be broken down into seven steps: 1) pipeline from the hydrogen production
site to the export terminal, 2) conversion of gaseous hydrogen into the shipping
medium, 3) storage at the import terminal, 4) shipping, 5) storage at the export
terminal, 6) reconversion to gaseous hydrogen, and finally the 7) pipeline to thedemand location.
Liquid hydrogen: Hydrogen has a boiling point of -253 °C, so liquefying gaseous
requires substantial compression and cooling. This process consumes the equivalentof roughly one third of hydrogen’s energy content but increases the volumetricenergy density by a factor of more than 10 compared to gaseous hydrogen at 80 bar.
Storage and transport containers for the liquid hydrogen must be very well insulated
to minimise the amount that boils off. The hydrogen is shipped on a vessel similar toan LNG tanker. A portion of the boil-off can be used as fuel for the ship, however theremaining boil off is flared to the environment in order to limit the pressure build up
inside the tank and prevent rupturing. Methods of reducing and eliminating boil-off
have been investigated, such as using tanks that can withstand higher pressures or
having a reliquefaction system onboard the ship. However, neither of these methods
have been demonstrated to be cost-effective.¹⁹⁰
LOHCs refer to organic chemicals that reversibly react with hydrogen to formchemicals that can be easily transported by ship. Good candidates are relatively
non-toxic, inexpensive, capable of “storing” large quantities of hydrogen, haverelatively low temperature conversion and reconversion reactions, and can withstandmany cycles. The most promising LOHC candidates are derivatives of toluene.¹⁹¹
Toluene can be reacted with hydrogen to produce methylcyclohexane, which can be
shipped and then reconverted into hydrogen and toluene. LOHC shipping typicallyconsumes more fuel than the other two methods because the LOHC is heavier thanammonia or hydrogen and must be shipped back after reconversion, meaning thatthe ship contains a full load each way and cannot transport a different cargo on
the return trip. The ship must also have a carbon-neutral fuel such as hydrogen,ammonia, or a synfuel to propel the ship since the cargo cannot be used as fuelwithout producing GHG emissions. Finally, the LOHC itself represents an additional
cost because it must be purchased and replaced as it degrades – approximately
0.1% is lost every conversion/reconversion cycle.
Ammonia involves the reaction of gaseous hydrogen with gaseous nitrogen toform ammonia via the Haber-Bosch process, one of the most widely used chemical
processes on the planet. Ammonia has a boiling point of -33 °C, so ammonia
shipping vessels must be insulated to keep the ammonia in liquid form, howeverboil-off is a much smaller concern for liquid ammonia than liquid hydrogen. As in
liquid hydrogen shipping, ammonia can be used to fuel the ship, and fuel demand ishigher than the boil-off rate, so excess boil-off is not a concern. However, cracking(reconversion) of ammonia back to nitrogen and hydrogen is relatively inefficientand not yet proven at scale. An advantage to ammonia shipping is that ammonia

is already internationally traded so the shipping infrastructure already exists and isproven. Another advantage is ammonia is a widely used chemical in and of itself, so
not all of the delivered ammonia necessarily needs to be reconverted to hydrogen.
Ammonia shipping may be able to benefit from the scale of combined ammonia
and hydrogen demand. This analysis considers hydrogen as an energy carrier, andreconversion of ammonia to hydrogen remains inefficient and unproven at scale.
For all three shipping methods, the fixed costs related to conversion andreconversion are the most significant portions of the total shipping cost, making up
between 60 to 80% of total transport costs for a 10,000 km journey. The marginal
cost increase per km shipped is relatively minor, so longer distances make the casefor shipping stronger. Figure 33 breaks down the levelized cost of each shipping
method assuming an illustrative 10,000 km route and 100 km pipelines from theproduction site to the export terminal and from the import terminal to the demandsite. Liquid hydrogen and ammonia ships are modelled to return to their origin
empty, though dual-use ships may be possible.¹⁹²
1.40
1.20

FIGURE 33
Levelized shipping cost breakdown for
liquid hydrogen, LOHC, and ammonia
over 10,000 km¹⁹³

0.80
0.60
0.40

Pipeline to Demand
Reconversion
Storage

0.20

Shipping
Conversion
Pipeline to Export

Liquid Hydrogen
Shipping

LOHC
Shipping

Ammonia
Shipping

0.00

Transport Cost (€/kg H₂/10,000 km)

1.00

Source: Guidehouse analysis

192 Forbes (2019): Dual Use LNG Shipping: A
Gamechanger For Carbon Management?
https://www.forbes.com/sites/
uhenergy/2019/02/28/dual-use-lngshipping-a-gamechanger-for-carbonmanagement/?sh=3ff5387e1f47f
193 Storage at import and export terminals iscombined into one figure. Pipeline figures
include both pipeline and compressors. Importand export pipelines are combined into one
figure for shipping options.

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
75

We estimate that transporting hydrogen by ship costs €0.78-€1.31/kg/
10,000 km. This is an optimistic cost projection that assumes significant scale-up
and technology development that will not be available in the near future. Please
see Appendix C. for more details on our approach and unit costs. We estimate thatliquid hydrogen shipping is the most expensive option due to the large amount ofenergy required to liquefy the hydrogen. LOHC and ammonia shipping are similar
in cost, with LOHC being slightly less expensive though less mature. It is worth
noting however that for liquid hydrogen shipping the most energy intensive step
– liquefaction – takes place in the export country, and little energy is required
to gasify it in the import country. It is likely that the export country is exportinghydrogen because of an abundance of very cheap renewable electricity. If energy inthe export country is sufficiently cheaper than that in the import country, the case forliquid hydrogen shipping over ammonia or LOHC shipping may become stronger.

4.3. Comparison of Hydrogen Transport Methods
and Supply Routes
Figure 34 compares the cost of shipping versus pipeline over various distances.
All three shipping methods are compared with new and repurposed 48-inch and36-inch pipelines, as well as the average levelised European Hydrogen Backbone
cost presented in section 4.2.¹⁹⁴

1.40

FIGURE 34
Comparison of hydrogen transport
options over various distances

1.20
1.00
0.80
0.60

Liquid Hydrogen
LOHC

48-inch Pipeline, New

0.20

48-inch Pipeline, Repurposed
36-inch Pipeline, New

0.00

36-inch Pipeline, Repurposed

km

0

1,000

2,000

3,000

4,000

5,000

Cost (€/kg)

0.40

Ammonia

6,000

Source: Guidehouse analysis (see Appendix C for assumptions)

For all possible hydrogen transport routes within or near Europe that can beserved by pipeline, a pipeline is a more cost-effective option than any shipping
method, assuming sufficient volumes are being transported to justify a pipelineat least 36 inches in diameter because pipelines with higher throughputs are lessexpensive. Shipping should be reserved for long distance, intercontinental trade
separated by ocean. Shipping is also advantageous from the perspective of security
and flexibility of supply. Pipelines can be difficult to construct across politicallyunstable regions, and shipping routes can be modified to react to changes inmarket dynamics. When hydrogen is shipped, export and import locations should
be selected as close to the production and demand sites as possible because themarginal cost of shipping per km is lower than that of pipelines.
To illustrate a real-world comparison between pipeline and shipping, we
examined two promising import routes into Europe that could use pipeline orshipping: (1) North Africa to Northern Europe and (2) Saudi Arabia to Southeast
Europe. Figure 35 displays these routes. Note that this analysis is not intended toprovide an exhaustive list of potential export regions, nor does it make any claims
about which exporters are more likely or favourable. The two routes were chosen tocompare shipping costs to pipeline costs simply because the distances travelled byship and pipeline would be similar. The routes displayed are illustrative.
194 Average EHB cost is weighted by length andcapacity of different pipeline diameters..

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
76

FIGURE 35
Map of example routes to compare
shipping and pipelines as hydrogentransport methods
For imports from
(1) North Africa to Northern Europe and(2) Saudi Arabia to Southeast Europe)

200 kmRotterdam

ROUTE B
2,800 km

CologneMilan

2,700 km
ROUTE A

3,500 km
1,200 km
ROUTE C

Catania

ROUTE D250 kmCasablanca

2,300 km

Marrakesch
NEOM
Duba

300 km(1) Import from North Africa (Marrakech) to Northern Europe (Cologne):
North Africa has excellent wind and solar resources and large amounts ofsuitable land to build renewable energy generation on. This region has potential to
become an exporter of very cheap renewable energy and is in close proximity toSouthern Europe. Furthermore, Morocco is only narrowly separated from Spain by
the Mediterranean Sea, so a subsea pipeline can be constructed to bridge the gap.
There is also an existing sub-sea natural gas pipeline between Morocco and Spainthat could be repurposed for hydrogen in the future.
As an illustrative exercise, Marrakech was selected as a representative locationof hydrogen production and Cologne was selected as a representative locationof hydrogen demand. (Route A) A pipeline route from Marrakech to Cologne(2,700 km) was compared to (Route B) a shipping route involving a pipeline from
Marrakech to Casablanca (250 km), ship from Casablanca to Rotterdam (2,800 km),and pipeline from Rotterdam to Cologne (200 km). Figure 36 compares the costs ofthe various transport options.

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
77

1.20

FIGURE 36
Transport cost comparison for
North Africa to Northwest Europe

1.00
0.80

0.40

North Africa to Northwest Europe
Reconversion
Storage

0.20

Shipping
Conversion
Pipeline + Compressors

Liquid Hydrogen
Shipping

LOHC
Shipping

Ammonia
Shipping

48-inch,New

48-inch,Repurposed

0.00

Transport Cost (€/kg)

0.60

Pipeline is by far the most cost-effective of the three options, adding 0.130.25 €/kg hydrogen delivered for 48” pipelines compared to 0.65-1.03 €/kg
hydrogen for the shipping options. It is worth noting that no sub-sea hydrogenpipelines have been developed to date. Sub-sea natural gas pipelines are often
operated at higher pressures and use thicker steel because it is challenging tocompress the gas along the stretch of pipe that is underwater, and it is uncertain
whether hydrogen pipelines can be safely and effectively operated at pressureshigher than 80 bar. However, the Strait of Gibraltar is 13-43 km across, so elevatedpressures are likely unnecessary to ensure that the hydrogen is transported effectively
across the Mediterranean Sea. The pipeline diameter and admissible pressure tooperate the pipeline safely will determine the transport capacity.
(2) Import from Saudi Arabia (NEOM) to Southeast Europe (Milan):
Saudi Arabia, like North Africa, has excellent renewable generation potential, isclose to Europe, and transport can largely take place over land or sea, dependingon the selected route. The country is therefore a potential hydrogen exporterand a good candidate to compare transport options. NEOM was selected as therepresentative production site and Milan was selected as the representative demandsite. (C) A pipeline from NEOM to Milan (3,500 km) was compared to (D) a shipping
route including a pipeline from NEOM to Duba (300 km), ship from Duba to Sicily(2,300 km), and a pipeline from Sicily to Milan (1,200 km) Figure 37 compares thecost of the different transport options.
1.20

FIGURE 37
Transport cost comparison for
Saudi Arabia to Southeast Europe

1.00
0.80

0.40

Saudi Arabia to Southeast Europe
Reconversion
Storage

0.20

Shipping
Conversion
Pipeline + Compressors

Liquid Hydrogen
Shipping
ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
78

LOHC
Shipping

Ammonia
Shipping

48-inch,New

48-inch,Repurposed

0.00

Transport Cost (€/kg)

0.60

195 Brito and Sheshinski (1997). Pipelines andthe Exploitation of Gas Reserves in the
Middle East. http://large.stanford.edu/
publications/coal/references/baker/
studies/tme/docs/TrendsinMiddleEast_
PipelinesExplorationGasReserves.pdf
196 https://sari-energy.org/oldsite/PageFiles/
What_We_Do/activities/GEMTP/CEE_
NATURAL_GAS_VALUE_CHAIN.pdf

The shipping options are more competitive for this route because the distanceis greater, however pipeline is still significantly more cost-effective than any of theshipping options. Pipeline route C shown in Figure 35 is almost entirely land-based,
however it would be possible to build a shorter pipeline by routing part of it under
the Mediterranean Sea. As previously mentioned, sub-sea pipelines for hydrogen
do not currently exist and R&D is required to determine if they can be safely andeffectively operated at the elevated pressures required. Assuming that a hydrogenpipeline under the Mediterranean Sea is possible, experience with natural gas
pipelines suggests that constructing a new sub-sea pipeline would be approximately
60% to 100% more expensive than an onshore pipeline.¹⁹⁵, ¹⁹⁶ Most of the additional
expense associated with constructing sub-sea pipelines is related to the difficulties ofworking underwater, rather than materials. For this reason, it is likely that incremental
savings from repurposing sub-sea natural gas pipelines for hydrogen are less thanthose from repurposing pipelines on land.
Australia was examined as a third potential exporter of hydrogen due to its
renewable generation potential and vast landmass. A shipping route was modelled
including a 100 km pipeline to Melbourne, a shipping route from Melbourne to Sicily(16,000 km), and a pipeline from Sicily to Milan (1,200 km). Pipeline is obviously
an unrealistic transport method for this route, while shipping transport costs from
Australia can be compared to those from other potential exporters.
Figure 38 indicates that the cheapest mode of transport of hydrogen from
Australia to Southeast Europe is LOHC shipping with a levelized cost of €1.00/kg.
Assuming North African and Saudi hydrogen exports are available by pipeline,
Australian hydrogen production would need to be €0.35/kg and €0.26/kg cheaper
than North African and Saudi hydrogen production respectively for Australian
exports to Europe to be competitive. It is unlikely for Australia to have such asignificant hydrogen production cost advantage over two of the best locations on
Earth to produce low-cost renewable energy. Furthermore, hydrogen is not supply
constrained as discussed in Chapter 3. Hydrogen Supply. Therefore, intercontinental
imports from regions such as Australia and Chile are unlikely to be economical,
because they will have to compete with imports from nearby regions such as
North Africa, Saudi Arabia, and Ukraine which can be transported to the European
Union and UK at lower cost. Note that regions such as Australia may implement
infrastructure necessary to export earlier than Ukraine or North Africa.

2.00

FIGURE 38
Australia to Southeast Europe

1.60

0.80
Australia to Southeast Europe
Reconversion

0.40

Storage
Shipping
Conversion
Pipeline + Compressors

Liquid Hydrogen
Shipping

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
79

LOHC
Shipping

Ammonia
Shipping

0.00

Transport Cost (€/kg)

1.20

4.4. Comparison of Electricity andHydrogen Infrastructure
4.4.1. Transport cost comparison between
pipeline and power line
Conversion of electricity to hydrogen via electrolysis can occur near the site ofelectricity production or near the site of hydrogen demand. Sometimes it is asserted
that instead of a hydrogen backbone, Europe could develop a more decentralised
infrastructure, relying on a larger electricity network with electrolysers placed
strategically near clusters of hydrogen demand. Europe’s hydrogen demand
could still be met this way without transporting hydrogen over long distances. The
presupposition herein is that electricity transport infrastructure is more cost-effective
than hydrogen transport infrastructure and that a hydrogen delivery system basedon decentralised electrolysers is equally capable of meeting customers’ hydrogenneeds while maintaining adequate electricity supply.
To test the main drivers of long-distance power line transport costs, we examined
three common types of electricity transmission infrastructure:– 380 kV (2.8 GW) overhead HVAC lines,– 525 kV (2.0 GW) underground HVDC lines, and– 800 kV (8.0 GW) overhead HVDC lines.
It is worth noting that 800 kV (8 GW) overhead HVDC lines do not currently
exist in Europe and face significant regulatory hurdles, particularly in Northwest
Europe, where population densities are high. However, they are the most costeffective electricity transmission method at long distances and are successfully usedin other countries such as the U.S. and China, so are worth considering assuming
the regulatory and permitting hurdles can be overcome. The cost of electricity
transmission infrastructure was then compared to that of hydrogen pipeline
infrastructure over various distances, assuming no branching or off-takers.
Wires were compared to pipelines assuming hydrogen as the end-use for bothcases. If the energy is transported as hydrogen, electrolyser conversion losses occur
before it is transported. However, if it is transported as electricity, electrolyser losses
occur after transport, so the transmission infrastructure must be over-designed tocompensate. 5000 full load hours were assumed for hydrogen pipelines. Utilisationof electricity transmission lines is typically lower, around 30-50%, so a 50% loadfactor (4380 full load hours) was assumed for electricity infrastructure.¹⁹⁷
Figure 40 shows that pipelines with a diameter of at least 36 inches with transportcapacities of at least 3.6 GW, when operated at 5000 full load hours, are more costcompetitive than power lines at all distances analysed here. The most competitiveelectricity transmission option is 800 kV overhead HVDC, which does not currently
exist anywhere in Europe, as stated above. Compared to these overhead HVDC
power lines, new pipelines are more cost-effective for hydrogen demands of atleast 4.7 GW (36-inch diameter) up to more than 2,500 km and at any distance fordemands of 12.7 GW (48-inch).

197 Load factor assumptions are consistent with
Energy Transitions Commission, Making theHydrogen Economy Possible (April 2021).

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
80

30.00FIGURE 39
Comparison of electricity and hydrogen
infrastructure costs for different
distances assuming hydrogen as the end
use for transported energy

25.00

20.00

15.00
Overhead HVAC (2.8 GW)

10.00

Overhead HVDC (8.0 GW)

48-inch Pipeline, New

5.00

48-inch Pipeline, Repurposed
36-inch Pipeline, New

0.00

36-inch Pipeline, Repurposed

km

0

250

500

750

1,000

1,250

1,500

1,750

2,000

2,250

Cost (€/MWh)

Underground HVDC (2.0 GW)

2,500

Source: Guidehouse analysis (see Appendix C for assumptions)

198 Estimates taken from multiple sources: Agora:
No regret Hydrogen (2021); Energy Transitions
Commission (2021); R.K. Ahluwalia (2019);
DNV-GL (2019); Lazard (2020); Schmidt et al.
(2019).

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
81

Both methods of energy transport have their benefits and trade-offs, yet theresults show that for high-volume transport of energy when the desired end-productis hydrogen, pipelines – both newly built and repurposed ones and excluding
storage costs – are 2 to 4 times more cost-effective than power lines.
It is important to note that this illustrative analysis, which serves to assess
the cost drivers of pipeline and power line transport, makes several simplifying
assumptions:– First, the analysis assumes direct transportation from dedicated renewablegeneration to demand with no branching or off-takers, where the actual energy
system is a complex network.
– Furthermore, the above analysis does not incorporate the effects or costs ofstorage, a crucial component to the energy system, or other balancing costs– which can be especially important in the electricity system. Without storage,
most renewable projects, excluding offshore wind, are not be able to reach the4380 to 5000 full load hours assumed in this calculation. Production of electricity
from these projects varies dramatically, and periods of peak production produce
significantly greater volumes than periods of average production. As a result, if
electricity transmission infrastructure is built to deliver peak electricity production,
it will be over-designed leading to low utilisation. Herein hydrogen infrastructure
presents a promising solution. Electricity transmission infrastructure can be built todeliver the average electricity production, and the excess electricity during peaks
can be converted and transported as hydrogen. Storage is also important in viewof the fact that most energy customers require energy to be delivered at a relatively
constant rate, which requires variable renewable electricity to be ‘shaped’ tomeet demand. These storage costs, ranging between 5-20 €/MWh for hydrogenstorage and 66-220 €/MWh for electricity storage,¹⁹⁸ need to be considered inaddition to the point-to-point transport costs shown in Figure 40.
– When looking at offshore wind, where the 5000 full load hours are more
realistic, additional grid investments will need to be considered including costs
for the crossing of the dunes, offshore grid interconnections, and a premium forsea cables.
These factors point to areas of further work that will help improve the understandingof how electricity and hydrogen infrastructures can collaborate to create the mostvalue to consumers, and how market design and policy can enable this.

4.4.2. Energy storage, system integration,and societal acceptance
The need for storage in a future decarbonised energy system is evident. Yet,electricity is challenging to store. The most common electricity storage technology
today, batteries, are only capable of storing electricity on hourly timescales andare relatively expensive. This means that the utilisation of electricity infrastructure
connected to dedicated large-scale renewable generation such as an offshore windfarm is essentially limited to the capacity factor of that wind farm. Furthermore, apurely electric system with significant intermittent renewable generation faces
logistical challenges to match supply with demand on both an hourly and longerterm basis.
Gas on the other hand is easier to store. Operating pressures can be modulated
to provide a few hours of storage from the capacity of the pipeline network alone– this is referred to as linepack.¹⁹⁹ Gas is stored in large geologic structures
underground such as depleted gas fields, aquifers, and salt caverns at enormousvolumes and for timescales as short as hours or as long as months. This storage
enables constant delivery of energy to customers, balances seasonal differences indemand, limits pipeline throughput allowing for more efficient pipeline infrastructure
investment, and provides insurance in periods of low energy production.
It has been demonstrated that hydrogen can be stored in salt caverns, and thelatest research suggests that it can be stored in depleted gas fields and aquifers
as well, though more R&D efforts are ongoing.²⁰⁰ Figure 41 below provides acomparison between the levelised cost of storing energy as hydrogen in salt caverns
and as electricity using a range of storage technologies.
The overview in Figure 41 show that the levelised cost of hydrogen storage in salt
caverns, expressed in €/MWh, is significantly lower than the levelised cost of electricity
storage. The highest estimate for hydrogen storage in salt caverns, 20 €/MWh,is still more than 3 times cheaper than the lowest estimate for a utility-scale battery
system built specifically for supply-demand firming of renewables, reported at
66 €/MWh in Lazard’s 2020 LCOS analysis. The difference is even greater whenlooking at averages. The average levelised cost of storage for hydrogen reported isaround 9 €/MWh, compared to 115 €/MWh for electricity storage.
Moreover, the levelised cost of hydrogen storage adds a relatively small component
to the overall cost of hydrogen delivered. At a levelised cost of 5-20 €/MWh,salt cavern storage would add between 8 and 33% to the cost of hydrogen delivery– assuming a production plus transport cost of 60 €/MWh (2 €/kg). This is arelatively small price to pay to firm up variable production profiles to meet the needsof industrial or power sector customers. In contrast, the levelised cost of battery
storage is, at 66 €/MWh in the most optimistic case, equal to or perhaps more thanthe price of the commodity itself.
As with the pipeline network itself, an economic advantage of deploying hydrogenstorage is that it would make use of existing assets and capabilities developed fornatural gas storage in the past. As Europe decarbonises, natural gas flows will
decrease, freeing up unused pipelines, storages, and other infrastructure for thedelivery of hydrogen. This infrastructure can be converted for hydrogen use at lower
cost than if it had to be built from scratch. Furthermore, the considerable overlap inuse cases for natural gas and hydrogen means that much of the existing infrastructure
and capabilities are already well-situated to meet hydrogen demand.
199 Linepack depends on the size, structure etc. of
the pipeline network.
200 R. Tarkowski (2019). Underground hydrogenstorage: Characteristics and prospects

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
82

FIGURE 40

Levelised cost of hydrogen storage in salt caverns, €/MWh H₂
125

Comparison between the levelised costof storing energy as hydrogen and aselectricity

100
75

25
20

7

5

6

5
0

Agora / Afry North Europe(2021)

Agora / Afry South Europe(2021)

Energy Transitions
Commission(2021)

2.06 full cycles/a, to balancewind production
to demand.
Requirement
for seasonal
accumulation.

8.45 full cycles/a,
to balance PV
production to
demand.
Requirement for
diurnal cycling.

Large volumestorage, medium
term (weeksmonths).

R.K. Ahluwalia
et al. (2019)

DNV-GL(2019)

500 tH₂
underground salt;
30% cushion gas;
50 tH₂/day basis.

100 MW
production,
9 cycles/a, 250 bar.

€/MWh H₂

50

Levelised cost of electricity storage using
various technologies, €/MWh electricity
125
100

102

116

50
70

66

25
0

Sources: Agora: No regret Hydrogen (2021); Energy
Transitions Commission: Making the Hydrogen
Economy Possible (2021); R.K. Ahluwalia (2019); DNVGL: Hydrogen in the Electricity Value Chain (2019);
Lazard LCOS Analysis (2020); Schmidt et al. (2019).

Lazard (2020),
wholesale – low

Lazard (2020),
wholesale – highUtility-scale 4-hourbattery (50 MW /200 MWh) pairedwith PV (100 MW)
to balance supply &demand.

Utility-scale 4-hourbattery (50 MW /200 MWh) pairedwith PV (100 MW)
to balance supply &demand.

Lazard (2020),
illustrative longduration case – low
10h illustrative
utility-scale energy
storage system (100
MW / 1000 MWh),low case.

Schmidt et al.
(2019),
compressed
air – 2050 low

Schmidt et al.
(2019),
Lithium-ion – 2050
low

Forecast for 2050
based onsteep cost
reductions

Forecast for 2050
based
on steep cost
reductions€/MWh electricity

75

220

The consideration between gas and electricity transport is not only an economic
question but also one of societal acceptance. Although any type of infrastructuredevelopment can face public acceptance concerns, the energy transport alternatives
compared in Figure 40 are of different scales. Whereas a 48-inch pipeline
can have a throughput capacity of up to 16.9 GW and a 36-inch pipeline up to
4.7 GW, power lines considered in the analysis above – deemed realisablein Europe – have throughput capacities of 2 GW (per underground HVDC)
to 3 GW (per overhead HVAC). This means that, to transport volumes of energy
corresponding to a 48-inch pipeline—as is done today with natural gas—using
power lines would require the equivalent of 5-6 overhead HVAC or 9 HVDC
overhead transmission lines. Such a build-out, whether economically attractive or

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
83

not, will almost certainly run into a range of social acceptance issues, including land
use and landscape pollution. In these cases, underground HVDC power lines mayneed to be considered, which are significantly more expensive.
Framing the discussion around energy transport infrastructure as a zerosum game between hydrogen and electricity is suboptimal because it ignorescomplementary strengths and synergies that make both important for theaffordability and security of Europe’s future energy supply. Instead, the optimal
infrastructure investment decisions depend on a range of factors including the
local cost and availability of electricity and hydrogen supply, end uses, requiredenergy profiles, interconnection costs, regional underground storage availability,
terrain, and public acceptance.
When it comes to the topic of Europe’s broader energy system, an integrated
electricity and hydrogen grid will be more resilient and efficient than an electricity
grid alone – for delivering electricity and hydrogen as end-uses alike. As identified
in the European Commission’s Energy System Integration Strategy, electricity andhydrogen infrastructure will work in harmony to create an integrated energy system,
wherein consumers and investors are able to choose the option that best matches
their need, based on prices that reflect the true cost and efficiency.

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
84

Appendix A.
Hydrogen Demand – Methodology
A.1. Industry
The industry chapter is based on bottom-up analysis on sector specific futurehydrogen demand in fuels, HVC, ammonia and iron & steel. The hydrogen demandfor industrial process heat is based on top-down analysis.
TABLE 5
Overview of expected industrial hydrogen
demand per country (in TWh/year)

Total
2040

Fuels &
HVC

Steel

3.30

1.59

7.51

1.20

6.74

11.78

4.67

24.39

1.50

9.39

11.96

6.16

29.01

9.58

4.29

3.04

17.86

5.06

27.05

9.10

8.73

49.94

6.33

37.71

7.90

11.37

63.31

Bulgaria

0.00

2.39

0.00

0.69

3.07

0.75

6.74

0.00

1.95

9.44

5.03

9.39

0.00

2.52

16.94

Croatia

0.00

1.64

0.00

0.25

1.89

0.35

4.63

0.00

0.71

5.69

2.33

6.45

0.00

0.93

9.71

Cyprus

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

Czech Republic

0.00

2.14

0.22

1.07

3.44

0.35

6.05

2.22

3.15

11.78

2.37

8.43

3.79

4.16

18.75
10.18

Total
2050

Industrial
heat

2.39

0.95

Industrial
heat

Steel

Ammonia

Fuels &
HVC

0.23

Belgium

Total
2030

Austria

Industrial
heat

Ammonia

2050

Steel

2040
Fuels &
HVC

2030
Ammonia

Country

Denmark

0.00

2.20

0.00

0.38

2.58

0.00

6.22

0.00

1.13

7.35

0.00

8.67

0.00

1.51

Estonia

0.00

0.00

0.00

0.03

0.03

0.00

0.00

0.00

0.11

0.11

0.00

0.00

0.00

0.16

0.16

Finland

0.00

3.06

2.03

0.14

5.22

0.00

8.64

4.05

0.52

13.20

0.00

12.04

4.11

0.76

16.91

87.09

7.34

France

1.10

17.71

6.83

5.28

30.92

5.87

49.99

15.68

15.55

69.69

18.72

20.53

116.28Germany

0.93

25.63

17.81

16.60

60.98

11.11

72.38

49.59

49.47 182.55

18.52 100.90

59.96

65.73

245.11

Greece

0.00

8.82

0.00

0.18

9.00

0.13

24.91

0.00

0.51

25.54

0.85

34.73

0.00

0.66

36.24

Hungary

0.00

2.02

0.15

0.76

2.93

0.58

5.70

1.53

2.17

9.98

3.85

7.95

2.61

2.83

17.23

Ireland

0.00

0.87

0.00

0.49

1.36

0.00

2.45

0.00

1.44

3.90

0.00

3.42

0.00

1.91

5.33

Italy

0.31

20.26

4.01

5.76

30.35

1.64

57.21

14.62

16.75

90.22

2.04

79.76

18.17

21.97

121.94

Latvia

0.00

0.00

0.00

0.04

0.04

0.00

0.00

0.00

0.12

0.12

0.00

0.00

0.00

0.15

0.15
15.81

Lithuania

0.00

2.32

0.00

0.21

2.53

0.89

6.56

0.00

0.58

8.03

5.91

9.15

0.00

0.74

Luxembourg

0.00

0.00

0.00

0.26

0.26

0.00

0.00

0.00

0.75

0.75

0.00

0.00

0.00

0.96

0.96

Malta

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00
102.41

Netherlands

1.90

16.15

3.21

3.77

25.03

10.13

45.61

3.41

10.93

70.08

12.66

63.58

11.85

14.33

Poland

0.00

6.99

2.14

2.82

11.95

2.24

19.73

5.03

8.20

35.19

14.91

27.50

7.90

10.76

61.07

Portugal

0.00

5.26

0.00

0.85

6.11

0.00

14.86

0.00

2.46

17.31

0.00

20.71

0.00

3.22

23.93

Romania

0.00

2.91

3.28

1.67

7.87

1.79

8.22

4.98

4.65

19.64

11.95

11.46

5.05

5.96

34.42

Slovakia

0.00

1.52

0.42

0.35

2.29

0.47

4.28

4.17

0.97

9.89

3.14

5.97

7.11

1.23

17.45

Slovenia

0.00

0.00

0.00

0.34

0.34

0.00

0.00

0.00

0.99

0.99

0.00

0.00

0.00

1.30

1.30

Spain

0.25

18.67

3.39

5.34

27.65

3.02

52.72

8.40

15.60

79.74

5.03

73.50

8.53

20.52

107.58

Sweden

0.00

5.10

2.70

0.06

7.86

0.00

14.41

6.07

0.17

20.64

0.00

20.08

6.16

0.22

26.47

UK

1.42

17.79

1.37

4.24

24.82

7.55

50.24

2.87

12.42

73.07

9.44

70.03

5.05

16.36

100.88Total

7.07 175.43

55.17

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
85

56.20 293.87

53.13 495.34 143.50 164.68 856.65 113.19 690.53 178.86 216.97 1,199.56

TABLE 6
Sources and assumptions for heavy road transport

Data category

Sources and assumptions

Capacities andproduction per plant– Capacities based on EUROFER data²⁰¹– Utilization factor of 80% based on historic levels of past ten years– Increase in capacity over time homogenously per plant, 106% by 2030, 113% by 2040 and 114% by 2050 (wrt current
2019 levels) based on Material Economics²⁰²

Decarbonisation
pathways– Increase of secondary steel production to 50/50 share secondary/primary steel share, based on EUROFER estimates– Full switch to DRI-EAF steelmaking by 2050, speed of adoption and intermediate pathways (hydrogen injection, natural
gas instead of hydrogen in DRI and/or CCUS) are all based company announcements, company websites, GH expertiseand interviews with steel companies– Hydrogen demand per technology stated in the table below verified by steelmakers

Hydrogen demand
per decarbonisation
technology

Data category

Technology

Hydrogen demand (MWh per ton of CS)

BF/BOF/CCU

4.50

H₂/DRI/EAF

1.88

BF/BOF/CCU/ H₂ injection

5.05

BF H₂ injection

1.10

Sources and assumptions

Capacities andproduction per plant– Capacities based on a combination of FCH Observatory²⁰³ and press releases for individual installations– Production capacity assumed constant over time

Decarbonisation
pathways– Green hydrogen from electrolysis of water, blue hydrogen from SMR + CCS using fossil methane, and SMR using
biomethane– Countries categorized according to early or late adoption and likeliness of adoption of blue hydrogen– Split of production by each pathway determined by GH expertise– Full decarbonisation by 2050

Hydrogen demand
per decarbonisation
technology– Mole balance of Haber-Bosch process.
– 3 mol H₂/mol NH₃ = 5.9 MWh H₂/t NH₃ (LHV)

TABLE 7
Sources and assumptions for HVCs

Data category

Sources and assumptions

Capacities andproduction per plant– Ethylene production capacities based on international survey for steam crackers. New large Ineos Antwerp cracker has
been added manually²⁰⁴. Using table 2-2 from Ren²⁰⁵ total HVC capacity is calculated from the ethylene capacity andfeedstock shares, all per plant.
– Utilization factor of 100% based on GH expertise– Stable capacity over time homogenously per plant: increase in demand is covered by increase in mechanical recycling,based on Material Economics²⁰⁶ new processes scenario

Decarbonisation
pathways– Three decarbonisation pathways:– Electric cracking– Steam cracking with decarbonized energy carrier– Methanol-to-Olefins (MtO)– and three for decarbonisation of feedstock (assumed to be Naphtha for cracking or methanol for MtO):– Bio-based– Synthetic– Chemical recycling– Homogenous approach since no installation specific information is available with an end-state of three way split for bothprocess and feedstock decarbonisation pathways. The future decarbonisation pathways are uncertain and among others
dependent on resource availability (biomass, waste, hydrogen, renewable energy, biogenic or DAC CO₂). In reality,
different plants will follow different pathways using different feedstocks and resources.

Hydrogen demand
per decarbonisation
technology– See Table 1 in HVC section for values, mostly based on Material Economics²⁰⁶– The feedstocks are assumed to be produced at fuel production locations, just as the fossil naphtha today is also
produced at refineries. Hydrogen demand is thus included as fuel production in estimates.

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
86

TABLE 8
Sources and assumptions forfuel production

Data category

Sources and assumptions

Capacities andproduction per plant– Refining capacities are based CIEP data²⁰⁷. The future capacities is based on plant capacity relative to total refining
capacity in EU+UK, thus the current market share remains the same per refinery.

Hydrogen demand
per decarbonisation
technology– Hydrogen demand for refining fossil fuels is taken from Agora/Afry²⁰⁸– Hydrogen demand for producing the feedstocks (methanol/naphtha) for HVCs is taken from HVC section– Hydrogen demand for upgrading bio kerosene is taken from Ricardo²⁰⁹ at 0.15 MWh per MWh of biojet fuel (averageof 3 technologies), bio kerosene fuel demand comes from transport section.
– Hydrogen demand for synthetic kerosene is assumed to be 430 kgs per ton of synthetic kerosene, the stoichiometricvalue. This could be more due to upgrading in reality, while also byproducts would be produced such as synthetic
naphtha. Exactly calculating this would require an extensive separate study, where all transport sectors are included.
Synthetic kerosene demand is calculated in the transport section.
– Total hydrogen demand is split up per refinery based on current capacity/market share of the refinery.

TABLE 9Sources and assumptions forindustrial process heat

Data category
Natural gas demand(baseline)

Hydrogen demand pertemperature level

Sources and assumptions– FFE Extremos, 2021²¹⁰: Natural gas demand 2020 per NUTS 2 region for low-, medium-, and high-temperature industrial
process heat (excluding spatial heating)– Constant gas demand assumed– Low-temperature heat (<100°C): Full electrification assumed based on GH insights and FFE Extremos, 2021
– Medium-temperature heat (100-500°C): 5% of current natural gas demand is replaced by hydrogen in 2030, 20% by
2040 and 30% by 2050
– High temperature heat (>500°C): 15% of current natural gas demand is replaced by hydrogen in 2030, 40% by 2040
and 50% by 2050
– For the conversion of natural gas demand in TWh to hydrogen demand in TWh for industrial heat, a study from DNV GL(2018)²¹¹ is used which assessed hydrogen use in industrial heating processes in the Netherlands. The energy demandwhen using hydrogen instead of natural gas is slightly lower at 88% of energy natural gas uses for low temperature heatand 85% for medium-and high temperature heat.

201 https://www.eurofer.eu/about-steel/learn-about-steel/where-is-steel-made-in-europe/
202 https://materialeconomics.com/publications/industrial-transformation-2050
203 https://www.fchobservatory.eu/observatory/technology-and-market/hydrogen-demand
204 http://www.mrcplast.com/news-news_open-382294.html
205 https://dspace.library.uu.nl/bitstream/handle/1874/21674/NWS-E-2006-3.pdf?sequence=1
206 https://materialeconomics.com/publications/industrial-transformation-2050
207 https://www.clingendaelenergy.com/inc/upload/files/CIEP_paper_2017-02_web.pdf
208 https://www.agora-energiewende.de/en/press/news-archive/no-regret-hydrogen-infrastructure-foreurope/
209 https://cdn.ricardo.com/ee/media/assets/hydrogen-demand-for-upgrading-biofuels-final-report_v2(002).pdf
210 http://opendata.ffe.de/dataset/final-energy-consumption-of-the-industry-sector-extremos-solideuscenario-europe-nuts-0/
211 https://www.dnv.com/oilgas/download/report-replace-natural-gas-with-hydrogen-for-industrialheating-processes.html
212 An analytical analysis is performed for aviation and heavy road transport determining the hydrogen
demand in each sector. Although hydrogen can play a role, the decarbonisation pathways andhydrogen demand values for rail transport, passenger cars and light duty vehicles, and shipping
are not performed due to their significantly lower hydrogen demand potentials and in the case ofshipping, the uncertainty in the decarbonisation pathway.

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
87

A.2. Transport
The transport analysis is a bottom-up analysis that determines the total EU+UK
energy demand pathway for heavy road transport and aviation.²¹² The total energy
consumption for heavy road vehicles and aviation is based on the forecasted annual
distance travelled, the energy consumption per technology, and the technology
share. The transport pathways are disaggregated to country level energy demands
based on historical data. The tables below give detailed information regarding thesources, assumptions, and values used in the analysis.
TABLE 10Sources and assumptions for heavy road transport

Data category

Sources and assumptions

Annual distancetravelled– IEA MoMo model²¹³: Yearly annual distance travelled for Medium Freight, Heavy Freight, and Buses for 2020-2050 in
5-year increments

Energy consumption– IEA MoMo model²¹³ for diesel trucks– 2% energy consumption improvements every 5 years²¹³– Hydrogen fuel cell vehicles are assumed to have a 40% reduction in energy consumption relative to diesel trucks– Battery electric vehicles are assumed to use 65% less energy compared to diesel trucks– Natural gas trucks are assumed to use 10% more energy compared to a diesel truck

Technology share– Updated from the Gas for Climate 2020 Pathways study²¹⁴– Based on company announcements and literature– Technology share penetrations are modelled using S-curve technology adoption curves

Total historical energy
demand– Historical total road transport energy demand values from the European Environmental Agency²¹⁵ are used to verify thecalculations

Country level
disaggregation– Based on IEA MoMo model²¹⁶ annual distance travelled, given per region– The region data is disaggregated using Freight distance per country data in the European Commission Statistical
Pocketbook²¹⁷

TABLE 11
Annual distance travelled per transport typefor 2020-2050 in billion km/year for EU+UK

Transport typeTransport subtype

2020

2025

2030

2035

2040

2045

2050

Freight vehicles

Medium freight

96

82

78

77

74

69

66

Freight vehicles

Heavy freight

225

222

219

216

214

211

208

Buses

Buses

22

25

28

32

35

38

42

Buses

Coaches

11

11

11

12

12

13

13

213 IEA (2021). The IEA Mobility Model. https://www.iea.org/areas-of-work/programmes-andpartnerships/the-iea-mobility-model
214 Gas for Climate (2020). Gas decarbonisation pathways study. https://gasforclimate2050.eu/sdm_
downloads/2020-gas-decarbonisation-pathways-study/
215 European Environment Agency (2021). Final energy consumption in Europe by mode of transport.
https://www.eea.europa.eu/data-and-maps/indicators/transport-final-energy-consumption-bymode/assessment-10
216 IEA (2021). The IEA Mobility Model. https://www.iea.org/areas-of-work/programmes-andpartnerships/the-iea-mobility-model
217 European Commission (2017). Statistical pocketbook. https://ec.europa.eu/transport/facts-fundings/
statistics/pocketbook-2017_en

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
88

TABLE 12
Technology share per road transport
type for 2020-2050

Transport type

Freight vehicles

Buses

Technology

2020

2025

2030

2035

2040

2045

2050

Electricity

0%

1%

6%

11%

21%

30%

35%

Hydrogen

0%

0%

5%

13%

30%

47%

55%

(bio)-LNG/CNG

2%

12%

30%

40%

32%

18%

10%

Diesel

97%

87%

60%

35%

18%

6%

0%

Electricity

1%

3%

12%

38%

64%

73%

75%

Hydrogen

0%

1%

4%

13%

21%

24%

25%

(bio)-LNG/CNG

3%

3%

3%

2%

0%

0%

0%

Diesel

96%

93%

82%

48%

14%

3%

0%

TABLE 13
Sources and assumptions for aviation

Data category

Sources and assumptions

Annual distancetravelled– IEA MoMo model²¹²: Yearly annual distance travelled for Passenger Aviation and Freight Aviation for 2020-2050 in
5-year increments

Energy consumption– 34 passenger-km/L for average aircraft²¹⁸– 1.5% energy consumption improvement per year²¹⁹– Hydrogen fuel cell aircrafts are assumed to have an 8% reduction in energy consumption relative to aircrafts poweredby jet fuel (Based on regional aircraft in FCH’s Hydrogen powered aviation report)²²⁰– Battery electric vehicles are assumed to use the same energy consumption as aircrafts powered by jet fuel due to therelatively low energy density but higher efficiency of batteries (Based on efficiency and energy density of batteries andjet fuel²²¹)

Technology share– Updated from the Gas for Climate 2020 Pathways study²²²– Based on company announcements and literature– Technology share penetrations are modelled using S-curve technology adoption curves

Country level
disaggregation– Freight air travel is disaggregated freight tonnage per country data from the World Bank²²³– Passenger air travel is disaggregated base on air passengers carried per country data from the World Bank²²⁴

Total historical energy
demand– Historical total road transport energy demand values from the European Environmental Agency²²⁵ are used to verify thecalculations

218 ICCT (2018). Transatlantic Airline Fuel Efficiency Ranking, 2017. https://theicct.org/sites/default/files/
publications/Transatlantic_Fuel_Efficiency_Ranking_20180912.pdf
219 IATA (2021). Fuel Efficiency. https://www.iata.org/en/programs/ops-infra/fuel/fuel-efficiency/
220 FCH (2020). Hydrogen-powered aviation. https://www.fch.europa.eu/sites/default/files/FCH%20
Docs/20200507_Hydrogen%20Powered%20Aviation%20report_FINAL%20web%20%28ID%20
8706035%29.pdf
221 Hepperle, M. (2018). Electric Flight – Potential and Limitations. https://nag.aero/wp-content/
uploads/2018/05/MP-AVT-209-09-Electric-Flight-Potential-and-Limitations.pdf
222 Gas for Climate (2020). Gas decarbonisation pathways study. https://gasforclimate2050.eu/sdm_
downloads/2020-gas-decarbonisation-pathways-study/
223 World Bank (2020). Air transport, freight. https://data.worldbank.org/indicator/IS.AIR.GOOD.
MT.K1?view=chart
224 World Bank (2020). Air transport, passengers carried. https://data.worldbank.org/indicator/IS.AIR.
PSGR?view=chart
225 European Environment Agency (2021). Final energy consumption in Europe by mode of transport.
https://www.eea.europa.eu/data-and-maps/indicators/transport-final-energy-consumption-bymode/assessment-10

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
89

TABLE 14
Technology share per aviation
technology for 2020-2050

Technology

2020

2025

2030

2035

2040

2045

2050

Electricity

0%

0%

0%

0%

1%

5%

10%

Hydrogen

0%

0%

0%

0%

1%

5%

10%

Synthetic Kerosene

0%

2%

7%

20%

33%

38%

40%

Bio Jet fuel

0%

2%

7%

20%

33%

38%

40%

Jet Fuel

100%

96%

85%

59%

32%

14%

0%

TABLE 15
Direct Hydrogen demand per country for thetransport sector for 2020-2050. (TWh/year)

Country

2020

2025

2030

2035

2040

2045

2050

Austria

0.0

0.0

0.3

0.9

2.1

3.8

5.6

Belgium

0.0

0.0

0.3

1.0

2.1

3.3

4.2

Bulgaria

0.0

0.0

0.3

0.9

1.8

2.6

2.9

Croatia

0.0

0.0

0.1

0.3

0.7

1.0

1.3

Czech Republic

0.0

0.0

0.5

1.6

3.4

4.9

5.7

Cyprus

0.0

0.0

0.0

0.1

0.1

0.2

0.2

Denmark

0.0

0.0

0.3

1.0

2.3

3.7

4.7

Estonia

0.0

0.0

0.1

0.2

0.4

0.6

0.7

Finland

0.0

0.0

0.4

1.3

2.9

4.5

5.8

France

0.0

0.1

3.3

9.8

21.3

33.3

41.5

Germany

0.0

0.1

3.0

9.0

19.8

32.0

41.5

Greece

0.0

0.0

0.3

1.0

2.0

3.0

3.8

Hungary

0.0

0.0

0.4

1.3

2.7

4.5

6.1

Ireland

0.0

0.0

0.2

0.8

2.3

6.0

11.2

Italy

0.0

0.1

2.2

6.7

13.8

20.1

23.4

Latvia

0.0

0.0

0.1

0.3

0.7

1.2

1.5

Lithuania

0.0

0.0

0.2

0.6

1.3

1.9

2.2

Luxembourg

0.0

0.0

0.1

0.2

0.5

1.1

1.9

Malta

0.0

0.0

0.1

0.3

0.6

0.9

1.2

Netherlands

0.0

0.0

0.7

2.1

4.7

8.0

10.8

Poland

0.0

0.0

2.5

7.2

15.5

23.0

26.6

Portugal

0.0

0.0

0.3

0.9

2.0

3.2

4.1

Romania

0.0

0.0

0.4

1.1

2.3

3.4

4.2

Sweden

0.0

0.0

0.7

1.9

4.2

6.5

7.9

Slovenia

0.0

0.0

0.1

0.4

0.9

1.4

1.6

Slovakia

0.0

0.0

0.4

1.1

2.4

3.5

4.1

Spain

0.0

0.1

1.9

5.5

11.9

18.7

23.7

United Kingdom

0.0

0.1

2.4

7.2

16.3

27.3

36.7

EU+UK

0.0

0.7

21.4

64.8

141.1

223.6

285.1

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
90

A.3. PowerThe analysis on hydrogen demand in the power system is based on ENTSO-E’s
TYNDP 2020 Scenario Report²²⁶ and the Gas for Climate 2020 ‘Gas Decarbonisation
pathways study’ ²²⁷. The total EU electricity generation values are based on the Gas
for Climate 2020 ‘Gas Decarbonisation pathways study’ ²²⁷, leading to 3674, 4166,
and 4633 TWh of electricity generation in 2030, 2040, and 2050, respectively.
The breakdown of generation per generation type and per country in the EU arebased directly on ENTSO-E’s TYNDP 2020 Scenario Report for 2030 and 2040²²⁶.
The generation values are then scaled to result in the Gas for Climate total electricity
generation values listed above. This leads to a total gas generation in the EU+UK of
496 TWh in 2030 and 436 TWh in 2040. To forecast the necessary gas generation
values for 2050, the TYNDP2020 values are extrapolated. Nuclear power is
extrapolated to 2050 using the 2030 and 2040 TYNDP forecasts, hydropower isassumed to remain constant from 2040 to 2050, total EU+UK generation is assumed
to increase by 0.2% per year with country level generation following the trend from2030 to 2040. Total solar and wind generation are expected to comprise of 15%
and 50%, respectively of total generation. Country level solar and wind generationin 2050 are expected to grow considering the growth in 2030 to 2040 and the
reduction in fossil and nuclear generation plants. Electricity from batteries in 2050 is
extrapolated from 2030 and 2040 values. Gas generation in 2050 is extrapolated
from 2030 and 2040 values considering the change in total per country generationand in solar, wind, hydro, nuclear, coal, lignite, and oil generation. The generation
values are then scaled to the Gas for Climate 2020 ‘Gas Decarbonisation pathways
study’ ²²⁷ total 2050 electricity generation of 4633 TWh, leading to a total gas
generation of 440 TWh in 2050. Based on the Gas for Climate 2020 study ²²⁷, thehydrogen demand for 2030, 2040, and 2050 is calculated assuming that 1%, 35%,
and 70% of the gas generation is hydrogen respectively and that hydrogen-to-power
has an efficiency of 50% ²²⁸. This results in 12 TWh of hydrogen in 2030, 301 TWh
in 2040, and 625 TWh in 2050. All sources, assumptions, and calculation methods
are shown in the table below.

226 ENTSO-E (2020). TYNDP 2020 Scenario Report. https://2020.entsos-tyndp-scenarios.eu/
227 Gas for Climate (2020). Gas decarbonisation pathways study. https://gasforclimate2050.eu/sdm_
downloads/2020-gas-decarbonisation-pathways-study/
228 In this study, gas to power is generalised to include power generated both in gas fired turbines and inhydrogen fuel cells. An efficiency of 50% is assumed for both applications.

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
91

TABLE 16
Hydrogen demand in power – sources,
assumptions, methods

Data category

Sources, assumptions, and methods

Total generation– 2030: 3674 TWh²²⁹– 2040: 4166 TWh²²⁹– 2050: 4633 TWh²²⁹

Per country generation– 2030 & 2040: ENTSO-E’s TYNDP²³⁰– 2050: Extrapolated from 2030 and 2040 country level generation values and based on the 2050 total generation value

Nuclear generation– 2030 & 2040: ENTSO-E’s TYNDP²³⁰– 2050:– Countries with increasing amounts of nuclear generated electricity from 2030 to 2040 are assumed to maintain
2040 generation values in 2050
– Countries with decreasing shares of nuclear power from 2030 to 2040 are linearly extrapolated to 2050

Hydro power– 2030 & 2040: ENTSO-E’s TYNDP²³⁰– 2050: Assumed that hydro power remains constant at 2040 values

Coal, lignite, oil– 2030 & 2040: ENTSO-E’s TYNDP²³⁰– 2050: Linearly extrapolated from 2030 and 2040 values

Solar generation– 2030 & 2040: ENTSO-E’s TYNDP²³⁰ per country values– 2050: total solar generation is assumed to be 15% of total generation– Country level solar generation values are extrapolated given the country level generation values and the change innuclear, hydro power, coal, lignite, and oil generation

Wind power– 2030 & 2040: ENTSO-E’s TYNDP²³⁰ per country values– 2050: total wind generation is assumed to be 50% of total generation– Country level wind generation values are extrapolated given the country level generation values and the change innuclear, hydro power, coal, lignite, and oil generation

Other renewables– 2030 & 2040: ENTSO-E’s TYNDP²³⁰ per country values– 2050: Assumed to remain constant at 2040 values

Battery– 2030 & 2040: ENTSO-E’s TYNDP²³⁰ per country values– 2050: Linearly extrapolated from 2030 & 2040 values

Gas generation– 2030 & 2040: ENTSO-E’s TYNDP²³⁰ per country values– 2050: Extrapolated from 2030 & 2040 values considering the change in total per country generation and in solar, wind,hydro, nuclear, coal, lignite, and oil generation

Hydrogen share of gas
generation– Hydrogen share of gas generation is assumed to be 1% in 2030, 35% in 2040, and 70% in 2050 based on GfC 2020
Pathways study²³¹

Gas-to-power
efficiency– 50% efficiency²²⁷, ²³²

229 Gas for Climate (2020). Gas decarbonisation pathways study. https://gasforclimate2050.eu/sdm_
downloads/2020-gas-decarbonisation-pathways-study/
230 ENTSO-E (2020). TYNDP 2020 Scenario Report. https://2020.entsos-tyndp-scenarios.eu/
231 Gas for Climate (2020). Gas decarbonisation pathways study. https://gasforclimate2050.eu/sdm_
downloads/2020-gas-decarbonisation-pathways-study/
232 In this study, gas to power is generalised to include power generated both in gas fired turbines and inhydrogen fuel cells. An efficiency of 50% is assumed for both applications. In the short term, hydrogencan be blended with natural gas to power gas turbines.

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
92

TABLE 17
Power sector hydrogen demand per country
for 2030, 2040, and 2050 (TWh/year)

Country

2020

2040

2050

Austria049Belgium1

13

27

Bulgaria

0

2

4

Croatia001Czech Republic

0

0

1

Cyprus001

Denmark

0

3

7

Estonia0

1

1Finland0

1

4

France0924Germany

3

78

183

Greece01

4Hungary0

1

2

Ireland

0

7

14

Italy

2

50

92

Latvia000Lithuania

023Luxembourg

0

0

0

Malta

0

0

1

Netherlands

1

13

20

Poland1

37

66

Portugal0

3

5

Romania0

2

8

Sweden000Slovenia

02

4

Slovakia

0

1

2

Spain

1

15

34

United Kingdom

2

56

106

Total

12

301

625

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
93

A.4. Buildings

TABLE 18
Floor space estimates per country (2020)

Country

Residential floor area

Service floor area

Useful energy demand

million m²

million m²

kWh/m²Austria117459

141.52

Belgium

144537

167.55

Bulgaria

71

297

53.92

Croatia

35

175

47.66

Czech Republic

105

405

153.41

Cyprus

7

48

48.30

Denmark

121

421

136.50Estonia48

98148.20Finland101

303

203.67

France873

3493

114.65Germany

1662

5227

164.02

Greece125561

107.85

Hungary104416

142.22

Ireland57

222

125.79

Italy

399

3047

101.37

Latvia18

81

192.26

Lithuania

35

118

139.09Luxembourg

731200.39

Malta

4

19

26.21

Netherlands

303

955

141.76

Poland404

1340

115.20Portugal

100

617

70.82

Romania

78

539

112.57

Slovakia

50

188105.85

Slovenia

24

93140.52

Spain

362

2235

58.82

Sweden167

581

137.54

United Kingdom

728

2907

127.34

Source: Hotmaps

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
94

TABLE 19
Estimate of fuel share mix per country (2020)

Country

District heat

Biomass

Natural gas

Other renewables

Electricity

Oil(e.g. solar thermal)
Austria

23.3%

19.5%

26.2%

4.4%

7.8%

18.8%

Belgium

1.0%

5.3%

51.1%

9.0%

5.2%

28.4%

Bulgaria

19.6%

32.7%

6.2%

5.6%

18.3%

17.6%

Croatia

12.9%

22.3%

37.6%

4.2%

10.9%

12.2%

Cyprus

0.0%

1.3%

0.0%

27.4%

13.5%

57.7%

Czech Republic

20.6%

14.4%

46.3%

1.5%

6.8%

10.4%

Denmark

49.9%

15.8%

18.0%

3.8%

4.6%

7.8%

Estonia

43.9%

28.7%

7.6%

6.1%

11.2%

2.5%

Finland

43.1%

15.4%

0.6%

8.3%

21.8%

10.8%

France

4.7%

14.6%

42.9%

8.2%

12.2%

17.4%

Germany

9.6%

8.2%

46.4%

12.0%

3.0%

20.8%

Greece

0.7%

10.7%

8.4%

8.4%

7.1%

64.7%

Hungary

12.7%

11.5%

64.6%

0.3%

5.2%

5.6%

Ireland

0.0%

1.4%

31.9%

12.9%

7.7%

46.0%

Italy

2.2%

14.6%

57.3%

5.7%

9.6%

10.7%

Latvia

31.9%

42.1%

14.3%

4.3%

2.5%

4.8%

Lithuania

35.2%

45.4%

10.2%

2.5%

2.5%

4.3%

Luxembourg

8.7%

2.7%

49.9%

9.1%

2.2%

27.4%

Malta

0.0%

1.0%

0.0%

6.9%

49.6%

42.4%

Netherlands

4.3%

2.4%

86.9%

1.8%

2.6%

2.0%

Poland

27.9%

10.4%

20.7%

5.5%

3.7%

31.8%

Portugal

1.2%

21.3%

22.4%

7.6%

8.5%

38.9%

Romania

19.2%

46.0%

30.6%

0.8%

1.7%

1.8%

Slovakia

38.5%

1.4%

51.9%

2.4%

1.7%

3.9%

Slovenia

10.1%

40.6%

11.0%

9.6%

7.8%

21.0%

Spain

0.4%

14.5%

31.7%

10.2%

7.6%

35.5%

Sweden

49.3%

12.1%

1.9%

16.0%

14.8%

5.9%

United Kindom

1.2%

1.1%

80.2%

2.2%

6.5%

8.8%

Source: Hotmaps

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
95

TABLE 20
Final energy savings per country, relative
to untouchedCountry

Energy related renovations

Energy related renovations

Energy related renovations“Light”“Medium”“Deep”

Austria

10.9%

42.9%

64.2%

Belgium

12.7%

40.3%

66.9%

Bulgaria

15.2%

42.7%

61.0%

Croatia

15.2%

41.9%

64.5%

Cyprus

12.5%

49.6%

64.1%

Czech_Republic

14.4%

41.0%

66.1%

Denmark

12.0%

42.8%

65.0%

Estonia

13.7%

41.7%

65.1%

Finland

10.3%

45.8%

62.7%

France

12.0%

42.9%

66.1%

Germany

12.6%

42.8%

64.9%

Greece

11.3%

45.6%

69.9%

Hungary

11.9%

41.6%

64.4%

Ireland

12.3%

43.2%

64.7%

Italy

13.3%

41.6%

68.2%

Latvia

11.4%

41.5%

63.7%

Lithuania

11.6%

37.9%

61.2%

Luxembourg

13.1%

46.2%

66.5%

Malta

12.3%

44.8%

68.9%

Netherlands

12.2%

39.1%

67.1%

Poland

11.5%

37.5%

69.6%

Portugal

13.5%

42.8%

65.7%

Romania

14.4%

42.6%

62.3%

Slovakia

13.7%

41.6%

62.9%

Slovenia

14.9%

40.7%

63.7%

Spain

17.1%

42.6%

67.8%

Sweden

10.1%

45.3%

62.8%

United_Kingdom

13.6%

44.4%

66.2%

Source: Guidehouse

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
96

Appendix B.
Hydrogen Supply – Methodology
B.1. Green Hydrogen
Technical potential
The technical renewable energy potential considers the theoretical energy potential
based on wind speeds and solar irradiation data (capacity factors), bearing in mind
technical restrictions. The main technical restriction is the physical suitability of sites.
For example, wind turbines and ground-mount PV parks cannot be installed in urban
areas. Table 21 summarises the sources, assumptions, and constraints consideredwhen estimating the technical potential.
TABLE 21
Technical potential – sources,
assumptions, and constraints

Technology

Sources, assumptions, and constraints
The starting point is the ENSPRESO “170 W/m², 100%” land scenario, which assumes that:Solar PV– Urban, industry, forests, transitional woodland-shrub, new energy crops, natural land, infrastructure, wetlands, water
bodies, urban green leisure, and other natural land areas are excluded for ground-mount– All land areas except for urban and industrial areas are excluded for rooftop
In this study the performance ratio is increased to 100% (actual electricity produced as a share of the PV panel’s rated
capacity), rather than the 75% assumed in the original ENSPRESO database.
Technical potential for onshore wind assumes the same values as the ENSPRESO “EU-wide low-restrictions”
scenarioENSPRESO “EU-wide low-restrictions” scenario, which assumes that:

Wind: onshore– Urban, industry, forests, transitional woodland-shrub, infrastructure, wetlands, water bodies, urban green leisure, andother natural land areas are excluded– Distance from settlements is 120 m for small turbines and 400 m for big turbines in all countries
Technical potential for offshore wind assumes the same values as the ENSPRESO “EU-wide low restrictions”
scenarioENSPRESO “EU-wide low restrictions” scenario, which assumes that:

Wind: offshore– There is no constraint with regards to distances to shore & inland waters– Distance to ship lanes, pipelines, gas wells, and submarine cables has to be greater than 2 nm
– Only areas with sea depths less than 1000 m and shipping densities less than 5000 ships per year are considered

Realistic potential
Even when there might be enough space or resource available for renewable energy
production from a technical perspective, it is often not desirable to utilise all thistechnical potential. The realistic renewable energy potential takes into account these
constraints by considering planning issues, competition for land-use, environmental
regulations, and public acceptance. Table 22 below summarises the sources,
assumptions, and constraints when estimating the realistic potential.

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
97

TABLE 22
Realistic potential – sources, assumptions,and constraints

Technology

Sources, assumptions, and constraints
For each country, 0.1-2.0% of non-artificial areas are available for ground-mount solar PV depending on population densityof the country in consideration, according to the following criteria:

Solar PV

– 0-50 persons/km²: 2.0%
– 50-100 persons/km²: 1.5%
– 100-150 persons/km²: 0.75%– 150-200 persons/km²: 0.50%– 200-250 persons/km²: 0.25%– > 250 persons/km²: 0.10%

Wind: onshore– ENSPRESO “EU-wide high restrictions” scenario – a hypothetical scenario in which the exclusion of surfaces for windconverges in all countries to a high level– Capacity factors > 25%– Distance from settlements: 1200 m for small turbines, 2000 m for big turbines

Wind: offshore– Wind Europe – “Our energy, our future” scenario in line with the European Commission’s 300 GW of offshore windtarget by 2050
– Includes floating technology

Renewable energy potential – installation rates
In this step the deployment of technologies at a certain point in time is taken into
account. The realisable renewable energy potential considers limitations related
to lead times and maximum deployment growth rates, building up to 80% of therealistic potential over time. Whereas the realistic renewable energy potential is timeindependent, the realisable potential increases over time.
To determine the share of the realistic potential which is realisable by 2030, 2040,
and 2050 – we look at shares of renewable sources in gross electricity consumption
per country, as reported by the European Commission for the year 2019.²³³ Countries
with a higher share of renewables today are assigned a faster realisable deployment
rate, although this rate converges to 80% of the realistic potential across all European
countries by 2050. This approach is shown in Table 23.

TABLE 23
Realisable deployment rates as a functionof present renewables penetration

Share of renewables in gross

2030

2040

2050

< 33%

25%

53%

80%

33% < x < 67%

35%

58%

80%

> 67%

45%

63%

80%

electricity consumption (2019)

233 Eurostat (2020). Share of energy from RES in gross electricity consumption in 2019. https://ec.europa.
eu/eurostat/web/energy/data/shares.

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
98

Final electricity demand, power-to-hydrogen-to-power, and net potential
available for dedicated green hydrogen production
Given the many decarbonisation benefits of combining rapid deployment of
renewables with widespread electrification of end-use technologies, we assume final
electricity demand – net of firm generation – receives priority access to renewableenergy supply. Hence, a thorough assessment of final electricity demand is essential
to understand the net realisable renewable energy potential which in fact remains
available for green hydrogen production.
We make use of final electricity demand figures presented in Chapter 1 of thisstudy and use extrapolated production figures from TYNDP’s Global Ambition
Scenario to estimate country-specific quantities of non-hydrogen forms ofdispatchable electricity production in 2030, 2040, and 2050.
Green hydrogen conversion considerations
Conversion losses associated with hydrogen production from water electrolysis mustalso be considered. We assume that electrolysis conversion efficiencies improve
gradually over time, starting at 71% in 2030 and reaching 76% and 80% by 2040
and 2050, respectively.
Country-level figures
TABLE 24
Realistic renewable energy potential per country(GW)

CountryPV

PV: rooftop

Wind

Wind

onshoreoffshore

Austria

31

20

17

0

Belgium

2

27

0

6

Bulgaria

164

18

3

0

Croatia

51

10

3

0

Czechia

46

25

6

0

Cyprus

17

2

0

0

Denmark

31

14

13

35

Estonia

29

3

17

7

Finland

32

14

80

17

France

122

153

164

58

Germany

60

191

22

36

Greece

198

24

89

10

Hungary

82

24

10

0

Ireland

46

11

71

22

Italy

77

136

48

10

Latvia

52

5

38

3

Lithuania

103

7

50

4

Luxembourg

0

0.857

0.5

0

Malta

0

1

0

10

Netherlands

3

39

4

60

Poland

183

91

90

28

Portugal

42

23

3

9

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
99

CountryPV

PV: rooftop

Wind

Wind

onshoreoffshore

Romania

396

48

17

0

Sweden

64

24

100

20

Slovenia

8

5

0

0

Slovakia

27

13

5

0

Spain

776

99

244

13

United Kingdom

15

148

154

80

TABLE 25
Realisable renewable energy potential per country(GW)

Country

2030

2040

2050

PV:
groundPV:rooftopWind
Wind
onshore offshorePV:groundPV:rooftopWind
Wind
onshore offshorePV:groundPV:rooftopWind
Wind
onshore offshore

Austria

14

9

8

0

19

13

11

0

25

16

14

0

Belgium

10

7

4

3

10

14

4

4

10

22

4

5

Bulgaria

41

5

1

0

86

10

2

0

131

15

3

0

Croatia

18

4

1

0

30

6

2

0

41

8

3

0

Czechia

11

6

1

0

24

13

3

0

37

20

4

0

Cyprus

4

1

0

0

9

1

0

0

14

2

0

0

Denmark

11

6

10

8

18

8

10

21

25

11

10

28

Estonia

7

1

4

1

15

2

9

4

23

3

14

6

Finland

11

6

28

3

18

8

46

10

26

11

64

13

France

44

38

41

9

64

80

86

35

97

122

132

46

Germany

98

69

20

15

98

110

20

21

98

153

20

28

Greece

50

7

22

2

104

13

47

6

159

19

71

8

Hungary

20

6

2

0

43

13

5

0

65

19

8

0

Ireland

16

8

25

4

27

8

41

13

37

9

57

18

Italy

51

48

17

2

51

78

28

6

61

109

38

8

Latvia

18

2

13

0

30

3

22

2

42

4

31

2

Lithuania

26

2

12

1

54

4

26

2

82

6

40

3

Luxembourg

0

0.608

0.4

0

0

0.857

0.5

0

0

0.857

0.5

0

Malta

0

0

0

2

0

0

0

6

0

1

0

8

Netherlands

27

10

12

10

27

20

12

36

27

31

12

48

Poland

46

23

23

5

96

48

47

17

147

73

72

22

Portugal

15

9

1

1

24

13

2

5

33

18

2

7

Romania

139

17

6

0

228

28

10

0

317

38

13

0

Sweden

29

12

17

3

40

15

30

12

51

19

40

16

Slovenia

2

1

0

0

4

3

0

0

7

4

0

0

Slovakia

7

3

1

0

14

7

3

0

21

11

4

0

Spain

272

47

85

2

446

57

140

8

621

79

195

10

United Kingdom

5

52

54

30

9

85

88

48

12

118

123

64

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
100

TABLE 26
Renewable energy potential per country(TWh/year)

Country

2030

2040

2050

Austria

50

70

89

Belgium

22

36

50

Bulgaria

73

153

234

Croatia

36

60

83

Czechia

25

53

81

Cyprus102132

Denmark

68

150

204

Estonia

25

59

87

Finland

110

204

281

France

258

576

850

Germany

192

302

415

Greece

171

369

559

Hungary

44

93

142

Ireland

137

260

358

Italy

168

286

396

Latvia

59

102

141

Lithuania

66

143

217

Luxembourg

2

2

2

Malta

5

17

23

Netherlands

58

189

257

Poland

161

364

541

Portugal

39

74

101

Romania

245

402

559

Sweden

108

201

265

Slovenia

5

10

15

Slovakia

16

34

51

Spain

740

1,232

1,713

United Kingdom

384

628

860

2030

2040

2050

Austria

105

128

154

Belgium

107

115

121

Bulgaria

36

38

40

Croatia

21

24

25

Czechia

80

90

99

Cyprus789Denmark

54

70

90

Estonia

11

13

16

Finland

111

123

135

France

489

549

607

Germany

668

708

742

Greece73

79

83

Hungary

54

60

66

TABLE 27
Final electricity demand (TWh/year)

Country

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
101

Country

2030

2040

2050

Ireland

48

53

59

Italy

376

423

471

Latvia11

15

20

Lithuania

14

18

23

Luxembourg

6.5

6.8

6.8

Malta

3

4

6

Netherlands

134

143

151

Poland

199

239

283

Portugal

47

50

52

Romania

72

81

90

Sweden

165

187

210

Slovenia

15

18

19

Slovakia

34

36

39

Spain

311

376

350

United Kingdom

415

484

557

2030

2040

2050

Austria

25

18

15

Belgium

15

12

10

Bulgaria

22

14

11

Croatia

5

4

3

Czechia

28

19

16

Cyprus2

10Denmark

7

5

4

Estonia2

1

1Finland

40

19

15

France

245

109

88

Germany

126

66

54

Greece15

7

6Hungary15

6

5

Ireland

8

4

3

Italy

93

62

50

Latvia2

11

Lithuania

221

Luxembourg

0.439

0.436

0.436

Malta

0

0

0

Netherlands

32

12

10

Poland68

41

34

Portugal

11

8

6

Romania

27

16

13

Sweden71

34

27

Slovenia

12

15

8

Slovakia

17

11

9

Spain

64

28

23

United Kingdom

88

68

55

TABLE 28
Hydro, nuclear, fossil, and other non-PV andwind electricity generation (TWh/year)

Country

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
102

TABLE 29
Overview of renewable energy targets
announced in National Energy and Climate
Plans (GW) in 2030

CountryPV

Wind: onshore

Wind: offshore

Austria

9.7

6.5

0

Belgium

10.27

4.9

4

Bulgaria

3.2

1

0

Croatia

0.8

1.4

0

0.2

0

CyprusCzechia4

10Denmark

7.8

6.3

10.3

Estonia

0.4

0.5

0.7

Finland

1

5.5

0.07

France

44

37.7

7.4

Germany

98

69

20

Greece

7.7

7.1

0

Hungary

6.4

0.33

0

Ireland

2.5

8.2

5

Italy

51.2

18.4

0.9

1.1

0

LatviaLithuania

0.13

0.9

0.7

Luxembourg

1

0.3

0

0

0

Malta
Netherlands

27

9

11.5

Poland7.3

15

7Portugal

9

9

0.2

Romania

5.1

5.3

0.3

Slovakia

1.2

0.5

0

Slovenia

1.65

0.15

0

Spain

39.2

47.3

3

Sweden2

12

0.2

United Kingdom

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
103

40

Levelised cost of green hydrogen
TABLE 30
Electrolyser techno-economic assumptions
used to calculate the levelised cost of greenhydrogen production (based on Alkalinetechnology at large scale >100 MW)

2030

2040

2050

Efficiency (LHV)

71% ²³⁴76%

80%

CAPEX (€/kWe)

270.00201.75133.50High

425.00312.50200.00Medium270.00201.75133.50Low

115.00

91.00

67.00

Electrolyser stack replacement cost (after half of lifetime)

35.0% of capex

Electrolyser opex (of yearly CAPEX)

5%Electrolyser lifetime (years)

30

Electrolyser availability

95%

Coincidence factor for hybrid (solar + wind) plants

15%

Medium case is used in calculations. Sources: BNEF, Hydrogen Project Valuation(H2Val) Model; Agora & AFRY, No-regret hydrogen; Florence School of Regulation,
Clean Hydrogen Costs in 2030 and 2050.
TABLE 31
Renewable energy capex assumptions
used to calculate the levelised cost ofgreen hydrogen production

€/kW

2030

2040

2050

PV

330

290

250

Wind onshore

800

743

686

Hybrid

1130

1033

936

Wind offshore

1179

995

811

2030

2040

2050

PV

8

7

6

Wind onshore

36

34.5

33

Hybrid

44

41.5

39

Wind offshore

95

87

79

TABLE 32
Renewable energy opex assumptions used
to calculate the levelised cost of greenhydrogen production€/kW/year

234 High temperature electrolysers/Solid Oxide Electrolysers (SOEL) already reach efficiency levels ofabove 85% (LHV) and higher, but need steam as input. This steam could come from industrial sourceor e.g. from the Fischer-Tropsch process for e-fuel production. This technology is not considered in thecentralised scenario this study assumes, but could play a substantial role in e.g. e-fuel production.

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
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TABLE 33
Renewable energy capacity factors pertechnology and per country

CountryPV

Wind: onshore

Austria

14.9%

29.7%

Belgium

13.8%

30.6%

49.8%

Bulgaria

17.8%

26.9%

36.1%

Czechia

14.1%

27.6%

Cyprus23.8%

Germany

13.8%

29.4%

50.8%

Denmark

13.6%

36.3%

52.5%

Estonia

12.7%

28.4%

48.7%

Greece

20.9%

32.5%

42.3%

Spain

19.4%

28.1%

46.4%

Finland

12.4%

33.0%

48.9%

France

16.4%

29.5%

48.2%

Croatia

17.5%

30.5%

28.8%

Hungary

16.7%

26.5%

Ireland

12.3%

44.7%

55.8%

Italy

18.7%

28.0%

34.0%

Lithuania

13.1%

29.7%

46.7%

Luxembourg

13.6%

30.6%

Latvia

13.0%

29.4%

Malta

23.4%

Netherlands

13.7%

32.2%

49.8%

Poland

13.9%

28.3%

48.1%

Portugal

15.8%

28.1%

38.6%

Romania

16.9%

26.4%

38.7%

Sweden

12.5%

34.1%

49.7%

Slovenia

16.1%

26.5%

Slovakia

15.2%

27.0%

United Kingdom

12.8%

37.3%

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
105

Wind: offshore

25.4%

48.8%
30.6%

55.6%

B.2. Blue Hydrogen
The greenfield large scale ATR estimate is based on estimates from H-Vision andH21 projects, for a 5 GW unit, while brownfield estimates are based on IEA’s Futureof Hydrogen (2019) and Gas for Climate (2019).

TABLE 34
Blue hydrogen techno-economic
assumptions

Parameter

Greenfield ATR

Brownfield SMR(5 GW)CAPEX (€/MWH₂)

800,000-1,000,000

375,000-1,175,000²³⁵

OPEX (of Annual CAPEX)

3%

3%

Efficiency (LHV)

69%

69%

Capture rate

94%

60-66%

Emissions w/o CCS (t CO₂/ MWh H₂)

0.29

0.29

CO₂ transport and storage costs(per tonne of CO₂)

20-50

20-50

Load hours per year

8,000

8,000

Cost of Capital

6%

6%

Lifetime

20

20

235 Low estimate assumes fully depreciated SMR unit, high estimate assumes that 50% of investment
costs have been depreciated

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
106

Appendix C.
Hydrogen Transport Infrastructure –Methodology
C.1. Hydrogen Transport by Pipeline
Hydraulic simulations performed by participating TSOs in the previous iterationof the EHB indicated that smaller compressor stations spaced 100 km apart andlarger compressor stations spaced 600 km apart result in similar costs per 100 km
transported. These simulations also found that compression capacity of 190-330 MWe
per 1000 km is sufficient to operate the network between 40 and 80 bar or between
30 and 67 bar in a 48-inch pipeline.
Compressors are assumed to be electrically powered piston compressors.
Compressors are modelled as a single large compressor at the beginning of thestretch of pipe to bring the hydrogen to the pipeline’s operating pressure andseveral evenly-spaced smaller compressor stations to maintain pressure and flowrate along the length of the pipeline. Compressors towards the end of the pipeline
are operated at lower capacity or bypassed to allow the pressure to decrease to
30 bar, as this is a suitable pressure delivery pressure for most industrial customers,
as determined through stakeholder interviews.
Much of the natural gas transmission infrastructure in Europe consists of pipelines
with diameters smaller than 48-inch. To better model this, subsequent hydraulicsimulations were performed this year assuming a 48-inch pipeline with a maximum
operating pressure of 80 bar, a 36-inch pipeline with a maximum operating pressureof 50 bar, and a 20-inch pipeline with a maximum operating pressure of 50 bar. For
each pipeline diameter, necessary compression power was determined to operate
the pipeline at 100% capacity, 75% capacity, and 25% capacity. Compressor
stations were placed at intervals of 100-200 km. Table 36 includes the outputs of thehydraulic simulations which were used to estimate pipeline costs.

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
107

TABLE 35
Network design parameters fromhydraulic simulations ²²⁶

Parameter

100% Capacity

75% Capacity

25% Capacity

48-inch Pipeline Throughput[GW at LHV (TWh/year)]

16.9 (148)12.7 (111)

4.2 (37)

36-inch Pipeline Throughput[GW at LHV (TWh/year)]

4.7 (42)3.6 (32)

1.2 (10)20-inch Pipeline Throughput[GW at LHV (TWh/year)]

1.2 (10)0.9 (8)0.3 (3)

New 48-inch Pipeline CAPEX (€/m)

2,750

New 36-inch Pipeline CAPEX (€/m)

2,200

New 20-inch Pipeline CAPEX (€/m)

1,510

Repurposed 48-inch Pipeline CAPEX (€/m)

500

Repurposed 36-inch Pipeline CAPEX (€/m)

400

Repurposed 20-inch Pipeline CAPEX (€/m)

275

Distance between compressors (km)100-200

Input pressure (bar)30-40Output pressure (bar)30Compressor CAPEX (€/MWe)

3,400,000

48-inch Pipeline Compression Capacity(MWe/1000 km)

434

183

6

36-inch Pipeline Compression Capacity(MWe/1000 km)

93

40

2

20-inch Pipeline Compression Capacity(MWe/1000 km)

26

6

0.6

Electricity cost (€/MWh)50

Assumed load factor for compressor
electricity consumption (hours/year)

5000

Compressor type

Electric reciprocating compressor

The cost of a pipeline can be broken down into three main categories: CAPEX,
variable OPEX, and fixed OPEX. CAPEX is comprised of the cost to build a newhydrogen pipeline, build compressor stations, and repurpose existing natural gas
pipelines for hydrogen. Variable OPEX consists of the electricity costs to power thecompressors. Fixed OPEX is the operating and maintenance costs of the pipeline
itself and the compressor stations. The length of the pipeline impacts all three
categories of costs. Throughput on the other hand impacts only the variable OPEX.
It is possible that lower throughputs would also translate to lower operating andmaintenance costs, however this has not been studied. Figure 41 breaks down thecost components of a hydrogen pipeline.

236 Figures provided by Transmission System Operators

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
108

FIGURE 41
Summary of pipeline cost components

CAPEX

Pipeline CAPEX (€/MW/km)
Compressor CAPEX (€/MW/km)

Variable OPEX

Fixed OPEX

Compressor power (€/MWh)

Pipeline O&M (% of CAPEX)
Compressor O&M (% of CAPEX)

C.2. Hydrogen Transport by ShipThree ways of shipping were analysed: liquid hydrogen, ammonia, and liquid organichydrogen carriers (LOHC), specifically toluene.
To model the shipping process, we broke it into 7 steps:
1. Pipeline from production to export terminal: Unless the renewable generationand electrolyser are located directly at the port, a pipeline will be required totransport the hydrogen from its point of production to the port.
2. Liquefaction/conversion: A facility is required to liquefy the hydrogen, convert
it to ammonia (Haber-Bosch process), or convert toluene to cyclohexane.
3. Storage at export terminal: Storage is needed to store the liquefied/convertedhydrogen before ships arrive at the port, and so that ships can be loaded quickly.
4. Shipping: The liquefied/converted hydrogen is transported from the export
terminal to the import terminal via tanker ship.
5. Storage at import terminal: The liquefied/converted hydrogen is stored at theimport terminal to allow for a consistent pipeline flow. It is stored in its liquid/
converted state because its energy density is much lower in gaseous state, and it
is more difficult to store.
6. Gasification/reconversion: A facility is required to gasify the liquid hydrogen,crack the ammonia, or dehydrogenate the cyclohexane to toluene and hydrogen.
7. Pipeline from export terminal to final destination: The gaseous hydrogen isdelivered by pipeline from the export terminal to its intended destination.
Pipeline sections as part of shipping routes are modelled the same way as allpipeline routes, assuming a new, 48-inch pipeline.
Overproduction is necessary to overcome losses in shipping and delivera specific flow to the site of demand. Overproduction is calculated as the largerof boil-off or fuel requirement for ammonia and liquid hydrogen shipping. LOHC
dehydrogenation is not 100% efficient, so for LOHC shipping, overproduction is
calculated to compensate for hydrogen that is lost in this step. All infrastructure
upstream of the shipping portion (including shipping) is sized to account for the
overproduction necessary to compensate for shipping losses.

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
109

All ships have 160,000 m³ capacity. The number of ships required is determinedby calculating the duration of one round trip and what quantity of hydrogen would
have to be shipped to meet the specified demand over the course of one round trip.
This quantity is then divided by the hydrogen capacity of one ship and rounded up.
Because it is more economically efficient than truck or rail, all ground transportof hydrogen is assumed to be by pipeline in gaseous form, and all conversion andreconversion occurs at the export and import terminals respectively.
Storage is sized to match the amount of hydrogen delivered between ships plus
a buffer of 50% to account for variation in the shipping schedule. Storage tanks storehydrogen in the same form as what is shipped, because storing hydrogen in gaseous
form would have significantly lower energy density and require compression.
TABLE 36
Key shipping parameters²³⁷, ²³⁸

Parameter

Liquid Hydrogen

Ammonia

LOHC

Pipeline diameter (in)48

Pipeline pressure (bar)80

Pipeline condition (new vs. repurposed)

New

Conversion CAPEX (€/kW H₂)

1350

808

84

Conversion variable OPEX (kWh/kWh H₂)

0.3

0.14

0.051

Conversion fixed OPEX (% of CAPEX)
Toluene CAPEX (€/kg tol.)²³⁹

2.5%
N/A

N/A

0.30

Ship volume (m³)

160,000

Ship speed (knots)

20

Ship CAPEX (€/ship)

179,944,000

134,924,800

99,600,000

Ship variable OPEX (€/ship/year)

9,900,000

9,047,000

15,604,000

Ship fixed OPEX (% of CAPEX)

4%Fuel requirement (MWh/kg/1000 km)

4.0

Boil-off Rate (%/km)

0.001%

0.00003%

Storage capacity (% of amount of hydrogendelivered between ship loads)
Storage CAPEX (€/MWh H₂)

0%
150%

750

226

239

Storage fixed OPEX (% of CAPEX)

2%Reconversion efficiency

100%

100%

90%

Reconversion CAPEX (€/kW H₂)

273

235

237

Reconversion variable OPEX (kWh/kWh H₂)

0.003

0.14

0.39

Reconversion fixed OPEX
Toluene degradation (%/cycle)²³⁹

2.5%
N/A

N/A

Electricity cost (€/MWh)

237 Cost estimates pertaining to conversion, reconversion, and storage came from: DNV GL – Study on
the Import of Liquid Renewable Energy: Technology Cost Assessment
238 Cost estimates pertaining to shipping came from: https://www.sciencedirect.com/science/article/pii/
S2352484720312312
239 https://www.sciencedirect.com/science/article/pii/S0360319920332134

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
110

0.1%
50

As with pipelines, shipping costs are divided into CAPEX, variable OPEX, andfixed OPEX. Figure 42 breaks down the cost components associated with shipping.

FIGURE 42
Shipping cost breakdown

Pipeline + compressors (€/MW/km)
Conversion or liquefaction infrastructure (€/MW)

CAPEX

Ships (€/MWh/km)
Storage tanks (€/MWh)
Reconversion or gasification infrastructure (€/MW)

Compressor power (€/MWh)

Variable OPEX

Conversion or liquefaction power (€/MWh)
Ship fuel and labour (€/ship)
Reconversion or gasification power (€/MWh)

Pipeline + compressor O&M (% of CAPEX)
Conversion or liquefaction infrastructure O&M (% of CAPEX)

Fixed OPEX

Ship O&M (% of CAPEX)
Storage tank O&M (% of CAPEX)
Reconversion or gasification infrastructure O&M (% of CAPEX)

C.3. Comparison of Hydrogen Transport Methods
and Supply Routes
The routes and corresponding distances shown in Figure 35 are illustrative andestimations. No analysis was performed to determine the optimal route from an
economic, geographical, and/or geopolitical perspective.

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
111

C.4. Comparison of Electricity andHydrogen Infrastructure
To model electricity infrastructure, a straight-line network with no branching or offtakers was assumed, as in the pipeline modelling. The cost of electricity infrastructureis broken down into Wires CAPEX, Converter CAPEX, operating and maintenance,and losses. To model the cost of losses, the total annual losses were multipliedby the assumed electricity cost. Figure 43 breaks down the cost components ofelectricity infrastructure.
Table 37 includes the assumptions used to estimate the cost of electricity
infrastructure.
FIGURE 43
Electricity infrastructure cosst breakdown

CAPEX

Wires CAPEX (€/GW/km)
Converter CAPEX (€/GW)

Variable OPEX

Wires Losses (€/km/GW)
Converter Losses (€/km/GW)

Fixed OPEX

Wires O&M (% of CAPEX)
Converter O&M (% of CAPEX)TABLE 37
Assumptions for electricity infrastructure

Parameter

Overhead HVAC

Overhead HVDC

Underground HVDC

Voltage (kV)

380

800

525

Power Rating (MW/MVA)

2800

8000

2000

Losses (% of energy transported/100 km)

1.1%

0.15%

0.5%

CAPEX (k€/km/GW)

190

255

1585

Fixed OPEX (% of CAPEX)

0.2%

Electricity cost (€/MWh)50

Number of Converters

0

2

2

Converter station CAPEX (k€/MW)

N/A

124

Converter station fixed OPEX (% of CAPEX)

N/A

2%

Converter Station losses (% of MWh converted)

N/A

1%

Electricity cost (€/MWh)50

Electrolyser efficiency

70%

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN112

To model hydrogen as an end-use, the electricity infrastructure cost was divided
by the electrolyser efficiency to account for the additional capacity required
to overcompensate for the electrolyser losses at the end of the line. Hydrogen
infrastructure was not modified because the electrolyser losses occur before thepipeline.
To model electricity as an end-use, electricity infrastructure cost is not modified
but hydrogen infrastructure costs are divided by the square of the electrolyser
efficiency to account for the electrolyser losses at the beginning of the pipeline andthe fuel cell losses at the end of the pipeline.

ANALYSING FUTURE DEMAND, SUPPLY,AND TRANSPORT OF HYDROGEN
113