Green Hydrogen

Investment and
Support Report
Hydrogen Europe’s input for a
post COVID-19 recovery plan
 CONTENTS
01 EXECUTIVE SUMMARY

03 INTRODUCTION

05 HYDROGEN PRODUCTION

06 4,4 million tonnes green hydrogen production in the EU

Import 3.0 million tonnes hydrogen from North Africa

08
and Ukraine

Tendering renewable energy with electrolyser capacity

10
for hydrogen production

12 8,2million tonnes low carbon hydrogen production by

SMR with CCS and low-carbon electrolysis

13 1,3 million tonnes low carbon hydrogen production by

coal gasification with CCS

14 Overview of hydrogen production investments

14 HYDROGEN INFRASTRUCTURE AND STORAGE

Hydrogen transport pipeline backbone throughout Europe

15
connected to Africa

3.700 Hydrogen refuelling stations (HRS), bunkering and

16
other fuelling points

17 Hydrogen Port Facilities

17 3 million tonnes hydrogen storage capacity in salt caverns

Overview hydrogen infrastructure and storage

18 investments
 CONTENTS
19 HYDROGEN APPLICATIONS

9,1 million tonnes hydrogen for the traditional industry

19 feedstock

22 2,5 million tonnes hydrogen for new industry feedstock

2 million tonnes hydrogen replacing or blended in

25 natural gas for heating

27 1,8 million tonnes hydrogen for mobility

1,5 million tonnes hydrogen for balancing electricity

28
production

28 Overview Hydrogen application investments

29 SCALE-UP HYDROGEN MANUFACTURING CAPACITY

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01 EXECUTIVE SUMMARY
Hydrogen will play a pivotal role in achieving an affordable, clean and prosperous
economy. To recover from the economic recession caused by the COVID-19 virus,
investments in building a hydrogen economy can contribute to a clean and
affordable energy system, but above all can scale up an innovative new hydrogen
manufacturing industry, creating new green jobs and economic growth. 

To get insight into building such a hydrogen system, consisting of production,

infrastructure and storage, and hydrogen applications, an estimate of the necessary
investments and required support has been made. These investments create new
markets for hydrogen products, equipment and applications, such as electrolysers and
fuel cells. Based on these data, European Member States together with the European
Union could design policies and support schemes, especially for a post COVID-19
economic recovery plan.

In this document, to estimate the total investments for building a hydrogen system up
to 2030 the FCH JU study Hydrogen Roadmap Europe has been used for the hydrogen
demand assumptions in 2030 and Hydrogen Europe’s paper 2x40 GW Green Hydrogen
Initiative has been used for green hydrogen production assumptions in 2030. Overall,
the total investments up to 2030 are estimated to be 430 billion Euro, with an
estimated necessary support of 145 billion Euro.

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Table 1

Starting from these investments, an innovative and competitive hydrogen

manufacturing industry can start up, build up and scale-up. The EU and
Member States could support the construction of this industry, by providing –
amongst others – loans, mezzanine financing and even equity. However, many
companies mention that the most important factor for them in order to
decide if expanding or not their manufacturing capacity is that they can be
sure that targets for the market, such as the 2x40 GW electrolyser capacity in
2030 and hydrogen demand increase, are secured and guaranteed by
governments.

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02 INTRODUCTION
To build a hydrogen system and help the economy recover from the recession caused
by the COVID-19 virus, with an increasing demand for clean hydrogen applications
together with scaling up hydrogen production and building up hydrogen
infrastructure, large scale investments are necessary. These investments need to be
initiated and stimulated through EU and governments policies and support. However,
these hydrogen investments can create a market to scale up, start-up and grow a
competitive and innovative European hydrogen manufacturing industry. If Europe is
at the forefront of these hydrogen developments, it can create a world class
manufacturing industry, especially in electrolyser, fuel cell and other hydrogen
equipment and manufacturing applications.

In this report we estimate the total needed investments in building a hydrogen system
up to 2030. Investments in renewable energy and hydrogen production, in hydrogen
infrastructure and storage and in hydrogen applications are estimated, together with
an indication of the financial support that is needed in this first phase of building a
hydrogen system. These investments give insight into the markets for specific
hydrogen products, equipment and applications. Based on these insights policies and
support schemes could be designed, especially for a COVID-19 economic recovery plan.

The starting points and assumptions to estimate total investments for hydrogen up to
2030 are from Hydrogen Europe’s paper ”Green Hydrogen for a European Green Deal -
A 2x40 GW Initiative” (2x40 GW Green Hydrogen Initiative)[1] and the FCH JU report
“Hydrogen Roadmap Europe - A sustainable pathway for the European Energy
Transition” (Hydrogen Roadmap Europe)[2].

The hydrogen demand, according to the Hydrogen Roadmap Europe ambitious

scenario in 2030, will be 665 TWh or 16,9 million tonnes. This hydrogen demand needs
to be produced in the EU or needs to be imported. According to the 2x40 GW Green
Hydrogen Initiative, 7,4 million tonnes of hydrogen is supplied by green hydrogen, 4,4
million tonnes is produced in the EU, while 3 million tonnes is imported from North-
Africa and Ukraine. This implies that 9,5 million tonnes of hydrogen need to be
produced additionally, with the lowest carbon content as possible. It is assumed that
the present amount of hydrogen can be produced through electrolysis, benefitting
from other low-carbon electricity sources in Europe, and also from natural gas with
Carbon Capture and Storage (CCS), producing al together 8,2 million tonnes low
carbon hydrogen. The remaining new low carbon hydrogen production, 1,3 million
tonnes, will be from coal gasification with CCS.

[1] Hydrogen Europe, Green Hydrogen for a European Green Deal – A 2x40 GW initiative, April 2020
[2] FCH JU (Fuel Cells and Hydrogen Joint Undertaking), Hydrogen Roadmap Europe – A sustainable pathway for
the European energy transition, January 2019

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Table 2: Hydrogen demand 2030 according to FCH JU Hydrogen Roadmap Europe and hydrogen
roduction according to Hydrogen Europe 2x40 GW Green Hydrogen Initiative and low carbon hydrogen
production assumptions.

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03 HYDROGEN
PRODUCTION

Hydrogen demand in the EU in 2030 according to the FCH JU’s Hydrogen Roadmap
Europe is 665 TWh or about 16,9 million ton. This amount of hydrogen will be supplied
as follows:

According to the 2x40 GW Green Hydrogen Initiative, 173 TWh or 4,4 million tonnes
green hydrogen will be produced in the EU and 118 TWh or 3 million tonnes green
hydrogen will be imported from North Africa and Ukraine. 

It is assumed that the other part of the hydrogen supply in 2030, 9,5 million
tonnes, will be low carbon hydrogen:

324 TWh or 8,2 million tonnes (the present grey hydrogen production) will be
produced from natural gas by SMR (Steam Methane Reforming) with CCS,
realising a 90% CO2 emission reduction, and from electrolysis from
decarbonised electricity sources.

50 TWh or 1,3 tonnes low carbon hydrogen is assumed to be produced from new
coal by gasification with CCS/CCU whereby nearly 100% CO2 emission reduction
can be realised. These coal gasification plants will be pre-dominantly realised in
Poland, Bulgaria, Romania and Hungary.

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4,4 MILLION TONNES GREEN HYDROGEN PRODUCTION IN THE

EU

The realization of 40 GW electrolyser capacity in the EU, producing 4,4 million tonnes
of clean hydrogen, requires the realization of up to 80 GW of additional renewable
electricity production, wind offshore, wind onshore and solar PV. Total investments are
up to 80 and 90 billion Euro, see table 3. These could be lowered by maximising the
use of already existing carbon free electricity available in Europe.

The realization of the 6 GW captive electrolyser capacity, whereby the electrolyser is

located at the hydrogen demand and connected to the electricity grid, does not need
a hydrogen infrastructure or storage capacity. The only restriction to this is the
electricity grid capacity and, therefore, these electrolyser installations will be in the 100
MW to 1 GW range. A load factor of 8.000 could be realised through electrolysers being
connected to the grid, benefiting from stable electricity supply, together with a strong
Guaranties of Origin system and traceability system, whereby the electricity could
come from renewable and low carbon electricity sources This approach could yield
synergies and benefit from sector coupling: additional flexibility for the electricity
system and additional revenues for electrolysers.However, realizing a load factor of
8.000 hours means that the electricity cost that needs to be paid will be higher than
the electricity production cost by the renewables due to grid fees, storage and flexible
costs in the electricity system.

The realization of the 34 GW hydrogen production plants, whereby the electrolyser is

located near the resource requires hydrogen infrastructure and storage. The load factor
will be restricted by the renewable resource. To realize 5.000 hours load factor,
especially in the south of Europe, a smart combination of solar PV with wind that
needs to be connected at location to the electrolyser capacity is required. Lower load
factors, for example by connecting solar PV capacity one to one to the electrolyser
capacity, would mean also a lower load factor for the pipeline and will need much
more hydrogen storage capacity. Meaning, in the end, a higher system cost.

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Table 3: Investments in solar, wind and electrolyser capacity to produce 4,4 million ton green hydrogen in
the EU.

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IMPORT 3.0 MILLION TONNES HYDROGEN FROM NORTH AFRICA

AND UKRAINE

The realization of 40 GW electrolyser capacity in North Africa (30 GW) and Ukraine (10
GW), producing 4 million tonnes of green hydrogen, requires the realization of about
77 GW of additional renewable electricity production, wind onshore, solar PV and solar
CSP. The total investments for renewable energy and electrolyser plants are about 92
billion Euro, see table 4.

The realization of the 30 GW hydrogen production plants in North Africa and 10 GW

hydrogen production plants in Ukraine, whereby the electrolyser is located near the
resource requires a hydrogen infrastructure and storage or a direct connection to an
ammonia plant. The load factor will be restricted by the renewable resource. To realize
5.000 hours load factor in North Africa, a smart combination of solar with onshore
wind or a smart combination of solar PV with solar CSP, that needs to be connected at
location to the electrolyser capacity is required. To realize 5.000 hours load factor in
Ukraine, a smart combination of solar PV with onshore wind, that needs to be
connected at location to the electrolyser capacity is required. Lower load factors, for
example by connecting solar PV capacity one to one to the electrolyser capacity,
would mean also a lower load factor for the pipeline and it will need much more
hydrogen storage capacity and therefore higher hydrogen cost for the consumer.

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Table 4: Investments in solar, wind and electrolyser capacity to produce 4 million ton green hydrogen in North
Africa and Ukraine.

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TENDERING RENEWABLE ENERGY WITH ELECTROLYSER

CAPACITY FOR HYDROGEN PRODUCTION

A tender procedure for the production of green hydrogen needs to be an integrated

one for both green electricity production and the conversion of electricity into
hydrogen by electrolysis. In such a tender procedure, a price is offered per kg of
hydrogen produced. The one with the lowest bid wins the tender. When the
production costs are higher than the market price, the idea is that governments
subsidise the difference.

However, that requires a 15-20 year relation, with yearly payments by governments. As
part of an economic recovery program, it is maybe interesting to capitalize the total
amount of subsidies that will be paid over a 15-20 year period to an investment subsidy
upfront when realizing the project. This will reduce investment cost, making it easier
and cheaper to finance these projects.

Tendering captive hydrogen production. Hydrogen production is at the demand,

while renewable electricity production is at another place, transported via the
electricity grid to the electrolyser. The electrolyser can produce at base load 8000
hours but needs the electricity system for transport, storage and flexibility. Because of
grid capacity constraints, the electrolyser capacity will be restricted to a couple of 100
MW. So, in this case the electricity costs at the electrolyser include the electricity
production cost plus grid fees for transport, storage and flexibility cost. Grid fees of 20-
40 Euro/MWh are assumed. These costs could be waived by regulation or compensated
by an extra subsidy of 1-2 Euro per kg of hydrogen. This needs to be arranged
separately from the tender.

The tender will be based on the production cost for hydrogen (renewable/carbon free
electricity plus electrolyser cost included). Let’s assume that on average there is a
difference between production cost and market price for hydrogen of 1 Euro per kg.
That would mean a subsidy of 1 billion Euro per year for the 6 GW captive electrolyser
capacity installed in the EU that produces about 1 million tonnes hydrogen. If we
capitalize this over a period of 15 years it is roughly 10 billion Euro. The total
investments were estimated to be 29 billion Euro. So, this tender based investment
subsidy percentage will be between 30% and 40%.

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Tendering integrated renewable hydrogen production plants. Hydrogen is

produced by electrolysers that are directly coupled to the renewable electricity
production. Because the electrolysers are directly connected to these intermittent
resources, these electrolysers do not produce in base load. We assume that by a clever
combination of solar and wind, solar PV and solar CSP or by offshore wind alone a load
factor of 5.000 hours can be realised. Although lower load factors for the electrolyser, it
is assumed that hydrogen production costs for these integrated renewable hydrogen
production plants can be the same or lower than captive hydrogen production,
because of better resource conditions, larger multi GW scale and integrated renewable
energy/electrolyser system optimization.

The problem in this case is that the hydrogen infrastructure, hydrogen pipelines and/or
ships plus salt cavern storage availabilities are limited according to geography.
Therefore, transport and storage costs at the beginning will be much higher and/or
hydrogen will need to be blended in the natural gas grid which reduces its value.
Therefore, it is necessary to compensated this by an extra subsidy, most probably 1-2
Euro per kg of hydrogen. However, this will take place only for a couple of years, when
the hydrogen infrastructure is ready this can be reduced and eventually will not be
needed.

The tender will be based on the production cost for hydrogen (renewable electricity
plus electrolyser cost included). Let us assume that on average there is a difference
between production cost and market price for hydrogen of 1 Euro per kg, the same as
for captive hydrogen production, although it is expected to be lower.

For the 34 GW integrated renewable hydrogen plants in the EU, producing 3.4 million
tonnes hydrogen, the subsidy will be 3,4 billion Euro per year. Or, by capitalizing this
amount, it is roughly 35 billion Euro. The investment is about 67 billion Euro, so about a
50% tender based investment subsidy. For the 10 GW integrated renewable hydrogen
plants in Ukraine, producing 1 million tonnes hydrogen, the subsidy will be of 1 billion
Euro per year. Capitalized about 10 billion Euro, which is about 50% of total
investments.

For the 10 GW integrated renewable hydrogen plants in the North Africa, producing 1
million tonnes of hydrogen, the subsidy will be 3 billion Euro per year. Capitalized
about 30 billion Euro, which is about 40-50% of total investments.

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Table 5: Investments and tender based capitalized investment subsidies in renewable energy and electrolyser
capacity according 2x40 GW green hydrogen initiative

8,2 MILLION TONNES LOW CARBON HYDROGEN PRODUCTION

BY SMR WITH CCS AND LOW-CARBON ELECTROLYSIS

The existing hydrogen production in the EU is predominantly from natural gas by

Steam Methane Reforming (SMR). In a study by the IEA[1], five different CO2 capture
technologies added to a SMR Plant that produces 75.000 tonnes hydrogen per year
have been investigated with respect to the CO2 capture rates and the required
investments. CO2 capture rates of these 5 capture technologies varies between 55%
(5,5 kg CO2/kg H2) and 90% (9 kg CO2/kg H2) of CO2 emissions. Additional
investment cost range between 40 and 176 million Euro, increasing hydrogen cost
between 0,23 and 0,57 Euro/kg H2.

Today around 8.2 million tons of grey hydrogen are produced in the EU – most of it
by SMR from natural gas When we assume that 90% of the CO2 emissions need to
be abated, the total additional investments are 19,2 billion Euro. Subordinated loans
could help to realize the carbon capture installations. Not included in these
investments are the CO2 transport and storage costs.

Low-carbon hydrogen with available clean electricity will also contribute to these
amounts as it is unlikely that all the current SMR capacity can be retrofitted with
CCS, given space and CO2 storage constraints.

[1] IEAGHG Techno Economic Evaluation of SMR Based Standalone (merchant) Plant with CCS, 2017/02,
February 2017

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1,3 MILLION TONNES LOW CARBON HYDROGEN PRODUCTION BY

COAL GASIFICATION WITH CCS

The future demand for hydrogen in 2030 is higher than the existing fossil fuel-based
hydrogen production and the projected hydrogen production by the 2x40 GW Green
Hydrogen Initiative. Therefore, new low carbon hydrogen needs to be produced from
fossil fuels with capturing and storing the CO2, or by relying in a more extensive way on
the production of low carbon hydrogen with carbon free and low carbon electricity
from the grid. The EU does not have a lot of own gas and oil production, it needs to
import gas mainly from Russia, Norway and Algeria by pipeline and oil from many
different countries by ship. The domestic fossil energy resource available in the EU is
coal, especially in Poland, Bulgaria, Romania, Hungary and Germany. It could be
interesting to produce low carbon hydrogen from coal gasification, capturing and
storing the CO2 as a start and expanding to green hydrogen production from biomass
gasification.

In Australia, Kawasaki Heavy Industries is building a coal gasification plant with carbon
capture and storage together with a hydrogen liquefaction plant and shipping the
hydrogen to Japan. A coal gasification plant producing 225.500 tonnes of hydrogen per
year is built with nearly 100% carbon capture and storage. The investments are of 2
billion Euro. If we assume similar investment costs in Europe to develop coal
gasification plants, then a total investment of 11,5 billion Euro is required. If indeed
nearly 100% CO2 emissions could be captured and stored, an investment grant of 25%
with additional subordinated loans could stimulate realization[1].

[1] Study on Introduction of CO2 free energy to Japan with Liquid Hydrogen, Shoyi Kamiya, Motohiko Nishimura,
Eichi Harada, Physics Procedia 67(2015)11-19

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OVERVIEW HYDROGEN PRODUCTION INVESTMENTS

Table 6: Investments in hydrogen production

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HYDROGEN
04 INFRASTRUCTURE
AND STORAGE
HYDROGEN TRANSPORT PIPELINE BACKBONE THROUGHOUT
EUROPE CONNECTED TO AFRICA

According to the hydrogen backbone infrastructure map in the 2x40 GW Green

Hydrogen Initiative, the main part of the hydrogen backbone is converting existing
natural gas pipelines into hydrogen pipelines. An estimated 50.000 km natural gas
pipeline infrastructure needs to be converted to a hydrogen pipeline infrastructure. Next
to this, about 5.000 km of new hydrogen pipelines to Africa, Greece-Black Sea to Italy,
Portugal-Spain, is needed. The specific investment cost in new transport pipeline
capacity is 1 million Euro per 10 GW capacity per km[1]. A new pipeline from Africa to
Greece and Italy, 2.500 km with capacity of 20 GW, will therefore cost 5 billion Euro[2].

The German gas transport grid operators have proposed to realise a hydrogen backbone
in Germany that connects large scale hydrogen production with the hydrogen demand
in large chemical, petrochemical and steel plant sites and with hydrogen salt cavern
storage. The hydrogen backbone will be realised to a large extent by converting natural
gas pipelines and with some new hydrogen pipelines to make the proper connections. A
total length of 5.900 km hydrogen backbone is proposed in Germany. A similar hydrogen
backbone plan is proposed in the Netherlands, for the period 2023-2027. In the
Netherlands the retrofit and partial new hydrogen pipeline cost will be about 1,5 billion
Euro. A fully new built hydrogen backbone (so not by converting the natural gas
pipelines into a hydrogen pipelines) would have cost about 5-6 billion Euro. So the cost
to re-use and convert natural gas pipelines for hydrogen are about 25% of the cost to
build a fully new hydrogen pipeline Backbone.

The estimated investment costs for a European-North Africa-Ukraine hydrogen

backbone, with 50.000 km converted natural gas pipelines and 5.000 km new hydrogen
pipelines with a capacity of 20 GW, will be

50.000 km* 2 million Euro/km *0,25 = 25 billion Euro for converting natural gas
pipelines,
5.000 km * 2 million Euro/km = 10 billion for new hydrogen pipelines.

[1] Ad van Wijk, Frank Wouters, Hydrogen, the bridge between Africa and Europe, to be published in Shaping an
inclusive Energy Transition, Springer, 2020
[2] Analysis of advanced H2 production & delivery pathways, Strategic Analysis, June 2018

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Converting pipelines could be stimulated with subordinated loans. However, new

hydrogen pipelines initiated by the European Union, North African countries and
Ukraine, jointly owned by gas transmission system operators of the countries involved,
need about 50% grants/subsidies together with 50% subordinated loans.

3.700 HYDROGEN REFUELLING STATIONS (HRS), BUNKERING

AND OTHER FUELLING POINTS

The FCH JU hydrogen roadmap Europe estimates that 3.740 HRS in 2030 needs to be
installed, requiring 8,2 billion Euro total investments. Next to this there is a need for
hydrogen bunkering stations for ships along rivers Rhine, Danube, Po and others.
Bunkering stations for sea ships in harbours. Fuelling stations for drone-tubes, etc. In
total an investment needs of about 10 billion Euro up to 2030 is estimated.

50% subsidy/grant (like in Germany) plus 50% subordinated loans

Figure 1. Development Hydrogen Re-fuelling

Station in the EU, source FCH JU

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HYDROGEN PORT FACILITIES

Port facilities are needed to import and export hydrogen by ship and transport the
hydrogen to the hinterland of these ports. Port facilities include, amongst others, liquid
hydrogen terminals, liquid hydrogen storage tanks, liquid hydrogen truck loading,
evaporation units, Liquid Organic Hydrogen Carrier (LOHC) terminals, storage tanks,
dehydrogenation plants, ammonia terminals, storage tanks, ammonia cracking
installations, etc.

Estimated investments that need to be done in a port, are:

Liquid hydrogen terminal and storage, Capex about 1 billion Euro

Ammonia terminal, storage and ammonia cracking installation, Capex about 300
million Euro

LOHC terminal, storage and dehydrogenation plant, Capex - especially

dehydrogenation - plant 200 million Euro

Port pipeline infrastructure for hydrogen, ammonia, bunkering facilities and multi
modal logistic centres, Capex 1 billion Euro.

In total an investment of about 2,5 billion Euro in port facilities is needed. An

estimated total of 8 ports in Europe needs to realize these port facilities, which is a
total investment of 20 billion Euro.

3 MILLION TONNES HYDROGEN STORAGE CAPACITY IN SALT

CAVERNS

At least, roughly estimated, 1/3 of green hydrogen needs to be stored before use, due to
the intermittency of solar and wind resources and the base load demand for hydrogen
in industry and mobility. This is an amount of 2 million tonnes hydrogen. Next to this,
about 20% of low carbon hydrogen needs to be stored before use. This 20% is the
same percentage as for natural gas storage due to seasonal variation in demand. This
equals to about 1 million tonne hydrogen storage. This gives a rough estimate of a total
3 million tonnes of hydrogen storage capacity needs.

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Each salt cavern can store on average 6.000 tonnes hydrogen, so 500 salt caverns are
needed. The average cost for one salt cavern is about 100 million Euro. A total 50
billion Euro investments is needed in hydrogen storage. A salt cavern needs to be filled
up with cushion gas first, before the storage facility can be operational. About 3 million
tonnes hydrogen is needed as cushion gas. Therefore, upfront investments are needed
for about 3 million tonnes hydrogen, times 1,5 Euro/kg means 5 billion Euro for cushion
gas.

The total investments in salt cavern hydrogen storage are 55 billion Euro, 50 billion
Euro Capex investments and 5 billion Euro for cushion gas.

OVERVIEW HYDROGEN INFRASTRUCTURE AND STORAGE

INVESTMENTS

Table 7: Investments in hydrogen infrastructure and storage

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05 HYDROGEN
APPLICATIONS
In the ambitious scenario of the FCH JU Hydrogen Roadmap Europe, the hydrogen
demand in 2030 is 665 TWhHHV or about 16,9 million tonnes as a starting point. We
have made some small adjustments for the hydrogen demand for feedstock and for
heating, compared to the roadmap.

9,1 MILLION TONNES HYDROGEN FOR THE TRADITIONAL

INDUSTRY FEEDSTOCK

The traditional use of hydrogen, as feedstock in chemical and refineries (9,1 million
tonnes in 2030), does not need additional or new investments in equipment. The cost
of decarbonising  the production of this hydrogen is already included in the section
“production” and “infrastructure and storage” For the other hydrogen applications, new
feedstock, hydrogen heating, mobility and electricity balancing, the investment in new
hydrogen equipment, appliances, etc. is necessary and estimated in the next chapters.

2,5 MILLION TONNES HYDROGEN FOR NEW INDUSTRY

FEEDSTOCK

1 million tonnes hydrogen for 20 million tonnes steel production

In Sweden Hybrit, a joint venture between SSAB, LKAB and Vattenfall, is developing
since 2016 a process where hydrogen is used for direct reduction of iron ore, called DRI
(Direct Reduction of Iron). With the DRI process about 45-55 kilo hydrogen is needed to
produce 1 tonnes of crude steel[1]. 1 million tonnes hydrogen is therefore needed to
produce about 20 million tonnes steel. The total steel production in the EU was about
160 million tonnes in 2019, assumed that it will increase to 200 million tonnes, then the
crude steel production with hydrogen as feedstock can cover 10% of steel production
in the EU.

According to Hybrit, the production cost for crude steel with the DRI process will be
20-30% higher, this is partly caused by higher fuel cost and extra investment cost for
retrofitting and installing new furnaces, ovens and other equipment in steel plants.

[1] Hybrit, Fossil free Steel, summary of findings from HYBRIT pre-feasibility study 2016-2017
Assessment of hydrogen direct reduction for fossil-free steelmaking, Valentin Vogl, Max Åhman, Lars J. Nilsson Journal of
Cleaner Production 203 (2018) 736-745

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The production costs for 1 tonne of steel are about 300 Euro/tonne. If you want to fully
compensate this price difference, about 75 Euro per tonne crude steel needs to be
supported, which means about 1 billion Euro per year.

However, Hybrit has assumed higher hydrogen production costs than via the 2x40 GW
Green Hydrogen Initiative, even when transport and storage costs are included.
Therefore, it seems logical to stimulate realizing DRI steel plants, by giving an
investment grant and/or subordinated loans with low interest rates. The Capex cost of
a DRI steel plant is estimated at about 350-450 Euro per ton of produced steel. So total
investment to produce 20 million ton steel is about 8 billion Euro. A 25% investment
grant could be considered.

Figure 2. schematic overview steel production via blast furnace and via DRI process,
source Hybrit

1,5 million tonnes hydrogen for 3 million tonnes synthetic kerosene and 2
million tonnes synthetic diesel

The kerosene demand in the EU in 2018 was 62,8 M tonnes. Kerosene is one of the
products produced from oil by a refinery. On average 7,5% of the refinery output is
kerosene.

[1] Ad van Wijk, Frank Wouters, Hydrogen, the bridge between Africa and Europe, to be published in Shaping an
inclusive Energy Transition, Springer, 2020
[2] Analysis of advanced H2 production & delivery pathways, Strategic Analysis, June 2018

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Figure 3. Historical demand for oil products in the EU 2018; source Wood McKenzie

Kerosene can also be produced by synthesis of hydrogen and carbon monoxide in a

Fischer Tropsch (FT) process and is called synthetic kerosene. Theoretically, for the
production of 1 tonne of kerosene about 0,3 tonnes of hydrogen is needed. However,
the output of the Fischer Tropsch synthesis is not only kerosene. A Fischer Tropsch
synthesis can deliver as output about 60% kerosene and 40% diesel. Therefore, 1,5
million tonnes hydrogen in a FT synthesis will deliver 3 million tonnes synthetic
kerosene and 2 million tonnes synthetic diesel.

We assume that only the investment cost in a Fischer Tropsch installation is needed to
produce synthetic kerosene and diesel. The CO will be supplied from other processes,
from biomass gasification plants (green CO) or synthesis gasses from conventional steel
plants or refineries where the CO is re-utilized (CCU carbon capture and utilization).
Investment cost for Fischer Tropsch is estimated to be 650 Euro per tonne synthetic
fuel output[1] (kerosene + diesel). The total investment is therefore 3,25 billion Euro. An
investment grant of 25% could be considered.

[1] Carbon Neutral Aviation with current engine technology: the take-off of synthetic kerosene production in the
Netherland, Quintel and Kalavasta, March 2018
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2 MILLION TONNES HYDROGEN REPLACING OR BLENDED IN

ATURAL GAS FOR HEATING

The final gas consumption in the EU28 in 2017 was 2.783 TWh. This was mainly for
heating, both for space heating of houses and buildings, and for high and medium
temperature heating in industry such as process heat in food and paper industry and
high temperature heat in chemical, glass/ceramics industry. We assume that natural gas
consumption in 2030 will be around 2.500 TWh. When 2 million tonnes hydrogen is used
for low and high temperature heating, this will replace 3,33% (energy content) of the gas
consumption (80 TWh) or will mean 10% (volume based) blending hydrogen into the gas
system.

Scenario 1: 100% pure hydrogen for heating replacing 3,33% of natural gas
demand

We assume in this scenario that 100% pure hydrogen is used to replace 3,33% of the gas
demand in 2030. 75% of this hydrogen (1,5 million tonnes) is for heating houses and
buildings and 25% for process/high temperature heat. This will imply the below numbers
of hydrogen installations for heating in the EU in 2030.

Hydrogen for space (low temperature) heating in houses and buildings is an interesting
option, especially for rural areas, small villages and old town/historical city centres. Other
space heating options, such as all electric heat pump or district heating are in these
areas not applicable and/or more expensive. We assume that 1,5 million tonnes of
hydrogen in 2030 will be used in houses/buildings in these areas. After isolation, it is
assumed that these houses consume on average about 250 kg of hydrogen (equivalent
of 900 m3 natural gas) when heated by a hydrogen boiler. 125 kg of hydrogen is used to
heat up a house with a hybrid heat pump hydrogen boiler system and 250 kilo hydrogen
is used in a fuel cell heat pump system that produces both heat and electricity.
Regions/areas/cities are fully converted from natural gas to hydrogen, which means that
the natural gas distribution grid, including measurement equipment, in these areas is
retrofitted to 100% hydrogen. Hydrogen boilers are already on the market and will not
cost more than natural gas boilers when produced in large quantities. Also fuel cells,
with a reformer to reform hydrogen from natural gas are already on the market in Japan,
the so-called Ene-farm. In a 100% hydrogen supply, these reformers are not necessary, of
course when 100% hydrogen is supplied, but on the other hand a small heat pump is
required to produce enough heat.

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A scenario in which 8 million houses/house equivalents are converted to 100%

hydrogen, is given below which consumes 1,5 million tonnes hydrogen:

2 million houses/house equivalents with a hydrogen boiler. 1.500 Euro per boiler
means total investments of 3 billion Euro.

4 million house/house equivalents with a hybrid system, heat pump plus a

hydrogen boiler for peak heating and hot water. A 4.000 Euro investment per
hybrid system means a total investment of 16 billion Euro.

2 million houses/houses equivalents with a 1-2 kWe fuel cell heat pump system for
electricity and heat production.7.500 Euro investment per system means a total
investment of 15 billion Euro.

8 million houses/houses equivalents gas distribution grid infrastructure needs to

be converted to hydrogen. Costs are about 200-300 Euro per house to convert
natural gas distribution grid and measuring equipment into hydrogen. Total
conversion cost are 2 Billion Euro[1].

Next to the hydrogen use for space heating, also 0,5 million tonnes of hydrogen for
process heat and high temperature heat is estimated to be used in boilers, furnaces,
gas-turbines, gas-engines, etc. If an average load factor of 5.000 hours is assumed,
the total installed capacity that needs to be retrofitted to pure hydrogen is of about 4
GW. Retrofit cost for the installations plus gas infrastructure is about 250 Euro/kW.
Total retrofit cost would be 1 billion Euro.

We can translate these numbers into a number of areas in Europe that will convert
from natural gas to hydrogen. Each area is equivalent to 200.000 houses/house
equivalents, plus industry. Which means 40 areas/hydrogen valleys in Europe
converted from gas to hydrogen by 2030. The total investments in this scenario are
estimated to be 37 billion Euro.

[1] Waterstof als optie voor een klimaatneutrale warmtevoorziening in de bestaande bouw, TNO Marcel Weeda,
Robin Niessink, March 2020

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Scenario 2: 10% volume hydrogen blending in natural gas system

We assume in this scenario that 10% volume hydrogen is blended in natural gas in
2030. Up to 20% volume can be blended in natural gas before gas appliances need to
be retrofitted or replaced. Up to 20%, there is also no significant need to retrofit or
adjust the natural gas infrastructure. However, due to the intermittency in hydrogen
production by renewable hydrogen plants and especially the seasonal variations in gas
demand for space heating, there will be fluctuations in the percentages of hydrogen
blended in. Further research is needed, but rough estimates indicate that with an
average of 10% hydrogen blending, actual blending percentages can vary between 0
and 40% when hydrogen is produced from solar and wind regionally. Keeping a
constant blending percentage of hydrogen in natural gas needs therefore system re-
design and adaptations.

The 10% blending of hydrogen in the natural gas system is equivalent to 2 million
tonnes hydrogen.

In this blending scenario, there is, of course, no need to replace gas boilers and other
heating equipment. However, anticipating full hydrogen conversion in areas that will
convert to 100% hydrogen soon after 2030, could initiate the same numbers of heating
appliances that are hydrogen ready. A hydrogen ready boiler is already on the market
today and will not cost more than a new natural gas or hydrogen boiler. Also fuel cells,
with on top a reformer to reform natural gas in hydrogen, are on the market in Japan,
the so-called Ene-farm system, of which a couple of 100.000’s systems are sold already
in Japan.

2 million houses/house equivalents with a hydrogen ready boiler. 1.500 Euro per
boiler means total investments of 3 billion Euro.

4 million house/house equivalents with a hybrid system, heat pump plus a hydrogen
ready boiler for peak heating and hot water. 4.000 Euro investment per hybrid
system means a total investment of 16 billion Euro.

2 million houses/houses equivalents with a 1-2 kWe natural gas reformer to hydrogen
and fuel cell for electricity and heat production.7.500 Euro investment per system
means a total investment of 15 billion Euro.

The total investments in this scenario are about 34 billion Euro, but excludes the cost
for blending hydrogen at a constant percentage into the natural gas system.

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1,8 MILLION TONNES HYDROGEN FOR MOBILITY

In the Hydrogen Roadmap Europe, numbers for fuel cell electric vehicles are
presented. Also, other hydrogen mobility applications will enter the market, such as
fuel cell inland vessels, seagoing vessels that use ammonia as fuel in the diesel engine,
tractors/heavy equipment that blend hydrogen in the air inlet in diesel engines, fuel
cell drones, forklifts, etc. As investments we have taken the cost for the on-board fuel
cell system or engine adaptation and the on-board hydrogen or ammonia storage
tanks. Most of the fuel consumption and investment figures are from the FCH JU State
of the Art and Future Targets KPI’s 2024.[1]

The hydrogen needs to be transported to the hydrogen re-fuelling stations (HRS),

which requires hydrogen tube trailers and liquid hydrogen trailers. 1 tube trailer can
transport 350 kilo H2 at 200 bar or 1.000 kilo on 500 bar. A liquid hydrogen trailer can
transport 3.500 kilo H2. We assume that 25% of the trailers is a liquid hydrogen trailer,
25% is a 500 bar tube trailer and 50% of the trailers is a 200 bar tube trailer. Each
trailer supplies a re-fuelling station 1 time a day every day of the year. If 1 million tonne
of hydrogen has to be supplied by tube trailers, there is a need of 2.400 tube and liquid
hydrogen trailers. The liquid hydrogen trailers will transport about 750.000 tonnes
hydrogen, while the tube trailers transport the other 250.000 tonnes hydrogen.
However, to liquify the hydrogen, we need liquefaction plants. About 40 liquefaction
plants that produce 50 tonnes liquid hydrogen per day are needed. Per kilo of liquid
hydrogen 7 kWh of electricity is needed. The cost of a 50 tonnes per day liquefaction
plant is about 40 million each.

Investments in transport/mobility hydrogen drive trains, mainly fuel cell systems and
storage tanks plus the necessary liquefaction plants and trailers to transport hydrogen
add up to about 40 billion Euro. We propose about half of this amount, 22 billion Euro
as a subsidy to stimulate hydrogen mobility and especially fuel cell electric mobility.

[1] https://www.fch.europa.eu/soa-and-targets

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Table 8: Numbers for hydrogen transport vehicles, ships, trailers, liquefaction plants with investments.

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1,5 MILLION TONNES HYDROGEN FOR BALANCING

ELECTRICITY PRODUCTION

The final electricity consumption in the EU28 in 2017 was 2.798 TWh. In 2030 it will
grow to 3.000 TWh. With 1,5 million tonnes of hydrogen, efficiency of STAG (Steam and
Gas turbine) powerplants at 50% and fuel cells at 60%, and half/half produced by STAG
and fuel cells we can produce 32,5 TWh or about 1% of final electricity use. If we
assume 3.250 h load factor for these power plants, total installed electricity production
capacity with hydrogen would be 10 GW, 5 GW STAG power plants and 5 GW fuel cell
power plants.
   
5 GW steam and gas turbine (STAG) hydrogen power plants. Capex of new STAG
power plant between 1.000-1.500 Euro/kW. If we assume that this 5 GW will be
retrofitting existing STAG power plants, with an investment cost of 250 Euro/kW,
total investments are 1,25 billion Euro. A subordinated loan with low interest rate
could help to do these investments.

5 GW fuel cell hydrogen power plants, new capacity. Capex of new fuel cell power
plant between 500-1.000 Euro/kW. This is a total investment of 3,75 billion Euro. An
investment grant of 1/3 of the investment could help to stimulate this, which would
mean 1,25 billion Euro.

The total investments for retrofitting 5 GW STAG power plants and building 5 GW fuel
cell hydrogen power plants is 5 billion Euro.

[1] https://www.fch.europa.eu/soa-and-targets

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OVERVIEW HYDROGEN APPLICATION INVESTMENTS

Table 9: Investments in new hydrogen applications

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SCALE UP HYDROGEN
06 MANUFACTURING
CAPACITY
Investing in renewable energy and hydrogen production, hydrogen infrastructure and
storage and in hydrogen applications up to 2030 an amount of 430 billion Euro,
creates an interesting market for the European manufacturing industry. The
manufacturing industry can scale up manufacturing production capacity and will be
able to produce at competitive prices if this hydrogen markets will become reality.
There is a variety of hydrogen manufacturing industry, but especially electrolyser and
fuel cell manufacturing together with a large variety of hydrogen application
manufacturing needs to scale up their production capacity.

Scaling up electrolyser with supply chain manufacturing capacity: Currently, the

European manufacturing capacity is about 1 GW per year, it needs to be scaled up to
25 GW/year in 2030 to fulfil the 2x40 GW Green Hydrogen Initiative.

Scaling up fuel cell with supply chain manufacturing capacity: Currently, the fuel cell
manufacturing capacity is very limited. This fuel cell capacity needs to be scaled up to
a 10-100 GW/year range. Fuel cells are needed for a variety of applications for
automotive, maritime, drones, planes, for power plants and for micro CHP (Combined
Heat and Power) home fuel cells.

Scaling up hydrogen application manufacturing capacity: The manufacturing

capacity for hydrogen compressors, boilers, hydrogen drive trains and storage tanks for
cars, trucks, busses, vans, ships, trains, drones, planes, hydrogen refuelling stations,
bunkering facilities, pipelines, sensors, measuring equipment, liquefaction plants,
ammonia cracking, etc., etc. needs to be build up. Existing manufacturing industry for
natural gas, automotive, chemistry and others could adapt or change their activities to
these new hydrogen applications and markets.

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In order to support a European hydrogen manufacturing industry, the following steps

and actions are required:

The EU and Member States could provide loans, mezzanine financing and equity.
They should try to build world champions (like Airbus) and pay for education cost,
part of salary for a couple of years, land cost, tax exemptions, etc.

The EU needs also policies to prevent take overs by companies outside the EU.

The EU needs to formulate and implement criteria that in tender procedures,

subsidy programmes and procurement will allow European companies to get a
preferential treatment. For example, by formulating number of jobs created in the
EU, innovation and research budget spending in the EU, tax payment in EU, etc.

Above all, many companies mention that the most important factor to decide to
expand manufacturing capacity is that they can be sure that targets for the
market, such as the 2x40 GW electrolyser capacity in 2030 and hydrogen demand
increase are secured and guaranteed by governments and European Union

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Hydrogen Europe is the European association representing the interest of the

hydrogen and fuel cell industry and its stakeholders. We promote hydrogen as the
enabler of a zero-emission society. With more than 160 companies, 78 research
organisations and 23 national associations as members, our association encompasses
the entire value chain of the European hydrogen and fuel cell ecosystem collaborating
in the Fuel Cell Hydrogen Joint Undertaking.
 
We are a Brussels-based association fostering knowledge and pushing for fact-based
policymaking ensuring that the European regulatory framework enables the role of
Hydrogen in our society.
 
For more information, please visit www.hydrogeneurope.eu.

Cover picture copyright: Thomas Ernsting

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