Five hydrogen supply
corridors for Europe in 2030
EUROPEAN HYDROGEN BACKBONE
MAY 2022© 2022 European Hydrogen Backbone,
all rights reserved

TABLE OF CONTENTS

1. Executive Summary
2. Five emerging supply corridors
Corridor A: North Africa & Southern Europe
Corridor B: Southwest Europe & North Africa
Corridor C: North Sea
Corridor D: Nordic and Baltic regions
Corridor E: East and South-East Europe

3. Detailed methodology

2

EXECUTIVE SUMMARY© 2022 European Hydrogen Backbone,
all rights reserved

Who we are& EHB Mission

3

Who we are2021 Member States
New member

EHB Mission– Accelerate decarbonisationof the European energy
system– Define the critical role ofhydrogen infrastructure– Support developmentof a competitive and liquid
European hydrogen market– Foster cross-bordercollaboration between
Europe and its neighbors

CMYK
10 0 / 75 / 2 0 / 10

PA N TO N E
2 81 C

CMYK
6 0 / 0 / 10 0 / 0

PA N TO N E
369 C

CMYK
12 / 0 / 10 / 5 0

PA N TO N E
4 31 CEXECUTIVE SUMMARY© 2022 European Hydrogen Backbone,
all rights reserved

Europe’s accelerated 2030 climate targets
define an aggressive role for hydrogen
Europe has defined a bolder and more ambitioushydrogen target of 20 MT by 2030 in response to the
RePowerEU plan to phase out Russian fossil fuel imports
well before 2030

42030 Hydrogen Targets
MT of hydrogen(TWh in brackets)

20(665 TWh)This includes a 10 MT target of domestic EU hydrogen
supply, as well as a 10 MT target of hydrogen imports
from outside the EU.¹
These targets are strengthened by accelerated
national climate ambitions as well as the accelerated
development of the European hydrogen market.
Note: This study’s underlying analysis was largely
completed prior to the publication of the detailed
RePowerEU plan and its 2030 hydrogen targets. As
such, this study’s supply and demand estimates were
not intended to align with the 20 MT target by 2030.

10(333 TWh)20

10(333 TWh)

Domestic supply target

1

The RePowerEU target of 10 MT of imports includes 6 MT of renewable hydrogen and 4 MTof imported ammonia / derivatives.

Imports targets

Total 2030 Target

EXECUTIVE SUMMARY© 2022 European Hydrogen Backbone,
all rights reserved

The EHB initiative has identified sufficient hydrogen
supply to exceed the 2030 domestic targets
EHB identified 12 MT of domestic supply,
exceeding the RePowerEU domestic target
by 20% and supporting European energy
independence and security of supply.

2030 Target

We expect this demand estimate to increase
and accelerate further in response to the
RePowerEU plan.
These supply and demand estimates represent
tangible and achievable projections basedon national targets, market developments andannounced projects, primarily prior to therelease of the RePowerEU plan.

2030 Hydrogen Supply ¹, ², ³, ⁴2030 Hydrogen Demand⁵

MT of hydrogen(TWh in brackets)

20(665 TWh)EHB also identified 5.4 MT of supply from
non-EU neighboring countries, for a total of
17.4 MT of supply.
EHB also identified 14.7 MT of demand basedon a bottom-up assessment of demand by sector
and country.

5

5.4(180 TWh)
ImporttargetGreen imports(non-EHB)

1012(400 TWh)
Blue
Green
grid-based

Domestic
target102030
Hydrogen Target

1.1

Accelerated demand
due to RePowerEU

2.5
2.1
0.8

17.4 MT

3.2

Power& Buildings

2.2

Transport

3.6

14.7 MT(580 TWh)(490 TWh)Green
dedicatedIndustry

7.7

Domestic EU supply

Non-EU Supply+20%

higher than RePowerEU

1 EHB did not analyse ship imports of hydrogen or derivatives like ammonia and methanol. To meet the 20 MT target, an additional 2.6 MT of hydrogen or derivative imports would be needed.
2 The 5.4 MT of non-EU supply includes 2.5 MT (~80 TWh) of green hydrogen imports from non-EHB countries (Morocco, Algeria, Tunisia and Ukraine), along with 2.1 MT of blue hydrogen and 0.8 MT of grid-based hydrogen from EHB, non-EU countries(the UK and Norway). Blue hydrogen potential, and its economic viability, is subject to the evolution of gas markets, regulations and the uncertainty of natural gas prices.
3 Estimates of national green hydrogen supply for European countries are based on projections of renewable energy scaling up above and beyond supply levels needed to meet electricity demand.
4 Other imports may include pipeline or ship imports from other regions not analysed in this study.
5 Demand includes all EU countries and the UK and Norway. Demand estimates do not include domestic EU consumption of ammonia for shipping or other derivates. For comparison, RePowerEU considered 4 MT of demand for ammonia and other derivatives.

8.9

Demand identified
by EHBEXECUTIVE SUMMARY© 2022 European Hydrogen Backbone,
all rights reserved

Regional differences in supply and demand show theimportance of connecting regions across Europe
Across different regions in Europe, there are significant
differences in the hydrogen supply-demand balance.
Some regions are characterised by a net supply of lowcost, hydrogen resources. These regions benefit fromvast renewable energy potential, high capacity factors andsubstantial land availability.

(TWh)¹, ², ³

127

502

/ Supply (2030/2040)/ Demand (2030/2040)

81

2030

171

2040

257
135

65

2030

Hydrogen pipeline infrastructure can bridge theseregional supply-demand differences across Europe in a
cost-effective manner.

727
2040

287
197
82

The EHB vision delivers the infrastructure needed
to connect hydrogen supply and demand acrossEurope.

2030

438

179

2040

30 37
273

129

2030

84

2030
Aggregated demand and supply are based on the 2030 figures determined in this study. Supply figures
include imports from North Africa and Ukraine. Note: Demand and supply figures may increase further in
response to more ambitious national policies and measures following the RePowerEU plan.
2 This analysis estimates ~490 TWh of demand and ~580 TWh of supply in 2030 and does not attempt todetermine how hydrogen supply and demand will balance out across Europe, nor which hydrogen supply
sources – or from which regions – will be used to meet demand.
3 Demand and supply figures may not align with figures presented in the rest of the report based on
aggregation of countries into regions and due to rounding.

255

Regional Supply and Demand,
2030 and 2040

Other regions will require hydrogen imports from other
European or neighboring regions to meet their hydrogen
demand.

1

6

216

2040

77

26

2030

102
2040

113

2040

EXECUTIVE SUMMARY© 2022 European Hydrogen Backbone,
all rights reserved

Five supply corridors are key to the EHB vision and can deliver
access to abundant and low-cost hydrogen supply by 2030

7

DTo deliver the 2030 hydrogen demand targets set by the
RePowerEU plan, five large-scale pipeline corridors are envisaged.
The corridors will initially connect local supply and demand indifferent parts of Europe, before expanding and connecting Europe
with neighboring regions with export potential.

Oslo

C

Certainty about the deployment of this infrastructure will enable
market actors to develop supply and demand more rapidly– Corridor B: Southwest Europe & North Africa

TalinnStockholm

Göteborg
Riga

Edinburgh

Copenhagen

Hamburg

Manchester
DublinBerlinRotterdam

Cork
LondonWarsaw
CologneLeipzig– Corridor D: Nordic and Baltic regions

Paris

Krakow

PragueFrankfurt– Corridor C: North Sea

MunichViennaBratislava
Budapest– Corridor E: East and South-East Europe

Ljubljana

Lyon

Milan
VeniceBordeaux

These five corridors span across both domestic and importsupply markets, consistent with the three import corridors
identified by the RePowerEU plan, including a corridor via
the Mediterranean (Corridors A and B), via the North Sea(Corridor C) and via Ukraine (Corridor E)

Vilnius

Gdansk

The five hydrogen supply corridors are:– Corridor A: North Africa & Southern Europe

Helsinki

Bucharest

BilbaoMarseille
Porto
MadridB

RomeBarcelona

Valencia

LisbonAlmeria
TarifaE

SoﬁaA

PalermoAthensEXECUTIVE SUMMARY© 2022 European Hydrogen Backbone,
all rights reserved

These five corridors represent the collective vision of the
31 gas infrastructure companies part of the EHB initiative
Corridor A
North Africa& Southern Europe

Corridor B
Southwest Europe& North Africa

Note: Since all corridors terminate in Germany, OGE and ONTRAS are presented in each corridor grouping.

Corridor C
North Sea

Corridor D
Nordic andBaltic regions

8

Corridor E
East and South-East
EuropeCMYK
10 0 / 75 / 2 0 / 10

PA N TO N E
2 81 C

CMYK
6 0 / 0 / 10 0 / 0

PA N TO N E
369 C

CMYK
12 / 0 / 10 / 5 0

PA N TO N E
4 31 CEXECUTIVE SUMMARY© 2022 European Hydrogen Backbone,
all rights reserved

Each corridor has a unique regional role in enabling the scale up of low-costhydrogen supply and the decarbonisation of energy demandCorridor A
North Africa& Southern Europe

Corridor A would transportlarge quantities of costcompetitive green hydro­
gen potential from Tunisia
and Algeria through Italy tocentral Europe leveraging
existing gas infrastructure.
Corridor A would decar­
bonise existing industries
along the route in Italy
and Central Europe aswell as in Germany.

1

Corridor B
Southwest Europe& North Africa

Corridor B would
transport green hydrogen
supply from the Iberianpeninsula and North
Africa, and gain accessto under­ground storagesites in France to deliver
stable hydrogen supply.
Corridor B would decar­
bonise regional industry
and transport clusters in
Portugal, Spain, Franceand Germany.

Corridor C
North Sea

Corridor D
Nordic andBaltic regions

Corridor C includes hydro­
gen supply from ongoingand planned offshorewind, blue hydrogen andlarge-scale integratedhydrogen projects in the
North Sea.
Corridor C would meetdemand from industrial
clusters and ports in theUK, the Netherlands,
Belgium and Germany.

While Ukraine is expected to be a hydrogen exporting region, there is significant uncertainty related to Russia’s invasion of Ukraine and its impact on Ukraine’s gas infrastructure and economic development.

Corridor D would transport
green hydrogen supply
potential from onshore
and offshore wind fromcountries surrounding theBaltic Sea.
Corridor D would be built
around regional networks
around industrial clusters,
serving numerous new green
steel, e-fuel, fertilizer andgreen chemicals projects
in the Nordics as well
as decarbonizing existing
industry in the Nordics,
Baltics, Poland and Germany
along the corridor route.

Corridor E
East and South-East
EuropeCorridor E would connect
high supply potential
regions such as Romania,
Greece, and Ukraine¹– leveraging vast landavailability and highcapacity factors for solar
and wind.
Corridor E would deliverhydrogen to off-takers
in Central Europe andGermany.

9

EXECUTIVE SUMMARY© 2022 European Hydrogen Backbone,
all rights reserved

These five supply corridors will enable the creationof a pan-European hydrogen market by 2030

D

– Connect substantial hydrogen supply and demand acrossEuropean regions and leverage underground storage todeliver stable supply

Oslo– Access vast volumes of cost-competitive domestic hydrogen
supply and hydrogen imports from neighboring regions

C– Foster the creation of a liquid, pan-European, hydrogen
trading market

Helsinki
TalinnStockholm

Göteborg
Riga

Edinburgh

Copenhagen

Vilnius

Gdansk– Accelerate the deployment and integration of renewableenergy resources

Hamburg

Manchester
DublinBerlinRotterdam

Cork
London– Support scale-up of green, innovative European industries

Warsaw
CologneLeipzig
Krakow

PragueFrankfurt

Paris

MunichViennaBratislava
Budapest– Increase the resiliency of Europe’s energy system

Ljubljana

Lyon– Contribute to European energy independence anddiversity of supply.

Milan
VeniceBordeaux

Bucharest

BilbaoMarseille
Porto
Madrid– Deliver substantial and cost-effective emission reductions

10

B

Rome
Barcelona

Valencia

LisbonAlmeria
TarifaE

SoﬁaA

PalermoAthensEXECUTIVE SUMMARY© 2022 European Hydrogen Backbone,
all rights reserved

To ensure the development of each corridor by 2030,
there is a need for clear and concrete actions
Fostering development of new and repurposed hydrogen infrastructure, for example, by unbundling rules
facilitating the efficient use of TSO expertise and services and by allowing the adoption of different vertical unbundlingmodels in the EU, as is the case with natural gas

Corridor A
North Africa& Southern Europe
Corridor D
Nordic andBaltic regions

Corridor B
Southwest Europe& North Africa

Unlock financing to fast-track hydrogen infrastructure deployment by applying regional regulatory flexibility andother pragmatic financing solutions (including incentivizing the adoption of hydrogen by demand sectors)

Simplify and shorten planning and permitting procedures for the full value chain of renewable energies andhydrogen infrastructure projects.

Facilitate integrated energy system planning of hydrogen, natural gas, and electricity infrastructure supporting
the accelerated deployment and integration of renewable energy resources
Corridor C
North Sea

Corridor E
East and South-East
EuropeIntensify energy partnerships with exporting, non-EHB countries (e.g., with Morocco, Algeria, Tunisia, Ukraine)providing financing support to reduce the cost of capital in export countries and identifying a common certification
system for hydrogen exchanges

However, speed will be of essence!

11

EXECUTIVE SUMMARY© 2022 European Hydrogen Backbone,
all rights reserved

The EHB initiative stands ready to deliver the hydrogen infrastructureneeded to achieve Europe’s 2030 hydrogen targets

We have identified a large
share of the demand andsupply needed to meet
the RePowerEU targets.

We analysed andstudied five largescale, hydrogen supply
corridors that will be
critical in transporting
the required amounts ofhydrogen.

These five supply corridors
have the potential toprovide Europe withaccess to abundantand low-cost hydrogen
supply by 2030.

To ensure thedevelopment of these
supply corridors on time,
we have identified five
key concrete actions

The EHB initiative and its members are ready to deliver

12

Ultimately, to realise
the hydrogen pipeline
infrastructure required by
2030, action is needednow.

EXECUTIVE SUMMARY© 2022 European Hydrogen Backbone,
all rights reserved

Our recommendation: Establish hydrogen supply corridors
as enabler for hydrogen market creation

Answering to RePowerEU
This reports shows how all
31 members are able toaccelerate the hydrogen
infrastructure development
to enable the 20 MT of renew-­able hydrogen by 2030

EHB recommends introducing
the establishment of hydrogen
supply & import corridors as
front-running infrastructure,including all infrastructure requirements, as a political objective.

13

© 2022 European Hydrogen Backbone,
all rights reserved

TABLE OF CONTENTS

1. Executive Summary
2. Five emerging supply corridors
Corridor A: North Africa & Southern Europe
Corridor B: Southwest Europe & North Africa
Corridor C: North Sea
Corridor D: Nordic and Baltic regions
Corridor E: East and South-East Europe

3. Detailed methodology

14

INTRODUCTION TO THE CORRIDORS© 2022 European Hydrogen Backbone,
all rights reserved

This report analyses each of the five hydrogen corridors
and their roles in enabling a pan-European backbone
Sections
1

Hydrogen
Demand& Supply

2 Costs & Cost
Compe­titive­ness
3 National
Strategies& Regulations

D

Questions answered– How will hydrogen demand and supply evolve
over time in this corridor?
– Which countries and sectors will drive thedevelopment of hydrogen demand in thiscorridor?
– How will the hydrogen supply mix changeover time?
– How competitive will hydrogen from this corridor
be with fossil alternatives?
– What cost-levers can lower hydrogen cost?

Oslo

C

Stockholm

Göteborg
Riga

Edinburgh

Copenhagen

Vilnius

GdanskHamburg

Manchester
DublinBerlinRotterdam

Cork
LondonWarsaw
CologneLeipzig

Paris

Krakow

PragueFrankfurt– What is the state of national hydrogen strategies
and regulation in the countries of this corridor?

MunichViennaBratislava
Budapest

Ljubljana

Lyon– What near-term regulatory and planning
actions are required to support the developmentof this corridor?

Helsinki
Talinn

Milan
VeniceBordeaux

4 Actions
Needed15

Bucharest

BilbaoMarseille
Porto
MadridB

RomeBarcelona

Valencia

LisbonAlmeria
TarifaE

SoﬁaA

PalermoAthensINTRODUCTION TO THE CORRIDORS© 2022 European Hydrogen Backbone,
all rights reserved

This study builds on previous EHB reports and findings,
and incorporates new corridor-specific analysis

16

Key study inputs

Major study uncertainties

Out of scope

Inputs are defined primarily over the 2030-2050
timeframe, building on the most recently published
EHB reports and maps:– Uncertainty on near- and long-term European
natural gas prices and supply mix.

– This study does not incorporate detailed
infrastructure planning associated with therepurposing of existing natural gas pipelines,
storage facilities, or gas import / export
terminals.

– Hydrogen demand forecasts by country,
sector and year.
– Realisable hydrogen supply potential bycountry and year;– Existing gas pipeline infrastructure (onshore
and offshore) and storage facilities;– Hydrogen infrastructure development plansby country; and– Costs assumptions associated with green andblue hydrogen supply and pipeline repurposing.

– Uncertainty related to Russia’s invasionof Ukraine and its impact on Ukraine’s gas
infrastructure, economic recovery anddevelopment of a hydrogen market.
– Uncertainty regarding the development ofhydrogen pipeline infrastructure acrossEurope, which is subject to developments
in European and national energy policy,
regulations and funding.

– This study does not account for ship importsof hydrogen or hydrogen-derivatives likeammonia and methanol into Europe.

– Uncertainty regarding future hydrogen demandand supply, which may accelerate and increase
further as a result of additional regulatory measures
adopted in response to the RePowerEU plan.

Methodology Section: Refer to the Section 3: Methodology for a description of the general supply and demand approach, key inputs, data sources, calculations, etc.

INTRODUCTION TO THE CORRIDORS© 2022 European Hydrogen Backbone,
all rights reserved

Since some corridors transit through the same countries,
key metrics – like corridor length, supply and demand – overlap
In this study, when a corridor transit through agiven country, even if only partially, it becomespart of the analysis of the corridor, including its
hydrogen demand, supply and transport infrastructure.

Total corridor length (km)²

13,500All five corridors of this study either: (1) transit
through some of the same countries, or (2)terminate in the same country¹.

17

10,00028,000Corridor E

2030

12,000For example:– Corridor B (Southwest Europe and North Africa) andCorridor C (North Sea) both transit through sectionsof the Netherlands, Belgium and Germany.
– Corridor D (Nordic and Baltic regions) andCorridor E (East and South-East Europe) both transit
through section of Germany, Czechia and Poland.

10,00011,000This means that all corridors partially overlap withother corridors. As a result, key metrics – likecorridor length, supply and demand – overlap
and are not mutually exclusive.
This is illustrated on the right for corridor lengths.
Corridor A
Since the largest demand clusters in Europe are concentrated in and around Germany,
all five corridors terminate – and thus, overlap – in Germany
2 The basis for these determining corridor lengths is the most recent publication of the
EHB maps (April 2022).

Corridor B

Corridor C

Corridor D

1

Note: Since all corridors partially overlap, summing all individual corridor lengths – without adjusting for overlaps – adds up to ~56,000km, which is two times the combined length of 28,000 km in 2030².

© 2022 European Hydrogen Backbone,
all rights reserved

TABLE OF CONTENTS

1. Executive Summary
2. Five emerging supply corridors
Corridor A: North Africa & Southern Europe
Corridor B: Southwest Europe & North Africa
Corridor C: North Sea
Corridor D: Nordic and Baltic regions
Corridor E: East and South-East Europe

3. Detailed methodology

18

CORRIDOR A© 2022 European Hydrogen Backbone,
all rights reserved

North Africa& Southern Europe

19

Agenda
1. Corridor Summary
2. Hydrogen Demand & Supply
3. Supply Costs & Cost-Competitiveness4. National Strategies & Regulation
5. Actions Needed

CORRIDOR A / FACTSHEET

20

Corridor emerges in Southern Europe providing access to low-costhydrogen supply from North Africa to demand clusters along the corridor

Italy
Switzerland
Slovenia
Hungary
Croatia
Czechia
Austria
Slovakia
Germany

Drivers &Opportunities
Hydrogen Supply& Decarbonization
Potential

Major driver of development is the need to meet hydrogen demand fromindustry, transport and power in Italy, Central Europe and Germany. Key
opportunities include the high repurposing potential of gas pipelines from Italy
to Central Europe, and pipeline interconnections with Algeria and Tunisia.
H₂ supply potential¹
Emissions
2030
2040
340 TWh(TWh/year)
Reductions
97 TWh2030

Supply Costs& CostCompetitiveness

Cost of H₂
production¹

1-160 Mt(18%)

Cost competitiveness²
1.4–2.8(€/kg of H₂)-55 Mt(6%)

2040

2.1–3.82030

Actions Needed(MtCO₂/year vs. 2019;% reduction)

2040

Hydrogendelivered pricevs.
natural gas pricehigh/low,(€/MWh)

72

73

69

59

62

2030

2040

42

– Fostering development of new and repurposed hydrogen infrastructure– Unlock financing to fast-track hydrogen infrastructure deployment– Simplify and shorten planning and permitting procedures– Facilitate integrated energy system planning of hydrogen, natural gas, andelectricity infrastructure– Intensify energy partnerships with exporting, non-EHB countries like Tunisia and Algeria

Figures reported reflect outputs for all countries included in the corridor. Even if a country is only partially in the corridor, results for the full country are included (e.g., supply potential and costs,
demand, transmission network length).
2 Savings are based on the corridor’s case study of hydrogen delivered in 2030 and 2040. The cost of natural gas includes CO₂ prices. Refer to Subsection 3 (Supply Costs & Cost-Competitiveness)© 2022 European Hydrogen Backbone, all rights reserved

North Africa& Southern Europe

Corridor A / North Africa & Southern Europe

CORRIDOR A© 2022 European Hydrogen Backbone,
all rights reserved

North Africa& Southern Europe

21

Agenda
1. Corridor Summary
2. Hydrogen Demand & Supply
3. Supply Costs & Cost-Competitiveness4. National Strategies & Regulation
5. Actions Needed

CORRIDOR SUMMARY

Corridor A / North Africa & Southern Europe

Drivers &Opportunities– The major driver behind the development of this corridor isthe adoption of hydrogen associated with the decarbonisationof industry, transport and power in Italy, Central Europe andGermany. The speed of hydrogen adoption in these regions may
be even faster than anticipated driven by increasing CO₂ prices
in the EU and the RePowerEU ambitions to replace natural gas
consumption.
– In the near term, the corridor offers access to abundant lowcost, renewable production from Italy and Tunisia. In thelonger term, this corridor may also provide access to hydrogen
imports from Algeria (via Tunisia) and additional supply fromCentral and South-Central Europe.

– A major opportunity of the corridor is the ability to repurpose alarge share of existing gas pipeline infrastructure across Italy,
Austria, Slovakia, and Czechia. Another key opportunity is the potential
repurposing of the Trans-Mediterranean pipeline connecting Tunisia
to Italy via Sicily, giving the corridor access to the abundant solar andwind resources of Northern Africa.
– Recently, RePowerEU identified the development of a new subsea
pipeline connecting Spain and Italy, expected to be available forhydrogen transport by 2030.
– The corridor would be stood up by 2030, covering 11,000 km oflarge-scale hydrogen pipelines across all countries of the corridor, of
which approximately 60% will be repurposed pipelines.

Hydrogen Demand& Supply– Total hydrogen demand in the corridor reaches ~140 TWh by
2030, increasing substantially to ~550 TWh by 2040. Up to2030, most hydrogen demand is driven by the industrial sector
in Germany and Italy, along with some use of hydrogen in power
generation. From 2040 to 2050, hydrogen demand expands into
the transport sector and continues to ramp up in industry andpower generation.

– Hydrogen adoption across all countries of the corridors enables anemissions reduction of ~220 MtCO₂/yr. by 2050, equivalent to a
25% emissions reduction.
– The corridor enables access to hydrogen supply potential of~100 TWh by 2030, increasing to roughly 340 TWh by 2040.
Major sources of supply include hydrogen imports from North Africa
and green hydrogen from Italy.

© 2022 European Hydrogen Backbone, all rights reserved

Corridor offers access to low-cost hydrogen supply from North Africa
to demand centers in Italy, Central Europe and Germany

22

CORRIDOR SUMMARY

Corridor A / North Africa & Southern Europe

Costs & CostCompeti­tiveness– By 2030, the corridor provides access to hydrogen ranging in
production costs from 2.1 to 3.8 €/kg. By 2040, as supply
options increase, technology costs decrease, and increased
imports from North Africa become available, hydrogenproduction costs decrease to 1.4 to 2.8 €/kg.
– Already by 2030, this corridor’s lowest-cost supply options areimports from North Africa.

– Based on a case-study of hydrogen supply and transport from Tunisia
to Germany, the cost of delivered hydrogen – inclusive of transportand storage costs – can be lowered to achieve cost levels
comparable to production costs by 2040. Lowering delivery costs
can be achieved through various cost levers including optimised
operation of the system and cost of capital reductions.

National Strategies& Regulation– Most countries have developed – or are in the processof developing – national strategies. Moving forward, thedevelopment of hydrogen regulation in all countries will be key
in enabling investment in infrastructure.

– In select countries, substantial funding has been allocated tosupport the development of the hydrogen market including funding
for gas network infrastructure.

Actions Needed

To support the buildout of this corridor by 2030, clear and concrete
actions related to infrastructure planning, financing and development
have been identified:– Fostering development of new and repurposed hydrogen
infrastructure.
– Unlock financing to fast-track hydrogen infrastructure deploy­ment by applying regional regulatory flexibility and other prag­
matic financing solutions.

– Simplify and shorten planning and permitting procedures for thefull value chain of renewable energies and hydrogen infrastructure
projects.
– Establish integrated energy system planning of hydrogen, naturalgas, and electricity infrastructure.
– Intensify energy partnerships with exporting, non-EHB countries
like Tunisia and Algeria.

© 2022 European Hydrogen Backbone, all rights reserved

To successfully stand up this corridor by 2030, actions are needed
to support infrastructure planning, financing and development

23

CORRIDOR A© 2022 European Hydrogen Backbone,
all rights reserved

North Africa& Southern Europe

24

Agenda
1. Corridor Summary
2. Hydrogen Demand & Supply
3. Supply Costs & Cost-Competitiveness4. National Strategies & Regulation
5. Actions NeededHYDROGEN DEMAND & SUPPLY / SECTION INTRODUCTION

Corridor A / North Africa & Southern Europe

This section explores the development of demand, supply andtransport infrastructure in the corridor from 2030 to 2050
2030 Corridor
Snapshot(Supply, Demand,and Infrastructure)

25

Hydrogen demand
By 2030, the corridor connects all major industrial clusters from Italy toGermany. From 2030 to 2040, the corridor expands to all demand centersalong its route, increasing demand from 140 to ~550 TWh.

Hydrogen supply
Pipelines
Repurposed
New
Import / Export
SubseaDemand per sector

By 2030, the corridor enables access to low-cost supply from Italy andTunisia. By 2040, the corridor gains access to supply from Algeria (via
Tunisia), Central and South-Central Europe
In 2030, hydrogen supply is ~100 TWh, of which more than 70% is imports.
Hydrogen supply increases significantly by 2040, reaching 340 TWh.

40 / 30 / 20 / 10 / 1 TWh
Efuels production
Industrial energy
Industrial feedstockPower

Storages
Salt cavern
Aquifer
Depleted field
Rock cavern
Other items
Existing or planned
gas-import-terminal
Energy island forH₂ production

Imports

Grid-based

Dedicated green

Blue

Hydrogen Infrastructure
By 2030, the buildout of pipeline infrastructure across all countries of thecorridor reaches 11,000 km of large-scale pipelines. Corridor benefits from avery large share of repurposed infrastructure.
60% (Repurposed pipelines)

40% (New pipelines)

11,000 km (2030)© 2022 European Hydrogen Backbone, all rights reserved

Supply in MWh/km²<1
1 – 2525 – 100
100 – 250
250 – 500
> 500

97 TWh (2030)

HYDROGEN DEMAND & SUPPLYCorridor A / North Africa & Southern Europe

2030

2040

Pipelines
Repurposed
New
Import / Export
SubseaPipelines
Repurposed
New
Import / Export
SubseaDemand per sector

Demand per sector

40 / 30 / 20 / 10 / 1 TWh

40 / 30 / 20 / 10 / 1 TWh

Efuels production
Industrial energy
Industrial feedstockPower

Efuels production
Industrial energy
Industrial feedstockPower

Storages
Salt cavern
Aquifer
Depleted field
Rock cavern

Storages
Salt cavern
Aquifer
Depleted field
Rock cavern

Other items
Existing or planned
gas-import-terminal
Energy island forH₂ production

Other items
Existing or planned
gas-import-terminal
Energy island forH₂ production© 2022 European Hydrogen Backbone, all rights reserved

Corridor connects major hydrogen clusters across Italy andCentral Europe by 2030, expanding to all demand centers by 2040

26

HYDROGEN DEMAND & SUPPLYCorridor A / North Africa & Southern Europe

Hydrogen demand increases rapidly from 2030 to 2040, largely driven
by Germany and Italy. Demand continues increasing to 2050
2030

2040

Hydrogen demand – across all countries of
the corridor – increases significantly from2030 to 2050. Demand reaches 140 TWh by
2030, increasing to 840 TWh by 2050.

2050

General H₂ flow

Total demand per country (TWh/y)
Italy

23

Croatia2

8

11

Slovenia

1

5

7

89

187

Hungary

4

15

25

Czechia51727Austria836

52

Slovakia

7

20

26

Germany
Total

90
140

364

Hydrogen demand may accelerate andincrease further as a result of additional
regulatory measures adopted in response to
the RePowerEU plan.
– Up to 2030, most hydrogen demand isdriven by the industrial sector in Germany
and Italy, along with some use of hydrogenin transport and power generation.
– From 2040 to 2050, hydrogen demand
expands into the transport sector and continues
to ramp up in industry and power generation.
505

553

1 Switzerland is not included in the demand figures because as a non-EU member, Switzerland is not included in the datasets used to estimate hydrogen demand in 2030, 2040 and 2050.
Note: Does not include grey hydrogen demand. Numbers represent total demand by country, even if only parts of the country are included in the corridor.

840© 2022 European Hydrogen Backbone, all rights reserved

Country¹

27

HYDROGEN DEMAND & SUPPLYCorridor A / North Africa & Southern Europe

Hydrogen adoption enables a reduction in emissionsof 25% by 2050 across all countries of the corridor
-6 %

-18%

-25 %

Hydrogen adoption across all demand
sectors enables an emission reduction of~220 MtCO₂/yr. by 2050, equivalent to a
25% reduction².

Decarbonisationin Mt CO₂ / year240

– Up to 2030, the decarbonisation ofindustry – largely the steel sector andrefining – contributes 75% of the total
emissions reductions.

221

220
200
180

– By 2040, emissions reductions from power
generation and transport (road, shipping andaviation) increase substantially and combined
account for 50% of emissions reductions.

159

160
140

– By 2050, most incremental emissions re­ductions are associated with hydrogen
adoption in the power and transport sectors.

120
100
80
60

54

40
20

IndustryPower
Buildings
Transport

02030© 2022 European Hydrogen Backbone, all rights reserved

2040

2050

1

CO₂-Emissions from countries and sectors included in corridor (0.89 bn t CO₂ / year),
Source: EEA
2 Emissions reductions are calculated compared to the baseline fossil fuel used in eachsectors. For example, emissions reductions associated with the adoption of hydrogen by the
primary steel sector are relative to the use of coal. Similarly, emissions reductions , for e-fuels
production are relative to the use of fossil fuels in domestic transport, shipping and other uses.

© 2022 European Hydrogen Backbone, all rights reserved

Emissions reductions(vs. 2019 emissions¹)

28

HYDROGEN DEMAND & SUPPLYCorridor A / North Africa & Southern Europe

Corridor enables access to supply from Italy and Tunisia by 2030,
expanding to supply from Central and South-Central Europe by 2040

Pipelines
Repurposed
New
Import / Export
SubseaSupply in MWh/km²<1
1 – 2525 – 100
100 – 250
250 – 500
> 500
Storages
Salt cavern
Aquifer
Depleted field
Rock cavern
Other items
Existing or planned
gas-import-terminal
Energy island forH₂ production
Total hydrogen supply shown per NUTS-2 region. MWhadjusted by the area of each NUTS-2 region in km².
* Note: Supply numbers do not include grey hydrogen.

2040*

Pipelines
Repurposed
New
Import / Export
SubseaSupply in MWh/km²<1
1 – 2525 – 100
100 – 250
250 – 500
> 500
Storages
Salt cavern
Aquifer
Depleted field
Rock cavern
Other items
Existing or planned
gas-import-terminal
Energy island forH₂ production© 2022 European Hydrogen Backbone, all rights reserved

2030*

29

HYDROGEN DEMAND & SUPPLYCorridor A / North Africa & Southern Europe

Hydrogen supply increases significantly from 2030 to 2040, largely
driven by green hydrogen supply from North Africa and Italy
2030
SupplyImports(TN, ALG)
Italy

General H₂ flow

Croatia

Czechia
Austria
Slovakia
Germany
Total

Net¹

-16

7

-2

0.1

-1

0

-4

0.4

-5

3.7

0.4 0.2

-75

14.6

70

-6

26

-43

Net¹

40

-40

9

4

11

-1

4

-5

10 1

-17

0.1

-31

5

-14

6

81

Supply

150

150

-4

0.1

2050

Supply70

70

Slovenia
Hungary

2040

-261

21

303

1 Net represents excess supply after subtracting demand;
2 Grid-based is estimated using national 2030 electrolyser targets which, by 2030, are assumed to be largely
grid-connected rather than dedicated. Grid-based increases over 2030-2050 with increasing RES adoption;
3 Switzerland is not included in the demand figures because as a non-EU member, Switzerland is not includedin the datasets used to estimate hydrogen demand in 2030, 2040 and 2050.

37

-214

Net¹
375

375

82

-94

11

7

18

-3

4

31

7

1

-27

0.1

-45

7

12

-13

1

-313

165 27687

Dedicated green
Blue
Grid-based
2050 technical potential

47

Hydrogen supply includes a mix of supply
options including grid-based green hydrogen²and dedicated green hydrogen.
– By 2030, hydrogen supply reaches~100 TWh, largely from grid-basedhydrogen.
– By 2040, hydrogen supply increases sub­stantially to ~340 TWh, of which 90%
is from dedicated green hydrogen. The
remaining share is grid-based hydrogen.
– By 2050, hydrogen supply increases
further to ~730 TWh. Dedicated green
supply continues to account for the largest
share at roughly 95%.
Hydrogen supply may accelerate andincrease further as a result of additional
regulatory measures adopted in response to the
RePowerEU plan.

-106

Note: Hydrogen supply volumes do not include hydrogen imports by ship.

© 2022 European Hydrogen Backbone, all rights reserved

Country30

HYDROGEN DEMAND & SUPPLYCorridor A / North Africa & Southern Europe

Tunisia and Algeria may become a potential sourcesof hydrogen imports to Europe as early as 2030
– North Africa connects to Italy via Tunisia with one interconnector: theEnrico Mattei – Transmed pipeline via Sicily (525km, 30 bcm/year)– Two existing Algerian LNG export terminals: Arzew/Bethouia(20.8 mln tonne per year) and Skikda (7.7mln tonnes per year)– Hydrogen export potential via this corridor focuses primarily on hydro­gen
supply from Tunisia and Algeria via the Transmed pipeline.

MarketAttractiveness– Abundant renewable energy potential particularly solar PV and onshorewind– Partnerships: Germany has established partnerships with both Tunisia andAlgeria exploring the potential of green hydrogen exports– Market developments:– Tunisia is taking part in the HyDeal project, which could see 1.4Mt/year
produced in the country and an investment of over 20bn €.
– Availability of Algerian hydrogen exports to Europe highly depends on
repurposing natural gas pipelines between Algeria and Tunisia.

MarketBarriers

1

Hydrogen supply potential (TWh)¹
Tunisia + Algeria

375

150
70

2030

2040

2050

– Limited renewable energy infrastructure, low renewables pene­tration in
own energy system and strong reliance on hydrocarbons today– Inadequate financing mechanisms on a state and local level for renewableprojects– Future growth in domestic hydrogen demand may impose limit on exports.

Supply figures estimated based on hydrogen supply potential combined for Tunisia and Algeria. Export potential is dependent on development ofdemand and infrastructure.

Note: The high potential import from Algeria and Tunisia depends on development of both demand and infrastructure© 2022 European Hydrogen Backbone, all rights reservedState ofGas Infrastructure

31

CORRIDOR A© 2022 European Hydrogen Backbone,
all rights reserved

North Africa& Southern Europe

32

Agenda
1. Corridor Summary
2. Hydrogen Demand & Supply
3. Supply Costs & Cost-Competitiveness4. National Strategies & Regulation
5. Actions Needed

SUPPLY COSTS & COST-COMPETITIVENESS / SECTION INTRODUCTION

Corridor A / North Africa & Southern Europe

This section explores the costs of hydrogen production and delivery
for this corridor and their competitiveness with fossil fuels
Hydrogen delivered costs

Comparison with fossil alternatives

What is the range of production costs
achieved by the corridor in 2030 and
2040?

Based on a case-study of hydrogen supply
from Tunisia to Germany:– What are the full costs of firm hydrogendelivery after accounting for transportand storage costs?
– What cost levers are available to lower thecost of hydrogen delivery?

How competitive is hydrogen supply
from this corridor compared to fossil fuelalternatives?

Baseline Costs

-26%
1.1

3.3

0.4
0.1

2.8

0.1

2.5
Levelised cost of hydrogen production (€/kg) and Supply per country (TWh)

3.8

3.0

0
0

20
Imports
Blue hydrogen

40

2.5
60

80

2.0

Wind offshore
Wind onshore

1.5

100

120

Solar PV
Grid-connected

140

160

180

200

220

240

260

280

300

320

340

2040

Case study (see next slide)

2.1

High
Low

1.0
1-3 See previous slide

0.5
0.0
0

10
Imports
Blue hydrogen

20
Wind offshore
Wind onshore

30
Solar PV
Grid-connected

40

50

60

70

80

90

Case study (see next slide)1 Cost curves are based on a bottom-up estimate of supply volumes per country and hydrogen production type. No transport or storage / firming cost are included.
2 Dedicated hydrogen production costs are based on renewable technology and electrolyser costs, and country-specific capacity factors and discount rates.
3 Grid-connected hydrogen production costs are determined based on costs of a mix of dedicated green hydrogen (solar, onshore wind, offshore wind) and adjusted for grid-connection costs.

Key Findings& Results

100

2030
High
Low

Baseline costsof H₂ production(€/kg)© 2022 European Hydrogen Backbone, all rights reserved

Au
str
ia

1.4

© 2022 European Hydrogen Backbone, all rights reserved

3.5

Ita
ly,
Slo
va
kia

4.0

G
er
m
an
y

1.0
0.5

N
or
th

Af
ric
a

1.5

0.3

2.1

2.0

– By 2030, the corridor provides accessto hydrogen production costs of 2.1 to
3.8 € / kg.
– By 2040, hydrogen production costs
decrease to the range of 1.4 to 2.8 € / kg.

€/MWhCost of H₂delivered

Optimisedsystem sizing

Battery storage
operation

Powerelectronics
savings

Reduced costof capital

Optimised costof H₂ delivered(€/kg)

1 Transport costs are based on several parameters including the type of pipeline (repurposed vs. new), transport distance and full-load-hour production on that pipeline. Firming costs are based on
additional storage cost required to deliver hydrogen at the equivalent of 8,000 full-load hours.
2 Optimised system sizing refers to right-sizing of solar PV and electrolyser capacity to increase full load hours. Similarly, battery storage operation enables an increase in the full load hours. Power
electronics savings refers to the removal of the inverter of the solar PV modules to reduce system cost. Reduced cost of capital refers to the use of foreign investment to reduce the WACC from 8 to 6%.
3 In some instances, cost reduction levers may result in cost increases for certain cost-components. For example, an increase in production costs at the same time as a decrease in firming costs. These cost
increases and decreases can result in connection lines that do not directly connect one step to the next.

114

Cost of fossil
fuel alternatives

Transport
Firming
Production

Delivered Costs (€/kg)(before and after cost levers)
2030

2040

Before costs lever

3.3

2.5

After costs lever

2.4

1.4

Production
costs
€/MWh

89‒115(=3.8 €/kg)

84
59‒73

63

– Several cost reduction levers can beapplied to lower the costs of hydrogendelivery.
– For the Tunisia-to-Germany case study,
these levers achieve delivery costs thatare low and cost-competitive.

63‒69

H₂ production
cost-range
Higher Cost H₂Lower Cost H₂

Case study
Deliveredcost of H₂
2.4 €/kg

NaturalGas
Fuel cost
CO₂ cost

Steam
Coal

Oil

85‒88

(=2.8 €/kg)

83‒95
Case study
Deliveredcost of H₂
1.4 €/kg

62‒69

72 €/MWh(=2.1 €/kg)

By 2030, the low range of hydrogenproduction costs are competitive
with natural gas and coal, andlower than oil alternatives.

Cost of fossil
fuel alternatives

Fuel cost
uncertainty– In 2040, hydrogen delivered
costs can be reduced by 40%(1.4 vs. 2.5 €/kg).

Transport &firming cost

2040

Production
costs– In 2030 (shown on the left),the cost of delivered hydrogencan be lowered by 26% (2.4 vs.
3.3 €/kg).

2.4

Cost range (€/kg)

2030

Cost reduction levers applied tocase study of hydrogen transport
from Tunisia to Germany enable
firm delivery costs to be reduced
significantly.

Cost Reductions Levers

38

42

42 €/MWh(=1.4 €/kg)

H₂ production
cost-range

Natural
Gas

Steam
Coal

Oil

Fuel uncertain

Note: Prices for fossil alternatives (2030/2040): Natural gas (pre-invasion): 28/13 [€/MWh], Coal: 123/5.6 [€/MWh], Oil: 52/24 [€/MWh]. Natural gas price levels are based on market conditions before Russia’s invasion of Ukraine. While natural gas prices
have skyrocketed since, there remains significant uncertainty on near- and medium-term European price trends and supply options. As a result, our analysis adopts the IEA’s Outlook 2021 price forecast pre-invasion developed pre-invasion. Prices in 2040
are significantly lower than in 2030 because of demand-supply conditions. By 2040, decreased demand for fossil fuels would lower prices. [Source: International Energy Agency, Outlook 2021 (IEA)] and fuel-cost uncertainty is shown with +50% range]

By 2040, the low range ofhydrogen costs are materiallylower than all fossil alternatives,
while the medium-to-high range
are cost competitive.
Hydrogen delivered costs from theTunisia-Germany case study arecompetitive to natural gas in 2030
(22% higher) and lower in 2040
(32% lower).
Natural gas prices are still
uncertain due to recent pricespike as a result of the Russian
invasion of Ukraine.
Note: For comparison purposes, cost of H₂ has been converted from“per kg” to “per MWh”
– 1 €/kg = 30 €/MWh (based on LHV of 33.3 kWh/kg)
Competitiveness of hydrogen highly dependant on CO₂-prices as they
make up a significant part of fossil fuel costs.
– CO₂ price 2030: 130 €/t– CO₂ price 2040: 205 €/t– Hydrogen costs are competitive withfossil fuel alternatives by 2030, andlower by 2040.
– Fossil fuel costs are subject to significant
uncertainty.

© 2022 European Hydrogen Backbone, all rights reserved

Cost of Hydrogen Delivered (€/kg) in 2030¹, ², ³

34
Cost range (€/kg)

Cr
oa
tia

G
er
m
an
y

Hydrogen Production Cost Range [2030]¹ ² ³
, ,

Slo
It
va aly
kia
, It
aly

G
er
m
an
y

It a
ly

N
or
th

G
er
m
an
y

InLevelised
2030,
the corridor offers access to hydrogencost of hydrogen production (€/kg) and Supply per country (TWh)production ranging in costs from 2.1 to 3.8 €/kg

Corridor A / North Africa & Italy

Hydrogen costs are cost-competitive with all fossil fuelalternatives by 2030, and materially lower by 2040

37

© 2022 European Hydrogen Backbone, all rights reserved

Corridor A / North Africa & Italy

SUPPLY COSTS & COST-COMPETITIVENESS

Corridor A / North Africa & Italy

Applying cost reduction levers to the Tunisia-to-Germany case study
lowers delivery costs by 26% keeping hydrogen cost-competitive

35

SUPPLYCOSTS& COST-COMPETITIVENESS
Hydrogen Production
Cost
Range
[2040]¹, ², ³

3.0

SUPPLY COSTS & COST-COMPETITIVENESS / CASE STUDY

Corridor A / North Africa & Italy

By 2040, hydrogen supply options increase and scale upeading to production costs ranging from 1.4 to 2.8 €/kg

© 2022 European Hydrogen Backbone, all rights reserved

SUPPLY COSTS & COST-COMPETITIVENESS

Af
ric
a

Content
Material

Hydrogen production cost

G
er
m
an
y
Hu
ng
ar
y

Key Questions
Answered

33

SUPPLY COSTS & COST-COMPETITIVENESS

Corridor A / North Africa & Southern Europe

In 2030, the corridor offers access to hydrogenproduction ranging in costs from 2.1 to 3.8 €/kg

34

Hydrogen Production Cost Range [2030]¹, ², ³

Ita
ly,
Slo
va
kia

G
er
m
an
y

Af
ric
a
N
or
th

4.0

Cost range (€/kg)

Au
str
ia

Levelised cost of hydrogen production (€/kg) and Supply per country (TWh)

3.8

3.5
3.0
2.5
2.0
1.5
1.0
0.5
0.0
0

10
Imports
Blue hydrogen

20
Wind offshore
Wind onshore

30
Solar PV
Grid-connected

40

50

60

70

80

90

Case study (see next slide)1 Cost curves are based on a bottom-up estimate of supply volumes per country and hydrogen production type. No transport or storage / firming cost are included.
2 Dedicated hydrogen production costs are based on renewable technology and electrolyser costs, and country-specific capacity factors and discount rates.
3 Grid-connected hydrogen production costs are determined based on costs of a mix of dedicated green hydrogen (solar, onshore wind, offshore wind) and adjusted for grid-connection costs.

100

2030
High
Low

© 2022 European Hydrogen Backbone, all rights reserved

2.1

SUPPLY COSTS & COST-COMPETITIVENESS

Corridor A / North Africa & Southern Europe

By 2040, hydrogen supply options increase and scale up
leading to production costs ranging from 1.4 to 2.8 €/kg

35

Hydrogen Production Cost Range [2040]¹, ², ³

Cr
oa
tia

G
er
m
an
y

G
er
m
an
y

G
er
m
an
y

Cost range (€/kg)

Slo
I
va taly
kia
,I
tal
y

3.0

G
er
m
an
y
Hu
ng
ar
y

N
or
th

It a
ly

Af
ric
a

Levelised cost of hydrogen production (€/kg) and Supply per country (TWh)

2.8

2.5
2.0

1.4

1.0
0.5
0
0

20
Imports
Blue hydrogen

1-3 See previous slide

40

60
Wind offshore
Wind onshore

80

100

120

Solar PV
Grid-connected

140

160

180

Case study (see next slide)

200

220

240

260

280

300

320

340

2040
High
Low

© 2022 European Hydrogen Backbone, all rights reserved

1.5

SUPPLY COSTS & COST-COMPETITIVENESS / CASE STUDY

Corridor A / North Africa & Southern Europe

Hydrogen delivered costs, including transport and storage
costs, can be kept low by applying cost reduction levers
analysis assesses a case study of hydrogen supply from Tunisia to
1 Thisindustrial offtakers in southern Germany to explore how the costs of firmhydrogen delivery can be lowered.

assess the full cost of firm delivery to Germany, transport and storage
2 To
costs are added to the cost of hydrogen production from Tunisia.

3

4

Transport
Costs+

Storage
Costs=

Corridor Case
Study Route

Pipelines
Repurposed
New
Import / Export
SubseaDelivered
Costs

Several cost reduction levers can be applied to lower firm delivery
costs, including optimised system operation, battery storage use, cost ofcapital reductions, among others.

These cost reduction levers achieve sufficient cost savings tokeep firm hydrogen delivery costs low and cost-competitive.

© 2022 European Hydrogen Backbone, all rights reserved

Production
Costs

+

36

SUPPLY COSTS & COST-COMPETITIVENESS / CASE STUDY

Corridor A / North Africa & Southern Europe

Applying cost reduction levers to the Tunisia-to-Germany case study
lowers delivery costs by 26% keeping hydrogen cost-competitive
Cost of Hydrogen Delivered (€/kg) in 2030¹, ², ³
Baseline Costs

Cost reduction levers applied tocase study of hydrogen transport
from Tunisia to Germany enable
firm delivery costs to be reduced
significantly.

Cost Reductions Levers

-27%
1.1

3.3

0.4
0.1

0.1

– In 2030 (shown on the left),the cost of delivered hydrogencan be lowered by 27% (2.4 vs.
3.3 €/kg).

0.3
2.4

2.1

– In 2040, hydrogen delivered
costs can be reduced by 44%(1.4 vs. 2.5 €/kg).

Transport &firming cost

Cost of H₂delivered

Optimisedsystem sizing

Battery storage
operation

Powerelectronics
savings

Reduced costof capital

Optimised costof H₂ delivered(€/kg)

Transport costs are based on several parameters including the type of pipeline (repurposed vs. new), transport distance and full-load-hour production on that pipeline. Firming costs are based on
additional storage cost required to deliver hydrogen at the equivalent of 8,000 full-load hours.
2 Optimised system sizing refers to right-sizing of solar PV and electrolyser capacity to increase full load hours. Similarly, battery storage operation enables an increase in the full load hours. Power
electronics savings refers to the removal of the inverter of the solar PV modules to reduce system cost. Reduced cost of capital refers to the use of foreign investment to reduce the WACC from 8 to 6%.
3 In some instances, cost reduction levers may result in cost increases for certain cost-components. For example, an increase in production costs at the same time as a decrease in firming costs. These cost
increases and decreases can result in connection lines that do not directly connect one step to the next.
1

Transport
Firming
Production

Delivered Costs (€/kg)(before and after cost levers)
2030

2040

Before costs lever

3.3

2.5

After costs lever

2.4

1.4

© 2022 European Hydrogen Backbone, all rights reserved

Baseline costsof H₂ production(€/kg)

37

SUPPLY COSTS & COST-COMPETITIVENESS

Corridor A / North Africa & Southern Europe

Hydrogen costs are cost-competitive with all fossil fuelalternatives by 2030, and materially lower by 2040
2040

Production
costs
€/MWh

114

Cost of fossil
fuel alternatives

Production
costs

Cost of fossil
fuel alternatives€/MWh89‒115(=3.8 €/kg)

Fuel cost
uncertainty

84
59‒73

63

63‒69

H₂ production
cost-range
Higher Cost H₂Lower Cost H₂

Case study
Deliveredcost of H₂
2.4 €/kg

NaturalGas
Fuel cost
CO₂ cost

Steam
Coal

Oil

85‒88

(=2.8 €/kg)

83‒95
Case study
Deliveredcost of H₂
1.4 €/kg

62‒69

72 €/MWh(=2.1 €/kg)

By 2030, the low range of hydro­gen
production costs are competitive
with natural gas and coal, andlower than oil alternatives.

42

42 €/MWh(=1.4 €/kg)

H₂ production
cost-range

Natural
Gas

Steam
Coal

Oil

Fuel uncertain

Note: Prices for fossil alternatives (2030/2040): Natural gas (pre-invasion): 28/13 [€/MWh], Coal: 123/5.6 [€/MWh], Oil: 52/24 [€/MWh]. Natural gas price levels are based on market conditions before Russia’s invasion of Ukraine. While natural gas prices
have skyrocketed since, there remains significant uncertainty on near- and medium-term European price trends and supply options. As a result, our analysis adopts the IEA’s Outlook 2021 price forecast pre-invasion developed pre-invasion. Prices in 2040
are significantly lower than in 2030 because of demand-supply conditions. By 2040, decreased demand for fossil fuels would lower prices. [Source: International Energy Agency, Outlook 2021 (IEA)] and fuel-cost uncertainty is shown with +50% range]

By 2040, the low range ofhydrogen costs are materiallylower than all fossil alternatives,
while the medium-to-high range
are cost competitive.
Hydrogen delivered costs from theTunisia-Germany case study arecompetitive to natural gas in 2030
(22% higher) and lower in 2040
(32% lower).
Natural gas prices are still
uncertain due to recent pricespike as a result of the Russian
invasion of Ukraine.
Note: For comparison purposes, cost of H₂ has been converted from“per kg” to “per MWh”
– 1 €/kg = 30 €/MWh (based on LHV of 33.3 kWh/kg)
Competitiveness of hydrogen highly dependant on CO₂-prices as they
make up a significant part of fossil fuel costs.
– CO₂ price 2030: 130 €/t– CO₂ price 2040: 205 €/t© 2022 European Hydrogen Backbone, all rights reserved

2030

38

CORRIDOR A© 2022 European Hydrogen Backbone,
all rights reserved

North Africa& Southern Europe

39

Agenda
1. Corridor Summary
2. Hydrogen Demand & Supply
3. Supply Costs & Cost-Competitiveness4. National Strategies & Regulation
5. Actions Needed

NATIONAL STRATEGIES & REGULATIONSCorridor A / North Africa & Southern Europe

Most countries have developed, or are developing, national strategies. Moving
forward, the development of regulation is key to enable infrastructure investment.
Highlights

PreRePowerEU
targets²

National Hydrogen strategy (NHS)

Network regulation & policy

Italy– NHS preliminary. 2% H₂ share at final energy 2030 (20% in 2050) in
transport, industry, refineries, blen.
– 5 GW electrolyser installed until 2030
– Hydrogen valleys / industrial clusters– Public consultation process in relation to pilot projects
to optimise the innovative uses of existing natural gas
transmission and distribution networks

Switzerland– The parliament currently developing national strategy– Explicitly mentioned import strategy for H₂– N/A– Hydrogen strategy is being developed– Energy plan: Industry & heavy duty transport

Slovenia– In NECP is set indicative target to have 10 % of renewable methane orhydrogen in the network (2030)– TSO is obliged to prepare the plan for acceptance of H₂– Foreseen demand sectors: Transport (2030), followed byindustry & buildings (NECP)

Croatia– Foresees demand in industry, buildings, transport and power, with a supply
potential of 1.3 GW electrolysers– N/A– First production site by 2025

Hungary– Production of 36k tons/a (incl. low carbon H₂)– 240 MW of electrolyser capacity– Use to decarbonize industry and transport– Min. 2% volume blending to natural gas grid

– H₂ infrastructure in focus. Funding for storage is available
and blending to natural gas grid is envisioned

Czech Republic– Focus Transport, then energy & chemical industry– Green H₂ production– Import and transit country for H₂– N/A– H₂-Readiness of gas transmission system is urged, due topotential focal role in H₂ transport (south to north and east to
west)

Austria– NHS is still in discussion; known elements are: 1 – 2 GW electrolyser capacity(2030), use in industry– H₂ mixtures of up to 10 % within Austria and 4-5 % on entry/
exit points are allowed– Production of green H₂ is subsidised– Preferred use to decarbonise industry– Focus: Transport sector and underground H₂ storage

Slovakia– H₂ used in the chemicals, petrochemicals, steel and heating industries as wellas in transport– N/A– Use H₂ in industries/areas impossible or not cost-effective todirectly use electricity

Germany– National production & import focus due to supply gap– In place since 2020, currently reviewed towards increasing its ambition– 10 GW (2030) electrolyser in coalition plans– H₂ network potentially opt-in regulated and vertically unbundled– First rules and standards for high pressure pipelines areformulated– Strong focus on international cooperation to ensuresufficient supply– National funding– Focus on transport sector and hydrogenvalleys for demand (industry) and production– Funding mainly to increase production of H₂– 99% of infrastructure is ready to transport H₂

5.0

0.1

0.5

9

General funding
SupplyNetwork
Demand© 2022 European Hydrogen Backbone, all rights reserved

Note: Sequencing of countries follows the general corridor direction but does not represent the hydrogen flows.
1 Cumulative public funding amount by the respective state until 2030
2 Strategies and funding is under evaluation of meeting latest targets

Funding¹ (bn €)40

CORRIDOR A© 2022 European Hydrogen Backbone,
all rights reserved

North Africa& Southern Europe

41

Agenda
1. Corridor Summary
2. Hydrogen Demand & Supply
3. Supply Costs & Cost-Competitiveness4. National Strategies & Regulation
5. Actions Needed

ACTIONS NEEDEDCorridor A / North Africa & Southern Europe

This corridor plays a fundamental role in achieving
a European backbone by 2040
The need for this corridor– The development of this corridor ensures access to abundant, low-costhydrogen supply from Italy and Tunisia by 2030, and by 2040 additional
supply from Algeria (via Tunisia) and from Central and South-Central Europe.
– The decarbonisation of the largest hydrogen demand centers along
this corridor – in Italy, Central Europe and Germany – is dependent on
the buildout of this corridor by 2030, and its expansion towards 2040.

42

2040
Pipelines
Repurposed
New
Import / Export
SubseaDemand per sector

40 / 30 / 20 / 10 / 1 TWh– The buildout of this corridor by 2030 requires national governments totake clear and concrete actions across.
– This includes actions associated with infrastructure development andplanning, the development of cross-national initiatives and securing
access to early funding and long-term, low-cost financing.

Efuels production
Industrial energy
Industrial feedstock
Power
Supply in MWh/km²<1
1 – 2525 – 100
100 – 250
250 – 500
> 500
Storages
Salt cavern
Aquifer
Depleted field
Rock cavern
Other items
Existing or planned
gas-import-terminal
Energy island forH₂ production© 2022 European Hydrogen Backbone, all rights reserved

Actions required

ACTIONS NEEDEDCorridor A / North Africa & Southern Europe

To ensure the development of this corridor by 2030,
there is a need for clear and concrete actions

Unlock financing tofast-track hydrogen
infrastructure deploy­ment by applying regional
regulatory flexibility andother pragmatic financing
solutions (including
incentivizing the adoptionof hydrogen by demand
sectors)

Simplify and shorten
planning and permitting
procedures for renewableenergy and hydrogen
infrastructure projects.

However, speed will be of essence!

Intensify energy partner­
ships with exporting,non-EHB countries
like Algeria and Tunisia,
and providing financing
support to reduce theircost of capital

Facilitate integrated
energy system planningof hydrogen, naturalgas, and electricity
infrastructure supporting
the accelerated deploy­ment and integrationof renewable energy
resources© 2022 European Hydrogen Backbone, all rights reserved

Fostering developmentof new and repurposedhydrogen infrastructure,for example, by unbund­ling rules facilitating theefficient use of TSO
expertise and services andby allowing the adoptionof different vertical un­bund­ling models in theEU, as is the case withnatural gas

43© 2022 European Hydrogen Backbone,
all rights reserved

TABLE OF CONTENTS

1. Executive Summary
2. Five emerging supply corridors
Corridor A: North Africa & Southern Europe
Corridor B: Southwest Europe & North Africa
Corridor C: North Sea
Corridor D: Nordic and Baltic regions
Corridor E: East and South-East Europe

3. Detailed methodology

44

CORRIDOR B© 2022 European Hydrogen Backbone,
all rights reserved

Southwest Europe& North Africa

45

Agenda
1. Corridor Summary
2. Hydrogen Demand & Supply
3. Supply Costs & Cost-Competitiveness4. National Strategies & Regulation
5. Actions Needed

CORRIDOR B / FACTSHEET

46

Corridor emerges in Southwest Europe providing access to low-costhydrogen supply from the Iberian peninsula, and potentially Morocco.

Portugal
Spain
FranceBelgium
Luxembourg
Germany

Drivers &Opportunities

Major driver of development is the need to meet hydrogen demand fromindustry, transport and power in the Iberian peninsula, France and Germany.
Key opportunities include the development of a new Spain-France interconnector
and underground storage in France, and access to imports from Morocco.

Hydrogen Supply& Decarbonization
Potential

H₂ supply potential¹

569 TWh(TWh/year)
164 TWh
2030

Supply Costs& CostCompetitiveness

Cost of H₂
production¹

Actions Needed

1(MtCO₂/year vs. 2019;% reduction)-73 Mt(7%)

2040-211 Mt(21%)

Cost competitiveness²
1.4–2.7

2030

2030

2040

2.0–3.8(€/kg of H₂)

Emissions
Reductions

2040

Hydrogendelivered pricevs.
natural gas pricehigh/low,(€/MWh)

62

73

69

59

62

2030

2040

45

– Fostering development of new and repurposed hydrogen infrastructure– Unlock financing to fast-track hydrogen infrastructure deployment– Simplify and shorten planning and permitting procedures– Facilitate integrated energy system planning of hydrogen, natural gas, andelectricity infrastructure– Intensify energy partnerships with exporting, non-EHB countries like Morocco and Algeria

Figures reported reflect outputs for all countries included in the corridor. Even if a country is only partially in the corridor, results for the full country are included(e.g., supply potential and costs, demand, transmission network length).
2 Savings are based on the corridor’s case study of hydrogen delivered in 2030 and 2040. The cost of natural gas includes CO₂ prices. Refer to Subsection 3 (Supply Costs & Cost-Competitiveness)© 2022 European Hydrogen Backbone, all rights reserved

Southwest Europe& North Africa

Corridor B / Southwest Europe & North Africa

CORRIDOR B© 2022 European Hydrogen Backbone,
all rights reserved

Southwest Europe& North Africa

47

Agenda
1. Corridor Summary
2. Hydrogen Demand & Supply
3. Supply Costs & Cost-Competitiveness4. National Strategies & Regulation
5. Actions Needed

CORRIDOR SUMMARY

Corridor B / Southwest Europe & North Africa

Drivers &Opportunities– The major driver behind the development of this corridor is the
adoption of hydrogen associated with the early decarbonisationof the industry, transport and power in the Iberian Peninsula,
France and Germany. The speed of hydrogen adoption in theseregions will accelerate driven by increasing CO₂ prices in the EU
and the RePowerEU ambitions to replace natural gas consumption.
– The corridor offers access to low-cost, renewable production
from the Iberian peninsula, currently the source of Europe’s
lowest renewable auction prices. In the longer term, this corridor
may also provide access to hydrogen imports from Morocco
and potentially Algeria.

– A major opportunity of the corridor is the potential development of a
new interconnection between Spain and France through the East
Pyrenees. The development of this interconnection would allow bothcountries to benefit from the complementary nature of low-cost, highvolume Spanish and Portuguese hydrogen production and French
underground storage sites to help provide stable supply for off-takers
in the region. This development of this new interconnection would in turnrequire infrastructure reinforcements along the corridor.
– A key longer-term opportunity is the potential repurposing of thecurrently-underutilised, Maghreb-Europe subsea interconnector
to enable low-cost hydrogen supply from Morocco and Algeria.
– Recently, RePowerEU identified the development of a new subsea
pipeline connecting Spain and Italy, expected to be available forhydrogen transport by 2030.
– The corridor would be stood up by 2030, covering 10,000 km oflarge-scale hydrogen pipelines across all countries of the corridor, of
which approximately 60% will be repurposed pipelines.

Hydrogen
Demand& Supply– Total hydrogen demand in the corridor reaches 200 TWh by
2030, increasing substantially to ~720 TWh by 2040. Up to2030, the major demand sector is industry, with hydrogen being
used as feedstock and for energy needs. From 2040 onwards,
most hydrogen demand is for e-fuels production and the power
sector.

– Hydrogen adoption across all countries of the corridors enables anemissions reduction of c.300 MtCO₂/yr. by 2050, equivalent to a
29% emissions reduction.
– The corridor enables access to hydrogen supply potential of ~160 TWh
by 2030, increasing to ~570 TWh by 2040. Major sources of supply
include green hydrogen from the Iberian Peninsula and France by 2030,
with a potential role for Moroccan imports by 2040.

© 2022 European Hydrogen Backbone, all rights reserved

Corridor offers access to low-cost hydrogen supply from the
Iberian peninsula to demand centers in France and Germany

48

CORRIDOR SUMMARY

Corridor B / Southwest Europe & North Africa

Costs & CostCompeti­tiveness– By 2030, the corridor provides access to hydrogen production
costs ranging from a production cost of 2.0 to 3.8 €/kg. By
2040, as supply options increase and technology costs decrease,hydrogen production costs decrease to 1.4 to 2.7 €/kg.
– In the long term, this corridor’s lowest-cost supply options areimports from Morocco and solar PV hydrogen from Spain andPortugal.

– Based on a case-study of hydrogen supply and transport from
Spain to Germany, the cost of delivered hydrogen – inclusive oftransport and firming costs – can be lowered to achieve cost levels
comparable to production costs. Lowering delivery costs can beachieved through various cost levers including optimised operation of
the system and cost of capital reductions.

National Strategies& Regulation– National hydrogen strategies have been developed by all
countries in the corridor, providing clear direction and supply
targets.

– In select countries, substantial funding has been allocated tosupport the development of the hydrogen market including funding
for gas network infrastructure.

Actions Needed

Low-cost H₂ supply/demand, but for realization and build-out of thiscorridor until 2030, key needs for action has been identified:– Fostering development of new and repurposed hydrogen
infrastructure.
– Unlock financing to fast-track hydrogen infrastructure
deployment by applying regional regulatory flexibility and otherpragmatic financing solutions.

– Simplify and shorten planning and permitting procedures for thefull value chain of renewable energies and hydrogen infrastructure
projects.
– Establish integrated energy system planning of hydrogen, naturalgas, and electricity infrastructure.
– Intensify energy partnerships with exporting, non-EHB countries
like Morocco and Algeria.

Source: Guidehouse analysis© 2022 European Hydrogen Backbone, all rights reserved

Key needs for action identified to successfully stand up
the hydrogen supply corridor until 2030

49

CORRIDOR B© 2022 European Hydrogen Backbone,
all rights reserved

Southwest Europe& North Africa

50

Agenda
1. Corridor Summary
2. Hydrogen Demand & Supply
3. Supply Costs & Cost-Competitiveness4. National Strategies & Regulation
5. Actions NeededHYDROGEN DEMAND & SUPPLY / SECTION INTRODUCTION

Corridor B / Southwest Europe & North Africa

This section explores the development of hydrogen demand,
supply and transport infrastructure across the corridor

2030
Corridor Snapshot (Supply,
Demand, and Infrastructure)

51

Hydrogen Demand
By 2030, the corridor connects all major industrial clusters from Spain toGermany. From 2030 to 2040, the corridor expands to all demand centersalong its route, increasing demand from 200 to ~720 TWh.

Hydrogen supply

Demand per sector

40 / 30 / 20 / 10 / 1 TWh
Efuels production
Industrial energy
Industrial feedstock
Power
Supply in MWh/km²<1
1 – 2525 – 100
100 – 250
250 – 500
> 500
Storages
Salt cavern
Aquifer
Depleted field
Rock cavern
Other items
Existing or planned
gas-import-terminal
Energy island forH₂ production

In 2030, hydrogen supply is ~160 TWh, of which 65% of supply is fromdedicated green hydrogen. Hydrogen supply increases significantly by 2040,
reaching 570 TWh.
164 TWh (2030)
Grid-based

Dedicated green

Blue

Hydrogen Infrastructure
By 2030, the buildout of pipeline infrastructure across all countries of thecorridor reaches 10,000 km of large-scale pipelines. Corridor benefits from alarge share of repurposed infrastructure.
60% (Repurposed pipelines)

40% (New pipelines)

10,000 km (2030)© 2022 European Hydrogen Backbone, all rights reserved

Pipelines
Repurposed
New
Import / Export
SubseaBy 2030, the corridor enables access to low-cost supply from parts of the
Iberian peninsula. By 2040, the corridor gains access to supply from mostof the peninsula and low-cost imports from Morocco.

HYDROGEN DEMAND & SUPPLYCorridor B / Southwest Europe & North Africa

2030

2040

Pipelines
Repurposed
New
Import / Export
SubseaPipelines
Repurposed
New
Import / Export
SubseaDemand per sector

Demand per sector

40 / 30 / 20 / 10 / 1 TWh

40 / 30 / 20 / 10 / 1 TWh

Efuels production
Industrial energy
Industrial feedstockPower

Efuels production
Industrial energy
Industrial feedstockPower

Storages
Salt cavern
Aquifer
Depleted field
Rock cavern

Storages
Salt cavern
Aquifer
Depleted field
Rock cavern

Other items
Existing or planned
gas-import-terminal
Energy island forH₂ production

Other items
Existing or planned
gas-import-terminal
Energy island forH₂ production© 2022 European Hydrogen Backbone, all rights reserved

Corridor connects substantial hydrogen demand by 2030,
expanding to all major demand centers by 2040

52

HYDROGEN DEMAND & SUPPLYCorridor B / Southwest Europe & North Africa

Hydrogen demand increases rapidly from 2030 to 2040,
with most demand from Germany and Spain
2030

2040

2050

20

28

Hydrogen demand – across all countries of
the corridor – increases significantly from2030 to 2050. Demand reaches 200 TWh by
2030, increasing to roughly 1,100 TWh by 2050.

General H₂ flow

Total demand per country (TWh/y)Portugal

5

Spain

46

156

France

33

97

161

Belgium

25

78

109

Luxembourg

1

Germany

Total

261

3

90

– Up to 2030, most hydrogen demand isdriven by the industrial sector in Spain,
France and Germany with hydrogen being
used as feedstock and for energy needs.
– From 2040 to 2050, most new hydrogen
demand is for e-fuels production and for
power generation.

7

364

200

Hydrogen demand may accelerate andincrease further than forecasted as a resultof additional regulatory measures adopted in
response to the RePowerEU plan.

505

718

Note: Does not include grey hydrogen demand. Numbers represent total demand by country, even if only parts of the country are included in the corridor.

1,071© 2022 European Hydrogen Backbone, all rights reserved

Country53

HYDROGEN DEMAND & SUPPLYCorridor B / Southwest Europe & North Africa

Hydrogen adoption in all countries of the corridor
enables an emissions reduction of 29% by 2050
7%21%

Decarbonisationin Mt CO₂ / year

29 %Hydrogen adoption across all demand
sectors enables an emissions reduction of~300 MtCO₂/yr. by 2050, equivalent to a
29% reduction².

297

300

– Up to 2030, the industrial sector contributes
75% of the total emissions reductions, largely
driven by the decarbonisation of the steel
sector.

250– By 2040, emissions reductions from transport(road, shipping and aviation) increase
substantially and combined with industry,account for 80% of emissions reductions. The
power sector account for the remaining 20%
of reductions.

211
200

150

– By 2050, the transport sector alone accounts
for over 50% of emissions reductions.

100
73
50
IndustryPower
Buildings
Transport

02030© 2022 European Hydrogen Backbone, all rights reserved

2040

2050

1

CO₂-Emissions from countries and sectors included in corridor (1.02 bn t CO₂ / year),
Source: EEA
2 Emissions reductions are calculated compared to the baseline fossil fuel used in eachsectors. For example, emissions reductions associated with the adoption of hydrogen by
the primary steel sector are relative to the use of coal. Similarly, emissions reductions , fore-fuels production are relative to the use of fossil fuels in shipping, aviation and other uses.

© 2022 European Hydrogen Backbone, all rights reserved

Emissions reductions(vs. 2019 emissions¹)

54

HYDROGEN DEMAND & SUPPLYCorridor B / Southwest Europe & North Africa

Corridor enables access to supply from parts of the Iberianpeninsula by 2030, and potentially from North Africa, by 2040

Pipelines
Repurposed
New
Import / Export
SubseaSupply in MWh/km²<1
1 – 2525 – 100
100 – 250
250 – 500
> 500
Storages
Salt cavern
Aquifer
Depleted field
Rock cavern
Other items
Existing or planned
gas-import-terminal
Energy island forH₂ production
Total hydrogen supply shown per NUTS-2 region. MWh adjusted by the area of each NUTS-2 region in km².
* Note: Supply numbers do not include grey hydrogen.

2040*

Pipelines
Repurposed
New
Import / Export
SubseaSupply in MWh/km²<1
1 – 2525 – 100
100 – 250
250 – 500
> 500
Storages
Salt cavern
Aquifer
Depleted field
Rock cavern
Other items
Existing or planned
gas-import-terminal
Energy island forH₂ production© 2022 European Hydrogen Backbone, all rights reserved

2030*

55

HYDROGEN DEMAND & SUPPLYCorridor B / Southwest Europe & North Africa

Hydrogen supply increases significantly from 2030 to 2040,
largely driven by green hydrogen supply from Spain
2030
SupplyImports²(Morocco)

General H₂ flow

Portugal

Net¹

15

Net¹

12

1

25 8
15

5

5

-4

6

53

20

Germany

81

107

23 34

-35

115

11

2

113
359 15

16
8 10
-50

8

-3

13

150 24

-98

11

-7

0

-261

21

488 28

72

45

68

0

-75
15

35

2

94

-1

0

Net¹

115

213

8

Supply46

44

Luxembourg

Total

Supply46

066

Belgium

2050

0

Spain

France

2040

-313
165

53

-149

1 Net represents excess supply after subtracting demand
2 No imports are reported for Morocco in 2030 as the interconnection with Morocco would likely not be available until after 2030.
3 Blue hydrogen supply volumes will be subject to the evolution of gas markets and the development of low carbon hydrogen regulation in different
country. As a result, some countries may have additional blue hydrogen supply which could be used to satisfy local demand.
4 Grid-based green hydrogen is estimated based on the oversupply of electricity (demand less supply) in each country of the corridor from 2030 to 2050.

27
861

Dedicated green
Blue
Grid-based
2050 technical potential

78

-132

Hydrogen supply includes a mix of supply
options including grid-based green hydrogen³,
dedicated green hydrogen, and bluehydrogen⁴.
By 2030, hydrogen supply reaches~160 TWh, largely from dedicated greenhydrogen and grid-based hydrogen.
By 2040, hydrogen supply increases
substantially to ~570 TWh, of which roughly
85% is from dedicated green hydrogen. The
remaining 15% is from grid-based and bluehydrogen supply. Grid-based supply increases
slightly from 2030 due to the increasing
decarbonization of the electricity grid mix.
By 2050, hydrogen supply increases further
to ~1,000 TWh. Dedicated green supply
continues to account for the largest share at
roughly 90%. Blue hydrogen supply is notincluded in 2050 due to assumed target of zero
emissions and de-fossilisation of Europe by 2050.

Note: Hydrogen supply volumes do not include hydrogen imports by ship.

© 2022 European Hydrogen Backbone, all rights reserved

Country56

HYDROGEN DEMAND & SUPPLYCorridor B / Southwest Europe & North Africa

Morocco may become a potential source of hydrogen
imports to Europe by 2040, and potentially Algeria

MarketAttractivenessMarketBarriers– North Africa connects to Spain through Morocco via the Maghred-Europe
offshore pipeline, currently used for natural gas exports to Europe. Morocco’s
national hydrogen roadmap identified the potential to repurpose the
Maghreb-Europe pipeline for hydrogen export¹.
– Morocco is in currently in preparatory stages ahead of upgrades to its
existing port infrastructure for LNG imports.
– Hydrogen export potential via this corridor focuses primarily on hydrogen
supply from Morocco, however, there is also potential for hydrogen exports
from Algeria to contribute to this corridor.
– Abundant renewable energy potential, particularly solar PV– Partnerships: Hydrogen cooperation agreement with Germany (June 2020) to
develop the hydrogen sector in Morocco².
– Market developments:– HEVO Ammonia: 183k t/yr. of green ammonia by 2026 (Vitol, Fusion
Fuel)³– Cluster Maroc Hydrogen: Organization aiming to mediate between the
different market actors to create a hydrogen cluster in Morocco.

Hydrogen supply potential (TWh)Morocco only
Morocco

115

46

–
2030

2040

2050

– Limited transparency and slow decision-making and procedures when
dealing with Government entities– Recent political disputes with neighboring countries (Algeria) and international
partners (Germany)

Algeria
1 MEM – Green Hydrogen Roadmap (2021)
2 HEVO Ammonia (https://energy-utilities.com/fusion-fuel-and-ccc-to-develop-850m-morocco-green-news113290.html; and stakeholder interviews)
3 Due to political tension as a result of the Western Sahara sovereignty, Morocco halted the agreement in 2021, however, it is currently looking torestore ties as of 2022.

Note:
Supply potential based on Reference scenario from National Green
Hydrogen Roadmap for Morocco¹

Note:
Hydrogen supply from Algeria has not been incorporate into the supply
figures of this corridor. Rather, it is reported under Corridor A.

© 2022 European Hydrogen Backbone, all rights reservedState ofGas Infrastructure

57

CORRIDOR B© 2022 European Hydrogen Backbone,
all rights reserved

Southwest Europe& North Africa

58

Agenda
1. Corridor Summary
2. Hydrogen Demand & Supply
3. Supply Costs & Cost-Competitiveness4. National Strategies & Regulation
5. Actions Needed

SUPPLY COSTS & COST-COMPETITIVENESS / SECTION INTRODUCTION

Corridor B / Southwest Europe & North Africa

This section explores corridor’s hydrogen production and delivery
costs and their cost-competitiveness with fossil-fuel alternatives
Hydrogen delivered costs

Comparison with fossil alternatives

What hydrogen production costs does thecorridor provide access to by 2030 and by
2040?

What are the full costs of deliveredhydrogen accounting for transport andstorage costs?
What cost levers are available to lower thecost of delivery costs?

How cost-competitive are hydrogen costs
compare to fossil fuel alternatives?

Corridor B / Southwest Europe & North Africa

Baseline Costs

5.2

0.8

2.7
Levelised cost of hydrogen production (€/kg) and Supply per country (TWh)2.5

Cost range (€/kg) – 2030

Large uncertainty on
blue hydrogen costs 4

3.8

3.5

0.5

3.0

0
0

50
Imports
Blue hydrogen

2.5
100

150

2.0

Wind offshore
Wind onshore

1.5

200

Solar PV
Grid-connected

250

300

350

400

450

500

550

2040

Case study (see next slide)

High
Low

2.0

1.0
1-4 See previous slide

0.5
0.0
0

20
Imports
Blue hydrogen

40
Wind offshore
Wind onshore

60
Solar PV
Grid-connected

80

100

120

140

Case study (see next slide)1 Cost curves are based on a bottom-up estimate of supply volumes per country and hydrogen production type. No transport or storage / firming cost are included.
2 Dedicated hydrogen production costs are based on renewable technology and electrolyser costs, and country-specific capacity factors and discount rates.
3 Grid-connected hydrogen production costs are determined based on costs of a mix of dedicated green hydrogen (solar, onshore wind, offshore wind) and adjusted
for grid-connection costs.

160

180

2030
High
Low

4 Blue hydrogen costs are subject to significant uncertainty in natural gas prices. Our analysis adopts natural gas price levels based on market conditions
before Russia’s invasion of Ukraine. While natural gas prices have skyrocketed since, there remains significant uncertainty on near- and medium-term
European price trends and supply options. As a result, our analysis adopts the IEA’s Outlook 2021 price forecast developed pre-invasion, with costs of 28 €/MWh in 2030 and 13 €/MWh in 2040.

Baseline costsof H₂ production(€/kg)© 2022 European Hydrogen Backbone, all rights reserved

1.4

4.0

1.0

© 2022 European Hydrogen Backbone, all rights reserved

Po
rtu
ga
l

Sp
ain

G
er
m
an
y
Be
lg
ium

Sp
ain
Fr
an
ce
Fr
an
ce
Fr
an
ce

Sp
ain

Po
rtu
ga
Fr l
an
ce

1.5

0.2

2.5

Fr
a
Be nce
lg ,
ium

2.0

– Corridor provides access to hydrogenproduction costs of 2.0–3.8 €/kg by
2030– The scale-up of hydrogen supply leads toreductions to 1.4–2.7 €/kg in 2040

Transport &firming cost

Cost of H₂delivered

Optimisedsystem sizing

Battery storage
operation

€/MWh

Power
electronics
savings

0.3

Reduced costof capital– In 2040, hydrogen delivered
costs are also lower than pro­duction costs (1.5 vs. 1.6 €/kg).

2.1

Optimised costof H₂ delivered(€/kg)

1 Transport costs are based on several parameters including the type of pipeline (repurposed vs. new), transport distance and full-load-hour production on that pipeline. Firming costs are based on
additional storage cost required to deliver hydrogen at the equivalent of 8,000 full-load hours.
2 Optimised system sizing refers to right-sizing of solar PV and electrolyser capacity to increase full load hours. Similarly, battery storage operation enables an increase in the full load hours. Power
electronics savings refers to the removal of the inverter of the solar PV modules to reduce system cost. Reduced cost of capital refers to the use of foreign investment to reduce the WACC from 8 to 6%.
3 In some instances, cost reduction levers may result in cost increases for certain cost-components. For example, an increase in production costs at the same time as a decrease in firming costs. These
cost increases and decreases can result in connection lines that do not directly connect one step to the next.

Transport
Firming
Production

Production vs. Delivered Costs(€/kg)
2030

2040

Production Costs

2.5

1.6

Delivered Costs

2.1

1.5

114

Cost of fossil
fuel alternatives

Cost of H₂
production€/MWh89‒115(=3.8 €/kg)

Cost of fossil
fuel alternatives

Fuel cost
uncertainty

85‒88
59‒73

62‒69

66

(=2.7 €/kg)

42(=1.4 €/kg)

83‒95
Case study
Deliveredcost of H₂
1.5 €/kg

62‒69

62 €/MWh60– Several cost reduction levers can beapplied to lower the costs of hydrogendelivery.
– For the Spain-to-Germany case study,
these levers achieve delivery costs thatare low and cost-competitive.

64

2040

Cost of H₂
production– In 2030 (shown below), cost
reductions allow the cost ofhydrogen delivered to be
16% lower than hydrogen pro­duction costs (2.1 vs. 2.5 €/kg).

1.7

Hydrogen Production Cost Range [2030]¹, ², ³

2030

Cost reduction levers enableshydrogen delivered costs toremain on par, if not lower, thanhydrogen production costs bothin 2030 and 2040.

Cost Reductions Levers

-59 %
2.7

3.0

Key Findings& Results

Cost of Hydrogen Delivered (€/kg) in 2030¹, ², ³

60

Po
rtu
ga
l

Sp
ain

Fr
an
ce

Fr
an
ce
Fr
a
Be nce
lg ,
ium
4
G
er
m
an
y
G
er
m
an
y
Sp
G ain
er
m
an
y

M
3.5

Sp
G ain
er
m
an
y
Fr
an
ce

InLevelised
2030,
the corridor offers access to hydrogen production Cost range (€/kg)
cost of hydrogen production (€/kg) and Supply per country (TWh)ranging in costs from 2.0 to 3.8 €/kg

Corridor B / Southwest Europe & North Africa

Hydrogen costs are cost-competitive with all fossil fuelalternatives by 2030, and significantly lower by 2040

63(=2.0 €/kg)

Case study
Deliveredcost of H₂
2.1 €/kg

H₂ productioncost­range
Higher Cost H₂Lower Cost H₂NaturalGas
Fuel cost
CO₂ cost

Steam
Coal

Oil

45 €/MWh

H₂ productioncost­range

Natural
Gas

Steam
Coal

Oil

Fuel uncertain

Note: Prices for fossil alternatives (2030/2040): Natural gas (pre-invasion): 28/13 [€/MWh], Coal: 123/5.6 [€/MWh], Oil: 52/24 [€/MWh]. Natural gas prices levels are based on market conditions before Russia’s invasion of Ukraine. While natural gas prices
have skyrocketed since, there remains significant uncertainty on near- and medium-term European price trends and supply options. As a result, our analysis adopts the IEA’s Outlook 2021 price forecast pre-invasion developed pre-invasion. Prices in 2040
are significantly lower than in 2030 because of demand-supply conditions. By 2040, decreased demand for fossil fuels would lower prices. [Source: International Energy Agency, Outlook 2021 (IEA)] and fuel-cost uncertainty is shown with +50% range]– By 2030, the low range ofhydrogen production costs arecompetitive with natural gas
and coal, and lower than oilalternatives.
– By 2040, the low rangeof hydrogen costs arematerially lower than all
fossil alternatives, while themedium­to­high range are costcompetitive.
– Hydrogen delivered costs fromthe Spain­Germany case study
are competitive to natural gas in
2030 (5% higher) and lower in
2040 (28% lower).
– Natural gas prices are still
uncertain due to recent pricespike as a result of the Russian
invasion of Ukraine
Note: For comparison purposes, cost of H₂ has been converted from“per kg” to “per MWh”
– 1 €/kg = 30 €/MWh (based on LHV of 33.3 kWh/kg)
Competitiveness of hydrogen highly dependent on CO₂-prices as they
will make up alternatives costs major part.
– CO₂ price 2030: 130 €/t– CO₂ price 2040: 205 €/t– Hydrogen costs are competitive withfossil fuel alternatives by 2030, andlower by 2040.
– Fossil fuel costs are subject to significant
uncertainty.

© 2022 European Hydrogen Backbone, all rights reserved

SUPPLYCOSTS& COST-COMPETITIVENESS
Hydrogen Production
Cost
Range
[2040]¹, ², ³

SUPPLY COSTS & COST-COMPETITIVENESS

Corridor B / Southwest Europe & North Africa

Applying cost reduction levers to the Spain-to-Germany case study
lowers delivery costs significantly keeping hydrogen cost-competitive61© 2022 European Hydrogen Backbone, all rights reserved

SUPPLY COSTS & COST-COMPETITIVENESS / CASE STUDY

Corridor B / Southwest Europe & North Africa

By 2040, hydrogen supply options increase and scale up
leading to production costs ranging from 1.4 to 2.7 €/kg

© 2022 European Hydrogen Backbone, all rights reserved

SUPPLY COSTS & COST-COMPETITIVENESS

or
oc
co

Content
Material

Hydrogen production cost

Po
rtu
& gal
Sp
ain

Key Questions
Answered

59

SUPPLY COSTS & COST-COMPETITIVENESS

Corridor B / Southwest Europe & North Africa

In 2030, the corridor offers access to hydrogen production
ranging in costs from 2.0 to 3.8 €/kg

60

Hydrogen Production Cost Range [2030]¹, ², ³
Levelised cost of hydrogen production (€/kg) and Supply per country (TWh)Cost range (€/kg) – 2030

Po
rtu
ga
l

Sp
ain

G
er
m
an
y
Be
lg
ium

Sp
ain
Fr
an
ce
Fr
an
ce
Fr
an
ce

Sp
ain

Po
rtu
ga
Fr l
an
ce

Fr
a
Be ncelg ,iumLarge uncertainty on
blue hydrogen costs 4

3.8

4.0
3.5
3.0
2.5
2.0
1.5
1.0
0.5
0.0
0

20
Imports
Blue hydrogen

40
Wind offshore
Wind onshore

60
Solar PV
Grid-connected

80

100

120

140

Case study (see next slide)1 Cost curves are based on a bottom-up estimate of supply volumes per country and hydrogen production type. No transport or storage / firming cost are included.
2 Dedicated hydrogen production costs are based on renewable technology and electrolyser costs, and country-specific capacity factors and discount rates.
3 Grid-connected hydrogen production costs are determined based on costs of a mix of dedicated green hydrogen (solar, onshore wind, offshore wind) and adjusted
for grid-connection costs.

160

180

2030
High
Low

4 Blue hydrogen costs are subject to significant uncertainty in natural gas prices. Our analysis adopts natural gas price levels based on market conditions
before Russia’s invasion of Ukraine. While natural gas prices have skyrocketed since, there remains significant uncertainty on near- and medium-term
European price trends and supply options. As a result, our analysis adopts the IEA’s Outlook 2021 price forecast developed pre-invasion, with costs of 28 €/MWh in 2030 and 13 €/MWh in 2040.

© 2022 European Hydrogen Backbone, all rights reserved

2.0

SUPPLY COSTS & COST-COMPETITIVENESS

Corridor B / Southwest Europe & North Africa

By 2040, hydrogen supply options increase and scale up
leading to production costs ranging from 1.4 to 2.7 €/kg

61

Hydrogen Production Cost Range [2040]¹, ², ³

Sp
ain

Fr
an
ce

Po
rtu
ga
l

Cost range (€/kg)

Fr
an
ce
Fr
a
Be nce
lg ,
ium
4
G
er
m
an
y
G
er
m
an
y
Sp
G ain
er
m
an
y

M

or
oc
co

Po
rtu
& gal
Sp
ain

Sp
G ain
er
m
an
y
Fr
an
ce

Levelised cost of hydrogen production (€/kg) and Supply per country (TWh)

3.5
3.0

2.7

2.5
2.0

1.4

1.0
0.5
0
0

50
Imports
Blue hydrogen

1-4 See previous slide

100
Wind offshore
Wind onshore

150

200

Solar PV
Grid-connected

250

300

Case study (see next slide)

350

400

450

500

550

2040
High
Low

© 2022 European Hydrogen Backbone, all rights reserved

1.5

SUPPLY COSTS & COST-COMPETITIVENESS / CASE STUDY

Corridor B / Southwest Europe & North Africa

Corridor offers access to low-cost hydrogen supply from the
Iberian peninsula to demand centers in France and Germany
analysis assesses a case study of hydrogen supply from southern
1 Our
Spain to industrial offtakers in Germany to explore how hydrogendelivered costs can be lowered.

assess the full cost of hydrogen delivery to Germany, transport
2 To
and storage costs are added to the cost of hydrogen production
from Spain.

Transport
Costs+

Storage
Costs=

Pipelines
Repurposed
New
Import / Export
SubseaDelivered
Costs

cost reduction levers are applied to lower firm delivery costs,
3 Several
including optimised system operation, battery storage use, cost of capital
reductions, among others.

4

Corridor Case
Study Route

These cost reduction levers achieve sufficient cost savings tokeep firm hydrogen delivery costs low and cost-competitive.

© 2022 European Hydrogen Backbone, all rights reserved

Production
Costs

+

62

SUPPLY COSTS & COST-COMPETITIVENESS / CASE STUDY

Corridor B / Southwest Europe & North Africa

Applying cost reduction levers to the Spain-to-Germany case study
lowers delivery costs significantly keeping hydrogen cost-competitive
Cost of Hydrogen Delivered (€/kg) in 2030¹, ², ³

Cost reduction levers applied tocase study of hydrogen transport
from Spain to Germany enable
firm delivery costs to be
reduced significantly.

Cost Reductions Levers

-59 %
2.7

5.2

0.8

– In 2030 (shown on the left),the cost of delivered hydrogencan be lowered by 59%(2.1 vs. 5.2 €/kg).

1.7

0.2

2.5

Baseline costsof H₂ production(€/kg)

Transport &firming cost

Cost of H₂delivered

Optimisedsystem sizing

Battery storage
operation

Powerelectronics
savings

0.3

Reduced costof capital

2.1

Optimised costof H₂ delivered(€/kg)

Transport costs are based on several parameters including the type of pipeline (repurposed vs. new), transport distance and full-load-hour production on that pipeline. Firming costs are based on
additional storage cost required to deliver hydrogen at the equivalent of 8,000 full-load hours.
2 Optimised system sizing refers to right-sizing of solar PV and electrolyser capacity to increase full load hours. Similarly, battery storage operation enables an increase in the full load hours. Power
electronics savings refers to the removal of the inverter of the solar PV modules to reduce system cost. Reduced cost of capital refers to the use of foreign investment to reduce the WACC from 8 to 6%.
3 In some instances, cost reduction levers may result in cost increases for certain cost-components. For example, an increase in production costs at the same time as a decrease in firming costs. These
cost increases and decreases can result in connection lines that do not directly connect one step to the next.
1– In 2040, hydrogen delivered
costs can be reduced by 63%(1.5 vs. 4.0 €/kg).

Transport
Firming
Production

Delivered Costs(€/kg)(before and after cost levers)
2030

2040

Before costs levers

5.2

4.0

After costs levers

2.1

1.5

© 2022 European Hydrogen Backbone, all rights reserved

Baseline Costs

63

SUPPLY COSTS & COST-COMPETITIVENESS

Corridor B / Southwest Europe & North Africa

Hydrogen costs are cost-competitive with all fossil fuelalternatives by 2030, and significantly lower by 2040
2040

Cost of H₂
production
€/MWh

114

Cost of fossil
fuel alternatives

Cost of H₂
production€/MWh89‒115(=3.8 €/kg)

Cost of fossil
fuel alternatives

Fuel cost
uncertainty

85‒88
59‒73

62‒69

66

(=2.7 €/kg)

83‒95
Case study
Deliveredcost of H₂
1.5 €/kg

62‒69

62 €/MWh60(=2.0 €/kg)

Case study
Deliveredcost of H₂
2.1 €/kg

H₂ production
cost-range
Higher Cost H₂Lower Cost H₂NaturalGas
Fuel cost
CO₂ cost

Steam
Coal

Oil

45 €/MWh42(=1.4 €/kg)

H₂ production
cost-range

Natural
Gas

Steam
Coal

Oil

Fuel uncertain

Note: Prices for fossil alternatives (2030/2040): Natural gas (pre-invasion): 28/13 [€/MWh], Coal: 123/5.6 [€/MWh], Oil: 52/24 [€/MWh]. Natural gas prices levels are based on market conditions before Russia’s invasion of Ukraine. While natural gas prices
have skyrocketed since, there remains significant uncertainty on near- and medium-term European price trends and supply options. As a result, our analysis adopts the IEA’s Outlook 2021 price forecast pre-invasion developed pre-invasion. Prices in 2040
are significantly lower than in 2030 because of demand-supply conditions. By 2040, decreased demand for fossil fuels would lower prices. [Source: International Energy Agency, Outlook 2021 (IEA)] and fuel-cost uncertainty is shown with +50% range]– By 2030, the low range ofhydrogen production costs arecompetitive with natural gas
and coal, and lower than oilalternatives.
– By 2040, the low rangeof hydrogen costs arematerially lower than all
fossil alternatives, while themedium-to-high range are costcompetitive.
– Hydrogen delivered costs fromthe Spain-Germany case study
are competitive to natural gas in
2030 (5% higher) and lower in
2040 (28% lower).
– Natural gas prices are still
uncertain due to recent pricespike as a result of the Russian
invasion of Ukraine
Note: For comparison purposes, cost of H₂ has been converted from“per kg” to “per MWh”
– 1 €/kg = 30 €/MWh (based on LHV of 33.3 kWh/kg)
Competitiveness of hydrogen highly dependent on CO₂-prices as they
will make up alternatives costs major part.
– CO₂ price 2030: 130 €/t– CO₂ price 2040: 205 €/t© 2022 European Hydrogen Backbone, all rights reserved

2030

64

CORRIDOR B© 2022 European Hydrogen Backbone,
all rights reserved

Southwest Europe& North Africa

65

Agenda
1. Corridor Summary
2. Hydrogen Demand & Supply
3. Supply Costs & Cost-Competitiveness4. National Strategies & Regulation
5. Actions Needed

NATIONAL STRATEGIES & REGULATION

Corridor B / Southwest Europe & North Africa

All countries have developed national strategies and targets. Moving forward,
the development of regulation is key to enable infrastructure investment.

Portugal

Network regulation & policy

Funding¹ (bn €)Highlights

PreRePowerEU
targets²– 5% share of hydrogen at final energy consumption, 2 GW
electrolyser 2030
– 10 – 15% H₂ injection to gas grid by 2030

– Expected to come with EU regulations

Spain– Replacing 25% of industrial grey hydrogen– Installation of 4 GW electrolyser capacity– Setting up H₂ refuelling stations across Spain– Expected to come with EU regulations

France– Implementation of local hydrogen hubs pre 2030
– Focus on demand (e.g. heavy transport) and generation(6.5 GW electrolyser in 2030)– No strategy on H₂ infrastructure yet– Hydrogen injections to gas grid are possible,
below threshold of technical restrictions– Focus: Industry, (freight) transport, electricity storage– 150 MW for electrolysis production by 2026
– Import and transit of H₂ and its derivatives via existing
network and additional infrastructure– 2026: 100-160 new km pipelines– Open access H₂ backbone by 2030
connecting ports, industrial clusters, andneighboring countries

Luxembourg– Focus on renewable hydrogen– Prioritized use in industry, sector coupling & transport– Dedicated H₂ network explicitly mentioned– Goal to regulate transmission, storage &distribution infrastructure in line with ambitionsof the EU– Strong need for imports, hence cross border
H₂ infrastructure & national networks to meetindustry & transport demand

Germany– National production & import focus due to supply gap– In place since 2020, currently reviewed towards
increasing its ambition– 10 GW (2030) electrolyser in coalition plans– H₂ network potentially opt-in regulated andvertically unbundled– First rules and standards for high pressure
pipelines are formulated– Strong focus on international cooperation toensure sufficient supply– National funding

Belgium

Note: Sequencing of countries follows the general corridor direction but does not represent the hydrogen flows.
1 Cumulative public funding amount by the respective state until 2030
2 Strategies and funding is under evaluation of meeting latest targets

1.1– Mixed focus on national consumption
and export to central Europe– Production for export with 1 GW in Sines
planned1.6– Decarbonisation of grey hydrogen use byindustry– H₂ in heavy transport (fuelling stations)– Strong investments in transport sector (heavyduty) and hydrogen production for industry– Need to accelerate strategy and policy aroundexports and imports

7.2– The NHS sees Belgium as an import hub ofrenewable molecules for Europe– Strong focus on national and cross-country
hydrogen network infrastructure

0.1

9General funding
SupplyNetwork
Demand© 2022 European Hydrogen Backbone, all rights reserved

National Hydrogen strategy

66

CORRIDOR B© 2022 European Hydrogen Backbone,
all rights reserved

Southwest Europe& North Africa

67

Agenda
1. Corridor Summary
2. Hydrogen Demand & Supply
3. Supply Costs & Cost-Competitiveness4. National Strategies & Regulation
5. Actions Needed

ACTIONS NEEDEDCorridor B / Southwest Europe & North Africa

This corridor plays a fundamental role in achieving
a European backbone by 2040
The need for this corridor– The development of this corridor ensures access to abundant, lowcost hydrogen supply from Spain and Portugal by 2030, and by 2040
additional supply from Morocco and potentially Algeria.
– The decarbonisation of the largest hydrogen demand centers along
this corridor – in Spain, France, and Germany – is dependent on thebuildout of this corridor by 2030, and its expansion towards 2040.

68

2040
Pipelines
Repurposed
New
Import / Export
SubseaDemand per sector

40 / 30 / 20 / 10 / 1 TWh– The buildout of this corridor by 2030 requires national governments totake clear and concrete actions across.
– This includes actions associated with infrastructure development andplanning, the development of cross-national initiatives and securing
access to early funding and long-term, low-cost financing.

Efuels production
Industrial energy
Industrial feedstock
Power
Supply in MWh/km²<1
1 – 2525 – 100
100 – 250
250 – 500
> 500
Storages
Salt cavern
Aquifer
Depleted field
Rock cavern
Other items
Existing or planned
gas-import-terminal
Energy island forH₂ production© 2022 European Hydrogen Backbone, all rights reserved

Actions required

ACTIONS NEEDEDCorridor B / Southwest Europe & North Africa

To ensure the development of this corridor by 2030,
there is a need for clear and concrete actions

Unlock financing tofast-track hydrogen
infrastructure
deployment by applying
regional regulatory
flexibility and otherpragmatic financing
solutions (including
incentivizing the adoptionof hydrogen by demand
sectors)

Simplify and shorten
planning and permitting
procedures for renewableenergy and hydrogen
infrastructure projects.

However, speed will be of essence!

Intensify energy
partnerships with
exporting, non-EHB
countries like Morocco,
and other countries
in North Africa, andproviding financing
support to reduce theircost of capital

Facilitate integrated
energy system planningof hydrogen, naturalgas, and electricity
infrastructure supporting
the accelerated
deployment andintegration of renewableenergy resources© 2022 European Hydrogen Backbone, all rights reserved

Fostering developmentof new and repurposedhydrogen infrastructure,for example, byunbundling rules
facilitating the efficientuse of TSO expertise andservices and by allowing
the adoption of different
vertical unbundling models
in the EU, as is the casewith natural gas

69© 2022 European Hydrogen Backbone,
all rights reserved

TABLE OF CONTENTS

1. Executive Summary
2. Five emerging supply corridors
Corridor A: North Africa & Southern Europe
Corridor B: Southwest Europe & North Africa
Corridor C: North Sea
Corridor D: Nordic and Baltic regions
Corridor E: East and South-East Europe

3. Detailed methodology

70

CORRIDOR C© 2022 European Hydrogen Backbone,
all rights reserved

North
Sea

71

Agenda
1. Corridor Summary
2. Hydrogen Demand & Supply
3. Supply Costs & Cost-Competitiveness4. National Strategies & Regulation
5. Actions Needed

CORRIDOR C / FACTSHEET72

Corridor emerges in the North Sea providing access to low-cost, blueand green hydrogen supply to demand clusters in northwestern Europe

NorwayIrelandNetherlands
Denmark
United Kingdom
Luxembourg
Belgium
FranceGermany

Drivers &Opportunities

Major driver of development is the need to meet demand from large industrial &transport clusters in the UK, Netherlands, Belgium, France and Germany. Key opportunities include the repurposing potential of onshore/offshore infrastructure, integration of North Sea wind resources and the portfolio of planned import terminals

Hydrogen Supply& Decarbonization
Potential

H₂ supply potential¹

852 TWh(TWh/year)
249 TWh
2030

Supply Costs& CostCompetitiveness

Cost of H₂
production¹

Actions Needed

1(MtCO₂/year vs. 2019;% reduction)-94 Mt
(8%)

2040

2040

-254 Mt(21%)

Cost competitiveness²
1.5–2.6

2030

2030

2040

1.6–3.5(€/kg of H₂)

Emissions
Reductions

Hydrogendelivered pricevs.
natural gas pricehigh/low,(€/MWh)

66

73
59

2030

69
62

2040

– Fostering development of new and repurposed hydrogen infrastructure– Unlock financing to fast-track hydrogen infrastructure deployment– Simplify and shorten planning and permitting procedures– Facilitate integrated energy system planning of hydrogen, natural gas, andelectricity infrastructure

Figures reported reflect outputs for all countries included in the corridor. Even if a country is only partially in the corridor, results for the full country are included(e.g., supply potential and costs, demand, transmission network length).
2 Savings are based on the corridor’s case study of hydrogen delivered in 2030 and 2040. The cost of natural gas includes CO₂ prices. Refer to Subsection 3 (Supply Costs & Cost-Competitiveness)

54© 2022 European Hydrogen Backbone, all rights reserved

North
Sea

Corridor C / North Sea

CORRIDOR C© 2022 European Hydrogen Backbone,
all rights reserved

North
Sea

73

Agenda
1. Corridor Summary
2. Hydrogen Demand & Supply
3. Supply Costs & Cost-Competitiveness4. National Strategies & Regulation
5. Actions Needed

CORRIDOR SUMMARY

Corridor C / North Sea

Drivers &Opportunities– The major driver behind the development of this corridor
is hydrogen adoption associated with the decarbonisationof industry, transport and power in the UK and northwestern
Europe. The speed of hydrogen adoption in these regions may
be even faster than anticipated driven by increasing CO₂ prices
in the EU and the RePowerEU ambitions to replace natural gas
consumption.
– In the near term, the corridor offers access to abundant, lowcost blue hydrogen supply from the North Sea. In the longer
term, this corridor also provide access to significant greenhydrogen potential leveraging strong onshore and offshore
wind resources in the North Sea, offering an opportunity tointegrate even higher capacities of offshore wind.

– A major opportunity for this corridor relates to the large portfolioof ongoing and planned hydrogen infrastructure projects in theregion – including large-scale offshore wind developments, largescale integrated hydrogen projects, and a growing list of planned
import terminals for hydrogen and hydrogen-derivatives – in the
Netherlands, Belgium, Germany and France.
– This corridor emerges as a highly-integrated supply corridor thatcan leverage extensive offshore gas infrastructure in the North
Sea, planned national and regional hydrogen backbones in the
Netherlands (by 2027), and in Belgium and Germany by 2030 –connecting all major demand clusters in north-western Europe – as wellas potential hydrogen storage at salt cavern locations northwest Europe.
– The corridor would be stood up by 2030, covering 12,000 km oflarge-scale hydrogen pipelines across all countries of the corridor,of which approximately 70% will be repurposed pipelines. The
corridor’s high repurposing potential of existing infrastructure offers
an opportunity to keep the cost of hydrogen transport relatively low.

Hydrogen Demand& Supply– Total hydrogen demand in the corridor reaches ~260 TWh by
2030, increasing substantially to ~900 TWh by 2040. Up to 2030,
most hydrogen demand is driven by large industrial clusters in the
UK and northwestern Europe. Hydrogen use in the transport sector
also contributes a significant share of hydrogen demand. From 2040
to 2050, hydrogen demand increases substantially in the transportand power sectors and continues to ramp up in industry.

– Hydrogen adoption across all countries of the corridors enables anemissions reduction of ~360 MtCO₂/yr. by 2050, equivalent to a
29% emissions reduction.
– The corridor enables access to hydrogen supply potential of ~250 TWh
by 2030, increasing to roughly 850 TWh by 2040. Major sources ofsupply include North Sea blue hydrogen potential in 2030, expanding togreen hydrogen from onshore and offshore wind resources in the North Sea.

© 2022 European Hydrogen Backbone, all rights reserved

Corridor offers access to low-cost, North Sea blue & green hydrogen
supply to demand clusters in the UK and northwestern Europe

74

CORRIDOR SUMMARY

Corridor C / North Sea

Costs & CostCompeti­tiveness– By 2030, the corridor provides access to hydrogen ranging
in production cost from 1.6 to 3.5 €/kg. By 2040, as supply
options increase and technology costs decrease, hydrogenproduction costs decrease to 1.5 to 2.6 €/kg.
– In the long term, this corridor’s lowest-cost hydrogen supply
options are onshore and offshore wind resources from theNorth Sea.

– Based on a case-study of green hydrogen supply and transport fromthe North Sea to North Rhine Westphalia (Germany), the cost ofdelivered hydrogen – inclusive of transport and firming costs – canbe lowered to achieve cost levels comparable to production
costs both in 2030 and 2040. Lowering delivery costs can beachieved through various cost levers including optimized operationof the system and cost of capital reductions.

National Strategies& Regulation– Most countries have developed – or are in the process ofdeveloping – national strategies. Further, in most high-demandcountries, hydrogen regulation is also already in place, if not
currently under development. The development of hydrogen
regulation in all other countries will accelerate investment ininfrastructure.

– In select countries, substantial funding has been allocated tosupport the development of the hydrogen market including funding
for gas network infrastructure.

Actions Needed

To support the buildout of this corridor by 2030, clear and concrete
actions related to infrastructure planning, financing and development
have been identified:– Fostering development of new and repurposed hydrogen
infrastructure.
– Unlock financing to fast-track hydrogen infrastructure
deployment by applying regional regulatory flexibility and otherpragmatic financing solutions.

– Simplify and shorten planning and permitting procedures for thefull value chain of renewable energies and hydrogen infrastructure
projects.
– Establish integrated energy system planning of hydrogen, naturalgas, and electricity infrastructure.

© 2022 European Hydrogen Backbone, all rights reserved

To successfully stand up this corridor by 2030, actions are needed
to support infrastructure planning, financing and development

75

CORRIDOR C© 2022 European Hydrogen Backbone,
all rights reserved

North
Sea

76

Agenda
1. Corridor Summary
2. Hydrogen Demand & Supply
3. Supply Costs & Cost-Competitiveness4. National Strategies & Regulation
5. Actions NeededHYDROGEN DEMAND & SUPPLY / SECTION INTRODUCTION

Corridor C / North Sea

This section explores the development of demand, supply andtransport infrastructure in the corridor from 2030 to 2050
2030 Corridor Snapshot(Supply, Demand and Infrastructure)

77

Hydrogen demand
By 2030, the corridor connects all major industrial clusters in the UK andnorthwest Europe. From 2030 to 2040, the corridor expands to all demandcenters along its route, increasing demand from 260 to ~900 TWh.

Hydrogen supply¹

Demand per sector

In 2030, hydrogen supply is ~250 TWh, of which over 40% is blue hydrogen.
Hydrogen supply increases significantly by 2040, reaching 850 TWh.

40 / 30 / 20 / 10 / 1 TWh

249 TWh (2030)

Efuels production
Industrial energy
Industrial feedstock
Power
Supply in MWh/km²<1
1 – 2525 – 100
100 – 250
250 – 500
> 500
Storages
Salt cavern
Aquifer
Depleted field
Rock cavern
Other items
Existing or planned
gas-import-terminal
Energy island forH₂ production

Grid-based

Dedicated green

Blue

Hydrogen Infrastructure
By 2030, the buildout of pipeline infrastructure across all countries of thecorridor reaches 12,000 km of large-scale pipelines. Corridor benefits froma very large share of repurposed infrastructure.
70% (Repurposed pipelines)
1

Ship imports of hydrogen and hydrogen-derivatives are not included.

30% (New pipelines) 12,000 km (2030)© 2022 European Hydrogen Backbone, all rights reserved

Pipelines
Repurposed
New
Import / Export
SubseaBy 2030, the corridor enables access to low-cost, blue hydrogen supply
from the North Sea. By 2040, the corridor diversifies its supply with greenhydrogen from offshore wind resources in the North Sea.

HYDROGEN DEMAND & SUPPLYCorridor C / North Sea

2030

2040

Pipelines
Repurposed
New
Import / Export
SubseaPipelines
Repurposed
New
Import / Export
SubseaDemand per sector

Demand per sector

40 / 30 / 20 / 10 / 1 TWh

40 / 30 / 20 / 10 / 1 TWh

Efuels production
Industrial energy
Industrial feedstockPower

Efuels production
Industrial energy
Industrial feedstockPower

Storages
Salt cavern
Aquifer
Depleted field
Rock cavern

Storages
Salt cavern
Aquifer
Depleted field
Rock cavern

Other items
Existing or planned
gas-import-terminal
Energy island forH₂ production

Other items
Existing or planned
gas-import-terminal
Energy island forH₂ production© 2022 European Hydrogen Backbone, all rights reserved

Corridor connects major industrial clusters in the UK and northwest
Europe by 2030, expanding to all demand centers by 2040

78

HYDROGEN DEMAND & SUPPLYCorridor C / North Sea

Hydrogen demand increases rapidly from 2030 to 2040, largely
driven by the UK, Belgium, the Netherlands, France and Germany
2030

2040

2050

Hydrogen demand – across all countries of
the corridor – increases significantly from2030 to 2050. Demand reaches 260 TWh by
2030, increasing to roughly ~900 TWh by 2050.

General H₂ flow

Total demand per country (TWh/y)
Norway8

1724

Ireland3

1730

United Kingdom

27

171

Denmark

27

52

Netherlands

46

109

Luxembourg

1

248

153

3

7

25

78

109

France

33

97

161

Germany

90

363
260

– Up to 2030, most hydrogen demand isdriven by large industrial clusters in theUK, Belgium, the Netherlands, France andGermany. Hydrogen use in power generation
also accounts for a significant share ofdemand.

67

Belgium

Total

Hydrogen demand may accelerate andincrease further than forecasted as a resultof additional regulatory measures adopted in
response to the RePowerEU plan.

– From 2040 to 2050, hydrogen demand
expands into the transport sector andcontinues to ramp up in industry and power
generation.
505

907

Note: Does not include grey hydrogen demand. Numbers represent total demand by country, even if only parts of the country are included in the corridor.

1,303© 2022 European Hydrogen Backbone, all rights reserved

Country79

HYDROGEN DEMAND & SUPPLYCorridor C / North Sea

Hydrogen adoption enables a reduction in emissionsof 29% by 2050 across all countries of the corridor
-8 %

-21%

-29 %

Hydrogen adoption across all demand
sectors enables an emissions reduction of~360 MtCO₂/yr. by 2050, equivalent to a
29% reduction².

Decarbonisationin Mt CO₂ / year

– Up to 2030, the industrial sector contributes
just under 70% of the total emissions reductions,largely driven by the decarbonisation of thesteel sector. Notably, roughly 20% of emissions
reductions are from the transport sector.

400
357
350
300

– By 2040, emissions reductions from trans­
port (road, shipping and aviation) increase
substantially and combined with industry,account for 80% of emissions reductions.
The power sector account for the remaining
20% of reductions.

254
250
200
150
100

– By 2050, the transport sector alone accounts
for over 50% of emissions reductions.

94

50
IndustryPower
Buildings
Transport

02030© 2022 European Hydrogen Backbone, all rights reserved

2040

2050

1

CO₂-Emissions from countries and sectors included in corridor (1.24 bn t CO₂ / year),
Source: EEA
2 Emissions reductions are calculated compared to the baseline fossil fuel used in eachsectors. For example, emissions reductions associated with the adoption of hydrogen by the
primary steel sector are relative to the use of coal. Similarly, emissions reductions , for e-fuels
production are relative to the use of fossil fuels in domestic transport, shipping and other uses.

© 2022 European Hydrogen Backbone, all rights reserved

Emissions reductions(vs. 2019 emissions¹)

80

HYDROGEN DEMAND & SUPPLYCorridor C / North Sea

Corridor enables access to North Sea blue hydrogen by 2030,
expanding to hydrogen supply from abundant offshore wind by 2040

Pipelines
Repurposed
New
Import / Export
SubseaSupply in MWh/km²<1
1 – 2525 – 100
100 – 250
250 – 500
> 500
Storages
Salt cavern
Aquifer
Depleted field
Rock cavern
Other items
Existing or planned
gas-import-terminal
Energy island forH₂ production
Total hydrogen supply shown per NUTS-2 region. MWhadjusted by the area of each NUTS-2 region in km².
* Note: Supply numbers do not include grey hydrogen.

2040*

Pipelines
Repurposed
New
Import / Export
SubseaSupply in MWh/km²<1
1 – 2525 – 100
100 – 250
250 – 500
> 500
Storages
Salt cavern
Aquifer
Depleted field
Rock cavern
Other items
Existing or planned
gas-import-terminal
Energy island forH₂ production© 2022 European Hydrogen Backbone, all rights reserved

2030*

81

HYDROGEN DEMAND & SUPPLYCorridor C / North Sea

Hydrogen supply increases significantly from 2030 to 2040, driven
by a scale up in supply across multiple countries in the corridor
2030

2040

SupplyNorwayIrelandGeneral H₂ flow

United Kingdom
Denmark
Netherlands
Luxembourg
Belgium
FranceGermany
Total

30

Net¹
39

16

6

9

25

23

12

15

9

-6

8

-1

0

15

25

-4

6

8

5

5

-75

15

69

Supply

33

106

74

-11

Net¹
134

100 18

30

46

12

30 10

2050

160

80

30 14

48

23 11

-3

94

81

-50

8

8

16

10

-261

21

568

181

103

-55

1 Net represents excess supply after subtracting demand;
2 Grid-based is estimated using national 2030 electrolyser targets which, by 2030, are assumed to be largely grid-connected rather than dedicated.
Grid-based increases over 2030-2050 with increasing RES;
3 Blue hydrogen supply volumes will be subject to the evolution of gas markets and the development of low carbon hydrogen regulation in different
country. As a result, some countries may have additional blue hydrogen supply which could be used to satisfy local demand.

Net¹
88

18

40

70

50

279 18

115

-1

0

20

94

33

21

73

Supply

179

75

27

41

15

-7

0

-98

11

150

165

13

24

-313

27

1,052

Dedicated green
Blue
Grid-based
2050 technical potential

140

-111

Hydrogen supply includes a mix of supply options
including grid-based green hydrogen², dedi­
cated green hydrogen, and blue hydrogen³.
– By 2030, hydrogen supply reaches~250 TWh, roughly 40% blue hydrogenand 30% each for dedicated green andgrid-based hydrogen.
– By 2040, hydrogen supply increases
substantially to ~850 TWh, of which 70%
is from dedicated green hydrogen. Blue
hydrogen accounts for just under 20%, while
grid-based hydrogen for the remaining 10%.
– By 2050, hydrogen supply increases further
to ~1,190 TWh. Dedicated green supply
account for the largest share at 90%, while
grid-based hydrogen account for the remaining
10%. Blue hydrogen supply is not included in
2050 due to assumed target of zero emissions
and de-fossilisation of Europe by 2050.
Hydrogen supply may accelerate and increase
further as a result of additional regulatory measures adopted in response to the RePowerEU plan.
Note: Hydrogen supply volumes do not include hydrogen imports by ship.

© 2022 European Hydrogen Backbone, all rights reserved

Country82

HYDROGEN DEMAND & SUPPLYCorridor C / North Sea

The scale up in supply is supported by the developmentof several hydrogen import terminals in the North Sea

83

Rotterdam– In feasibility study, strategy ready– Planning to import 0.3 – 0.4 mio.
tons of hydrogen by 2030

Stade
– LNG-terminal underway– Comes ready with fuel switch
option to H₂

Netherlands
Germany

Eemshaven / Groningen– Planning to import H₂ with NORTH₂
Project

Wilhelmshaven– Working on feasibility study,
strategy ready– LNG-terminal underway– Planning to import and producewith 410 MW electrolyser onsite
0.3 mio. tons by 2030
Brunsbuettel– LNG-terminal underway– Comes ready with fuel switch
option to H₂

Dunkerque– Ambitions to establish H₂ terminal– Onsite H₂-strategy to decarbonise
harbour with integrated heat, CCS andhydrogen use for transport

FranceNote: Ship imports of hydrogen or hydrogen-derivatives are not included in the analysis of Corridor C.
Infrastructure shown for 2030.
Strategy ready indicates that the terminal announced to import H₂

Belgium

Zeebrugge– Large scale LNG-terminal present,
ambitions to accommodate H₂– Planning to import 0.5 mio tons ofhydrogen by 2030

Strategy ready

Strategy in progress

Strategy ambitions© 2022 European Hydrogen Backbone, all rights reserved

Amsterdam– During proof of concept,
strategy ready– Planning to scale up imports to
1 mio. ton of hydrogen starting
2030

Hamburg– Ambitions to establish H₂ terminal– Onsite H₂-project H₂Global

CORRIDOR C© 2022 European Hydrogen Backbone,
all rights reserved

North
Sea

84

Agenda
1. Corridor Summary
2. Hydrogen Demand & Supply
3. Supply Costs & Cost-Competitiveness4. National Strategies & Regulation
5. Actions Needed

SUPPLY COSTS & COST-COMPETITIVENESS / SECTION INTRODUCTION

Corridor C / North Sea

This section explores the costs of hydrogen production anddelivery for this corridor and their competitivenessHydrogen delivered costs

Comparison with fossil alternatives

What is the range of production costs
achieved by the corridor in 2030 and
2040?

Based on a case-study of hydrogen
supply from the North Sea to Germany:– What are the full costs of firm hydrogendelivery after accounting for transportand storage costs?
– What cost levers are available to lower
the cost of hydrogen delivery?

How competitive is hydrogen supply
from this corridor compared to fossil fuelalternatives?

Corridor C / North Sea

Fr
an
ce

De
nm
ar
k
G
er
m
an
y

N
or
wa
y

Un
ite
d

3.0
2.5

3.4

0.1

0.1

0.1

0.9

Cost range (€/kg)

2.2

Fr
an
ce
G
er
m
an
y

0
0

100
Imports
Blue hydrogen

2.5

200

2.0

Wind offshore
Wind onshore

1.5

300
Solar PV
Grid-connected

400

500

600

700

800

2040

Case study (see next slide)

High
Low

1.6

1.0
1-4 See previous slide

0.5
0.0
0

25
Imports
Blue hydrogen

50
Wind offshore
Wind onshore

75
Solar PV
Grid-connected

100

125

150

175

200

Case study (see next slide)1 Cost curves are based on a bottom-up estimate of supply volumes per country and hydrogen production type. No transport or storage / firming cost are included.
2 Dedicated hydrogen production costs are based on renewable technology and electrolyser costs, and country-specific capacity factors and discount rates.
3 Grid-connected hydrogen production costs are determined based on costs of a mix of dedicated green hydrogen (solar, onshore wind, offshore wind) and adjusted
for grid-connection costs.

225

250

2030
High
Low

4 Blue hydrogen costs are subject to significant uncertainty in natural gas prices. Our analysis adopts natural gas prices levels based on market conditions
before Russia’s invasion of Ukraine. While natural gas prices have skyrocketed since, there remains significant uncertainty on near- and medium-term
European price trends and supply options. As a result, our analysis adopts the IEA’s Outlook 2021 price forecast developed pre-invasion, with costs of 28 €/MWh in 2030 and 13 €/MWh in 2040.

Baseline costsof H₂ production(€/kg)© 2022 European Hydrogen Backbone, all rights reserved

3.5

3.0

© 2022 European Hydrogen Backbone, all rights reserved

N F
Un eth ran
ite er ce,
d lan
Kin d
gd s,
om

3.5

De
nm
ar
k

4.0

De
nm
ar
k
N
or
De wa
nm y,
ar
k
Ire
la
N nd,
or
wa
y

Un Nethite e
d rla
Kin nd
gd s,
Be om
lg ,
ium

N
or
wa
y

1.0
0.5

1.5

– By 2030, the corridor provides accessto hydrogen production costs of 1.6 to
3.5 €/kg.
– By 2040, hydrogen production costs
decrease to the range of 1.5 to 2.6 €/kg.

Transport &firming cost

Cost of H₂delivered

Optimisedsystem sizing

Battery storage
operation

Powerelectronics
savings

Reduced costof capital

Optimised costof H₂ delivered(€/kg)

1 Transport costs are based on several parameters including the type of pipeline (repurposed vs. new), transport distance and full-load-hour production on that pipeline. Firming costs are based on
additional storage cost required to deliver hydrogen at the equivalent of 8,000 full-load hours.
2 Optimised system sizing refers to right-sizing of solar PV and electrolyser capacity to increase full load hours. Similarly, battery storage operation enables an increase in the full load hours. Power
electronics savings refers to the removal of the inverter of the solar PV modules to reduce system cost. Reduced cost of capital refers to the use of foreign investment to reduce the WACC from 8 to 6%.
3 In some instances, cost reduction levers may result in cost increases for certain cost-components. For example, an increase in production costs at the same time as a decrease in firming costs. These cost
increases and decreases can result in connection lines that do not directly connect one step to the next.

Transport
Firming
Production

Delivered Costs (€/kg)(before and after cost levers)
2030

2040

Before costs lever

3.4

2.9

After costs lever

2.2

1.8

Cost of fossil
fuel alternatives€/MWh

Production
costs(=3.5 €/kg)

Cost of fossil
fuel alternatives€/MWh89‒115
105

Fuel cost
uncertainty

85‒88
59‒73

– In 2040, hydrogen delivered
costs can be reduced by 40%(1.4 vs. 2.5 €/kg).

90

2040

Production
costs– In 2030 (shown on the left),the cost of delivered hydrogencan be lowered by 35% (2.2
vs. 3.4 €/kg).

2.6
2.3

2030

Cost reduction levers applied tocase study of hydrogen transport
from the North Sea to Germany
enable firm delivery costs to be
reduced significantly.

Cost Reductions Levers

Large uncertainty on
blue hydrogen costs 4

1.5

Key Findings& Results

Baseline Costs-35 %Levelised cost of hydrogen production (€/kg) and Supply per country (TWh)2.0

Cost of Hydrogen Delivered (€/kg) in 2030¹, ², ³

86

1.2

N
or
Ire waylan ,dHydrogen Production Cost Range [2030]¹, ², ³

N
eth
er
Un
ite Be landd lg s,Kin iu
gd m,
om
G
er
m
an
y
G
N er
eth m
er anylan ,ds

InLevelised
2030,
the corridor offers access to hydrogen production Cost range (€/kg)
cost of hydrogen production (€/kg) and Supply per country (TWh)ranging in costs from 1.6 to 3.5 €/kg

Corridor C / North Sea

Hydrogen costs are cost-competitive with all fossil
alternatives by 2030, and lower by 2040.

89

78
63‒69

83‒95

(=3.5 €/kg)

62‒69

66 €/MWh

Case study
Deliveredcost of H₂
1.8 €/kg

54 €/MWh48– Several cost reduction levers can beapplied to lower the costs of hydrogendelivery.
– For the North Sea-to-Germany case study,
these levers achieve delivery costs thatare low and cost-competitive.

Case study
Deliveredcost of H₂
2.2 €/kg(=1.6 €/kg)

H₂ production
cost-range
Higher Cost H₂Lower Cost H₂NaturalGas
Fuel cost
CO₂ cost

Steam
Coal

Oil

45

(=1.6 €/kg)

H₂ production
cost-range

Natural
Gas

Steam
Coal

Oil

Fuel uncertain

Note: Prices for fossil alternatives (2030/2040): Natural gas (pre-invasion): 28/13 [€/MWh], Coal: 123/5.6 [€/MWh], Oil: 52/24 [€/MWh]. Natural gas prices levels are based on market conditions before Russia’s invasion of Ukraine. While natural gas prices
have skyrocketed since, there remains significant uncertainty on near- and medium-term European price trends and supply options. As a result, our analysis adopts the IEA’s Outlook 2021 price forecast pre-invasion developed pre-invasion. Prices in 2040
are significantly lower than in 2030 because of demand-supply conditions. By 2040, decreased demand for fossil fuels would lower prices. [Source: International Energy Agency, Outlook 2021 (IEA)] and fuel-cost uncertainty is shown with +50% range]– By 2030, the low range ofhydrogen production costs
are lower than all fossil
alternatives.
– By 2040, the low-to-medium
range of hydrogen costs arematerially lower than all
fossil alternatives, while themedium-to-high range are costcompetitive.
– Hydrogen delivered costs fromthe North Sea-to-Germany casestudy are competitive to natural
gas in 2030 (12% higher) andlower in 2040 (13% lower).
– Natural gas prices are still
uncertain due to recent pricespike as a result of the Russian
invasion of Ukraine
Note: For comparison purposes, cost of H₂ has been converted from“per kg” to “per MWh”
– 1 €/kg = 30 €/MWh (based on LHV of 33.3 kWh/kg)
Competitiveness of hydrogen highly dependant on CO₂-prices as they
make up a significant part of fossil fuel costs.
– CO₂ price 2030: 130 €/t– CO₂ price 2040: 205 €/t– Hydrogen costs are competitive withfossil fuel alternatives by 2030, andlower by 2040.
– Fossil fuel costs are subject to significant
uncertainty.

© 2022 European Hydrogen Backbone, all rights reserved

SUPPLYCOSTS& COST-COMPETITIVENESS
Hydrogen Production
Cost
Range
[2040]¹, ², ³

SUPPLY COSTS & COST-COMPETITIVENESS

Corridor C / North Sea

Applying cost reduction levers to the North Sea-Germany case study
lowers delivery costs by 35% keeping hydrogen cost-competitive87© 2022 European Hydrogen Backbone, all rights reserved

SUPPLY COSTS & COST-COMPETITIVENESS / CASE STUDY

Corridor C / North Sea

By 2040, as hydrogen supply options increase and scale up,
production costs decrease to a range from 1.5 to 2.6 €/kg

© 2022 European Hydrogen Backbone, all rights reserved

SUPPLY COSTS & COST-COMPETITIVENESSU
Kin nite
g d
De do
nm m,
ar
k

Content
Material

Hydrogen production cost

Kin
gd
Ire omlan ,d

Key Questions
Answered

85

SUPPLY COSTS & COST-COMPETITIVENESS

Corridor C / North Sea

In 2030, the corridor offers access to hydrogen production
ranging in costs from 1.6 to 3.5 €/kg

86

Hydrogen Production Cost Range [2030]¹, ², ³
Levelised cost of hydrogen production (€/kg) and Supply per country (TWh)Cost range (€/kg)

Fr
an
ce
G
er
m
an
y

De
nm
ar
k

De
nm
ar
k
N
or
De wa
nm y,
ar
k
Ire
lan
N d,
or
wa
y

N F
Un eth ran
ite er ce,
d lan
Ki d
ng s,
do
m

4.0

Un Netite he
d rla
Ki nd
ng s,
d
Be om
lg ,
ium

N
or
wa
y

Large uncertainty on
blue hydrogen costs 4

3.5

3.5
3.0
2.5

1.5

1.6

1.0
0.5
0.0
0

25
Imports
Blue hydrogen

50
Wind offshore
Wind onshore

75
Solar PV
Grid-connected

100

125

150

175

200

Case study (see next slide)1 Cost curves are based on a bottom-up estimate of supply volumes per country and hydrogen production type. No transport or storage / firming cost are included.
2 Dedicated hydrogen production costs are based on renewable technology and electrolyser costs, and country-specific capacity factors and discount rates.
3 Grid-connected hydrogen production costs are determined based on costs of a mix of dedicated green hydrogen (solar, onshore wind, offshore wind) and adjusted
for grid-connection costs.

225

250

2030
High
Low

4 Blue hydrogen costs are subject to significant uncertainty in natural gas prices. Our analysis adopts natural gas prices levels based on market conditions
before Russia’s invasion of Ukraine. While natural gas prices have skyrocketed since, there remains significant uncertainty on near- and medium-term
European price trends and supply options. As a result, our analysis adopts the IEA’s Outlook 2021 price forecast developed pre-invasion, with costs of 28 €/MWh in 2030 and 13 €/MWh in 2040.

© 2022 European Hydrogen Backbone, all rights reserved

2.0

SUPPLY COSTS & COST-COMPETITIVENESS

Corridor C / North Sea

By 2040, as hydrogen supply options increase and scale up,
production costs decrease to a range from 1.5 to 2.6 €/kg

87

Hydrogen Production Cost Range [2040]¹, ², ³

2.6

N
or
Ire way
lan ,
d

3.0

Cost range (€/kg)

N
eth
er
Un
ite Be landd lg s,Kin iu
gd m,
om
G
er
m
an
y
G
N er
et m
he an
rla y,
nd
s

Fr
an
ce

De
nm
ar
k
G
er
m
an
y

Kin
gd
Ire om
lan ,
d

Un
ite
d

N
or
wa
y

U
Ki nite
ng d
De do
nm m,
ar
k

Levelised cost of hydrogen production (€/kg) and Supply per country (TWh)

2.5
2.0
1.5
1.0
0.5
0
0

100
Imports
Blue hydrogen

1-4 See previous slide

200Wind offshore
Wind onshore

300
Solar PV
Grid-connected

400
Case study (see next slide)

500

600

700

800

2040
High
Low

© 2022 European Hydrogen Backbone, all rights reserved

1.5

SUPPLY COSTS & COST-COMPETITIVENESS / CASE STUDY

Corridor C / North Sea

Hydrogen delivered costs, incl. transport and storage costs,
can be kept low and comparable to hydrogen production costs
analysis assesses a case study of hydrogen supply from the North
1 ThisSea to North Rhine Westphalia (Germany) to explore how the costs offirm hydrogen delivery costs can be lowered.

88

Corridor Case
Study Routeassess the full cost of hydrogen delivery to Germany, transport and2 To
storage costs are added to the cost of hydrogen production from

Production
Costs

+

Transport
Costs+

Storage
Costs=

Delivered
Costs

cost reduction levers are applied to lower firm delivery costs,
3 Several
including optimised system operation, battery storage use, cost of capital
reductions, among others.

4

These cost reduction levers achieve sufficient cost savings tokeep firm hydrogen delivery costs low and cost-competitive.

Pipelines
Repurposed
New
Import / Export
SubseaUK© 2022 European Hydrogen Backbone, all rights reserved

the North Sea.

SUPPLY COSTS & COST-COMPETITIVENESS / CASE STUDY

Corridor C / North Sea

Applying cost reduction levers to the North Sea-Germany case study
lowers delivery costs by 35% keeping hydrogen cost-competitive
Cost of Hydrogen Delivered (€/kg) in 2030¹, ², ³

Cost reduction levers applied tocase study of hydrogen transport
from the North Sea to Germany
enable firm delivery costs to be
reduced significantly.

Cost Reductions Levers

-35 %
1.2

3.4

0.1

0.1

0.1

0.9

2.3

Baseline costsof H₂ production(€/kg)

2.2

Transport &firming cost

Cost of H₂delivered

Optimisedsystem sizing

Battery storage
operation

Powerelectronics
savings

Reduced costof capital

Optimised costof H₂ delivered(€/kg)

Transport costs are based on several parameters including the type of pipeline (repurposed vs. new), transport distance and full-load-hour production on that pipeline. Firming costs are based on
additional storage cost required to deliver hydrogen at the equivalent of 8,000 full-load hours.
2 Optimised system sizing refers to right-sizing of solar PV and electrolyser capacity to increase full load hours. Similarly, battery storage operation enables an increase in the full load hours. Power
electronics savings refers to the removal of the inverter of the solar PV modules to reduce system cost. Reduced cost of capital refers to the use of foreign investment to reduce the WACC from 8 to 6%.
3 In some instances, cost reduction levers may result in cost increases for certain cost-components. For example, an increase in production costs at the same time as a decrease in firming costs. These cost
increases and decreases can result in connection lines that do not directly connect one step to the next.
1– In 2030 (shown on the left),the cost of delivered hydrogencan be lowered by 35% (2.2
vs. 3.4 €/kg).
– In 2040, hydrogen delivered
costs can be reduced by 40%(1.8 vs. 2.9 €/kg).

Transport
Firming
Production

Delivered Costs (€/kg)(before and after cost levers)
2030

2040

Before costs lever

3.4

2.9

After costs lever

2.2

1.8

© 2022 European Hydrogen Backbone, all rights reserved

Baseline Costs

89

SUPPLY COSTS & COST-COMPETITIVENESS

Corridor C / North Sea

Hydrogen costs are cost-competitive with all fossil
alternatives by 2030, and lower by 2040.
2040

Production
costs

Cost of fossil
fuel alternatives€/MWh

Production
costs
€/MWh

89‒115105(=3.5 €/kg)

Cost of fossil
fuel alternatives

Fuel cost
uncertainty

85‒88
59‒73

78
63‒69

83‒95

(=2.6 €/kg)

62‒69

66 €/MWh

Case study
Deliveredcost of H₂
1.8 €/kg

54 €/MWh48

Case study
Deliveredcost of H₂
2.2 €/kg(=1.6 €/kg)

H₂ production
cost-range
Higher Cost H₂Lower Cost H₂NaturalGas
Fuel cost
CO₂ cost

Steam
Coal

Oil

45

(=1.5 €/kg)

H₂ production
cost-range

Natural
Gas

Steam
Coal

Oil

Fuel uncertain

Note: Prices for fossil alternatives (2030/2040): Natural gas (pre-invasion): 28/13 [€/MWh], Coal: 123/5.6 [€/MWh], Oil: 52/24 [€/MWh]. Natural gas prices levels are based on market conditions before Russia’s invasion of Ukraine. While natural gas prices
have skyrocketed since, there remains significant uncertainty on near- and medium-term European price trends and supply options. As a result, our analysis adopts the IEA’s Outlook 2021 price forecast pre-invasion developed pre-invasion. Prices in 2040
are significantly lower than in 2030 because of demand-supply conditions. By 2040, decreased demand for fossil fuels would lower prices. [Source: International Energy Agency, Outlook 2021 (IEA)] and fuel-cost uncertainty is shown with +50% range]– By 2030, the low range ofhydrogen production costs
are lower than all fossil
alternatives.
– By 2040, the low-to-medium
range of hydrogen costs arematerially lower than all
fossil alternatives, while themedium-to-high range are costcompetitive.
– Hydrogen delivered costs fromthe North Sea-to-Germany casestudy are competitive to natural
gas in 2030 (12% higher) andlower in 2040 (13% lower).
– Natural gas prices are still
uncertain due to recent pricespike as a result of the Russian
invasion of Ukraine
Note: For comparison purposes, cost of H₂ has been converted from“per kg” to “per MWh”
– 1 €/kg = 30 €/MWh (based on LHV of 33.3 kWh/kg)
Competitiveness of hydrogen highly dependant on CO₂-prices as they
make up a significant part of fossil fuel costs.
– CO₂ price 2030: 130 €/t– CO₂ price 2040: 205 €/t© 2022 European Hydrogen Backbone, all rights reserved

2030

90

CORRIDOR C© 2022 European Hydrogen Backbone,
all rights reserved

North
Sea

91

Agenda
1. Corridor Summary
2. Hydrogen Demand & Supply
3. Supply Costs & Cost-Competitiveness4. National Strategies & Regulation
5. Actions Needed

NATIONAL STRATEGIES & REGULATIONSCorridor C / North Sea

Most countries have developed national strategies and targets. Moving forward,
the development of regulation is key to enable infrastructure investment.
Highlights

PreRePowerEU
targets²

National Hydrogen strategy (NHS)

Network regulation & policy

Norway– 2025: H₂ hubs for maritime, industrial & product.
– 2030: Network of spread hydrogen hubs

– N/A

Ireland– Government plans NHS in July, 2022

– N/A

– Early stage policy developments only

UnitedKingdom– 2030: 10 GW of low-carbon hydrogen production– Mix of green and blue hydrogen incl. funding– Blending of 20% vol. to gas network foreseen– Initial network regulatory and legal framework not expected
before 2025

– More clarity on H₂ funding & strategy for ind. cluster
application & H₂ production– Policy decision on heat due in 2026

Denmark– Focus on green H₂ (4-6 GW) and Efuels, and export of Efuels and PtXtechnologies to demand hubs (DE, NL, etc.)– Proposition: Allow TSO & DSO to own and operate H₂
infrastructure

Netherlands– Focus: Production & network to supply industry– Build dedicated national hydrogen grid
– 3 – 4 GW electrolyser capacity in 2030

– Unbundling of natural gas and H₂ grid operation andproduction– Integrated network planning

Luxembourg– Focus on renewable hydrogen– Prioritized use in industry, sector coupling & transport– Dedicated H₂ network explicitly mentioned– Goal to regulate transmission and distribution infrastructure inline with ambitions of the EU– Strong need for imports, hence cross border H₂
infrastructure & national networks to meet industry &transport demand

Belgium– Focus: Industry, (freight) transport, electricity storage– 150 MW for electrolysis production by 2026
– Import and transit of H₂ and its derivatives via existing network and additional
infrastructure– 2026: 100-160 new km pipelines– Open access H₂ backbone by 2030 connecting ports,
industrial clusters, and neighboring countries– The NHS sees Belgium as an import hub of renewablemolecules for Europe– Strong focus on national and cross-country hydrogen
network infrastructure

France– Implementation of local hydrogen hubs pre 2030
– Focus on demand (e.g. heavy transport) and generation (6.5 GW electrolyser
in 2030)– No strategy on H₂ infrastructure yet– Hydrogen injections to gas grid are possible, below thresholdof technical restrictions

Germany– National production & import focus due to supply gap– In place since 2020, currently reviewed towards increasing its ambition– 10 GW (2030) electrolyser in coalition plans– H₂ network potentially opt-in regulated and verticallyunbundled– First rules and standards for high pressure pipelines areformulated– Focus on maritime applications and H₂ hubs
– Assessment of CCFDs for industrial projects

0.1

2.3

– Transport infrastructure is seen as key to enable role as PtX
producer and exporter

0.2– Production and transport infrastructure– €750 m funding for national hydrogen transmission
network.

1.5

0.1

–

Strong investments in transport sector (heavy duty) andhydrogen production for industry– Need to accelerate strategy and policy around exports andimports

7.2

9

General funding
SupplyNetwork
Demand– Strong focus on international cooperation to ensuresufficient supply– National funding© 2022 European Hydrogen Backbone, all rights reserved

Note: Sequencing of countries follows the general corridor direction but does not represent the hydrogen flows.
1 Cumulative public funding amount by the respective state until 2030
2 Strategies and funding is under evaluation of meeting latest targets

Funding¹ (bn €)92

CORRIDOR C© 2022 European Hydrogen Backbone,
all rights reserved

North
Sea

93

Agenda
1. Corridor Summary
2. Hydrogen Demand & Supply
3. Supply Costs & Cost-Competitiveness4. National Strategies & Regulation
5. Actions Needed

ACTIONS NEEDEDCorridor C / North Sea

This corridor plays a fundamental role in achieving
a European backbone by 2040
– The development of this corridor ensures access to abundant, lowcost blue hydrogen supply from the North Sea by 2030, and by 2040
diversifying its supply with green hydrogen from offshore wind resources in
the North Sea.
– The decarbonisation of the largest hydrogen demand centers along
this corridor – in the UK, the Netherlands, Belgium, northern France
and western Germany – is dependent on the buildout of this corridor by
2030, and its expansion towards 2040.
Actions required– The buildout of this corridor by 2030 requires national governments totake clear and concrete actions across.
– This includes actions associated with infrastructure development andplanning, the development of cross-national initiatives and securing
access to early funding and long-term, low-cost financing.

2040
Pipelines
Repurposed
New
Import / Export
SubseaDemand per sector

40 / 30 / 20 / 10 / 1 TWh
Efuels production
Industrial energy
Industrial feedstock
Power
Supply in MWh/km²<1
1 – 2525 – 100
100 – 250
250 – 500
> 500
Storages
Salt cavern
Aquifer
Depleted field
Rock cavern
Other items
Existing or planned
gas-import-terminal
Energy island forH₂ production© 2022 European Hydrogen Backbone, all rights reserved

The need for this corridor

94

ACTIONS NEEDEDCorridor C / North Sea

To ensure the development of this corridor by 2030,
there is a need for clear and concrete actions

Unlock financing tofast-track hydrogen
infrastructure deploy­ment by applying regional
regulatory flexibility andother pragmatic financing
solutions (including
incentivizing the adoptionof hydrogen by demand
sectors)

Simplify and shorten
planning and permitting
procedures for renewableenergy and hydrogen
infrastructure projects.

However, speed will be of essence!

Facilitate integrated
energy system planningof hydrogen, naturalgas, and electricity
infrastructure supporting
the accelerated deploy­ment and integrationof renewable energy
resources© 2022 European Hydrogen Backbone, all rights reserved

Fostering developmentof new and repurposedhydrogen infrastructure,for example, by un­bundling rules facilitating
the efficient use of TSO
expertise and services andby allowing the adoptionof different vertical un­bundling models in theEU, as is the case withnatural gas

95© 2022 European Hydrogen Backbone,
all rights reserved

TABLE OF CONTENTS

1. Executive Summary
2. Five emerging supply corridors
Corridor A: North Africa & Southern Europe
Corridor B: Southwest Europe & North Africa
Corridor C: North Sea
Corridor D: Nordic and Baltic regions
Corridor E: East and South-East Europe

3. Detailed methodology

96

CORRIDOR D© 2022 European Hydrogen Backbone,
all rights reserved

Nordics& Baltics

97

Agenda
1. Corridor Summary
2. Hydrogen Demand & Supply
3. Supply Costs & Cost-Competitiveness4. National Strategies & Regulation
5. Actions Needed

CORRIDOR D / FACTSHEET

98

Corridor emerges in the Nordics and Baltics providing access to low-costhydrogen supply from vast onshore and offshore wind resources

FinlandSwedenEstonia
Lithuania
LatviaDenmark
PolandGermany
Czechia

Drivers &Opportunities

Major drivers of development are early national decarbonisation targets of Nordic
countries and hydrogen adoption in heavy industry and transport. Key opportunities
include the early development of new H₂ infrastructure in the Bothnian Bay, andregional opportunities for offshore pipelines and salt cavern storage.

Hydrogen Supply& Decarbonization
Potential

H₂ supply potential¹

501 TWh(TWh/year)
184 TWh
2030

Supply Costs& CostCompetitiveness

Cost of H₂
production¹

Actions Needed

1(MtCO₂/year vs. 2019;% reduction)-91 Mt
(12%)

2040

2040

-228 Mt(30%)

Cost competitiveness²
1.5–2.7

2030

2030

2040

2.1–3.8(€/kg of H₂)

Emissions
Reductions

Hydrogendelivered pricevs.
natural gas pricehigh/low,(€/MWh)

75

73

69

59

63

2030

2040

– Fostering development of new and repurposed hydrogen infrastructure– Unlock financing to fast-track hydrogen infrastructure deployment– Simplify and shorten planning and permitting procedures– Facilitate integrated energy system planning of hydrogen, natural gas, andelectricity infrastructure

Figures reported reflect outputs for all countries included in the corridor. Even if a country is only partially in the corridor, results for the full country are included(e.g., supply potential and costs, demand, transmission network length).
2 Savings are based on the corridor’s case study of hydrogen delivered in 2030 and 2040. The cost of natural gas includes CO₂ prices. Refer to Subsection 3 (Supply Costs & Cost-Competitiveness)

60© 2022 European Hydrogen Backbone, all rights reserved

Nordics& Baltics

Corridor D / Nordics & Baltics

CORRIDOR D© 2022 European Hydrogen Backbone,
all rights reserved

Nordics& Baltics

99

Agenda
1. Corridor Summary
2. Hydrogen Demand & Supply
3. Supply Costs & Cost-Competitiveness4. National Strategies & Regulation
5. Actions Needed

CORRIDOR SUMMARY

Corridor D / Nordics & Baltics

Drivers &Opportunities– The major driver behind the development of this corridor isthe adoption of hydrogen associated with the decarbonisationof industry, transport and power in the Nordics, the Baltics,
Poland and Germany. Initially, the development of the corridor
will be driven by new green steel and e-fuel projects and earlynational decarbonisation targets in Sweden and Finland. The
speed of hydrogen adoption in these regions may be even fasterthan anticipated driven by increasing CO₂ prices in the EU andthe RePowerEU ambitions to replace natural gas consumption.
– In the near term, the corridor offers access to abundant lowcost, onshore wind and grid-based hydrogen supply from theNordics. In the longer term, the corridor also provides accessto hydrogen supply from offshore wind in the Nordics and theBaltics.

– A major opportunity of this corridor is the early and accelerated
development of new hydrogen infrastructure in the Bothnian
Bay, one of the earliest, greenfield hydrogen infrastructure projects in
Europe. The early buildout of hydrogen infrastructure also offers an
opportunity to pilot and operationalise new regulatory, planningand permitting processes aiming to accelerate and streamline therollout of hydrogen infrastructure.
– Another set of opportunities includes the development of offshore
pipelines connecting Nordic offshore wind resources to demandcenters in Germany and Central Europe, as well as the potential
development of salt cavern hydrogen storage.
– The corridor would be stood up by 2030, covering 13,500 km oflarge-scale hydrogen pipelines across all countries of the corridor,of which approximately 45% will be repurposed pipelines.

Hydrogen Demand& Supply– Total hydrogen demand in the corridor reaches ~220 TWh
by 2030, increasing substantially to ~725 TWh by 2040. Up
to 2030, most hydrogen demand is driven by the steel sector in
Germany and the Nordics, along with some hydrogen adoption
in transport. From 2040 to 2050, hydrogen demand expands
further in industry and transport and plays a more meaningful rolein power generation.

– Hydrogen adoption across all countries of the corridors enables anemissions reduction of ~290 MtCO₂/yr. by 2050, equivalent to a
39% emissions reduction. Emissions reductions are notoriously
higher than other corridors due to the high emissions reduction
potential in the steel sector.
– The corridor enables access to hydrogen supply potential of ~185 TWhby 2030, increasing to roughly 500 TWh by 2040. Major sourcesof supply include hydrogen from onshore and offshore wind in theNordics, along with grid-based green hydrogen, leveraging the vast,
low-cost hydropower potential of the Nordics.

© 2022 European Hydrogen Backbone, all rights reserved

Corridor offers access to low-cost supply from the Nordics todemand centers along the corridor to Poland and Germany

100

CORRIDOR SUMMARY

Corridor D / Nordics & Baltics

Costs & CostCompeti­tiveness– By 2030, the corridor provides access to hydrogen ranging in
production costs from 2.1 to 3.8 €/kg. By 2040, as supply
options increase and technology costs decrease, hydrogenproduction costs decrease to 1.5 to 2.7 €/kg.
– In the long term, this corridor’s lowest-cost hydrogen supply
options are onshore and offshore wind from the Nordics.

– Based on a case-study of hydrogen supply and transport from theBothnia Bay region of Finland to Germany, the cost of deliveredhydrogen – inclusive of transport and storage costs – can belowered significantly and be cost-competitive with fossil fuelalternatives. Lowering delivery costs can be achieved throughvarious cost levers including optimised operation of the system andcost of capital reductions.

National Strategies& Regulation– Most countries have developed – or are in the processof developing – national strategies. Moving forward, thedevelopment of hydrogen regulation in all countries will be key
in enabling investment in infrastructure.

– In select countries, substantial funding has been allocated tosupport the development of the hydrogen market including funding
for gas network infrastructure.

Actions Needed

To support the buildout of this corridor by 2030, clear and concrete
actions related to infrastructure planning, financing and development
have been identified:– Fostering development of new and repurposed hydrogen
infrastructure.
– Unlock financing to fast-track hydrogen infrastructure
deployment by applying regional regulatory flexibility and otherpragmatic financing solutions.

– Simplify and shorten planning and permitting procedures for thefull value chain of renewable energies and hydrogen infrastructure
projects.
– Establish integrated energy system planning of hydrogen, naturalgas, and electricity infrastructure.

© 2022 European Hydrogen Backbone, all rights reserved

To successfully stand up this corridor by 2030, actions are needed
to support infrastructure planning, financing and development.

101

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all rights reserved

Nordics& Baltics

102

Agenda
1. Corridor Summary
2. Hydrogen Demand & Supply
3. Supply Costs & Cost-Competitiveness4. National Strategies & Regulation
5. Actions NeededHYDROGEN DEMAND & SUPPLY / SECTION INTRODUCTION

Corridor D / Nordics & Baltics

This section explores the development of demand, supply andtransport infrastructure in the corridor from 2030 to 2050
2030 Corridor Snapshot(Supply, Demand and Infrastructure)

103

Hydrogen demand
By 2030, the corridor connects all major industrial clusters from the Nordics
to Germany. By 2040, the corridor expands to all demand centers along its
route, increasing demand from 220 to 725 TWh.

Hydrogen supply
Pipelines
Repurposed
New
Import / Export
SubseaDemand per sector

By 2030, the corridor enables access to low-cost, hydrogen supply fromparts of the Nordics. By 2040, the corridor expands access to supply acrossthe Nordics and into the Baltics.
In 2030, hydrogen supply is ~185 TWh, of which nearly 70% is dedicated greenhydrogen. Hydrogen supply increases significantly by 2040, reaching 500 TWh.

40 / 30 / 20 / 10 / 1 TWh
Efuels production
Industrial energy
Industrial feedstockPower

Storages
Salt cavern
Aquifer
Depleted field
Rock cavern
Other items
Existing or planned
gas-import-terminal
Energy island forH₂ production

Grid-based

Dedicated green

Blue

Hydrogen Infrastructure
By 2030, the buildout of pipeline infrastructure across all countries of thecorridor reaches 13,500 km of large-scale pipelines. Notably, this corridor
includes a large share of new pipeline infrastructure.
45% (Repurposed pipelines)

55% (New pipelines)

13,500 km (2030)© 2022 European Hydrogen Backbone, all rights reserved

Supply in MWh/km²<1
1 – 2525 – 100
100 – 250
250 – 500
> 500

184 TWh (2030)

HYDROGEN DEMAND & SUPPLYCorridor D / Nordics & Baltics

2030

2040

Pipelines
Repurposed
New
Import / Export
SubseaPipelines
Repurposed
New
Import / Export
SubseaDemand per sector

Demand per sector

40 / 30 / 20 / 10 / 1 TWh

40 / 30 / 20 / 10 / 1 TWh

Efuels production
Industrial energy
Industrial feedstockPower

Efuels production
Industrial energy
Industrial feedstockPower

Storages
Salt cavern
Aquifer
Depleted field
Rock cavern

Storages
Salt cavern
Aquifer
Depleted field
Rock cavern

Other items
Existing or planned
gas-import-terminal
Energy island forH₂ production

Other items
Existing or planned
gas-import-terminal
Energy island forH₂ production© 2022 European Hydrogen Backbone, all rights reserved

Corridor connects major hydrogen clusters from the Nordics toGermany by 2030, expanding to all major demand centers by 2040

104

HYDROGEN DEMAND & SUPPLYCorridor D / Nordics & Baltics

Hydrogen demand increases rapidly from 2030 to 2040,
largely driven by Germany, Poland and the Nordics
2030

2040

2050

66

Hydrogen demand – across all countries of
the corridor – increases significantly from2030 to 2050. Demand reaches ~220 TWh by
2030, increasing to roughly 970 TWh by 2050.

General H₂ flow

Total demand per country (TWh/y)Finland25

53

Sweden

50

100

123

Estonia022

Latvia0

13Lithuania

5

15

20

Denmark

27

52

67

Poland22

Czechia
Total

120

90

Germany– Up to 2030, most hydrogen demand isdriven by the industrial sector in Sweden
and Germany – primarily related to theadoption of hydrogen in the steel sector.
– From 2040 to 2050, most new hydrogen
demand is for e-fuels production andfor power generation, with demand in
Finland, Denmark and Poland contributing an
increasing share.

505

17
224

Hydrogen demand may accelerate andincrease further than forecasted as a resultof additional regulatory measures adopted in
response to the RePowerEU plan.

155
363

5

Early national decarbonisation targets
in Sweden (2045) and Finland (2035) also
contribute to early adoption.

27
725

Note: Does not include grey hydrogen demand. Numbers represent total demand by country, even if only parts of the country are included in the corridor.

969© 2022 European Hydrogen Backbone, all rights reserved

Country105

HYDROGEN DEMAND & SUPPLYCorridor D / Nordics & Baltics

Hydrogen adoption in all countries of the corridor
enables an emissions reduction of 39% by 2050
-12 %

-30%

-39 %

Hydrogen adoption across all demand
sectors enables an emissions reduction of~290 MtCO₂/yr. by 2050, equivalent to a
39% reduction².

292

Emissions reductions are notoriously higher
than other corridors due to the high emissions
reduction potential in the steel sector.

Decarbonisationin Mt CO₂ / year
300

250

– Up to 2030, the industrial sector contributes
70% of the total emissions reductions, largely
driven by the steel sector in Sweden andGermany.

228

200– By 2040, emissions reductions from trans­
port (road, shipping and aviation) increasesub­stantially and combined with industry,account for 80% of emissions reductions.
The power sector account for the remaining
20% of reductions.

150

100

91

50
IndustryPower
Buildings
Transport

02030© 2022 European Hydrogen Backbone, all rights reserved

2040

2050

– By 2050, emissions reductions from thetransport and power sector continue rising.
1

CO₂-Emissions from countries and sectors included in corridor (0.75 bn t CO₂ / year),
Source: EEA
2 Emissions reductions are calculated compared to the baseline fossil fuel used in eachsectors. For example, emissions reductions associated with the adoption of hydrogen by the
primary steel sector are relative to the use of coal. Similarly, emissions reductions, for e-fuels
production are relative to the use of fossil fuels in shipping, aviation and other uses.

© 2022 European Hydrogen Backbone, all rights reserved

Emissions reductions(vs. 2019 emissions¹)

106

HYDROGEN DEMAND & SUPPLYCorridor D / Nordics & Baltics

Corridor enables access to supply from parts of the Nordics
by 2030, expanding to supply from the Baltics by 2040

Pipelines
Repurposed
New
Import / Export
SubseaSupply in MWh/km²<1
1 – 2525 – 100
100 – 250
250 – 500
> 500
Storages
Salt cavern
Aquifer
Depleted field
Rock cavern
Other items
Existing or planned
gas-import-terminal
Energy island forH₂ production
Total hydrogen supply shown per NUTS-2 region. MWhadjusted by the area of each NUTS-2 region in km².
* Note: Supply numbers do not include grey hydrogen.

2040*

Pipelines
Repurposed
New
Import / Export
SubseaSupply in MWh/km²<1
1 – 2525 – 100
100 – 250
250 – 500
> 500
Storages
Salt cavern
Aquifer
Depleted field
Rock cavern
Other items
Existing or planned
gas-import-terminal
Energy island forH₂ production© 2022 European Hydrogen Backbone, all rights reserved

2030*

107

HYDROGEN DEMAND & SUPPLYCorridor D / Nordics & Baltics

Hydrogen supply increases significantly from 2030 to 2040,
largely driven by green hydrogen supply from the Nordics
2030

2040

SupplyFinlandSwedenGeneral H₂ flow

Estonia
LatviaLithuania
Denmark
PolandGermany
Czechia
Total

51

Net¹
36

10

52

14

12

1

1 0.1

-0.4

0

-5

1

25

12

15

-19

3

-75

15

-4

0.1

130

54

2050

Supply

79

Net¹
40

14

107

18

19 0.1

7

9

-7

9

39

48

21

-77

4

81

-261

21

-17

0.1

-41

1 Net represents excess supply after subtracting demand.
2 Grid-based is estimated using national 2030 electrolyser targets which, by 2030, are assumed to be largely
grid-connected rather than dedicated. Grid-based increases over 2030-2050 with increasing RES.

423

121

24

18

80

Supply

78

-223

143

Net¹
73

18

42

23

33

35 0.1

18

20

-5

15

115

115

165

75

27

-42

27

-313

27

-27

0.1

722

Dedicated green
Blue
Grid-based
2050 technical potential

101

-146

The hydrogen supply mix includes grid-based
green hydrogen² and dedicated greenhydrogen.
– By 2030, hydrogen supply reaches~185 TWh, largely from dedicated greenhydrogen and grid-based hydrogen.
– By 2040, hydrogen supply increases
substantially to ~500 TWh, of which roughly
85% is from dedicated green hydrogen.
The remaining 15% is from grid-basedhydrogen supply. Grid-based supply increases
slightly from 2030 due to the increasing
decarbonization of the electricity grid mix.
– By 2050, hydrogen supply increases
further to ~820 TWh. Dedicated green
supply continues to account for the largest
share at roughly 90%.
Hydrogen supply may accelerate andincrease further as a result of additional
regulatory measures adopted in response to
the RePowerEU plan.

Note: Hydrogen supply volumes do not include hydrogen imports by ship.

© 2022 European Hydrogen Backbone, all rights reserved

Country108

CORRIDOR D© 2022 European Hydrogen Backbone,
all rights reserved

Nordics& Baltics

109

Agenda
1. Corridor Summary
2. Hydrogen Demand & Supply
3. Supply Costs & Cost-Competitiveness4. National Strategies & Regulation
5. Actions Needed

SUPPLY COSTS & COST-COMPETITIVENESS / SECTION INTRODUCTION

Corridor D / Nordics & Baltics

This section explores the costs of hydrogen production and delivery
for this corridor and their competitiveness with fossil fuels
Hydrogen delivered costs

Comparison with fossil alternatives

What is the range of production costs
achieved by the corridor in 2030 and
2040?

Based on a case-study of hydrogen supply
from the Bothnian Bay (Finland) to Germany:– What are the full costs of firm hydrogendelivery after accounting for transportand storage costs?
– What cost levers are available to lower thecost of hydrogen delivery?

How competitive is hydrogen supply
from this corridor compared to fossil fuelalternatives?

-33 %

Lith
ua
nia

0.2

Levelised cost of hydrogen production (€/kg) and Supply per country (TWh)Cost range (€/kg)

2.5
100

0
Imports
Blue hydrogen

200

2.0

Wind offshore
Wind onshore

1.5

Solar PV
Grid-connected

300

400

500

2040

Case study (see next slide)

High
Low

2.1

1.0
1-3 See previous slide

0.5
0.0
0

10

20

Imports
Blue hydrogen

30

40

Wind offshore
Wind onshore

50

60

Solar PV
Grid-connected

70

80

90

100

110

120

130

140

150

160

170

180

Case study (see next slide)1 Cost curves are based on a bottom-up estimate of supply volumes per country and hydrogen production type. No transport or storage / firming cost are included.
2 Dedicated hydrogen production costs are based on renewable technology and electrolyser costs, and country-specific capacity factors and discount rates.
3 Grid-connected hydrogen production costs are determined based on costs of a mix of dedicated green hydrogen (solar, onshore wind, offshore wind) and adjusted for grid-connection costs.

Key Findings& Results

0.04

2.3

190

2030
High
Low

Baseline costsof H₂ production(€/kg)© 2022 European Hydrogen Backbone, all rights reserved

3.8

3.0

0

0.1

2.5

– By 2030, the corridor provides accessto hydrogen production costs of 2.1 to
3.8 €/kg.
– By 2040, hydrogen production costs
decrease to the range of 1.5 to 2.7 €/kg.

Transport &firming cost

Cost of H₂delivered

Optimisedsystem sizing

Battery storage
operation

Powerelectronics
savings

Reduced costof capital

Optimised costof H₂ delivered(€/kg)

1 Transport costs are based on several parameters including the type of pipeline (repurposed vs. new), transport distance and full-load-hour production on that pipeline. Firming costs are based on
additional storage cost required to deliver hydrogen at the equivalent of 8,000 full-load hours.
2 Optimised system sizing refers to right-sizing of solar PV and electrolyser capacity to increase full load hours. Similarly, battery storage operation enables an increase in the full load hours. Power
electronics savings refers to the removal of the inverter of the solar PV modules to reduce system cost. Reduced cost of capital refers to the use of foreign investment to reduce the WACC from 8 to 6%.
3 In some instances, cost reduction levers may result in cost increases for certain cost-components. For example, an increase in production costs at the same time as a decrease in firming costs. These cost
increases and decreases can result in connection lines that do not directly connect one step to the next.

Delivered Costs (€/kg)(before and after cost levers)
2030

2040

Before costs lever

3.7

3.1

After costs lever

2.5

2.0

Cost of fossil
fuel alternatives€/MWh

Production
costs(=3.5 €/kg)

Cost of fossil
fuel alternatives€/MWh89‒115
105

Fuel cost
uncertainty

85‒88
59‒73

– In 2040, hydrogen delivered
costs can be reduced by 35%(3.1 vs. 2.0 €/kg).

Transport
Firming
Production

2040

Production
costs– In 2030 (shown on the left),the cost of delivered hydrogencan be lowered by 33% (3.7 vs.
2.5 €/kg).

1.5© 2022 European Hydrogen Backbone, all rights reserved

Fin
lan
d

Sw
ed
en

Sw
ed
en

Fin
lan
d

G
er
m
an
Lith y
ua
nia
Po
lan
d

3.5

De
nm
ar
k

4.0

Fin
la
Sw nd
e ,
De den
nm ,
ar
k

De
nm
ar
k

1.0
0.5

1.0

2.7

2.0
1.5

3.7

2030

Cost reduction levers applied tocase study of hydrogen transport
from the Bothnian Bay to Germany
enable firm delivery costs to be
reduced significantly.

Cost Reductions Levers

90

78
63‒69

83‒95

(=3.5 €/kg)

62‒69

66 €/MWh

Case study
Deliveredcost of H₂
1.8 €/kg

54 €/MWh48– Several cost reduction levers can beapplied to lower the costs of hydrogendelivery.
– For the Bothnian Bay-to-Germany casestudy, these levers achieve delivery
costs that are low and cost-competitive.

Case study
Deliveredcost of H₂
2.2 €/kg(=1.6 €/kg)

H₂ production
cost-range
Higher Cost H₂Lower Cost H₂NaturalGas
Fuel cost
CO₂ cost

Steam
Coal

Oil

45

(=1.6 €/kg)

H₂ production
cost-range

Natural
Gas

Steam
Coal

Oil

Fuel uncertain

Note: Prices for fossil alternatives (2030/2040): Natural gas (pre-invasion): 28/13 [€/MWh], Coal: 123/5.6 [€/MWh], Oil: 52/24 [€/MWh]. Natural gas prices levels are based on market conditions before Russia’s invasion of Ukraine. While natural gas prices
have skyrocketed since, there remains significant uncertainty on near- and medium-term European price trends and supply options. As a result, our analysis adopts the IEA’s Outlook 2021 price forecast pre-invasion developed pre-invasion. Prices in 2040
are significantly lower than in 2030 because of demand-supply conditions. By 2040, decreased demand for fossil fuels would lower prices. [Source: International Energy Agency, Outlook 2021 (IEA)] and fuel-cost uncertainty is shown with +50% range]– By 2030, the low range ofhydrogen production costs
are lower than all fossil
alternatives.
– By 2040, the low-to-medium
range of hydrogen costs arematerially lower than all
fossil alternatives, while themedium-to-high range are costcompetitive.
– Hydrogen delivered costs fromthe North Sea-to-Germany casestudy are competitive to natural
gas in 2030 (12% higher) andlower in 2040 (13% lower).
– Natural gas prices are still
uncertain due to recent pricespike as a result of the Russian
invasion of Ukraine
Note: For comparison purposes, cost of H₂ has been converted from“per kg” to “per MWh”
– 1 €/kg = 30 €/MWh (based on LHV of 33.3 kWh/kg)
Competitiveness of hydrogen highly dependant on CO₂-prices as they
make up a significant part of fossil fuel costs.
– CO₂ price 2030: 130 €/t– CO₂ price 2040: 205 €/t– Hydrogen costs are competitive withfossil fuel alternatives by 2030, andlower by 2040.
– Fossil fuel costs are subject to significant
uncertainty.

© 2022 European Hydrogen Backbone, all rights reserved

Baseline Costs

1.4

Hydrogen Production Cost Range [2030]¹, ², ³

2.5

Cost of Hydrogen Delivered (€/kg) in 2030¹, ², ³

111
Cost range (€/kg)

Po
lan
d

Sw
ed
en

G
er
m
an
y

G
er
m
an
y
G
er
m
an
y

Fin
la
Es nd,
to
nia

Sw
ed
en

G
er
m
an
y

De
nm
ar
k

Sw
ed
en

InLevelised
2030,
the corridor offers access to hydrogencost of hydrogen production (€/kg) and Supply per country (TWh)production ranging in costs from 2.1 to 3.8 €/kg

Corridor C / North Sea

Hydrogen costs are cost-competitive with all fossil
alternatives by 2030, and lower by 2040.

114© 2022 European Hydrogen Backbone, all rights reserved

Corridor D / Nordics & Baltics

SUPPLY COSTS & COST-COMPETITIVENESS

Corridor D / Nordics & Baltics

Applying cost reduction levers to the Bothnian Bay-to-Germany case study
lowers delivery costs significantly and keep hydrogen cost-competitive

112

SUPPLYCOSTS& COST-COMPETITIVENESS
Hydrogen Production
Cost
Range
[2040]¹, ², ³

3.0

SUPPLY COSTS & COST-COMPETITIVENESS / CASE STUDY

Corridor D / Nordics & Baltics

By 2040, hydrogen supply options increase and scale up
leading to production costs ranging from 1.5 to 2.7 €/kg

© 2022 European Hydrogen Backbone, all rights reserved

SUPPLY COSTS & COST-COMPETITIVENESS

De
nm
ar
k

Content
Material

Hydrogen production costFin
Sw lande
De de ,
nm n,
ar
k
Fin
lan
d

Key Questions
Answered110

SUPPLY COSTS & COST-COMPETITIVENESS

Corridor D / Nordics & Baltics

In 2030, the corridor offers access to hydrogenproduction ranging in costs from 2.1 to 3.8 €/kg

111

Hydrogen Production Cost Range [2030]¹, ², ³

G
er
m
an
y
Lit
hu
an
ia
Po
lan
d

Cost range (€/kg)

Fin
lan
d

Sw
ed
en

Sw
ed
en

De
nm
ar
k

Fin
lan
d

Fin
l
Sw and
ed ,
De en
nm ,
ar
k

De
nm
ar
k

Levelised cost of hydrogen production (€/kg) and Supply per country (TWh)

4.0

3.8

3.5
3.0
2.5
2.0
1.5
1.0
0.5
0.0
0

10

20

Imports
Blue hydrogen

30

40

Wind offshore
Wind onshore

50

60

Solar PV
Grid-connected

70

80

90

100

110

120

130

140

150

160

170

180

Case study (see next slide)1 Cost curves are based on a bottom-up estimate of supply volumes per country and hydrogen production type. No transport or storage / firming cost are included.
2 Dedicated hydrogen production costs are based on renewable technology and electrolyser costs, and country-specific capacity factors and discount rates.
3 Grid-connected hydrogen production costs are determined based on costs of a mix of dedicated green hydrogen (solar, onshore wind, offshore wind) and adjusted for grid-connection costs.

190

2030
High
Low

© 2022 European Hydrogen Backbone, all rights reserved

2.1

SUPPLY COSTS & COST-COMPETITIVENESS

Corridor D / Nordics & Baltics

By 2040, hydrogen supply options increase and scale up
leading to production costs ranging from 1.5 to 2.7 €/kg

112

Hydrogen Production Cost Range [2040]¹, ², ³

Po
lan
d

Sw
ed
en

G
er
m
an
y

G
er
m
an
y
G
er
m
an
y

Cost range (€/kg)

2.7

Lit
hu
an
ia

3.0

Fin
la
Es nd,
to
nia

Sw
ed
en

G
er
m
an
y

De
nm
ar
k

Sw
ed
en

Fin
Sw lande
De de ,
nm n,
ar
k
Fin
lan
d

De
nm
ar
k

Levelised cost of hydrogen production (€/kg) and Supply per country (TWh)

2.5
2.0
1.5
1.0
0.5
0
0

100
Imports
Blue hydrogen

1-3 See previous slideWind offshore
Wind onshore

200
Solar PV
Grid-connectedCase study (see next slide)

300

400

500

2040
High
Low

© 2022 European Hydrogen Backbone, all rights reserved

1.5

SUPPLY COSTS & COST-COMPETITIVENESS / CASE STUDY

Corridor D / Nordics & Baltics

Hydrogen delivered costs, incl. transport and storage costs,
can be kept low by applying cost reduction levers
analysis assesses a case study of hydrogen supply from onshore
1 Thiswind in the Bothnian Bay (Finland) to industrial offtakers in Germany to
explore how the costs of firm hydrogen delivery can be lowered.

assess the full cost of firm hydrogen delivery to Germany, transport
2 To
and storage costs are added to the cost of hydrogen production
from the Bothnian Bay.

Transport
Costs+

Storage
Costs=

Pipelines
Repurposed
New
Import / Export
SubseaDelivered
Costs

cost reduction levers are applied to lower firm delivery costs,
3 Several
including optimised system operation, battery storage use, cost of capital
reductions, among others.

4

Corridor Case
Study Route

These cost reduction levers achieve sufficient cost savings tokeep firm hydrogen delivery costs low and cost-competitive.

© 2022 European Hydrogen Backbone, all rights reserved

Production
Costs

+

113

SUPPLY COSTS & COST-COMPETITIVENESS / CASE STUDY

Corridor D / Nordics & Baltics

Applying cost reduction levers to the Bothnian Bay-to-Germany case study
lowers delivery costs significantly and keep hydrogen cost-competitive
Cost of Hydrogen Delivered (€/kg) in 2030¹, ², ³

Cost reduction levers applied tocase study of hydrogen transport
from the Bothnian Bay to Germany
enable firm delivery costs to be
reduced significantly.

Cost Reductions Levers

-33 %
1.4

3.7

1.0

0.2

0.1

0.04

2.3

Baseline costsof H₂ production(€/kg)

Transport &firming cost

Cost of H₂delivered

Optimisedsystem sizing

Battery storage
operation

Powerelectronics
savings

Reduced costof capital

2.5

Optimised costof H₂ delivered(€/kg)

Transport costs are based on several parameters including the type of pipeline (repurposed vs. new), transport distance and full-load-hour production on that pipeline. Firming costs are based on
additional storage cost required to deliver hydrogen at the equivalent of 8,000 full-load hours.
2 Optimised system sizing refers to right-sizing of solar PV and electrolyser capacity to increase full load hours. Similarly, battery storage operation enables an increase in the full load hours. Power
electronics savings refers to the removal of the inverter of the solar PV modules to reduce system cost. Reduced cost of capital refers to the use of foreign investment to reduce the WACC from 8 to 6%.
3 In some instances, cost reduction levers may result in cost increases for certain cost-components. For example, an increase in production costs at the same time as a decrease in firming costs. These cost
increases and decreases can result in connection lines that do not directly connect one step to the next.
1– In 2030 (shown on the left),the cost of delivered hydrogencan be lowered by 33% (3.7 vs.
2.5 €/kg).
– In 2040, hydrogen delivered
costs can be reduced by 35%(3.1 vs. 2.0 €/kg).

Transport
Firming
Production

Delivered Costs (€/kg)(before and after cost levers)
2030

2040

Before costs lever

3.7

3.1

After costs lever

2.5

2.0

© 2022 European Hydrogen Backbone, all rights reserved

Baseline Costs

114

SUPPLY COSTS & COST-COMPETITIVENESS

Corridor D / Nordics & Baltics

Hydrogen costs are cost-competitive with all fossil fuelalternatives by 2030, and materially lower by 2040.
2040

Production
costs

Cost of fossil
fuel alternatives

Production
costs

€/MWh

Cost of fossil
fuel alternatives

€/MWh
114

89‒115(=3.8 €/kg)

Fuel cost
uncertainty

85‒88
59‒73

63

81

63‒69

Higher Cost H₂Lower Cost H₂(=2.7 €/kg)

75 €/MWh

Case study
Deliveredcost of H₂
2.0 €/kg

63‒69
60 €/MWh(=2.1 €/kg)

H₂ production
cost-range

83‒95

Case study
Deliveredcost of H₂
2.5 €/kg

NaturalGas
Fuel cost
CO₂ cost

Steam
Coal

Oil

45

(=1.5 €/kg)

H₂ production
cost-range

Natural
Gas

Steam
Coal

Oil

Fuel uncertain

Note: Prices for fossil alternatives (2030/2040): Natural gas (pre-invasion): 28/13 [€/MWh], Coal: 123/5.6 [€/MWh], Oil: 52/24 [€/MWh]. Natural gas prices levels are based on market conditions before Russia’s invasion of Ukraine. While natural gas prices
have skyrocketed since, there remains significant uncertainty on near- and medium-term European price trends and supply options. As a result, our analysis adopts the IEA’s Outlook 2021 price forecast pre-invasion developed pre-invasion. Prices in 2040
are significantly lower than in 2030 because of demand-supply conditions. By 2040, decreased demand for fossil fuels would lower prices. [Source: International Energy Agency, Outlook 2021 (IEA)] and fuel-cost uncertainty is shown with +50% range]– By 2030, the low range ofhydrogen production costs arecompetitive with natural gas
and coal, and lower than oilalternatives.
– By 2040, the low range ofhydrogen costs are materiallylower than all fossil alternatives, while the medium-to-highrange are cost competitive.
– Hydrogen delivered costs fromthe Bothnian Bay-to-Germany
case study are competitive
to natural gas in 2030 (27%higher) and lower in 2040 (5%lower).
– Natural gas prices are still
uncertain due to recent pricespike as a result of the Russian
invasion of Ukraine
Note: For comparison purposes, cost of H₂ has been converted from“per kg” to “per MWh”
– 1 €/kg = 30 €/MWh (based on LHV of 33.3 kWh/kg)
Competitiveness of hydrogen highly dependant on CO₂-prices as they
make up a significant part of fossil fuel costs.
– CO₂ price 2030: 130 €/t– CO₂ price 2040: 205 €/t© 2022 European Hydrogen Backbone, all rights reserved

2030

115

CORRIDOR D© 2022 European Hydrogen Backbone,
all rights reserved

Nordics& Baltics

116

Agenda
1. Corridor Summary
2. Hydrogen Demand & Supply
3. Supply Costs & Cost-Competitiveness4. National Strategies & Regulation
5. Actions Needed

NATIONAL STRATEGIES & REGULATIONSCorridor D / Nordics & Baltics

Most countries have developed, or are developing, national strategies. Moving
forward, the development of regulation is key to enable infrastructure investment.
Highlights

PreRePowerEU
targets²

National Hydrogen strategy (NHS)

Network regulation & policy

Finland– H₂ strategy part of National Climate & Energy Plan, with focus on production(via wind resources) and industrial use of green H₂– Act on Guarantees of Origin for Energy extended to gas &H₂

Sweden– Focus on industry & heavy-duty vehicles– Electrolyser capacity 5 GW (2030) & 15 GW (2045)– National H₂ strategy requests regulator to have commissioned
revenue framework by 2023

Estonia– Intention to create national hydrogen strategy– N/A– Potential for local production and export

Latvia– No specific national hydrogen strategy– N/A– Most potential is seen in transport sector

Lithuania– National hydrogen strategy is in progress– Legal framework allows issue guarantees of origin forhydrogen– Potential for production, transit and export

Denmark– Focus on green H₂ and export of PtX technologies to demand hubs (GER,
NL, etc.)– Proposition: Allow TSO & DSO to own and operate H₂
infrastructure

Poland– Focus: Power/heat sector, transport, industry, production, network, creating
regulatory framework– Creation of regulatory framework mentioned in H₂ strategy– Gas network to be adapted & new build: “Hydrogen
Highway” (North-South)

Germany– National production & import focus due to supply gap– In place since 2020, currently reviewed towards increasing its ambition– 10 GW (2030) electrolyser in coalition plans– H₂ network potentially opt-in regulated and verticallyunbundled– First rules and standards for high pressure pipelines areformulated– Strong focus on international cooperation to ensuresufficient supply– National funding

Czech Republic– Focus Transport, then energy & chemical industry– Production also CCS and nuclear– Import and transit country for H₂ from the south

– N/A

0.2

– Recommended to build 1st dedicated H₂ pipelines– Significant additional potential for wind power and e-fuels
production, chemicals and fertilisers.

0.1– •Funding is provided to various hydrogen projects fordemand and supply by the Swedish Energy Agency

0.16– Transport infrastructure is seen as key to enable role as PtX
producer and exporter

0.2

9– H₂-Readiness of gas transmission system is urged, due topotential role in H₂ transport from south to north and fromeast to west

General funding
SupplyNetwork
Demand© 2022 European Hydrogen Backbone, all rights reserved

Note: Sequencing of countries follows the general corridor direction but does not represent the hydrogen flows.
1 Cumulative public funding amount by the respective state until 2030
2 Strategies and funding is under evaluation of meeting latest targets

Funding¹ (bn €)117

CORRIDOR D© 2022 European Hydrogen Backbone,
all rights reserved

Nordics& Baltics

118

Agenda
1. Corridor Summary
2. Hydrogen Demand & Supply
3. Supply Costs & Cost-Competitiveness4. National Strategies & Regulation
5. Actions Needed

ACTIONS NEEDEDCorridor D / Nordics & Baltics

This corridor plays a fundamental role in achieving
a European backbone by 2040
– The development of this corridor ensures access to abundant, low-costsupply from parts of the Nordics by 2030, expanding to supply from theBaltics by 2040.
– The decarbonisation of the largest hydrogen demand centers along
this corridor – in the Nordics, Baltics, Poland and Germany – isdependent on the buildout of this corridor by 2030, and its expansion
towards 2040.
Actions required– The buildout of this corridor by 2030 requires national governments totake clear and concrete actions across.
– This includes actions associated with infrastructure development andplanning, the development of cross-national initiatives and securing
access to early funding and long-term, low-cost financing.

2040
Pipelines
Repurposed
New
Import / Export
SubseaDemand per sector

40 / 30 / 20 / 10 / 1 TWh
Efuels production
Industrial energy
Industrial feedstock
Power
Supply in MWh/km²<1
1 – 2525 – 100
100 – 250
250 – 500
> 500
Storages
Salt cavern
Aquifer
Depleted field
Rock cavern
Other items
Existing or planned
gas-import-terminal
Energy island forH₂ production© 2022 European Hydrogen Backbone, all rights reserved

The need for this corridor

119

ACTIONS NEEDEDCorridor D / Nordics & Baltics

To ensure the development of this corridor by 2030,
there is a need for clear and concrete actions

Unlock financing tofast-track hydrogen
infrastructure deploy­ment by applying regional
regulatory flexibility andother pragmatic financing
solutions (including
incentivizing the adoptionof hydrogen by demand
sectors)

Simplify and shorten
planning and permitting
procedures for renewableenergy and hydrogen
infrastructure projects.

However, speed will be of essence!

Facilitate integrated
energy system planningof hydrogen, naturalgas, and electricity
infrastructure supporting
the accelerated deploy­ment and integrationof renewable energy
resources© 2022 European Hydrogen Backbone, all rights reserved

Fostering developmentof new and repurposedhydrogen infrastructure,for example, by unbund­ling rules facilitating theefficient use of TSO
expertise and services andby allowing the adoptionof different vertical un­bund­ling models in theEU, as is the case withnatural gas

120© 2022 European Hydrogen Backbone,
all rights reserved

TABLE OF CONTENTS

1. Executive Summary
2. Five emerging supply corridors
Corridor A: North Africa & Southern Europe
Corridor B: Southwest Europe & North Africa
Corridor C: North Sea
Corridor D: Nordic and Baltic regions
Corridor E: East and South-East Europe

3. Detailed methodology

121

CORRIDOR E© 2022 European Hydrogen Backbone,
all rights reserved

East andSouth-East Europe

122

Agenda
1. Corridor Summary
2. Hydrogen Demand & Supply
3. Supply Costs & Cost-Competitiveness4. National Strategies & Regulation
5. Actions Needed

CORRIDOR E

Corridor E / East and South-East Europe

GreeceBulgaria
Romania
Hungary

Slovenia
Croatia
Slovakia
Czechia

Corridor emerges in Eastern & South-Eastern Europe providing accessto low-cost hydrogen supply to demand centers along the corridor

Austria
Germany
PolandDrivers &Opportunities
Hydrogen Supply& Decarbonization
Potential

Major driver of development is the need to meet hydrogen demand fromindustry, transport and power across Eastern and South-Eastern Europe.
Key opportunities include leveraging the abundant renewables potential in
Eastern Europe and gaining access to hydrogen imports from Ukraine
H₂ supply potential¹
Emissions
2030
2040
346 TWh(TWh/year)
Reductions(MtCO₂/year vs. 2019;% reduction)-65 Mt(7%)

50 TWh2030

Supply Costs& CostCompetitiveness

Cost of H₂
production¹

1

Cost competitiveness²
1.7–3.1

2030

Actions Needed2040

2.5–4.5(€/kg of H₂)-195 Mt
(21%)

2040

Hydrogendelivered pricevs.
natural gas pricehigh/low,(€/MWh)

75

73
59

2030

69
62

2040

– Fostering development of new and repurposed hydrogen infrastructure– Unlock financing to fast-track hydrogen infrastructure deployment– Simplify and shorten planning and permitting procedures– Facilitate integrated energy system planning of hydrogen, natural gas, andelectricity infrastructure– Intensify energy partnerships with exporting, non-EHB countries like Ukraine

Figures reported reflect outputs for all countries included in the corridor. Even if a country is only partially in the corridor, results for the full country are included (e.g., supply potential and costs,
demand, transmission network length).
2 Savings are based on the corridor’s case study of hydrogen delivered in 2030 and 2040. The cost of natural gas includes CO₂ prices. Refer to Subsection 3 (Supply Costs & Cost-Competitiveness)

54© 2022 European Hydrogen Backbone, all rights reserved

East andSouth-East Europe

123

CORRIDOR E© 2022 European Hydrogen Backbone,
all rights reserved

East andSouth-East Europe

124

Agenda
1. Corridor Summary
2. Hydrogen Demand & Supply
3. Supply Costs & Cost-Competitiveness4. National Strategies & Regulation
5. Actions Needed

CORRIDOR SUMMARY

Corridor E / East and South-East Europe

Drivers &Opportunities– The major driver behind the development of this corridor is the
adoption of hydrogen associated with the decarbonisation ofindustry, transport and power across Eastern and South-Eastern
Europe, particularly new green steel projects and existing industry
along the corridor through Greece, Romania, Hungary, Austria
and Germany. The speed of hydrogen adoption in these regions
may be even faster than anticipated driven by increasing CO₂
prices in the EU and the RePowerEU ambitions to replace natural
gas consumption.
– In the near term, the corridor offers access to low-cost,hydrogen supply from Eastern and South-Eastern
Europe – including hydrogen imports from Ukraine, Poland,
Greece, and Romania among the larger sources of supply. In thelonger term, this corridor gains further access to hydrogen supply
across the entire region.

– A major opportunity of the corridor is to leverage the abundant
renewables potential in Eastern Europe with its vast land availability
and high-capacity factors for solar and onshore wind, particularly in
relation to the high hydrogen export potential of Ukraine. Anothermajor opportunity relates to the potential for hydrogen storage
provided by depleted fields along the corridor in Greece,
Czechia, Austria and Germany.
– The corridor would be stood up by 2030, covering 10,000 km oflarge-scale hydrogen pipelines across all countries of the corridor, of
which approximately 60% will be repurposed pipelines.

Hydrogen Demand& Supply– Total hydrogen demand in the corridor reaches ~165 TWhby 2030, increasing substantially to ~660 TWh by 2040. Up
to 2030, the major driver of hydrogen adoption is the industrial
sector, with hydrogen being used as feedstock. From 2040
onwards, most new hydrogen demand is for the transport and thepower sectors.

– Hydrogen adoption across all countries of the corridors enables anemissions reduction of ~260 MtCO₂/yr. by 2050, equivalent to a 28%
emissions reduction.
– The corridor enables access to hydrogen supply potential of~50 TWh by 2030, increasing to roughly 350 TWh by 2040.
Major sources of supply include grid-connected hydrogen production
by 2030, with a huge potential role for Ukrainian imports by 2040.

© 2022 European Hydrogen Backbone, all rights reserved

Corridor offers access to low-cost hydrogen supply from Easternand South-Eastern Europe to demand centers along the corridor

125

CORRIDOR SUMMARY

Corridor E / East and South-East Europe

Costs & CostCompeti­tiveness– By 2030, the corridor provides access to hydrogen ranging in
production costs from 2.5 to 4.5 €/kg. By 2040, as supply
options increase, technology costs decrease, and imports from
Ukraine scale up, hydrogen production costs decrease to 1.7 to
3.1 €/kg.
– In the long term, this corridor’s largest amounts of low-cost supply
options are hydrogen imports from Ukraine.

– Based on a case-study of hydrogen supply and transport fromSouth-Eastern Romania to Germany, the cost of deliveredhydrogen – inclusive of transport and storage costs – can belowered significantly and be cost-competitive with fossil fuelalternatives. Lowering delivery costs can be achieved throughvarious cost levers including optimised operation of the system andcost of capital reductions.

National Strategies& Regulation– Some countries have developed national strategies, whilein others they are under development. Moving forward, thedevelopment of hydrogen regulation in all countries will be key inenabling investment in infrastructure.

– In select countries, substantial funding has been allocated tosupport the development of the hydrogen market including funding
for gas network infrastructure. However, most countries are yet todefine and earmarked funds.

Actions Needed

To support the buildout of this corridor by 2030, clear and concrete
actions related to infrastructure planning, financing and development
have been identified:– Fostering development of new and repurposed hydrogen
infrastructure.
– Unlock financing to fast-track hydrogen infrastructure
deployment by applying regional regulatory flexibility and otherpragmatic financing solutions.

– Simplify and shorten planning and permitting procedures for thefull value chain of renewable energies and hydrogen infrastructure
projects.
– Establish integrated energy system planning of hydrogen, naturalgas, and electricity infrastructure– Intensify energy partnerships with exporting, non-EHB countries
like Ukraine.

© 2022 European Hydrogen Backbone, all rights reserved

To successfully stand up this corridor by 2030, actions are needed
to support infrastructure planning, financing and development

126

CORRIDOR E© 2022 European Hydrogen Backbone,
all rights reserved

East andSouth-East Europe

127

Agenda
1. Corridor Summary
2. Hydrogen Demand & Supply
3. Supply Costs & Cost-Competitiveness4. National Strategies & Regulation
5. Actions NeededHYDROGEN DEMAND & SUPPLY / SECTION INTRODUCTION

Corridor E / East and South-East Europe

This section explores the development of demand, supply andtransport infrastructure in the corridor from 2030 to 2050
2030 Corridor
Snapshot(Supply, Demandand Infrastructure)

128

Hydrogen demand
By 2030, the corridor connects major demand clusters across Eastern andSouth-Eastern Europe. From 2030 to 2040, the corridor expands to all
demand centers along its route, increasing demand from 165 to ~660 TWh.

Hydrogen supply
Pipelines
Repurposed
New
Import / Export
SubseaDemand per sector

By 2030, the corridor enables access to low-cost supply from parts of Easternand South-Eastern Europe and Ukraine. By 2040, the corridor gains additional
access expanding across the region.
In 2030, hydrogen supply is ~50 TWh, of which 65% of supply is from grid-basedhydrogen. Hydrogen supply increases significantly by 2040, reaching ~350 TWh.

40 / 30 / 20 / 10 / 1 TWh
Efuels production
Industrial energy
Industrial feedstockPower

Storages
Salt cavern
Aquifer
Depleted field
Rock cavern
Other items
Existing or planned
gas-import-terminal
Energy island for H₂
production

Imports

Grid-based

Dedicated green

Blue

Hydrogen Infrastructure
By 2030, the buildout of pipeline infrastructure across all countries of thecorridor reaches 10,000 km of large-scale pipelines. Corridor benefits from alarge share of repurposed infrastructure.
60% (Repurposed pipelines)

40% (New pipelines)

10,000 km (2030)© 2022 European Hydrogen Backbone, all rights reserved

Supply in MWh/km²<1
1 – 2525 – 100
100 – 250
250 – 500
> 500

52 TWh (2030)

HYDROGEN DEMAND & SUPPLYCorridor E / East and South-East Europe

2030

2040

Pipelines
Repurposed
New
Import / Export
SubseaPipelines
Repurposed
New
Import / Export
SubseaDemand per sector

Demand per sector

40 / 30 / 20 / 10 / 1 TWh

40 / 30 / 20 / 10 / 1 TWh

Efuels production
Industrial energy
Industrial feedstockPower

Efuels production
Industrial energy
Industrial feedstockPower

Storages
Salt cavern
Aquifer
Depleted field
Rock cavern

Storages
Salt cavern
Aquifer
Depleted field
Rock cavern

Other items
Existing or planned
gas-import-terminal
Energy island forH₂ production

Other items
Existing or planned
gas-import-terminal
Energy island forH₂ production© 2022 European Hydrogen Backbone, all rights reserved

Corridor connects hydrogen clusters from South-Eastern Europe toGermany by 2030, expanding to major demand centers by 2040

129

HYDROGEN DEMAND & SUPPLYCorridor E / East and South-East Europe

Hydrogen demand increases rapidly from 2030 to 2040,
largely driven by Germany and Poland
2030

2040

2050

Hydrogen demand – across all countries of
the corridor – increases significantly from2030 to 2050. Demand reaches 165 TWh by
2030, increasing to roughly 920 TWh by 2050.

General H₂ flow

Total demand per country (TWh/y)
Greece72742Bulgaria

5

17

23

Romania

14

34

46

Hungary

4

15

25

Slovenia

1

5

7

Croatia2

7

11

Slovakia

7

20

26

Czechia51727Austria836

52

Germany
Poland
Total

90
22

– Up to 2030, most hydrogen demandis driven by the industrial sector in thedestination countries – Germany and Poland.
– From 2040 to 2050, most new hydrogen
demand is for e-fuels production and for
power generation.

363

505

120
165

Hydrogen demand may accelerate andincrease further than forecasted as a resultof additional regulatory measures adopted in
response to the RePowerEU plan.

155
662

Note: Does not include grey hydrogen demand. Numbers represent total demand by country, even if only parts of the country are included in the corridor.

920© 2022 European Hydrogen Backbone, all rights reserved

Country130

HYDROGEN DEMAND & SUPPLYCorridor E / East and South-East Europe

Hydrogen adoption enables a reduction in emissions of
28% by 2050 across all countries of the corridor
-7 %

-21%

Decarbonisationin Mt CO₂ / year
260

-28 %

Hydrogen adoption across all demand sectors
enables an emissions reduction of ~260
MtCO₂/yr. by 2050, equivalent to a 28%
reduction².

258– Up to 2030, the industrial sector contributes
85% of the total emissions reductions.

240– By 2040, emissions reductions from transport(road, shipping and aviation) increase
substantially and combined with industry,account for 75% of emissions reductions. The
power sector account for the remaining 25%
of reductions.

220
195

200
180
160
140

– By 2050, most incremental emissions
reductions are associated with hydrogen
adoption in the power and transport sectors.

120
100
80

65

60
40
20

IndustryPower
Buildings
Transport

02030© 2022 European Hydrogen Backbone, all rights reserved

2040

2050

1

CO₂-Emissions from countries and sectors included in corridor (0.91 bn t CO₂ / year),
Source: EEA
2 Emissions reductions are calculated compared to the baseline fossil fuel used in eachsectors. For example, emissions reductions associated with the adoption of hydrogen by
the primary steel sector are relative to the use of coal. Similarly, emissions reductions , fore-fuels production are relative to the use of fossil fuels in shipping, aviation and other uses.

© 2022 European Hydrogen Backbone, all rights reserved

Emissions reductions(vs. 2019 emissions¹)

131

HYDROGEN DEMAND & SUPPLYCorridor E / East and South-East Europe

Corridor enables access to supply from Eastern & South-Eastern Europe
and Ukraine by 2030, expanding across the region by 2040

Pipelines
Repurposed
New
Import / Export
SubseaSupply in MWh/km²<1
1 – 2525 – 100
100 – 250
250 – 500
> 500
Storages
Salt cavern
Aquifer
Depleted field
Rock cavern
Other items
Existing or planned
gas-import-terminal
Energy island forH₂ production
Total hydrogen supply shown per NUTS-2 region. MWhadjusted by the area of each NUTS-2 region in km².
* Note: Supply numbers do not include grey hydrogen.

2040*

Pipelines
Repurposed
New
Import / Export
SubseaSupply in MWh/km²<1
1 – 2525 – 100
100 – 250
250 – 500
> 500
Storages
Salt cavern
Aquifer
Depleted field
Rock cavern
Other items
Existing or planned
gas-import-terminal
Energy island forH₂ production© 2022 European Hydrogen Backbone, all rights reserved

2030*

132

HYDROGEN DEMAND & SUPPLYCorridor E / East and South-East Europe

Hydrogen supply increases significantly from 2030 to 2040, largely
driven by imports from Ukraine and South-Eastern Europe
2030
SupplyImports(Ukraine)

12

Greece11

Bulgaria

General H₂ flow

Romania

1.6
2.2

Hungary

0.4

Slovenia

0.1

Slovakia

0.4

Czechia

0.1

Austria

4

Germany

15

Poland

2.9
14

Net¹
12
4
-3
-9
-4

39

38

-113

26
-7

2

45

15

5

10

-5

1

-1

4

4

11

-14

1

6

-17

0

-5

-19

50

15

7

-4

-75

Net¹

50

-2
-6

2050

Supply-10Croatia

Total

3

2040

-31

5
21

81
39

-261
-77

4
292

54

-316

1 Net represents excess supply after subtracting demand.
2 Grid-based is estimated using national 2030 electrolyser targets which, by 2030, are assumed to be largely grid-connected rather than dedicated. Gridbased increases over 2030-2050 with increasing RES.

Supply

Net¹
100

100

44

20

67

16

3

36
77
31

37

6

7

1

-3

4

7

18
12

-13

1

-27

0

-45

7

-313

165 27
108

-42

5
618

Dedicated green
Blue
Grid-based
2050 technical potential

70

-232

The hydrogen supply mix includes grid-based
green hydrogen² and dedicated greenhydrogen.
– By 2030, hydrogen supply reaches
50 TWh, largely from grid-based greenhydrogen.
– By 2040, hydrogen supply increases sub­stantially to ~350 TWh, of which roughly
85% is from dedicated green hydrogen. The
remaining 15% is from grid-based hydrogen
supply.
– By 2050, hydrogen supply increases
further to ~690 TWh. Dedicated green
supply continues to account for the largest
share at roughly 90%, while grid-basedhydrogen increases only slightly.
Hydrogen supply may accelerate andincrease further as a result of additional
regulatory measures adopted in response to
the RePowerEU plan.

Note: Hydrogen supply volumes do not include hydrogen imports by ship.

© 2022 European Hydrogen Backbone, all rights reserved

Country133

HYDROGEN DEMAND & SUPPLYCorridor E / East and South-East Europe

XXXXX
Ukraine may become a potential
source of imports by 2030
– Supply potential estimated based on Hydrogen Europe’s 2x40 GW Green
Hydrogen Initiative report¹.
– This analysis assumes a delay compared to the 2x40 GW report – due to thewar in Ukraine – resulting in more moderate hydrogen export volumes².

State ofGas Infrastructure– Ukraine is approaching H₂ as an export opportunity and is actively
investigating retrofitting existing gas pipelines to hydrogen.
– The Ukrainian Ministry of Energy highlighted the potential of using existinggas pipelines for the domestic use and for exports to Romania, Slovakia,
Hungary and Poland³.

MarketAttractiveness– Technical green hydrogen potential is substantial. Based on an estimatedtechnical potential of ~500-800 GW of renewable energy capacity, the supply
potential ranges between ~1,000-1500 TWh.
– Ukraine has a well-developed ammonia and steel production industries(applicable for green hydrogen).
– Ukraine’s Naftogaz joined the European Clean Hydrogen Alliance with theambition of becoming a leader in hydrogen export to EU countries.
– Partnerships: TSO’s of Slovakia, Austria and Germany – as part of aninternational consortium – are investigating the establishment of necessary
capacities for transporting hydrogen from Ukraine via Slovakia and Austria to
Germany for accessing storage facilities in Central Europe.

MarketBarriers

Mayor uncertainties relate to the current war– The operational state of Ukraine’s natural gas infrastructure– The speed of economic recovery and infrastructure investment– The development of a hydrogen market and related supply chains in Ukraine.

Hydrogen Europe (2021). 2x40 GW Green Hydrogen Initiative. https://hydrogeneurope.eu/wp-content/uploads/2021/11/Hydrogen-Europe_2x40GW-Green-H2-Initative-Paper.pdf
2 This report estimates 12 TWh of exports in 2030 based on of 5.5 GW of export capacity (vs. 8 GW in Hydrogen Europe’s estimations). Export
volumes assume an onshore wind capacity factor of 35% and an electrolyser efficiency of 70%.
3 UNECE – Draft Roadmap for Production & Use of Hydrogen in Ukraine (2021)

Hydrogen supply potential (TWh)¹
100

50
12
2030

2040

2050

1

Note: Export projections to Europe from 2030 to 2040-2050 are based on an assumed four-fold increase in exports by 2040 and two-fold increase from2040 to 2050. These assumptions are informed by scale up projections from other export countries of this study and Hydrogen Europe’s 2x40 GW report.

© 2022 European Hydrogen Backbone, all rights reserved

Supplypotential

134

CORRIDOR E© 2022 European Hydrogen Backbone,
all rights reserved

East andSouth-East Europe

135

Agenda
1. Corridor Summary
2. Hydrogen Demand & Supply
3. Supply Costs & Cost-Competitiveness4. National Strategies & Regulation
5. Actions Needed

SUPPLY COSTS & COST-COMPETITIVENESS / SECTION INTRODUCTION

Corridor E / East and South-East Europe

This section explores the costs of hydrogen production and delivery
for this corridor and their competitiveness with fossil fuels
Hydrogen delivered costs

Comparison with fossil alternatives

What is the range of production costs
achieved by the corridor in 2030 and
2040?

Based on a case-study of hydrogen supply
from South-Eastern Romania to Germany:– What are the full costs of firm hydrogendelivery after accounting for transportand storage costs?
– What cost levers are available to lower
the cost of hydrogen delivery?

How competitive is hydrogen supply
from this corridor compared to fossil fuelalternatives?

Corridor E / East and South-East Europe

Hydrogen Production Cost Range [2030]¹ ² ³

6.0

2.8

3.9
0.3

Slo
va
Ro kia
m
an
ia

4.0
3.5

0

50 3.00
Imports
Blue hydrogen

100

2.5

Wind offshore
Wind onshore

2.0

150

Solar PV
Grid-connected

200

250

300

350

2040

Case study (see next slide)

High
Low

2.5

1.5
1.0
1-3 See previous slide

0.5
0.0
0

5
Imports
Blue hydrogen

10
Wind offshore
Wind onshore

15
Solar PV
Grid-connected

20

25

30

35

40

Case study (see next slide)1 Cost curves are based on a bottom-up estimate of supply volumes per country and hydrogen production type. No transport or storage / firming cost are included.
2 Dedicated hydrogen production costs are based on renewable technology and electrolyser costs, and country-specific capacity factors and discount rates.
3 Grid-connected hydrogen production costs are determined based on costs of a mix of dedicated green hydrogen (solar, onshore wind, offshore wind) and adjusted
for grid-connection costs.

Key Findings& Results

45

50

2030
High
Low

4 Blue hydrogen costs are subject to significant uncertainty in natural gas prices. Our analysis adopts natural gas price levels based on market conditions
before Russia’s invasion of Ukraine. While natural gas prices have skyrocketed since, there remains significant uncertainty on near- and medium-term
European price trends and supply options. As a result, our analysis adopts the IEA’s Outlook 2021 price forecast developed pre-invasion, with costs of 28 €/MWh in 2030 and 13 €/MWh in 2040.

Baseline costsof H₂ production(€/kg)© 2022 European Hydrogen Backbone, all rights reserved

4.5

4.5

0.5

0.1

0.3

– By 2030, the corridor provides accessto hydrogen production costs of 2.5 to
4.5 €/kg.
– By 2040, hydrogen production costs
decrease to the range of 1.7 to 3.1 €/kg.

Transport &firming cost

Cost of H₂delivered

Optimisedsystem sizing

135

Cost of fossil
fuel alternatives

Battery storage
operation

Powerelectronics
savings

Reduced costof capital

Optimised costof H₂ delivered(€/kg)

1 Transport costs are based on several parameters including the type of pipeline (repurposed vs. new), transport distance and full-load-hour production on that pipeline. Firming costs are based on
additional storage cost required to deliver hydrogen at the equivalent of 8,000 full-load hours.
2 Optimised system sizing refers to right-sizing of solar PV and electrolyser capacity to increase full load hours. Similarly, battery storage operation enables an increase in the full load hours. Power
electronics savings refers to the removal of the inverter of the solar PV modules to reduce system cost. Reduced cost of capital refers to the use of foreign investment to reduce the WACC from 8 to 6%.
3 In some instances, cost reduction levers may result in cost increases for certain cost-components. For example, an increase in production costs at the same time as a decrease in firming costs. These cost
increases and decreases can result in connection lines that do not directly connect one step to the next.

Transport
Firming
Production

Delivered Costs (€/kg)(before and after cost levers)
2030

2040

Before costs lever

6.0

4.5

After costs lever

2.5

1.8

Production
costs(=4.5 €/kg)

By 2030, the low range of hydrogenproduction costs are competitive
with natural gas and coal, andlower than oil alternatives.

Cost of fossil
fuel alternatives€/MWh89‒115
Fuel cost
uncertainty

59‒73– In 2040, hydrogen delivered
costs can be reduced by 60%(4.5 vs. 1.8 €/kg).

2.5

1.7

5.0

1.0

© 2022 European Hydrogen Backbone, all rights reserved

Ro
m
an
ia

G
er
m
an
y

ce
G
re
e

1.5

Uk
ra
ine

Au
str
ia

2.0

€/MWh

141

2040

Production
costs– In 2030 (shown on the left),the cost of delivered hydrogencan be lowered by ~60%
(2.5 vs. 6.0 €/kg).

3.1
Cost range (€/kg)

2030

Cost reduction levers applied tocase study of hydrogen transport
from Romania to Germany enable firm delivery costs to be
reduced significantly.

Cost Reductions Levers-58 %Levelised cost of hydrogen production (€/kg) and Supply per country (TWh)

2.5

Baseline Costs

2.1

, ,

3.0

Cost of Hydrogen Delivered (€/kg) in 2030¹, ², ³

137

Po
lan
G d
re
ec
e
Ro
m
an
ia

Ro
m
an
ia

Po
lan
d
G
er
m
an
y

G
er
m
an
y

3.5

Hu
ng
ar
y
G
er
m
an
y

InLevelised
2030,
the corridor offers access to hydrogen production Cost range (€/kg)
cost of hydrogen production (€/kg) and Supply per country (TWh)ranging in costs from 2.5 to 4.5 €/kg

Corridor E / East and South-East Europe

Hydrogen costs are cost-competitive with fossil fuelalternatives by 2030, and lower by 2040

140

75

– Several cost reduction levers can beapplied to lower the costs of hydrogendelivery.
– For the Romania-to-Germany case study,
these levers achieve delivery costs thatare low and cost-competitive.

(=2.5 €/kg)

Case study
Deliveredcost of H₂
2.5 €/kg

H₂ production
cost-range
Higher Cost H₂Lower Cost H₂NaturalGas
Fuel cost
CO₂ cost

Steam
Coal

93

(=3.1 €/kg)

75 €/MWh

63‒69

Oil

85‒88

83‒95

62‒69

Case study
Deliveredcost of H₂
1.8 €/kg

54 €/MWh48(=1.6 €/kg)

H₂ production
cost-range

Natural
Gas

Steam
Coal

Oil

Fuel uncertain

Note: Prices for fossil alternatives (2030/2040): Natural gas (pre-invasion): 28/13 [€/MWh], Coal: 123/5.6 [€/MWh], Oil: 52/24 [€/MWh]. Natural gas prices levels are based on market conditions before Russia’s invasion of Ukraine. While natural gas prices
have skyrocketed since, there remains significant uncertainty on near- and medium-term European price trends and supply options. As a result, our analysis adopts the IEA’s Outlook 2021 price forecast pre-invasion developed pre-invasion. Prices in 2040
are significantly lower than in 2030 because of demand-supply conditions. By 2040, decreased demand for fossil fuels would lower prices. [Source: International Energy Agency, Outlook 2021 (IEA)] and fuel-cost uncertainty is shown with +50% range]

By 2040, the low-to-medium
range of hydrogen costs arematerially lower than all fossil
alternatives, while the medium-tohigh range are cost competitive.
Hydrogen delivered costs from the
Romania-to-Germany case study arecompetitive to natural gas in 2030
(27% higher) and 2040 (13% lower).
Natural gas prices are still uncertain due to recent price spikeas a result of the Russian invasionof Ukraine.

Note: For comparison purposes, cost of H₂ has been converted from“per kg” to “per MWh”
– 1 €/kg = 30 €/MWh (based on LHV of 33.3 kWh/kg)
Competitiveness of hydrogen highly dependant on CO₂-prices as they
make up a significant part of fossil fuel costs.
– CO₂ price 2030: 130 €/t– CO₂ price 2040: 205 €/t– Hydrogen costs are competitive withfossil fuel alternatives both in 2030 and
2040.
– Fossil fuel costs are subject to significant
uncertainty.

© 2022 European Hydrogen Backbone, all rights reserved

SUPPLYCOSTS& COST-COMPETITIVENESS
Hydrogen Production
Cost
Range
[2040]¹, ², ³

SUPPLY COSTS & COST COMPETITIVENESS

Corridor E / East and South-East Europe

Applying cost reduction levers to the Romania-to-Germany case study
lowers delivery costs significantly keeping hydrogen cost-competitive138© 2022 European Hydrogen Backbone, all rights reserved

SUPPLY COSTS & COST-COMPETITIVENESS / CASE STUDY

Corridor E / East and South-East Europe

By 2040, as supply options increase and scale up,
production costs decrease to a range from 1.7 to 3.1 €/kg

© 2022 European Hydrogen Backbone, all rights reserved

SUPPLY COSTS & COST-COMPETITIVENESS

Uk
ra
ine

Content
Material

Hydrogen production cost

G
re
ec
e
G
er
m
an
y
G
re
ec
e

Key Questions
Answered136

SUPPLY COSTS & COST-COMPETITIVENESS

Corridor E / East and South-East Europe

In 2030, the corridor offers access to hydrogen production
ranging in costs from 2.5 to 4.5 €/kg

137

Hydrogen Production Cost Range [2030]¹, ², ³

Sl
ov
ak
Ro ia
m
an
ia

Cost range (€/kg)

Ro
m
an
ia

G
er
m
an
y

G
re
e

ce

Uk
ra
ine

Au
str
ia

Levelised cost of hydrogen production (€/kg) and Supply per country (TWh)

5.0

4.5

4.5
4.0
3.5
3.0
2.5
1.5
1.0
0.5
0.0
0

5
Imports
Blue hydrogen

10
Wind offshore
Wind onshore

15
Solar PV
Grid-connected

20

25

30

35

40

Case study (see next slide)1 Cost curves are based on a bottom-up estimate of supply volumes per country and hydrogen production type. No transport or storage / firming cost are included.
2 Dedicated hydrogen production costs are based on renewable technology and electrolyser costs, and country-specific capacity factors and discount rates.
3 Grid-connected hydrogen production costs are determined based on costs of a mix of dedicated green hydrogen (solar, onshore wind, offshore wind) and adjusted
for grid-connection costs.

45

50

2030
High
Low

4 Blue hydrogen costs are subject to significant uncertainty in natural gas prices. Our analysis adopts natural gas price levels based on market conditions
before Russia’s invasion of Ukraine. While natural gas prices have skyrocketed since, there remains significant uncertainty on near- and medium-term
European price trends and supply options. As a result, our analysis adopts the IEA’s Outlook 2021 price forecast developed pre-invasion, with costs of 28 €/MWh in 2030 and 13 €/MWh in 2040.

© 2022 European Hydrogen Backbone, all rights reserved

2.5

2.0

SUPPLY COSTS & COST-COMPETITIVENESS

Corridor E / East and South-East Europe

By 2040, as supply options increase and scale up,
production costs decrease to a range from 1.7 to 3.1 €/kg

138

Hydrogen Production Cost Range [2040]¹, ², ³

Po
lan
G d
re
ec
e
Ro
m
an
ia

Cost range (€/kg)

Ro
m
an
ia

G
er
m
an
y

Po
lan
d

G
er
m
an
y

3.5

Hu
ng
ar
y
G
er
m
an
y

G
er
m
an
y
G
re
ec
e

G
re
e

ce

Uk
ra
ine

Levelised cost of hydrogen production (€/kg) and Supply per country (TWh)

3.1

3.0
2.5
2.0
1.5
1.0
0.5
0
0

50
Imports
Blue hydrogen

1-3 See previous slideWind offshore
Wind onshore

100
Solar PV
Grid-connected

150
Case study (see next slide)

200

250

300

350

2040
High
Low

© 2022 European Hydrogen Backbone, all rights reserved

1.7

SUPPLY COSTS & COST-COMPETITIVENESS / CASE STUDY

Corridor E / East and South-East Europe

Hydrogen delivered costs, including transport and storage
costs, can be kept low by applying cost reduction levers
analysis assesses a case study of hydrogen supply from South1 This
Eastern Romania to industrial offtakers in Germany to explore how thecosts of firm hydrogen delivery can be lowered.

assess the full cost of firm hydrogen delivery to Germany, transport
2 To
and storage costs are added to the cost of hydrogen production
from Romania.

Transport
Costs+

StorageCosts(firming costs)=

Pipelines
Repurposed
New
Import / Export
SubseaDelivered
Costs

cost reduction levers are applied to lower firm delivery costs,
3 Several
including optimised system operation, battery storage use, cost of capital
reductions, among others.

4

Corridor Case
Study Route

These cost reduction levers achieve sufficient cost savings tokeep firm hydrogen delivery costs low and cost-competitive.

© 2022 European Hydrogen Backbone, all rights reserved

Production
Costs

+

139

SUPPLY COSTS & COST-COMPETITIVENESS / CASE STUDY

Corridor E / East and South-East Europe

Applying cost reduction levers to the Romania-to-Germany case study
lowers delivery costs significantly keeping hydrogen cost-competitive
Cost of Hydrogen Delivered (€/kg) in 2030¹, ², ³
Baseline Costs

Cost reduction levers applied tocase study of hydrogen transport
from Romania to Germany en­able firm delivery costs to be
reduced significantly.

Cost Reductions Levers

-58 %
6.0

2.8

– In 2030 (shown on the left),the cost of delivered hydrogencan be lowered by ~60%
(2.5 vs. 6.0 €/kg).

3.9
0.3

Baseline costsof H₂ production(€/kg)

Transport &firming cost

Cost of H₂delivered

Optimisedsystem sizing

Battery storage
operation

0.1

Power
electronics
savings

0.3

Reduced costof capital

2.5

Optimised costof H₂ delivered(€/kg)

Transport costs are based on several parameters including the type of pipeline (repurposed vs. new), transport distance and full-load-hour production on that pipeline. Firming costs are based on
additional storage cost required to deliver hydrogen at the equivalent of 8,000 full-load hours.
2 Optimised system sizing refers to right-sizing of solar PV and electrolyser capacity to increase full load hours. Similarly, battery storage operation enables an increase in the full load hours. Power
electronics savings refers to the removal of the inverter of the solar PV modules to reduce system cost. Reduced cost of capital refers to the use of foreign investment to reduce the WACC from 8 to 6%.
3 In some instances, cost reduction levers may result in cost increases for certain cost-components. For example, an increase in production costs at the same time as a decrease in firming costs. These cost
increases and decreases can result in connection lines that do not directly connect one step to the next.
1– In 2040, hydrogen delivered
costs can be reduced by 60%(1.8 vs. 4.5 €/kg).

Transport
Firming
Production

Delivered Costs (€/kg)(before and after cost levers)
2030

2040

Before costs lever

6.0

4.5

After costs lever

2.5

1.8

© 2022 European Hydrogen Backbone, all rights reserved

2.1

140

SUPPLY COSTS & COST COMPETITIVENESS

Corridor E / East and South-East Europe

Hydrogen costs are cost-competitive with fossil fuelalternatives by 2030, and lower by 2040
2040

Production
costs
€/MWh

135

Cost of fossil
fuel alternatives

Production
costs(=4.5 €/kg)

By 2030, the low range of hydro­­gen
production costs are competitive
with natural gas and coal, andlower than oil alternatives.

Cost of fossil
fuel alternatives€/MWh89‒115
Fuel cost
uncertainty

59‒73
75

(=2.5 €/kg)

Higher Cost H₂Lower Cost H₂NaturalGas
Fuel cost
CO₂ cost

Steam
Coal

(=3.1 €/kg)

75 €/MWh

63‒69

Case study
Deliveredcost of H₂
2.5 €/kg

H₂ production
cost-range

93

Oil

85‒88

83‒95

62‒69

Case study
Deliveredcost of H₂
1.8 €/kg

54 €/MWh51(=1.7 €/kg)

H₂ production
cost-range

Natural
Gas

Steam
Coal

Oil

Fuel uncertain

Note: Prices for fossil alternatives (2030/2040): Natural gas (pre-invasion): 28/13 [€/MWh], Coal: 123/5.6 [€/MWh], Oil: 52/24 [€/MWh]. Natural gas prices levels are based on market conditions before Russia’s invasion of Ukraine. While natural gas prices
have skyrocketed since, there remains significant uncertainty on near- and medium-term European price trends and supply options. As a result, our analysis adopts the IEA’s Outlook 2021 price forecast pre-invasion developed pre-invasion. Prices in 2040
are significantly lower than in 2030 because of demand-supply conditions. By 2040, decreased demand for fossil fuels would lower prices. [Source: International Energy Agency, Outlook 2021 (IEA)] and fuel-cost uncertainty is shown with +50% range]

By 2040, the low-to-medium
range of hydrogen costs arematerially lower than all fossil
alternatives, while the medium-tohigh range are cost competitive.
Hydrogen delivered costs from the
Romania-to-Germany case study arecompetitive to natural gas in 2030
(27% higher) and 2040 (13% lower).
Natural gas prices are still un­
certain due to recent price spikeas a result of the Russian invasionof Ukraine.

Note: For comparison purposes, cost of H₂ has been converted from“per kg” to “per MWh”
– 1 €/kg = 30 €/MWh (based on LHV of 33.3 kWh/kg)
Competitiveness of hydrogen highly dependant on CO₂-prices as they
make up a significant part of fossil fuel costs.
– CO₂ price 2030: 130 €/t– CO₂ price 2040: 205 €/t© 2022 European Hydrogen Backbone, all rights reserved

2030

141

CORRIDOR E© 2022 European Hydrogen Backbone,
all rights reserved

East andSouth-East Europe

142

Agenda
1. Corridor Summary
2. Hydrogen Demand & Supply
3. Supply Costs & Cost-Competitiveness4. National Strategies & Regulation
5. Actions Needed

NATIONAL STRATEGIES & REGULATION

Corridor E / East and South-East Europe

A selection of countries have developed national strategies. Moving forward,
the development of regulation is key to enable infrastructure investment.
Network regulation & policy

Greece– In 2020, the government formed a Committee to work on NHS. The final
draft of the NHS is expected in Q2 2022.

– N/A– H₂ in shipping, power, production fromrenewable electricity and H₂ related R&D

Bulgaria– No specific national hydrogen strategy, but consideration of role forhydrogen in NECP

– N/A

– 20 MW H₂ refuelling stations are planned and a demandof 32 GWh in transport by 2030

Romania– Hydrogen strategy to be published in 2022

– N/A

– Project with 2 x 20 MW electrolysers powered by solar-PV
parks is under development

Hungary– 240MW of electrolyser capacity– Demand seen in industry and transport sector– Min. 2% volume blending to natural gas grid

– Low carbon and renewable H₂ planned– €5.3 m for project to store H₂ underground

Slovenia– In NECP is set indicative target to have 10 % of renewable methane orhydrogen in the network (2030)– TSO is obliged to prepare the plan for acceptance of H₂– Foreseen H₂ demand sectors: Transport (2030), buildings,
industry (NECP)

Croatia– Foresees demand in industry, buildings, transport and power, with a supply
potential of 1.3 GW electrolysers– N/A– First production site by 2025

Slovakia– H₂ used in the chemicals, petrochemicals, steel and heating industries aswell as in transport– N/A– Use H₂ in industries/areas impossible or not cost-effective todirectly engage electricity

Czech Republic– Focus Transport, then energy & chemical industry– Production also CCS and nuclear– Import and transit country for H₂ from the south– N/A– H₂-Readiness of gas transmission system is urged, due topotential role in H₂ transport from south to north and fromeast to west

Austria– NHS is still in discussion; known elements are: 1 – 2 GW electrolyser
capacity (2030), use in industry– H₂ mixtures of up to 10 % within Austria and 4-5 % on entry/
exit points are allowed– Production of green H₂ is subsidised– Preferred use to decarbonise industry– Focus: Transport sector and underground H₂ storage

Germany– National production & import focus due to supply gap– In place since 2020, currently reviewed towards increasing its ambition– 10 GW (2030) electrolyser in coalition plans– H₂ network potentially opt-in regulated and vertically unbundled– First rules and standards for high pressure pipelines areformulated

Poland– Focus: Power/heat sector, transport, industry, production, network, creating
regulatory framework– Creation of regulatory framework mentioned in H₂ strategy

0.59– Strong focus on international cooperation to ensure sufficient
supply– National funding– Gas network to be adapted & new build: “Hydrogen
Highway” (North-South)

General funding
SupplyNetwork
Demand© 2022 European Hydrogen Backbone, all rights reserved

Highlights

PreRePowerEU
targets²

National Hydrogen strategy (NHS)

Note: Sequencing of countries follows the general corridor direction but does not represent the hydrogen flows.
1 Cumulative public funding amount by the respective state until 2030
2 Strategies and funding is under evaluation of meeting latest targets

Funding¹ (bn €)143

CORRIDOR E© 2022 European Hydrogen Backbone,
all rights reserved

East andSouth-East Europe

144

Agenda
1. Corridor Summary
2. Hydrogen Demand & Supply
3. Supply Costs & Cost-Competitiveness4. National Strategies & Regulation
5. Actions Needed

ACTIONS NEEDEDCorridor E / East and South-East Europe

This corridor plays a fundamental role in achieving
a European backbone by 2040
– The development of this corridor ensures access to abundant, low-costhydrogen supply from parts of Eastern and South-Eastern Europe andUkraine by 2030, and by 2040 expanding access to additional supply
from the region.
– The decarbonisation of the largest hydrogen demand centers along
this corridor – in Greece, Romania, Bulgaria, Hungary, Austria andfurther towards Germany and Poland – is dependent on the buildout of
this corridor by 2030, and its expansion towards 2040.
Actions required– The buildout of this corridor by 2030 requires national governments totake clear and concrete actions across.
– This includes actions associated with infrastructure development andplanning, the development of cross-national initiatives and securing
access to early funding and long-term, low-cost financing.

2040
Pipelines
Repurposed
New
Import / Export
SubseaDemand per sector

40 / 30 / 20 / 10 / 1 TWh
Efuels production
Industrial energy
Industrial feedstock
Power
Supply in MWh/km²<1
1 – 2525 – 100
100 – 250
250 – 500
> 500
Storages
Salt cavern
Aquifer
Depleted field
Rock cavern
Other items
Existing or planned
gas-import-terminal
Energy island forH₂ production© 2022 European Hydrogen Backbone, all rights reserved

The need for this corridor

145

ACTIONS NEEDEDCorridor E / East and South-East Europe

To ensure the development of this corridor by 2030,
there is a need for clear and concrete actions

Unlock financing tofast-track hydrogen
infrastructure deploy­ment by applying regional
regulatory flexibility andother pragmatic financing
solutions (including
incentivizing the adoptionof hydrogen by demand
sectors)

Simplify and shorten
planning and permitting
procedures for renewableenergy and hydrogen
infrastructure projects

However, speed will be of essence!

Intensify energy partner­
ships with exporting,non-EHB countries likeUkraine, and providing
financing support to
reduce their cost of capital

Facilitate integrated
energy system planningof hydrogen, naturalgas, and electricity
infrastructure supporting
the accelerated deploy­ment and integrationof renewable energy
resources© 2022 European Hydrogen Backbone, all rights reserved

Fostering developmentof new and repurposedhydrogen infrastructure,for example, by unbund­ling rules facilitating theefficient use of TSO
expertise and services andby allowing the adoptionof different verticalunbundling models in theEU, as is the case withnatural gas

146© 2022 European Hydrogen Backbone,
all rights reserved

TABLE OF CONTENTS

1. Executive Summary
2. Five emerging supply corridors
Corridor A: North Africa & Southern Europe
Corridor B: Southwest Europe & North Africa
Corridor C: North Sea
Corridor D: Nordic and Baltic regions
Corridor E: East and South-East Europe

3. Detailed methodology

147

DETAILED METHODOLOGY / SECTION INTRODUCTION© 2022 European Hydrogen Backbone,
all rights reserved

This section describes the methodology used to define hydrogen
demand, supply,decarbonisation potential and cost competitivenessObjective

Content
Material

148

H₂ demandH₂ supply & decarbonisation

H₂ cost competitiveness

Forecast and localise future hydrogen
demand.

Forecast and localise future hydrogen
supply and determine the emissions
reductions impact of hydrogen
adoption

Calculate the cost of delivered hydrogenfor different corridor case studies

HYDROGEN DEMAND

HYDROGEN DECARBONIZATION & SUPPLY© 2022 European Hydrogen Backbone,
all rights reserved

Detailed approach:
HYDROGENapproach:
Detailed
DemandforDEMAND
power generation
HYDROGENapproach:
Detailed
DemandforDEMAND
industrial heat
HYDROGENapproach:
Detailed
forDEMAND
e-fuels
Category of H₂ use
Approach
Sub sectorDemand
Overallfor
approach:industrial
feedstockFertilizer
Categoryof H₂ use
Approach
Sub sectorDemand
Industrial
feedstock
Includeshydrogen replacing natural gas in gas fired powered plants, as included EHB analysis
report (June 2021)1.
Primarysteel
demandFertilizer
Categoryof H₂useApproach
Sub sectorLocalisation of hydrogen
Industrial
feedstock
Includeshydrogen replacing natural gas for medium temperature (150-500°C) and high

153Backbone,© 2022 European Hydrogenall rights reserved
152Backbone,© 2022 European Hydrogenall rights reserved
151Backbone,© 2022 European Hydrogenall rights reserved
150

temperature(>500°C)
industrial
processes
in all2021)1.
industrial
sectors (cement/lime,
ceramics,
Refineries¹
Demandnumbers
are based
on EHBheating
analysisreport (June
Adjustments
have been madePrimarysteel
Fertilizer
Categoryof H₂
Approach
Sub sector
Industrial
feedstock
Includese-kerosene
for aviation,
e-methanol
paper/pulp,
secondarysteelmaking,rockwooletc.). for shipping and hydrogen use for bio, waste andfor ausefew
countries
due
to country-specifics.
E-fuels
Cement/Lime
syn-methanol/naphtha production for High Value chemicals (HVCs). HVCs are mostly used for
Refineries¹(Bio)-CCUS
PrimarysteelCategoryof H₂useApproachFertilizer
Demand sector Sub sector
Industrial
feedstock
Includeshydrogendemandinrefineriesfordesulphurisationoffossils,
fertilisers(ammonia) andproduction
ofdemandplastics.
Demandnumbers
are based
on EHB analysis
report(June
Adjustments
been madeE-fuels
Localisation,hydrogenis allocatedper country
overthe 2021)1.
plants basedon theirhave
relative
Paper/Pulp
Cement/Limeprimary due
steeltoproduction(as reducing agent of iron ore).
Refineries¹(Bio)-CCUS
for ina few
countries
country-specifics.
Primarysteelcapacity
MW3.
Industry
Fertilizer
Start from previous EHB analysis database, which includes installation specificIndustrial feedstock
Demand numbers are largely based on EHB analysis report (June 2021)1. Addition is e-methanol
OtherPaper/Pulp
IndustryE-fuels
Industrial heat
pathwaysandanalysis
their locations/coordinates,
some assumptions(rate/pace
Cement/Lime
Refineries¹ (Bio)-CCUS
Demandnumbersarebased
on perEHB
report1,
adjusted
foradjustnewannouncements
Primary steel
for shipping(adds~80 TWhin 2050),
while
for toHVCs
based
onplants
recentannouncements
the byLocalisation,hydrogendemandis H₂
allocatedcountrydifferent
basedon theirof decarbonisation,
newtheannouncements
etc.)
fertilizer
and steelcompanies,
while for
steel
also
using
the Process
Marketand Trends
report2.
OtherPaper/Pulp
IndustryE-fuelsof syn-methanol/naphtha
is reduced
vs thesharebio/wastefuelsState(reduces~100
H₂ ForBiomass
relativeshareemissions
intensity
in 20192
pertemperature
level
perof
country.
emissions
are TWh
Cement/Lime
Refineries¹ Industrial heat(Bio)-CCUS
refineries,
as
in
the
EHB
analysisreport1,
hydrogendemandforfossilfuels
isreduced
to
0
over
in
2050).
Note
that
the
latter(bio/waste)also
requireshydrogen.
excluded to calculate these shares. Note that 2019 is chosen as “pre-covid” year.
Start from previous EHB H₂ demand for e-fuels production, add additional
Gas-firedE-fuels
OtherPaper/Pulp
Industrytime.
Biomass
Cement/Lime
Industrial
heat(Bio)-CCUS
Power generation
demandandshipping,
spreadcountries
over existing
Localisation at current refining e-methanol
installations (75%)2,
for selected(Spain,refineries
Portugal,and cement/
Gas-firedplantsAviation¹
Other Industry
Paper/Pulp
Biomass
Localisation
based
on
plant
locationsfromdatabases
EUtl3, Eurofer,
FertilizersPaper
EuropeNordics) also partly at (biogenic)paper/biomass
carbonsourcesfor
CCU: Biomass
power plants3,
andand CIEP.
Industrial heat
Power generation
In the bubble
maps (25%).
for visualisation,
the countrieshydrogenalso
demandin refineries
for desulphurisationof
Pulp,
Cement
and
Lime4
The
selectedareallocatedalargershareof the;²
Shipping¹
Other
IndustryGas-fired
Aviation¹
Biomass
Industrial
heat
Allocatehydrogendemandfrom EHB 2021
over plants based on country,
fossilsisnotincludedintheindustrial
feedstock
sector.
hydrogendemandintherefineries,
only
minor
changeonnon-selected
countries.
DSO levelPower generation
plant’s CO₂ emissions and process temperature level.
Road Shipping¹(freight) ; ² Gas-fired
Biomass
Aviation¹ PowerDSO levelPower generation(freight) ; ²
Heat Road Shipping¹
Gas-fired
Aviation¹
Power generation
Allocated hydrogen demand from EHB 2021 over plants based on country
DSO level(freight);²
Heat Road Shipping¹
and plant capacity in MW.
Transport
Aviation¹

Sources:
1 EHB analysis report (June 2021),

2 EUtl database (2019);
3 JRC power plant database (2019)

Heat Road (freight)

Sources:
1 EHB analysis report (June 2021),

Heat

2 EUtl database (2019);
3 JRC power plant database (2019).

Sources:
1 EHB analysis report (June 2021),
2 Clingendael International Energy Program (CIEP) (2017);

Buildings

DSO level

Shipping¹; ²Road (freight)
Heat

Note:
For Paper and Pulp, Cement and lime, if a location is selected as e-fuel production location no hydrogen demand is included for industrial heat – as efuels will provide for significant demand numbers already.

3 JRC power plant database (2019);
4 EUtl database (2019), company announcements, stakeholderinterviews.

Sources:
1 EHB analysis report (June 2021);
2 GfC Market state and trends report (2021) EUtl database (2019);

DSO level

No localisation of demand / keep at country level; for relevant countries
Note:(UK, DE), based on external data/literature/announced projects/TSO inputs
In the bubble maps for visualisation, the efuels category also includes hydrogen demand in refineries for desulphurisation of fossils. For Paper and Pulp, Cement and lime, if a location is
selected as e-fuel production location no hydrogen demand is included for industrial heat – as efuels will provide for significant demand numbers already

3 JRC power plant database (2019);
4 Eurofer;
5 Fertilzers Europe; Company announcements, Stakeholder interviews.

HYDROGEN COST-COMPETITIVENESS© 2022 European Hydrogen Backbone,
all rights reserved

Overall approach:Definitions of hydrogen supply options

154Backbone,© 2022 European Hydrogenall rights reserved

HYDROGEN DEMAND

H₂ supply type

HYDROGEN DECARBONIZATION & SUPPLYApproach
Sub sector

Dedicated Green

Onshore wind

© 2022 European Hydrogen Backbone,
all rights reserved

Overall approach:
Dedicated green hydrogen refers to hydrogen production via electrolysis using electricity generated fromrenewable energy resources dedicated exclusively for hydrogen supply. This includes electricity from solar
Solar
Hydrogen supply forecasting&ground)localisation
PV (rooftop andand wind (onshore and offshore).

157

Blue/Turquoise

Dedicated Green
Existing SMR
New ATR
Methane pyrolysis

GridBlue/Turquoise

Sub sector
Onshore wind
Solar
Hybrid¹
Offshore wind

Existing SMR
New ATR

Imports

Blue hydrogen refers
to hydrogen production primarily via steam methane reforming using natural gas
Approachas feedstock. Other production methods using natural gas as feedstock include autothermal reforming(blue hydrogen) and methane
pyrolysishydrogen)Start fromprevious(turquoise
EHB analysis/ ENSPRESO database, estimate potential by NUTS 2 region using

previous EHB assumptions, correct for national electricity demand & supply, curtailment, grid losses and max
electricity transmission capacities on country-level.² Offshore wind supply is allocated to the NUTS2 region
Grid-based green hydrogenrefersto hydrogenproduction
via electrolysis
renewable
electricity
with closest
proximity.
Validatedwith selectedstakeholderusing
interviews
with e.g.
project developers.
from the power grid.
Corridor-specific analysis on blue hydrogen incl. review of projects and announcement. To be validatedwith TSOs.
Hydrogen imports refers to green hydrogen production from export countries analysed in this report.
This includes North Africa (Morocco, Tunisia and Algeria) and Ukraine.

Methane pyrolysis

Grid

Corridor-specific analysis on green hydrogen project/announcement basis per country, localised in NUTS
2 based on where relatively most demand sits (weighted average; more H₂ demand in a NUTS 2 means
more grid-based hydrogen supply). To be validated with TSOs.

Imports
1 Hybrid means any combination of renewables technologies which can lead to more load hours as wind and solar resources are often complementing, most common example being solar PV+ onshore wind.
2 In the previous EHB analysis not all data input was on NUTS 2 level; where no NUTS 2-level data is available weighted averages will be used: for instance for electricity demand; the electricity demand data is
on country level and will be allocated to NUTS 2 regions based on their relative supply potential.

1 Hydrogen demand for e-fuels were allocated to refineries in previous EHB analyses, for this analysis a different approach is used: localisation based on potential sources of biogenic CO₂ locations.
2 Ammonia as shipping fuel assumed to be imported

Example:Production costs per kg of hydrogen:
Power electronics: Removing the inverter of the solar PV modules, enabling a
Calculationhydrogendeliverycost
Annualised costs of systemsetup, divided by ofreductionof 11% in CAPEX,
which reduces
the production costs.
Transportation costs per kg of hydrogen:
Optimisation
Depends on type of pipelines
used in results
Baseline Costs
combination with full load hours on thatpipeline and the length of the pipeline.
Firming costs: Reflecting the additional cost2.9
to deliver at 8,000 full-load hours. It is assumed
that with 4,000 full load hours of hydrogenproduction, 1.25 €/kg is added to the total
costs1. After adding the firming 2.5
costs, the total
cost of hydrogen reflect hydrogen delivered at
8,000 full-load hours to offtakers.
Baseline costsof H₂ production(€/kg)

Transport &firming cost

Assumptions
used

5.4

Presenting initial
methodology

Update methodology
based on feedback

Generating
results

Present anddiscuss results

161

CAPEX

1.3

Battery energy storage: Including battery energy storage increases full load
1.1
hours, and with that reduces the transport and firming costs.
0.1

0.3

2.6

System optimisation: Optimising electrolyser size and installed capacity of solar
and wind to increase full load hours, which reduces transport and firming costs.
System optimisation also reduces production costs.
Optimise
capacity
offshorewind turbine
based
on hydrogen
Cost of H₂generator
Optimised
Batteryoff
storage
Power
Reduced cost
Optimisedcost
deliveredsystem sizingtotal energy
operation output,
electronics
capitalH₂ delivered
production:
Increasing
leveraging offlexibility
inoftransmission
savings(€/kg)
capacity of H₂ infrastructure ⁴© 2022 European Hydrogen Backbone,
all rights reserved

Used
All

Leveraging foreign investment: Foreign investment will reduce the Weighted
Average Cost of Capital. This reduces annualised CAPEX and total production costs.

Full Load
Hours
Transport
Firming
Production

Energyoutput3 Resulting in a 12.4% reduction of offshore infrastructure costs in comparison with full-electric infrastructure.
4 Resulting in a 5% higher energy yield, based on increasing the generator capacity from 15GW to 16GW.

A, B, E

Potential conclusions
CostCreduction levers enablehydrogen delivered costs tobe lower than production costs
both in 2030 and 2040.
All– Cost reductions allow the costof delivered hydrogen to be
X% lower than production costs.
All
Production vs. Delivered Costs(€/kg)

C

2030

2040

Production Costs

2.5

2.6

Delivered Costs

2.1

1.5

Location

Latitude = 37°, longitude = -5.6°,
WACC = 8%, lifetime = 30 years

Solar PV modules

CAPEX = 300 €/kW, OPEX = 1.5%, tilt = 35°

Transportation

Distance to Duisburg = 2,000 km
through onshore pipelines

Onshore wind
generator

CAPEX = 860 €/kW, OPEX = 3%,
Generator = Siemens SWT 3.6 120, Losses = 19%

Electrolyser

CAPEX = 500 €/kW, OPEX = 3%, efficiency = 65%

Batteries

CAPEX = 70 €/kWh, OPEX = 3%, Round trip efficiency = 98%

Using the iterative process the working groups provided
Overall
Process

Cost factor

Using integrated electrolysis: Increasing
total energy efficiency due to reduction
Cost Reductions Leversof conversion inefficiencies (DC/AC and AC/DC steps) ². Also enabling to replaceExamelectrical infrastructure for H₂ pipeline, also reducing the peak capacity
costple+4 % ³component of the infrastructure

1 1.25 €/kg is based on the cost of 5 € to store 1kg of hydrogen for a year, assuming an average of 2 storage cycles. Source: U.S. Department of Energy (2019).
2 Resulting in 2% more energy output due to reduction of conversion inefficiencies and 3% CAPEX reduction due to avoiding of electrical infrastructure.

Literature review (strategies, targets, announcements, studies) and export country stakeholder interviews,
localise based on entry point in EHB network

160

H₂ COST-COMPETITIVENESS
Cost components ofPotential cost reduction levershydrogen delivered

total produced hydrogen per year.

Hybrid¹
Offshore windH₂ supply type© 2022 European Hydrogen Backbone,
all rights reserved

Methodology:
Calculation of hydrogen delivery cost

156

Finalized
results© 2022 European Hydrogen Backbone,
all rights reserved

149

Detailed methodology
1. Hydrogen demand
2. Hydrogen supply & decarbonisation
3. Hydrogen cost-competitivenessHYDROGEN DEMAND© 2022 European Hydrogen Backbone,
all rights reserved

Overall approach:
Localisation of hydrogen demand

150

Demand sector

Sub sector

Category of H₂ use

Approach

Industry

Fertilizer

Industrial feedstock

Start from previous EHB analysis database, which includes installation specificpathways and their locations/coordinates, adjust some assumptions (rate/paceof decarbonisation, new announcements etc.)

E-fuels

Start from previous EHB H₂ demand for e-fuels production, add additional
e-methanol demand shipping, spread over existing refineries and cement/
paper/biomass plants

Industrial heat

Allocate hydrogen demand from EHB 2021 over plants based on country,
plant’s CO₂ emissions and process temperature level.

Power generation

Allocated hydrogen demand from EHB 2021 over plants based on country
and plant capacity in MW.

DSO level

No localisation of demand / keep at country level; for relevant countries(UK, DE), based on external data/literature/announced projects/TSO inputs

Primary steel
Refineries¹
Cement/Lime(Bio)-CCUS

Paper/Pulp
Other Industry
Power

Biomass
Gas-firedTransport

Aviation¹
Shipping¹; ²Road (freight)

Buildings

Heat

1 Hydrogen demand for e-fuels were allocated to refineries in previous EHB analyses, for this analysis a different approach is used: localisation based on potential sources of biogenic CO₂ locations.
2 Ammonia as shipping fuel assumed to be imported

HYDROGEN DEMAND© 2022 European Hydrogen Backbone,
all rights reserved

Detailed approach:
Demand for industrial feedstock151

Sub sector

Category of H₂ use

ApproachFertilizer

Industrial feedstock

Includes hydrogen demand in refineries for desulphurisation of fossils, fertilisers (ammonia) andprimary steel production (as reducing agent of iron ore).

Primary steel
Refineries¹
Cement/Lime

E-fuels(Bio)-CCUS

Paper/Pulp
Other Industry

Industrial heat

Biomass
Gas-fired
Aviation¹

Power generation

Shipping¹; ²Road (freight)

DSO level

Heat
Sources:
1 EHB analysis report (June 2021);
4 Eurofer;
2 GfC Market state and trends report (2021) EUtl database (2019); 5 Fertilzers Europe; Company announcements, Stakeholder
3 JRC power plant database (2019);
interviews.

Demand numbers are based on EHB analysis report¹, adjusted for new announcements byfertilizer and steel companies, while for steel also using the Market State and Trends report². For
refineries, as in the EHB analysis report¹, hydrogen demand for fossil fuels is reduced to 0 overtime.
Localisation based on plant locations from databases EUtl³, Eurofer⁴, Fertilizers Europe⁵ and CIEP.
In the bubble maps for visualisation, the hydrogen demand in refineries for desulphurisation offossils is not included in the industrial feedstock sector.

HYDROGEN DEMAND© 2022 European Hydrogen Backbone,
all rights reserved

Detailed approach:
Demand for e-fuels152

Sub sector

Category of H₂ use

ApproachFertilizer

Industrial feedstock

Includes e-kerosene for aviation, e-methanol for shipping and hydrogen use for bio, waste andsyn-methanol/naphtha production for High Value chemicals (HVCs). HVCs are mostly used for
production of plastics.

E-fuels

Demand numbers are largely based on EHB analysis report (June 2021)¹. Addition is e-methanol
for shipping (adds ~80 TWh H₂ in 2050), while for HVCs based on recent announcements theshare of syn-methanol/naphtha is reduced vs the share of bio/waste fuels (reduces ~100 TWh H₂
in 2050). Note that the latter (bio/waste) also requires hydrogen.

Primary steel
Refineries¹
Cement/Lime(Bio)-CCUS

Paper/Pulp
Other Industry

Industrial heat

Biomass
Gas-fired
Aviation¹

Power generation

Localisation at current refining installations (75%)², and for selected countries (Spain, Portugal,
Nordics) also partly at (biogenic) carbon sources for CCU: Biomass power plants³, Paper and
Pulp, Cement and Lime⁴ (25%). The selected countries also are allocated a larger share of thehydrogen demand in the refineries, only minor change on non-selected countries.

Shipping¹; ²Road (freight)

DSO level

Heat
Sources:
1 EHB analysis report (June 2021),
2 Clingendael International Energy Program (CIEP) (2017);

3 JRC power plant database (2019);
4 EUtl database (2019), company announcements, stakeholderinterviews.

Note:
In the bubble maps for visualisation, the efuels category also includes hydrogen demand in refineries for desulphurisation of fossils. For Paper and Pulp, Cement and lime, if a location is
selected as e-fuel production location no hydrogen demand is included for industrial heat – as efuels will provide for significant demand numbers alreadyHYDROGEN DEMAND© 2022 European Hydrogen Backbone,
all rights reserved

Detailed approach:
Demand for industrial heat153

Sub sector

Category of H₂ use

ApproachFertilizer

Industrial feedstock

Includes hydrogen replacing natural gas for medium temperature (150-500°C) and hightemperature (>500°C) industrial heating processes in all industrial sectors (cement/lime, ceramics,
paper/pulp, secondary steelmaking, rockwool etc.).

E-fuels

Demand numbers are based on EHB analysis report (June 2021)¹. Adjustments have been madefor a few countries due to country-specifics.

Industrial heat

Localisation, hydrogen demand is allocated per country to the different plants based on theirrelative emissions intensity in 2019² per temperature level per country. Process emissions are
excluded to calculate these shares. Note that 2019 is chosen as “pre-covid” year.

Primary steel
Refineries¹
Cement/Lime(Bio)-CCUS

Paper/Pulp
Other Industry
Biomass
Gas-firedPower generation

Aviation¹
Shipping¹; ²

DSO level

Road (freight)
Heat
Sources:
1 EHB analysis report (June 2021),

2 EUtl database (2019);

Note:
For Paper and Pulp, Cement and lime, if a location is selected as e-fuel production location no hydrogen demand is included for industrial heat – as efuels will provide for significant
demand numbers already.

HYDROGEN DEMAND© 2022 European Hydrogen Backbone,
all rights reserved

Detailed approach:
Demand for power generation

154

Sub sector

Category of H₂ use

ApproachFertilizer

Industrial feedstock

Includes hydrogen replacing natural gas in gas fired powered plants, as included EHB analysis
report (June 2021)¹.

Primary steel
Refineries¹
Cement/Lime

E-fuels(Bio)-CCUS

Localisation, hydrogen demand is allocated per country over the plants based on their relative
capacity in MW².

Paper/Pulp
Other Industry

Industrial heat

Biomass
Gas-fired
Aviation¹

Power generation

Shipping¹; ²Road (freight)

DSO level

Heat
Sources:
1 EHB analysis report (June 2021),

Demand numbers are based on EHB analysis report (June 2021)¹. Adjustments have been madefor a few countries due to country-specifics.

2 JRC power plant database (2019)© 2022 European Hydrogen Backbone,
all rights reserved

155

Detailed methodology
1. Hydrogen demand
2. Hydrogen supply & decarbonisation
3. Hydrogen cost-competitivenessHYDROGEN DECARBONIZATION & SUPPLY© 2022 European Hydrogen Backbone,
all rights reserved

Overall approach:Definitions of hydrogen supply options

156

H₂ supply type

Sub sector

Approach

Dedicated Green

Onshore wind

Dedicated green hydrogen refers to hydrogen production via electrolysis using electricity generated fromrenewable energy resources dedicated exclusively for hydrogen supply. This includes electricity from solar
PV (rooftop and ground) and wind (onshore and offshore).

Solar
Hybrid¹
Offshore wind

Blue/Turquoise

Existing SMR
New ATR
Methane pyrolysis

Grid

Imports

Blue hydrogen refers to hydrogen production primarily via steam methane reforming using natural gas
as feedstock. Other production methods using natural gas as feedstock include autothermal reforming(blue hydrogen) and methane pyrolysis (turquoise hydrogen)Grid-based green hydrogen refers to hydrogen production via electrolysis using renewable electricity
from the power grid.

Hydrogen imports refers to green hydrogen production from export countries analysed in this report.
This includes North Africa (Morocco, Tunisia and Algeria) and Ukraine.

HYDROGEN DECARBONIZATION & SUPPLY© 2022 European Hydrogen Backbone,
all rights reserved

Overall approach:Hydrogen supply forecasting & localisation
H₂ supply type

Sub sector

Approach

Dedicated Green

Onshore windStart from previous EHB analysis / ENSPRESO database, estimate potential by NUTS 2 region using
previous EHB assumptions, correct for national electricity demand & supply, curtailment, grid losses andmax electricity transmission capacities on country-level.² Offshore wind supply is allocated to the NUTS2
region with closest proximity. Validated with selected stakeholder interviews with e.g. project developers.

Solar
Hybrid¹
Offshore wind

Blue/Turquoise

Corridor-specific analysis on blue hydrogen incl. review of projects and announcement. To be validatedwith TSOs.

Existing SMR
New ATR
Methane pyrolysis

Grid

157

Corridor-specific analysis on green hydrogen project/announcement basis per country, localised in NUTS
2 based on where relatively most demand sits (weighted average; more H₂ demand in a NUTS 2 means
more grid-based hydrogen supply). To be validated with TSOs.
Literature review (strategies, targets, announcements, studies) and export country stakeholder interviews,
localise based on entry point in EHB network

Imports
1 Hybrid means any combination of renewables technologies which can lead to more load hours as wind and solar resources are often complementing, most common example being solar PV+ onshore wind.
2 In the previous EHB analysis not all data input was on NUTS 2 level; where no NUTS 2-level data is available weighted averages will be used: for instance for electricity demand; the electricity demand data is
on country level and will be allocated to NUTS 2 regions based on their relative supply potential.

HYDROGEN DECARBONIZATION & SUPPLY© 2022 European Hydrogen Backbone,
all rights reserved

Overall approach:
Emissions reductions calculation

158

Demand sector

Sub sector

Approach

Industry

Fertilizer

CO₂-Emission by transforming methane (80% market share) and coal (20%) to hydrogen for ammonia production, resulting in 13.10 tons
CO₂ saved by using 1 ton of green hydrogen.

Primary steel

Using direct-reduction-plants instead of common blast-furnaces 26 tons of CO₂ can be saved by 1 ton of green hydrogen.

Refineries

By using 1 ton green hydrogen for Hydrocracking or Hydrotreating, Steam-Methane-Reforming is not longer necessary whichconcludes in 10.92 tons CO₂ saved.

EnergyA 2.4 times higher calorific value of hydrogen in comparison with methane, which emits 182 g CO₂/ kWh by burning, conclude to
0.43 t CO₂ saved using one ton of hydrogen.

Power

Gas-fired

One ton of hydrogen saves 0.74 ton CO₂ in 2030, 0.46 ton CO₂ in 2040 and 0.27 ton CO₂ in 2050, depending on the total
emissions of the electricity mix in that year.

Transport

Mobility

Direct hydrogen use for heavy transport (e.g. 25 t truck) saves 4.375 litres diesel per kg hydrogen, which equals to 11.55 tons CO₂
saved by 1 ton of hydrogen.

EfuelsDepending on the FLH of synthesis plant (e.g. 4000 h/year) 10.89 tons CO₂ can be saved by using 1 ton of hydrogen considering adiesel engine with 2.64 kg CO₂/ litre diesel as status-quo.

Heat

A 2.4 times higher calorific value of hydrogen in comparison with methane, which emits 182 g CO₂/ kWh by burning, conclude to
0.43 t CO₂ saved using one ton of hydrogen.

Buildings

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all rights reserved

159

Detailed methodology
1. Hydrogen demand
2. Hydrogen supply & decarbonisation
3. Hydrogen cost-competitivenessHYDROGEN COST-COMPETITIVENESS© 2022 European Hydrogen Backbone,
all rights reserved

Methodology:
Calculation of hydrogen delivery cost
Cost components ofhydrogen delivered

Production costs per kg of hydrogen:
Annualised costs of system setup, divided bytotal produced hydrogen per year.
Transportation costs per kg of hydrogen:
Depends on type of pipelines used in
combination with full load hours on thatpipeline and the length of the pipeline.
Firming costs: Reflecting the additional cost
to deliver at 8,000 full-load hours. It is assumed
that with 4,000 full load hours of hydrogenproduction, 1.25 €/kg is added to the total
costs¹. After adding the firming costs, the total
cost of hydrogen reflect hydrogen delivered at
8,000 full-load hours to offtakers.

Potential cost reduction levers

160

Cost factor

Power electronics: Removing the inverter of the solar PV modules, enabling a
reduction of 11% in CAPEX, which reduces the production costs.
Leveraging foreign investment: Foreign investment will reduce the Weighted
Average Cost of Capital. This reduces annualised CAPEX and total production costs².

Used
All

CAPEX

A, B, E

Using integrated electrolysis: Increasing total energy efficiency due to reductionof conversion inefficiencies (DC/AC and AC/DC steps) ³. Also enabling to replaceelectrical infrastructure for H₂ pipeline, also reducing the peak capacity cost
component of the infrastructure ⁴

C

Battery energy storage: Including battery energy storage increases full load
hours, and with that reduces the transport and firming costs.

All

System optimisation: Optimising electrolyser size and installed capacity of solar
and wind to increase full load hours, which reduces transport and firming costs.
System optimisation also reduces production costs.
Optimise generator capacity off offshore wind turbine based on hydrogenproduction: Increasing total energy output, leveraging flexibility in transmission
capacity of H₂ infrastructure ⁵

Full Load
Hours

EnergyoutputAllC

1 1.25 €/kg is based on the cost of 5 € to store 1kg of hydrogen for a year, assuming an average of 2 storage cycles. Source: U.S. Department of Energy (2019).
3 Resulting in 2% more energy output due to reduction of conversion inefficiencies and 3% CAPEX reduction due to avoiding of electrical infrastructure.
2 A reduction in WACC is only applied to select corridors; for example, a reduction of 10% to 8% is applied to imports from Tunisia in Corridor A and supply from Romania in Corridor E, while a re4 Resulting in a 12.4% reduction of offshore infrastructure costs in comparison with full-electric infrastructure.
duction of 8% to 6% is applied to imports from Spain in Corridor B. No cost reductions are applied to Corridors C and D because the credit rating of its supply countries are already relatively high. 5 Resulting in a 5% higher energy yield, based on increasing the generator capacity from 15GW to 16GW.

H₂ COST-COMPETITIVENESS© 2022 European Hydrogen Backbone,
all rights reserved

Example:Calculation of hydrogen delivery cost

161

Optimisation results

Potential conclusions

Baseline Costs

Cost Reductions Levers

E xa m p

+4 %
2.9

5.4

Cost reduction levers enablehydrogen delivered costs tobe lower than production costs
both in 2030 and 2040.

le

1.3
1.1
0.1

2.5

Baseline costsof H₂ production(€/kg)

Assumptions
usedTransport &firming cost

Cost of H₂delivered

Optimisedsystem sizing

Battery storage
operation

Powerelectronics
savings

0.3– Cost reductions allow the costof delivered hydrogen to be
X% lower than production costs.

2.6

Reduced costof capital

Optimised costof H₂ delivered(€/kg)

Transport
Firming
Production

Production vs. Delivered Costs(€/kg)
2030

2040

Production Costs

2.5

2.6

Delivered Costs

2.1

1.5

Location

Latitude = 37°, longitude = -5.6°,
WACC = 8%, lifetime = 30 years

Solar PV modules

CAPEX = 300 €/kW, OPEX = 1.5%, tilt = 35°

Transportation

Distance to Duisburg = 2,000 km
through onshore pipelines

Onshore wind
generator

CAPEX = 860 €/kW, OPEX = 3%,
Generator = Siemens SWT 3.6 120, Losses = 19%

Electrolyser

CAPEX = 500 €/kW, OPEX = 3%, efficiency = 65%

Batteries

CAPEX = 70 €/kWh, OPEX = 3%, Round trip efficiency = 98%