Extending theEuropean Hydrogen
Backbone
A EUROPEAN HYDROGEN INFRASTRUCTURE
VISION COVERING 21 COUNTRIESAPRIL 2021

Creos, DESFA, Elering, Enagás, Energinet, Eustream, FGSZ, Fluxys Belgium,
Gasgrid Finland, Gasunie, GAZ-SYSTEM, GCA, GNI, GRTgaz, National Grid,
NET4GAS, Nordion Energi, OGE, ONTRAS, Plinovodi, Snam, TAG, Teréga

Tableof contents
Executive summary3

1. Introduction

5

2. Gradual creation of a dedicated hydrogen infrastructure6

2.1. Connecting industrial clusters to an emerging infrastructure in 2030

62.2. Growing network by 2035 covers more countries and enables imports

8

2.3. Mature infrastructure stretching towards all directions by 2040

11

3. Updated cost of an expanded European Hydrogen Backbone

14

Appendix A. Updated costs

17

Appendix B. Country-specific developments

19

Imprint
Supported by:
Guidehouse

Date:
April 2021

Authors:
Jaro Jens, Anthony Wang, Kees van der Leun,
Daan Peters, Maud Buseman

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

2 / EXTENDING THE EUROPEAN HYDROGEN BACKBONE

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

Executive
summaryThis report presents an updated
and extended EHB vision, now
involving 23 gas infrastructurecompanies from 21 countries.

Last year, eleven gas infrastructure companies published a vision of a European
Hydrogen Backbone (EHB), a dedicated hydrogen pipeline transport network spanningten European countries. That report sparked a debate on the role that a hydrogen
network can play in the future European energy system. The role of hydrogen in
enabling climate neutrality is widely acknowledged, as is the need for hydrogen pipelinetransport. This report presents an updated and extended EHB vision, now involving
23 gas infrastructure companies from 21 countries. It presents updated hydrogen
infrastructure maps for 2030, 2035 and 2040 with a dedicated hydrogen pipelinetransport network largely based on repurposed existing gas infrastructure.
By 2030, the EHB could consist of an initial 11,600 km pipeline network,
connecting emerging hydrogen valleys. The hydrogen infrastructure can thengrow to become a pan-European network, with a length of 39,700 km by 2040.
Further network development can be expected after 2040. In addition, the maps
show possible additional routes that could emerge, including potential offshore
interconnectors and pipelines in regions outside the area where the EHB members
are active. The proposed expanded pan-European hydrogen backbone can further
support the integration of renewable and clean energy sources in regions that were
not yet included in the initial European Hydrogen Backbone plan as published in2020. These include Finland, Estonia, large parts of central and eastern Europe,
Greece, Ireland, and the United Kingdom.

FIGURE 1
Mature European Hydrogen Backbone
can be created by 2040

H2 pipelines by conversion of existing natural gas pipelines (repurposed)
Newly constructed H2 pipelines
Export/Import H2 pipelines (repurposed)
Subsea H2 pipelines (repurposed or new)Helsinki

Countries within scope of study

Tallinn

Countries beyond scope of study

Stockholm

Göteborg

EdinburghPotential H2 storage: Salt cavern

Copenhagen

Potential H2 storage: Aquifer

DublinPotential H2 storage: Depleted field

Cork

Energy island for offshore H2 production

GdanskManchester
Hamburg

City, for orientation purposes

Amsterdam
BerlinLondonWarsaw

CologneLeipzig

Frankfurt

PragueKrakow

Paris
ViennaMunichBratislava

Budapest
Lyon
Bordeaux

Milan

BilbaoVeniceLjubljanaMarseille

MadridBarcelona

Rome

Valencia

TarifaAlmería

Palermo

European Hydrogen Backbone initiative 2021, supported by Guidehouse

3 / EXTENDING THE EUROPEAN HYDROGEN BACKBONE

AthensEHB is an attractive and ­cost-effective option for
long-distance transportationof hydrogen

4 / EXTENDING THE EUROPEAN HYDROGEN BACKBONEThe European Hydrogen Backbone creates an opportunity to accelerate
decarbonisation of the energy and industrial sectors whilst ensuring energy system
resilience, increased energy independence and security of supply across Europe.
Such a vision can be achieved in a cost-effective manner, but it requires close
collaboration between EU Member States and neighbouring countries and a stable,
supportive, and adaptive regulatory framework.
In addition to maps showing the possible future topology of hydrogen
infrastructure, the report also provides an updated breakdown of repurposed versus
new pipelines and estimates of total investment costs up to 2040. The 39,700 km
European Hydrogen Backbone for 2040 as proposed in this report requires anestimated total investment of €43-81 billion, based on using 69% of repurposed
natural gas pipelines and 31% new pipeline stretches. This cost is relatively limited in
the overall context of the European energy transition.
The investment per kilometre of pipeline is lower compared to the network
investment costs as estimated in the initial European Hydrogen Backbone plan. Whilethe initial plan only included cost estimates for pipelines with a diameter of 48 inch,
this update takes into account that a large part of today’s natural gas infrastructure
and of tomorrow’s hydrogen infrastructure consists of smaller 24- or 36-inch
pipelines. Smaller pipelines are cheaper to repurpose leading to lower investment
costs overall. However, the operating costs to transport hydrogen over 1,000 km
are higher for smaller diameter pipelines compared to bigger diameter pipelines,
which raises the levelised transportation costs for the entire EHB to €0.11-0.21 per
kg of hydrogen. This is slightly higher than last year’s estimate of €0.09 to €0.17,
but confirms that the EHB is an attractive and cost-effective option for long-distancetransportation of hydrogen, taking into account an estimated future production costof €1.00-2.00 per kg of hydrogen.
The proposed infrastructure pathway up to 2040 shows the vision of 23 European
gas TSOs, based on national analyses of availability of existing natural gas
infrastructure, future natural gas market developments, and future hydrogen market
developments. Nonetheless, it is important to note that the eventual infrastructure
solution will be highly dependent on future supply and demand dynamics of theintegrated energy system, including natural gas, hydrogen, electricity, and heat. The
real development of hydrogen supply and demand and the increasing integrationof the energy system may lead to alternative or additional routes compared to theones described in this paper, and the timeline of some of the 2030, 2035 and 2040
proposed routes may be shifted forward or backward in time.
The EHB initiative is looking forward to discussing its vision with stakeholders
including policy makers, companies and initiatives along the hydrogen value chain.

1. Introduction

1

https://gasforclimate2050.eu/publications/

5 / EXTENDING THE EUROPEAN HYDROGEN BACKBONEThe European Hydrogen Backbone (EHB) initiative is a group of European gas
Transmission System Operators (TSOs) that has drafted a proposal for a dedicatedhydrogen pipeline infrastructure, to a large extent based on repurposed natural gas
pipelines. The initiative published a vision paper in July 2020, with maps coveringnine EU Member States plus Switzerland, home to the eleven TSOs participating atthat time. Since then, the EHB initiative has grown to 23 European gas TSOs with gas
networks covering 19 EU Member States plus the United Kingdom and Switzerland.
This report contains a geographically extended vision for a dedicated hydrogen
infrastructure stretching across these 21 European countries.
This updated European Hydrogen Backbone represents a vision of the growing
initiative, with extended hydrogen infrastructure maps for 2030, 2035, and 2040.
The report also provides an updated breakdown of repurposed versus new pipelines
and estimates of total investment costs. As in the last report, this paper includes thelocations of possible hydrogen storage locations. The amount of storage that would
be required in the future depends on a number of factors and is not further analysedin this paper. Neither does this paper analyse the cost of hydrogen storage. The
suggested pathway for the creation of dedicated hydrogen backbone infrastructure
is informed by studies¹ commissioned by the Gas for Climate consortium in 2019 and2020 which showed a large future role for hydrogen in a decarbonised European
energy system and a gradually declining role for natural gas, partially replaced bybiomethane.
Natural gas remains important to ensure security of supply during the 2020s and2030s, yet increasingly, gas infrastructure could be freed-up for the transportationof hydrogen as over time, hydrogen will become a competitive commodity andenergy carrier with a key role in the future energy system. Based on these insights,
the EHB initiative has created a possible and reasonable scenario on how hydrogen
infrastructure in Europe may be created that would be technically viable andachievable. The EHB vision is based on the abovementioned Gas for Climate studies,
national hydrogen strategies and planning processes as well as an evaluation ofannounced projects on hydrogen supply and demand across Europe, partly througha series of hydrogen supply chain stakeholder interviews.
The European Hydrogen Backbone vision starts from the current status quo yet
assumes a high ambition level for future climate change policies. This report presents
a vision rather than a final proposal based on detailed network planning. The
timelines for the scale up of hydrogen can vary from country to country, reflecting
national energy policy discussions and the status of hydrogen investment projects.
Hence, while for some countries more detailed information on planned hydrogen
infrastructure is already available, this information is not yet available in othercountries. On certain routes, natural gas and hydrogen may compete for existing
pipeline infrastructure. Across Europe, the speed with which dedicated hydrogentransport infrastructure can be created depends on market conditions for natural
gas and hydrogen as well as political support to stimulate hydrogen production anddemand and regulatory frameworks for hydrogen transport.
Modelling of hydrogen and natural gas flows would provide further insights onwhether and by when specific gas pipeline stretches would become available forhydrogen transport and investments in hydrogen infrastructure would be desirable.
This is out of scope of the present report.

2.1. Connecting industrial clusters to an
emerging infrastructure in 2030

2. Gradualcreation ofa dedicatedhydrogeninfrastructure2

https://gasforclimate2050.eu/sdm_downloads/
european-hydrogen-backbone/

6 / EXTENDING THE EUROPEAN HYDROGEN BACKBONEThe EHB vision published in 2020² showed that by 2030, separated hydrogen
networks can develop, consisting mainly of repurposed existing natural gas
pipelines. These initial stretches include the proposed Dutch and German national
backbones, with additional sections in Belgium and France. Hydrogen networks
were also expected to emerge in Denmark, Italy, Spain, Sweden, France, andGermany. The updated European Hydrogen Backbone map in Figure 2 shows that
additional repurposed stretches are expected to emerge by 2030 in Hungary andthe United Kingdom, with new stretches emerging in Finland. In this updated vision,some of the countries already depicted in the previous report show an accelerated
deployment of their hydrogen networks. For 2030, this holds for Sweden, France
and Italy. Some stretches of the network are now envisioned to emerge already by2030, representing updated insights.
In Hungary, the emergence of dedicated hydrogen pipelines by 2030 is
attributable to rapidly changing natural gas flows, growing hydrogen demand in theregion, and proximity to abundant renewable energy sources. The changing natural
gas flows are due to the new LNG terminal in Croatia, new pipeline connections in
the region and a changing of the gas market. At the same time, hydrogen demand in
the region is expected to ramp up. A dedicated hydrogen infrastructure connecting
the region’s customers to potential green hydrogen supply regions (Ukraine andsouthern Hungary) will be beneficial for the energy system at large.
In the UK, hydrogen could contribute significantly to meeting climate targets.
By 2030, four of the country’s five major industrial clusters could be connected
through the phased repurposing of existing gas pipelines to form an initial hydrogen
backbone. Due to the sensitivities around industrial cluster developments, National
Grid Gas does not hold any views on the phased sequencing of which industrial
clusters in the UK are likely to connect first as it relates to this study, which is thereason for the dotted lines.
In Finland, the hydrogen network could develop near the first hydrogen valleys
in the south, southwest and northwest. Here, significant use of hydrogen in industry
is envisioned in low-carbon fuel production, chemicals, steel, and mining, while
also the hydrogen network develops along the west coast, which has a large shareof the onshore wind potential. Additionally, the hydrogen production potential
is enhanced by land and water availability while the recovery of waste heat fromelectrolysers could be a potential solution to decarbonise district heating, which is
widely used in Finland.
In Italy, the use and production of hydrogen is expected to increase, also given
the Italian Hydrogen Strategy guidelines published in 2020. Domestic production
will ramp up, and growing demand also creates the possibility of green hydrogen
imports from North Africa as early as 2030, of course subject to market conditions.
This possible import could be enabled by repurposing given there are five parallel
pipelines between Tunisia and Italy.

Figure 2
Emerging European
Hydrogen Backbone in2030

H2 pipelines by conversion of existing natural gas pipelines (repurposed)
UK 2030 pipelines depends on pending selection of hydrogen clusters
Newly constructed H2 pipelines
Export/Import H2 pipelines (repurposed)
Subsea H2 pipelines (repurposed or new)
Countries within scope of study
Countries beyond scope of study
Potential H2 storage: Salt cavern
Potential H2 storage: Aquifer
Potential H2 storage: Depleted field
Energy island for offshore H2 production
City, for orientation purposes

Helsinki
Tallinn
Stockholm

Göteborg

Edinburgh

Copenhagen
DublinCork

GdanskManchester
Hamburg
Amsterdam
BerlinLondonWarsaw

CologneLeipzig

Frankfurt

PragueKrakow

Paris
ViennaMunichBratislava

Budapest
Lyon
Bordeaux

Milan

BilbaoVeniceLjubljanaMarseille

MadridBarcelona

Rome

Valencia

TarifaAlmería

European Hydrogen Backbone initiative 2021,
supported by Guidehouse

7 / EXTENDING THE EUROPEAN HYDROGEN BACKBONE

PalermoAthens2.2. Growing network by 2035 covers morecountries and enables imports
Between 2030 and 2035, the European Hydrogen Backbone will continue to grow,covering more regions and developing new interconnections across Member
States as shown in Figure 3 below. The increase in dedicated hydrogen pipelinetransport reflects the urgency to mitigate climate change and the opportunity forcost-effective decarbonisation. A rapidly increasing number of hydrogen projects
are expected to receive public support. Industries will require access to a liquid,mature and cross-border European hydrogen market, enabled by a growinghydrogen backbone. Pipeline transport will be valuable to connect regions with
abundant solar PV and wind potential with energy demand centres, including areas
which are out of reach for power transmission infrastructure. Whereas initially thehydrogen backbone predominantly mainly serves industrial hydrogen demand,studies including the Gas for Climate Gas Decarbonisation Pathways 2020-2050
study show that during the 2030s hydrogen will become a significant energy
vector in other sectors, including heavy transport, and electricity production andstorage, thereby complementing the electricity grid to integrate large volumes ofrenewables in the energy system.
In central and eastern Europe - in addition to what was presented in the2020 EHB paper - by 2035 an import route from Ukraine to the EU could emerge,
passing through the networks in Slovakia and the Czech Republic into Germany. Thistransit route consists of large diameter pipelines that can be repurposed. Ukraine
has high land availability and good on- and offshore wind and solar PV resources.
Combinations of offshore and onshore wind plus solar PV can reach high capacity
factors, thus ensuring a high utilisation of electrolysers and pipelines, with limited
storage.
Through Spain and France, a corridor towards Germany could emerge
by 2035. This route could connect hydrogen demand clusters in the north ofEurope with sources in the Iberian Peninsula, or even North Africa. This enables
these intermittent renewable energy sources across Europe to complement one
another, while also providing connection to storage options. This further enables
the transport of large quantities of hydrogen to facilitate a liquid, cross-borderhydrogen market.
Hydrogen Europe’s 2x40 GW Initiative³ has called for 24 GW of electrolyser
capacity in North Africa and 8 GW in Ukraine to be developed by 2030 for
exports to Europe. Increased collaboration with those countries, as priority
partners, was also specifically identified in the EU’s Hydrogen Strategy.⁴ The
corridors connecting regions with abundant renewable energy resources would
hereby not only serve for hydrogen imports, but also enhance the integrated
energy system by connecting diverse renewable sources, such as offshore wind in
the north and Solar PV in the south.

342x40 GW initiative, available at https://www.
hydrogen4climateaction.eu/2x40gw-initiative
COM (2020) 301, published on 8 July 2020

8 / EXTENDING THE EUROPEAN HYDROGEN BACKBONE

Figure 3
Growing network covering
more countries in2035

H2 pipelines by conversion of existing natural gas pipelines (repurposed)
Newly constructed H2 pipelines
Export/Import H2 pipelines (repurposed)
Subsea H2 pipelines (repurposed or new)
Countries within scope of study
Countries beyond scope of study
Potential H2 storage: Salt cavern
Potential H2 storage: Aquifer
Potential H2 storage: Depleted field
Energy island for offshore H2 production
City, for orientation purposes
Helsinki
Tallinn
Stockholm

Göteborg

Edinburgh

Copenhagen
DublinCork

GdanskManchester
Hamburg
Amsterdam
BerlinLondonWarsaw

CologneLeipzig

Frankfurt

PragueKrakow

Paris
ViennaMunichBratislava

Budapest
Lyon
Bordeaux

Milan

BilbaoVeniceLjubljanaMarseille

MadridBarcelona

Rome

Valencia

TarifaAlmería

European Hydrogen Backbone initiative 2021,
supported by Guidehouse

9 / EXTENDING THE EUROPEAN HYDROGEN BACKBONE

PalermoAthens5
6

COWI for EC DG ENER (2019), Study on Baltic
offshore wind energy cooperation under BEMIP
German hydrogen strategy (2020), available
at https://www.bmwi.de/Redaktion/EN/
Publikationen/Energie/the-national-hydrogenstrategy.pdf?__blob=publicationFile&v=6

10 / EXTENDING THE EUROPEAN HYDROGEN BACKBONE

In many parts of Europe, gas pipelines can be repurposed to hydrogen in anaffordable manner. In Sweden, Finland, and the Baltic states, however, little gas
infrastructure exists today. A significant new hydrogen infrastructure is proposed
for these countries, which reflects the ambitious plans to use hydrogen in heavy
industry in Sweden and Finland. In addition, development of this hydrogen network
can enable more extensive utilisation of clean energy sources and provide importantconnections between hydrogen production and demand in the EU. The network
will also support the increased need to balance the future decarbonised energy
system. The possible nuclear phase out in Sweden and ambitious national targets
to reach climate neutrality by 2045 in Sweden and already by 2035 in Finlandrequire a massive scale-up of variable renewable electricity. Because energy
demand is centred in the southern parts of Finland and Sweden, large amountsof energy would need to be transported from north to south. In combination withelectricity transmission, hydrogen pipelines can provide this energy transport costeffectively. Moreover, next to transporting energy from north to south, hydrogenfrom the Nordics could eventually also be exported into the rest of Europe, using
the hydrogen infrastructure and interconnections. This development would benefit
from excellent onshore wind conditions along the coast of the Gulf of Bothnia, andfrom the Baltic sea offshore wind potential. Land and water availability will enablesignificant development of onshore wind projects in these countries.
In the Baltic Sea, in the 2030s the deployment of offshore wind may alreadyreach a significant share of its 93 GW potential⁵, which will create a need for greenhydrogen to integrate and store the large amounts of intermittent wind energy. In thethree Baltic states this would create an oversupply of renewable energy, especiallyduring windy periods. For instance, in Estonia, renewable energy production duringwindy periods could reach four times its projected energy demand. By connecting
Baltic energy markets with the rest of Europe, hydrogen could be exported to Central
and Eastern Europe. The Baltic sea region and offshore wind also play importantroles in the German hydrogen strategy.⁶
In the UK by 2035, all five industrial clusters could be connected, resulting in amatured national backbone. In Ireland, a hydrogen valley could emerge in the southaround the coastal city of Cork, where hydrogen could also be imported by ship.
By 2035, the hydrogen network development would allow for the route from
Italy, and beyond that North Africa, to expand its reach all the way into northwestern and south-eastern Europe. For the latter, a new interconnection from Italy to
Slovenia would be used, while Hungary’s network will enable transport further into
south-east Europe. Possible imports into Germany are enabled by the repurposedinterconnection between Italy and Austria and large diameter repurposed pipelines
through Austria, Slovakia and the Czech Republic. Slovakia and the Czech Republic
could become an important hydrogen hub as hydrogen from the north, south andeast could flow through the country. The repurposing could solely happen if natural
gas flows were to drop significantly, freeing up one of the parallel lines across Italy,
Austria, Slovakia and Czech Republic, while still allowing natural gas transport overthis route to the extent needed.
The situation in Germany shows a much more dynamic picture in 2035
compared to the 2020 EHB paper. As natural gas and hydrogen may very well becompeting for the same pipeline infrastructure, it is unclear as of today whether
some of the pipelines shown will actually be converted to hydrogen. An example isthe newly suggested route connecting the Ruhrgebiet/Cologne area to the southernparts of Germany. Whether all suggested pipelines will be converted to hydrogenor remain natural gas pipelines largely depends on political support for the scale
up of hydrogen and the general market developments of hydrogen and natural gas
respectively.

2.3. Mature infrastructure stretching
towards all directions by 2040
By 2040, a pan-European dedicated hydrogen transport infrastructure can beenvisaged with a total length of around 39,700 kilometres, consisting of 69%
repurposed existing infrastructure and 31% of new hydrogen pipelines.
As shown in Figure 4, the network could stretch from Ireland to Hungary andfrom Spain to the Nordic countries, connecting different regions with different
renewable energy production profiles, providing a cost-effective way to transportlarge amounts of renewable energy to demand centres, and connections to regionswith storage capacity. The network would also allow pipeline imports from Europe’s
eastern and southern neighbours, as well as imports of liquid hydrogen from othercontinents via Europe’s main harbours. This would provide security of supply andenable the creation of a liquid, European market for hydrogen.

11 / EXTENDING THE EUROPEAN HYDROGEN BACKBONE

Figure 4
Mature European Hydrogen
Backbone can be created by2040

H2 pipelines by conversion of existing natural gas pipelines (repurposed)
Newly constructed H2 pipelines
Export/Import H2 pipelines (repurposed)
Subsea H2 pipelines (repurposed or new)
Countries within scope of study
Countries beyond scope of study
Potential H2 storage: Salt cavern
Potential H2 storage: Aquifer
Potential H2 storage: Depleted field
Energy island for offshore H2 production
City, for orientation purposes
Helsinki
Tallinn
Stockholm

Göteborg

Edinburgh

Copenhagen
DublinCork

GdanskManchester
Hamburg
Amsterdam
BerlinLondonWarsaw

CologneLeipzig

Frankfurt

PragueKrakow

Paris
ViennaMunichBratislava

Budapest
Lyon
Bordeaux

Milan

BilbaoVeniceLjubljanaMarseille

MadridBarcelona

Rome

Valencia

TarifaAlmería

European Hydrogen Backbone initiative 2021,
supported by Guidehouse

12 / EXTENDING THE EUROPEAN HYDROGEN BACKBONE

PalermoAthensBy 2040, two additional interconnections between Spain and France canincrease the security of supply and flexibility in the large expected flows of hydrogenfrom Spain and possibly North Africa into the rest of Europe.
In the North Sea, approximately 180 GW of offshore wind power capacity canbe installed by 2050. Model studies⁷ have shown that its integration in the northwest
European energy system would require a smart combination of electricity andhydrogen infrastructure, making use of 80-90 GW of electrolysers in coastal regions.
Electricity and gas TSOs in Denmark, Germany, and the Netherlands are alreadyactively collaborating on planning a hub-and-spoke offshore network of energy
hubs in an internationally coordinated roll-out⁸. Several MoUs and LoIs between
governments in the region, and together with potential connections to the United
Kingdom and Norway, extensive offshore hydrogen pipelines and energy hubs acting
as an international hydrogen network in the North Sea can be envisioned already inthe late 2030s, connecting the countries bordering the North Sea.
Analysis by Energinet confirmed the need for hydrogen to integrate large amounts
of offshore wind energy by showing that effective utilization of more than 10 GW ofadditional offshore wind requires up to 5-8 GW of electrolysis by 2035⁹. Gasunie
Germany confirmed a vision on offshore hydrogen production near Helgoland in
the North Sea as per 2030. Both plans are shown on the maps. Other plans could
not yet be shown on the maps due to uncertainties about locations and timing.
New hydrogen pipeline stretches in Central, Eastern and Southern Europe by2040 would enable pan-European energy system integration and decarbonisation.
It would enable a larger role of renewables in a largely coal-based power mix andenable hydrogen supply to decarbonise heavy industry located in central andeastern Europe.
In Poland, by 2040 a mature hydrogen network could emerge which would
enable the integration of large amounts of (offshore) wind energy up north. This
energy could then be transported in the form of hydrogen to possible industrial
demand regions in the south, while storage of the intermittently produced energy
would be enabled by a salt cavern near the supply in the north. Additionally, theBaltic gas pipeline from Denmark to Poland could be repurposed to dedicatedhydrogen transport by 2040, respecting long-term natural gas contracts on thispipeline which run until the end of 2037.
In Austria, an alternative route to transport hydrogen from east to west or
vice versa would be available. The additional possibilities would contribute to thedecarbonisation of industry in Austria and to reach the ambitious 2040 carbon
neutrality target set by the Austrian government.
In the northwest of Europe, the 2040 pan-European network would also
connect Ireland with the UK to the rest of the European Hydrogen Backbone, byrepurposing one of the interconnectors from the UK to Ireland and by repurposingof the IUK interconnector from Belgium to UK. In Ireland, a hydrogen valley could
emerge around Dublin, just south of where the repurposed interconnector from the
UK would land. In the UK, all options for converting the existing gas network tohydrogen have been shown, however not all of these pipelines will have completed
conversion to hydrogen within this period.
78
9

Guidehouse (2020), for North Sea Wind
Power Hub: https://northseawindpowerhub.
eu/wp-content/uploads/2020/04/NSWPHIntegration-routes-offshore-wind-2050.pdf
NSWPH, 2020, available at https://northseawindpowerhub.eu/category/studies/
Energinet, 2020. Available at https://en.energinet.dk/Analysis-and-Research/
Analyses/System-perspectives-for-the-70pcttarget-and-large-scale-offshore-wind

13 / EXTENDING THE EUROPEAN HYDROGEN BACKBONE

3. Updated
cost ofan expanded
EuropeanHydrogen
Backbone

10 Not all of these operating costs are additional
to current costs of running natural gas
infrastructure. For reference, annual operating
costs of natural gas infrastructure are around
5% of investment costs.
11 Load factor. This study considers the backbone
from an infrastructure investment perspective
and does not take a strong stance on the exact
level of network utilization. A load factor of5000 hours per year is deemed reasonable,cognizant of the fact this value will change
depending on future market developments –and impact resulting costs accordingly.
12 This corresponds to €3.3-6.3 per MWh ofhydrogen (LHV) per 1,000 km with €4.9 per
MWh in the central case.

14 / EXTENDING THE EUROPEAN HYDROGEN BACKBONE

Total investment costs of the envisaged 2040 European Hydrogen Backbone are
expected to range from €43 to €81 billion, covering the full capital cost of building
new hydrogen pipelines and repurposing pipelines for the European backbone. The
ranges reflect differences in capital cost assumptions, with the greatest uncertainty
stemming from compressor costs. Annual operating costs are estimated to be
between €1.7 and €3.8 billion¹⁰ when assuming a load factor of 5,000 hours per
year.¹¹ An overview of these costs is given in Table 1. Transporting hydrogen over
1,000 km along an average stretch of the hydrogen backbone, as presented inthis report, would cost €0.11-0.21 per kg of hydrogen transported, with €0.16 per
kg for the central case.¹² Although marginally higher than last year’s estimate thisconfirms that the EHB is an attractive and cost-effective option for long-distancetransportation of hydrogen, taking into account an estimated future production cost of€1.00-2.00 per kg of hydrogen.
The updated investment costs shown in Table 1 and updated transport costs per
kg of hydrogen differ from the previous estimate of €27 to €64 billion reported in
the 2020 study, with transport costs of €0.09 to €0.17 to transport a kilogrammeof hydrogen over 1,000 km. The difference in investment costs and levelised costs
compared to the previous EHB report are due to a combination of three factors:
1. The backbone has expanded in length and scope. The updated network
covers a total distance of 39,700 km across 21 European countries with highly
diverse gas infrastructures, compared to 23,000 km across 10 countries in theprevious EHB report.
2. The relative share of repurposed and new pipelines has changed following
the geographic expansion of the network. The enlarged network includes 69%
repurposed pipelines, while 75% of the previous shorter network consisted of
repurposed pipelines. This change is due to country-specific differences in
network topology, expected pipeline availability as well as the creation of newhydrogen networks for renewable energy integration in the Nordics, where today
limited gas infrastructure exists. These country-specific factors and developments
are substantiated in Annex B of the report.
3. A more granular assessment of pipeline diameters has been conducted.
Pipeline diameters of gas grids across Europe differ in size. The previous study
used a simplified assumption that the entire backbone would consist of large
48-inch pipelines. The updated investment costs as presented in the current
report differentiate between 48-, 36- and 20-inch pipelines (1200, 900, and
500 mm respectively). We now estimate that about half of the total network willconsist of medium sized pipelines plus smaller stretches of pipelines with a small
diameter. Repurposing or building new smaller sized pipelines imply reduced
unit capital costs and lower throughput capacities compared to 48-inch pipelines.
The breakdown of the European Hydrogen Backbone network by pipeline length,
diameter, and type – repurposed or new – is presented in Figure 5.
Additional information regarding the investment and operating cost estimation
methodology, including network design considerations such as throughput capacity,
compression requirements, and operating pressure are detailed in Appendix A.

TABLE 1
Estimated investment and operating
cost of the European Hydrogen
Backbone (2040)

MediumHigh

Pipeline cost

€ billion

33

41

51

Compression cost

€ billion

10

15

30

Total investment cost

€ billion

43

56

81

OPEX
(excluding electricity)€ billion/year

0.8

1.1

1.8

Electricity costs€ billion/year

0.9

1.1

2.0

Total OPEX

€ billion/year

1.7

2.2

3.8

Repurposed
27,200 km

Newly
constructed12,450 km

Small

8%

4%

Medium

29%

13%

Large

32%

14%

FIGURE 5
Breakdown of the European Hydrogen
Backbone network by pipeline length,
diameter, and share of repurposed vs
new pipelines

Low(< 28 inch / < 700 mm)(28-37 inch / 700-950 mm)(> 37 inch / > 950 mm)

0%

20%

40%

60%

80%

100%

Figure 5 shows that, based on an analysis of the existing gas network, almost
90% of the European Hydrogen Backbone can be expected to consist of medium(28-37 inch, 700-950 mm diameter) and large (> 37 inch, > 950 mm diameter)pipelines. For simplicity, it is assumed that the share of pipeline diameters for newly
built hydrogen stretches remains comparable to the current shares in the natural gas
network.
Representative unit capital cost figures for small, medium, and large hydrogenpipelines are summarised in Table 2. These figures use 20-inch (~500 mm), 36-inch(~900 mm), and 48-inch (~1200 mm) as models to represent small, medium, andlarge pipelines respectively. This is a simplification of reality, given that the actual
backbone is made up of a continuous range of pipeline sizes. Additional underlying
cost assumptions such as compressor costs, depreciation periods, and operating andmaintenance costs are also shown and are consistent with those used in the previous
EHB report of July 2020. These cost estimates are based on gas TSOs’ preliminary
R&D efforts with regards to hydrogen infrastructure. The ranges are determinedthrough comparison with experience investing in and operating existing natural gas
networks and based on initial experience in pilot projects. Although some dedicatedhydrogen components have been tested in pilot projects, no large-scale hydrogen
infrastructure exists to date to provide real historical benchmark figures. Equal to theprevious results in 2020, these cost estimates are based on running an average single
stretch of hydrogen pipeline. They do not incorporate a scenario-based simulation ofa full-scale network as is commonly done for network development planning.

15 / EXTENDING THE EUROPEAN HYDROGEN BACKBONETABLE 2
Cost input ranges used for estimating total
investment, operating, and maintenancecosts for hydrogen infrastructure. Adaptedfrom the original European Hydrogen
Backbone Report (2020)

Cost parameter
Pipeline
Capex,
new
Pipeline
Capex,
repurposed

Unit

Low

Medium

High

Small

< 700 mm

< 28 inch

1.4

1.5

1.8

Medium

700-950 mm

28-37 inch

2.0

2.2

2.7

Large

> 950 mm

> 37 inch

2.5

2.8

3.4

Small

< 700 mm

< 28 inch

0.2

0.3

0.5

Medium

700-950 mm

28-37 inch

0.2

0.4

0.5

Large

> 950 mm

> 37 inch

0.3

0.5

0.6

M€/km

Compressor station Capex

M€/MWe

2.2

3.4

6.7

Electricity price

€/MWh

40

50

90

Depreciation period pipelines

Years

Depreciation period compressors

30-55
15-33

Weighted average cost of capital

%

5-7%

Operating & maintenance costs (excluding electricity)€/year as a
% of Capex

0.8-1.7%

13 This corresponds to €3.3-6.3 per MWh ofhydrogen (LHV) per 1,000 km with €4.9 per
MWh in the central case.
14 The blended levelized cost of €0.11-0.21 per kg
per 1,000 km is calculated by multiplying theestimated levelized costs for each pipeline
diameter by their respective capacity- anddistance-weighted shares, i.e. the relative
amount of hydrogen transported by thatpipeline size across the entire backbone. A
detailed breakdown of levelized costs for eachpipeline size and their respective capacityand distance-weighted shares are shown inAppendix A Table 4.

16 / EXTENDING THE EUROPEAN HYDROGEN BACKBONE

The inclusion of sub-48-inch stretches – mainly medium-sized pipelines ofaround 36 inch in diameter – significantly reduces the overall investment costcompared to a case where all pipelines are assumed to be 48 inch in diameter.
At the same time, the levelised cost of transport is somewhat higher for smaller
pipelines, which raises the overall levelised cost. As a result, transporting hydrogenover 1,000 km along an average stretch of the hydrogen backbone, as presented
in this report, would cost €0.11-0.21 per kg of hydrogen transported with €0.16 per
kg in the central case.¹³
This price figure represents a blended average across a wide range of pipeline
sizes and types – ranging from repurposed 20-inch pipelines to new 48-inch ones
– and also reflects their respective distance and capacity-weighted shares within thecontext of the overall European Hydrogen Backbone.¹⁴ This means that even thoughsmaller pipelines have a higher cost of transport per unit distance, their modest
share in terms of length and capacity leads to a modest impact on overall transport
costs when considering the pan-European picture.
The cost ranges reflect uncertainties in the estimate of the cost of the European
Hydrogen Backbone as a whole. Depending on circumstances, the costs forindividual stretches can be lower or higher than the range indicated.

Appendix A.
Updated costs
The updated cost estimates are the result of a series of hydraulic simulations
conducted by gas TSOs. The modelled scenarios cover a range of point-to-point
pipeline transport cases with varying input parameters – selected by TSOs –including pipeline diameter, operating pressure, and design capacity. Note thatthese analyses, while thoroughly conducted, are not exhaustive and merely serve as
high-level approximations of what would happen in a real network. Regarding inlet(starting) pressure, operating (maximum) pressure, and compression requirements toachieve these, there are no standardised rules or benchmarks for these as of today.
Views on these key parameters differ amongst TSOs and depend on project-specificplanning considerations, and in reality pressures may differ from the figures reported
in this study. Hence, given the simplifying assumptions made in the analyses, theseresults should not be considered as representative of a fully optimised, actual
meshed pipeline grid. Key results are summarised in the tables below.
TABLE 3
Overview of unit capital costs fordifferent pipeline transport scenarios

Pipeline

Repurposed /Design /Inlet

OperatingPipeline

Compression

diameternewcapacitypressurepressure

Capex

Capex

bar

M€/km

M€/km

0.5

0.62

2.8

0.62

0.4

0.14

2.2

0.32

0.3

0.09

1.5

0.09

mm / inch
1200 / 48
900 / 36500 / 20GW H2 (LHV)¹⁵ bar
Repurposed

13

New

13

Repurposed

3.6

New

4.7

Repurposed

1.2

New

1.2

40

30

80

50

‘Small’ pipelines, as defined in this study, make up about 10% of the backbone interms of length and typically only cover modest distances, up to 200 km, at a time.
For this reason, levelised costs are expressed per 1,000 km for medium and large
pipelines but per 200 km for small pipelines. In addition, newly built ‘small’ pipelines
would likely only be constructed in niche situations, e.g. where they are needed toconnect two existing repurposed natural gas pipelines of the same size.
15 We choose to report LHV as it is customarily
used in energy system analyses, including instudies published by the EC. Note that someexperts recommend using HHV for electrolysis
as it is a closed system and LHV for fuel cells.

17 / EXTENDING THE EUROPEAN HYDROGEN BACKBONETABLE 4
Overview of levelised cost of pipelinetransport assuming 5,000 full load hours
for different scenarios

Pipeline

Repurposed /Design /Inlet

Operating

Levelised cost of

Capacity- & distance-

diameternewcapacitypressurepressuretransport

weighted share

GW H2
(LHV)

barg

barg

€/kg/­
1000 km€/kg/­
200 km% of backbone

40

80

0.08

–

33%

0.16

–

25%

0.11

–

19%

0.30

–

13%

–

0.05

6%

–

0.14

3%

mm
1200
900
500

Repurposed

13

New

13

Repurposed

3.6

New

4.7

Repurposed

1.2

New

1.2

30

50

TABLE 5
Breakdown of estimated lengths bypipeline size and shares of repurposed
and new pipelines of the Europe
Hydrogen Backbone (2040)

Length, km

Sub-total% shareSize

Small (< 700 mm)

Medium (700-950 mm)

Large (> 950 mm)

Repurposed

3,200

11,50012,50027,200

69%

New

1,450

5,300

5,700

12,45031%

Sub-total

4,650

16,80018,20039,650100%

18 / EXTENDING THE EUROPEAN HYDROGEN BACKBONE

Appendix B.
Country-specific developments
The evolution of a hydrogen network in the maps presented above illustrates a vision.
Further detailed modelling and a flow study is needed to define the shape, sizeand ordering of hydrogen infrastructure, alongside policy support, development ofhydrogen markets and hydrogen supply scaling up. The evolution of a hydrogen
network in these maps illustrates one of many repurposing scenarios. This showsa scenario for the development of a dedicated hydrogen infrastructure. The EHB
initiative considers blending and deblending hydrogen in/from natural gas fortransportation purposes as a suitable step especially during the 2020s and early2030s towards a dedicated hydrogen pipeline transport network.

TABLE 6Country narratives

Country
Austria(GCA and TAG)

BackgroundHydrogen infrastructure development

Austria’s current transmission gas network is
operated by two TSOs, TAG and GCA and stretches
over ~1,700 km. TAG mainly transits natural gas fromthe eastern border with Slovakia towards Italy. GCA’s
network serves a dual function and simultaneouslytransits gas mainly from Slovakia towards Germany,
Hungary and Slovenia and provides gas fordomestic customers in Austria. In the future both
TSOs expect to transport hydrogen. Austria has anambitious target to produce 100% of its electricity
from renewable sources by 2030 and a carbon
neutrality target by 2040, although enabled partly
by its hydro sources, solar PV and wind will needto scale up substantially. Future hydrogen use will
increase in Austria with its industry presence in fuels,chemical and steel. However, the main driver for the
emerging hydrogen infrastructure would be a transit
role, for the east-west and north-south corridors.
Transiting hydrogen into north western Europe from
North Africa coming in from Italy or from Ukraine
coming in from Slovakia. The network would next to
the transit role also serve residential and industrial
customers.

In 2030, a first step towards a dedicated hydrogen
network could be reached via blending anddeblending into/from the existing infrastructure
connecting Slovakia, Hungary, Slovenia, Italy andGermany.

19 / EXTENDING THE EUROPEAN HYDROGEN BACKBONE

By 2035, one of TAGs parallel pipelines could be
repurposed to transit hydrogen in both directions(from north to south and vice-versa). Furthermore,
3 interconnectors from Italy, Slovenia and Hungary
could already emerge enabling H 2 transportation from
North Africa and Ukraine to Slovenia, Hungary andGermany via Slovakia and Czech Republic.
By 2040, an additional interconnector to Germany
could be added by entirely looping GCA’s WAG
pipeline offering an alternative transport route ofUkrainian H 2 to Germany (Slovakia to Germany). Uponcompletion, Austria’s grid would be ready to serve asa hydrogen hub in the region. Bidirectional hydrogentransportation possibilities at all interconnection points
would be in place.
In addition, GCA’s network would also transport H 2 toAustrian (industrial) customers, such as one of Europe’s
largest steel plants in Linz, which is already running
trials for hydrogen-based steelmaking and a large
refinery located near Vienna.

Country
Belgium(Fluxys)

BackgroundHydrogen infrastructure development

Fluxys Belgium is the owner and operator of gas
transmission, storage and LNG regasification facilities
in Belgium. The network consists of 4,000 kmof pipelines and 18 interconnection points withneighbouring countries and import facilities.

The Belgian national backbone is expected to emerge
through developments in and around the industrial
clusters in Antwerp, Ghent, and along the industrial
valley in Wallonia. Given the proximity between
Antwerp and Rotterdam, port-to-port interconnections
with the Netherlands are likely. In addition, inter­
connections with France and Germany provide Belgium
access to hydrogen from/to neighbouring countries.
Hydrogen demand in Belgium in 2040 is expected
to exceed production capacity. Imports and exports
with all neighbouring countries including the UK – if
technical and economic conditions are right – andimports through the Zeebrugge terminal could shape
the North-Western European hydrogen market by
2040 and beyond.

Fluxys is ready to build the gas network of the future.
Our plan is to progressively reconfigure our natural
gas network in Belgium towards the future energy
system. We have taken steps with Belgian industrial
players and policymakers to identify the potential
for hydrogen production and consumption andthe infrastructure needed. However, the timing of
the investments for new pipelines and repurposed
pipelines depend on the evolution of natural gas
demand and the uptake of hydrogen demand.

Czech Republic(NET4GAS)

Czechia’s gas TSO, NET4GAS, operates around
4,000 km of pipelines consisting of three major
branches of double or even triple pipelines which
serve for international transit - connecting Germany,
Slovakia and Poland - while also covering domestic
demand. NET4GAS sees the gas infrastructure as
an enabler of decarbonisation in the energy sector
and expects to transport hydrogen (and otherrenewable or decarbonised gases) in the future.
Due to its geographical position, NET4GAS willremain an important transit TSO as it can transporthydrogen from an Eastern direction (e.g. from
Ukraine via Slovakia), from a Southern direction(e.g. from North Africa via Italy and Austria) as
well as from the North-West (e.g. Germany). The
Czech Republic is currently developing its own
hydrogen strategy. Potential utilisation of hydrogenis expected in carbon intensive and hard-to-abate
industrial processes such as ammonia, cement, steel
production or fuels and transportation. But also, inthe power production and (district) heating sectors
there is an increased interest in hydrogen as anenergy carrier.

20 / EXTENDING THE EUROPEAN HYDROGEN BACKBONE

There are several long-term gas transmission contracts
in place. The major contracts expire at the beginningof 2035 and in 2039, respectively. The possibility
for hydrogen transportation from the Eastern borderwith Slovakia to the Western border with Germany
is shown in the updated maps in 2035. This option
would - under certain circumstances still to be analysed- allow for hydrogen imports from Ukraine and North
Africa already in 2035 by connecting major non-EU
supply sources and regions with the hydrogen demand
centres in the EU. In addition, the Gazelle pipeline
could provide a large-scale connection for hydrogentransportation between the Northern and Southern
regions of Germany. For 2040, as there might be
additional hydrogen demand in the industrial regions
close to the Polish border, a new connection to thehydrogen backbone might have to be analysed.

Country
Denmark(Energinet)

BackgroundHydrogen infrastructure development

Denmark’s electricity and gas TSO, Energinet, owns
and operates a gas transmission pipeline grid ofaround 925 km, with cross border connections toGermany and Sweden. An expansion with the Baltic
Pipe connecting Norway, Denmark with Poland
will be in operation from 2022, expanding thepipeline grid to approx. 1,250 km. Energinet owns
and operate two gas storages, one cavern and one
aquafer storage.

By 2030, Initial development of the Danish backbone
consists of constructing new pipelines parallel to theexisting natural gas network, connecting hydrogenproducers and industrial clusters with large scalestorage facilities.

In the view of EU’s climate ambition, Energinet seesa need for coordinated and holistic planning ofenergy infrastructure across electricity and gas,including new energy carriers such as hydrogen.
Energinet welcomes and is active in the work
undertaken by European TSOs with regards
to identifying possible hydrogen cross-border
networks, which can bridge the regional disparities
between renewable hydrogen generation anddemand for hydrogen across Europe.
Denmark has set out a 70% greenhouse gas
emissions reduction target by 2030. Power-to-X isan integral part of the government’s plan to install
two energy islands of 3 respectively 2 GW in 2030.
Analyses show that effective utilization of morethan 10 GW of additional offshore wind require
up to 5-8 GW of electrolysis by 2035. Several
electrolysis projects are underway in Denmark,which indicates an installed capacity of around
3 GW in 2030. This includes a 1.3 GW plantoutside Copenhagen and two projects in Northernand Southern Jutland linking the west coast (windproduction) to industrial clusters and hydrogenstorage facilities in the east and north of Jutland.
Additionally, an announced bilateral cooperationagreement with the Netherlands includes a €135 mln
Dutch investment in large-scale Power-to-X plants
in Denmark, ensuring that both countries fulfil their2020 renewable energy targets

21 / EXTENDING THE EUROPEAN HYDROGEN BACKBONE

Beyond 2035, Denmark seeks to draw upon its
significant offshore wind resource in combination withelectrolysis to attract new industries, such as e-fuels.
The energy islands will be the drivers for the expansionof the hydrogen infrastructure. As such, the national
backbone expands throughout the 2030s into several
directions. The eastern route is extended all the way
to the Copenhagen region by retrofitting the existing
pipeline and connecting to Sweden. A northernconnection also emerges from west which includes
access to the cavern storage and towards demandareas in Sweden. In addition, the southern part of thegas in Jutland (interconnection with Germany) can be
retrofitted and a new transmission pipeline could beconstructed from Copenhagen area southwards toward
Germany. Also, the Baltic Pipe could be repurposed asa supply connection to Poland. The 2040 map shows
many possible developments for hydrogen transport,
which ones to be realized depend on the societal
economic value and demand situation in the future. The
development will co-exist with the biomethane grid.
Also, by 2040 the Danish energy island in the North
Sea should be scalable to 10 GW, for which offshore
production of hydrogen can be envisioned and aradial hydrogen pipeline connection from the energy
island to the national onshore hydrogen network.

Country
Estonia(Elering)

BackgroundHydrogen infrastructure development

Estonia’s electricity and gas TSO, Elering, operates apipeline grid of 977 km, including the recently built
subsea interconnector with Gasgrid Finland.

In the beginning of the 2030s, the first offshore
windfarms are expected to be present west of Estonia,
in the Baltic Sea¹⁷. Due to the large volumes ofenergy produced in offshore wind farms, comparedto the relatively small electricity demand in theBaltics, hydrogen production could be economicallyfeasible early on. This renewable energy oversupply
could open a possibility to export green hydrogento Central Europe with an offshore pipeline alreadyin 2035. As such an offshore pipeline would be agreat undertaking for a small country like Estonia,
the realization of an offshore pipeline like this would
largely depend on the demand side interest for greenhydrogen produced within the EU and political will.
Additionally, hydrogen could be needed to integrate
the large amounts of offshore wind energy penetrating
the Estonian Energy system, hereby it could also
provide seasonal storage and complement theelectricity grid, which is also operated by Elering.

With offshore wind potential of 7GW and 24TWh¹⁶,
Estonian offshore wind energy potential alone will
far exceed its domestic electricity demand (link).
Without the introduction of green hydrogen, theoffshore wind production and installed capacity may
not even reach its full potential due to large amountsof energy which could be curtailed during highwind periods. Connecting the national backbone to
the European Hydrogen Backbone supports system
integration of large volumes of offshore wind,enabling a relatively small country to supply multiple
potential demand regions across Europe. Estonia
could also act as a transit corridor for hydrogenthat would be produced in Finland. The benefitsof realising the Baltic sea offshore- and Nordic
onshore wind potential would not only be regional.
Connecting the Baltic region with Central Europe
with an offshore pipeline would enable Europe
to increase its energy self-sufficiency and energy
security. Green hydrogen would allow for integrationand storage of the offshore wind and transport thisgreen energy to hard-to-decarbonise regions inCentral (Eastern) Europe.
Locally, hydrogen could enable Estonia to complete
the phase out of fossil oil shale-based power
plants by 2035. Hydrogen pipeline network could
enable the use of hydrogen in dispatchable power
plants, thus guaranteeing the security of supply forelectricity.

16 EU, 2020, Study on Baltic offshore wind energy cooperation under BEMIP
17 Euractiv, 2021, The untapped green energy potential of the Baltic States

22 / EXTENDING THE EUROPEAN HYDROGEN BACKBONE

By 2040 further offshore wind power expansion
is expected together with hydrogen production inwestern Estonia. Also, an interconnection with Latvia
emerges to connect Finland and Estonia with Eastern
Europe through the other Baltic states.

Country
Finland(Gasgrid)

BackgroundHydrogen infrastructure development

Finland’s gas transmission system operator (TSO)
Gasgrid Finland owns and operates a networkin the south of Finland of 1,300km and a subsea
interconnector into Estonia with Estonian gas andelectricity TSO Elering. Finland has an ambitious
carbon neutrality target already for 2035. A
hydrogen network could support the developmentof a carbon neutral energy system in Finlandby providing intermediate energy storage andefficient transport of renewable energy from supply
sources to the demand locations. In a later stage
the hydrogen network could also be connected tomultiple markets across Europe and make Finland ahydrogen exporter. Finland has significant onshore
wind potential and possibility to utilise heat fromelectrolysis process for production of district
heating – factors supporting competitivenessof hydrogen production. The potential for wind
power is significant and 70 GWs of inquiries forwind power have been made already¹⁸ to Fingrid(electricity TSO in Finland), who is envisioning 25
GW of wind power already by 2035¹⁹ in one of its
scenarios. Thus, Power-to-X production could have asignificant potential in Finland that should be further
investigated.

By 2030, the Finnish hydrogen network could
develop around first hydrogen valleys in the southand south west of Finland (Kymenlaakso & Uusimaaand Southwest Finland & Satakunta) and north-west(Bothnia Bay area) with an interconnector to Sweden in
the last one mentioned. The development of hydrogenvalleys could emerge due to envisioned significant useof hydrogen in industry (low-carbon fuel production,
chemicals, steel, mining) and possibility to utilise clean
energy resources for hydrogen production. Hydrogen
networks could connect producers and consumers,
enable utilisation of wind power potential located at
the west coast, provide possibilities for intermediate
energy storage and create a hydrogen market. An
interconnection to Sweden could create a FinnishSwedish market at the Bothnia Bay area.

In addition, Finland is relatively close to the Central
European countries with expected significant
increase in hydrogen demand. In parallel, demandfor clean hydrogen in Finland could grow and scale
rapidly in industry, considering the 2035 carbon
neutrality target and strong presence of steel,chemicals, and fuel production. In addition, the needfor energy system integration is a key driver of ahydrogen network in Finland. Furthermore, land andwater availability further add to the large potential ofhydrogen production in Finland.

18 Available at https://www.tekniikkatalous.fi/uutiset/fingrid-saanut-70000-megawatin-verrantuulivoiman-hanketiedusteluja-vastaisi-44aa-olkiluoto-3-ydinvoimalaa/0f88bec8-5831-4532-9ce7653d066f0d2f)
19 Fingrid, 2020, Network Vision, available at https://www.fingrid.fi/globalassets/dokumentit/fi/
kantaverkko/kantaverkon-kehittaminen/fingrid_network_vision.pdf Fingrid, 2020, Network
Vision, available at https://www.fingrid.fi/globalassets/dokumentit/fi/kantaverkko/kantaverkonkehittaminen/fingrid_network_vision.pdf [1] EVwind, 2021, available at https://www.evwind.
es/2021/02/05/iberdrola-strengthens-its-commitment-to-offshore-wind-energy-and-acquires3-gw-in-ireland/79178#:~:text=Ireland%20has%20ambitious%20climate%20change,of%20
potential%20for%20offshore%20development.

23 / EXTENDING THE EUROPEAN HYDROGEN BACKBONE

By 2035, Finland would achieve its carbon neutrality
targets and could become a hydrogen exporter.
National hydrogen valleys are connected, and anational hydrogen network could be developed. A
connection along the west coast of Finland enables
more extensive utilization of wind for hydrogenproduction and aids the energy transfer from north tosouth. Also, another interconnector to Sweden could
be developed with direct subsea route crossing the
Gulf of Bothnia and Åland Island. Åland Island has thetarget of becoming a society scale demo of an energy
system running 100 % on renewables. A possible
subsea interconnector to Estonia connects Finland to
the Baltics and to potential demand markets in central,northern and eastern Europe.
By 2040 up north, the hydrogen grid extends further
north, and potentially also additional north-south
pipelines are developed. Expansion of the Finnish
hydrogen network facilitates accelerated deploymentof wind power to fully utilize the potential enabled bygreat land availability in the northern and eastern partsof Finland. Further expansion of the network could
also aid transmission of energy from north to south of
Finland.

Country
France(GRTgaz and Teréga)

BackgroundHydrogen infrastructure development

France’s current gas network
is operated by GRTgaz which
operates 32,000 kilometres ofpipelines and Teréga, which
operates a 5,000 km network inthe south-west. The networks serve
industry, power and residential
customers while GRTgaz alsotransits gas to Switzerland, Italy and
Teréga transports gas to and from
Spain. Both TSOs are convincedthat hydrogen and biomethane,next to electrification, will play
an important role in the future
French energy system. GRTgaz
have ongoing hydrogen projects
such as mosaHYc, Jupiter 1000,
Hyfen, while Teréga is involvedin trials around hydrogen storageas HyGéo project and studying
a hydrogen dispatchable power
plant (Lacq Hydrogen project).".
The “France Hydrogène”
association study estimates Frenchhydrogen demand to increase
to approximately 110 TWh/y by
2040.

The majority of France’s future hydrogen backbone would exist of
repurposed pipelines, hereby providing a cost-effective way to transporthydrogen. By 2030, regional dedicated hydrogen networks will emerge
around industrial clusters, with existing fossil hydrogen production
or consumption, in Dunkerque, in the Seine Valley from Le Havre to
the vicinity of Paris, and around Lyon, Lacq and Marseille. These firstregional hydrogen networks will foster the achievement of the French
Government ambition, issued in September 2020, which aims to reach
6.5 GW of electrolysis capacity installed in 2030, to decarbonise
industrial and mobility uses. The hydrogen cluster around Dunkerque will
be supplied with decarbonised hydrogen from offshore wind, as well as
low-carbon hydrogen. This cluster will also co-benefit from the hydrogenvalleys in Belgium and the Netherlands. In the east of France, a regional
cluster will also develop at the border between France, Germany,and Luxemburg with the commissioning of the mosaHYc project. The
southern clusters in Marseille-Fos and Lacq are also expected to haveaccess to green hydrogen from solar PV and Mediterranean offshore
wind. Lastly, dynamic development of green hydrogen for fuel cellprojects and industrial uses is expected to continue and to lead to aneed for a dedicated hydrogen pipeline in the region surrounding
Lyon. By 2035, additional hubs emerge near Saint Nazaire/Nantes,
Bordeaux and along the Mediterranean coast, powered by offshore windor low-carbon electricity and combined with the evolution of Seaports
activities. Those hubs will connect to Region of Paris, and to Lyon along
the Rhone Valley, thus enabling the decarbonisation of existing greyhydrogen consumptions and the development of new hydrogen uses
in mobility (road, inland navigation, rail, airports). The North-West ofFrance will also be connected to the East of France and to the Regionof Paris via the retrofitting of existing gas pipelines. This will enableinterregional transit and an easier integration of renewable electricity inthe energy system, and it will bring flexibility to the system. The French
network will also allow a transnational transit from Spain to Belgium,
Germany or Luxembourg. By 2040, a mature network has emerged ofmostly repurposed pipelines which has 3 interconnectors with Spain,
while also connecting to Belgium, Germany, and Switzerland. The threeinterconnectors to Spain enable security of supply and flexibility in thelarge expected flows of hydrogen from Spain and possibly North Africa
into the rest of Europe. On the west side another stretch also provides
a different route within France to transport hydrogen, while also serving
local customers and industry on the way. In the south, Teréga’s storage
locations could provide another way to store the intermittent productionof green hydrogen, hereby enabling a stable and secure hydrogen
supply further up north.

24 / EXTENDING THE EUROPEAN HYDROGEN BACKBONE

Country
Germany(ONTRAS and OGE)

BackgroundHydrogen infrastructure development

OGE, headquartered in Essen, operates thelargest German gas transmission system spanning
12,000 kilometres. Two thirds of natural gas
consumed in Germany flow through OGE’s pipeline
system, comprising about 100 compressor units andabout 1100 exit points. The OGE 2030+ strategy
aims to secure the OGE transmission business in
the long run and prepares the pipeline network andnumerous compressor stations for new gaseous
energy carriers. OGE actively support the European
gas market and work together with the European
distribution network operators to create theprerequisites for transnational.

As part of the network development plan process(2020-2030), the German transmission system
operators queried specific projects for the generationor use of hydrogen by means of a market partner
query. For 2030, the market participants asked for
1 GW of green hydrogen feed-in capacity. The
exit capacity requested for the same point in time
was significantly higher with 3 GW. This should bebased on an annual hydrogen requirement of around
20 TWh for industrial purposes only. To close thegap in the entry-exit balance for H 2 in 2030, thenetwork operators envisage hydrogen imports fromthe Netherlands, the connection of cavern storage
facilities and additional feeds from wind farms that are
equipped with electrolysers. The plans for the German
H 2 start grid 2030 foresee pipeline connections to the
Dutch H 2 grid.

ONTRAS Gastransport GmbH is a national gas
transmission system operator in the European
gas transport system based in Leipzig. ONTRAS
operates Germany's second-largest gas transmission
system, with approximately 7,500 km of pipelines
and about 450 interconnection points. ONTRAS
links the interests of transport customers, dealers,regional network operators and producers ofregenerative gases.
With the National Hydrogen Strategy (NWS) of
the German government aims to create a coherent
framework for action for the future production,transport, and utilization of hydrogen and thus forcorresponding innovations and investments. The
German government will intensify the cooperation
with countries around the North and Baltic Seas,
primarily to accelerate hydrogen production from
offshore wind. It also regards hydrogen as afoundation for strenghtening energy partnerships
beyond Europe.
German transmission system operators plan todetermine the need for entry and exit capacity as
part of the network development plan process inorder to be able to provide the necessary transportcapacities. Studies estimate the 2040 hydrogen
demand for Germany at over 300 TWh (GfC’s
Decarbonization Pathways Study; DENA - Pilot
study on integrated energy system transformation).
Regarding sources of hydrogen an increase indomestic production as well as additional imports ofhydrogen from the Netherlands, Norway Denmarkand Russia, as well as from Southern Europe are
expected. The European Hydrogen Backbone
creates additional import opportunities from acrossthe continent, e.g. green hydrogen from Spain orNorth Africa.

25 / EXTENDING THE EUROPEAN HYDROGEN BACKBONE

Since the market partner query is the first broad-based
query for future hydrogen transport needs, it canbe assumed that further requirements will become
apparent in the coming years. This also corresponds tothe view of the German government expressed in thenational hydrogen strategy, which forecasts hydrogenrequirement of 90-110 TWh for 2030. In the updated
map for 2035, an accelerated repurposed connection
from the Czech border is possible in order to importhydrogen from the south and east via the Czech
Republic to Germany.
In the Western part, a pipeline has been added
which is mainly repurposed with the aim to connect
the industrial cluster of the Ruhr and Cologne/Bonnarea with areas in South-Western Germany. As ofcurrent data that pipeline connection might still beneeded for natural gas, depending on development ofdemand and policy decisions. By 2040, multiple newinterconnections emerge to Belgium, Switzerland andAustria, further enhancing the security of supply.

Country
Great Britain(National Grid)

BackgroundHydrogen infrastructure development

National Grid owns and operates the National
Transmission System in Great Britain, a network
consisting of approximately 7,660km of pipelines.
The UK government has targeted at least 5 GW
hydrogen production capacity and 40 GW offshore
wind by 2030, with four low carbon industrial
clusters established. A dedicated hydrogentransmission system is expected to emerge in GreatBritain (the island consisting of England, Scotland
and Wales) initially through the phased repurposing
of existing natural gas transmission pipelines tojoin GB’s largest industrial clusters (Grangemouth,
Teesside, Humberside, Merseyside and South
Wales). This will provide resilience to the clusters
and could support the conversion of some industries
outside of these clusters.

By 2030, up to four of the five industrial clusters
could be connected and will form the basis of a
GB hydrogen transmission backbone. Due to thesensitivities around industrial cluster developments,
National Grid Gas does not hold any views on thephased sequencing of which industrial clusters
are likely to connect first as it relates to this study.
Additionally, there may be connections to St Fergus innorth Scotland and Bacton on the east coast, providing
additional hydrogen supplies which could help
integrate the large amounts of renewable energy from
offshore wind.

The initial development of the emerging hydrogen
backbone in GB aims to utilise and repurpose
pipelines to transport hydrogen, whilst still
maintaining the security of supply on the existing
natural gas transmission system. Further conversionof remaining pipelines will likely develop at alater stage and may require small sections of new
pipelines to enable the transition.

Greece(DESFA)

Greece’s TSO is DESFA, which operates a relatively
new network of 1,456km. Greece’s excellent
conditions for both wind and solar power would
allow the complete phase out of coal-based power
plants by 2028 or even earlier. There are plans toincrease installed capacity of Wind Power to 7 GW
and Solar PV to almost 8 GW, as stated in its
NECP. This may lead to the need to use hydrogenin dispatchable power. The two main industrial
clusters, in Thessaloniki and Athens, are potential
large demand sources for hydrogen. In addition,according to the recently developed Master Plan forthe decarbonisation of the lignite production areaof West Macedonia, there is the large potential ofhydrogen production in the region This potential
stems from the expected deployment of large scale
PV plants, along with the potential for the use ofhydrogen locally or its transportation through the
new hydrogen-ready pipeline DESFA is deploying in
the region.

26 / EXTENDING THE EUROPEAN HYDROGEN BACKBONE

By 2035, it is possible that all clusters could beconnected. A converted pipeline to Bacton, locatedon the east coast, could enable future hydrogen flows
across the interconnectors between GB and Belgium
and GB and the Netherlands once ready. Further
repurposed pipelines may start to emerge between
2035 and 2040, including a connection to Moffat,
enabling hydrogen to flow across the interconnector
between GB and Ireland alongside natural gas flows.
As hydrogen production scales, further expansion ofthis hydrogen network will occur throughout the 2040s
enabling a greater reach across industrial, power,transport and domestic heating sectors. The maps
represent the selection of pipelines that could havestarted the hydrogen repurposing process but may
not have completed full conversion by the date on themap. Sequencing and formally defined routes have notbeen determined, therefore some of these pipelines
could be converted in the following 5 to 10-year
period.
By 2040, Greece’s two main industrial clusters inAthens and Thessaloniki would be connected, withnew pipelines following the existing natural gas route,repurposing existing pipelines can also be an option
depending on market conditions. Storage could beavailable in the form of an aquifer near the Island of
Thasos. The connection to Europe could either gothrough the seas using the TAP pipeline or via South
East Europe. The potential hydrogen cluster in West
Macedonia will also be connected to Thessaloniki,near the existing connection to TAP, through thenew, hydrogen-ready pipeline in the region, which iscurrently under development.

Country
Hungary(FGSZ)

Ireland(GNI)

BackgroundHydrogen infrastructure development

FGSZ, Hungary’s gas grid operator, operates amature network of 5,874 km. The network is partiallyfor domestic use, while playing a recently changedtransit role from Ukraine to South Eastern Europe.
The flows reversed partially and decreased slightly
with opening of the LNG terminal on the Croatianisland Krk in 2021 and with the gradual openingof the new Balkan routes. Therefore, part of the
network might become available at an early stage tobe repurposed for green hydrogen transport from
Ukraine into the coal-based regions in South Eastern
Europe and to the West via Slovenia. Hungary has
set a carbon neutrality target for 2050 and targets
6 GW of Solar PV to be installed by 2030. The
solar PV potential sits mainly in the south and could
lead to variable oversupply of renewable energy,
especially if the second nuclear plant in Hungary
materializes and operates in parallel with the current
nuclear power plant. The current nuclear power
plant will be phased out a couple of years after thestart of the new plant.

By 2030, changing gas flows make part of the network
available to be repurposed for hydrogen transport. This
could mean the repurposing of the interconnector with
Ukraine which would connect the Hungarian market
to the large potential hydrogen supply from Ukraine.
The rest of the network connects several industrial
customers in the steel, chemical, and fertilizer sector.

Gas Networks Ireland (GNI), operates a networkin Ireland of 2,477 km of transmission pipelines
and 12,044 km of distribution and 2 subsea
interconnectors from Moffat in Great Britain to justnorth of Dublin on Ireland’s east coast. Ireland has
30GW of offshore wind projects already in thepipeline and plans 5GW²⁰ of offshore wind to be
operational by 2030.

By 2035, a hydrogen “valley” network could emerge
around the city of Cork, on Irelands’ south coast.
Supply resilience for this mainly green hydrogencluster would be assured with supplementary
imported hydrogen which could be either tanker orinterconnector sourced (via a hydrogen pipeline direct
to the continent).

Large amounts of intermittent offshore windproduction, particularly off the Atlantic west coast
could result in electricity grid congestion andcurtailment for a country of Irelands’ scale. Greenhydrogen production and integration with the gas
network could provide a way to maximise Irelands
wind energy potential, as a store of energy, as analternative to imported hydrogen and potentially inpeak production periods enabling hydrogen export.
While scale hydrogen from offshore wind in Irelandis still developing, Ireland could import hydrogen,initially for the power sector providing zero carbon
support to intermittent renewables and later fortransport, industry and heating. This could beachieved mainly through repurposed existing gas
pipeline network, and possibly some new bespokehydrogen pipelines.

20 EVwind, 2021, available at https://www.evwind.es/2021/02/05/iberdrola-strengthens-itscommitment-to-offshore-wind-energy-and-acquires-3-gw-in-ireland/79178#:~:text=Ireland%20
has%20ambitious%20climate%20change,of%20potential%20for%20offshore%20development.

27 / EXTENDING THE EUROPEAN HYDROGEN BACKBONE

By 2035, Hungary could already have a mature mostly repurposed - hydrogen network with in total
6 interconnections to the Ukraine, Austria, Slovenia,
Serbia, Romania, and Croatia. This would connect
Slovenia and the mostly coal based nations in SouthEast Europe to Ukrainian hydrogen, effectively making
Hungary a green hydrogen transit country enabling thedecarbonisation of heavy industry in South-East Europe
and the transition away from coal. Interconnections to
Slovenia and Austria would, already by 2035, connect
the energy systems of South-eastern Europe and Northwestern Europe.
By 2035, a 7 th interconnection to Slovakia would
add to the market liquidity and security of supply ofhydrogen.

By 2040, one of the 2 Moffat interconnectors from the
UK could be converted for 100% hydrogen transportand some relatively small-scale reconfiguration of the
Dublin gas transmission network could enable local,
scale, hydrogen – fired power generation. The other
Moffat interconnector could sustain resilient supply
to the remaining unconverted network, it no longer
having to serve the Cork cluster and Dublin power
generation loads.
Development of these dedicated hydrogen networks
provide for accommodation of and ready market
access for scale green hydrogen and could create
the potential for future (through the 2040’s) extended
gas network conversion to hydrogen, hydrogenconsumption for residential heating and industry andultimately green hydrogen export to Great Britain or
beyond.

Country

BackgroundHydrogen infrastructure development

Italy(Snam)Snam owns and operates the National Transmission
System in Italy, with over 32.500 km of trans­
portation network in use and 17 bcm of storage
capacity. The Italian guidelines for the nationalhydrogen strategy foresee that by 2030 hydrogen
could make up 2% of Italy’s final energy demand.
This demand will be mainly concentrated in industrial
clusters located in the North and in some areas of
the South. The Italian national backbone will connect
these clusters with green production facilities in
the Center and South and blue production facilities
that may emerge in the North. There is also thepossibility of tapping into additional renewablecapacity at favourable cost from North Africa. The
extended infrastructure will help the country inmeeting the target set by the national strategy anddeliver green and low carbon hydrogen to industrial
clusters in the North of the country (Pianura
Padana) and drive the creation of other hydrogenvalleys in the South (Sicily, Puglia). Most of thesedevelopments will likely happen in conjunction with aswitch from fossil sources to hydrogen, thus allowing
the use retrofitted existing natural gas pipelines andpivoting on the availability of parallel routes. As theindustry scales up and costs fall, the grid will be
extended in order to connect with other markets(Austria, Germany, Eastern Europe) and maximize
the corridor role Italy may play in supplying Europe
with cost-competitive green hydrogen coming from
North Africa.

By 2030, The Italian backbone may stretch from Sicily
till the hydrogen valley of Emilia Romagna supportingan accelerated development of hydrogen in the
country as indicated by the Guidelines on the Italian
National Hydrogen Strategy. These developments will
be coupled with the potential to import hydrogen from
Tunisia, fully exploiting the cost advantage of solar
production and land availability in Northern Africa.
Most of these developments will consist of repurposed
natural gas pipelines as a result of the availabilityof parallel routes. Hydrogen could potentially betransported both from North Africa and from injection
points in Southern Italy to industrial clusters in theSouth and potentially integrating the blue production in
the North that could serve industrial uses in the area.
By 2035, the connection to Austria may already allowhydrogen from North Africa to be used in Northern
Europe, provided that gas consumption would be
gradually replaced by hydrogen and gas security ofsupply and balancing needs were guaranteed. On the
Eastern side, the interconnection to Slovenia connects
two large potential supply regions - Ukraine and North
Africa. By 2040, an interconnection to Switzerland
could be added to provide another connection to
North-Western Europe.

Luxembourg(Creos)Luxembourg’s network operator, Creos, operates
a network of 2.130 km with interconnections to
Belgium, France and Germany. It mostly serves
residential clients, but also serves industry mostly
located in the South of Luxembourg. In the longerterm, Luxembourg could also serve as transit ofhydrogen, while use of hydrogen in other sectors
beyond industry could also pick up.

By 2040, a north south connection could emerge,
if a significant decrease in both residential andindustrial gas flows allow it, and hydrogen demand
picks up A new pipeline would be built connecting to
Belgium at Bras to the MosaHyc project near Remich
at the German border. Another option might be a
repurposed pipeline, if the structure of end customers
would no longer justify continuing the conventional
operation and provided that security of supply of
the customers can be guaranteed. The network of
Luxembourg would connect Germany to Belgium andthus in the future could also serve a transit role.

28 / EXTENDING THE EUROPEAN HYDROGEN BACKBONE

Country
Netherlands(Gasunie)

BackgroundHydrogen infrastructure development

In the Netherlands Gasunie operates and owns a gas
network of approximately 11,700 kilometers.

By making maximum use of the existing natural
gas transport infrastructure, the national hydrogen
backbone can have a capacity of approximately
10-15GW by 2030. The first regions in the Netherlands
where hydrogen transport infrastructure can be built
are the Rotterdam-Rijnmond region (2024) and thenorthern Netherlands region (2025). The provinceof Zeeland, the Amsterdam-IJmond region and theprovince of Limburg will follow after that. The national
backbone can be ready by 2027 and used as apipeline ring by 2030, whereby the connection toseaports will also be an important point.

The most ambitious project Gasunie worked on
in 2020 concerns the development of a nationaltransport network for hydrogen, the ‘hydrogen
backbone’. For this network, Gasunie is repurposing
existing gas pipelines as these become available
due to declining demand for natural gas. Thisbackbone could be in place as early as 2026.
Thanks to this hydrogen infrastructure, theNetherlands and northern Germany can be themarket leaders in Europe for the global hydrogenmarket, just as they are now for natural gas. Thishydrogen backbone connects the large industrial
hubs to factories that will soon be producing
blue and green hydrogen. This will enable major
companies to wean themselves off natural gas,
massively reduce their carbon footprint and maintainjobs, their export strength and innovation capacity
for the Dutch economy.
As an independent network operator, Gasunie
wants to transport hydrogen from various providers
to the large industrial clusters in the Netherlands
through a newly developed hydrogen backbone withnationwide coverage. Together with TenneT and theMinistry for Economic Affairs and Climate Policy,
Gasunie is exploring the possibilities through a study
called HyWay 27, named for the year when the
backbone is supposed to be ready. This study willanswer the question whether and on what conditions
part of the existing gas infrastructure can be used
for hydrogen transport and storage. The first resultsof this study will be available over the course of2021, so that an investment decision can be madein time.

29 / EXTENDING THE EUROPEAN HYDROGEN BACKBONE

In collaboration with foreign network operators,
neighbouring industrial areas can be connected toeach other and the Zuidwending hydrogen storage
facility. A hydrogen partnership agreement was signedwith EWE, northern Germany’s largest regional energy
distribution company. EWE operates large natural
gas caverns, making them predestined to be part of
the future large-scale hydrogen storage landscape.
By mutually aligning plans for hydrogen transport andstorage, joint Dutch and northern German hydrogen
infrastructure is very much a possibility. Additionally,green hydrogen will be used to integrate large
amounts of offshore wind energy, particularly in thenorth of the Netherlands. Here the North Sea Wind
Power hub expects to build 180 GWs of offshore windby 2050 and a vital role is foreseen for hydrogen to
integrate the large amounts of energy into the systemand provide seasonal storage.

Country
Poland(GAZ-SYSTEM)

BackgroundHydrogen infrastructure development

Poland’s grid operator GAZ-SYSTEM operates
a large and increasing network of 11,056 km ofgas pipelines, connecting to Germany, the Czech
Republic, Belarus, Ukraine and in the future also
Denmark, Slovakia and Lithuania, to accelerate theswitch from coal to gas, foster competition, market
integration and ensure security of supply. Natural
gas and its infrastructure will play a pivotal role in
the Polish energy transformation by contributing toemission reduction by allowing a switch away fromcoal. An increase in gas demand is expected until
the 2030s.

A possible scenario is that Poland's hydrogen network
would be in place around 2035. Mainly aroundthe offshore wind potential in the North and theindustrial clusters in the South, Center and West. An
interconnection to Germany would allow to integrate
the emerging Polish hydrogen network with the rest ofEurope. Additionally, the connection to storage in a salt
cavern could be envisioned to enable offshore windenergy to be stored and re-used later in periods of
low wind speeds. Hereby providing a valid alternative
for gas or even coal peaker plants. It shall play animportant role to connect industrial clusters. Post
2040, all industrial clusters are to be connected, while
also the North South connection would complement
the integration of large amounts of renewable energy
in the North from offshore wind. Repurposing is notalways on option due to increasing demand on naturalgas, technical constraints and age existing networks.

Poland has recently published a draft Hydrogen
Strategy aiming for 2 GW of installed electrolyser
capacity by 2030. Moreover, the Polish government
has also published ambitious offshore wind capacity
targets of 5.9 GW by 2030 and 11 GW by 2040.
The draft Polish Hydrogen Strategy indicates theneed to build a hydrogen highway, which in its main
objectives is to connect the north with the south andthe emerging hydrogen valleys.
Poland is the third European country in terms ofcurrent hydrogen demand (1 million tons), mainly
located in the industry in the South plus industrial
clusters across the country. A hydrogen backbone
in Poland would be crucial to transport energy
produced offshore in the North to the demandregions in the South and other consumption centers,
while also opening the possibility of green hydrogen
imports from Scandinavian wind and decarbonise
hard-to-abate heavy industry. Import from otherdirections such as Ukraine, could be considered,once production ramps up.
However, due to the specificity the Polish energy
transition, it is important to bear in mind a certain
fluidity concerning the timeframes.

Slovakia(Eustream)

In Slovakia, Eustream operates a main east-west
450 km backbone network of 4 and sometimes 5large diameter pipelines, while the total length ofEustream’s network is 2,230km. Eustream’s network
connects Ukraine to the rest of Europe, thus its roleis mainly a transit country. In the future a similarrole is foreseen, only this time for large amounts ofgreen hydrogen which could potentially be supplied
from Ukraine. The large parallel pipelines would
provide a very cost-efficient way of transporting
energy, as it would mean substantial savings of themost important cost factor in hydrogen transport –compression.

30 / EXTENDING THE EUROPEAN HYDROGEN BACKBONE

Meanwhile, the vision of the Hydrogen Highway
outlined in the Polish Hydrogen Strategy could
be implemented. In the post 2040 perspective,
interconnections to Denmark through the Baltic Pipeand Lithuania (via GIPL) in the East opens up importroutes of hydrogen produced from (offshore) windin the Nordics and Baltics. Via the East of Polandhydrogen could be imported from the Ukraine andpossibly even transited into East Germany in a costefficient manner.
One important factor to take into account in developinga hydrogen network is the growing consumption ofnatural gas, which will still require large parts of thePolish transmission system until 2040. Any solution
concerning repurposing/retrofitting will be carefully
assessed on a case-by-case basis, due to technicallimitations and heterogeneity of existing network. An
analysis of such potential in the area of materials has
already been initialised by GAZ-SYSTEM - mappingof potential is in progress, as is the analysis of thetransmission system itself and its possible cooperation
with hydrogen.
By 2035 - in an optimistic scenario for hydrogen
supply from Ukraine or North Africa taking off – thetimeline could allow the repurposing of one of its
large diameter pipelines from Ukraine in the East to theAustrian and Czech networks in the West.
In the beginning with green hydrogen flows still
picking up, the lower capacity of hydrogen flowing
the repurposed network would also serve the currently
coal-based steel industry in the region near Košice andchemical industry near Šala.
Repurposed interconnections to Hungary in 2035 andPoland in 2040 would connect multiple markets andprovide security of supply.

Country

BackgroundHydrogen infrastructure development

Slovenia(Plinovodi)

Plinovodi, the TSO of Slovenia, operates a networkof 1,195 km, for domestic use while also playing
a transit role from Austria to Croatia and Italy. For
both using a doubled main backbone from its
capital Ljubljana into the east which then stretches
north into GCA’s and TAG network in Austria. With
the LNG terminal in Croatia on the Krk Island, up
and running since beginning of 2021, planed newinterconnection with Hungary and other changes,
the transit role will change. As a result, one ofthe pipelines of the main backbone could be
repurposed for hydrogen. Slovenia has nuclear
energy and Solar PV installation is expected toincrease. About one third of its electricity comesfrom coal. The coal fired power plant could be
replaced in the future by a gas-fired power plant,
thus providing another possible opportunity for thehydrogen. A hydrogen network could be used toserve industry users and power plants with available
green hydrogen via Austrian and FGSZ’s networkor with North African green hydrogen via SNAM's
network, as well as from domestic production.
While the hydrogen network could also play a transit
role, connecting sources of demand and supply,and integrating the energy systems in Italy, Austria,
Hungary and Croatia.

By 2035, a regional backbone could emerge. The
current main gas pipeline is doubled and together
with the changing gas flows due to changes on energy
markets, new interconnection with Hungary, andupgrade of connection with Croatia, it enables the
repurposing of parallel natural gas pipelines. Thus,
the domestic production and consumption can beconnected. There would be hydrogen interconnections
from Slovenia to Hungary and Italy which connects
the national hydrogen markets, but also major greenhydrogen supply sources (e.g. North Africa). The
connection to Austria and possibly Croatia would
ensure that the European Hydrogen Backbone
becomes an integrated hydrogen network stretchingfrom South-Eastern to North-Eastern Europe.

Spain(Enagás)Enagás operates an extensive gas transmission
network in Spain that comprises over 11,000 km
of gas pipelines. This network has six international
connections: two with Africa via Tarifa and Almeria(linking with the Magreb and Medgaz gas pipelines,
respectively); two with Portugal via Badajoz and Tuy;and another two with France via Irun and Larrau.

By 2030, industrial clusters within reach of the
proposed parallel network and therefore relevant for
initial development of the backbone are along theMediterranean coast and in the center and north of thepeninsula.

The Spanish Hydrogen Roadmap recognises that
renewable hydrogen is a key sustainable solution forthe decarbonisation and the development of a highvalue-added green economy. For 2030, the strategy
foresees an installed capacity of 4 GW electrolysers
and a series of milestones in the industrial, mobility
and electricity sectors. The hydrogen pipeline
network in Spain is based on a high-level analysis
and it would enable the coexistence of both natural
gas and hydrogen for a defined period, optimising
the use of current infrastructure to serve potential
demand in industry and guaranteeing security ofsupply. At the same time the backbone aims toharness the significant potential of Spain´s solar PV
and onshore wind resources, which could enable theexportation of green hydrogen to other European
countries. Hereby, also ensuring the role of Spain
as a transit country, with pipeline infrastructure totransport low cost hydrogen produced in North
Africa to demand centres in Western Europe.

31 / EXTENDING THE EUROPEAN HYDROGEN BACKBONE

Later, the development of the network will guarantee
cohesion between the different demand regions,also integrating the multiple supply points that will be
distributed across the geography.
Spain’s long-term ambition is to be one of themain hydrogen suppliers in Europe, building on its
significant large-scale solar PV and wind and hybrid
potential to produce green hydrogen.
The national backbone will enable this by connecting
to France through the existing connections by Larrau(2035) and Irún (2040) and creating a new route
through Catalonia by 2040. Connections to North
Africa can be made from 2035 to complement national
supply with imports from the south to cover thedemand in Central Europe.

Country
Sweden(Nordion Energi)

BackgroundHydrogen infrastructure development

The Swedish climate target is to reach net-zeroemissions of greenhouse gases by 2045. The
decarbonisation efforts necessary for this goal to beachieved are many and the visionary and ambitious
scenario of a dedicated hydrogen backbone not
only supports this goal, but it brings additional
robustness to the entire energy system. The
backbone would aid the transmission of energy from
north to south creating a sustainable, flexible, andbalanced energy system.

By 2030, significant industrial use of hydrogen is
expected, and the total energy demand requires
large scale-up of RES and transmission solutions.
Large onshore wind parks situated mainly in scarcely
populated areas, and offshore wind parks emerge
across the country. The southern backbone stretches
further north not far from the Stockholm region of
Sweden, linking industrial demand centres and cities
in southern and central Sweden. In the most northernparts of Sweden an additional backbone emerges
with an interconnection to the Finnish backbone. The
transforming mining and steel industries are the main
drivers behind the hydrogen demand in the most
northern parts of the country.

During the late 2020s, the Swedish backbone
emerges on the coastal region in the south-west of
the country with an interconnection to the Danish
grid. Chemical and petrochemical industries situatedclose to the backbone are the drivers of hydrogen
demand. Given the absence of parallel piping
infrastructure, dedicated hydrogen pipelines will
have to be newly built.
Given the nature of Sweden’s geography, terrain,
and location of industrial clusters, hydrogen island
grids are starting to arise and are subsequently
connect via regional networks.

By 2035, the southern and northern backbones
connect, creating a hydrogen corridor across thecountry, linking the backbones of Denmark, Sweden,and Finland to the European hydrogen backbone. A
new energy transmission network from north to south
would be a reality. An offshore connection across theGulf of Bothnia, via an energy island, would be thesecond possible interconnection between Sweden and
Finland.
By 2040, a second interconnection (offshore) from
Denmark could emerge via the Kattegat sea area,
which is the fourth possible interconnector for Sweden.

32 / EXTENDING THE EUROPEAN HYDROGEN BACKBONE