Carbon-free steel production : cost reduction options and usage of existing gas infrastructure.
Date: 2021-11-29
Institutions: Directorate-General for Parliamentary Research Services
Subjects: energy technology, energy transition, hydrogen, industrial infrastructure, iron and steel industry, mode of production, production cost, reduction of gas emissions

Carbon-free 
steel 
production 
Cost reduction 
options and usage 
of existing gas 
infrastructure 

STUDY 
Panel for the Future of Science and Technology 

EPRS | European Parliamentary Research Service 

Scientific Foresight Unit (STOA) 
PE 690.008 – April 2021 

EN 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Carbon-free steel 
production: Cost 
reduction options 
and usage of existing 
gas infrastructure 

The  steel  sector  is  one  of  the  most  challenging  sectors  to 
decarbonise  and  has  recently  received  special  attention  owing  to 
the potential use of low-carbon hydrogen (green and blue) to reduce 
its  fuel  combustion  and  process-related  carbon  emissions.  This 
report  addresses  concerns  that  might  arise  while  evaluating  the 
in 
potential  and 
decarbonising the iron and steel industries. 

limitations  of  the  future  role  of  hydrogen 

The report provides a comprehensive overview of current technical 
knowledge, (pilot) projects and road maps at national and EU level. 
This information is supplemented by previously published indicative 
price projections for the various steel production routes and a long-
term study, analysing the evolution of the global steel sector up until 
2100. 

 
 
 
 
 
 
 
AUTHORS 

This study was written by Juan Correa Laguna, Jan Duerinck, Frank Meinke-Hubeny and Joris Valee of VITO NV 
at the request of the Panel for the Future of Science and Technology (STOA) and managed by the Scientific 
Foresight Unit of the Directorate for Impact Assessment and European Added Value, within the Directorate-
General for Parliamentary Research Services (EPRS) of the Secretariat of the European Parliament.  

ADMINISTRATORS RESPONSIBLE 

Lieve van Woensel, Scientific Foresight Unit (STOA) 

Andrés García Higuera, Scientific Foresight Unit (STOA) 

To contact the publisher, please e-mail stoa@ep.europa.eu 

LINGUISTIC VERSION 

Original: EN 

Manuscript completed in March 2021.  

DISCLAIMER AND COPYRIGHT 

This  document  is  prepared  for,  and  addressed  to,  the  Members  and  staff  of  the  European  Parliament  as 
background  material  to  assist  them  in  their  parliamentary  work.  The  content  of  the  document  is  the  sole 
responsibility of its author(s) and any opinions expressed herein should not be taken to represent an official 
position of the Parliament. 

Reproduction  and  translation  for  non-commercial  purposes  are  authorised,  provided  the  source  is 
acknowledged and the European Parliament is given prior notice and sent a copy. 

Brussels © European Union, 2021. 

PE 690. 008 
ISBN: 978-92-846-7891-4 
doi: 10.2861/01969 
QA-02-21-302-EN-N 

http://www.europarl.europa.eu/stoa (STOA website) 
http://www.eprs.ep.parl.union.eu (intranet) 
http://www.europarl.europa.eu/thinktank (internet) 
http://epthinktank.eu (blog) 

 
 
 
 
 
 
Carbon-free steel production: Cost reduction options and usage of existing gas infrastructure 

Executive summary 

The steel sector is one of the most challenging sectors to decarbonise and has recently received 
special  attention  on  account  of  the  potential  use  of  low-carbon  hydrogen  to  reduce  its  fuel 
combustion and process-related carbon emissions. This report addresses concerns that might arise 
while evaluating the potential and limitations of the future role of hydrogen in decarbonising the 
iron and steel industries. 

The sector is one of the pillars of the European industry and job market, supporting approximately 
2.7 million (direct and indirect) jobs. In 2019, the production of crude steel in Europe was 157 Mt, 
which accounted for 4 % of the greenhouse Gas (GHG) emissions in Europe. Investment decisions 
are  challenging  since  margins are  tight  and  the  competition  is  fierce.  The  slowdown  due  to  the 
pandemic has worsened the situation, resulting in a reduction in demand for steel products in 2020. 
In Europe alone, prices have fallen nearly 30 % since 2018. Furthermore, manufacturing sectors are 
now including carbon neutrality in their strategies, putting pressure on steel producers to embrace 
these commitments while remaining competitive and maintaining their place in the supply chain. 

In Europe, some blast furnaces are almost 25 years old, making them fit candidates for technology 
replacement, while others have recently undergone refurbishments that entailed large investments. 
In  the  coming  decades,  this  condition  could  open  a  window  of  opportunities  to  replace  current 
assets with cleaner, novel technologies. Nevertheless, the decision to shift to a cleaner route is site-
specific and will come at different times. 

Decarbonising the steel sector in Europe 

The iron and steel sector is part of the hard to 
decarbonise  sectors  together  with  cement, 
aviation,  refineries  and  the  petrochemical 
sectors. Currently, 60 % of steel produced in 
Europe  originates  from  the  integrated  blast 
furnace/basic 
route 
(BF/BOF),  which  emits  around  1.9  tCO2/tsteel. 
Other  routes,  for  instance,  the  natural-gas-
based NG-DRI and Scrap-EAF generate lower 
emissions,  with  1.4 
tCO2/tsteel  and  0.4 
tCO2/tsteel, respectively. 

furnace 

oxygen 

Sixty  per  cent  (94  Mt)  of  the  total  steel 
produced  in  Europe  originates  from  the 
BF/BOF  route  and  is  more  suitable  for  the 
hydrogen  direct  reduction  route  (H-DRI). 
Estimates suggest that 94 Mt of 'green steel' 
would  require  approximately  37-60 GW  of 
producing 
capacity, 
electrolyser 
approximately  6.6  Mt  of  hydrogen  per  year. 
As  a  reference,  the  EU  Hydrogen  Strategy 
aims to have 40 GW  of electrolyser capacity 
installed within the EU by 2030. The authors 
estimate  that  these  electrolysers  would 
consume approximately 296 TWh of green electricity per year; as a reference, Germany produced in 
total 176 TWh of green electricity in 2020. 

Several H-DRI projects have been backed by iron and steel producers across Europe. The companies 
involved  expect  the  technology  to  reach  commercialisation  at  large  capacities  by  2035.  This 

I 

 
STOA | Panel for the Future of Science and Technology  

transition will create demand for low-carbon hydrogen (60-80 kgH2/tsteel). This hydrogen could be 
supplied by installing electrolysers on-site, in which case the storage of hydrogen could guarantee 
an uninterrupted hydrogen supply. A second alternative is the use of pipelines to link the hydrogen 
production sites with consumption locations. Both methods are challenging and the prevalence of 
one  over  the  other  depends  strongly  on  the  location  of  the  steel  plant  and  access  to  low-cost 
renewable energy. 

such 

Other  decarbonisation 
routes,  such  as  carbon 
capture  and 
storage 
(CCS), face technical and 
non-technical 
as 
challenges, 
public  acceptance  and 
regulatory  hurdles.  For 
example  to  store  the 
annual CO2 emissions of 
the  current  steel  sector 
(163  MtCO2),  over  100 
projects  with  the  initial 
annual  storage  capacity 
of  the  Northern  Lights 
project in Norway would 
be required. 

Steel production cost breakdown by route (€/t)

538

184

207

46

16
13

8

52

19
11

564

97

207

51

54

8

2030
597

11

99

223

58

101

55

676

9

82

223

118

58
76

59

6

8

666

237

262

56

48

Integrated rout
(BF/BOF)

BF/BOF + H2 injection
+ CCSU

NG-DRI/EAF + CCSU

NG-DRI/EAF + H2 +
CCSU

H2-DRI/EAF

CAPEX

Others

Electricity for H2

Iron ore/scrap

Coal

CCS

Natural Gas

Electricity

CO2

Comparing the expected cost per ton of steel among the potential production routes, the authors' 
calculation  shows  that,  by  2030,  the  innovative  routes  will  increase  the  end-product  cost  by  a 
premium of 5 to 24 %, with an abatement cost of €73-€166 per ton of CO2, compared with the 
integrated BF/BOF route.1 

Steel production and recycling forecast 

The  authors  previously  performed  a  study on  the  long-term  global  outlook  for  steel.  This  study, 
which is also presented in a summarised format in this report, analysed 13 world regions on the basis 
of  an  integrated  steel  production  and  recycling  model.  The  study  found  that  on  a  global  scale 
demand for steel will increase and stabilise around the year 2070. The global demand for flat steel 
(e.g. for car manufacturing and so-called white products) is projected to increase by 87 %, while the 
demand for long steel products (e.g. for infrastructure and construction) will only increase by 30 %. 
The availability of steel scrap re-entering the production cycle will increase by 167 % and play an 
important role in decarbonising the long steel sectors globally. 

Hydrogen production 

The technology used to produce hydrogen determines the carbon emissions associated with the 
fuel. A hydrogen colour convention has been widely accepted; these hydrogen colours include, but 
are not limited to, grey (from natural gas reforming), green (from Renewable Energy Sources (RES)), 
blue (from fossil fuels with CCS/U) and turquoise (from natural gas pyrolysis). 

The production of low-carbon hydrogen in the EU depends on the availability of renewable energy 
sources (RES), and the feasibility and availability of CCS and carbon capture and  utilisation (CCU) 
applications. Considering the increasing hydrogen demand in Europe, the limited potential of new 
wind and solar power generation installations, and the need for other sectors to decarbonise by 

1 The calculation assumes an EU ETS of €84 /ton of CO2 in 2030 for all production routes (for 2050 price comparisons see 

Figure 15).  

II 

 
Carbon-free steel production: Cost reduction options and usage of existing gas infrastructure 

consuming carbon-free electricity (such as transport and heating), it  is most likely that hydrogen 
imports  will  play  a  relevant  role  as  well.  Currently,  Europe  consumes  approximately  9 Mt  of 
hydrogen  annually,  which  is  almost  exclusively  produced  by  natural-gas-based  steam  methane 
reforming.  Future  hydrogen  production  within  the  borders  of  the  European  Union  (EU)  is  being 
championed by the '2×40' initiative. According to the European Commission's hydrogen strategy, it 
will be possible to produce 10 Mt of green hydrogen (of 333 TWhH2) by 2030. 

Hydrogen handling infrastructure 

Hydrogen  infrastructure  describes  the  physical  links  between  the  points  of  production  and 
consumption.  It comprises  long and  short-distance  pipelines,  transport  by  ship  or  road,  terminal 
stations, long and short-term storage facilities, and filling stations. Currently, the existing hydrogen 
transport infrastructure is one of the main bottlenecks in the transition to sustainable hydrogen use 
in the EU. In Europe, there are roughly 2 000 km of dedicated hydrogen pipelines distributed among 
four countries: Belgium (613 km), Germany (376 km), France (303 km) and the Netherlands (237 km). 
By way of comparison, there are approximately 260 000 km of natural gas transport pipelines. 

Currently, EU gas transmission owners are conducting studies and tests to find out which parts of 
their  infrastructure  can  be  reused  for  transporting  hydrogen.  This  is  the  case  for  the  Europe 
Hydrogen Backbone initiative proposed by several gas transmission operators, aiming in the first 
phase to have 6 800 km of hydrogen pipelines available by 2030 and 23 000 km by 2040, of which 
75 % would consist of reused natural gas pipelines. Most of the upgrades involve the compressor 
stations,  valves,  fittings,  metering  stations  and  storage  tanks.  Compared  with  building  new 
pipelines,  these  costs are  relatively  small.  Investment  costs  for new  hydrogen  pipelines  can  vary 
significantly depending on location, material and regulation (0.93 – 3.28 M€/km). However, in both 
cases  of  newly  constructed  hydrogen  and  repurposed  natural  gas  pipelines,  compressor 
installations will have to be upgraded to  increase the transportation capacity (flow volume) over 
time with growing hydrogen demand. Important to mention is that the development of dedicated 
hydrogen pipelines will likely be concentrated in areas with high industrial demands (for feedstock 
or high-temperature fuel), which are already heavily concentrated in industrial clusters. 

Hydrogen can also be transported by ship. However, due to its low energy density, it will have to be 
liquefied, which implies high energy losses. Another way to transport hydrogen in large quantities 
overseas is by transforming it into a carrier with higher densities, such as ammonia or binding it in 
liquid organic hydrogen carriers (LOHCs). This requires special handling at the terminals to convert 
hydrogen  into  these  carriers  and  back  to  hydrogen  at  the  destination.  The  conversion  costs, 
potential  emissions  (e.g.  NOX  in  the  case  of  ammonia),  as  well  as  matters  of  safety  and  social 
acceptance must be considered. 

Hydrogen can be blended with natural gas at limited percentages of 5 %-20 %, while higher shares 
of  up  to  30 %  are  being  investigated.  Blending  percentages  are  case-specific  and  may  enable 
decentralised  renewable  hydrogen  production  in  small  amounts  during  a  transitional  phase. 
However,  with  larger  volumes  of  hydrogen,  it  is  economically  advantageous  to  use  a  dedicated 
route as blending becomes less efficient. Blending degrades the quality of the gas consumed. This 
might lead to fragmentation of the internal market if different standards of blending are accepted 
by Member States. The impact on emissions is also limited, for instance: blending 10 % hydrogen 
leads to a reduction of only 3 % in CO2 emissions. 

Increasing  volumes  of  hydrogen  coming  from  variable  renewable  energy  sources  will  not  be 
available at constant rates. Thus, a matching storage capacity similar to the one used to balance the 
natural gas grid and market applies. For low volumes of hydrogen applications, hydrogen can be 
stored in tanks with high discharge rates and efficiencies. When compressed at 700 bars, the energy 
density  is  only  15 %  of  gasoline,  requiring  six  times  more  volume  to  store  the  same  amount  of 
energy. Long-duration storage facilities are required to overcome seasonal shortage if hydrogen is 
to be used as feedstock supply or high temperature heat fuel in continuous operations for industries. 

III 

STOA | Panel for the Future of Science and Technology  

Depleted gas or oil reservoirs and aquifers require careful analysis and preparation to ensure proper 
locking mechanisms are in place to prevent gas leaks. Besides gas volume losses, special care has to 
be taken when repurposing depleted gas fields, caverns or aquifers for storing hydrogen in pure or 
blended  form.  Corrosion  and  weaknesses  in  the  sealings  of  the  borehole  can  occur  due  to  the 
formation of hydrogen sulphide, which is caused by microbiological reactions within the aquifer. 
Bacterial  growth  can  lead  to  further  volume  losses.  A  study  run  for  the  Netherlands  Enterprise 
Agency  analyses  the  risks  of  storing  hydrogen  underground  in  greater  depth  (DBI  Gas-  und 
Umwelttechnik GMBH, 2017). 

IV 

 
 
Carbon-free steel production: Cost reduction options and usage of existing gas infrastructure 

Table of contents 

1. Introduction  __________________________________________________________________  1 

2. Steel production _______________________________________________________________  4 

2.1. Steel production in Europe - Overview  ____________________________________________  5 

2.2. Established steel production paths _______________________________________________  8 

2.3. Steel products and applications  ________________________________________________  11 

2.4. Decarbonisation paths ________________________________________________________  14 

2.4.1. Hydrogen-based steel production ____________________________________________  16 

2.4.2. Alternatives pathways to decarbonise steel production  ___________________________  20 

3. Case Study 'A Long-term vision on steel production' ________________________________  26 

3.1. Base assumptions - Steel production in a nutshell  __________________________________  26 

3.1.1. Steel recycling ____________________________________________________________  27 

3.1.2. Steel products: Flat steel and long steel ________________________________________  28 

3.2. The global steel production and scrap availability model _____________________________  28 

3.3. Scenario results  _____________________________________________________________  29 

4. Production and supply of hydrogen______________________________________________  32 

4.1. Production of hydrogen_______________________________________________________  32 

4.2. Supply of hydrogen __________________________________________________________  33 

4.3. Hydrogen handling __________________________________________________________  35 

5. Hydrogen infrastructure _______________________________________________________  36 

5.1. Transport of hydrogen ________________________________________________________  37 

5.1.1. Pipelines  ________________________________________________________________  37 

5.1.2. Shipping  ________________________________________________________________  39 

5.2. Hydrogen Backbone  _________________________________________________________  39 

5.3. Transmission and distribution __________________________________________________  42 

5.3.1. Existing hydrogen network __________________________________________________  42 

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STOA | Panel for the Future of Science and Technology  

5.3.2. Repurposing _____________________________________________________________  43 

5.3.3. Compressors _____________________________________________________________  43 

5.3.4. H2 repurpose initiative in Germany ____________________________________________  44 

5.3.5. Transmission costs  ________________________________________________________  45 

5.4. Blending and retrofitting ______________________________________________________  46 

5.5. Storage of hydrogen  _________________________________________________________  48 

5.5.1. Storage in tanks  __________________________________________________________  48 

5.5.2. Underground storage ______________________________________________________  49 

5.5.3. Storage cost  _____________________________________________________________  51 

5.6. Alternative transport and storage methods  _______________________________________  51 

5.6.1. Sponge iron ______________________________________________________________  51 

5.6.2. Metal hydrides  ___________________________________________________________  52 

5.7. Geographical hot spots _______________________________________________________  52 

6. Conclusions __________________________________________________________________  54 

Annex: Techno-economic assumptions _____________________________________________  58 

VI 

 
 
 
Carbon-free steel production: Cost reduction options and usage of existing gas infrastructure 

List of acronyms 

ATR 

BF 

BOF 

CEN 

CCS 

CCU 

DRI 

Auto Thermal Reforming 

Blast Furnace 

Basic Oxygen Furnace 

European Committee for Standardisation 

Carbon Capture and Storage 

Carbon Capture and Utilization 

Direct Reduced Iron 

DRI/EA 

Direct Reduced Iron integrated with an Electric Arc 

EAF 

EII 

GHG 

HHV 

Electric Arc Furnace 

Energy Intensive Industries 

Greenhouse Gas 

High Heating Value 

LCOT 

Levelised Cost of Transmission 

LHV 

SMR 

Low Heating Value 

Steam Methane Reforming 

TEN-E 

Trans-European Network - Energy 

VII 

 
 
STOA | Panel for the Future of Science and Technology  

Table of figures 

Figure 1. Crude steel production in Europe by country in 2019  _____________________________  6 

Figure 2. Map of EU production sites __________________________________________________  7 

Figure 3. EU finished steel production in 2019, by product category  _________________________  7 

Figure 4. EU steel production in a baseline scenario to 2050 ________________________________  8 

Figure 5. Indexed energy consumption by a ton of crude steel production ____________________  9 

Figure 6. Overview of different steelmaking routes ______________________________________  10 

Figure 7. CO2 emissions from steel production _________________________________________  11 

Figure 8. Steel uses and final products ________________________________________________  12 

Figure 9. Aggregated flat and rebar global steel prices averages  ___________________________  13 

Figure 10. Steel price for flat products by region ________________________________________  13 

Figure 11. The average age of main assets in the iron and steel sector by region _______________  14 

Figure 12. Hydrogen direct iron reduction process in the HYBRIT project_____________________  17 

Figure 13. High-level hydrogen-based steelmaking infographic ____________________________  18 

Figure 14. Energy intensity and CO2 emissions by steel production route ____________________  22 

Figure 15. Steel production cost breakdown by production route, 2020 / 2030 / 2050  __________  23 

Figure 16. Hydrogen route steel production price sensitivity to electricity prices in 2050  ________  24 

Figure 17. Carbon-free electricity demand of hydrogen-based routes _______________________  25 

Figure 18. World steel production by technology _______________________________________  27 

Figure 19. Global steel production scenarios ___________________________________________  29 

Figure 20. European Steel Production Scenarios ________________________________________  30 

Figure 21. Trade of obsolete scrap in the global steel production scenario  ___________________  30 

Figure 22. Potential impact of a European Climate Policy _________________________________  31 

Figure 23. Hydrogen production costs for different technology options in 2030 _______________  34 

Figure 24. FCH-JU vision on Europe's future hydrogen demand by sector ____________________  35 

Figure 25. Hydrogen production and transport route using pipelines  _______________________  37 

Figure 26. Existing European gas network _____________________________________________  38 

Figure 27. Mature European Hydrogen Backbone _______________________________________  41 

Figure 28. Existing no-natural gas pipelines in Europe  ___________________________________  43 

Figure 29. National Hydrogen Backbone in Germany in 2030 –Proposed by FNB Gas  ___________  45 

Figure 30. Effect of hydrogen blend level on the energy delivery of gas pipelines ______________  47 

Figure 31. Underground salt deposits and cavern fields in Europe __________________________  50 

Figure 32. Possible routes for steel making instead of hydrogen shipping ____________________  52 

VIII 

Carbon-free steel production: Cost reduction options and usage of existing gas infrastructure 

Table of tables 

Table 1. Decarbonisation options for the steel sector  ____________________________________  15 

Table 2. Hydrogen-based steel production projects in Europe _____________________________  19 

Table 3. Hydrogen types in a colour scheme by technology and fuel ________________________  32 

Table 4. Cable versus pipeline energy transport examples  ________________________________  38 

Table 5. Costs for repurposing or replacing gas network transmission _______________________  46 

Table 6. Costs for hydrogen storage __________________________________________________  51 

IX 

Carbon-free steel production: Cost reduction options and usage of existing gas infrastructure 

1. Introduction 

The steel sector is one of the most challenging sectors to decarbonise and has recently received 
special attention owing to the potential use of low-carbon hydrogen (green and blue) to reduce its 
fuel  combustion  and  process-related  carbon  emissions.  This  report  aims  to  address  and  several 
concerns  that  have  arisen  while  evaluating  the  potential  and  limitations  of  the  future  role  of 
hydrogen in decarbonising the iron and steel industries.  

The  scope  of  this  study,  in  terms  of  timing  and  budget,  is  limited  and  it  therefore  focuses  on 
providing a comprehensive overview of the current technical knowledge, (pilot) projects and road 
maps at national and EU level. This information is supplemented by indicative price projections for 
the various steel production routes (see Chapter 2 and Figure 15) and a long-term study, analysing 
the evolution of the global steel sector up until 2100 (see Chapter 3), both based on readily available 
data and scientific reports from Vito. 

More in-depth analysis is required to gain a deeper understanding of the barriers to and enablers of 
the up-take of hydrogen in energy intensive industries (EIIs) in general and the iron and steel sector 
in  particular.  Here  the  authors'  team  would  also  like  to  refer  to  the  project  'AidRES  -  Advancing 
industrial decarbonisation by assessing the future use of renewable energies in industrial processes'2 
which was launched in January 2021 and will create a database of the main EIIs in Europe, including 
current and future energy and feedstock needs and the mapping of renewable energy needs in high 
spatial resolution. 

The  tender  document  provides  a  list  of  specific  questions  as  well.  For  easier  orientation,  the 
following text boxes provide an overview of how far this report addresses those questions and in 
which chapter the relevant information can be found. 

2 Aid RES – Advancing industrial decarbonisation by assessing the future use of renewable energies in industrial processes, 
NUMBER –ENER/2020/OP/0011-C2/SER/2019-569/SI2.840687, (Pilot Project No. 32027714 of the European Parliament)  - 
Project Officer: Eric Lecomte (DG ENER), Consortium Project Manager: Frank Meinke-Hubeny (Vito). 

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STOA | Panel for the Future of Science and Technology  

QUESTIONS FROM THE TENDER 

•
•

•

•

•
•

•

•

•

•

•

•

•

Pathways and timelines for coal substitution with hydrogen in steelmaking.  
Hydrogen  direct  reduction  (H-DRI)  will  need  the  development  of  large  infrastructure  (see 
Figure 13) and competes against CCS and CCU alternatives, as well as emerging solutions such 
as natural gas pyrolysis and iron ore electrolysis (see section 2.4). 
The  steel  sector  will  compete  with  other  sectors  (e.g.:  petrochemical,  transport)  for  the 
available  low-carbon  hydrogen.  Thus,  the  deployment  of  new  technologies  in  this  sector 
depends not only on technology readiness but also on hydrogen supply potential, demand in 
other  sectors,  financial  incentives  and  business  strategies.  A  clear  pathway  needs  more 
complex and robust models to deal with the barriers as well as enablers for the plant specific 
transformation. 
From an end product cost point of view Figure 15 provides indicative cost projections for each 
considered production route for the year 2020, 2030 and 2050.  

The potential of using existing gas infrastructure for the transport of hydrogen. 
Sections 5.2 Hydrogen Backbone and 5.3 Transmission and distribution provide an overview of 
techno-economic parameters as well as insights from current (pilot) projects. 

Energy  prices  and  CAPEX  reduction needed to  make  the  H-DRI  route  an  attractive  business 
case. 
There are several parameters that influence the competitiveness of H-DRI such as electricity 
prices,  electrolyser  CAPEX  and  CO2  emissions  prices.  An  overview  of  the  production  cost 
breakdown  is  given  in  Figure  15,  and  the  assumptions  used  are  listed  in  Techno-economic 
assumptions,  including  the  expected  CAPEX  reductions  in  key  technologies,  such  as 
electrolysers. 

Technical, financial and regulatory barriers for large-scale deployment of hydrogen-based steel 
production.  
Insights into technical aspects to be resolved specially in the case of hydrogen transport, as 
well  as  in  the  case  of  carbon  storage  are  addressed  in  section  5.1.  The  main  parameters 
influencing the hydrogen price (€/kgH2) are the electricity price and electrolyzer CAPEX, since 
DRI is a mature technology (see Figure 13). 

Hydrogen needed across all the sectors to enable a cost-efficient transition towards carbon-
neutrality in Europe by 2050.  
Hydrogen must reach a competitive price to make low-carbon production routes financially 
viable. This prices vary from sector to sector and case to case. Hence, sectorial analysis as well 
as  a  cross-sectorial  global  perspective  are  necessary  to  identify  the  most  cost-efficient 
alternatives to reach full decarbonisation.  
Several projects, joint ventures and research efforts aim to solve this situation. Among such 
studies the AidRES project, which focuses on assessing the future use of renewable energies in 
industrial processes towards full decarbonisation. 

2 

 
 
 
 
 
 
 
 
Carbon-free steel production: Cost reduction options and usage of existing gas infrastructure 

QUESTIONS FROM THE TENDER 

•
•

•

•

•
•

•

•

•
•

•
•

•
•

The possible amount of hydrogen generated within the EU.  
The electricity available to produce green hydrogen within Europe is not only subject to the 
potential for renewable energy sources (RES) within the EU, but also will be impacted by the 
use of the generated green electricity. The European green deal prioritizes direct electrification 
over other alternatives, because of the better energy efficiency (no conversion losses), which 
will compete with the so-call indirect electrification (such as hydrogen production from green 
electricity).  A  more  in-depth  energy  system  analysis  (model  application)  is  needed  to  gain 
better insights and supply and demand projections. 
The EU Hydrogen strategy foresees the production of 10Mt of green hydrogen by 2030, while 
Hydrogen  Europe  estimates  a  total  of  7.4Mt  (including  imports).  FCH-JU  vision  for  Europe 
allocates approx. 4 Mt of green hydrogen for the steel sector by 2050. 
Figure 13 provides a high-level calculation for the hydrogen required to decarbonise the coal-
based production route with a hydrogen based production route. 

Hydrogen production onsite or centralized.  
The decision for on-site production versus centralized production will likely be plant-specific: 
the geographical location of the existing blast furnaces, access to RES, the existing power grid 
and  natural  gas  infrastructure  with  conversion  potential  are  important  factors  to  determine 
whether captive or merchant hydrogen production is more advantageous (see Figure 2 and 
sections 4.2 and 4.3). 
In general one can say that hydrogen transmission pipelines can transport 10 to 20 times more 
energy over long distance at the same cost compared to high voltage power cable (see Table 
4). 
DECHEMA estimates that access to low-carbon electricity is the main bottleneck in the use of 
hydrogen in the European chemical sector, which is estimated to use 500 - 1 400 TWh in 2030 
and 2 000 – 4 500 TWh in 2050 of low-carbon electricity to produce hydrogen. Therefore, the 
chemical industry is set to be an important competitor for low-carbon hydrogen.  

Hydrogen blending and hydrogen dedicated pipelines. 
There  are  technical  limitations  for  hydrogen  blending  into  the  natural  gas  network  –  see 
Chapter 5.4  
Significant investments are needed to increase the hydrogen blending level. 
Regulatory alignment is needed among the country gas operators regarding the threshold of 
hydrogen blending.  

Technical requirements for hydrogen pipeline transport.  
Chapter 5 is dedicated to the requirements for hydrogen transport 

3 

 
 
 
 
 
 
STOA | Panel for the Future of Science and Technology  

2. Steel production 

Takeaways 

•

•

•

Steel  manufacturing  faces  challenges  from  regulatory  decarbonisation  targets  and  steel 
product consumers -e.g. car manufacturers who aim to decarbonise their supply chain- to 
radically transform their production routes towards carbon-neutrality. 
Existing assets, such as blast furnace ovens, are relatively easy to refurbish and can be kept 
operational at low costs, which can hinder the transition to cleaner steel technologies such 
as hydrogen-based DRI. 
Europe produces approximately 157 Mt of steel, of which 60% (94 Mt) originates from the 
coal-based  blast  furnace  (BF/BOF)  route  and  is  more  suitable  for  the  hydrogen  direct 
reduction route (H-DRI). 

• One can estimate that 94 Mt of ‘green steel’ would require approximately: 
•

37-60 GW of electrolyser capacity (as a reference, the EU Hydrogen Strategy aims to have 40 
GW installed within the EU by 2030). 
296 TWh of green electricity (as a reference, Germany produced 176 TWh of green electricity 
in 2020). 

•

•

• Other decarbonisation routes such as carbon capture and storage (CCS) face non-technical 
challenges like public acceptance and regulatory hurdles. To store the current CO2 emission 
of the steel sector (163 MtCO2), over 100 projects with the initial annual storage capacity of 
the Northern Lights project in Norway would be required. 
The  authors’  calculation  show  that  by  2030,  the  alternative  routes  will  increase  the  end 
product cost by a premium of 5-24%, with an abatement cost of €73-€166 per ton of CO2 
(compared with the integrated route BF/BOF). 
Natural gas pyrolysis and iron electrolysis are alternatives that might produce low-carbon 
steel but have still a low level of implementation readiness.  

•

Steel is a central input material for many products in the European economy, positioning the iron 
and steel sector with close links to several other industries in manufacturing or construction sectors. 
Production of steel was responsible for 4% of greenhouse gas emissions in Europe (EU28) in 2018. 
The sector is part of the hard to decarbonise sectors together with cement, aviation, oil refineries 
and petrochemical sectors, which makes it imperative for Europe to reach its GHG reduction targets. 

Currently,  60%  of  the  steel  produced  in  Europe  originates  from  integrated  blast  furnace/blast 
oxygen  furnace  route  (BF/BOF)  which  emits  around  1.9  tCO2/tsteel.  To  avoid  these  emissions,  the 
direct  reduction  of  iron  ore  (DRI)  based  on  100%  low-carbon  hydrogen  (H-DRI)  seems  to  be  a 
promising production route. Several challenges must be addressed for large-scale adoption of this 
innovative  route,  such  as  the  production  of  the  required  amount  of  hydrogen  and  necessary 
infrastructure besides the steel production facility such as electrolyser, wind, and solar power plants 
and hydrogen pipelines. In addition, technical requirements have to be met to enable alternative 
pathways  to  further  decarbonise  the  steel sector  employing  carbon capture  &  storage (CCS) and 
utilisation  (CCU).  Also,  fully  electrified  steel  production  routes  such  as  iron  ore  electrolysis  are 
promising technologies on the road to clean steel. 

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Carbon-free steel production: Cost reduction options and usage of existing gas infrastructure 

2.1. Steel production in Europe - Overview 

In  2019,  the  production  of  crude  steel  in  the  world  was  1 870  Mt  of  which  Europe  produced 
approximately 8.5% (World Steel Association, 2020). This took place mostly in Germany, Italy and 
France where half of the steel within Europe was manufactured as shown in Figure 1 Understanding 
the geographical spread of the production sites (see Figure 2) is relevant for identifying the sites and 
regions that can initiate the transition towards low carbon steel production routes. Specifically, in 
the case of the Blast Furnace – Basic Oxygen Furnace (BF/BOF) production facilities, which account 
for 60% of the steel made in Europe  (Roland Berger, 2020), are good candidates to invest in new 
technologies in order to comply with the greenhouse gas (GHG) emission targets set for the sector 
in the coming decades. On the other hand, the Electric Arc Furnace (EAF) sites are wider distributed 
across Europe and are mostly dedicated to the production of steel of lower quality from scrap using 
grid electricity. In this regard, it is important to highlight that the large majority of the GHG emissions 
of the EAF route are indirect emissions accounted for in the power sector. Thus, decarbonising the 
EAF  route  requires  the  decarbonisation  of  the  power  sector.  This  is  a  further  relevant  point  to 
guarantee low-carbon steel production within Europe, considering also that EAF is part of cleaner 
routes such as the natural gas direct reduction (NG-DRI) in combination with carbon capture and the 
hydrogen direct reduction (H-DRI).  

The steel sector is one of the pillars of the European industry and the job market. EUROFER estimates 
that a total of 2.7 million jobs are supported by the industry, out of which 12.5% are direct jobs and 
the remaining 87.5% are indirect and induced jobs (EUROFER, 2020). In the last decade, the total 
number  of  direct  jobs  decreased  by approximately  40 000,  which has a  similar  trend  to  the  total 
crude  steel  production  over  the  same  period.  This  can  also  be  seen  in  the  net  trade  balance  of 
finished products, which shrunk from nearly 10 Mt in 2010 to almost - 5 Mt in 2019, making Europe 
a net importer of finished steel products (EUROFER, 2020).  

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STOA | Panel for the Future of Science and Technology  

Figure 1. Crude steel production in Europe by country in 2019 

Source: EUROFER, 2020. 

Depending on the production route, steel is divided into primary steel, originating mostly from iron 
ore which is traditionally being produced in a blast furnace/basic oxygen furnace route (BF/BOF), 
and  secondary  steel,  originating  mostly  from  recycled  steel  and  which  is  traditionally  being 
produced  in  an  electric  arc  furnace  (EAF).  Each  route  produces  different  qualities  of  steel.  The 
primary steel generally delivers higher quality since it does not deal with impurities from recycled 
materials as is the case in secondary steel. A second dimension is the steel type which can be flat or 
long steel.  Flat  steel  products  are made  from  steel  slabs  and  require high-quality steel  or  iron as 
input. Typical applications for this kind of high-quality steel are the automotive or aviation sectors. 
Conversely,  long  steel  products  are  made  from  blooms  or  billets,  with  lower  quality.  Long  steel 
products  are  for  example  utilised in  infrastructure  and construction  projects.  Figure  3 shows  the 
distribution of steel production by finished product in the EU in 2019. 

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Carbon-free steel production: Cost reduction options and usage of existing gas infrastructure 

Figure 2. Map of EU production sites 

Source: EUROFER, 2020. Large BF-BOF Clusters highlighted by VITO NV. 

Figure 3. EU finished steel production in 2019, by product category 

Source: EUROFER 

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STOA | Panel for the Future of Science and Technology  

Figure 4. EU steel production in a baseline scenario to 2050 

Source: Material Economics based on EUROFER (2018), World Steel (1990-2018), and Pauliuk et al. (2013). 

Figure 4 shows a forecast of the steel production within the EU up to the year 2050 according to 
Material Economics, which is expected to stabilise around 190 Mt, which corresponds to a saturation 
of approximately 13.7 ton per capita. 

Steel and steel scrap are globally traded commodities; to gain further insights into the dynamics of 
the global steel sector in the coming decades a case study based on a global steel model has been 
included in this report, see Chapter 3 for more details. 

2.2. Established steel production paths  

The iron and steel sector is one of the main sectors in Europe and it is intrinsically embedded with 
many other sectors of the economy such as the automotive industry, construction and machinery. 
At the same time, steel production is one of the world's most polluting industry, accounting for 7% 
of global emissions (Grattan Institute, 2020) of which 4% in EU28 in 2018 (EUROSTAT, 2019). It is a 
highly energy-intensive sector, consuming 22% of the worldwide industrial energy demand – about 
8%  of  global  total  final  energy,  which  makes  it  sensitive  to  fuel  price  volatility,  considering  that 
energy weights between 10-40% in the total production cost (IEA, 2020), (World Steel Association, 
2019). The World Steel Association argues that currently, the average energy intensity is 20 GJ/tsteel, 
and  that  there  is  room  for  improvements  in  terms  of  energy  efficiency  of  15-20%  (World  Steel 
Association, 2020).  

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Carbon-free steel production: Cost reduction options and usage of existing gas infrastructure 

Figure 5. Indexed energy consumption by a ton of crude steel production 

Source: (World Steel Association, 2019) 

Currently,  there  are  two  main  steel  production  routes:  Blast  Furnace  –  Basic  Oxygen  Furnace 
(BF/BOF) and Electric Arc Furnace (EAF). Additionally, Direct Reduced Iron integrated with an Electric 
Arc  (DRI/EA)  contributes  to  a  lesser  extent  to  global  production.  In  Europe,  the  DRI  route  is  less 
conventional as it relies on access to cheap natural gas. The major DRI producers are in the Middle 
East, India, and Russia (MIDREX, 2018). In the case of the BF/BOF route, iron ore and coal are the main 
raw materials. The majority of which are pre-processed to obtain sinter and pellets from iron ore and 
coke from coal. After being transformed, coke and sinter (or pellets) go to the Blast Furnace, where 
the iron ore is reduced to iron by removing oxygen. The resulting pig iron is processed into crude 
steel by the BOF. At this stage, high-quality scraps of iron can be added to increase recycling rates. 
In Figure 6 the most common routes for crude steel production are illustrated. Finally, the crude steel 
is  processed  further  into  rolls  and  sheets  and  can  be  finished  by  galvanisation,  tin  plating,  or 
lacquering if required. The finishing process of crude steel is the same for all the routes (BF-BOF, DRI-
EA, EAF, etc.). 

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STOA | Panel for the Future of Science and Technology  

Figure 6. Overview of different steelmaking routes 

Source: World steel association, 2019. 

Note: BF = Blast Furnace, BOF = Blast Oven Furnace, DR = Direct Reduction, DRI = Direct Reduction Iron, EAF = 
Electric Arc Furnace, OHF = Open-Hearth furnace, ORE = Iron ore 

In  steelmaking,  process  emissions  are  related  to  the  combustion  of  fossil  fuels  and  chemical 
reactions. There are several CO2 emission sources in the process (see Figure 7), and each route has a 
different emission footprint. The most carbon-intensive path is the coal-DRI/EAF, which is estimated 
to  emit  2.4  tCO2/tsteel,  compared  to  2  tCO2/tsteel  in  the  case  of  BF-BOF,  and  1.4  tCO2/tsteel  and  0.4 
tCO2/tsteel for NG-DRI/EA and Scrap/EA, respectively (Ellis & Bao, 2020)3. Since the process has evolved 
considerably in the last centuries, nowadays it is a highly integrated process where outputs of one 
step are used as inputs in consecutive steps. These links between the process building blocks offer 
opportunities for improvements in energy efficiencies and feedstock intensity. However, it also acts 
as a disadvantage because it is difficult to implement changes in one part of the process without 
having implications elsewhere.  

3 CO2 emissions include estimated indirect emission from power grid in this literature source. 

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Carbon-free steel production: Cost reduction options and usage of existing gas infrastructure 

Figure 7. CO2 emissions from steel production  

Source: Material Economics, 2019. 

Note: Unit: tCO2/tsteel 

2.3. Steel products and applications 

Steel is used in a wide range of sectors, from which the main ones are buildings and infrastructure, 
mechanical equipment,  automotive  and  metal  products.  Inherently,  semi-finished  steel  products 
affect the decarbonisation targets in the above-mentioned sectors as they are part of the supply 
chain. For instance, car manufacturers Volkswagen and Toyota have committed themselves to fully 
decarbonise their value chain, including upstream stages. Another recent phenomenon is the rising 
awareness and commitment of investment firms towards environmental responsibility. Such is the 
case of the investment firm BlackRock, which is now more oriented toward the sustainability and 
environmental impact of its business. Therefore, the steel manufacturers have the obligation and 
the need to keep up with such commitments to remain competitive to maintain their place in the 
supply chain. In this regard, 14% of the companies in the global steel industry could be at risk if they 
are not able to reduce their environmental impact, according to a recent analysis of McKinsey & Co. 
(McKinsey & Company, 2020).  

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STOA | Panel for the Future of Science and Technology  

Figure 8. Steel uses and final products 

Source: EUROFER, 2020. 

Margins  in  the  steel  sector are  tight and  competition  is  high,  which  makes  investment  decisions 
challenging. The slowdown due to the COVID-19 pandemic has worsened the situation, resulting in 
a reduction in demand for steel products in 2020. As a result, the sharp drop in global steel prices, as 
can be observed in Figure 9, induces a more arduous competition among the different players in the 
sector, jeopardising the survival or geographical presence of some companies. This situation is more 
accentuated  in  Europe,  where  prices  have  fallen  more  dramatically  compared  with  other  world 
regions -nearly 30% since 2018- as can be seen in Figure 10. 

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Carbon-free steel production: Cost reduction options and usage of existing gas infrastructure 

Figure 9. Aggregated flat and rebar global steel prices averages 

Source: (OECD, 2020) 

Figure 10. Steel price for flat products by region 

Source: (OECD, 2020) 

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STOA | Panel for the Future of Science and Technology  

2.4. Decarbonisation paths 

The  European green  deal  stresses  the  need  to  modernise  and  decarbonise  energy-intensive  and 
hard-to-decarbonise  industries  such  as  steel  and  cement  as  an  essential  step  toward  attaining 
carbon neutrality by 2050. The solutions designed to eliminate CO2 emissions in the steel sector can 
be classified into two main groups: carbon abatement and full decarbonisation. In previous years 
the emphasis has been on material management and carbon abatement, yet, some emissions will 
remain considering the limitations of steel scrap availability and opportunities for carbon capture in 
the steel sector. On the other hand, hydrogen has been regarded as a vital element of the European 
energy transition and plays a central role in decarbonisation pathways, finding also its position in 
the steel sector.  

Hydrogen can replace the fossil fuels required to reach high temperatures, as well as the carbon used 
in  the  reduction  of  iron  ore.  To  guarantee  complete  decarbonisation  of  steel  production,  the 
production  of  hydrogen  has  to  be  carbon-free  (so-called  green  hydrogen)  and  the  remaining 
electricity  used  in  the  production  process has  to  originate  from  renewable  energy  sources (RES). 
Another important factor to consider is the hydrogen price as the main enabler of the transition from 
coal-based production routes. It is expected that the price of green hydrogen (or blue hydrogen) will 
gradually drop to reach competitive levels in the next three decades.  

Finally, it is paramount to not just consider the environmental challenges and commitments that the 
sector has toward the half of the current century, but to bear in mind the age of the existing assets 
that  are  expected  to  undergo  major  investment  until  2050  (Material  Economics,  2019).  Existing 
installations such as blast furnaces have an investment cycle of 10-15 years and coke plants require 
substantial  investments  as  well.  This  condition  could  open  a  window  of  opportunities to  replace 
current assets with cleaner and novel technologies while meeting climate targets. While some blast 
furnaces in Europe are almost 25 years old (see Figure 11), making them fit candidates for technology 
replacement, others have recently undergone refurbishing works that entailed large investments. 
Consequently, the decision to shift to a cleaner route is site-specific and will come at different times.  

Figure 11. The average age of main assets in the iron and steel sector by region 

Source: (IEA, 2020) 

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Carbon-free steel production: Cost reduction options and usage of existing gas infrastructure 

The  following  table  provides  an  overview  of  innovative  steel  production  routes,  including  the 
approximate implementation readiness and location of exemplary pilot level projects in Europe. 

Table 1. Decarbonisation options for the steel sector 

Group 

Process/ 
Tech.  

Description 

Example 

Carbon 
abatement 

BF/BOF + 
Top gas 
recovery 
and 
recycling 

There are two different ways to use the top 
gas  from  the  blast  furnace.  Firstly,  the  gas 
could  be  recycled  into  the  blast  furnace  to 
reduce the consumption of coke. Secondly, 
the  gas  can  be  used  in  a  Top  Recovery 
Turbine (TRT) to generate electricity. 

STEPWISE 
(Sweden) 
ArcelorMittal 
(Belgium) 

Implem. 

Readiness 

CO2 
reduction 
potential 
(compared 
with BF/BOF) 

Energy 
Needs 

(per ton 
of steel) 

High 

10-20% of 
CO2 
emissions 

14-16 
[GJ/t] 

BF/BOF + 
Biomass 

Partially  replace  the  use  of  coal  and  coke 
with  biomass  (charcoal,  torrefied  material, 
wood  pellets)  for  iron  reduction  or  fuel 
consumption.  It  is  more  feasible  in  regions 
with  biomass  availability  such  as  South 
America and Russia. 

Torero-
ArcelorMittal 
(Belgium) 
Small tests 
(Brazil) 

High 

5-28% of 
CO2 
emissions 

33-60 
[GJ/t] 

Deploy  carbon  capture  technologies  in  the 
different  emissions  points  of  the  primary 
route  and  valorise  the  CO2  with  synergies 
with  the  chemical  industry,  as  well  as  CO2 
recycling  in  the  BF  within  the  steelmaking 
process. 
ethanol, 
methanol etc. Can be produced from the CO2 
emission of the Blast Furnace.  

hydrogenation 

By 

BF/BOF + 
CCU 

Steelanol 
(Belgium) 
Lanzatech 
(China) 
FReSMe 
(Europe) 
Carbon2Chem 
(Germany) 
Carbon4PUR 
(Europe) 

IGAR 
(Belgium) 

Medium 

up to 65% 

18-20 
[GJ/t] 

BF/BOF + 
H2 
enrichme
nt + CC 
(optional) 

Reduce  the  use  of  coal  with  injections  of 
hydrogen 
into  the  Blast  Furnace  as  a 
reductant  agent.  This  could  reduce  CO2 
emissions  by  20%.  The  technology  could 
reduce even more the emissions if coupled 
with carbon capture technologies.  

NG-
DRI/EAF + 
CC 

NG-
DRI/EAF + 
H2 
injections 
+ CC 
(optional) 

Smelting 
reduction 
+ CCUS 

Add  carbon  capture  to  the  emission  in  the 
DRI.  The  carbon  concentration  in  the  gas 
makes  it  more  expensive  and  technology-
wise  more  challenging  to  reach  a  high 
capture level. 

In  the  NG-DRI/EAF,  H2  is  obtained  from 
natural gas, this could be replaced up to one 
third  by  green  hydrogen  directly  injected 
into  the  shaft,  reducing,  thus, 
its  CO2 
emissions. 

It  is  a  combination  of  direct  reduction  and 
smelting process to produce molten pig iron 
directly using coal instead of coke. The plant 
is intended to operate with CCUS to increase 
its environmental impact.  

ThyssenKrupp 
(Germany) 

Medium 

up to 72% 

17-19 
[GJ/t] 

Al Reyadah 
(Abu Dhabi) 

Medium/ 

High  

up to 80% 

15-17 
[GJ/t] 

MIDREX H2 

Medium 

up to 80%, 
plus H2 mix 

16-18 
[GJ/t] 

Hisarna - TATA 
steel 

Medium 

by 20%, and 
up to 80% 
with CC 

15-17 
[GJ/t] 

15 

STOA | Panel for the Future of Science and Technology  

Group 

Process/ 
Tech.  

Description 

Example 

Full 
decarbonisa
tion 

H2-
DRI/EAF 

Hydrogen is used as the only reductant gas 
in  the  shaft  to  produce  sponge  iron.  If  the 
electricity  to  produce  H2  and  in  the  EAF  is 
carbon-free, the steel production has no CO2 
emissions. 

Smelting 
reduction: 
H2 
plasma 

Iron ore 
electrolysi
s 

In the hydrogen plasma smelting reduction, 
iron  ore  is  reduced  by  hydrogen  in  the 
plasma state in a plasma arc reactor. 

electric 

Iron  ore  is  dissolved  in  a  solvent  at  high 
current 
temperatures,  where 
ions  and 
charges  oxygen 
negatively 
separating  O2  from  the  iron  ore.  There  are 
two  main  routes:  Molten  Oxide  Electrolysis 
(MOE) 
Process 
(ULCOWIN) 

Electrowinning 

and 

HYBRIT 
(Sweden) 
Voestalpine 
(Austria) 
ThyssenKrupp 
(Germany) 

SuSteel 
(Austria) 
University of 
Utha (USA) 

Boston Metal 
(USA) 
Siderwin 
(Europe) 

Implem. 

Readiness 

CO2 
reduction 
potential 
(compared 
with BF/BOF) 

Energy 
Needs 

(per ton 
of steel) 

High 

Up to 100% 

17-19 
[GJ/t] 

Medium 

Up to 100% 

- 

Medium 

Up to 100% 

13-15 
[GJ/t] 

Source: VITO based on (IEA, 2020), (IEA, 2019), and own calculation and database. 

2.4.1. Hydrogen-based steel production  
A  small  quantity  of  steel  is  made  today  using  what  is  called  the  'direct  reduction'  process, 
approximately 7% of the 1 402 Mt of primary steel production in 2018 (IEA, 2019). This is a mature 
technology, which could also be operated solely on hydrogen. The base principle of the hydrogen 
reduction route (H-DRI) is the use of hydrogen as a reductant agent to obtain sponge iron (direct 
reduced iron) instead of the current use of a mix of hydrogen and carbon in the BF. Only water is 
obtained as a by-product of the hydrogen-based process. The reaction takes place in a shaft furnace 
at  an  operating  temperature  of  around  800°C.  The  operating  temperature  could  be  reached  by 
employing electrification and the use of residual heat within the same process. Afterwards, sponge 
iron is tuned into crude steel in an EAF, where a carbon source is still needed to obtain steel with a 
carbon content of less than 0.4%. To fully decarbonise the entire production route, the carbon source 
for  the  pellet  production  plant,  the  lime  production  plant,  and  the  EAF  have  to  be  considered. 
Options  would  be  the  use  of  biomass  or  bio-coal.  Additionally,  the  electricity  consumed  in  the 
process needs to originate come from renewable sources.  

In Europe, several projects are being tested and pilot plants initiated, which are backed by iron and 
steel producers such as SSAB, LKAB, Voestalpine, ThyssenKrupp, and Salzgitter. These companies 
expect the technology to reach commercialisation at large capacities by 2035 (Material Economics, 
2019).  The  first  experiments  in  large  scale  direct  reduction  using  pure  hydrogen  are  now  being 
carried out at the SSAB steel facilities in Sweden under the HYBRIT4 project. These pilots will provide 
more precise data on the amount of hydrogen needed. 

4 https://www.hybritdevelopment.com/ 

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Carbon-free steel production: Cost reduction options and usage of existing gas infrastructure 

Figure 12. Hydrogen direct iron reduction process in the HYBRIT project 

Source: (HYBRIT, 2018) 

It  is  estimated  that  the  H-DRI  steel  production  theoretically  requires  51-57  kgH2/tsteel5,  assuming 
100% reaction efficiency in the shaft. However, this is not always the case and the consumption of 
hydrogen could increase accordingly to reach values near 65-80 kgH2/tsteel, depending on operating 
conditions6. An additional factor affecting the hydrogen requirements is the scrap-to-iron ratio in 
the EAF, which reduces the need for sponge iron per ton of steel. If it is assumed to use 70 kgH2/tsteel 
and zero scrap in the EAF, 3.2 MWh of clean electricity are required to produce one ton of primary 
steel.  To  cover  the  total  European  production  of  primary  flat  steel  in  2019  -  94  Mt  according  to 
EUROFER - a total of 296 TWh of clean electricity would be required to power 55 GW of electrolyser7. 
To put these numbers into perspective; the total electricity production of EU27 in 2019 was 2 724 
TWh8 Germany produced 176 TWh of green electricity in 2020 (Energy Charts, 2021). This means that 
around 10% of the annual produced electricity in the EU alone would be needed to supply the steel 
industry.  Additionally,  the  required  capacity  of  electrolyser exceeds  the  40  GW envisioned in  the 
2x40 FW initiative. See also Figure 13 for a simplified overview of the assumptions in this paragraph. 

5 Based on LHV and 74% efficiency of electrolyzer for the HYBRIT project. 
6 Reaction efficiency assumed to be 65-80%. 
7 Full load= 5000 hours per year. 
8 Data from EUROSTAT report: https://ec.europa.eu/eurostat/statistics-explained/pdfscache/9990.pdf   

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Figure 13. High-level hydrogen-based steelmaking infographic 

Source: Own elaboration. 

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Carbon-free steel production: Cost reduction options and usage of existing gas infrastructure 

Table 2. Hydrogen-based steel production projects in Europe 

H2-DRI projects in Europe 

HYBRIT  9:  

LKAB12:  

Hydrogen 
Ironmaking 
Breakthrough 
Technology is a joint venture of SSAB, LKAB, 
and Vattenfall, launched in 2016 in Sweden, 
with  the  aim  to  have  a  fossil-free  steel 
production  solution  by  2035.  This  will  help 
SSAB to be practically carbon-free by 2045. 

ArcelorMittal 10:  

In  2019,  ArcelorMittal  started  collaborating 
with Midrex to build a production plant able 
to annually produce 0.1 Mtsteel using only H2 
as a reductant agent in Hamburg, Germany. 
It  will  initially  start  production  using  grey 
hydrogen  and  be  ready  for  when  green 
hydrogen supply is reliable and affordable.  

to 

The  mining  group  plans 
integrate 
downstream  and  initiate  trading  sponge  iron 
produce  entirely  using  H2  from  renewable 
energy  sources.  In  other  words,  it  will  install 
hydrogen shafts (H-DRI), without the EAF step. 

Voestalpine13:  

in  Linz,  Austria, 

in 
The  production  facility 
association  with  VERBUND,  Siemens,  Austrian 
Power  Grid,  K1-MET,  and  TNO  are  under 
development.  With  6  MW  of  electrolyser 
capacity, the project expects to reduce by 30% 
the  emissions  of  Voestalpine  by 2035,  with the 
final goal of reducing the emission by over 80% 
by 2050. 

Thyssenkrupp  11: 

Salzgitter14:  

In partnership with REW, the steel producer 
expects  to  convert 
its  current  BF/BOF 
production into H-DRI by 2050. Starting with 
the  facilities  in  Duisburg  (2%  of  Germany's 
CO2  emissions)  in  2025,  one  of  the  main 
challenges  is  the  need  for  a  pipeline  to 
transport H2 from Lingen to the plant. If H2 is 
not  available  in  the  quantities  needed,  the 
plant will start running on natural gas. 

With the project SALCOS, the company expects 
to  develop  and  demonstrate  the  techno-
economic  feasibility  of  hydrogen-based  steel 
production.  The  project  is  divided  into  several 
stages: demonstration of MW scale electrolyser, 
wind  power  production  onsite,  pipe  for  H2 
transport and storage, and final profitability for 
steel production. 

Liberty Steel Group 15:  

Constriction  of  a  DRI/EAF  plant  to  produce  2 
Mtsteel. It will be designed to phase into H2 from 
natural gas (grey H2), reaching carbon neutrality 
by 2030. 

Source: own elaboration. 

The supply of H2 to the hydrogen shaft could be done by installing an electrolyser within the facilities 
of the steel plant, in which case the storage of H2 should be considered to keep production rates 
stable. The second alternative is the use of a pipeline to link the hydrogen production sites with the 
consumption  centres.  Both  methods  are  challenging  and  the  prevalence  of  one  over  the  other 
depends strongly on the location of the steel plant and the access to cheap and renewable energy.  

9 https://www.hybritdevelopment.com/  
10 https://corporate.arcelormittal.com/media/case-studies/hydrogen-based-steelmaking-to-begin-in-hamburg  
11 https://www.thyssenkrupp.com/en/newsroom/press-releases  
12 https://www.lkab.com/en/news-room/press-releases  
13 https://www.voestalpine.com/group/en/media/press-releases 
14 https://salcos.salzgitter-ag.com/en/  
15 https://libertysteelgroup.com/news 

19 

 
 
 
STOA | Panel for the Future of Science and Technology  

In a transitioning phase, some argue that hydrogen could be blended into the natural gas grid (for 
more  details  see  chapter  5.4).  However,  in  the  case  of  H-DRI,  such  an  alternative  entails  further 
challenges and discussion. For instance, to fully reach decarbonisation  of crude steel production, 
sites  would  have  to  invest  not  only in  the  direct  reduction shaft  and  the  EAF  but  also  in  carbon 
capture and transport facilities. This high overnight investment together with high natural gas prices 
is the reason why DRI plants are mainly located where natural gas is cheap (e.g.: The Middle East and 
Russia).  

Moving forward 

for 
Continue  political  and  social  momentum 
decarbonisation 
(carbon  dioxide  pricing,  hydrogen 
economy  boosting  plans  and  subsidies)  to  accelerate 
knowledge  exchange,  innovation  and  technological 
shift.  

Joint  effort  between  governments,  regulators  and 
industry to alleviate overnight required investments and 
increase market stability. 

To reach long-term environmental goals, decisions made 
today  must  follow  a  clear  decarbonisation  road  map 
since industrial sites have long lifetimes and investment 
cycles. 

Steel decarbonisation timeline should be aligned and 
back  with  national  and  industry  roadmaps  for  RES 
deployment,  infrastructure  development,  supply  and 
decarbonisation plans in other sectors. 

Supply and infrastructure investment could pave the 
way for industrial hydrogen demand. 

to  guarantee 

Another  barrier  is  the  regulatory  framework 
needed 
the  same  mixture 
(hydrogen share) in all the European natural gas 
grid (see chapter 5.4), as well as determine the 
price of the hydrogen injected into the pipelines 
and the remuneration rules for natural gas and 
hydrogen  suppliers.  To  illustrate  this,  consider 
that  hydrogen  density  is  approximately  eight 
times  lower  than  the  one  of  natural  gas16  and 
the  hydrogen  content  of  natural  gas  is  25%, 
then, the quantity of hydrogen and natural gas 
mixture  to  be  delivered  would  decrease, 
although not in a linear proportion. For instance, 
with  a  5%  of  hydrogen  mixture  the  mass 
delivered would decrease by 13%, while with a 
20%  hydrogen  mixture  the  decrease  would  be 
37%.  These  changing  conditions  could  impose 
operating  and  regulatory  challenges  for  the 
natural gas-hydrogen blending case. 

Financial support to mitigate investment risk due to 
supply risk and market uncertainty, especially in sectors 
with tight margins. 

Harmonization  and  common  standards  covering 
hydrogen  purity,  hydrogen-natural-gas  blending  and 
market regulation. 

While  the  transport  of  electricity  entails  fewer 
energy  losses  than  the  pipeline  option,  the 
variability  of  renewables  plus  the  normally 
constant  operation  of  the  steel  plants  could 
further  congest  the  power  grid.  This  happens 
especially 
and 
sometimes congested industrial hubs. Thus, for 
the onsite electrolyser case, an ad-hoc storage unit should be included in other to deal with green 
electricity fluctuations and other electricity supply restrictions that might occur. On the other hand, 
in  the  case  of  a  pipeline,  such  infrastructure  needs  to  be  developed  and  tested  to assess  its  real 
capacity and reliability. However, and in contrast to the traditional primary route, the DRI system is 
flexible in terms of production and electricity demand. This feature could help with grid flexibility 
employing hydrogen and hot-briquetted iron storage, as well as the reduction of the share of scrap 
used to cope to some extent with shortages of H2. 

concentrated 

in  highly 

2.4.2. Alternatives pathways to decarbonise steel production 
Besides  the  hydrogen  route  to  reach  full  decarbonisation  in  the  steel  industry,  some  other 
technologies and projects reduce the carbon intensity partially (see Table 1). Although most of these 
alternatives  are  far  to  reach  full  decarbonisation  some  might  turn  out  to  be  advantageous  and 
favourable in the transition phase. Beyond the technology path to replace natural gas with hydrogen 
without major changes to the shaft (DRI), other alternatives that require lower investments seem to 
be  appealing  in  the  short  term.  As  mentioned  above,  the  assets  of  the  steel  industry  require 

16 Assuming natural gas density to be the same as methane density. 

20 

 
Carbon-free steel production: Cost reduction options and usage of existing gas infrastructure 

significant investments, especially considering the current age of the assets. This could suggest that 
steel producers will initially focus on incremental solutions to reduce carbon emissions (e.g.: top gas 
recovery, carbon capture, H2 injections) before moving to more disruptive process changes such as 
hydrogen direct reduction or iron electrolysis. This approach may extend the life of current assets 
while reaching interim milestones to carbon neutrality by 2050. However, it is important to note the 
limitation of the maximal decarbonisation potential that alternatives such as BF top gas recovery or 
BF-CCUS have (see Table 1). 

When considering a carbon capture and storage or utilisation approach, it is critical to consider that 
currently there is no market for the vast amount of CO2 that will originate from the steel sector in the 
case of BF-CCUS or NG-DRI-CCUS. Therefore, the establishment of synergies with the chemical sector 
should be developed alongside the progress of this decarbonisation pathway. On the other hand, 
carbon  storage  still  needs  to  overcome  public  acceptance  and  scale-up.  It  is  estimated  that  at 
present there are 26 CCS plants in operation with a capacity of 39 MtCO2 per year – equivalent to 
approximately 0.1% of global emissions from fossil fuels (Friends of the Earth Scotland and Global 
Witness, 2020). One of Europe's most advanced carbon capture and storage projects, the Northern 
17, which 
Lights project in Norway, is envisioned to have an annual storage capacity of 1.5 MtCO2
would be sufficient to store only approximately 1% of the current iron and steel industry emissions 
from Europe (EU28)18. 

Finally, the use of turquoise hydrogen19 , as well as the direct use of ammonia in the direct reduction 
of iron ore (DRI), are emerging alternatives that could solve some barriers of other similar routes. In 
the case of turquoise H2, the storage of CO2 could be partially solved since the use of carbon black20 
is more common nowadays as well as its transport and storage. Moreover, the direct use of ammonia 
to reduce iron could solve the reconversion losses in H2 shipping using ammonia as a carrier, since 
ammonia is much easier to handle compared to H2 in gaseous or liquid format. The iron electrolysis 
route  has  the  advantage  that  it  does  not  involve  electrolysis  of  water  or  the hydrogen  transport 
challenges. Still, it is a technology that is not close to maturity and involves very high investments. 
However, it could play a role in the long term to compete with low carbon H2. 

17 It corresponds to the capacity indicated by Equinor in its website. 
18 Data from Eurostat: Greenhouse gas emissions by source sector. Total emissions= fuel emissions + process emissions.  
19 Turquoise hydrogen is a by-product of methane (natural gas) pyrolysis, which splits methane into hydrogen gas and 

solid carbon, see Chapter 0. 

20 Carbon black is a by-product of natural gas pyrolysis. Is should not be confused with black carbon, an unwanted pollutant 

from incomplete combustion. 

21 

 
 
STOA | Panel for the Future of Science and Technology  

Figure 14. Energy intensity and CO2 emissions by steel production route 

Source: own elaboration 

Reducing the carbon intensity of steel production will imply some costs as well as policies enabling 
novel production routes to reach cost competitiveness in the long run. The average production cost 
of the integrated route (BF/BOF) remains the cheapest one up to 2030. However, the gap with other 
routes  shrinks  as  electricity  prices  decrease  and  CO2  emissions  prices  increase.  By  2050,  the 
integrated route could lose its competitive status mainly due to the increase of the CO2 emissions 
price. The production cost of the rest of the routes will come closer to each other, where hydrogen 
DRI becomes the most economical route under certain conditions. Forecasting the steel production 
cost  comes  with  high  uncertainty  due  to  the  volatility  and  expected  change  of  several  of  the 
parameters involved in the production (e.g.: iron ore price, electricity price, electrolyser CAPEX, CO2 
emission price, etc.). Thus, under certain assumptions (see Techno-economic assumption), Figure 15 
shows the weight of the different parameters in the final product price of steel, including the sinter, 
lime,  coke  plants  and  the  finishing  step.  By  2030,  the  cleaner  routes  will  have  an  environmental 
premium of 5-24% and an abatement cost of €73-€166 per ton of CO2, when compared with the 
integrated route (BF/BOF). 

22 

 
 
Carbon-free steel production: Cost reduction options and usage of existing gas infrastructure 

Figure 15. Steel production cost breakdown by production route, 2020 / 2030 / 2050  

Steel production cost breakdown by route (€/t)

549

15

97

3

7

17

16

207

69

54

7

412

55

207

46

14
19

2020

575

99

223

53

92

55

700

3

82

223

160

52
69

59

Integrated rout
(BF/BOF)

BF/BOF + H2 injection
+ CCSU

NG-DRI/EAF + CCSU

NG-DRI/EAF + H2 +
CCSU

538

184

207

46

16
13

52

8

19

11

564

97

207

51

54

8

2030
597

11

99

223

58

101

55

676

9

82

223

118

58

76

59

Integrated rout
(BF/BOF)

BF/BOF + H2 injection
+ CCSU

NG-DRI/EAF + CCSU

NG-DRI/EAF + H2 +
CCSU

659

237

249

2

7

44

66

H2-DRI/EAF

666

237

262

6

8

48

56

H2-DRI/EAF

699

350
699

350

207

207

7

7

11
13
11
13

571

98

97
571

98
207
97

16

207

16

7

7

14
11
14
11

46
46
Integrated rout
Integrated rout
(BF/BOF)
(BF/BOF)

54
54
BF/BOF + H2 injection
BF/BOF + H2 injection
+ CCSU
+ CCSU

2050

589

99

21

2050
589
223
99

21

588

82

588
223
82

17

17

11

11

42
223
99
42
99
55
55
NG-DRI/EAF + CCSU
NG-DRI/EAF + CCSU

38
223
42
75
38
42
75
59
59
NG-DRI/EAF + H2 +
NG-DRI/EAF + H2 +
CCSU
CCSU

565

237
565

237
173

173

35

35

7
7

52
52
H2-DRI/EAF
H2-DRI/EAF

CAPEX

Others

Coal

Natural Gas

Electricity

Electricity for H2

Iron ore/scrap

CCS

CO2

Source: own elaboration, see annex for underlying technical assumptions 

23 

 
STOA | Panel for the Future of Science and Technology  

Since the hydrogen-direct-reduction alternative is highly sensitive to electricity prices -or hydrogen 
price centrally produced- the location within Europe of the steelmaking sites and access to cheap 
electricity  could  be  advantageous.  Electricity  prices  in  2050  involve  great  uncertainty,  especially 
when  high  penetration  of  renewables  is  considered.  IEA  estimates  a  variable  renewable  price  of 
€43/MWh in the long term in Europe (IEA, 2019), however, lower prices are expected to be attained 
in  southern  Europe  (Spain,  Portugal,  and  Italy).  Figure  16  shows  the  impact  of  electricity  prices 
ranging between €20/MWh to €80/MWh on the steel production cost for the H-DRI route. In the two 
extremes,  the  electricity  share  of  the  production  cost  increases  from  20%  in  the  case  of  cheap 
electricity up to 50% when electricity prices are high. 

Figure 16. Hydrogen route steel production price sensitivity to electricity prices in 2050 

Impact of electricity price in H-DRI steel production - 2050

€ 716/tsteel
(€80/MWh)

€ 446/tsteel
(€20/MWh)

20%

€20/MWh

€50/MWh

39%

50% €80/MWh

Others

Electricity

H2-DRI/EAF

Source: Own elaboration, see annex for underlying technical assumptions 

The steel sector will have to compete with other sectors for access to low-carbon hydrogen to reach 
the environmental targets set for those sectors. Such is the case of the chemical sector, which is well-
positioned  to  use  green  or  blue  hydrogen  when  available  at  competitive  prices.  The  chemical 
industry uses hydrogen in the production of several platform molecules or end products such as 
methanol, ammonia and olefins, which are currently produced chiefly using natural gas. DECHEMA 
estimated in 2017 that the use of hydrogen produced from low-carbon electricity will be part of the 
decarbonisation path of the chemical industry, utilizing 500 - 1 400 TWh in 2030 and 2 000 – 4 500 
TWh in 2050 (DECHEMA, 2017). 

24 

 
 
 
 
 
Carbon-free steel production: Cost reduction options and usage of existing gas infrastructure 

Figure 17. Carbon-free electricity demand of hydrogen-based routes 

Source: (DECHEMA, 2017) 

25 

 
 
STOA | Panel for the Future of Science and Technology  

3. Case Study 'A Long-term vision on steel production' 

Takeaways 

A global long-term steel study by Vito and KTH (Stockholm) evaluated the evolution of the 
global steel sector taking into account: 

•
•
•
•

13 world regions, modelling for each region. 
The projected demand for long and flat steel products;  
The projected availability of steel scrap re-entering the production cycle; 
The projected trade among the world regions to balance supply and demand. 

The main insights of study show that ... 

Global steel demand will increase and plateau by 2070; 

•
• Majority of production increase will mainly be observed in flat steel production (87%) and 

•

•

•

less so in long steel (30%); 
The  availability  of  steel  scrap  will  increase  by  167  %  and  play  an  important  role  in 
decarbonizing the long steel production; 
GHG policies (such as unilateral CO2taxes in one region) can heavily impact the location of 
production facilities; 
Trade  of  scrap  and  finished  products  among  regions  balance  the  demand  and  supply 
globally making well developed regions (e.g. Europe) net-exporters while maintaining their 
existing production facilities. 

Vito and KTH Royal Institute of Technology (Stockholm) conducted a study (Xylia, Silveira, Duerinck, 
& Meinke-Hubeny, 2018) in collaboration with Arcelor Mittal, the largest steel production company 
in the world in 2016. The likely evolution of steel production, recycling, demand and trade among 
13 defined world regions from today till the year 2070 are evaluated. 

For  this  study,  a  Global  Steel  Production  and  Scrap  Availability  Model  has  been  developed  and 
applied. The Global Steel Production and Scrap Availability Model is a peer-reviewed model that has 
been created by VITO in cooperation with KTH. In this section, this model will be introduced, and the 
main findings of the study presented. 

3.1. Base assumptions - Steel production in a nutshell  

All steel in the world originates from iron ore either directly, or indirectly through recycled scrap 
molecules  consisting  of  iron and  oxygen  atoms.  The  production  of  steel  can  be  represented  in a 
simplified  way  as  a  two-stage  process.  In  the  first  step,  the  oxygen  is  removed  from  iron  ore 
molecules. This is done by a chemical reaction in the presence of a reducing agent. This is an energy-
intensive process at elevated temperatures and depending on the reducing agent it is also a CO2-
intensive process. The second step is to produce liquid steel, suitable for further processing. In this 
process,  impurities  are  removed,  and  the  material  is  melted  if  required.  Figure  18  presents  the 
quantities processed by different technologies for the two stages. 

26 

 
 
 
 
Carbon-free steel production: Cost reduction options and usage of existing gas infrastructure 

Note: The product categories, data, and graphs in this chapter reflect the assumption chosen in the 
aforementioned study and the underlying Global Steel Production and Scrap Availability Model and 
might show slight deviations from values in other chapters of this report.  

Figure 18. World steel production by technology 

Source: World Steel Association 

3.1.1. Steel recycling  
Steel  recycling  is  a  cost-competitive  option  for  decarbonising  the  steel  sector.  If  the  electricity 
supplied to the Electric Arc Furnace (EAF) is carbon-free, then this steel is almost carbon-free. Steel 
can  be  recycled  endlessly,  and  recycling  rates  are  very  high.  Between  2000  and  2018  scrap  use 
increased  by  136%.  Steel  scrap  accounts  now  for  23%  of  global  steel  production  and  scrap 
availability  is  expected  to  increase  further.  Consequently,  in  any  decarbonisation  scenario,  steel 
recycling will play a major role. 

The availability of steel scrap is considered in the steel production scenarios that will be discussed 
further on. However, for a proper understanding it is useful to take into account different type of 
scrap quality, which are also introduced in the applied model: 

•  Own scrap refers to material losses in the steel company itself, mainly in the finishing section. This 

scrap is of the highest quality and recycled internally. 

•  Prompt scrap is lost material in the manufacturing industry and also of very high quality. This is 

mainly recycled to the steel company that produced the steel within a short delay. 

•  Obsolete scrap is scrap released at the end of the life of products and is collected by scrap dealers. 
The delay between production and recycling depends on the type of application. E.g. beverage 
cans have a short lifetime (1-2 years), transport equipment such as cars have a longer lifetime (6-
20  years),  and  in  construction,  lifetimes  can  sometimes  exceed  100  years,  e.g.  in  buildings  or 
bridges. 

Whereas  availability  for  the  first  two  categories  can  be  considered  as  being  related  to  steel 
production itself, this is no longer the case for obsolete scrap. Availability of obsolete scrap depends 
on a long history of steel use, which is closely tied to the economic development of the respective 
world region. With respect to the geographic availability of scrap, there is also a layer of complexity 
since  for  certain  steel  applications,  the  demolishing  can  take  place  in  another  region  then  the 

27 

 
 
 
STOA | Panel for the Future of Science and Technology  

production  of  usage.  A  further  aspect  to  consider  is  the  composition  of  the  scrap  in  terms  of 
impurities. For own and prompt scrap the precise composition is known, facilitating the recycling 
for  production  of  similar  steel  qualities.  Obsolete  scrap  is  a  mixture  of  various  sources  and  the 
composition (level and type of impurities) is not known and not consistent. 

3.1.2. Steel products: Flat steel and long steel 
The World Steel Organisation (WSO) produces detailed statistics per country. In these statistics, a 
differentiation  is  made  between  flat  products  and  long  products.  Flat  products  have  major 
applications in car manufacturing, household appliances, radiators and many others. Long products, 
on  the  contrary,  have  major  applications  in  infrastructural  works  (bridges,  buildings,  concrete 
reinforcing,  railways,  etc.).  Although  both  steel  types  can  be  produced  by  different  production 
routes, the distinction is relevant in this context as scrap quality requirements for flat products are 
higher compared to long products. 

3.2. The global steel production and scrap availability model  

The global steel production model is a techno-economic 13 region model that has been designed 
to  develop  steel  production  scenarios  with  a  long-term  horizon  (up  to  2100).  Starting  from 
demographic  projections,  based  on  the  UN  statistical  department  work  and  macro-economic 
growth assumptions, the model generates demand for flat- and long steel products and determines 
optimal production pathways, considering the historical background. The 13 regions are linked by 
trade variables for flat- and long steel products and for high quality and low-quality scrap. 

Optimal production pathways are calculated by the model from a cost minimisation perspective. 
The model output provides the least-cost solution to supply the world with the required quantities 
of  flat  and  long  steel  products  over  the  full  model  horizon,  considering  feedstock,  CAPEX,  and 
transport cost for all possible options. 

Historical background includes the long-term history of steel appliances that become available as 
scrap, the lifetime structure of existing steel production plants. The history of steel consumption in 
developed  countries  has  also  been  used  as  a  reference  to  estimate  the  steel  consumption  in 
developing countries. 

28 

 
Carbon-free steel production: Cost reduction options and usage of existing gas infrastructure 

3.3. Scenario results  

Global  and  European  production  scenario  results  from  the  Global  Steel  Production  model  are 
presented in Figure 19 and Figure 20. 

Figure 19. Global steel production scenarios 

Source: VITO 

To satisfy increasing demand, the model results show a global flat steel production increase of 87% 
and production of long products of 30% between 2020 and 2070. However, in the same period, the 
availability of scrap is expected to increase by 167%, allowing for a higher share of EAF production. 
The production of virgin material tends to stabilise between 2020 and 2070. As EAF production is far 
less  energy  and  CO2  intensive,  these  scenarios  don't  demonstrate  a  dramatic  increase  in  CO2 
emissions but rather a stabilisation.  

A key issue in these scenarios is the allocation of global scrap available. Scrap availability is a function 
of historical steel use and tends to be much higher in well-developed countries. As steel recycling is 
the  most cost-efficient  way  for  decarbonising  the  steel  sector,  one  would expect  that developed 
countries have more cost-efficient options to decarbonise their respective sector, because of the 
high availability of scrap material. However, when looking at recent steel trade data we observe that 
well-developed regions like Europe and North America are net exporters of scrap. 

As global warming is related to global GHG emissions and not to their specific location, a global 
approach is used to allocate available scrap among the 13 regions in the Global Steel Production 
and Scrap Availability Model, i.e. scrap is considered as a tradable good and the allocation is purely 
based on economic considerations, namely to find globally the cheapest solution to satisfy the steel 
demand  for  flat  and  long  products  in each  region  of  the  world.  The  results  of  this  approach  are 
illustrated in Figure 21. In a global cost optimising setting Africa, India and other Asia (Asia excluding 
China,  India,  South  Korea,  and  Japan)  will  become  major  scrap  importers  by  2050  and  Europe 
(30 countries – including UK, Switzerland, and Norway) becomes the second-largest exporter after 
China, exporting almost 55 Mton of scrap (compared to 275 Mton for China). 

European scrap exports are also considered in the European Steel Production scenarios in Figure 20. 
By 2050, long products are completely based on the use of scrap in EAF, but for flat products, EAF 
takes  only  a  small  fraction  and  the  major  part  (93  Mton)  is  still  virgin  production  from  iron  ore 
(represented as BOF new).  

29 

 
 
 
STOA | Panel for the Future of Science and Technology  

Figure 20. European steel production scenarios 

Source: VITO 

Figure 21. Trade of obsolete scrap in the global steel production scenario 

Source: VITO 

The  global  steel  production  model  has  also  been  used  to  investigate  the  potential  impact  of  an 
isolated European Climate Policy in the absence of any special external border policies, i.e. import 
restrictions/border  taxation  for  embedded  CO2 emissions  of  imported  steel.  For  this  exercise,  we 
simply applied a CO2 price of respectively €15 and €50 on CO2 emissions of European steel producers. 
This has mainly an impact on flat steel production and less on long production as it will be based on 
the use of scrap. For €15/ton CO2 the impact is rather limited, but for €50 we see that European flat 
steel production will be very sensitive to re-locate to other regions in the world with a CO2 price. 

30 

 
 
 
 
 
Carbon-free steel production: Cost reduction options and usage of existing gas infrastructure 

Figure 22. Potential impact of a European Climate Policy 

Source: VITO 

Note: Base = Model scenario without CO2 price, T15EU & T50EU = Scenarios with a respective 15 / 50 Euro per ton CO2 
price in the Europe region only. 

31 

 
 
 
 
STOA | Panel for the Future of Science and Technology  

4. Production and supply of hydrogen 

Takeaways 

•

•

•

If the primary steel produced in Europe is expected to be produced solely by H-DRI route, it 
is necessary to produce 6-8 MtH2 (green/blue hydrogen) by 2050. This is almost all the green 
hydrogen  expected  in  the  EU  Hydrogen  Strategy  in  2030  (10  MtH2),  and  more  than  the 
hydrogen allocated as feedstock in the Hydrogen Roadmap Europe-FCH-JU (10 MtH2). 
Besides water electrolysis (Green H2), natural gas based pyrolysis (Turquoise H2) and iron ore 
electrolysis can offer an almost carbon free alternative to BF/BOF. 
Delivering low-carbon hydrogen to steel production sites depends on the development of a 
reliable and suited infrastructure (pipelines, compression units, storage, power grid). 

Hydrogen is an odourless, invisible gas and one of the most abundant elements on earth. However, 
it is rarely found in its pure form (H2) and more commonly as a compound such as in water (H2O) or 
methane  (CH4).  Therefore,  it  must  be  obtained  by  separating  processes  such  as  Steam  Methane 
Reforming (SMR), water electrolysis, Auto Thermal Reforming (ATR), and pyrolysis. Since hydrogen 
is not an energy source itself but rather an energy carrier, its production requires a certain amount 
of  energy  to  break  the  covalent  bonds21  that  keep  the  hydrogen  molecules  bonded  to  other 
elements. 

4.1. Production of hydrogen 

The source of hydrogen as well as the technology used to produce it determine the carbon emissions 
associated and, therefore, the type of hydrogen. Recently, a hydrogen colour convention has been 
used and widely accepted among research institutes, governments, and industries (see Table 3). An 
additional classification for hydrogen is given by the emission linked to its production (gCO2/MJH2). 
In 2016, under the CertfHy project, FCH-JU established the threshold for low-carbon hydrogen at an 
emission  factor  of  36.4  gCO2-eq/MJH2  (CertifHy,  2019).  The  defined  threshold  was  expected  to  be 
reduced annually following a declining path until reaching a point where only green hydrogen was 
produced. 

Table 3. Hydrogen types in a colour scheme by technology and fuel 

Type of Hydrogen 

Production 

Considerations 

Emission Factor 

Brown/ 

Black 

through 
The 

coal 
Produced 
gasification. 
colour 
depends  on  the  type  of  coal 
used: brown (lignite) or black 
(bituminous) coal. 

It  is  a  highly  polluting  process 
since  both  CO2  and  CO  are  not 
reused  and,  thus,  released  into 
the atmosphere. 

19 tCO2/tH2  

(IEA, 2019) 

21 A covalent bond involves the sharing of electron pairs between atoms in a molecule.  

32 

 
 
 
 
Carbon-free steel production: Cost reduction options and usage of existing gas infrastructure 

Type of Hydrogen 

Production 

Considerations 

Emission Factor 

Grey 

Blue 

Purple/ 

Pink  

Turquoise 

Sunlight 

Yellow  

Green 

Produced  from  fossil  fuels, 
most commonly from natural 
gas through the SMR process. 
Less  commonly  it  uses  the 
ATR process 

it 

is 

Although 
a  mature 
technology,  it  involves  notable 
disadvantages such as mass and 
heat  transfer  issues,  as  well  as 
coke  deposition  during 
the 
reaction. 

10 tCO2/tH2  

(IEA, 2019) 

It  is  produced  in  the  same 
way  as  brown  or  grey 
hydrogen,  but 
is 
captured and stored or used. 

its  CO2 

Depends  on  the  availability  of 
carbon  storage  (CCS)  or  carbon 
use (CCU).  

0.64  –  0.99  tCO2/tH2 
(CE Delft, 2018) 

Obtained  by 
electrolysis 
linked  to  a  nuclear  power 
plant. 

It faces the public acceptance of 
nuclear plants and the phase-out 
plans defined by several Member 
States.  

CO2 free 

Turquoise  hydrogen  is  a  by-
product  of  methane  (natural 
gas)  pyrolysis,  which  splits 
methane  into  hydrogen  gas 
and solid carbon.  

It is highly energy-intensive. The 
current market will not be able to 
absorb  the  massive  amounts  of 
carbon  black  produced  (Wiley-
VCH-GmbH, 2020). 

CO2 free  

Produced 

It  does  not  have  yet  an 
to  be 
established  colour 
classified. 
by 
photocatalytic water splitting 
with  solar  energy,  without 
the 
going 
electrolysis step. 

through 

Several  technologies  are  being 
developed but are still at the lab 
or small prototype scales. 

CO2 free 

by 

Produced 
water 
electrolysis utilising using the 
power  of  mixed  origin  from 
(others  refer  to 
the  grid 
hydrogen  produced 
from 
solar power)  

It  is  produced  by electrolysis 
solely 
of  water, 
electricity 
renewable 
from 
energy sources. 

using 

Since  the  origin  of  the  power  is 
not carried, it could have a high 
CO2 emission factor associated. 

Power  grid 
factor 
(gCO2/kWh).  Incurred 
T&D  losses  should  be 
accounted for. 

Availability of RES and water play 
a key role. 

CO2 free 

Source: Own elaboration based on (IEA, 2019), (CE Delft, 2018), (Wiley-VCH-GmbH, 2020), and own analysis. 

4.2. Supply of hydrogen 

The production of low carbon hydrogen in the EU, either green or blue, depends on the availability 
of RES and the feasibility  and potential of carbon capture and storage or utilisation, respectively. 
Considering the increasing hydrogen demand in Europe, which is expected to be 12-17 MtH2 in 2030 
and 20-57 MtH2 in 205022 (FCH-JU, 2019), and the potential of new wind and solar power generation 
installations,  it  is  most  likely  that  hydrogen  imports  will  play  a  relevant  role.  Currently,  Europe 
consumes approximately 9 MtH2, which is to a large extend being produced by natural gas-based 
steam  methane  reforming.  In  this  regard,  Hydrogen  Europe  estimates  that  by  2030  Europe  will 

22 Based on the HHV of H2 = 141.88 MJ/kgH2 . 

33 

 
 
 
 
 
 
 
 
 
 
 
 
 
STOA | Panel for the Future of Science and Technology  

import 3 MtH2 -nearly 18% of its hydrogen demand- and will produce locally 7.4 MtH2 (Hydrogen 
Europe,  2020).  The  share  of  imported  hydrogen  could  increase  in  the  long  term  if  fossil-based 
hydrogen  with  carbon  capture  and  storage  or  utilisation  is  not  deployed  in  time  to  meet  the 
remaining  9.5  MtH2  that  are  expected  to  be  covered  by  blue  hydrogen  by  2030  according  to 
Hydrogen Europe.  

Figure 23. Hydrogen production costs for different technology options in 2030 

Yellow 

Green 

Grey 

Blue 

Brown 

Blue 

Source. (IEA, 2019). 23 
Hydrogen label colours included by VITO NV. 

Future hydrogen production within the borders of the European Union is being championed by the 
2x40 initiative while considering the potential of neighbouring countries in the North Africa region 
and  Ukraine.  The  initiative  envisions  by  2030  the  installation  of  40  GW  of  electrolyser  in  Europe 
powered by 82 GW of wind and solar generation. It additionally foresees the rollout of 32.5 GW of 
electrolyser in the neighbouring countries which will be dedicated to exports to Europe (Hydrogen 
Europe, 2020). The European Commission mentions in its Hydrogen Strategy that it will be possible 
to produce 10 Mt of green hydrogen (333 TWhH2) by 2030. This represents more than the hydrogen 
needed to completely produce 94 Mtstee with the H-DRI route -this requires approximately 6.6 MtH2. 
However,  producing  10  Mt  of  green  hydrogen  means  that  75  GW  of  electrolysers  (the  capacity 
envisioned in the 2x40 initiative), with an efficiency of 74%, will operate with green electricity around 
6  000  hours  per  year  –  this  without  considering  transport  and  storage  losses  and  energy 
consumption.  

To put the hydrogen needs of the steel sector with the H-DRI route (6-8 MtH2) into perspective, the 
additional hydrogen demand forecasted by FCH-JU in its ambitious scenario for all hydrogen end 
uses is forecast to be 7 MtH2 by 2030 and 56 MtH2 by 2050. This is on top of 13 MtH2 and 12 MtH2 
demanded by the existing industry for the same years (FCH-JU, 2019). In the same study, 1.9 MtH2 
are allocated to New Industry Feedstock in 2030 and 7.8 MtH2 in 2050 (out of which 4.2 MtH2 are 
indicated to be used in the steel sector in 2050 to produce 20% of the steel in Europe). Thus, if the 

23 CAPEX used in IEA 2019: Electrolysis = 647 €2020/kWe. SMR = 841 €2020/kWH2. SMR with CCS = 1257 €2020/kWH2. 

34 

 
 
 
Carbon-free steel production: Cost reduction options and usage of existing gas infrastructure 

production of primary steel continues to be 60% of the total production and it is fully produced with 
the H-DRI route, the demand for low-carbon hydrogen in the sector by 2050 could be 7-12 MtH2.  

Figure 24. FCH-JU vision on Europe's future hydrogen demand by sector 

Source: (FCH-JU, 2019) 

4.3. Hydrogen handling 

For  hydrogen  to  reach  the  end-use  location,  its  transport,  storage,  and  distribution  should  be 
carefully  considered  and  planned.  The  development  of  the  required  infrastructure,  which  will  be 
addressed in more detail in Chapter 5: Hydrogen infrastructure, depends not only on the hydrogen 
production sites or the hydrogen importing terminals but as well on the so-called hydrogen valleys. 
Such valleys aggregate several current and potential hydrogen users (e.g.: petrochemical industry, 
steel) in an industrial cluster within a defined geographical area. To better characterise such valleys 
and  overcome  the  lack  of  information  for  the  participants  of  the  future  hydrogen  economy,  the 
European Commission launched in 2019 the European Hydrogen Valleys Partnership24.  

By 2030, the members of Gas for Climate envision an initial hydrogen backbone in western-central 
Europe, around the already established industrial clusters in the Netherlands, Belgium, the west of 
Germany, and north of France (Guidehouse, 2020).  

24 Hydrogen Valleys website: https://s3platform.jrc.ec.europa.eu/hydrogen-valleys  

35 

 
 
 
 
STOA | Panel for the Future of Science and Technology  

5. Hydrogen infrastructure 

Takeaways 

•

•

•

•

•

•

•

Europe has approximately 260 000 km of gas transmission and 1.4 million km of distribution 
pipelines. Compared to approximately 2 000 km of existing hydrogen pipelines. The natural 
gas  grid  is  operated  by  different  organizations  across  the  EU  with  who  can  apply  their 
experience to plan for transporting hydrogen on larger scale. The demand of hydrogen is 
estimated to be 1 130 TWh per annum. 
Converting selected parts of the existing natural gas grid for transporting hydrogen creates 
pathways for hydrogen producers, industrial off takers, operators and regulators to prepare 
for  deep  decarbonisation  of  hard  to  abate  sectors  such  as  iron  and  steel.  The  Hydrogen 
Backbone study envisions a network of 23 000 km of hydrogen pipelines of which 75% are 
repurposed natural gas pipelines.  
It is estimated that total cost spent for repurposing natural gas pipelines represents 10 - 20% 
of  the  cost  of  newly  installed  dedicated  hydrogen  pipelines  (compression  and  storage 
infrastructure  excluded).  However,  natural  gas  infrastructure  will  exist  in  parallel  with 
hydrogen for a considerable time. Selected new hydrogen pipelines will have to be built in 
adjunction. 
Blending of hydrogen, 5%-20% with bio methane or natural gas is technically possible and 
can be made available at relatively low cost, however it comes with complex regulations and 
compatibility constraints in a European grid context while the impact on reducing carbon 
emissions is limited e.g.: blending in 10% green hydrogen results in 3% CO2 reduction. 
Storage capacity to provide short and long-term backup, due to the intermittent nature of 
green hydrogen is an essential element of the European hydrogen infrastructure. 
Existing storage facilities in the form of salt caverns or depleted oil and gas fields are good 
candidates due to its relatively low cost (€6 - €26 MWh/H2) but will have to be investigated 
further in terms of engineering safety and matched with the hydrogen needs of industry and 
other sectors.  
Large hydrogen of takers are often concentrated in industrial clusters, with high demands 
for hydrogen often as a fuel and feedstock, are some of the geographical hot spots in the 
European hydrogen backbone. They can exist as islands and might be interconnected where 
it makes sense.  

Hydrogen  infrastructure  describes  the  physical  links  between  the  point  of  production  and 
consumption. It comprises the long and short distance pipelines, transport by ship, road, terminal 
stations, long and short-term storage facilities and filling stations. Similar to roads, providing the 
means for cars to drive on, adequate and secure hydrogen infrastructure is essential in the mass roll-
out  of  hydrogen  in  industrial,  power,  transport,  food  and  process  sectors.  Currently,  the  existing 
hydrogen  transport  infrastructure  is  one  of  the  main  bottlenecks  in  the  transition  to  sustainable 
hydrogen use in the EU. 

36 

 
 
Carbon-free steel production: Cost reduction options and usage of existing gas infrastructure 

Upscaling  hydrogen  in  the  European  gas  grid  can  be  achieved  by  reusing  existing  natural  gas 
infrastructure,  blending  to  a  certain  extend  hydrogen  with  natural  gas  and  building  dedicated 
hydrogen routes. This requires careful planning across the entire value chain. Specifically, for the 
steel industry, where hydrogen can be used both as an energy vector and feedstock, large amounts 
of green or blue hydrogen can help to reach the EU 2050 climate targets.  

5.1. Transport of hydrogen 

Regardless of the production method of hydrogen, as described in Chapter 4, the molecule will have 
to be transported as long as it is not used at the place of production. Costs for transmission and 
distribution of hydrogen could end up being three times higher, when building new infrastructure, 
compared  to  the  cost  of  hydrogen  production.  In  summary,  hydrogen  can  be  transported  as  a 
compressed gas or as a cryogenic liquid due to liquefaction (just below its boiling point of -252.9 °C). 
The cheapest method of delivery depends on the quantity delivered and the distance. 

5.1.1. Pipelines 
For distances below 1 500 km, transporting hydrogen as a gas by pipeline is likely to be the cheapest 
delivery  option  (IEA,  2019).  This  way,  expensive  liquefaction  or  high-pressure  compression 
infrastructure, compared to transporting hydrogen by road or water, can be avoided. See Figure 25. 

Figure 25. Hydrogen production and transport route using pipelines 

Source: (Siemens Energy, 2020) 

The requirements for a hydrogen pipeline line system has similarities with the existing natural gas 
infrastructure in Europe. Today, the European natural gas network consists of approximately 260 000 
km  of  high-pressure  pipelines  which  are  operated  by  transmission  system  operators,  and 
approximately  1.4  million  km  of  medium  and  low-pressure  pipelines  operated  by  distribution 
system operators (Navigant, 2019) as shown in Figure 26.  

37 

 
 
STOA | Panel for the Future of Science and Technology  

Figure 26. Existing European gas network 

Source: (Navigant, 2019) 

When comparing the energy density of hydrogen (3 kWh/Nm3), it is 3 times lower than the active 
component of natural gas, methane (10 kWh/Nm3). This makes hydrogen very light. However, its 
LHV is roughly 2.5 times higher than methane. Hydrogen is a very compressible gas that can 
increase the energy density and makes it comparable with the energy density of natural gas. In gas 
form, hydrogen can be transported in large amounts through pipelines and stored in caverns or 
pore storage. A comparison in terms of energy volumes transported between the electricity grid 
and the gas grid is often made to point out the large differences and opportunities for using gas as 
an energy carrier. The gas infrastructure can transport between 10 and 20 times more energy over 
long distances than a high voltage electricity cable can as illustrated in Table 4. 

Table 4. Cable versus pipeline energy transport examples 

Name 

Capacity 

Cable 

Cable (BritNed) 

1GW 

Construction costs 

EUR 600M 

Pipeline 

Pipeline (BBL) 

20GW 

EUR 500M 

38 

 
 
Carbon-free steel production: Cost reduction options and usage of existing gas infrastructure 

Distance 

Volume (year) 

Name 

Capacity 

260 km 

8TWh 

Cable 

Cable (NEMO) 

1000 MW 

Construction costs 

EUR 690M 

Distance 

Volume (year) 

140km 

8TWh 

Source: (Hydrogen Europe, 2019) 

230km 

120TWh 

Pipeline 

Pipeline (IUK) 

FWD (import BE): 27 153 MWh/h REV 
(export BE): 33 476 MWh/h 

EUR 713M 

235 km 

240TWh 

There  are  various  studies  ongoing  where  transporting  hydrogen  through  existing  natural  gas 
pipelines  are  tested.  Both  blending  hydrogen  and  natural  gas,  as  well  as  transporting  of  100% 
hydrogen belong to the possibilities. This contributes to developing transition pathways towards 
the EU2050 climate targets, safeguarding existing assets and investments, whilst allowing for the 
industry to prepare for the next steps. Besides existing pipelines, most likely additional infrastructure 
would have to be built to facilitate future demand across all sectors. (Siemens Energy, 2020) 

5.1.2. Shipping 
Hydrogen can also be imported by ship. However, due to its low energy density, it will have to be 
liquefied  by  decreasing  the  temperature  to  below  240  °C.,  in  combination  with  increasing  the 
pressure.  Energy  requirements  for  liquifying  hydrogen  are  greater  than  compressing  hydrogen 
though, at very low temperatures, hydrogen takes more than ten times less space. Another means 
to transport hydrogen in large quantities overseas is by transforming it into a carrier with higher 
densities such as ammonia or in liquid organic hydrogen carriers (LOHCs). Once the hydrogen or 
carrier molecule arrives at a port somewhere in the EU, they can be loaded onto the gas grid and 
transported or temporarily stored. Using a different molecule than hydrogen as a carrier overseas 
makes hydrogen more cost-efficient due to the availability of large amounts of variable renewable 
energy  sources.  However,  it  requires  special  handling  at  the  terminals  to  convert  hydrogen  into 
these carriers and back to hydrogen. These costs have to be taken into account as well as matters of 
safety and social acceptance. (IEA, 2019) 

Finally, the transmitted hydrogen has to arrive at the point of use where it can be used as a source 
of energy or feedstock such as in the steel sector where hydrogen can play a role, as described in 
chapter 2.4.2 Alternatives pathways to decarbonise steel production. 

5.2. Hydrogen Backbone 

The EU gas network is well developed with a working gas volume of approx. 24.3 billion m³. The 
existing natural gas pipelines can play a key role in repurposing the gas transmission for hydrogen. 
Both  in  terms  of  time  to  build and  investments,  it  presents  opportunities  to  transition towards  a 
climate-neutral hydrogen-based industry. Depending on the size and material, pipes of the natural 
gas grid could either be used in their current state or might require repurposed to cope with the 
higher pressure required to transport hydrogen and degradation of the iron and steel walls of the 
pipes due to hydrogen embrittlement. The latter can lead to cracks in the pipework. Most of the 
upgrades will have to take place on the compressor stations, valves, fittings, metering stations, and 
storage tanks. Though compared with building new pipelines, these costs are relatively small. The 
technical  aspects  differ  by  the  location  of  the  gas  grid  and  the  topography  such  as  hills  and 

39 

 
STOA | Panel for the Future of Science and Technology  

mountains. Besides the infrastructure cost, spatial planning, social acceptance, environmental and 
building permitting as well as regulatory procedures can be time and cost-intensive. These required 
steps could easily take five to seven years between planning and commissioning of the new pipeline. 
The existing gas pipelines, including their rights of way and use, are however available and generally 
accepted by the population. (Siemens Energy, 2020)  

Existing gas grids often consist out of parallel pipelines which could be used to build scenarios of 
introducing  hydrogen  in  a  phased  approach,  aligned  to  demand  and  production  volumes  and 
technology development, as (Navigant, 2019) describe in their report Gas for Climate. Currently, EU 
gas  transmission  owners  are  conducting  studies  and  tests  to  find  out  which  parts  of  their 
infrastructure can be reused for transporting hydrogen. A projection of how a European hydrogen 
backbone could look like is shown in Figure 27.  

On December 15th, a proposal to extend the existing framework for trans-European energy network 
(TEN-E) has been published in the European Commission. A revision of the current TEN-E allowing 
for changes in the gas landscape such as the production, transmission, distribution and storage is 
required.  The  next  TEN-E  version  will  also  include  dedicated  new  hydrogen  infrastructure, 
repurposed pipes and connections with other countries. However, the proposal does not mention 
the option of retrofitting existing gas infrastructure for the purpose of blending hydrogen (European 
Commission, 2020). Studies such as the Thyga project, coordinated by Engie and eight partners from 
six  other  European  countries  (DGC,  Electrolux,  BDR,  Gas.be,  CEA,  GWI,  DVGW-EBI  and  GERG),  are 
working  together  in  this  36-month  project  which  started  in  2019  as  part  of  the  Fuel  Cells  and 
Hydrogen Joint Undertaking organisation. Its purpose is to get a better understanding of blending 
hydrogen with natural gas (Thyga, 2021). 

40 

Carbon-free steel production: Cost reduction options and usage of existing gas infrastructure 

Figure 27. Mature European Hydrogen Backbone 

Source: (Guidehouse, 2020) 

This  idea  of  the  hydrogen  backbone  has  been  developed  by  ten  European  countries  (Germany, 
France, Italy, Spain, the Netherlands, Belgium, Czech Republic, Denmark, Sweden, and Switzerland) 
which host eleven gas transmission operators Enagás, Energinet, Fluxys Belgium, Gasunie, GRTgaz, 
NET4GAS,  OGE,  ONTRAS,  Snam,  Swedegas  (Nordion  Energi),  Teréga,  and  consultancy  company 
Guide house (formerly known as Navigant). Its vision aims in the first phase to have 6 800 km of 
hydrogen pipelines available by 2030 and 23 000 km by 2040 of which 75% would consist out of 
reused natural gas  pipelines.  Due  to  its  phased approach  of  rolling  out  the  hydrogen  backbone, 
dedicated hydrogen microgrids can emerge around industrial clusters. As the backbone develops 
over  time,  larger  volumes  of  hydrogen  can  be  transported  within  industrial  clusters  and  their 
connections  with  other  clusters  as  well  as  regional,  national,  and  international  connections. 
(Hydrogen Europe, 2019) 

According to the Hydrogen Europe Backbone report (Guidehouse, 2020), one of the challenges is 
dealing with the diversity in operational gas pipeline sizes in Europe today, ranging from 20-inch 
pipelines to large 48-inch pipelines and even larger in some cases. Depending on the diameter but 
also the pressure applied, more or less energy can be transported. For instance, a 36-inch pipeline 
has  a  transport  capacity  of  7  GW and  a  48-inch  pipe has  a  capacity  of  13 GW  for  the  purpose  of 
transporting natural gas. The capacity could be optimised to 17 GW in the case of hydrogen due to 

41 

 
STOA | Panel for the Future of Science and Technology  

higher flow rates. One backside is that increasing flow rates could lead to higher compressor costs. 
In some cases, for newly build stretches, it might be more economically advantageous to install a 
parallel pipeline with the same diameter rather than investing in more expensive compressors.  

The electrolyser needs to be sized according to the demand for hydrogen which could lead to the 
pipeline  having  a  larger  capacity  than  the  hydrogen  the  electrolyser  is  producing  at  its  output 
pressure. For example, during the start-up phase of a new section of the hydrogen backbone, the 
demand for hydrogen might be low. However large-sized pipelines  might already be installed to 
accommodate future demand. By running in low capacity mode, costs for compressors can initially 
be kept low until an  increase in the flow of hydrogen  is warranted by demand increases. Finally, 
when  looking  at  the  consolidated  interconnected  grid,  the  study  from  the  hydrogen  backbone 
envisions enough capacity to meet the total hydrogen transport demand by 2040 which is estimated 
to be 1 130 TWh annually. (Guidehouse, 2020) 

Part of the EU hydrogen backbone includes storage. Hydrogen used in heavy industry, such as the 
iron and steel sector, mainly require intraday or intra-week storage. For small amounts of hydrogen 
storage, onsite pressurised tanks are often sufficient to ensure continuity whereas large amounts of 
hydrogen buffers require underground storage. (Guidehouse, 2020) 

Besides  the  gas  network,  there  are  about  33  000  km  of  oil  pipelines  that  could  be  re-used  for 
hydrogen transport, depending on the future need for liquid fossil fuels, once they are no longer 
needed (Navigant, 2019). 

5.3. Transmission and distribution 

Currently, the natural gas grid consists out of long-distance pipelines with high pressure, between 
15  and  80  bars,  and  distribution  pipelines  for  shorter  distances  with  pressure  below  15  bars. 
Transmission  pipelines  are  usually  made  out  of  steel  to  cope  with  the  higher  pressures  and 
distribution pipelines are made of various materials like cast iron, PVC enriched polyethylene, fibre-
reinforced cement or steel. Assuming large amounts of hydrogen are required for use in the steel 
industry, the focus of the next chapters lies on the transmission network. 

5.3.1. Existing hydrogen network 
Besides the natural gas grid, which is by size and coverage the largest gaseous molecules network, 
there are worldwide more than 4 500 km of dedicated hydrogen pipelines in total, mainly operated 
by  private  company  Air  Liquide.  The  longest  pipelines  are  operated  in  the  USA,  in  the  states  of 
Louisiana and Texas (2 608 km), followed by Belgium (613 km), Germany (376 km), France (303 km) 
and the Netherlands (237 km) (Europe, 2017). Figure 28 shows an overview of the largest no-natural 
gas infrastructure in the EU. 

42 

Carbon-free steel production: Cost reduction options and usage of existing gas infrastructure 

Figure 28. Existing no-natural gas pipelines in Europe 

Source: (Air Liquide, 2021). 

5.3.2. Repurposing 
There is a strong indication that the natural gas network pipelines can be repurposed to transport 
hydrogen. Various studies and experiences of technology and material are showing that it makes 
sense to re-use at least part of the existing gas grid and can be implemented in a phased approach. 
Comparing repurposing with constructing new pipelines, the former lowers complexity and time to 
market. When comparing the energy flow of two gases through a pipeline, it is not only the volume 
that is important. Mainly values of density, flow velocity and pressure impact the amount of energy 
that can be delivered via a pipe. Since hydrogen has a density which is nine times lower and three 
times the flow rate of natural gas, almost three times the volume of hydrogen can be transported 
simultaneously  in  the  pipeline  at  the  same  pressure.  Therefore,  the  switch  from  natural  gas  to 
hydrogen has little impact on the capacity of a pipeline to transport energy. (Siemens Energy, 2020). 

5.3.3. Compressors 
Compressor stations play a vital role in transporting gas in a pipeline. Parameters of the viscosity of 
the  gas  as  well  as  the  velocity  of  the  gas,  combined  with  friction  against  the  inner  side  of  the 
pipelines and elevation distances, causes resistance of the flow and leads to a pressure drop. As the 
pressure in a pipeline has to be kept within certain ranges, recompression is needed. A gas that flows 
through  a  pipeline  with  lower  capacity  utilisation,  which  is  the amount  of  hydrogen  that  passes 
through  a  compressor  per  unit  if  time,  experiences  a  lower  pressure  drop  thus  require  smaller 
compressors.  This  an  important  parameter  towards  the  sizing  and  costs  of  the  compressors. 
Repurposing or retrofitting large transmission lines requires larger and more expensive compressors 
compared to smaller pipes. The distance between compressor stations is typically 100 km but can 
reach up to 600 km and depends on the size of the pipes, material, and landscape (Calisto, 2020). 

The  type  and  number  of  compressors  in  each  compression  station  depend  on  the  size  of  the 
pipelines. Currently, piston compressors are used – up to 750 000 Nm3/h, which are fed from the 
natural gas grid to which they are connected. For transmission of larger volumes per unit of time, 

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STOA | Panel for the Future of Science and Technology  

turbo compressors are needed. When using hydrogen, blended with natural gas or pure, they will 
have to be adapted to burn the hydrogen as an operating fuel. However, most common compressors 
can already handle a certain amount of hydrogen. When using more than 10% of hydrogen, typically 
the compressor needs to be retrofitted. In case more than 40% of hydrogen is used, the compressor 
needs to be replaced by an adequate model. As technology advances, this problem diminishes, and 
future compressors could be made 100% compatible with the use of hydrogen. (Siemens Energy, 
2020) 

Safety protocols, in case of emergency shut-off, will have to be revised as well as existing regulations 
within and across nations and network operators. Inspections prior to commissioning the retrofitted 
part of the grid have to be carried out and maintenance plans will have to be updated. 

5.3.4. H2 repurpose initiative in Germany 
The Get H2 Initiative, together with FNB Gas as the main national gas and transport companies aims 
to establish a national hydrogen infrastructure in Germany. The plan is to build a 5 900 km hydrogen 
grid  (see  Figure  29).  Industrial  sites  such  as  steel  and  chemical clusters can  be  connected  to  the 
network. Local hydrogen production from wind and solar as well as imports can feed the grid with 
hydrogen.  The  main  objective  is  to  repurpose  90%  of  the  network  by  converting  existing  gas 
infrastructure to the hydrogen-based grid. It is estimated that this approach results in a total cost of 
10-20% of the investment of constructing a new dedicated hydrogen network. This kind of initiatives 
are essential to get a better understanding of how an existing part of the European gas grid could 
technically and economically be optimised for the use of hydrogen.  

44 

 
 
 
 
 
 
 
 
Carbon-free steel production: Cost reduction options and usage of existing gas infrastructure 

Figure 29. National Hydrogen Backbone in Germany in 2030 –Proposed by FNB Gas 

Source: (FNB Gas, 2020) 

5.3.5. Transmission costs 
Investment  costs  for  new  pipelines  can  vary  significantly  depending  on  location,  material  and 
regulation.  Besides  material,  also  the  installation  costs  are  determined  by  the  type  of  pipeline. 
Typically, two methods are used for installation. Trenchless pipes, where a tunnel is bored or drilled, 
which is generally cheaper than cut-and-cover pipes which are usually built in segments. The great 
diversity in pipelines materials, utilisation capacities, compressor stations, blending %, the grade of 
repurposing  existing  pipes,  distances  but  also  the  geographical  spread  and  volumes  of  (future) 
supply  and  demand  make  it  difficult  to  make  estimations  on  the  final  cost  of  the  hydrogen 
backbone.  An  overview  of  investment  cost  ranges  and  the  Leverage  Cost  of  Transmission  for 
repurposing existing versus new pipelines are shown in Table 5.  

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STOA | Panel for the Future of Science and Technology  

Table 5. Costs for repurposing or replacing gas network transmission 

Component 

Value (2019) 

Comment 

Investment repurposing 
existing pipelines 

M€ 0.37/km 

Germany based case, cost of repurposing 15% 
compared to the new pipeline  

Source 

[1] 

Investment cost new 
pipeline (range) 

M€ 0.93/km 

16-inch average diameter. Costs for 
transmission of 6 300 km in the UK.  

(excl. compressors). 

M€ 2.1/km 

The 48-inch pipeline, operating between 30-
80 bar with a length of 300 km in the UK.  

M€ 3.28/km 

48-inch pipeline.  

(excl. compressors) 

Investment New 
compressor (range) 

M€ 0.65/MW 

M€ 1.07/MW 

Costs for a 5.8 MW compressor, with a 240 
t/day throughput.  

5.8 MW capacity for compressor, calculated 
according to cost curve in source  

(compressors are required every 100-600 km, 
highly case-specific) 

LCOT for H2 
transmission – 
repurposing natural gas 
infrastructure  

LCOT for H2 
transmission - New 
natural gas 
infrastructure (range) 

M€ 3.7/MWh H2 
per 600km 

Repurposing existing gas infrastructure for 
100% hydrogen.  

M€ 4.6/MWh H2 
per 600km 

48-inch pipeline. Includes pipeline and 
compressor CAPEX and OPEX and 
compression fuel-related costs.  

M€ 11.4/MWh H2 
per 600km 

Transportation over 1500 km is assumed 
by source, considering all capital and 
operating costs. Normalised to 600 km.  

M€ 45/MWh H2 
per 600km 

Estimated including compression costs for 
pipes of diameters between 7-10 inches 
over 100 km as assumed by source. 
Normalised to 600 km.  

[2] 

[3] 

[4] 

[5] 

[4] 

[6] 

[6] 

[7] 

[8] 

Sources: 1. (FNBGas, 2019), 2. (Element Energy & E4Tech, 2018), 3. (Navigant, 2019), 4. (Jacobs, Element Energy, 
2018) , 5. (Baufumé, 2012), 6. (Navigant, 2019), 7. (IEA, 2019), 8. (DNV GL, 2019). 

Note: LCOT, Levelised Cost of Transmission 

5.4. Blending and retrofitting 

Hydrogen can be blended with methane in the natural gas network at limited percentages of 5%-
20%, higher shares of up to 30% are being investigated. However, the latter involves blending 30% 
of locally produced hydrogen into a 840 MW Power plant in Los Angeles, USA as part of an island 
gas network connected as well to underground storage. Blending percentages are case-specific and 
may  enable  decentralised  renewable hydrogen  production  in small amounts  and  local  networks 

46 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Carbon-free steel production: Cost reduction options and usage of existing gas infrastructure 

during a transitional phase. However, when larger volumes of hydrogen need to be transported in 
combination  with  less  natural  gas,  it  makes  more  sense  to  use  the  dedicated  route  as  blending 
becomes less efficient and reduces the energy delivery of the pipeline thus the value of hydrogen 
and might require expensive retrofitting of the pipes. (IEA, 2019)  

The level of blending hydrogen and natural gas is mainly directed by the energy density by volume 
and  the  flow  properties  of  hydrogen.  Though hydrogen  as a gas  is highly compressible,  it is less 
compressible than natural gas and the effect of reduced energy delivery becomes more pronounced 
at  higher  pressures.  Figure  30  shows  the  energy  delivery  of  pipelines,  at  low  and  intermediate 
pressure levels, with increasing levels of hydrogen injection as a percentage of the energy delivery 
of  pure  methane.  In  order  to  manage  the  reduced  energy  delivery  in  gas  networks,  either  peak 
energy demand would need to be reduced, or higher flowrates would be needed. This would lead 
to pressure drops which in turn requires higher, more costly compression infrastructure. (Quarton, 
2018) 

Figure 30. Effect of hydrogen blend level on the energy delivery of gas pipelines 

Source: (Quarton, 2018) 

According to the (European Commision, 2020) Hydrogen Strategy report, blending might degrade 
the quality of the gas consumed and the variety of end-user gas applications such as in the European 
steel sector. Both the design of the infrastructure and interoperability between the Member States 
might  be  affected.  This  might  lead  to  the  fragmentation  of  the  internal  market  when  different 
standards of blending and transport of mixed hydrogen and natural gas are accepted by Member 
States. It is recommended to investigate the technical feasibility of different blending scenarios and 
their  related costs  to  get  a  better  view  of  the  risks  involved.  This  will  most  likely  lead to  revising 
applicable standards and regulations in each Member State as well as the European Committee for 
Standardisation (CEN).  

Important  to  highlight  is  the  effect  of  blending  on  the  carbon  content.  Since  Hydrogen  has  a 
volumetric  energy  density  three  times  larger  than natural  gas,  the  effect  of  e.g.  blending  10%  of 
hydrogen will lead to a limited carbon emission reduction of only 3%. 

Safety hazards related to hydrogen blending can range from hydrogen leakage in confined spaces 
to  explosions  which  have  been  described  in  studies  and  are  limited  to  cases  of  low  %  blending 

47 

 
 
 
STOA | Panel for the Future of Science and Technology  

(under 20%). They increase substantially, however, when more than 50% of hydrogen is mixed in 
the  natural  gas  network.  When  commissioning  a  100%  dedicated  hydrogen  infrastructure,  it  is 
assumed that appropriate safety measures have been taken into account by design. (Melaina M.W, 
2010) 

An initiative started by the largest natural gas pipeline operator in Europe, Snam in Italy in 2019, 
investigates blending hydrogen into a transmission network in Europe. 5% of hydrogen was added 
and delivered to a pasta factory and a mineral water bottle company as fuel for heat. In a second 
stage,  the  percentage  of  hydrogen  was  increased  to  10%.  “If  the  gas  flows  continuously  at  a 
predefined  pressure,  the  pipeline  under  testing  could  deliver  0.63  MMT  of  hydrogen  per  year, 
equivalent to 1% of deliberately produced hydrogen in 2018.” These types of projects prove that it 
is possible, to introduce hydrogen in an isolated part of the natural gas grid, under certain conditions 
(BNEF, SNAM, IGU, 2020). However, making forecasts of a pan-European blended hydrogen rollout 
based on this example is another level. It would require a complete end-to-end approach, where all 
the components of the grid and its users, including regulatory bodies, will have to be involved. 

5.5. Storage of hydrogen 

Increasing  volumes  of  hydrogen  coming  from  variable  renewable  energy  sources  will  not  be 
available at constant rates. Due to the intermittent nature of solar PV and wind, storage capacity is 
needed to deal with hourly, daily, and seasonal fluctuations. Depending on the scale of consumption 
in various sectors of the hydrogen value chain, a matching storage capacity applies. In the natural 
gas market, storage in Europe and Ukraine have proven to be essential for balancing the LNG market 
in the past. Similarities can be made for a hydrogen-based grid (BNEF, SNAM, IGU, 2020).  

For low volumes of hydrogen applications, hydrogen can be stored in tanks with high discharge 
rates and efficiencies. When compressing hydrogen at 700 bars, the energy density is only 15% of 
gasoline. Meaning, hydrogen tanks will have to be more than 6 times larger. (IEA, 2019) Likewise, 
with shipping, besides liquefying hydrogen and very low temperature, hydrogen can be converted 
to other molecules and stored in tanks, at certain costs and energy losses. Large scale applications 
of hydrogen, such as industrial clusters and transport overseas, require different storage techniques. 
Prior to loading a ship with hydrogen, storage might be needed to bridge short periods while the 
ship  prepares.  Long  duration  storage  facilities  are  required  to  overcome  seasonal  shortage  if 
hydrogen were to be used as feedstock supply or heat demand to provide continuous operations 
for industries. Finally, the geographical spread of hydrogen production, transport, storage, and use 
will also play an important factor in the design of adequate storage facilities across the EU. 

Besides storing hydrogen underground or in tanks, the pipelines used for transport act as storage. 
Depending on the pressure, the diameter of the pipes, and the length of the network, large amounts 
of hydrogen are stored. Example: 2 000 km pipeline at 100 bars of pressure with a width of 35 inches 
can store approximately 130 GWh of hydrogen, assuming constant flow rates. However, these are 
ideal conditions. In reality, hydrogen will most likely be produced decentral across the EU at different 
pressures and flow rates resulting in fluctuating storage across the grid. 

5.5.1. Storage in tanks 
Pressurised tanks are the most cost-efficient and available technology for storing limited amounts 
of  hydrogen,  up  to  1  100  kg  (33.6  MWh).  These  types  of  tanks  are  commonly  used  across  the 
hydrogen  value  chain  and  can  be  sized  and  strengthened  relatively  easily.  Storing  liquefied 
hydrogen in a tank reduces the volume but is more complex and costlier due to the energy required 
for the conversion from gas to liquid state at very low temperatures (-252.9 °C). This method, also 
called cryogenic storage, consists out of cooling down the gas to at least -239.96 °C and compressing 
it in several steps. In the first step, pure hydrogen gas is compressed. This causes the temperature of 
the hydrogen gas to rise. Next, the hot gas is passed through two heat exchangers and mixed to be 

48 

Carbon-free steel production: Cost reduction options and usage of existing gas infrastructure 

passed through a tank containing liquid nitrogen. In the last step, the cooled gas is passed through 
another heat exchanger  to  reach  its  final  temperature.  The entire  liquefaction  process consumes 
about 30% of the energy in compressors and coolers, which is available in the hydrogen. 

5.5.2. Underground storage 
Storing large volumes of hydrogen requires larges deposits as it takes more than three times more 
space than natural gas for the same amount of energy. The main difference between storing natural 
gas underground is its purpose of providing long-term security of supply whereas, in the case of 
hydrogen, it serves as a solution for short to mid-term energy balancing. Depleted gas or oil fields 
on land or at sea, excavated rock caverns, aquifers (or pore storage) and salt caverns are the most 
common geological storage locations for storing gases. Salt caverns have the lowest total cost due 
to their natural behaviour of trapping gas effectively, are strong and do not degrade easily over time. 
What salt caverns lack in storage capacity compared to an empty oil or gas field, is compensated by 
increased  flexibility  to  deliver.  The  simple and  robust  design  of  these  caverns  makes  them  more 
reliable  for  rapid  filling  and  withdrawing,  which  is  a  favourable  property  in  an  intermittent 
renewable energy world. Depleted gas or oil reservoirs and aquifers require more careful analysis 
and preparation to make sure proper locking mechanisms are in place to prevent gas leaks. Besides 
gas volume losses through cracks in the structure, special care has to be taken into account when 
repurposing depleted gas fields, caverns or aquifers for storing hydrogen in pure or blended form. 
Corrosion  and  weaknesses  in  the  sealings  of  the  borehole  can  occur  due  to  the  formation  of 
hydrogen sulphide which is caused by microbiological reactions within the aquifer. Bacterial growth 
can lead to further volume losses. A study run for the Netherlands Enterprise Agency dives deeper 
into the risks of storing hydrogen underground. (DBI Gas- und Umwelttechnik GMBH, 2017)  

Figure 31 indicates the availability of various geological storage areas across Europe. Although there 
is  no  accurate  number  available  to  indicate  the  storage  capacity  available,  some  countries  are 
investigating their potential. Germany, for example, has an estimated capacity of 9.1 billion m3 of 
pore  storage and  17.6  billion  m3  of cavern storage  in  the north  of  the  country.  This  would  cover 
storing the entire natural gas consumption of Germany for three months (Siemens Energy, 2020). In 
the  north  of  the  Netherlands,  the  Hystock  project  is  planning  to  demonstrate  the  production  of 
hydrogen and storage in depleted gas fields.  

49 

 
 
 
 
 
 
 
 
 
STOA | Panel for the Future of Science and Technology  

Figure 31. Underground salt deposits and cavern fields in Europe 

Source: (Blanco, 2018) 

50 

 
 
 
 
 
 
Carbon-free steel production: Cost reduction options and usage of existing gas infrastructure 

5.5.3. Storage cost 
Table 6. Costs for hydrogen storage 

Investment Costs 

Technology 

Range (2019) 

Comment 

Source 

Depleted gas field  

€280 - 424 /MWh H2 
stored 

CAPEX including compressors and pipes, 4% 
OPEX.  

Salt caverns  

€344 /MWh H2 
stored  

CAPEX for 1,160 t of working capacity (+1/3 
additional for cushion gas), but highly 
dependent on geography. 4% OPEX, includes 
compressors and pumps. 

Rock caverns  

€1 232 /MWh H2 
stored  

4% OPEX.  

Levelised Cost of Storage 

Technology 

Range (2019) 

Comment 

Tank 

€0.17 kg H2 

Compressed state hydrogen at 5 – 1 100kg per 
container 

€4.1 kg H2 

Liquid state hydrogen at 0.18 - 4 500t H2 per 
tank 

[1] 

[1] 

[1] 

Source 

[1] 

Depleted gas field  

€51 - 76 /MWh H2  

Salt caverns  

€6 - 26 /MWh H2  

Rock caverns 

€17 /MWh H2  
€19 - 104 /MWh 
H2  

Sources: 1. (BNEF, 2019), 2. (IEA, 2019) 

Cost for working gas capacity, 1 cycle/year. 
Including the cost of compression and 
pipelines needed for the facility to 
function.  
300-10,000 t per cavern, lower bound: 
monthly cycling, upper value: bi-annual 
cycling.  
300-2,500 t per cavern, lower bound: 
monthly cycling, upper bound: bi-annual 
cycling.  

[1] 

[1] 

[2] 

[1] 

5.6. Alternative transport and storage methods 

Besides the main principle of transport and storing routes of hydrogen described in the previous 
chapters, several other means and technologies could become interesting in a specific context. 

5.6.1. Sponge iron 
In the production of Direct Reduced Iron, sponge iron is the output product of the reduction of iron 
ore with natural gas. In emerging technologies, reducing iron ore with hydrogen is tested. In both 
cases, hydrogen is stored during the reduction process. The sponge iron can be reacted in a later 
stage with steam to extract the hydrogen, which can be used for other purposes, and iron ore.  

Another  approach  is  to  ship  H-DRI  sponge  hydrogen  instead  of  the  green  hydrogen  or  carrier 
molecules. This way, the sponge iron can be produced close to low-cost green hydrogen locations 

51 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
STOA | Panel for the Future of Science and Technology  

and shipped to the location where the EAF further processes the sponge iron into steel and steel 
finishing, potentially at a lower cost and less complexity. Figure 32 shows a possible route in a study 
done for the Australian steel sector. 

Figure 32. Possible routes for steel making instead of hydrogen shipping 

Source: (Grattan Institute, 2020) 

Note: The semi-finished product sponge iron, produced close to green hydrogen production, is shipped 

5.6.2. Metal hydrides 
Metal hydrides create chemical hydrogen bonds with other elements and can store hydrogen up to 
6%.  At  low  pressure,  these  hydrides  absorb  hydrogen  which  can  be  released  at  a  later  point  by 
applying  heat.  There  is  a  large  range  of  elements  and  alloys  that  can  be  used.  Though  a  few 
percentages of hydrogen can be captured, the effect in volume is significant. Shipping these metal 
hydrides requires special vessels that keep the atmospheric and temperature conditions stable. 

5.7.  Geographical hot spots 

The development of the hydrogen pipeline infrastructure across Europe has two main drivers. On 
one hand, the location of the production sites within Europe and the shipping terminals to handle 
with  hydrogen  carriers  (e.g.:  ammonia,  methanol,  methane,  LOHC)  and  on  the  other  hand,  the 
locations  of  the  consumption,  which are  likely  to  initially  be highly  concentrated industrial  hubs 
(chemical clusters, steel sector, manufacturing sectors) or major consumers. Hence, the transport 
distances will play a decisive role while prioritising the construction of one pipeline over another to 
connect two different points of the future hydrogen network.  

In case hydrogen carriers are used during shipping, they will have to be converted back to hydrogen 
at or close to the port before being transported via the hydrogen backbone. Ammonia, for example, 
causes  stress  corrosion  in  steel  and  requires  specific  infrastructure  and  handling,  different  from 
hydrogen or methane. Moreover, industrial takers of hydrogen would be burdened by having to 
invest in reconversion facilities. 

The  future  hydrogen  backbone  for  Europe  needs  to  be  carefully  planned  since  the  transport  of 
hydrogen  implies  challenges  such  as  safety,  pressure,  and  the  techno-economic  challenges  of 

52 

 
 
 
Carbon-free steel production: Cost reduction options and usage of existing gas infrastructure 

repurposing the existing natural gas (as was addressed in section 5.3). The existing gas grid currently 
reaches  the  main  industrial  hubs,  which  will  be  most  likely  the  initial  hydrogen  valleys.  Then, 
leveraging on this already deployed infrastructure might reduce costs and ease the planning of the 
hydrogen backbone. It is relevant to take into account the development of larger-scale hydrogen 
storage facilities and the parallel development of a CO2 infrastructure to enable CCU or CCS, which 
is expected to have an important role in the decarbonisation of Europe. However, there is also the 
need for policies that boost the creation of these hydrogen valleys in the current locations -which in 
most cases have also a privileged geographical location concerning the complete value chain- and 
the creation of new geographical hot sports to facilitate the development of hydrogen pipelines and 
large-scale storage facilities.  

53 

 
STOA | Panel for the Future of Science and Technology  

6. Conclusions 

The iron and steel sector is one of the most challenging sectors to decarbonise among the energy-
intensive  industries  in  Europe,  while  at  the  same  time  being  one  of  the  pillars  of  the  European 
industry  and  job  market.  In  Europe  the  production  of  crude  steel  is  currently  at  around  157  Mt, 
accounting for 4 % of GHG emissions. 

Approximately 60 % (94 Mt) of total European steel production originates from the coal-based blast 
furnace/basic oxygen furnace (BF/BOF) route and is more suitable for the hydrogen direct reduction 
route  (H-DRI).  The  authors  of  this  study  estimate  that  94  Mt  of  'green  steel'  would  require 
approximately 37-60 GW of electrolyser capacity, producing approximately 6.6 Mt of hydrogen per 
year. As a reference, the EU hydrogen strategy aims to have 40 GW of electrolyser capacity installed 
within the EU by 2030. The authors estimate that these electrolysers would consume approximately 
296 TWh of green electricity per year; as a reference, Germany produced in total 176 TWh of green 
electricity in 2020. 

Currently,  the  existing  hydrogen  transport  infrastructure  is  one  of  the  main  bottlenecks  in  the 
transition to sustainable hydrogen use in the EU, where  there are roughly 2 000 km of dedicated 
hydrogen  pipelines  located  in  four  Member  States,  compared  with approximately  260 000  km  of 
natural  gas  pipelines.  EU  gas  transmission  owners  are  conducting  studies  and  tests  on  which 
components of their infrastructure can be reused for transporting hydrogen. A most likely approach 
will be the creation of so-called hydrogen valleys to serve and connect regions of energy-intensive 
industrial  clusters  or  the  Europe  Hydrogen  Backbone  initiative  aiming  in  the  first  phase  to  have 
6 800 km  of hydrogen  pipelines available  by  2030  and  23  000 km  by  2040,  of  which  75 %  would 
consist  of  reused  natural-gas  pipelines.  Most  of  the  upgrades  will  involve  compressor  stations, 
valves, fittings, metering stations and storage tanks. 

The transformation of the iron and steel sector has to be viewed in a broader context. Other energy-
intensive  sectors  face  similar  challenges,  albeit  with  different  possible  technology  pathways. 
Therefore,  an  integrated  approach  to  evaluating  the  potential  decarbonisation  pathways  for  all 
European  industries  is  required,  also  looking  at  the  real  potential  of  industrial  symbiosis 
opportunities, such as exchange and re-use of heat and products between industrial installations. 
This broad understanding of mid-term (2030) and long-term (2050) industrial energy and material 
needs can then be integrated in energy system analysis tools covering all sectors of the economy. 

industrial 
Here,  the  authors'  team  would  also  refer  to  the  AidRES  project  –  advancing 
decarbonisation by assessing the future use of renewable energies in industrial processes,25 which 
was launched in January 2021 and which will create a database for the main EIIs in Europe, including 
current and future energy and feedstock needs, and map out renewable energy needs in high spatial 
resolution. 

25 Aid RES – Advancing industrial decarbonisation by assessing the future use of renewable energies in industrial processes, 
NUMBER –ENER/2020/OP/0011-C2/SER/2019-569/SI2.840687, (Pilot Project No. 32027714 of the European Parliament)  - 
Project Officer: Eric Lecomte (DG ENER), Consortium Project Manager: Frank Meinke-Hubeny (Vito) 

54 

 
 
 
Carbon-free steel production: Cost reduction options and usage of existing gas infrastructure 

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STOA | Panel for the Future of Science and Technology  

Annex: Techno-economic assumptions 

Parameter 

Unit 

2020 

2030 

2050 

Source 

Biomass 

M€/PJ 

7.99 

8.42 

9.69 

Coal 

€/t 

26.9 

18.4 

18.1 

Electricity 

€/MWh 

58 

Hydrogen 

€/kgH2 

4 

66 

3.1 

46 

1.1 

Heat Roadmap Europe 

(European Commission, 2017) 

IEA-The Future of Hydrogen 

(IEA, 2019) 

VITO NV 

BNEF 

(BNEF, SNAM, IGU, 2020) 

Lime 

€/t 

62.5 

62.5 

62.5 

European Lime association website 

Natural Gas 

€/MWh 

24.8 

27.1 

26.8 

IEA-The Future of Hydrogen 

(IEA, 2019) 

Steel scrap 

CO2 Price (EU 

ETS) 

Iron Ore 

CCS 

€/t 

€/t 

€/t 

€/t 

220 

220 

220 

(MEPS ltd, 2020) 

25 

84 

160 

IEA Energy outlook 

145 

85 

145 

85 

145 

85 

(Trading Economics, 2020) 

(Toktarova, et al., 2020) 

Electrolyser 

€/kWe 

450 

208 

144 

Hydrogen import coalition and 

Hydrogen Europe 

Hydrogen generation in Europe 

(European Commission , 2020) 

M€/km 

1.61 

1.61 

1.61 

h/yr 

8 000 

% 

64% 

67% 

74% 

h 

80 000 

80 000 

90 000 

Hydrogen generation in Europe 

(European Commission , 2020) 

Hydrogen generation in Europe 

(European Commission , 2020) 

Short distance 

pipeline 

Operating 

hours 

Electrolyser 

efficiency 

Electrolyser 

lifetime 

Stack cost (% 

CAPEX) 

Discount Rate 

% 

% 

40% 

5.40% 

58 

 
 
 
 
 
(green  and  blue)  to 

The steel sector is one of the most challenging sectors 
to  decarbonise  and  has  recently  received  special 
attention  owing  to  the  potential  use  of  low-carbon 
fuel 
hydrogen 
combustion and process-related carbon emissions. This 
report  addresses  concerns  that  might  arise  while 
evaluating  the  potential  and  limitations  of  the  future 
role  of  hydrogen  in  decarbonising  the  iron  and  steel 
industries. 

reduce 

its 

Q
A
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0
2
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2
1
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3
0
2
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E
N
N

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The  report  provides  a  comprehensive  overview  of 
current  technical knowledge,  (pilot)  projects  and  road 
maps  at  national  and  EU  level.  This  information  is 
supplemented by previously published indicative price 
projections for the various steel production routes and 
a long-term study, analysing the evolution of the global 
steel sector up until 2100. 

This is a publication of the Scientific Foresight Unit (STOA) 
EPRS | European Parliamentary Research Service 

This document is prepared for, and addressed to, the Members and staff of the European 
Parliament as background material to assist them in their parliamentary work. The content of 
the document is the sole responsibility of its author(s) and any opinions expressed herein should 
not be taken to represent an official position of the Parliament. 

ISBN 978-92-846-7891-4 | doi: 10.2861/01969 | QA-02-21-302-EN-N