Sectorial integration : long-term perspective in the EU energy system.
Date: 2020-11-04
Institutions: Directorate-General for Energy
Subjects: business model, clean technology, energy efficiency, energy grid, greenhouse gas, hydrogen, price of energy, reduction of gas emissions, renewable energy, simulation, technical standard

ASSET Study on 

Sectoral integration: 
long-term perspective in the  
EU energy system 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

AUTHORS  

Alessia De Vita (E3 Modelling) 

Pantelis Capros (E3 Modelling) 

Stavroula Evangelopoulou (E3 Modelling) 

Maria Kannavou (E3 Modelling) 

Pelopidas Siskos (E3 Modelling) 

Georgios Zazias (E3 Modelling) 

Sil Boeve (Ecofys) 

Marian Bons (Ecofys) 

Rob Winkel (Ecofys) 

Jan Cihlar (Ecofys) 

Louise De Vos (Tractebel) 

Niels Leemput (Tractebel) 

Pavla Mandatova (Tractebel) 

EUROPEAN COMMISSION 

Directorate-General for Energy 
Contact: Tudor Constantinescu 

E-mail:  ENER-SECRETARIAT@ec.europa.eu 

European Commission 
B-1049 Brussels 

January 2018  I  2 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

Legal Notice 
This document has been prepared for the European Commission. However, it reflects 
the views only of the authors, and the Commission cannot be held responsible for any 
use which may be made of the information contained therein. More information on the 
European Union is available on the Internet (http://www.europa.eu). 

Luxembourg: Publications Office of the European Union, 2020 

© European Union, 2020  

The reuse policy of European Commission documents is implemented by the 
Commission Decision 2011/833/EU of 12 December 2011 on the reuse of Commission 
documents (OJ L 330, 14.12.2011, p. 39). Except otherwise noted, the reuse of this 
document is authorised under a Creative Commons Attribution 4.0 International (CC-
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PDF ISBN 978-92-76-24729-6 doi: 10.2833/347937 MJ-01-20-652-EN-N 

January 2018  I  3 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

About ASSET 
ASSET (Advanced System Studies for Energy Transition) is an EU funded project, which 
aims  at providing  studies  in  support  to  EU  policymaking,  including  for  research  and 
innovation.  Topics  of  the  studies  will  include  aspects  such  as  consumers,  demand-
response,  smart meters, smart grids, storage,  etc., not  only in terms  of technologies 
but also in terms of regulations, market design and business models. Connections with 
other  networks  such  as  gas  (e.g.  security  of  supply)  and  heat  (e.g.  district  heating, 
heating and cooling) as well as synergies between these networks are among the topics 
to study. The rest of the effort will deal with heating and cooling, energy efficiency in 
houses,  buildings  and  cities  and  associated  smart  energy  systems,  as  well  as  use  of 
biomass  for  energy  applications,  etc.  Foresight  of  the  EU  energy  system  at  horizons 
2030, 2050 can also be of interests. 

The  ASSET  project  will  run  for  36  months  (2017-2019)  and  is  implemented  by  a 
Consortium led by Tractebel with Ecofys and E3-Modelling as partners. 

Disclaimer 
The study is carried out for the European Commission and expresses the opinion of the 
organisation having undertaken them. To this end, it does not reflect the views of the 
European Commission, TSOs, project promoters and other stakeholders involved. The 
European Commission does not guarantee the accuracy of the information given in the 
study, nor does it accept responsibility for any use made thereof. 

Authors 
This  study  has  been  developed  as  part  of  the  ASSET  project  by  a  consortium  of  E3 
Modelling, Ecofys and Tractebel. 

Authoring 
team: 

Alessia  De  Vita,  Pantelis  Capros,  Stavroula  Evangelopoulou,  Maria 
Kannavou, Pelopidas Siskos, Georgios Zazias (E3 Modelling) 

Sil Boeve, Marian Bons, Rob Winkel, Jan Cihlar (Ecofys) 

Louise De Vos, Niels Leemput, Pavla Mandatova (Tractebel) 

January 2018  I  4 

 
 
 
 
 
 
 
 
 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

Executive summary 
Within  the  Paris  Agreement,  the  European  Union  (EU)  has  committed  to  limit 
greenhouse gases (GHG) emissions to levels as low as needed to stay well below a 2°C 
rise in average global temperature compared to pre-industrial levels. Global emissions 
must reduce radically to achieve this goal. Within a world effort-sharing allocation, it is 
likely that OECD countries will need to limit energy-related emissions at a level close to 
zero shortly after 2050. 

The EU is close to full adoption of an Energy Union policy package that aims at achieving 
ambitious  targets  for  GHG  emission  reductions,  renewables  and  energy  efficiency,  in 
2030.  Mostly  sectoral  policy  measures  (efficiency  policies,  standards,  renewables 
support, including biofuels), as well as carbon pricing within the ETS, acting as the main 
price signal for the sectors subject to ETS obligations, are the drivers of the transition. 
The 2030 targets have been defined by the EU to be compatible with the 2050 emissions 
reductions targets that are part of the EU’s pledges for the long term. 

This  study  analyses  the  importance  of  sectoral  integration  to  achieve  the  long-term 
clean  energy  transition,  to  achieve  the  emission  reduction  pledges  for  2050,  and 
furthermore to reach close to zero CO2  emissions in the energy  system after 2050 in 
the EU. Sectoral integration involves combined actions towards low carbon transition in 
more than one sector, aiming at exploiting synergies between them.  

The Energy Union policy and legal initiatives  adopted  over the past two years mostly 
focus on sectoral measures: measures for energy efficiency for the buildings sector, car 
standards and other measures for low emissions mobility, promotion of best techniques 
in industry and facilitation of renewables in various sectors. The ETS is a measure, which 
is multi-sectoral, as is the energy efficiency obligation that is a crucial element of the 
Energy  Efficiency  Directive.  The  main  sectoral  integration  mechanism  created  by  the 
proposed measures is the increase in the use of electricity in transport and heating and 
this,  while  power  generation  decarbonises,  leads  to  emissions  reductions,  as  well  as, 
gains in energy efficiency. The development of advanced biofuels also requires sectoral 
integration as the profound reorganisation is needed in the  refining sector to provide 
such fuels for the transport sector, as well as profound beyond the energy sector in the 
agricultural sector.  

The  scenario  quantifications  that  underpinned  the  Energy  Union  initiatives  for  2030 
(using  the  PRIMES  energy  systems  model)  show  that  there  are  significant  remaining 
emissions  primarily  in  mobility,  but  also  in  the  domestic  (residential,  services  and 
agriculture) and industrial sectors in 2050, which are difficult to abate fully. It might be 
necessary  to  enlarge  the  sectoral  measures  and  enhance  sectoral  integration,  to 
eliminate  the  remaining  emissions.  Enhancing  sectoral  integration  without  heavily 
influencing consumption patterns implies going beyond the role of electricity as a clean 
energy carrier, by considering inclusion of hydrogen in various roles - be it intermediate 
(as feedstock  for the production  of other  energy carriers)  or as of direct use  - in the 
energy system under transition.  

Hydrogen scenarios definition 
Hydrogen is used today in industry as a feedstock, for non-energy purposes, mostly in 
the chemical and petrochemical sectors. The future role of hydrogen could be far broader 
and may be fundamental in the energy system transition.  

This  study  explores  three  stylized  strategies  and  a  balanced  pathway  for  sectoral 
integration based on hydrogen, going beyond the main decarbonisation used to support 
the Energy Union proposals. The study focuses first on three stylised strategies that are 
defined as follows:  

January 2018  I  5 

 
 
 
Sectoral integration: long-term perspective in the EU energy system 

(A) 
secondarily as a provider of electricity storage 

Hydrogen as a carbon-free energy carrier in all consumption sectors, and 

(B) 
hydrocarbons, and as a provider of electricity storage 

Hydrogen as a feedstock for the production of carbon-free gas and liquid 

(C) 
acting as the main carbon-free carrier in the energy consumption sectors. 

Hydrogen serving mainly as versatile power storage to support electricity 

All the strategies above place a central role to hydrogen, but each one emphasises on 
one particular pathway for using hydrogen. 

All  three  strategies  require  the  production  of  hydrogen  from  carbon-free  electricity 
produced through electrolysis, and then to process hydrogen and CO2 through additional 
steps, which are strategy specific. The production of hydrogen from natural gas steam 
methane reformer is not compatible with the decarbonisation aims unless combined with 
CCS technologies for the permanent storage of CO2 emissions. However, the value chain 
of  steam  reforming  with  CCS  is  likely  to  be  significantly  less  competitive  than  an 
electrolysis-based value chain benefitting from large economies of scale. Some of the 
technologies  required in the stylized strategies  are not yet market mature,  and while 
there  is  a  high  potential  for  development,  considerable  uncertainties  surround  their 
future  performance  regarding  costs,  efficiency  and  the  timing  of  readiness.  The  CO2 
used  as  feedstock  in  these  strategies  is  mainly  captured  from  the  air,  however  other 
carbon-neutral sources could co-exist. 

It is important to emphasise that the hydrogen-based sectoral integration strategy acts 
on top of the options included in the basic decarbonisation context. In other words, the 
following elements of the basic decarbonisation strategy are indispensable (otherwise 
the hydrogen-based strategy is not sustainable).  A basic decarbonisation strategy, as 
envisaged in the Energy Union initiatives, includes four key elements : maximum energy 
efficiency for buildings, transport and the industrial sectors; high share of renewables 
in the energy system, particularly for power generation; electrification of mobility and 
stationary energy end-uses, where applicable, through battery electric vehicles and heat 
pumps;  production  of  advanced  biofuels,  mainly  for  aviation  and  shipping  purposes. 
These elements are the essential building blocks of a decarbonisation strategy, which 
should achieve the bulk of emission reductions in the energy system.  

Strategy A requires the development of end-use technologies using hydrogen directly, 
including  fuel  cells  in  stationary  and  mobile  energy  uses,  and  equipment  combusting 
hydrogen  directly.  Because  of  the  widespread  use  of  hydrogen  in  Strategy  A,  the 
development of a fully-fledged hydrogen distribution system is necessary.  

Strategy B requires the development of power-to-gas and power-to-liquid technologies 
to substitute the remaining fossil fuels in the long-term.  

In both strategies A and B, hydrogen and clean hydrocarbons are also providing power 
storage services.  

Strategy  C  gives  priority  to  maximum  electrification  in  all  sectors  and  uses  hydrogen 
mainly for power storage.  

The three strategies are contrasted to each other to help understand the respective pros 
and cons of different hydrogen applications.  

Based  on  the  assessment  of  the  three  stylized  strategies,  the  study  quantified  a 
balanced  sectoral  integration  scenario  that  combines  elements  of  all  three 
strategies. The balanced scenario includes the development of hydrogen use as an end-
use fuel, a feedstock and a power storage option, in specific market segments where 
hydrogen  can  achieve  a  competitive  advantage  in  the  future.  The  balanced  scenario 
achieves deeper  emissions  reductions in the  energy sector by  2050 than in the basic 

January 2018  I  6 

 
 
 
Sectoral integration: long-term perspective in the EU energy system 

decarbonisation  scenario,  as  by  assumption  it  includes  a  strong  techno-economic 
development of hydrogen-related technologies.  

Finally,  the  study  also  quantified  a  sensitivity  analysis  on  the  balanced  scenario 
assuming less optimistic development of hydrogen technology costs. 

The main lessons from the analysis  

Key technologies and business models 

Following a bottom-up technical approach, the study provides an overview of different 
hydrogen-related  and  power-to  hydrogen  technologies  and  assesses  the  market 
potential  for  carbon-free  hydrogen.  The  analysis  identifies  market  and  non-market 
barriers  to  deploy  carbon-free  hydrogen  for  different  applications  successfully.  The 
electricity  price  is  among  the  key  factors  that  will  affect  the  production  costs  of 
hydrogen. On the other hand, the availability of hydrogen for the power system allows 
considerable smoothing of the load variations thanks to the chemical storage services 
enabled by hydrogen and hence allows exploiting the renewable resources at maximum, 
without curtailment. The resulting system can further benefit from economies of scale 
both in power generation and in electrolysis as the renewable sources may diversify to 
minimise variability. The analysis confirms that in the future the power system can offer 
competitive  prices,  even  slightly  lower  than  in  the  basic  decarbonisation  scenario, 
despite the considerable increase in the volume of electricity generated.  

Regarding deployment across the sectors, the study looks first at mobility. By comparing 
the technical options and the potentials to decarbonise mobility through hydrogen fuel-
cells  and  battery-based  electricity,  the  analysis  considers  that  there  will  be  market 
segments  for  both  technological  options  to  succeed  depending  on  their  relative 
competitiveness and strengths in each market segment. For instance, the dominance of 
electric vehicles in all road transport segments is hindered by range limitations that limit 
the use of batteries for long-distant trips. 

The study also focuses on the use of hydrogen in heavy industry for energy purposes 
(combustion),  beyond  the  non-energy  uses  where  hydrogen  currently  has  an 
established  market.  In  high-temperature  applications  in  industry,  fuel  cells  are  not 
appropriate  but  instead  direct  injection  of  hydrogen  in  furnaces,  as  in  the  iron-  and 
steel-making  direct  injection  technologies  is  a  valid  use  of  hydrogen  both  from  a 
technical and economic perspective in the context of an emission reductions strategy. 

Furthermore, in low- and medium-enthalpy uses of heat in industry, fuel cells are also 
applicable, and they may compete against electric heat pumps in the future if the former 
becomes  less  expensive.  Even  though  significant  advancements  in  heat  pumps  are 
possible in the future, there still exist low enthalpy uses in industry that is technically 
difficult to supply solely by heat pumps. Similarly, fuel cells and heat pumps compete in 
the buildings sector, where the small scales favour the latter. A fuel cell application in 
buildings is expensive and requires complex management, as well as heat or electricity 
storage. Therefore, the heat pumps have a competitive advantage in this sector.  

In case of large-scale, direct use of hydrogen in the residential and services sectors and 
industry,  a  fully-fledged  distribution  system  would  have  to  develop  in  the  long-term. 
Adaptation of existing natural gas distribution infrastructure is technically possible, but 
the business undertaking of such enormous infrastructure investment is difficult.  

The  use  of  hydrogen  to  absorb  excess  renewable  electricity  production  in  the  power 
sector and thus penetrate in specific markets in the same geographic area is a concrete 
business case, which is feasible for the private sector to undertake in the early stages 
of  the  transition.  The  study  has  identified  such  cases  to  provide  information  on  key 
regions that today already have excess electricity generation.  

January 2018  I  7 

 
 
 
Sectoral integration: long-term perspective in the EU energy system 

Electrolysis is the key technology to produce carbon-free hydrogen and is necessary for 
all  strategies.  Alkaline  water  electrolysis  and  the  rapidly  improving  PEM  (proton 
exchange membrane) electrolysers are at a sufficient technology readiness level (TRL). 
Very significant cost reductions are possible if electrolysers develop at a large scale. The 
SOEC (solid oxide electrolyser cell) technology is currently at a low TRL but may become 
a promising technology in the chain producing liquid hydrocarbons from hydrogen and 
CO2 in the future.  

Storage  of  hydrogen  at  a  large-scale,  for  example  in  natural  caverns,  will  have  to 
accompany  the  development  of  large-scale  distribution  systems  in  the  context  of  a 
strategy  where  hydrogen  becomes  a  universal  energy  carrier.  Smaller  scale  storage 
systems,  for  example,  pressurised  tanks  and  tubes  storing  liquefied  hydrogen,  are 
appropriate for small- and medium- scale applications, such as in industrial areas and 
in large-scale stations refuelling hydrogen. Small-scale storage systems could develop 
in the early stages of the transition to facilitate the development of small and medium 
scale specific uses of hydrogen, especially in the transport sector and in industry. 

Two  possible  business  models  exist  for  hydrogen:  decentralised  hydrogen  production 
close to end-users or centralised hydrogen production. For the transition period and in 
view  of  using  hydrogen  as  an  energy  carrier,  decentralised  hydrogen  production  is  a 
valid  option  for  private  investment.  However,  it  is  currently  uncertain  whether 
electrolysis  at  the  scale  of  refuelling  stations  or  in  industrial  areas  is  more  economic 
than  the  distribution  of  hydrogen  to  the  refuelling  stations  using  tanks  or  tubes. 
However,  the  centralised  option  would  probably  be  the  preferred  option  for  the 
production of hydrogen in the long-term because the industry expects large economies 
of scale for large-scale electrolysis. 

Any business model  - to be  successful in the long term  -  requires the entire  chain of 
users, producers and infrastructure to be available in a timely manner. In reality, market 
coordination  failures  may  occur  in  such  circumstances.  To  this  respect,  decentralised 
production in the initial expansion phase is less vulnerable. But for the development at 
hydrogen  availability  scales  as  envisaged  in  the  strategies,  successful  market 
coordination is essential. Coordination applies to infrastructure developers, technology 
and research providers, upstream hydrogen producers and end-use consumers. As the 
actors have different aspirations, long-term anticipation and regulatory certainty are of 
utmost importance for market coordination.  

Pros and cons of the respective strategies 

Strategy A explores the use of hydrogen as an energy carrier for the entire system and 
in most end-use sectors directly. In road transport, the use of hydrogen may eliminate 
range limitations that electric powertrains currently have and has an easier application 
than electricity to several of the transport modes. However, the strategy requires the 
development of new hydrogen transport and distribution infrastructure for all sectors, 
which  would  replace  the  gas  system.  The  implementation  may  be  difficult.  However, 
some  recent studies envisage ways of accommodating the gas grids  effectively. Both 
centralised  and  decentralised  production  of  hydrogen  can  co-exist  as  valid  business 
models  in  this  context.  Centralised  production  in  large  electrolysers  can  produce 
hydrogen  at  competitive  prices  to  feed  the  distribution  infrastructure  of  pipelines. 
Smaller-scale decentralised production in refuelling stations can co-exist. The strategy 
A  also  requires  the  development  of  large-scale  hydrogen  storage  facilities.  In  an 
intermediate phase, the hydrogen could be blended (up to 15%) in the gas grid to take 
advantage  of  the  natural  gas  infrastructure  and  ensure  a  more  gradual  transition. 
However,  in  the  long-term,  the  grid  should  be  adapted  to  hydrogen.  The  end-use 
equipment  has  to  be  converted  for  hydrogen  burning  (for  mixtures  beyond  the  15% 
blending limit), while industry needs to invest in furnace technologies using hydrogen 
directly.  In  the  mobility  sector  and  power-heat  cogeneration  applications,  the  key 

January 2018  I  8 

 
 
 
Sectoral integration: long-term perspective in the EU energy system 

uncertainty is the cost reduction and development of fuel cells. Market coordination is 
essential to allow such a scenario to develop, as demand, production and infrastructure 
need to develop simultaneously. The modelling shows that Strategy A implies significant 
increases in the volume of electricity generation, to produce hydrogen, but the increase 
is at a rather manageable scale, provided that large-scale interconnections allow access 
to renewable intensive sites across all of Europe. The large-scale production of hydrogen 
allows the provision of electricity storage services through hydrogen, which facilitates 
the large-scale integration of renewables in the power system. The projection assumes 
enhancement of access to remote areas with high renewables potential via high voltage 
interconnections and shows the possibility of further expanding nuclear capacity. 

Strategy B, which explores the use of hydrogen as a feedstock, has the main advantage 
that  end-use  sectors  do  not  require  major  changes  of  equipment  and  infrastructure 
beyond  those  envisaged  in  the  basic  decarbonisation  scenario.  Also,  the  existing 
refuelling  infrastructure  can  continue  to  be  used.  However,  to  be  carbon  free,  the 
scenario requires the development of technologies such as direct carbon capture from 
air, which is still far from reaching market maturity. Further, the scenario requires very 
high  amounts  of  electricity  to  produce  the  clean  hydrocarbons,  and  according  to  the 
modelling projections, producing the clean synthetic fuels at relatively high costs and 
with poor overall energy efficiency is inevitable. The modelling shows that electrification 
of transport, heat pumps and biofuels as projected in the basic decarbonisation scenario 
must be maintained and probably enhanced, to limit the increase in electricity demand 
implied by the production of the synthetic fuels. Otherwise, the huge electricity demand 
would bring the power system to its limits.  

Strategy C explores using hydrogen mainly for power storage: while seeming initially 
less complex than other pathways and requiring the least increase in power generation, 
the strategy would require the full electrification of all end-use sectors to achieve near-
zero emissions. While this can work for the domestic sector, for industry and transport 
it is barely possible. In industry, complete electrification is probably impossible without 
considerable changes in production processes. In transport, extreme solutions such as 
electric aviation and shipping would need to succeed or alternatively massive production 
of fungible biofuels will be necessary for aviation and ships. Electricity is being the single 
energy form for all consumers, which may cause concerns in case of lack of sufficient 
reliability. The power to hydrogen process for storage is the closest to market maturity 
and can be expected to develop without major uncertainties. The modelling shows only 
a  modest  increase  in  demand  of  electricity  compared  to  the  basic  decarbonisation 
scenario,  due  to  the  high  efficiency  of  the  electric  end-use  equipment,  and  a  reliable 
power system operation due to the role of hydrogen as storage.  

All three stylised strategies have the merit to lead to almost full energy independence 
in the EU. They are all affordable regarding total energy system costs, provided that the 
new technologies exploit their learning potential and the infrastructure develops without 
market coordination failures.  

Although  all  three  stylised  strategies  have  specific  advantages  and  allow  for  the 
achievement  of  close  to  zero  CO2  emissions  in  the  energy  system,  they  also  involve 
major uncertainties, notably around technology developments, and market coordination 
across  actors  with  different  aspirations.  In  this  perspective,  the  current  study  simply 
outlines  the  likely  impacts  of  such  stylised  pathways,  while  the  study  is  inconclusive 
about the respective merits and drawbacks. Thus, the study does not recommend one 
of  the  stylised  strategies  but  instead  considers  a  balanced  approach  to  approximate 
cost-effectiveness.  

In such a balanced scenario, the aim to achieve a near full decarbonisation of the energy 
system implies the hydrogen-based sectoral integration combining all possible roles of 
hydrogen in the most promising sectors and at different proportions, . Assuming that in 

January 2018  I  9 

 
 
 
Sectoral integration: long-term perspective in the EU energy system 

the  long  term  hydrogen  technologies  achieve  the  lowest  possible  costs,  a  balanced 
scenario could be one with the following characteristics: 

1. Mix hydrogen up to 15% in the gas distribution grids, together with amounts of 
bio-methane and clean methane (produced from hydrogen and CO2 captured in 
the air); the share of each of the latter reaches between 15-20% in the long-
term; 

2. Use electrolysis-produced hydrogen to feed fuel-cell powertrains in large vehicles 
(trucks, buses, etc.) and long distance travelling cars (including taxis). Hydrogen 
refuelling can benefit from returns to scale as only fuelling hubs are required to 
feed the large vehicles; 

3. Use hydrogen directly in high-temperature furnaces in industry, including in iron 

and steel, the chemical industry and other sectors; 

4. Develop power-to-H2 technologies in the power sector to provide electricity 

storage services at a large-scale, as needed to maximise the use of renewables, 
and produce hydrogen and clean methane used by consumers. 

The  scenario  finds  that  at  the  costs  assumed,  fuel  cell  heavy-duty  vehicles  start 
penetrating the market from 2030 onwards and achieve a considerable market share by 
2050. Battery-charged cars combined with fuel cell powertrains for heavy-duty and large 
mileage travelling vehicles succeed to drop carbon emissions in road transport close to 
zero  by  2050.  Advanced  biofuels  drastically  reduce  carbon  emissions  in  aviation  and 
maritime sectors by 2050. As the focus only on these sectors, the required amounts of 
biofuels by 2050 are reasonable and sustainable from a supply perspective.  

The refuelling infrastructure for hydrogen develops only in the main road highways and 
in refuelling hubs, at scales that are cost-effective. The mix of hydrogen, bio-methane 
and clean methane in the gas distribution system allows 50% of the gas to be carbon-
free by 2050. The merit is to continue using the 
gas infrastructure and maintain the uses of gas 
in  the  domestic  and  industrial  sectors.  In 
buildings,  the  combination  of  the  strong 
renovation  of  buildings, 
the  widespread 
penetration of heat pumps and a 50% “carbon-
free” gas reduce the remaining emissions very 
emissions 
significantly. 
reduction takes place in the low-enthalpy heat 
uses in industry, thanks to the combination of 
efficient  energy  saving  technologies,  heat 
pumps  and  the  50%  carbon-free  gas.  Adding 
the  direct  uses  of  hydrogen 
in  high-
temperature  applications 
implies  that  the 
industrial  sector  can  also  reach  very  low 
emission levels.  

Similar 

carbon 

from 

The balanced scenario has the merit of limiting 
the use of technologies and infrastructures that 
seem  difficult 
today’s 
to  develop 
perspective. The balanced scenario achieves a 
96%  reduction  in  CO2  emissions  from  the 
energy  sector  (including  industrial  processes) 
in  2050  (relative  to  1990),  which  is  12 
percentage  points  more  than  in  the  basic 
decarbonisation scenario (-84% CO2 in 2050). 
The  user  prices  of  energy  and  the  overall 

January 2018  I  10 

143429959375108592Basic DecarbonisationScenarioBalanced ScenarioCO2emissions in MtRemaining CO2Emissions in 2050Energy SupplyTransport SectorDomestic SectorIndustry and Processes13213318288Basic DecarbonisationScenarioBalanced ScenarioEUR per tCO2abated cumulativelyAverage unit cost of emissions reduction2031-20502021-2030 
 
 
Sectoral integration: long-term perspective in the EU energy system 

energy  costs  from a consumers’ perspective  remain affordable and close to the basic 
decarbonisation scenario. The average annual total energy system costs in the period 
2030-2050  are  3.5%  lower.  The  balanced  scenario  abates  CO2  at  an  average  cost  of 
€88/t CO2 (cumulatively in the period 2030-2050), which is less than half of the cost in 
the basic decarbonisation scenario (€182/tCO2 abated). This  remarkable performance 
of the balanced scenario owes to the new technology assumptions for the technologies 
that allow multiple roles of hydrogen as a sectoral integration means and its particular 
role in the transport sector.  

in 

the 

than 

scenario 

scenario,  which 

Despite  reaching  close  to  zero  emissions  by 
2050,  total  costs  in  transport  are  lower  in  the 
basic 
balanced 
decarbonisation 
projects 
emissions  to  be  in  2050  only  60%  below  1990 
levels.  Hydrogen  utilisation  in  specific  market 
segments in transport  where it can achieve the 
lowest possible cost, in particular, the heavy duty 
or the large mileage travelling vehicles, provide 
cost reduction benefits. In addition, this reduces 
the total amount of biofuels allows utilisation of 
the  biofuels  at  quite  reasonable  fuel  costs 
specifically  in  aviation.  All  transport  sectors 
optimise costs, including the private cars dominated by battery-based powertrains. The 
cost reductions in the transport sector depend on assumptions. A cost reduction of the 
fuel  cell  stack  from  roughly  €300/kW  today  down  to  €44/kW  in  2050,  and  a  similar 
reduction  of  battery  costs  from  roughly  €400/kWh  today  down  to  €100/kW  by  2050 
enable the cost reductions. Regarding the levelized cost of an average medium-size car, 
the scenario assumes that the EVs are the cheapest in 2050 and that the fuel cells reach 
cost parity with conventional internal combustion cars.  

to 

The  part  of  the  power  sector  producing  hydrogen 
and  clean  fuel  reaches  29%  of  total  power 
generation  in  the  balanced  scenario  by  2050.  It  is 
remarkable  that  despite  the  significant  increase  in 
the  volume  of  power  generation  in  the  balanced 
scenario  (34%  above  the  basic  decarbonisation 
scenario  in  2050  and  69%  above  the  reference 
scenario),  the  average  EU  electricity  prices  do  not 
increase, but rather presents a marginal drop. This 
owes 
the 
interconnected system allowing access to remotely 
located  renewables  and  an  effective  sharing  of 
balancing resources. In this respect, the hydrogen-
based  storage  of  electricity  has  a  considerable 
contribution to smooth the load curves and to shift 
energy  from  renewable  electricity  to  times  periods 
when renewables are in deficit. The maximisation of 
renewables’ capacity factors, enabled by hydrogen, 
helps  lowering  electricity  costs.  In  this  way,  the 
renewables  increase  by  36%  in  the  balanced 
scenario,  compared  to  the  basic  decarbonisation 
scenario 
in  power 
in  2050.  The  RES  share 
generation  is  slightly  above  70%  by  2050,  but 
power generation from RES needs to increase by 1300 TWh in the balanced scenario by 
2050 compared to the basic decarbonisation scenario. 

integration  and 

the  market 

January 2018  I  11 

3333333333333340363131313030594945423935342020202520302035204020452050Levelised cost (EUR/100km)Conventional vehicleElectric vehicleHydrogen fuel cell vehicleIndustry, 1370, 20%Domestic, 2258, 33%Transport, 605, 9%Supply, 2649, 38%Electricity Consumption in the Balanced Scenario in 2050 (GWh)Thermal, 1303, 19%Nuclear, 1166, 17%RES, 4416, 64%Electricity Production in the Balanced Scenario in 2050 (GWh) 
 
 
Sectoral integration: long-term perspective in the EU energy system 

Hydrogen, clean gas and bio-methane cover almost half of total consumption of gaseous 
fuels in the balanced scenario by 2050. The natural gas is mainly necessary for power 
generation and industrial applications; in both cases, the respective plants are equipped 
with CCS technologies. Only 42% of total gaseous fuels are imported in 2050, the rest 
produced domestically using hydrogen and electricity. Given also that the largest part 
of the liquid fuels remaining in use by 2050  is fungible advanced biofuels, the overall 
import dependency is only 27% in the balanced scenario by 2050, significantly down 
from 56% in 2015 and lower than in the basic decarbonisation scenario (36% in 2050). 
The use of oil products decreases by 80% in the balanced scenario by 2050 compared 
to 2015 levels, and non-energy industrial applications use the 102 out of the 117 Mtoe 

oil products remaining in 2050. The imports of natural gas are 38% below 2015 levels 
in 2050.  

The  renewables  cover  the  largest  part  of  the 
incremental  energy  in  the  balanced  scenario.  In 
consequence, the RES-share approaches 75% in 

2050 
in  the  balanced  scenario,  14 
percentage  points  above  its  level  in  the 
basic  decarbonisation  scenario.  Despite 
the  production  of  significant  amounts  of 
biofuels,  biomass 
imports  are  only 
14Mtoe  in  2050,  3.3  Mtoe  up  from  the 
projection  for  2020.  The  imports  of 
biomass  in  the  balanced  scenario  are  5 
Mtoe 
basic 
decarbonisation  scenario,  in  2050.  The 
domestic  production  of  biofuels  meets 
sustainability criteria regarding feedstock 
and land-use.  

lower 

than 

the 

in 

A  sensitivity  analysis  scenario  which 
assumes a less optimistic development of 
hydrogen  technology  costs  shows  that 

January 2018  I  12 

21.121.121.121.027.127.127.124.374.660.466.131.2Balanced ScenarioBasic DecarbonisationScenarioSensitivity ScenarioReferenceRES-share2020203020501437742997359375160108510992BasicDecarbonisationSensitivityBalancedCO2emissions in MtRemaining CO2Emissions in 2050Energy SupplyTransportSectorDomestic SectorIndustry andProcesses13213913318213188BasicDecarbonisationSensitivityBalancedEUR per tCO2abated cumulativelyAverage unit cost of emissions reduction2031-20502021-2030Natural Gas, 219, 54%Clean Gas, 28, 7%Hydrogen, 114, 28%BioCH4, 42, 11%Balanced Scenario -Demand of Gas in 2050(MTOE)Production, 142, 35%Primary Energy, 93, 23%Net Imports, 168, 42%Balanced Scenario -Supply of Gas in 2050 (Mtoe) 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

emissions reductions close to 90% in 2050 are possible at relatively affordable costs; 
the average annual total energy system costs in the period 2030-2050 are 1.9% higher 
than  in  the  case  of  the  balanced  scenario.  If  hydrogen  technologies  would  be  more 
expensive in the long term, as in the sensitivity analysis, the energy system costs would 
still be lower in the balanced scenario compared to the basic decarbonisation scenario, 
but  only  by  1.6%.  The  average  CO2  abatement  cost  would  be  €131/t  CO2  in  the 
sensitivity  scenario  (cumulatively  in  the  period  2031-2050).  The  sensitivity  scenario 
show lower penetration of hydrogen in the end-uses due to the higher costs of fuel cells. 
The total amount of hydrogen used in the EU  either as a fuel or as  feedstock  for the 
production of synthetic methane in this scenario is 100 Mtoe, down from 150 Mtoe in 
the balanced one.  

If  hydrogen-related  technologies  (on  both  the  demand  and  supply  sides)  reduce 
significantly  in  costs  compared  to  today,  they  can  become  a  key  technology  to  help 
reduce emissions beyond the levels achieved in the basic decarbonisation scenario and 
at affordable costs.  

The balanced scenario benefits from the availability of hydrogen technology options and 
the reduced costs of fuel cells, which by assumption were not available in the context 
of  the  basic  decarbonisation  scenario.  In  this  sense,  the  two  scenarios  are  not  fully 
comparable regarding their total cost performance. The merit of the sectoral integration 
enabled by hydrogen is that it enables stronger abatement and lower costs, just because 
this option has not been considered in the basic decarbonisation scenario.  

The sectoral integration enabled by the Power-to-H2 and H2-to-gas technologies allow 
the carbon-free use of hydrogen in final energy consumption in those applications that 
cannot be directly supplied with renewable energy or direct electricity. To achieve the 
expected  cost  reductions  in  the  technologies,  large-scale  investments  and  effective 
market coordination of different actors are necessary.  

In  order  to  achieve  overall  GHG  emission  reductions  beyond  the  80%  target,  it  is 
paramount that such technologies develop in a timely manner. The strategy to follow 
must be decided most probably before 2030. The high R&D developments required for 
the  successful  achievement  of  zero  emissions  need  clear  signals  to  allow  positive 
anticipation  by  the  research  community  and  the  investors.  To  achieve  close  to  zero 
emissions  shortly after  2050, modifications of the energy system must be  well under 
way a decade before. In this context, a review of technological developments must occur 
within probably the next  10 years to progress  towards finding a decisive  reply to the 
question “which strategy to follow?”. The investment requirements are such that it is 
deemed  impossible  to  be  able  to  maintain  development  of  certain  options  in  parallel 
over an extended period. In the long term, a few of the technologies will dominate as it 
is unlikely that all competing technologies will achieve the required economies of scale. 
Choices among the technologies and therefore strategies are necessary to  be decided 
at some point in the future.  

As a next step, not addressed in this study, the assessment of suitable energy policy 
instruments  should  have  priority.  The  question  is  which  instruments  would  enable 
emergence  and  widespread  adoption  of  the  technologies,  and  facilitate  market 
coordination  more  effectively.  Further  steps  are  also  required  to  assess  the  sectoral 
integration  strategies  from  a  financing  perspective  and  evaluate  the  impacts  on 
industry, exports and employment in the EU. Further analysis of the possible integration 
of clean hydrogen in the industrial processes and produced materials also requires more 
in-depth insights. 

January 2018  I  13 

 
 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

Table of Content 

Executive summary ........................................................................................... 4 
Hydrogen scenarios definition ........................................................................... 5 
The main lessons from the analysis ................................................................... 7 
Key technologies and business models ........................................................... 7 

Pros and cons of the respective strategies ...................................................... 8 

About ASSET ..................................................................................................... 4 
Table of Content ...............................................................................................14 
Tables .............................................................................................................16 
Figures ............................................................................................................16 
Introduction .....................................................................................................18 
Objective of the study ....................................................................................18 
Structure of the report ...................................................................................19 
Hydrogen  roadmap  TO  2050:  assessment  of  technological  and  market  developments
 ......................................................................................................................20 
Hydrogen value chain and the key business models ...........................................20 
Hydrogen production ..................................................................................20 

Hydrogen  as  a  feedstock  for  synthetic  hydrocarbons  (concentrated  industrial 
processes) .................................................................................................22 

Hydrogen use for final energy consumption (decentralised, small-scale) ............22 

Sector coupling of the mobility sector ...............................................................24 
Overview of the mobility sector ....................................................................24 

Applicability of hydrogen-fuelled vehicles in the mobility sector ........................25 

Required infrastructure changes (refuelling station) ........................................26 

Current characteristics of hydrogen-fuelled vehicles and expected development .27 

Linking the power sector and hydrogen-demanding industry ...............................34 
The power-to-hydrogen conversion chain ......................................................34 

Sustainable hydrogen-based processes in industry .........................................35 

Linking the power and heating sector ...............................................................37 
Overview power-to-heat conversion technologies ...........................................38 

Overview thermal storage options ................................................................39 

Benefits for electricity sector ........................................................................41 

Linking hydrogen to the heating sector ..........................................................42 

Energy storage and sectoral integration ............................................................43 
Hydrogen storage .......................................................................................43 

Impact of hydrogen based flexibilities on decarbonisation of the gas grid ..........44 

Contribution of hydrogen based flexibilities for the energy transition .................45 

Specific key regions .......................................................................................46 
Regions where Carbon-free Production of Hydrogen is possible ........................46 

Regions with industrial demand for carbon-free hydrogen ................................50 

Mobility demand for hydrogen ......................................................................50 

Summary ......................................................................................................53 
Modelling the impact of sectoral integration on the energy system towards 2050 ......56 
Introduction ..................................................................................................56 

January 2018  I  14 

 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

Background: key elements to be considered in the Modelling Task .......................57 
Features of hydrogen ..................................................................................57 

Business drivers for hydrogen ......................................................................57 

Carbon free hydrogen production .................................................................59 

The synergies with Power-to-gas and Power-to-liquids fuels.............................60 

The techno-economic challenges towards a hydrogen economy ........................60 

The pathway towards 2050 ..........................................................................61 

Description of the PRIMES model extension ...................................................64 

Sectoral integration in the energy system towards 2050: three strategies .............67 
Common elements of the strategies ..............................................................67 

Strategy A: Hydrogen as an energy carrier ....................................................69 

Strategy B: Hydrogen as feedstock ...............................................................72 

Strategy C: Hydrogen for power storage .......................................................76 

Electricity demand and generation ................................................................78 

Discussion of modelling results ........................................................................79 
A balanced sectoral integration scenario: A realistic deep decarbonisation pathway for 
the long term to 2050 ....................................................................................81 
Description of the main scenarios analysed in the study ..................................81 

Key scenario results and discussion ..............................................................83 

Conclusions and recommendations ................................................................... 102 
Bibliography ................................................................................................... 107 
APPENDIX: Technical and economic data ........................................................... 111 

January 2018  I  15 

 
 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

Tables 

Table 1: Cost specifications, fuel consumption, refuelling time and CO2 emissions of the 
fuel cell electric bus compared to the Diesel bus ...................................................28 
Table 2: Cost specifications, range and weight capacity of the hydrogen truck compared 
to the electric truck...........................................................................................29 
Table 3: Cost specifications, fuel consumption, refuelling time and CO2 emissions of the 
H2 passenger vehicle compared to the gasoline passenger vehicle and the EV..........30 
Table 4: Steam Methane Reforming process.........................................................35 
Table 5: Thermal storage techniques ..................................................................40 
Table 6: Annual curtailment per country (absolute in share in total renewables electricity 
production) ......................................................................................................47 
Table  7:  Recommended  areas  for  electrolyser  installation  based  on  the  renewables 
curtailment in that area .....................................................................................47 
Table 8: Remaining GHG emissions in a basic decarbonisation scenario ...................62 
Table 9: Remaining fossil fuels in a basic decarbonisation scenario .........................63 
Table 10. EU dependency on imports ..................................................................97 

Figures  

Figure 1: An illustrative scheme of a hydrogen value chain: ...................................20 
Figure 2: Trends in passenger transport activity (left) and freight transport (right, excl. 
international shipping) and energy consumption (E3M et al., 2016) ........................25 
Figure 3: Hydrogen refuelling station for passenger vehicles with two compressor stages
 ......................................................................................................................27 
Figure 4: Hydrogen refuelling station for trucks or buses with one compressor stage 27 
Figure 5: The advantages of the fuel cell compared to a battery for buses and trucks29 
Figure 6: Evolution of activity of passenger cars and vans by type and fuel (E3M et al., 
2016) ..............................................................................................................33 
Figure  7:  Plug-in  electric  vehicles  per  charging  point;  0-5  (blue),  5-25  (green),  >25 
(red); (Source: Ecofys based on EAFO 2017) .......................................................34 
Figure 8: PtH technologies in the residential sector (DIW 2017) .............................38 
Figure 9: Linking the power and the gas infrastructure via hydrogen (European Power 
to Gas Platform, 2017) ......................................................................................45 
Figure 10: Annual curtailment per renewable technology in Germany (maximum height 
bar is 475 GWh) [28] ........................................................................................48 
Figure  11:  Annual  curtailment  per  renewable  technology  in  France  (maximum  height 
bar is 72 GWh) [28] ..........................................................................................48 
Figure  12:  Annual  curtailment  per  renewable  technology  in  Great  Britain  (maximum 
height bar is 117 GWh) [28] ..............................................................................49 
Figure 13: Annual curtailment per renewable technology in Denmark (maximum height 
bar is 442 GWh) ...............................................................................................49 
Figure 14: Hydrogen refuelling stations across Europe, of which part is funded by H2ME
 ......................................................................................................................52 
Figure 15: LNG Blue Corridors ............................................................................53 
Figure 16: GHG emissions reduction to 2050 ........................................................64 
Figure 17: A process flow diagram of the new PRIMES sub-model ...........................65 

January 2018  I  16 

 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

Figure  18:  Prospects  of  production  cost  of  hydrogen  in  a  decarbonisation  scenario 
context............................................................................................................68 
Figure 19: Prospects for clean gas costs in a decarbonisation scenario context .........73 
Figure 20: Prospects for clean liquid fuel costs in a decarbonisation scenario context 74 
Figure  21:  Development  of  fuel  cell  stack  and  battery  costs  in  the  three  scenarios 
considered .......................................................................................................82 
Figure 22. Evolution of CO2 emissions from the energy sector and industrial processes 
in EU28 ...........................................................................................................85 
Figure 23. Remaining CO2 emissions in EU28 in 2050. ...........................................85 
Figure 24. Relative shares of remaining emissions in EU28 in 2050 .........................86 
Figure 25. Hydrogen consumption for energy purposes in the EU28 ........................87 
Figure 26. Consumption of hydrogen as a direct fuel per energy sector in EU28 .......87 
Figure 27. Power generation in EU28 ..................................................................89 
Figure 28. Electricity consumption by sector in EU28 in 2050 .................................89 
Figure 29. Structure of power generation in EU28 .................................................90 
Figure 30. CO2 emissions from the transport sector in EU28 ...................................91 
Figure 31. Energy consumption in the transport sector by fuel in EU28 ....................91 
Figure 32. Fuel mix in transport in 2050 ..............................................................92 
Figure 33. Shares of powertrains in the stock of cars in EU28 .................................92 
Figure 34. Fuel mix in trucks in EU28 ..................................................................93 
Figure 35. Levelized and running costs for an average medium-size car operating with 
conventional and advanced powertrains ..............................................................94 
Figure 36. Total final consumption by fuel in EU28 ................................................94 
Figure 37. Gross Inland Consumption by fuel in EU28 ...........................................95 
Figure 38. Gaseous fuel demand in EU28 in 2015 and 2050 ...................................96 
Figure 39. Gaseous fuel supply in EU28 in2015 and 2050 ......................................96 
Figure 40. Net imports of fuels in the EU28 ..........................................................97 
Figure  41.Average  annual  energy  system  cost  (left)  average  unit  cost  of  emission 
reduction (right) in EU28 for the two main scenarios .............................................98 
Figure 42. Average prices of electricity in EU28 ....................................................99 
Figure 43. Investment expenditure in power generation ........................................99 
Figure  44.  Final  consumption  by  fuel  in  industry  (left-hand  side)  and  transport  (right 
hand side) in EU28 ......................................................................................... 100 
Figure 45. CO2 emissions from the energy sector and industrial processes n EU28 . 101 
Figure  46.Average  annual  energy  system  cost  (left)  average  unit  cost  of  emission 
reduction (right) in EU28 for the two main scenarios and the sensitivity scenario ... 101 

January 2018  I  17 

 
 
 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

Introduction 
Both  the  Energy  Union  strategy  and  the  SET  plan  for  innovation  primarily  focus  on 
sectors,  such  as  efficiency  in  buildings,  sustainable  transport,  energy  market 
integration, renewables, etc. At the same time, the strategy recognises energy system 
integration as an enabler of transformations towards deep decarbonisation. While the 
advanced  technologies  and  the  supporting  measures  operate  at  a  sectoral  level,  the 
optimum  transformation  of  the  energy  system  requires  moving  along  integrated 
pathways.  

An already agreed option of sectoral integration is the role of electricity as a carrier of 
emissions reductions in transport and heat uses combined with deep decarbonisation of 
power generation. The sectoral integration enabled by electricity brings also substantial 
energy  efficiency  gains.  The  electrification,  however,  may  not  be  technically  able  to 
cover 100% of all uses of fossil fuels in the energy system and at the same time, carbon-
free substitutes such as biofuels do not have sufficient feedstock resources to cover the 
residual uses of fossil fuels.  

The  decarbonisation  roadmaps  developed  so  far  have  shown  persistence  in  the  long-
term of emissions from fossil fuel combustion in heating and industrial uses mainly due 
to the use of natural gas and in the transport sector due to the use of mineral oil liquid 
fuels in certain transport means. Therefore, a strategy towards full decarbonisation of 
the energy system –i.e. going beyond the 80% emission reduction in 2050-, as required 
by the climate strategy in the long term, consistent with the Paris Agreement ambition, 
is  not  feasible  unless  emissions-free  carriers  develop  based  on  a  sectoral  integration 
strategy.  Emissions-free  methane  and  liquid  hydrocarbons,  as  well  as  emissions-free 
hydrogen are probably necessary to develop. Their production in the power sector may 
be  challenging  regarding  resources  and  grids.  They  will  also  likely  require  a  large 
increase in electricity production due to large energy conversion losses and, in the case 
of  wide-spread  use  of  hydrogen,  would  require  a  dedicated  distribution  network. 
However,  it  is  widely  recognised  that  the  production  of  such  carriers  can  also  deliver 
electricity  storage  services  in  the  power  sector  (known  as  chemical  storage)  thus 
allowing maximum possible use of variable renewables in power generation.  

Hydrogen  plays  a  central  role,  directly  or  indirectly,  in  the  integration  of  sectors. 
However, there exist alternative pathways regarding hydrogen, which deserve economic 
and  feasibility  assessment.  In  a  stylised  manner,  hydrogen  may  serve  for  storage  of 
electricity a feedstock to produce emissions-free gas and liquid hydrocarbons, and as 
an energy carrier serving final stationary and  mobile  energy uses directly. Therefore, 
the power to hydrogen, gas or liquids technologies, are key for an adequate  sectoral 
integration in the context of deep decarbonisation of the energy system. 

Objective of the study 

The  objective  of  this  study  is  to  identify  the  impact  of  sectoral  integration  on  energy 
system including the cost and infrastructure requirements of the energy system, in the 
context of deep decarbonisation in line with the Paris Agreement. The following aspects 
will be analysed: 

▪  Power to Gas, and the use of H2 and clean gas in decarbonising the natural gas grid 

▪  The use of carbon-free H2 in industry (in high temperature applications in addition to 

its use as a feedstock in some industrial sectors) 

▪  Linking the power and mobility sector, both via electricity and hydrogen 

▪  Linking the power and heating sector, in buildings and industry 

January 2018  I  18 

 
 
 
Sectoral integration: long-term perspective in the EU energy system 

▪  Analysing strategies which allow to achieve deep decarbonisation and the enabling 

contribution of power-to-X technologies to produce renewable hydrogen and 
hydrocarbons. 

Structure of the report 

The study comprises two main tasks: 

Task 1 consists of a mapping of the key Power-to-X technologies and an assessment of 
the  techno  economic  parameters  and  barriers  including  associated  costs  of  hydrogen 
production and the development of a transmission and distribution network. The task 
aims at improving the  understanding of the potential of the  various technologies and 
the interactions between different energy sectors, including the electricity and gas grids. 
The goal is to define the potentials and limitations  of  energy  storage,  serving energy 
needs in final energy demand and other relevant applications.  

The Task consists of five subtasks: a) Linking the power and mobility sector & Usage of 
H2 in transportation, b) Linking the power sector and H2-demanding industry, c) Linking 
the  power  and  heating  sector,  d)  Energy  storage  and  sectoral  integration  and  e) 
Identifying key regions with local overproduction and excess of renewables. 

Task 2 uses systems analysis and modelling to develop narratives about future impact 
of sectoral integration in the energy system towards 2050, in the context of the deep 
decarbonisation  required  by  the  Paris  Agreement.  To  assess  the  potential  role  and 
contribution  of  power-to-X  technologies  and  storage  under  different  contexts,  three 
narratives  seem  relevant:  a)  the  ‘hydrogen  as  an  energy  carrier’  scenario,  b)  the 
‘hydrogen  as  feedstock’  scenario  and  c)  the  ‘hydrogen  for  power  storage’  scenario. 
Based  on  this  analysis  a  balanced  scenario  and  a  sensitivity  scenario  to  2050  are 
modelled  with  different  assumptions  about  the  development  of  hydrogen  related 
technologies and the market penetration of hydrogen.   

The main results are subject to discussion in the final ‘Discussion’ section. The document 
also  includes  a  large  bibliography  on  the  topic  and  ends  with  conclusions  and 
recommendations. 

January 2018  I  19 

 
 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

integration  within  a 

Hydrogen roadmap TO 2050: assessment of 
technological and market developments  
As  mentioned  in  the  introductory  section,  hydrogen  could  be  present  in  all  possible 
configurations  of  sectoral 
for  deep 
decarbonisation  of  the  energy  system.  In  the  sense  of  the  integration  strategy,  i.e. 
hydrogen as an energy carrier that could serve all the end uses, the full value chain of 
hydrogen  is  as  shown  in  Figure  1.  As  subsequent  sections  explain,  alternative 
configurations  of the sectoral integration  strategies  may not develop the  entire value 
chain of hydrogen. It may be that hydrogen produced from electrolysis fed by carbon-
free electricity serves as a means of storage of electricity. It may also be that hydrogen 
is  a  feedstock  to  produce  carbon-free  methane  and  liquid  hydrocarbons  to  substitute 
the corresponding fossil fuel products in end-use consumptions. Finally, hydrogen can 
well be an energy carrier in all the end-use consumptions.  

long-term  strategy 

This section describes the main technological and market developments of hydrogen. 
The section also mentions key technologies that compete with hydrogen where this is 
relevant.  The  data  collected  on  costs  and  technologies  serve  to  create  technology 
assumptions  used  in  the  modelling.  Consultation  on  these  data  with  stakeholders  is 
ongoing. The data on technologies are specific to application areas,  such as mobility, 
heating, power, industry and storage. 

Hydrogen value chain and the key business models 

Figure 1: An illustrative scheme of a hydrogen value chain:1 

Hydrogen production 

Steam methane reforming is the currently conventional technology to produce hydrogen 
from fossil fuels, mainly natural gas. The technology is mature and competitive but it is 
not carbon-free.  

In a decarbonisation context, electrolysis using carbon-free electricity is the technology 
of preference for producing hydrogen. The cost reduction potential is very significant for 
electrolysis technologies. 

In a deep decarbonisation context, the large use of intermittent renewables implies that 
excess carbon-free electricity can occur at certain times as well as shortage of carbon-
free  electricity  at  other  times.  Producing  carbon-free  hydrogen  using  electrolysis  at 
times of excess of carbon-free electricity allows producing electricity from hydrogen at 
times  of  carbon-free  electricity  shortage.  Obviously,  this  maximizes  the  use  of 
renewables and serves as a perfect storage of electricity – known as chemical storage 
of electricity through electrolysis.  

An  electrolyser  can  produce  hydrogen  at  a  pressure  of  30  bar.  This  can  be  further 
compressed to 80, 350, 700, 950 bar to reduce the size of storage needed. An 80 bar 
pressure is necessary  for injection in the natural gas network, whereas a pressure  of 
350-950  bar  applies  for  using  hydrogen  in  transport,  for  example  in  trucks  and 
passenger vehicles.  

1 The scheme is only exemplary for possible hydrogen value chains, others are possible and might be economically 
more viable.  

January 2018  I  20 

 
 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

The data collected suggest the following basic cost assumptions: 

▪  Large-scale alkaline electrolysers, which is currently the most wide-spread 

electrolyser technology , currently cost less than 500 €/kW [1]  and have an electric 
efficiency of 55 kWh/kg H2 (72%) [2]; the cost may drop to 350 €/kW by 2020 
based on industrial estimates and further decrease in the long term significantly. 
The CAPEX of the electrolyzer is expected to decrease in the following years due to 
the increase of the cumulative produced volume of electrolyzer thanks to the 
increase in sale which will decrease the production costs.  The energy efficiency may 
exceed 85% in the long term.  

▪  More advanced electrolysis technologies are under development: proton exchange 
membrane – PEM and solid oxide electrolyzer cell – SOEC. The advantage of PEM 
versus the alkaline technology is the ability to operate efficiently under variability of 
electricity inputs, which facilitates the use of renewable-based electricity. Also, the 
PEM electrolysers can achieve higher efficiency in the future compared to the 
alkaline ones and be applicable at various sizes as the dis-economies of scale –
which are a problem for Alkaline electrolysers- are rather limited (in the order of 
20% in levelized output costs). The SOEC electrolysers can reach the highest 
efficiency, among all technologies, if they become mature in the future. The main 
advantage of SOEC is the possibility to co-electrolyse hydrogen and carbon dioxide 
to produce syngas (mixture of hydrogen and carbon monoxide), which can further 
upgrade to methane and other hydrocarbons. However, the SOEC electrolyser runs 
at high temperature, which poses challenging engineering problems requiring 
solutions in future mature systems.  

▪  Electrolysis can reach an efficiency of above 80%. As the reuse of hydrogen for 
electricity generation can have an efficiency of 60%, the overall efficiency of 
chemical storage of electricity based on hydrogen can be close to 50%. If the reuse 
of hydrogen takes place in fuel cells, the overall electric efficiency can be up to 60-
65% (excluding possible heat uses).  

▪  Storage of electricity based on hydrogen is versatile regarding the timeframe and, 
depending on the available facilities of hydrogen storage, storage of electricity can 
be seasonal, weekly and daily.  

The  CAPEX  of  electrolysers  will  decrease  in  the  future  because  of  large-scale 
installations. Except the SOEC, all other technologies of electrolysis are currently at a 
high  level  of  technology  readiness.  SOEC  electrolysers  have  a  similar  cost  reduction 
potential  but  have  additional  benefits  as  they  can  produce  syngas  in  one  unit  and 
produce hydrogen directly at different pressures.  

The unit cost of hydrogen produced from electricity mainly depends on the unit cost of 
electricity. Maximizing the use of intermittent renewables, thanks to hydrogen storage 
combined with the technology learning effects imply significant reductions of unit costs 
of hydrogen in the future. The levelized unit cost of electricity production using mature 
renewables  technologies  can  reach  levels  well  below  50  EUR/MWh  of  electricity. 
Therefore, the unit cost of hydrogen can be well below 60-70 EUR/MWh hydrogen in the 
future. At a price of 35-40 EUR/MWh-natural gas, hydrogen requires a carbon price of 
the order of 80-100 EUR/tCO2 to become competitive vis-à-vis natural gas.2  

Using the same price range, the storage of electricity using hydrogen can reach a unit 
cost of 100 EUR/MWh of electricity stored. Expectations are that the battery technology 
at a large scale is able to reach similar levels of unit costs of electricity stored. However, 
the battery storage is less versatile than hydrogen-based storage of electricity regarding 

2 However, for a fully correct comparison the efficiency of the end-use technology would also need to be taken into 
account. E.g. fuel cells in mobility are more efficient than ICEs using compressed natural gas. 

January 2018  I  21 

 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

the timeframe of storage, but depending on the use both have advantages (see section 
Energy storage and sectoral integration).  

As the cost of electricity is of critical importance for the cost of hydrogen, it is of great 
importance to place the production facility of hydrogen in areas with a supply of cheap 
electricity, directly or via large-scale interconnections.  

The economics of electrolysis also suggest maximizing the rate of use of the facilities, 
which implies that it is useful to form a portfolio of carbon-free electricity featuring a 
base-load  load  profile.  Therefore,  combination  of  renewables  from  various  sources  or 
from different locations including via interconnections is important for reducing the unit 
cost of hydrogen. Dispatchable carbon-free generation, such as nuclear, can provide a 
base-load  supply  to  electrolysis  and  ensure  the  achievement  of  largest  possible 
economies of scale.  

The  analysis  of  business  cases  for  electrolysis  development  in  the  private  sector 
suggests that two critical factors need to co-exist: 

1.  Large-scale and base-load supply of cheap electricity 
2.  Demand certainty for electricity depending on demand for hydrogen to feed units 

producing clean fuels or distributing hydrogen and clean fuel 

Hydrogen as a feedstock for synthetic hydrocarbons (concentrated industrial 
processes) 

If  hydrogen  is  a  feedstock  for  the  production  of  clean  hydrocarbons,  the  seller  of 
hydrocarbons requires demand certainty. If hydrogen is an energy carrier, the hydrogen 
seller  requires  demand  certainty.  In  both  cases,  the  simplest  way  to  ensure  a  solid 
economics  basis  for  the  business  case  are  back-to-back  contracts  between  electricity 
supply  and  the  seller  of  hydrogen  or  the  products  derived  from  hydrogen  can.  The 
demand for the hydrogen products or services should be guaranteed through policies 
e.g.  such  as  zero  emission  standards  for  transport  or  supported  by  policy  and 
policymakers  through  regulations  and  infrastructure  construction.  Regarding  the 
electricity storage services, the purchaser of the services would usually be the systems 
operators or large-scale suppliers of electricity in the case of self-balancing practices. 
The business case will strongly depend on the arrangements and the functioning of the 
market for ancillary services and the balancing of electricity. It is well possible in the 
future  to  also  see  large-scale  aggregators  acting  as  electricity  suppliers  to  combine 
intermittent renewables and storage including through hydrogen to form economically 
versatile supply portfolios. 

All  these  business  cases  need  to  be  concentrated  and  conducted  at  industrial  scale 
because  of  the  importance  of  the  economies  of  scale  and  the  base-load  operation 
requirement. Large-scale companies are likely to invest and develop this business. As 
mentioned, the economic environment has to be a strong decarbonisation policy and a 
carbon price, implicit or explicit, featuring sufficient range and stability. 

Hydrogen use for final energy consumption (decentralised, small-scale) 

Small and medium scale business applications for hydrogen can coexist. They include 
the  direct  use  of  hydrogen  in  consumer’s  applications,  e.g.  for  mobility,  heating,  or 
industrial purposes. A fuel cell is a device that converts the chemical energy of hydrogen 
into electric energy and heat. The products of the reaction are electricity and water. The 
fuel cell is a promising technology because of the easiness of use, the robustness and 
its efficiency. The applications areas are diverse and can be at various scales. However, 
the  main  issue  is  the  capital  cost  of  fuel  cells,  which  is  persistently  high  despite  the 
research  and  industrial  efforts  over  a  long  period  in  the  past.  Therefore,  great 

January 2018  I  22 

 
 
 
Sectoral integration: long-term perspective in the EU energy system 

uncertainty surrounds the economics of fuel cells. Should the fuel cell costs experience 
strong  learning  potentials,  they  could  present  an  alternative  to  the  battery-based 
electrification of mobility particularly for modes such as heavy duty vehicles for which 
electrification is also a challenge. Under such conditions, the fuel cells could also get a 
large share in stationary heat uses in the domestic sector and in industry.  

Using steam reforming of natural gas integrated in the end-use application of a fuel cell, 
as it is today a conventional solution, but is incompatible with a deep decarbonisation 
policy. Production of hydrogen with zero-crbon electricity might be a solution for deep 
decarbonisation.  A  large-scale  application  of  hydrogen  as  an  energy  carrier  requires 
development  of  new  industrial  base  and  large  scale  of  end-uses  poses  the  issue  of 
distribution of hydrogen.  

The large-scale use of hydrogen in end-uses implies development of a pipeline-based 
distribution  system,  similar  to  the  gas  distribution  infrastructure.  The  hydrogen 
infrastructure comprises high-pressure backbone pipelines and medium to low pressure 
pipelines  at  a  local  level.  Due  to  technical  reasons,  the  currently  available  gas 
infrastructure is not fully appropriate for hydrogen and needs adaptations of significant 
investment  cost.  The  system  also  requires  hydrogen  storage  at  a  large  scale  and  in 
particular  in  salt  caverns  and  other  facilities,  similarly  to  the  storage  of  conventional 
fuels. Another possibility for the distribution system of hydrogen is the use of trucks, 
more precisely hydrogen tube trailers, which transports compressed hydrogen (180-250 
bar) in steel tubes. Each trailer can transport about 280-720 kg of hydrogen. [3] 

The business model of hydrogen infrastructure is similar to the business model of gas 
distribution. Unsupported private investment is rather unlikely to be able to develop the 
network at a full scale. This is due to the uncertainty regarding the size and the pace of 
development of the hydrogen market, which to develop requires large-scale distribution. 
A market coordination failure, manifested as lack of appropriate infrastructure in relation 
to the targeted hydrogen market could be expected. Public support  and intervention, 
notably for development of infrastructure or industrial base, if appropriately designed, 
can  achieve  a  positive  externality  regarding  the  benefits  of  the  consumers  from 
hydrogen availability for end-uses in a decarbonised society.  

Evidently, the hydrogen (pipeline) infrastructure at a large-scale constitutes a natural 
monopoly. Therefore, there is scope to apply unbundling between network ownership 
and operation  and commercial business in hydrogen production and sales. The scope 
for  interoperability  of  hydrogen  infrastructures  within  the  EU  internal  market  for 
hydrogen  is  important.  The  benefits  of  an  EU  market  integration  are  similar  to  other 
networks,  and  regard  development  of  competition,  sharing  of  storage  resources,  and 
the security of supply when facing technical shortages.  

Integration  of  the  hydrogen  markets  across  the  EU  is  also  a  prerequisite  for  the 
integration of the hydrogen upstream market.  

The upstream supply of hydrogen is expected to be domestic in the EU,3 in contrast to 
the  gas  market,  as  this  is  the  most  efficient  way  from  a  systems  perspective 
(transporting electricity if required is much more efficient than transporting hydrogen). 
It would require integration of the power markets extended by the development of the 
electrolysis facilities and, if at sufficiently large scale, the feeding of hydrogen networks. 
The development of such a large-scale hydrogen infrastructure and markets is a huge 
endeavour and requires long and a well-coordinated preparation at a European level.  

The business of smaller-scale hydrogen supply to specific or niche markets is possible 
too  and  feasible  to  develop  probably  also  on  a  pure  private  basis.  For  example, 

3 While currently import/export plans for hydrogen exist in other parts of the world (e.g. Japan); the hydrogen is not 
derived from carbon free sources. It is expected that domestic carbon free hydrogen production is the best option 
for Europe including to increase energy independence, as well as security of supply.  

January 2018  I  23 

 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

development of small-scale electrolysis located close to the hydrogen refuelling stations, 
distribution of hydrogen in pressurized tanks or in tubes containing liquefied hydrogen. 
They constitute an appropriate business model for a small or medium size market for 
hydrogen, for example regarding fuel cells in the transport sector or selected transport 
modes (e.g. long distance road freight). Small-scale electrolysis is more expensive than 
large-scale, but the effect of dis-economies of scale is not very high due to the modular 
structure of electrolysers. Whether a local electrolyser is economically preferable than 
a  system  distributing  hydrogen  in  tanks  or  tubes  is  unknown  today  and  depends  on 
specific market conditions. In reality, both ways may well coexist in the future.  

The  use  of  hydrogen  as  a  non-energy  feedstock  in  industry  (notably  in  fertiliser 
production, petrochemicals, as well as  some  metallurgic applications and  others) and 
refineries  is  a  current  practice  and  the  corresponding  industry  follows  mature 
technological  and  business  solutions.  Electrolysis  using  carbon  free  electricity  may 
substitute in the future the carbon emitting hydrogen technologies, which are common 
today.  The  amounts  of  hydrogen  used  in  industry  as  a  non-energy  feedstock  are  far 
smaller than the potential uses of hydrogen in industry in high temperature applications. 
The  current  business  practices  for  carbon  free  hydrogen  cover  only  niche  market 
segments,  upscaling  of  business  models  are  at  least  required  to  cover  the  future 
requirements of developing hydrogen for energy purposes.   

Sector coupling of the mobility sector 
This  section  provides  an  overview  of  different  options  for  linking  the  power  to  the 
mobility sector. The focus lies  on electric vehicles and hydrogen-fuelled vehicles, and 
their  applicability  for  a  transformation  of  the  mobility  sector.  Within  a  deep 
decarbonisation  context,  the  mobility  sector  faces  the  highest  challenges  in  the 
reduction  of  carbon  emissions.  Electrification  has  a  high  potential  as  an  option  but 
cannot  cover  all  the  transport  markets  due  to  range  and  other  limitations.  Producing 
advanced generation biofuels to fully substitute mineral oil fuels is also a valid option, 
which however is limited by the availability of sustainably produced biomass feedstock 
in  the  production  of  advanced  biofuels.  Hydrogen  as  an  energy  carrier  in  transport 
depends  crucially  on  the  fuel  cell  technology,  which  is  currently  expensive  and  the 
expectations  about  cost  reductions  in  the  future  are  highly  uncertain,  although 
improvements have occurred in recent years. Otherwise, the fuel cells would present a 
robust solution with wide coverage across all transport means.  

Overview of the mobility sector 

The  mobility  sector  accounts  for  about  one  third  of  total  EU  final  energy  demand. 
According to the projections of the EU Reference Scenario 2016 (E3M et al., 2016 4) the 
current share of 31% will slightly increase up to 33% in 2050. Total final energy demand 
of the mobility sector until 2050 will stay rather constant showing fluctuations around 
350 Mtoe. Road transport accounts for the largest share of final energy demand of the 
mobility sector (more than 250 Mtoe), followed by aviation. 

Figure 2 illustrates the transport activity (based on passenger or freight kilometres) and 
energy demand indexed to 1995. The figure shows that the activity in the mobility sector 
is  expected  to  grow  significantly  in  the  next  decades.  Due  to  the  shift  in  economy 
towards  more  services  and  information  activities,  a  weakening  of  activity  growth  is 
projected  beyond  2030.  However,  as  indicated  above,  energy  demand  stays  almost 
constant and will decouple from transport activity. 

4  E3M  et  al.  (2016):  “EU  Reference  Scenario  2016  –  Energy,  transport  and  GHG  emissions  –  Trends  to  2050”, 
European Commission 

January 2018  I  24 

 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

Figure  2:  Trends  in  passenger  transport  activity  (left)  and  freight  transport 
(right, excl. international shipping) and energy consumption (E3M et al., 2016) 

The decoupling of transport activity and final energy demand is explained by efficiency 
improvements  of  technologies  and  fuel  mix.  Until  2030  the  efficiency  in  passenger 
transport  will  be  affected  by  regulations  on  CO2  emission  standards  for  light  duty 
vehicles. After 2030 the gradual renewal of the vehicle fleet, advanced technologies and 
increasing  fuel  prices  result  in  an  efficiency  increase  of  36%  by  2050.  Efficiency  for 
freight transport with heavy good vehicles is expected to improve by 23% until 2050. 

The relatively long lifetime of the rolling stock in rail transportation is a reason for lower 
efficiency  gains  compared  to  road  transport.  Further  electrification  will  lead  to  an 
improvement of 31 % and 29 % by 2050 for passenger and freight rail respectively. The 
largest efficiency gains (around 41%) are expected for passenger aviation due to more 
efficient aircrafts and a renewal of the fleet. 

The  decarbonisation  of  the  mobility  sector  is  crucial  to  meet  the  European  emission 
reduction targets. However, the EU final energy demand of the mobility sector is still 
met  by  about  95%  with  fossil  fuels.  In  contrast  to  the  electricity  and  heating  sector 
which  have  already  seen  significantly  increasing  shares  of  renewable  energy  supply 
(solar PV, wind energy, solar thermal, biomass), renewable energy technologies are not 
widely applied in the mobility sector yet. Biofuels are one option for direct renewable 
energy  use  in  the  mobility  sector.  However,  biomass  resources  are  limited  and  there 
will be an increase in land use competition between food and energy crops, and the use 
of biomass for the mobility sector conflicts with the use of bioenergy in the electricity 
and heating sector. Further the sustainability criteria for bioenergy are becoming stricter 
and proposed legislation plans to entirely phase out food based biofuels. The coupling 
of the power and mobility sector, either by direct use of electricity in electric vehicles or 
electricity-based production of hydrogen and its use in hydrogen fuelled vehicles, are 
the most discussed options for a decarbonisation of the mobility sector.  

Within this study, we distinguish between four different mobility segments: 

1. Railway  

2. Aviation 

3. Shipping 

4. Road transport covering cars and trucks 

Applicability of hydrogen-fuelled vehicles in the mobility sector 

A  possibility  for  decarbonizing  the  mobility  sector  is  the  use  of  hydrogen  in  fuel  cell 
electric vehicles (FCEV) as an alternative or in combination with electric vehicles with 
batteries  (BEV);  particularly  for  some  transport  modes  FCEVs  are  a  better  adapted 

January 2018  I  25 

 
 
 
     
 
Sectoral integration: long-term perspective in the EU energy system 

solution compared to BEVs. Today, several projects and business cases already exist in 
several mobility sectors, e.g. passenger vehicles, trucks, buses, and even ferries. For 
realising  these  projects,  an  infrastructure  of  refuelling  stations  needs  to  be 
implemented. 

Required infrastructure changes (refuelling station) 

To support the development of the hydrogen-fuelled mobility sector, the infrastructure 
needs to be built, i.e. hydrogen production, storage, distribution and refuelling stations. 
Worldwide there are 280 active hydrogen refuelling stations, of which 92 are in Europe 
[4], and at the beginning of 2017 there were 140 stations in planning, construction or 
commissioning  phase.  Investing  in  hydrogen  refuelling  stations  today  is  financially 
challenging, due to the low utilization rate, which is why most  of them are built with 
funding support ; the capital costs of a refuelling station range from 1.2 to 8.2 million 
$/(kg H2),  depending  on  the  production  of  hydrogen  on-site  or  off-site,  how  the 
hydrogen being produced off-site is transported, and the size of the refuelling station 
[5]. 

There are different possibilities to install a hydrogen refuelling station for all types of 
hydrogen vehicles: [5] 

1. Integration in an existing refuelling station: hydrogen as an additional fuel 

option. The prerequisite is that there is still enough space available for the 
storage and dispensers of hydrogen. This option is economically the most 
interesting option, as it leverages on existing infrastructure, such as the service 
building. [6] [7] For example, Shell today builds all his hydrogen refuelling 
stations in existing ones. Furthermore, these locations are already known as 
refuelling stations to vehicle users. 

2. Greenfield project: a new, standalone refuelling station. 

3. Mobile refuelling station: intended for launching a market at a location without 

hydrogen refuelling station or for demonstration projects. 

In a mature market refuelling stations integrated in existing ones are more likely. 

There are two different options for the hydrogen production for refuelling station that 
impact the total costs of the refuelling station.  

1. The first option is the production of hydrogen with an on-site electrolyser. This 
will increase the total investment costs of the refuelling station, due to the cost of 
the electrolyser. Furthermore, the electricity cost might be relatively high, since it 
might be challenging to source excess renewable electricity in the area where the 
refuelling station is situated. 

2. The second option is off-site hydrogen production at a location nearby, with 
cheap excess renewable electricity. This reduces the investment costs of the 
refuelling station, but it adds the costs of transporting the hydrogen from the 
production site to the hydrogen refuelling station. Today, the transport of 
hydrogen is mostly done with compressed hydrogen truck trailers (tube trailers) 
since it is cheaper than liquefied hydrogen for the relatively small volumes needed 
so far. Liquefaction is very energy intensive, amounting to 20 to 30% of the 
energy content of hydrogen [8]  [9]. Furthermore, liquefied hydrogen requires a 
management of the boil-off, which is needed to maintain ambient pressure. 
Typically, the boil-off gas is compressed and stored in an auxiliary gaseous 
storage system, and is therefore less of a problem. The high capital costs 
continue however to be an impediment. 

For the different type of vehicles, distinction in types of refuelling stations can be found. 

January 2018  I  26 

 
 
 
Sectoral integration: long-term perspective in the EU energy system 

Distributed refuelling 

For passenger vehicles, the refuelling stations are geographically distributed. There are 
more  than  115,000  petrol  stations  in  Europe  [10].  One  refuelling  station  distributed 
about 5-10 million litres of fuel every year [11]. 

Figure  3:  Hydrogen  refuelling  station  for  passenger  vehicles  with  two 
compressor stages 

In case of hydrogen refuelling stations, two compressor stages are needed to decrease 
the storage size needed in the passenger vehicle as well as to reduce the refuelling time 
to a few minutes.  

In  Germany,  a  project  has  started  (H2  Mobility  Germany)  to  build  100  hydrogen 
refuelling stations for 2018-2019 [12]. 

Central refuelling for trucks 

There  are  about  4,400  traditional  refuelling  stations  for  heavy  duty  trucks  in  Europe 
with about 370 heavy duty trucks daily using each station.  

A traditional refuelling station sells about 12 million litres per year. Therefore, central 
refuelling stations have a lower marginal cost than distributed refuelling stations, which 
has resulted in many demonstration projects and start-ups for the case of buses, trucks, 
and taxis: 

▪  In Europe about 20 H2 refuelling stations have been funded by FCH JU [13]. 

▪  For the central hydrogen refuelling stations, there are several phases for the H2 

daily consumption increase when the number of hydrogen vehicles increases due to 
the uptake of hydrogen: 

o  Phase 1 – 5 buses – 125 kg H2/day 

o  Phase 2 -  5-20 buses – 125-500 kg H2/day 

o  Phase 3 – more than 20 buses – 500-1000 kg H2/day 

Figure 4: Hydrogen refuelling station for trucks or buses with one compressor 
stage 

For buses and trucks one compressor stage is sufficient in hydrogen refuelling stations, 
since the storage size can be larger than for passenger vehicles.  

Current characteristics of hydrogen-fuelled vehicles and expected 
development 

Carbon-free hydrogen fuelled vehicles have the advantage of only emitting water vapour 
and thus being 100% emission free. Industrial trucks, buses, commercial trucks, taxis, 
and  passenger  vehicles  will  be  analysed.  The  applications  for  buses,  taxis,  and 

January 2018  I  27 

 
 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

passenger vehicles attract more attention due to the size of the market and thus costing 
information is more readily available for these applications than for others. 

Industrial trucks 

Industrial trucks, such as forklifts and tow trucks, run on the road or on a rail system, 
usually  in  enclosed  areas.  The  powertrain  is  either  electric  or  based  on  an  internal 
combustion engine (ICE). The most common storage technology for electrically driven 
industrial trucks is the lead acid battery storage [5]. 

Fuel cell trucks are suitable for indoor activities, due to the absence of harmful exhaust 
emissions  and  low  noise  levels.  An  advantage  over  the  battery  solution  is  the  higher 
operational flexibility, due to the short time for refuelling and constant availability of full 
lifting power. Therefore, in case of multi-shift operation, substantial cost reductions are 
possible compared to battery technologies [14]. 

The  market  today  consists  of  11,000  fuel  cell  industrial  trucks  in  the  USA,  with  an 
average fleet size of 100 trucks. In Europe, there are about 140 fuel cell industrial trucks 
deployed in demonstration fleets (HyLIFT Europe project) ) [5]. 

Buses 

Buses  today  are  the  most  tested  vehicles  for  hydrogen  applications,  with  the  first 
applications  occurring  in  1990  in  the  USA.  Fuel  cell  electric  buses  (FCEB)  receive 
promotion mostly in cities as a clean mobility option. FCEBs today typically consist of 
two fuel cell system of around 100 kW with a small battery to recuperate the braking 
energy, making them de facto hybrid vehicles. They carry about 30-50 kg of compressed 
hydrogen at 350 bar. The technical maturity level is already an achievement, however 
the FCEB have a minority share in the market due to the higher costs compared to ICE 
buses.  The  investment  cost  for  FCEB  today  is  around  €  650,000  while  for  the  diesel 
buses  it  is  around  €250,000.  Currently,  maintenance  costs  are  higher  for  FCEB  than 
diesel buses, i.e. 0.40 €/km for the FCEB compared to 0.30 €/km for the diesel buses, 
however this could be improved if the technology is widespread. [5] 

Today 

Price 

Range 

Maintenance costs 

Fuel consumption 

FCEB 

€650,000 

350-450 km 

0.40 €/km 

Diesel bus 

€250,000 

350-450 km 

0.30 €/km 

8-10 kg H2/100km ~ 267-333 
kWh/100 km (LHV) 

24-40 l/100 km ~ 213-356 
kWh/100 km (LHV) 

Refuelling time 

10-20 minutes 

< 5 minutes 

CO2 emissions wheel-to-wheel  0 

892 g/km CO2 [15] 

Table  1:  Cost  specifications,  fuel  consumption,  refuelling  time  and  CO2 
emissions of the fuel cell electric bus compared to the Diesel bus  

A cost reduction to below €500,000 is expected for2020, and even €350,000 according 
to FCH JU [16]. This cost reduction will be dependent on the accumulated sales of FCEBs, 
determining the learning curve leading to cost reductions. 

The market today consists of several small fleets worldwide which are publicly funded, 
in Europe, USA and Asia. 

January 2018  I  28 

 
 
 
Sectoral integration: long-term perspective in the EU energy system 

Commercial and heavy-duty trucks 

Heavy duty trucks  represent less than 5%  of the vehicles stock, but  represent about 
30%  of  the  CO2  emissions  since  Heavy  duty  trucks  travel  significantly  more  vehicle 
kilometres  than  other  road  vehicles  (Heavy  duty  trucks  travel  over  three  times  more 
than the average passenger car) and consume more fuel per kilometre driven. [17] [18] 
[19] [20] 

2019-2020 

Price 

Range 

Hydrogen 
(Nikola) 

truck 

Electric  semi-truck5 
(Tesla) 

Diesel truck 

NA 

$150,000 

$120,000 

1280-1960 km 

480-800 km 

800-1000 km 

Weight capacity 

32 ton 

10 ton 

10 ton 

Table 2: Cost specifications, range and weight capacity of the hydrogen truck 
compared to the electric truck  

Therefore, it is important to change the technology of this mobility segment to reduce 
greenhouse  gases.  Batteries  have  not  yet  succeeded  to  penetrate  the  market  since 
these trucks do long distances and therefore  would need very heavy batteries with a 
large volume, which is not feasible, as illustrated in Figure 5. However, Tesla will release 
in 2019 an electric transport truck for the expected price of $150,000. [21] This not-
yet-released semi-truck has a limit driving range, a low payload capacity and a relatively 
high cost, thus the success of it remains to be seen. Today, smaller commercial trucks 
already exist that run on a fuel cell. Some first prototypes exist for heavy duty trucks, 
but still need to be tested over long distances. An example of such a prototype is the 
fuel cell heavy duty truck in Switzerland. [22] 

Figure 5: The advantages of the fuel cell compared to a battery for buses and 
trucks  

Taxis 

A taxi operating cycle contains many starts and stops due to the traffic. Therefore, it is 
very suitable for an electric drive system with regenerative braking. A taxi has also very 
varied  duty  cycles  and  daily  driving  distances,  occasionally  requiring  a  long  range. 
Therefore, battery electric propulsion is not perfectly suited, due to the range required 
and the long recharging time. Nowadays, there exists a plug-in hybrid configuration with 
fuel cells extending the range of the taxi. In case that a hydrogen refuelling distribution 
network would be in place, this fuel cell could be replenished quickly. An example is the 
fuel cell Black Cab used for the 2012 Olympics in London, combining a 14 kWh Li-Ion 
battery with a 3.7kg H2 tank (at 350 bar) and a 30 kW fuel cell [23]. 

The Toyota Mirai has been delivered as a taxi in Paris for the Hype project (alongside 
other models), with a total range of 502 km. The vehicle has a 114 kW Fuel cell, a 5 kg 

5 The Tesla truck is called semi-truck because of its semi-autonomous driving capacity 

January 2018  I  29 

 
 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

700 bar H2 storage tank weighing 87 kg, and a 1.6 kWh battery. Air Liquide has installed 
the first H2 recharging station in Paris in collaboration with taxi start-up STEP, and with 
the support of Paris City Council and Ile-de-France. Today, it recharges more than 50 
taxis and the capacity is planned to increase to 600 taxis by 2020 [24] [25].. 

Cost specifications and maintenance can be found in the table of the passenger vehicles, 
see Table 2. 

Passenger vehicles 

Today, manufacturers offer hydrogen passenger vehicles, producing only about 100 fuel 
cell vehicles per year. The market may see a growth to thousands of cars before 2020. 
In 2017, 10 brands were selling H2 fuel cell vehicles, e.g. Toyota, Lexus, Daimler, and 
Hyundai. Since the launch of hydrogen passenger vehicles, the sales reached 5,500 cars 
worldwide. Approx. 10% of these vehicles sales were in Europe and close to 2,400 were 
in the first three quarters of 2017. Passenger vehicles are typically equipped with PEM 
fuel cells of around 100 kW.  

The cost of one H2 passenger vehicle is around €60,000 today, [5] thus about double 
the average gasoline/diesel passenger vehicle. They store usually 4-7 kg of H2 on board 
at 700 bar. 

Today 

Cost 

Range 

H2 passenger 
vehicle 

Gasoline 
passenger vehicle 

€60,000 

€25,000 

Battery electric 
passenger 
vehicle 

€30,000-
€40,000 

400-700 km 

800 km 

100-250 km 

Maintenance costs 

15 €/100 km 

15 €/100 km 

15 €/100 km 

Fuel consumption 

1.1-1.15 kg 
H2/100km ~ 33-66 
kWh/100 km (LHV) 

6 l/100 km ~ 53 
kWh/100 km 
(LHV) 

20 kWh/100 km 

Refuelling time 

3-5 minutes 

1-3 minutes 

90-240 minutes 

CO2 emissions 
wheel-to-wheel 

0 

118-143 g/km CO2  0 

Table  3:  Cost  specifications,  fuel  consumption,  refuelling  time  and  CO2 
emissions  of  the  H2  passenger  vehicle  compared  to  the  gasoline  passenger 
vehicle and the EV  

Other transport modes 

▪  Railway: Demonstrations exist today for light rail vehicles, called Hydrail (hydrogen 

railway). These could be used in locations where electricity rail infrastructures 
cannot be built. The two prototypes that exist today are shunting locomotives and 
railcars, which are fuel cell powered and are used for public rail passenger transport. 
[26] Austria’s Zillertal Railway is also opting for hydrogen fuel cell trains for the 
replacement of a 32 km line between Jenbach and Mayrhofen, that today uses a 
diesel locomotive. The electricity rail infrastructure was opposed by municipalities 
for visual intrusion. Zillertal Railway will build a prototype and launch a tender for 
the series trains by 2022. [27] 

▪  Ships: Today, there are no fuel cells scaled for large merchant vessels, since these 

are too expensive compared to heavy fuel diesel engine used today in these vessels. 

January 2018  I  30 

 
 
 
Sectoral integration: long-term perspective in the EU energy system 

There are however applications in trial phase in small passenger ships, ferries or 
recreational ships. [26] 

▪  Aviation: Small propeller aircrafts have been tested in small demonstration projects, 

where these aircrafts were fitted with PEM fuel cells and Li-Ion batteries for the 
drive. However, also in larger commercial aircraft hydrogen-powered fuel cells are 
viewed as potential energy providers for aircraft since already in space travels they 
are used. [26] 

Applicability of electric vehicles in the mobility sector 

The electrification of the mobility sector is already widely applied for  railway systems. 
In  future,  the  focus  will  be  on  further  penetration  in  road  transport,  making  use  of 
improved battery capacity and ranges. For shipping and aviation, electrification is more 
difficult. This section gives a comprehensive overview of the applicability of electricity 
for the individual mobility segments until 2050. 

Railway 

Electrified  railway networks have been in use  since the late 19th century.  The proven 
technology makes it by far the most electrified transport mode. 53% of the 210,000 km 
railway lines of the EU and 52% of the 350,000 km long railway system of Europe are 
electrified lines (UIC 20176). In the coming years, further electrification of remote tracks 
is expected, reducing the diesel-powered rolling stock. As it is often not cost-efficient to 
install new overhead lines in rural areas, battery driven concepts for remote tracks are 
gaining  attention  and  are  currently  tested  in  research  projects,  e.g.  in  the  UK  and 
Germany, as hybrid or dual-mode propulsion systems (European Commission, 20177). 
The research examines various charging technologies, including platform side charging 
stations (e.g. RailBaar, an automatic overhead electric charging station8). 

Aviation 

Big  aircrafts  used  for  intercontinental  and  international  flights  are  characterised  by  a 
high total energy consumption per flight. Frequent recharging is technically not feasible. 
The energy density  of  batteries is currently too low to  cover the  energy consumption 
with  acceptable  fuel  storage  volumes  and  concepts  are  only  applicable  for  smaller 
engines. For aviation in general, the power-to-weight ratios for battery technology are 
still a long way short of what is required for full electrification. Therefore, is not expected 
that aviation as we know it can be fully electrified before 2030. 

R&D  activity  regarding  the  compliance  of  future  CO2  standards  such  as  for  hybrid 
concepts  is  taking  place.  Research  includes  new  technologies  on  energy  storage  and 
supra  conduction  and  improved  reliability  of  electric  motors.  In  addition,  research  is 
done  on  very  small  aircrafts  for  which  electrification  is  easier.  For  example,  Siemens 
and Airbus presented in 2015 a 2 passenger aircraft with 200 km range.  

Shipping 

Diesel generators (internal combustion motors) produce the electricity used on board 
for lighting, fans, pumps, compressors, and electronics. In Europe, over 500 ships under 
EU  Member  State  flags  use  electricity  for  propelling  instead  of  mechanical  means. 
Electric propulsion offers advantages in performance and efficiency. Typical applications 
of  electric  propulsion  systems  today  are  vessels  with  special  operational  needs  like 

6 UIC (2017): Railway Statistics – 2016 synopsis, International Union of Railways 
7  European  Commission  (2017):  “Electrification  of  the  transport  system”,  Directorate-General  for  Research  and 
Innovation 
8 For more information, see http://opbrid.info/railbaar 

January 2018  I  31 

 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

icebreakers  or  oceanographic  research  vessels,  passenger  cruise  ships  (noise 
reduction),  hybrid  forms  for  offshore  platform  support,  inland  shipping  and  ships  for 
short distances.  

The  common  option  for  electric  propulsion  in  shipping  are  the  diesel  engines.  The 
batteries  are  currently  too  expensive  for  larger  deployment  and  the  energy  densities 
are still too low. With further improvement of energy densities, cargo vessels could use 
battery  electricity  assuming  installation  of  recharging  facilities  and  battery  swap 
systems. Building a charging infrastructure for  ships presents  challenges, if it implies 
high peak charging currents. In addition, the trend for alternative fuels in shipping is 
going toward LNG, and not toward electrification.  

Road transport 

Road transport is a suitable field for electrification. There are two main concepts  that 
compete  with  hydrogen-fuelled  technologies:  battery  driven  concepts  and  direct 
connections to overhead lines. In this report, battery swap is not discussed because of 
the unsuccessful results that are achieved until now (LeVine, 20139). 

Several  European  governments  currently  support  battery  electric  vehicles  as  a 
promising solution for the decarbonisation of the car fleet. The support applies to pure 
electric vehicles (EVs) or on plug-in hybrid models. In 2015, about 500,000 EVs were 
circulating in Europe. 

For trucks, the battery applications usually imply a limited range due to size and weight, 
thus limiting battery applications for now to urban area trips. In the UK, the Netherlands 
and  Germany,  the  e-buses  serve  to  electrify  public  transport.  Several  automobile 
manufacturers are introducing electric cargo trucks e.g. the electric truck of Build Your 
Dreams (BYD) Company Ltd and recently TESLA’s electric truck. Further development 
for electric road transport the situation could change for trucks, making electrification 
also possible for long distance transport. 

An alternative concept for trucks is to provide them with a direct connection to electricity 
overhead  lines.  This  technology  is  mature  and  applies  to  city  buses-trolleys.  The 
application for long-distance travelling trucks requires development of overhead lines in 
motorways; pilot projects of overhead contact line trucks on highways are currently in 
operation.  Alternatives  to  cable  charging  include  battery  swapping  or  continuous 
charging or at least charging while the bus is on the move. 

Figure 6 illustrates the projected EU activity of passenger cars and vans until 2050 by 
type and fuel for the reference scenario. The market domination of gasoline and diesel 
fuelled  cars  will  strongly  decrease  by  2050  although  they  will  still  account  for  almost 
50%  in  2050.  The  highest  uptake  is  for  hybrid  cars  (conventional  cars  with  electrical 
recuperation) with 31%. Despite the ambitious goals of some EU Member States, the 
EU Reference Scenarios show only a limited uptake of electric vehicles with a share of 
9% for plug-in hybrids and 6% for pure electric vehicles in 2050. 

9 For more information see: https://qz.com/88871/better-place-shai-agassi-swappable-electric-car-batteries/ 

January 2018  I  32 

 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

Figure 6: Evolution of activity of passenger cars and vans by type and fuel (E3M 
et al., 2016) 

To  enable  the  wide-scale  electrification  of  cars  and  trucks,  the  road  transport 
infrastructure  requires  significant  changes.  To  allow  long-distance  travels  of  battery 
electric vehicles that exceed the maximum range of the vehicle, a distributed charging 
station  network  is  required  similar  to  the  existing  refuelling  station  distribution.  Fast 
charging  stations  are  required  near  highways  to  allow  for  fast  recharging  times. 
Furthermore,  private  and  sufficient  public  charging  stations  are  required  to  allow 
charging at home and in cities.  

Today,  a  higher  coverage  of  charging  stations  is  necessary  to  develop  in  most  EU 
Member  States  to  promote  EVs.  However,  the  charging  stations  existing  today  suffer 
from low utilisation rates that undermine their economic viability and discourage further 
investment in charging stations. Figure 7 shows the number of plug-in electric vehicles 
(including plug-in hybrids and pure EVs) per charging point in European countries. Only 
10  out  of  the  33  countries  have  more  than  five  plug-in  electric  vehicles  per  charging 
point. 

January 2018  I  33 

 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

Figure 7: Plug-in electric vehicles per charging point; 0-5 (blue), 5-25 (green), 
>25 (red); (Source: Ecofys based on EAFO 201710) 

Trucks using overhead lines to cover the electricity demand rely on overhead lines for 
long-distance travels. Overhead lines could cover specific routes or most highways to 
allow  maximum  flexibility.  In  some  European  cities,  overhead  line  systems  exist  for 
buses (e.g. Tallinn, Estonia).  

Impact of road transport electrification on the power sector 

The electrification of road transport also has impacts on the power sector. In general, 
electrification increases total electricity demand and is likely to increase peak demand, 
which requires grid expansions. Firstly, the increase in local (peak) demand, especially 
in residential areas with high EV use and areas with fast charging stations, stresses the 
local distribution grid. Secondly, the increase in system (peak) demand and residential 
load centres puts pressure on the transmission grid. Intelligent loading and use  of EV 
batteries as a local flexibility source could reduce potential grid constraints. Simulations 
of the poser system show that intelligent loading systems can offset the adverse effects 
on peak load. However, the implementation of this intelligence at a large-scale is costly 
and requires technological development. 

Linking the power sector and hydrogen-demanding industry 

The power-to-hydrogen conversion chain 

Today hydrogen is traditionally produced with a Steam Methane Reformer (SMR), which 
produces hydrogen from natural gas (CH4 + H2O <-> H2 + CO) at high temperatures of 
about  700-1100  °C  in  the  presence  of  a  catalyst.  For  large  industries  (refineries, 
fertilizer industries) such an SMR is usually found on-site. The cost of H2 produced with 
a SMR is in the range of 1,800-2,250 €/t H2 and it produces about 7.2 kg CO2/kg H2. 
The cost of hydrogen from steam methane reformers is dependent on the carbon price 

10  EAFO  (2017):  Electric  vehicle  charging 
charging-infrastructure, accessed 16th Nov 2017, European Alternative Fuels Observatory 

infrastructure,  http://www.eafo.eu/electric-vehicle-

January 2018  I  34 

0255075BulgariaCroatiaMaltaSlovakiaSloveniaIrelandCyprusCzech RepublicDenmarkEstoniaNetherlandsPolandRomaniaSpainFinlandHungaryLatviaPortugalAustriaGermanyItalySwitzerlandGreeceLithuaniaTurkeyFranceUnited KingdomLuxembourgSwedenNorwayBelgiumIcelandPEVs per charging point 
 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

in the majority of cases, as they are mainly found in large industries and therefore are 
included in the ETS. [28] has found that already a price of 28€/t CO2 would increase the 
cost of hydrogen from SMR by 202 €/tH2. [29] 

Table 4: Steam Methane Reforming process  

A  carbon-free  alternative  is  producing  hydrogen  with  an  on-site  electrolyser  that  is 
electrically fed by locally produced renewable electricity, e.g. with solar panels or wind 
turbines.  A  constant  hydrogen  flow  is  guaranteed  by  oversizing  the  electrolyser  and 
installing a gaseous storage (30 bar). This would reduce the greenhouse gas emissions 
footprint considerably. An alkaline electrolyser today costs between 650 and 1,000 €/kW 
with an efficiency of 55 kWh/kg H2. The cost of H2 produced on site with an electrolyser, 
compressor  and  gaseous  storage  is  between  2,810-3,200  €/ton  H2  with  a  55%  load 
factor  and  low  electricity  cost  of  35  €/MWh,  without  considering  the  costs  of  the 
renewable energy investment.  

Today the production of hydrogen with SMR is still cheaper than carbon-free hydrogen 
production with an electrolyser.  At a carbon price of 78-140 €/kg CO2 green hydrogen 
production could become economically more interesting. However, this calculation does 
not  consider  other  possible  side  revenues  streams  from  the  carbon-free  hydrogen 
production, such as oxygen sales, heat at 85°C for district heating and grid services in 
the form of flexibility delivered by the electrolyser. 

Sustainable hydrogen-based processes in industry 

Cement industry 

The cement industry is a multi-stage process. Typically, a cement plant consumes about 
100 kWh/tonne cement of electricity and 900 kWh/tonne cement of heat. A typical plant 
size  is  1  mtpa  cement  and  in  case  of  a  flat  profile  a  production  of  114  tonne 
cement/hour.  It  implies  a  demand  of  11  MWh  electricity  and  101  MWh  heat.  Heat 
requirements are at a high temperature of around 800-1,200 °C in a tower.  

Therefore, there are two  reasons why a hydrogen fuel cell will not suffice to produce 
combined heat and power. One is the too high temperature heat demand and the other 
is  the  electricity  to  heat  ratio  of  a  cogeneration  unit  which  is  incompatible  with  the 
electricity-heat  ratio  of  demand  in  the  cement  industry.  Alternatively,  there  is  a 
possibility  to  use  a  hydrogen  in  the  cement  kiln  to  replace  part  of  the  fossil  fuels. 
Hydrogen has flame temperatures of about 3200 °C. However, replacing traditional fuels 
(coal,  petroleum)  with  hydrogen  in  the  rotary  kiln  of  the  cement  factory  can  be 
complicated  requiring  engineering  adaptations  at  a  significant  scale.  The  reasons  are 
the following [28]:  

January 2018  I  35 

 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

▪  The change of composition of the off-gas would require changes in the downstream 

processes. 

▪  A considerable amount of hydrogen would leave the furnace with the off-gas, 

limiting the benefits. 

▪  Due to the simultaneous injection of air, hydrogen blast furnaces present safety 

issues. 

Today, there are no European projects dealing with use of hydrogen in furnaces.  

Fertilizer industry 

The  fertilizer  industry  requires  hydrogen  to  produce  ammonia,  which  is  used  in  most 
fertilizers, such as urea, ammonium nitrate, and diammonium phosphate. The following 
chemical reaction produces ammonia with nitrogen and hydrogen: 

𝑁2 + 3𝐻2 → 2𝑁𝐻3 

This reaction is exothermic, thus besides compressing the nitrogen and hydrogen, no 
additional energy is needed since thermal energy is recuperated with heat exchangers. 
Therefore, a fuel cell could be useful to produce electricity for the ammonia plant.  

But, as is evident in the equation above there is also a direct hydrogen demand. For 1 
ton of ammonia, 0.18 tonne of hydrogen is needed. A typical plant size is 0.7 mtpa of 
ammonia. This results in 0.12 mtpa of hydrogen or thus 14.1 tonne H2 /hour in case of 
a flat profile. Today, ammonia plants use SMR to produce hydrogen from natural gas. 
To have a constant output of carbon-free hydrogen, oversizing of the electrolyser would 
be necessary, as well as installing a large (gaseous) hydrogen storage, since variable 
renewable energy sources do not have a constant electricity output. 

Thus, the ammonia industry would be the most promising industry due to its large direct 
hydrogen demand. The EU fertilizer industry has a total ammonia capacity of 21 mtpa 
or thus a total demand of 3.7 mtpa H2. 

Steel industry 

The  steel  industry  is  a  multi-stage  process  with  an  electricity  consumption  of  390 
kWh/tonne steel and heat consumption of about 205 kWh/tonne steel at temperatures 
of  900-1300  °C  [30].  Also  chemical  energy  consumption  of  125  kWh/tonne  steel  is 
required in the form of energy arising from the oxidation of elements such as carbon, 
iron, silicon and the burning of gas in oxy-fuel burners. A typical plant size is 3 mtpa of 
steel and thus 342 tonne steel/h in case of a flat profile.  

The  electricity  demand  is  134  MW  and  heat  demand  70  MW  per  hour.  The  high 
temperature requirements make a fuel cell inappropriate for the full cogeneration. On-
site electricity production could use a fuel cell. 

Hydrogen  produced  with  high  temperature  electrolyser,  such  as  the  Solid  Oxide  Fuel 
Cell  SOFC,  could  be  deployed  today  in  existing  annealing  processes,  according  to 
Salzgitter  [31].  Hydrogen  can  create  the  needed  inert  atmosphere  in  the  annealing 
process (inert meaning without oxygen), to prevent the oxidation of steel.  

Also,  it  could  be  partially  used  as  a  reduction  agent  in  the  blast  furnace  instead  of 
carbon. Hydrogen is also less endothermic than reduction by carbon which is used today 
and thus improves the heat balance [32].. 

This would result in a flat profile of 9 tonne H2 /h to produce 342 tonne steel/h. 

𝐹𝑒2𝑂3 + 3𝐻2

→        2𝐹𝑒 + 3𝐻2𝑂  
𝑇@1100°𝐶

January 2018  I  36 

 
 
 
Sectoral integration: long-term perspective in the EU energy system 

Using  the  waste  heat  from  the  steel  processes  for  the  electrolysis  could  increase  the 
efficiency of the electrolyser. In case that electricity is too expensive (low availability of 
renewable electricity), the system at Salzgitter can be switched to a fuel cell mode with 
natural  gas  from  the  grid  to  have  a  reliable  power  supply.  Today,  such  a  reversible 
system from Boeing Company and Sunfire, which is used at Salzgitter, has a maximum 
power of 100 kW in SOEC mode and 20 kW in SOFC mode [33]. 

Refining industries 

Hydrogen is mainly used in the refineries for the desulphurisation of the crude oil. Due 
to  European  regulations  and  lower  crude  oil  quality,  European  refineries  need  to 
consume  high  amounts  of  hydrogen.  Currently,  the  refineries  commonly  use  on-site 
SMR and hydrogen pipelines for internal transport. Depending on incentives regarding 
the reduction of carbon intensity, it would be possible to install on-site H2 production by 
electrolysis (an example is the P2H project). 

A typical refinery produces roughly 5000 ktpa of oil and consumes between 3.2-7.2 kg 
H2/tonne oil. This implies an annual H2 production requirement of 16-36 ktpa or 1.8-4.1 
ton H2/h in case of a flat profile. 

Linking the power and heating sector 
The power and heating sector have been linked historically on the power  supply side 
through  cogeneration.  Currently,  operation  is  mostly  heat-driven  with  electricity  as  a 
by-product due to limited heat storage facilities and low power prices. Operation may 
move from heat-driven to electricity-driven cogeneration along with the development of 
power systems highly based on intermittent renewable sources generation to provide 
the required flexibility for the power system.  

The increasing relevance of electricity to cover heat demand directly calls for power-to-
heat applications (both central in district heating systems and decentralised) with the 
aim  to  decarbonise  the  heating  sector  and  provide  flexibility  to  the  power  sector.  In 
addition to electrification of heat demand there are also other  options to decarbonize 
the heating sector:  

▪  Biomass: First, biomethane can be produced, which is used in existing gas 

infrastructure. Secondly, pellets can be made that are used in stoves. The main 
challenge of biomass is the limited availability of biomass that is produced in a 
sustainable way (e.g. not competing with food production).  

▪  Solar thermal systems: Solar thermal technology uses the sun’s energy to generate 
low-cost, environmentally friendly thermal energy. This energy is used to heat water 
or other fluids. Solar thermal systems differ from solar photovoltaic (PV) systems, 
which generate electricity rather than heat. As solar thermal systems are often 
placed on rooftops, it has limited space available and competes for this space with 
other systems such as solar PV and green roofs. The relative business case of solar 
thermal depends highly on country specific factors. 

▪  Geothermal heat: Geothermal energy is the heat from the Earth. Resources of 

geothermal energy range from the shallow ground to hot water and hot rock found a 
few miles beneath the Earth's surface. One of the main challenges faced by 
geothermal developers is the combination of geological uncertainty with high 
upfront costs and the resulting difficulty in acquiring adequate financing. 

▪  Waste heat: Waste heat that is recovered from industrial processed can be used to 
provide district heating to the residential buildings and offices. One of the main 
difficulties for waste heat is the uncertainty, or lack of commitment, of the supply of 

January 2018  I  37 

 
 
 
Sectoral integration: long-term perspective in the EU energy system 

waste heat for the economic lifetime of the assets that are required to transport the 
heat from where it is generated to where the heat demand is.  

The focus of this section is on electrification, so not on the other options of decarbonizing 
the heat demand or on cogeneration. 

Overview power-to-heat conversion technologies 

Power-to-heat technologies (PtH) act on the power demand side. They can generally be 
divided  into  centralized  and  decentralized  applications.  The  figure  below  gives  an 
overview on PtH in the residential sector. In the case of centralised PtH, electricity is 
converted into heat at a location distant to the place of consumption and is distributed 
via a district heating network. Decentralised PtH is generated close to residential blocks 
or single houses and can directly be used through fans and radiators, or be stored for 
later  consumption.  Storage  can  be  differentiated  by  external  storage  and  internal 
storage.  External  storage  is  located  outside  of  the  product  that  generates  heat,  for 
example a water basin. For internal storage the heat is stored within the same product 
that is generating it, for example an electric thermal storage system, a technology that 
stores the heat in ceramic bricks of the heating application itself. So internal storages 
come  in  the  form  of  smart  electric  storage  heating,  while  external  storage  through 
buffers can be supplemented by heat pumps and resistive heating.  

Figure 8: PtH technologies in the residential sector (DIW 2017) 

The two main PtH technologies are heat pumps and resistive heating. While heat pumps 
offer highly efficient heat supply connected to high investment costs, resistive heating 
has  comparably  low  investment  costs  but  also  lacks  efficiency.  This  makes  the  latter 
more suitable for peak supply applications, as the need for peak supply is very limited, 
so  the  investment  cost  should  be  as  low  as  possible  and  operational  cost  and/or 
efficiencies are of less importance. 

Heat pump technologies 

We distinguish three heat pump technologies: 

January 2018  I  38 

 
 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

1.  Air source heat pumps using ambient energy in air 

2.  Water source heat pumps using energy stored in water 

3.  Ground source or brine heat pumps use geothermal energy stored in the ground 

using a vertical or horizontal collector 

The applicability of heat pump technologies is dependent on local energy resources and 
building specifications such as access to water or ground, and the space needed for air 
heat pump systems.  

The efficiency of a heat pump is measured using the seasonal performance factor (SPF) 
and  dependent  on  the  building  conditions  (supply  temperature  level)  and  the  local 
environmental  conditions (ambient temperature of heat  resource). The SPF for space 
heating (35°C) varies between: 

1.  4.5 for air HP 

2.  < 6 for water HP 

3.  4.5 – 5.5 for brine HP 

SPFs for higher space heating temperatures can be significantly lower (Ecofys, 201311). 

When  comparing  European  countries,  large  differences  in  the  market  deployment  of 
heat pumps become visible. While markets like Germany, Austria, UK, Belgium, France 
as well as Italy and Spain are strongly growing, Sweden had already reached saturation 
levels of more than 20% of the total energy demand for heating and heat pumps account 
for 45% of the turnover on the heating market in 2014 (Ecofys, 2013; Profu, 2014 12). 
The strong uptake in annual heat pump sales in Sweden since the mid-1990’s can be 
explained by a vast increase of the carbon tax. 

In contrast to heat pump applications in the residential sector, the industry sector only 
has  limited  potential,  as  most  industrial  processes  require  significantly  higher 
temperatures. Still, there exist applications in industries like the nutrition sector, where 
heat pumps > 100 kWth can provide heat with temperatures up to 130°C. 

Resistive heating 

Resistive  heating  can  be  provided  in  the  form  of  electric  boilers  or  electric  heating 
elements in boilers that are fuelled by some other form of primary energy as so-called 
hybrid heating.  

In  central  PtH  it  can  be  used  in  peak  times  to  convert  otherwise  curtailed  renewable 
energy  at  low  cost.  In  the  industry  where  heat  pumps  only  provide  a  limited 
temperature, it can be used for steam generation. Nevertheless, it has to compete with 
conventional options and thus has currently only a limited potential. In the residential 
sector  heat  pumps  have  a  predominant  role  but  can  be  supplemented  with  resistive 
heating in special cases. 

Overview thermal storage options 

To enable a shift towards a more power-driven cogeneration and thus more flexibility in 
the  power  sector,  thermal  storage  solutions  are  needed.  Not  only  CHP  is  a  possible 
application area, but also storages for central (district heating network) and decentral 
(buildings, industrial) use. The varying heat demand can be balanced on a daily, weekly 
or  seasonal  basis.  As  a  result,  peak  demand,  energy  consumption  and  emissions  are 
reduced, and efficiency increased.  

11 Ecofys (2013): Heat pump implementation scenarios until 2030 
12 Profu et al. (2014): The heating market in Sweden – an overall view 

January 2018  I  39 

 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

Thermal energy storages can be categorised by: 

▪  Temperature range (High temperature 300°-600° C for solar thermal, glass and 
steel industry; Process heating and steam generation 100-250°C; Heating of 
buildings 25-90°C; air conditioning 5-18° C) 

▪  Storage period: buffer (hours to days); seasonal (months)  

▪  Location: central (renewables power plant, district heating, large industrial) or 

decentral (buffer storage for buildings) 

There are three main thermal storage technologies: 

▪  Sensible thermal storage: Sensible storage is characterised by a change of 

temperature during the storing process. The storage medium is heated or cooled, 
and the transferred energy depends on the specific heat capacity of the medium. A 
commonly used option is water due to its low cost, environmental compatibility and 
high heat capacity. Other storage materials are sand, molten salts and rocks. 
Sensible heat storages are commonly used in heating systems with buffer storages. 

▪  Latent thermal storage: Latent energy storages make use of the energy that is 
set free during phase changes, mostly from solid to liquid state. The core of latent 
thermal storages uses phase change materials (PCM). The temperature of the PCM 
stays mostly constant during the charging process. Growing research interest is 
directed towards phase change slurries (PCS). Latent heat materials are combined 
with water to benefit from pumping characteristics and of a liquid while having high 
energy density levels of latent heat storages.  

▪  Thermochemical thermal storage: For thermochemical thermal storage, 

reversible chemical reactions are used to store and release thermal energy. In a 
desorption process, heat is charged through the supply of energy and discharged in 
a sorption process. The process can offer the highest energy densities, but the 
system configuration is complex and involves high investment costs. There are 
currently almost no applications and there is a need for further research. 

Sensible thermal storage is a proven technology and widely applied in residential heating 
(central and decentral). Its disadvantages compared to latent and thermochemical heat 
storage  are  lower  energy  densities  and  thus  require  larger  storage  volumes.  Latent 
thermal storages have slower charging rates compared to sensible thermal storage. 

As seen in the table below, sensible thermal storage has the least costs, with insulation 
being the largest driver. With complex constructions, expensive storage materials and 
a low level of development the cost for latent storage is significantly higher. Materials 
for  thermochemical  applications  have  similar  prices  as  latent  thermal  storage  (here 
PCM)  but  need  an  additional  treatment.  Main  cost-driver  is  the  complex  reactor  and 
further required peripherals.  

TES System 

Capacity 
(kWh/t) 

Power 
(MW) 

Efficiency 
(%) 

Storage 
period 

Cost 
(€/kWh) 

Sensible 
water) 

(hot 

10-50 

0.001-10 

50-90 

Latent (PCM) 

50-150 

0.001-1 

75-90 

Thermochemical  120-250 

0.01-1 

75-100 

Days 
moths 

Hours 
months 

Hours 
days 

to 

0.1-10 

to 

10-50 

to 

8-100 

Table 5: Thermal storage techniques 

January 2018  I  40 

 
 
 
Sectoral integration: long-term perspective in the EU energy system 

Central, seasonal storages require large storage volumes but have only 1-1,5 cycles per 
year and therefore require cheap mediums like water but very high insulation to reduce 
heat losses. For central residential heating, the district heating network is also used as 
a buffer storage.  

Benefits for electricity sector  

The  growing  share  of  renewables  in  power  generation  leads  to  increasing  generation 
peaks and curtailment due to grid constraints. In general, the increase in electrification 
leads to a higher electricity demand but it can also add system flexibility if the demand 
is shifted intelligently into times of high supply. The excess electricity can be used by 
increasing the electricity demand during these times.  

The flexibility potential of power-to-heat technologies is dependent on the heat demand 
and the ability to store the heat. Intelligently controlled power-to-heat applications in 
combination with thermal storage have multiple benefits for the power sector based on 
their increase in electricity demand-side management potential. The enlargement of the 
flexibility of the electricity system leads to the following benefits: 

1. Local integration of renewable energies (short-term): The use of excess 

electricity for local heat generation reduces local curtailment and thus improves 
local integration of renewable energies. 

2. System balancing (short-term): On the system level, the flexible load can be 
used for system balancing reducing system operation costs by avoiding operation 
of expensive power plants (Ecofys, Prognos, 201113). 

3. Reduced required installed capacity (long-term): A significant increase in 

system flexibility that is controlled based on the system situation can have a long-
term impact on the required available installed capacity of the power plant fleet. 
This can lead to long-term savings for the provision of power plants, especially if 
the capacity is remunerated by the market, e.g. via capacity markets (Ecofys, 
201614). 

The  potential  benefits  are  dependent  on  the  technical  controllability  of  the  power-to-
heat applications and the market incentives.  In the industry and  commercial sectors, 
demand-side management technologies are increasingly used to reduce energy costs. 
For  households,  the  roll-out  of  intelligent  metering  devices  offers  the  opportunity  of 
intelligent demand-side management in this sector. However, to make most use of the 
potential benefits of power-to-heat for the power sector, market incentives need to be 
set  accordingly.  Demand-side  flexibilities  will  only  be  operated  in  a  system  friendly 
manner, if the wholesale or control energy markets give sufficient financial incentives. 
On  the  other  side,  a  system  oriented  behaviour  can  contradict  with  the  local  grid 
situation at the same time. Thus, system prices can set contradictory incentives. Local 
markets could set the right prices to reduce local grid congestion and improve regional 
renewable energy integration, but could also conflict with the system situation. In total, 
a comprehensive approach is needed to use local power-to-heat flexibilities in the most 
beneficial way. 

Hybrid  heat  pump  systems  can  have  strong  benefits  for  the  power  sector.  The 
combination of an electric heat pump combined with a peak supply technology (e.g. a 
natural  gas  boiler)  is  more  flexible  than  pure  electric  heat  pump  systems.  The  peak 
supply technology can also be used in high load times of the power system to cover the 
heat demand if the thermal storage cannot cover the heat demand anymore.  

13  Ecofys,  Prognos  (2011):  „Potenziale  der  Wärmepumpe  zum  Lastmanagement  im  Strommarkt  und  zur 
Netzintegration erneuerbarer Energien“ 
14  Ecofys  (2016):  „Flex-Efficiency.  Ein  Konzept  zur  Integration  von  Effizienz  und  Flexibilität  bei  industriellen 
Verbrauchern“ 

January 2018  I  41 

 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

Linking hydrogen to the heating sector 

Hydrogen  based  heating  technologies  have  not  been  in  focus  much  of  the  European 
debate  on  the  decarbonisation  of  the  heating  sector  until  now.  However,  there  exist 
multiple technologies that have been applied in international – mostly Asian – markets. 
There exist four main hydrogen-based technologies for use in households (Dodds et al., 
200515): 

1. Fuel cell mirco-CHP: The most established hydrogen utilisation is in the form of 
fuel cell CHPs. However, for buildings the fuel cells micro-CHP runs currently on 
natural gas, which is converted to hydrogen within the product, therefore it does 
not interfere so much with the market for hydrogen. While fuel cells are usually 
known for their highly efficient electricity production, they do also provide heat. 
Since fuel cells are modular existing small-scale applications can easily be scaled 
up. Protone-exchange-membranes fuel cells (PEMFC) are the most developed fuel 
cell technology suitable for decentral residential heating and account for 90% of 
total fuel cell systems sold. Solid oxides fuel cells (SOFC) are also used in 
household heating system sizes. Currently, SOFC and PEMFC have total 
efficiencies of 80-90% and 95% respectively.  

2. Direct flame combustion boiler: Direct flame combustion boilers powered with 
hydrogen are functionally identical to European natural gas boilers. In operation, 
there is no difference for the consumer. 

3. Catalytic boilers: Hydrogen can be used in catalytic boilers in which it is passed 
over a reactive metal catalyst. The exothermic chemical reaction produces heat 
that can be used for domestic heat supply. Catalytic boilers have no flame and do 
not emit any NOx in contrast to conventional gas boilers in residential heating. 

4. Gas-powered heat pumps: Hydrogen can be combusted in gas heat pumps to 
generate the phase change instead of an electric compressor which is used in 
electrical heat pumps. Besides this, the concept of both heat pump types is the 
same. 

In  Europe,  fuel  cell  programmes  have  led  to  first  installations  in  multiple  countries. 
However, hydrogen based heating technologies are not widely distributed in Europe. In 
the EU, demonstration projects started in 2008 and are part of the goal to install 50 000 
systems with a subsequent commercial roll-out until 2020. 

In  other  markets,  ambitious  goals  and  support  programmes  led  to  a  large-scale 
implementation of fuel cells. Technology deployment of fuel cell micro-CHPs for domestic 
use  was  supported  in  particular  in  Japan  and  South  Korea.  The  Japanese  support 
programme with about € 200 million per year for more than 10 years has led to a strong 
growth and a decrease of prices of 85% in Japan over ten years.  

Despite  the  potential  for  the  decarbonisation  of  the  heating  sector  and  the  improved 
integration of renewable energies by using excess electricity for hydrogen generation, 
the ability of CHPs to operate during black-out times makes them favourable in certain 
regions.  However,  the  relatively  high  investment  costs  are  still  a  challenge  for  this 
technology today. In the future hydrogen could play a bigger role, especially in off-grid 
areas.  Within  off-grid  areas  there  are  a  limited  number  of  flexibility  sources  that  can 
ensure  the  balance  in  the  system.  Therefore  electrolyses  and  hydrogen  could  play  a 
relatively big role. 

15 Dodds et al. (2015): Hydrogen and fuel cell technologies for heating: A review, International Journal of Hydrogen 
Energy, Volume 40, Issue 5, 9 February 2015, pp. 2065-2083 

January 2018  I  42 

 
 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

Energy storage and sectoral integration 

This chapter lays out the technical options for hydrogen storage. It aims to show the 
role of hydrogen and methanation to decarbonise the gas grid, and in a broader sense 
the contribution of hydrogen based flexibilities to the energy transition. 

In  general,  the  role  of  energy  storage  will  become  more  important  in  a  sustainable 
energy system in the future. Navigant research estimates that 1,500 GW of additional 
global energy storage capacity is expected to be installed over the next 10 years for the 
integration of large scale renewables. There are a variety of technical storage options 
known that can provide different services for the energy sectors. First, there are storage 
options for short term (up to minutes) uses that require high power capacity, but low 
energy capacity, such as supercapacitors, flywheels and some batteries. Secondly, there 
are  options  for  medium  term  storage  (up  to  a  day),  for  example  batteries  and 
compressed-air-energy-storage (CAES). Finally, there is the need for long-term storage, 
to bridge the difference in energy supply and demand between seasons, therefore power 
to gas will play an important role. The most applied form of storage today is pumped 
hydro storage, which can be used for all of the time scales, and is relatively cheap in 
certain areas with right conditions (e.g. mountains), which makes it a preferred option. 
However, this the use of pumped hydro storage will only be applied in a limited number 
of regions, in other regions power to gas will be required.   

Hydrogen storage 

Hydrogen  can  be  stored  similar  to  other  conventional  energy  carriers.  The  energy 
density  of  hydrogen  rises  with  increasing  compression.  Liquefied  hydrogen  has  the 
highest density and thus requires the least space. However, due to the low boiling point 
of  hydrogen  of  -253  °C,  cryogenic  storage  systems  need  strong  insulation  to  reduce 
evaporation losses.  Moreover, liquefaction of hydrogen is energy intensive, amounting 
to more than 20%-30% of the energy content of hydrogen) and increases the economic 
costs of storage systems significantly.  

Hydrogen can be stored centrally at a large-scale and in decentralised facilities usually 
close  to  consumers.  Hydrogen  can  be  also  stored  in  small  decentralised  storage 
systems. Tanks are suitable for on-site storages close to generation facilities, and for 
household and mobile storages. Low pressure tanks only hold hydrogen at 50 bar while 
for intermediate storage pressures up to 1000 bar are possible. To mitigate the weight 
of the tanks composite materials are used. This is particularly important in the mobility 
sector. In stationary applications steel tanks provide secure storage. 

For centralised hydrogen storage, there exist three main options: 

1. Salt caverns: The most common option for central hydrogen storage are salt 

caverns, artificially created underground cavities. They provide large underground 
storage of more than 500,000 m³ and at more than 200 bar per cavern are 
possible. Historically salt caverns have been used for natural gas storage but the 
applicability for hydrogen injection has been shown in projects in the UK and the 
US. Special focus regarding the hydrogen application is on the materials’ 
hydrogen-tightness but also on the special security requirements that affect the 
acceptance for this form of storage. The potential of a cavern as a storage 
solution depends on the geological structures (high potential in Germany, Poland, 
United Kingdom, Spain, Romania). The main advantages of caverns are the high 
capacities of single sites and the availability, high safety as well as relatively low 
costs. 

2. Porous storages: Hydrogen can be stored in porous storages, old extracted 

natural porous deposits. In most cases depleted natural gas or oil reservoirs are 

January 2018  I  43 

 
 
 
Sectoral integration: long-term perspective in the EU energy system 

used, since they are already well explored. Due to the possible contamination of 
the hydrogen with hydrocarbons in porous storages, additional “filtering” of the 
hydrogen can be required after extraction. The high reactivity of hydrogen with 
different minerals inside porous storages can lead to gas losses and impaired 
flowing properties. 

3. Aquifers: A third possibility for hydrogen storage are aquifers. In contrast to 
porous storages these permeable rock reservoirs were formerly filled with salt 
water. Regarding gas purity and safety, they suffer the same disadvantages as 
porous storages and their exploration is challenging.  

The  best  option  for  a  large  scale,  central  hydrogen  storage  are  salt  caverns  because 
they  are  technically  hydrogen-tight  and  are  not  affected  by  contamination  or 
biochemical reactions. Porous storages become more relevant with increasing storage 
needs.  

Emerging technologies 

Upcoming technologies currently researched deal with different materials: 

▪  Metal hydrides: Hydrogen is adsorbed by metal, which leads to formation of metal 
hydrides. To free the hydrogen again, the storage needs to be heated. This storage 
method offers good volumetric capacity, but the storages are heavy. Advantages 
are the no evaporation losses and the purifying effect of metal. 

▪  Liquid organic hydrogen carriers (LOHC): This method applies the chemical 
bond of hydrogen molecules to the liquid carrier material through a catalytic 
reaction. Hydrogen is stored in a non-molecular form. Advantages are the high 
storage density and easy handling and transportation in diesel-tanks16. 

▪  Nano-structures: Building nanostructured porous materials from metallic organic 
compounds, vats amount of hydrogen can be stored in high densities. One of the 
main challenges is to find a material which has a controllable hydrogen affinity 
whilst being able to store and release hydrogen in a short time. 

Impact of hydrogen based flexibilities on decarbonisation of the gas grid 

Hydrogen feed-in into the gas grid, generated via power-to-gas from renewable energy 
sources, is one option for the decarbonisation of the gas grid. Hydrogen can be injected 
directly into the existing gas grid up to a level of about 0-12% depending on country 
specific  standards  and  regulation  (Newton,  2014)17.  Large-scale  feed-in  of  hydrogen 
into  the  transmission  gas  grid  requires  additional  compression  of  the  generated 
hydrogen to 60 bar. Feed-in in distribution gas grids which are operated with 5 to 10 
bar does not require additional compression (ENEA consulting, 201618). Due to the high 
interconnectivity  of  the  European  gas  grid,  methane  can  be  fed  into  the  gas  grid  at 
basically every point with limited gas infrastructure expansion needs. Hydrogen can be 
fed into the gas grid without restrictions if the hydrogen is converted to methane, so 
called “carbon-free gas”, in a methanation process (named the Sabatier process). The 
CO2 needed for the process can be provided from biogas, fossil power plants or from 
carbon  capture  technologies.  There  are  already  experiments  in  the  EU  that  test  this 
process, like the one of Stedin in Rozenburg (Stedin, 201419). However, this process is 

16 For more information, see http://www.hydrogenious.net 
17 Newton, J. (2014): Power-to-Gas and Methanation – pathways to a 'Hydrogen Economy', in: 14th annual APGTF 
Workshop, London, 2014, ITM Power 
18 ENEA consulting (2016): “The potential of power-to-gas - Technology review and economic potential assessment” 
19 For more information see: https://www.stedin.net/over-stedin/pers-en-media/persberichten/powertogas-officieel-
geopend-elektriciteit-wordt-aardgas-in-rozenburg 

January 2018  I  44 

 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

still far away for large scale deployment as the price for natural gas is still low and cost 
for hydrogen are high.  

Another idea is to transport 100% hydrogen gas within the existing gas grid. This would 
require  one  conversion  step  less  compared  to  the  methanation  process  but  would 
require extra investments in the gas grid and for consumer appliances.  There are no 
existing examples of a 100% hydrogen grid that is used within the urban environment. 
Leeds is seriously investigating the options for a hydrogen grid (Northern Gas Networks, 
201720). 

Contribution of hydrogen based flexibilities for the energy transition 

A decarbonised gas grid enables the opportunity to use carbon-free gas in the existing 
connected gas power plants. Excess electricity can thus  be stored via electrolysis and 
methanation  in  the  gas  grid  and  the  stored  energy  can  be  used  in  power  plants  for 
electricity generation. This process chain is called power-to-gas-to-power.  

Figure 9: Linking the power and the gas infrastructure via hydrogen (European 
Power to Gas Platform, 2017) 

Figure 9 illustrates the interactions of the power infrastructure and the gas infrastructure 
related to hydrogen. Electricity is stored in the gas grid via electrolysis and methanation. 
“Carbon-free gas” from the gas grid can be used in the industry and mobility sector, for 
heating and for power generation. 

The benefits along with the power-to-gas-to-power process are: 

▪  Seasonal energy storage: The gas grid offers seasonal storage capacities. The 
natural gas grid with the connected gas storages is the biggest existing energy 
storage. 

▪  Increase in system flexibility: The decarbonisation of the power sector leads to a 
long-term phase out of conventional power plants. Gas power plants are considered 
by some as a transition technology. With the decarbonisation of the gas grid, gas 

20https://www.northerngasnetworks.co.uk/2017/04/27/northern-gas-networks-hydrogen-project-takes-step-
forward-as-25-million-fund-announced-for-hydrogen-in-homes/ 

January 2018  I  45 

 
 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

power plants could be operated based on carbon-free gas from renewable energy 
sources and could take a leading role in central flexibility supply for system 
balancing. 

▪  Energy transmission: The increase in intermittent renewable energy generation 
requires higher interregional exchanges. Power transmission capacities are limited 
and grid congestion is a burden for renewable energy integration, thereby increases 
system cost. Gas transmission capacities in Europe are usually greater than power 
transmission capacities and could help temporarily to reduce power grid congestion. 
In the long-term, a comprehensive transmission system planning approach for gas 
and power infrastructure could make use of the gas transmission capacities to 
transport large quantities of energy within Europe.  

However, the process power-to-gas-to-power has high energy losses. In addition to the 
losses  of  the  hydrogen  generation  via  electrolysis,  losses  arise  in  power  generation 
where current large-scale gas power plants reach efficiencies of up to 60% (combined 
cycle gas power plants) with possibilities to only slight increases up to 64% projected 
for  2030  (IEA  201021).  Efficient  centralised  gas  CHP  plants  reach  higher  combined 
efficiency for the electricity and heat supply, but have a lower electric efficiency.  

Specific key regions 
This  section  analyses  regions  in  Europe  where  carbon-free  production  of  hydrogen  is 
possible  due  to  local  overproduction  of  renewables,  which  today  may  suffer  from 
curtailment. The excess carbon-free electricity could feed a power-to-hydrogen facility. 
The  section  also  deals  with  possible  locations  of  H2  demand  in  Europe,  specifically  in 
relation to the industry, the mobility sectors and the natural gas network. The industry 
sector could in the coming years replace its hydrogen demand produced with an SMR 
with hydrogen produced with renewable energy. For the mobility sector, the carbon fuel 
driven  vehicles  will  be  partly  replaced  by  electric  vehicles  and  hydrogen  fuel-cell 
powered  vehicles  due  to  the  regulations  in  the  EU  Member  States,  such  as  in  France 
where in Paris from 2030 Diesel and petrol vehicles will be banned. 

Regions where Carbon-free Production of Hydrogen is possible 

Access to cheap carbon-free electricity is a key factor to profit from the production of 
carbon-free hydrogen with an electrolyser. This can be obtained by accessing curtailed 
renewable energy due to oversupply in cases of high wind or solar production. In such 
conditions the wholesale markets experience very lower prices or even negative prices. 
Due to the strong learning effects experienced already today, a local renewable source 
can need low CAPEX investments and of course very low OPEX. It was confirmed by the 
results of a study performed by Tractebel and Hinicio for FCH-JU, being regarding the 
early  business  cases  for  hydrogen.  The  study  assessed  geographical  locations  where 
there  were  bottlenecks  or  an  excess  of  renewable  electricity.  The  study  identified 
electricity costs at a level of 40% of the electricity market price at times of oversupply 
in specific regions. This cheap electricity could be used to make carbon-free hydrogen 
competitive.  Also  by  providing  grid  services  in  the  form  of  frequency  control,  to  the 
power system, a hydrogen project could improve its financial performance. 

The focus of the key regions is on Germany, France, Great-Britain and Denmark. The 
Tractebel-Hinicio  study  for  the  year  2017-2025  identified  the  following  renewables 
annual production yields for these countries: 

21 IEA (2010): “Technology brief E02 - Gas-fired power”, Energy Technology Systems Analysis Programme 

January 2018  I  46 

 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

GWh  (%  renewables 
national production) 

Germany 

France 

Great Britain  Denmark 

2017 

2025 

2124 (1.8%) 

104 (0.3%) 

660 (1.1%) 

2242 (14.6%) 

1702 (0.9%) 

464 (0.6%) 

2108 (2.1%) 

2801 (13.4%) 

Table 6: Annual curtailment per country (absolute in share in total renewables 
electricity production) 

As shown in Table 6, the greatest potentials lie in Germany and Denmark in 2017, with 
more than 2000 GWh yearly curtailment. The most promising areas for these countries 
with the highest share in curtailment are: 

GWh (% 
renewables 
national 
production) 

2017 

2025 

Germany 

France 

Great-Britain 

Denmark 

Herrenwyk 

Albi 

Iverarnan & 

Trige 

Tongland 

428 (34%, 59% 
hours/year ) 

24 (12%, 9% of 
hours/year) 

71 (20%, 34% 
of hours/year) 

89 (2.5%, 5% 
of hours/year) 

475 (40%, 43% 
hours/year) 

72 (20%, 15% 
hours/year) 

117 (20%, 35% 
pf hours/year) 

442 (13%, 23% 
of hours/year) 

Table  7:  Recommended  areas  for  electrolyser  installation  based  on  the 
renewables curtailment in that area 

As shown in Table 7, for 2017 the greatest potential lies in Germany and Great-Britain, 
where  high  full  load  hours  for  the  electrolyser  are  possible,  combined  with  a  high 
renewables  share  being  curtailed.  In  2025,  also  France  and  Denmark  increase  their 
potential.  

Germany 

The key region in Germany is Herrenwyk, which is in the North of Germany. This region 
has the highest curtailment in Germany due to high levels of onshore wind energy. For 
2025, there are plans for grid reinforcements, HVDC lines from North to South, which 
will limit the increase of curtailment, as can be seen in Table 6 and Table 7.  

In the year 2015, 3500 MW onshore wind was added in Northern Germany, increasing 
significantly the renewables curtailment in the last few years. One of the goals of the 
Energiewende (the German Energy Transition strategy) is that by 2050 Germany should 
ensure that 80% of the electricity is provided by renewables. In case that the grid is not 
greatly reinforced, power to hydrogen could become very important for 2050. 

January 2018  I  47 

 
 
 
Sectoral integration: long-term perspective in the EU energy system 

Figure  10:  Annual  curtailment  per  renewable  technology  in  Germany 
(maximum height bar is 475 GWh) [28] 

France 

The  key  region  in  France  is  Albi,  with  a  rather  limited  curtailment  that  will  slightly 
increase  in  2025.  In  Albi  onshore  wind  has  the  highest  curtailment  in  France. 
Curtailment is high during spring and autumn, due to strong winds (autumn) and lower 
electricity demand (spring), driven by a lower electric heating demand. 

Figure 11: Annual curtailment per renewable technology in France (maximum 
height bar is 72 GWh) [28] 

Great Britain 

Tongland (2017) and Iverarnan (2025) are the key regions of Great Britain, located in 
Scotland, suffering from onshore wind curtailment. For 2025, 1 GW of additional wind 
power  will  be  added  in  Scotland.  In  general,  most  of  the  renewables  curtailment 
concerns onshore wind production in Scotland.  

January 2018  I  48 

 
 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

Figure  12:  Annual  curtailment  per  renewable  technology  in  Great  Britain 
(maximum height bar is 117 GWh) [28]  

High  curtailment  occurs  in  the  South  near  Canterburry  and  concerns  offshore  wind 
farms. This curtailment is expected to decrease by 2025 thanks to the NEMO project, 
which is an HVDC interconnection with Belgium. 

Denmark 

The key region for Denmark is Trige, which suffers from high offshore wind curtailment. 
There  is  quite  high  curtailment  of  onshore  wind  production  in  West  Denmark  and 
offshore wind curtailment in central Denmark.  

Figure  13:  Annual  curtailment  per  renewable  technology  in  Denmark 
(maximum height bar is 442 GWh)  

January 2018  I  49 

 
 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

Regions with industrial demand for carbon-free hydrogen 

Previous sections dealt with the cement, fertilizer, steel and refining industries regarding 
the  possibilities  of  hydrogen  use  and  identified  key  limitations  of  a  technical  and 
economic nature. Carbon-free hydrogen is nevertheless already used in some industrial 
projects and further demand growth is expected in the four key regions identified above. 

Projects that already use carbon-free hydrogen 

▪  GrInHy: With high-temperature electrolysis providing a higher overall efficiency of 

80% HHV, a 150 kW solid oxide reversible electrolyser was installed providing 
hydrogen to steel industry for surface treatment. It has been operational since 
beginning of October 2017. This was done in the framework of the H2020 program 
and the project started in in 2015. [34] 

▪  H2Future: This project plans to install a 6 MW PEM electrolyser for a steel plant in 
Austria, where the hydrogen will be injected in the coke oven and burned in the 
plant’s power plant. The project also aims to provide grid balancing services. The 
electrolyser is still under development. This project is part of the H2020 program, 
and the project started in 2016. [34] 

▪  Glomfjord, Norway: From 1953-1991 an ammonia plant used an electrolyser to 
produce 30,000 Nm³ H2/h with 168 units of electrolysers by NEL. The installed 
electricity installation was 135 MW. [35] 

▪  Rheinland Refinery Complex, Germany (REFHYNE project): ITM Power has a 

joint project with Shell to install a 10 MW PEM electrolyser to produce hydrogen at 
the Rheinland Refinery Complex in Germany, where they consume about 180,000 
tons hydrogen per year. [36] 

Industries in key regions that have a hydrogen demand  

In  the  four  key  regions  discussed  in  section  0,  it  is  possible  to  find  industries  where 
carbon-free hydrogen could be part of energy supply.  

▪  Herrenwyk, Germany: Near Herrenwyk, there are four refineries in operation in a 
range of 110 km (Tamoil Holborn - 16.3 ktpa H2, H&R Ölwerke Schindler, Nynas – 
2.5 ktpa H2, Heide – 29.9 ktpa H2). Also steel industries can be found, such as 
ArcelorMittal in Hamburg. Regarding fertilizer plants, the Brunsbüttel ammonia plant 
can be found at 135 km. 

▪  Trige, Denmark: In a range less than 100 km, there is the Fredericia refinery. No 

data was found about demand for hydrogen in the refinery. 

▪  Albi, France: In France, there are 2 fertilizers plants located at about 300 km of 

Albi, being one in Pardies and the other in Ambès. The ammonia is imported, but it 
should be possible to produce it on site by making investments in ammonia 
reactors, nitrogen air separators and of course carbon-free hydrogen production. 
The marginal cost of onsite production has to be competitive to the cost of 
importing the ammonia by ship [37], [38]. 

▪  Tolberg - Iverarnan, Great Britain: No H2 demanding industry was found near 

Tolberg or Iverarnan. 

Mobility demand for hydrogen 

Also  in  the  mobility  sector,  number  of  projects  using  carbon-free  hydrogen  exist  and 
more are expected to appear with the regulatory incentives being put in place by both 
national governments and city authorities, such as bans of diesel and petrol cars. 

January 2018  I  50 

 
 
 
Sectoral integration: long-term perspective in the EU energy system 

Projects that already use carbon-free hydrogen 

▪  Taxis:  

o  Hype taxi fleet in France, which currently counts 50 hydrogen vehicles 

but plans to increase up to 600 for 2020 [39]. 

o  Paris-Orly airport: new refuelling station opened on 7 December 2017 

by Air Liquide and Groupe ADP with support of FCH JU [39]. 

o  Hydrogen fuel cell power Black Cab made its debut at 2012 Olympics in 

London [40]  

▪  Trucks/forklifts 

o  Carrefour group, France: Carrefour has purchased 57 Forklifts with fuel 

cell solution from Plug Power Inc in 2016. Possibly, Carrefour will 
purchase more than 150 units. This is part of the the HyLIFT-EUROPE 
project [41] [42]. 

o  Coop, Switzerland: In Switzerland, the Coop truck company has in 
collaboration with PowerCell Sweden AB and Swiss hydrogen, for 
introducing the country’s first hydrogen fuel cell truck (350 bar, 31 kg 
H2 storage and range of about 400 km) and also the hydrogen refuelling 
station. In case that tests are successful, Coop intends to replace its 
entire fleet [43]. The refuelling station will offer hydrogen at both 
pressure stages (350 and 700 bar) to be able to fuel the hydrogen 
trucks and 12 fuel cell cars being used by a distribution centre nearby 
[44]. 

o  Life 'N Grab Hy, WaterstofNet: Two garbage trucks have been equipped 
with batteries and fuel cells to be tested in 10 cities, where emissions 
should be reduced as much as possible [45]. 

o  H2 Share, Interreg North-West Europe: A heavy duty H2 truck of 27 tons 
is current being designed and will be demonstrated in Belgium, the 
Netherlands, and Germany. The truck will be refuelled with a mobile 
refuelling station. The project will run from 2017 to 2020 [46]. 

o  London, UK: Tower Transit buses from London fill their buses in less 

than 10 minutes at the hydrogen refuelling station by Air Products with 
hydrogen produced in the Netherlands coming from an SMR [13]. 

o  Oslo, Norway: Five Ruter fuel cell buses (35 kg H2 storage) use a 

refuelling station operated by Air Liquide Norway. The hydrogen is 
produced by 2 electrolysers (HySTAT 60), consuming renewable energy 
[13]. 

o  Cologne, Germany: Cologne wants to replace its entire bus fleet with 
alternative powertrains. Four fuel cell buses operate there today. The 
hydrogen is produced as by-product by chemical processes near 
Cologne [13]. 

▪  Buses 

▪  Hydrogen refuelling stations 

o  Hydrogen Mobility Europe: This is a flagship project where they try to 

give fuel cell electric vehicles access to a European network of hydrogen 
refuelling stations. To produce carbon-free hydrogen, also grid balancing 
value streams were taken into consideration. 

January 2018  I  51 

 
 
 
Sectoral integration: long-term perspective in the EU energy system 

o  H2 Mobility, Germany: The establishment of the first 100 refuelling 

stations by 2018-2019 and in case of an uptake of fuel cell vehicles, this 
number will be increased to 400 [12] . 

Figure 14: Hydrogen refuelling stations across Europe, of which part is funded 
by H2ME 

Mobility in key regions 

In the EU there are today a total of 92 public hydrogen refuelling stations. For the key 
countries  discussed  in  section  0,  there  are  already  today  several  hydrogen  refuelling 
stations installed, as well as near the key regions of each country.  

▪  Germany: There were 30 hydrogen refuelling stations in June 2017 [47]. Hamburg, 

near Herrenwyk (key region of Germany) has three hydrogen refuelling stations 
today in operation and two in planning.  

▪  France: France has about 15 hydrogen refuelling stations. One public station is in 

Albi, the key region of France, where they provide electricity to EVs and hydrogen at 
350 bar, 15 kg per day [48]. By 2040 they will end the sales of gas and diesel 
powered vehicles. [49] Paris will also ban all petrol and diesel fuelled cars by 2030. 
[50] This means that by 2030 hydrogen fuelled and electric vehicles will have an 
important role in the decarbonization of the mobility sector. 

▪  Great Britain: Also 15 hydrogen refuelling stations are today in operation in Great 
Britain and two in Scotland but still at 150-200 km from Ivernarnan and Tongland, 
the key regions of Great Britain [4]. The UK has also stated that by 2040 sales on 
gasoline and diesel cars will be banned and by 2050 all cars on the road will need to 
have zero emissions. [49] 

▪  Denmark: Denmark has about 11 hydrogen refuelling stations. There is one 

refuelling station (700 bar) near Trige in Aarhus (14 km away). 

Another  interesting  hydrogen  mobility  domain  could  be  the  freight  truck  corridors  in 
Europe, which are the routes trucks take often throughout several Member States. In 
case  the  hydrogen  truck  projects  are  successful,  corridors  with  hydrogen  refuelling 
stations  for  trucks  could  become  a  reality.  A  similar  project  already  exists  for  Liquid 

January 2018  I  52 

 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

Natural Gas LNG, the LNG Blue Corridors, which is part of a Horizon 2020 programme. 
[51] 

Figure 15: LNG Blue Corridors  

 Gas grid injection 

In the report by Tractebel and Hinicio [28] mentioned above, it was found that gas grid 
injections of hydrogen can boost cash flows at a low marginal cost. This allows also for 
continuous electrolyser operation, helping secure  revenues for providing grid services 
and  increasing  the  electrolyser  efficiency.  In  general,  no  additional  investments  are 
needed in the infrastructure of the existing natural gas network. Therefore, it could be 
an  ideal  solution  for  transporting  excess  of  renewables  from  point  A  to  point  B.  An 
example is Germany, with the large excess of renewables in the North. However, there 
are today technical and regulatory limits for the H2 injection in the gas grid as well as 
the fact that hydrogen without support cannot compete with natural gas flowing through 
the natural gas network. The injection limits are the following for the key countries [28] 
[52]: 

▪  Germany: 10%vol, 2%vol in case that there is a CNG station downstream 

▪  France: 6%vol 

▪  Great Britain: 0.1%vol 

▪  Denmark: 2%vol 

Summary 
The aim of this Task was to map different power-to-hydrogen technologies and assess 
market  potential  for  carbon-free  hydrogen.  Furthermore,  existing  barriers  to 
successfully  deploy  carbon-free  hydrogen  for  different  applications  were  identified. 

January 2018  I  53 

 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

Additionally,  the  impact  on  emissions  for  the  different  technologies  in  these  market 
domains was assessed. 

First, the basics of the carbon-free hydrogen production chain were explained, including 
the electrolyser cost assumptions. The analysis found that the electricity price will be 
the key factor that will affect the production costs of hydrogen.  

Next, the mobility sector was analysed first with focus on hydrogen fuelled vehicles and 
then in electricity.  

For  hydrogen-powered  vehicles,  the  analysis  focused  on  assessing  the  required 
infrastructure  changes  for  the  refuelling  stations  and  the  most  relevant  cost 
assumptions. It is important to note the difference in refuelling stations for passenger 
vehicles  compared  to  those  for  trucks  and  buses,  with  the  latter  requiring  one  less 
compression  stage.  The  size  of  the  refuelling  station  (kg  H2/day),  the  location  of 
hydrogen  production  (on-site/off-site),  the  transportation  method  of  hydrogen  and 
electricity  cost  are  the  four  key  factors  impacting  the  cost  of  the  hydrogen  refuelling 
stations. For the hydrogen-fuelled vehicles, the attention was paid to buses, taxis and 
passenger vehicles, since these have better market potential compared to the ones for 
trucks.  For  buses  and  taxis,  there  are  more  projects  in  the  EU  than  for  passenger 
vehicles,  since  central  refuelling  stations  require  lower  investment  costs  due  to  the 
higher  utilization  rate.  Diesel  buses  and  taxis  emit  today  118  and  892  g/km  CO2 
respectively (tank-to-wheel assessment). 

For  electrification  of  the  mobility  sector,  the  applicability  of  electrification  of  different 
mobility segments has been discussed. The analysis found that the biggest potential for 
electrification lies in road transport. The analysis has thus been focused on assessing 
the options for electrification of cars and trucks. We found that in 2015 already 500 000 
electric  vehicles  were  driving  on  European  streets.  For  trucks,  there  are  pilots  for 
overhead contact line trucks on highways. Similar concepts for buses exist already. To 
promote electric vehicles, a higher coverage of charging stations is needed. However, 
existing charging stations suffer low utilisation rates. 

The  hydrogen  demanding  heavy  industry  was  also  studied.  The  steel,  fertilizer  and 
refinery  industries  were  identified  as  segments  with  the  highest  potential  in 
economically  viable  use  of  carbon-free  hydrogen.  This  would  require  infrastructure 
installation  and  changes  on  site.  Steam  Methane  Reforming  (SMR)  which  is  most 
commonly used for production of hydrogen emits 7.2 kg CO2/kg H2.  

Next, power-to-heat technologies have been analysed. We found that heat pumps have 
reached shares of over 20% of total heating demand in some European markets. The 
use of electricity for heating can support the decarbonisation of the heating sector. The 
increase  electricity  demand  impacts  the  power  sector.  However,  we  have  found  that 
intelligently  controlled  power-to-heat  technologies  can  have  benefits  for  the  power 
sector. They can improve local integration of renewable energy sources, support system 
balancing and reduce the required installed capacity of power plants in the long-term. 
Thermal storage increases the flexibility of heating technologies. Hydrogen can also be 
used for heat supply. There exist proven technologies as fuel cells that are widely applied 
in  Asian  markets.  In  Europe,  fuel  cell  programmes  have  led  to  first  installations.  The 
goal is to install 50 000 fuel cells with a subsequent commercial roll-out until 2020. 

Different  hydrogen  storage  technologies  as  energy  storages  have  been  analysed. 
Hydrogen can be stored in decentral tanks under low and high pressure up to 1 000 bar. 
The main  options for central hydrogen storage are salt  caverns, porous  storages and 
aquifers. The potential for central storages depends on the geological structures. The 
impact of hydrogen based flexibilities on the decarbonisation of the gas grid and their 
contribution for the energy transition have been assessed. The analysis has shown that 
hydrogen can be injected into the gas grid without restrictions, if hydrogen is converted 

January 2018  I  54 

 
 
 
Sectoral integration: long-term perspective in the EU energy system 

to methane. The stored “carbon-free gas” can again be used power generation offering 
benefits  as  seasonal  storage  potential,  increased  system  flexibility  and  energy 
transmission capacity. 

Finally, key regions were analysed in the following countries: Germany, France, Great 
Britain,  and  Denmark,  where  an  excess  of  renewable  electricity  exists  today  and  will 
likely  increase  by  2025.  In  these  key  regions,  hydrogen  could  be  cheaply  produced. 
Industry  and  mobility  applications  were  identified  near  these  key  regions  to  identify 
possible H2 demand. Also, EU projects related to H2 demand for industry mobility were 
assessed. 

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Sectoral integration: long-term perspective in the EU energy system 

Modelling  the  impact  of  sectoral  integration  on  the 
energy system towards 2050 

Introduction 
This section provides  a  systems analysis view  of the impact of sectoral integration of 
the  energy  system  towards  2050.  In  view  of  the  objective  to  fully  decarbonise  the 
energy  system,  the  integration  across  multiple  energy  sectors  is  expected  to  better 
adapt to the challenge of achieving the zero emissions goal, while taking full advantage 
of e.g. the variable renewables, potential exhaustion of resources and ultimately limit 
the resulting energy system costs.  

Roadmaps  developed  so  far  continue  to  have  remaining  CO2  emissions  in  the  energy 
system in 2050, particularly in transport  – mineral oils for certain transport modes  – 
and  in  heating  and  industrial  uses  –  mainly  natural  gas.  With  systems  analysis, 
underpinned  by  modelling  with  a  novel  PRIMES  model  extension,  the  present  section 
presents  an  overview  of  the  options,  their  advantages  and  disadvantages  from  a 
systems  perspective.  This  approach  allows  to  analyse  the  interaction  between  the 
different  energy  sectors  to  better  understand  and  quantify  the  benefits  of  sectoral 
integration.  

The  scenarios  analyse  different  options  based  on  different  developments  of 
technologies.  The  existing  studies  are  not  conclusive  about  the  technico-economic 
potential of the technologies but agree that massive deployment of the technologies can 
deliver  the  potential  of  learning-by-doing.  Therefore,  the  model  projects  technology 
readiness in the future is in the context of alternative scenarios, assuming that market 
conditions enable massive deployment, which differs per scenario.   

The  sectoral  integration  through  hydrogen  is  greatly  depending  on  the  assumptions 
about  technology  readiness  and  cost  reductions  in  the  future.  A  successful  market 
deployment requires technological maturity at sufficient degree in all stages of the value 
chain,  involving  consumption  equipment,  distribution  systems  and  production  and 
supply. A possible technological failure in one of the stages of the value chain can make 
the entire chain inefficient. From a business perspective, the investment and technology 
provision  in  each  stage  of  the  value  chain  depend  on  different  actors  with  different 
aspirations  and  activities.  Therefore,  the  market  coordination  issue  is  of  utmost 
importance for the overall maturity of the value chain. A successful market coordination 
can be seen as a positive externality which markets alone may not be able to deliver.  

Therefore, public intervention is necessary to help achieving the market coordination in 
a  timely  manner.  Market  coordination  failures  are  quite  common  in  reality  when  a 
transformation of technology usage at the end-consumer level requires development of 
infrastructure  and  development  of  the  technology  at  the  same  time.  The  sectoral 
integration  cases  are  precisely  of  a  similar  nature.  For  example,  if  fuel  cells  become 
mature  and  less  costly  and  similarly  if  electrolysis  becomes  competitive,  these 
conditions are not sufficient for a hydrogen market development unless the hydrogen 
distribution  infrastructure  develops  simultaneously.  Market  coordination  failure  also 
requires coordination of the public policy measures which are applicable to every stage 
of  the  value  chain.  For  example,  public  policies  supporting  development  of  hydrogen 
distribution infrastructure and policies supporting RTD for fuel cells are not sufficient if 
there is no policy discouraging carbon emissions in the production of hydrogen.  

The Appendix includes the background information on power-to-X technologies and the 
related  value  chains.  They  scenarios  combine  the  dynamics  of  improvement  of  these 
technologies with similar developments in end-use equipment and vehicles.  

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The  storylines  representing  different  strategies  for  sectoral  integration  assume  the 
context of deep decarbonisation. The focus is on strategies which aim at removing the 
remaining  emissions  in  the  long  term  as  a  result  of  coordinated  changes  in  different 
energy sectors enabled by the power-to-X technologies. Firstly, stylized and contrasted 
scenarios  are  quantified  that  are  helpful  to  understand  the  limitations  and  the 
advantages  of  the  strategies.  Based  on  this  understanding,  a  balanced  scenario  is 
specified and quantified that aims at combining the attractive elements of the stylized 
cases. A sensitivity analysis regarding technology costs is added to assess the impacts 
of  the  uncertainty  surrounding  technological  development.  The  horizon  of  the 
simulations  is  2050  and  the  scenarios  build  on  a  basic  decarbonisation  scenario 
developed using PRIMES for the Winter Package proposal of the European Commission.  

Background: key elements to be considered in the Modelling Task 

 Features of hydrogen 

The sectoral integration based on hydrogen can be seen from various angles depending 
on the role of hydrogen in the system. The following aspects of hydrogen need to be 
taken into consideration:  

▪  Use of hydrogen for chemical storage of electricity: storage of electricity in the 
form of hydrogen involves re-electrification of hydrogen mainly in gas turbines or 
CCGT at an energy efficiency rate of 50%-60%; as electrolysis has an efficiency 
maximum of 80%, the maximum efficiency of the storage chain is 48%.  

▪  Use of hydrogen as a feedstock: it requires blending with CO2 to transform into 

syngas which is further upgraded to methane or a liquid hydrocarbon. The 
technologies are known but the industry has not yet reached the economically 
efficient scale.  

▪  Use of hydrogen as an energy carrier: Direct use of hydrogen in stationary and 

mobile energy applications can use fuel cells which either operate at high 
temperature as small scale CHP or lower temperature for mobility. The fuel cells are 
technically reliable and energy efficient but currently expensive; the learning 
potential is currently very uncertain. Hydrogen can also burn in equipment which 
uses natural gas, after adaptations. 

▪  Storage and transportation of hydrogen: Hydrogen conditioning is necessary 
but inefficient for energy consumption. Compressed H2 can be produced directly 
from electrolysis with low additional energy losses. Liquefied production of H2 to 
transport over long distances would require 20-30% losses in liquefaction. In 
addition to this, road or rail transport of compressed H2 is expensive. Pipeline 
transport of H2 will need adaptation of the gas pipelines at a significant cost. 
However, H2 storage in pressurized tanks and line packs is a practical and 
economical option. Mass storage of H2 is possible in underground caverns. 

Business drivers for hydrogen 

The already published roadmaps for Europe describing energy systems achieving strong 
emissions reductions until 2050 base decarbonisation on mainly two pillars, renewables 
and energy efficiency, and use electricity produced from carbon-free sources to reduce 
emissions in transport and heating. The full decarbonisation of the power sector faces 
the  challenge  of  balancing  large  amounts  of  intermittent  renewables.  Despite  the 
increasing shares of electricity and the use of biofuels, significant amounts of emissions 
remain in the system in transport – use of mineral oil fuels in specific transport modes 
- and in heating and industrial uses – mainly natural gas. System integration and the 
use  of  an  intermediate  energy  carrier,  such  as  hydrogen,  as  a  means  of  storage  and 

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feedstock,  can  provide  a  possible  solution  for  the  remaining  carbon  emissions  in  the 
energy system and for the maximum use of renewables.  

The power system includes increasing amounts of variable  renewables and almost all 
projections see an increasing role of variable renewables in the system. While having 
considerable  benefits  in  terms  of  emission  reduction,  the  increased  share  of  variable 
renewables requires enhanced flexibility of the power system. Among the requirements 
of  the  changing  power  system  are:  multi-hour  fast  ramping  to  balance  variable 
renewables, in particular for solar PV; fast responding dispatchable resources to balance 
fluctuating  renewables;  storage  beyond  a  daily  cycle  to  cope  with  renewables 
unavailability  periods;  load  shifting  on  a  daily  basis  to  avoid  over-generation 
inefficiencies. Traditional storage technologies have limited potentials: hydro-pumping 
has limitations due to sites; pure pumping has limited storage capacity and acts mainly 
as  a  peak  device;  compressed  air  energy  storage  is  expensive  and  is  also  subject  to 
siting  limitations;  batteries  are  small  to  medium  scale  (mostly  connected  to  the 
distribution  grid)  and  cannot  cover  multiple-day  cycles  or  seasonal  storage.  The 
production of hydrogen from excess power could alleviate the limitations of traditional 
technologies  and  provide  a  flexible  storage  for  excess  power  and  provide  balancing 
capacity. Further hydrogen, besides pure storage, can be used as a fuel directly or act 
as a feedstock for the production of hydrocarbons for fuel.  

The production of excess hydrogen occurs through electrolysis which uses electricity to 
split water molecules. The hydrogen can then be used for a variety of purposes: it can 
be mixed with natural gas to reduce its emission factor, it can be burnt directly in gas 
turbines  or  motors,  or  with  fuel  cells.  Fuel  cells  can  be  either  centralised  if  it  is  for 
feeding electricity back to the grid or decentralised both in stationary as well as in mobile 
uses. Further hydrogen can be used as a feedstock for the production of hydrocarbons. 
In the production of methane, after the production of hydrogen through electrolysis, a 
process  called  methanation  occurs:  this  process  combines  the  hydrogen  with  CO2  to 
produce methane or with further steps also longer hydrocarbon chains. These can then 
substitute fossil fuel based fuels for stationary or mobility purposes, with the latter being 
the most promising (and larger) market. The production of liquid hydrocarbons from the 
mixture of hydrogen and CO2 can follow various technological pathways, of which the 
main are the methanol route and the Fischer-Tropsch route. Integrated co-electrolysis 
of hydrogen and CO2 is also an important technology step in the chain producing liquid 
hydrocarbons.  All  these  technologies  are  well  known  in  the  chemical  and  oil  refining 
industry. However, they have not reached full economic and technological maturity due 
to lack of large-scale applications.  

Hydrogen  is  therefore  a  flexible  energy  carrier  with  potential  application  across  all 
energy sectors; it can:    

• 

• 

• 

compete  against  direct  electricity  use  in  transport  and  heating  depending  on  the  future  learning 
curve of fuel cells 
be  injected  to  the  gas  grid  up  to  a  certain  percentage  (<15%  due  to  the  Wobbe  index  which  is 
important for the end-use of the gas mix) reducing the average emission factor of distributed gas 
provide feedstock for the production of carbon-free or low-carbon methane or liquid hydrocarbons 
which can support versatile solutions as they serve as both electricity storage and energy carriers. 

However,  all  hydrogen  chains  are  expensive  and  require  significant  developments  in 
order  to  come  closer  to  market  competitiveness.  From  a  technical  perspective  the 
processes of hydrogen production and use are known, however significant development 
is needed in the engineering in order to upscale the processes for economic production 
and  development.  The  production  and  usage  chains  of  hydrogen  are  additionally 
complex because they require multiple actors of different sectors to interact: this implies 
that  regulation  and  policy  support  will  be  needed  and  that  possibly  large  players  will 
undertake  the  investment  and  the  related  risks  rather  than  small  investors.  Even  in 
niche markets  where hydrogen is  close to techno-economic maturity, hydrogen could 

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benefit from support in the form of monetary benefits for being emission free. In order 
for the business case of hydrogen to develop an enabling context for hydrogen needs to 
be put in place, which includes: 

▪  policy and regulatory certainty, including standards for the security of hydrogen to 

enhance public acceptance 

▪  support and development of consumer structure 

▪  R&D support 

Carbon free hydrogen production   

Hydrogen  can  be  produced  in  various  ways:  currently  the  main  way  of  producing 
hydrogen  is  through  steam  reforming  from  natural  gas  or  oil,  however  even  coal 
gasification  is  used  to  produce  hydrogen.  However,  while  these  processes  are  all 
economically viable and produce hydrogen for industrial purposes, none are carbon free. 
This  implies  that  because  of  environmental  concerns  and  under  the  presence  of 
increasing  carbon  prices  the  technology  will  gradually  be  driven  out  of  the  market.  
Adding carbon capture and storage equipment to gas steam reforming is expensive and 
has  no  sense  in  the  context  of  a  low  carbon  system,  as  it  is  more  cost-efficient  to 
produce  clean  hydrogen  instead  of  searching  ways  of  storing  carbon  dioxide 
underground.  Carbon  capture  and  use  to  produce  hydrocarbons  or  in  other  uses  is 
interesting and important in the course of transition of the system but is of no interest 
in the long term in the context of a low carbon system, because the  chain of  carbon 
dioxide capture and use is not carbon neutral.  

Therefore, we need to produce carbon free hydrogen as the first step of any sectoral 
integration strategy. To produce carbon free hydrogen from electrolysis is the only way, 
and evidently requires that electricity generation is also carbon free, as electrolysis splits 
water using electric current.  

Three  water  electrolysis  technologies  can  be  considered  for  hydrogen  production: 
Alkaline  Electrolysis  Cells  (AEC),  Proton  Exchange  Membrane  Electrolysis  Cells  (PEM-
EC)  and  Solid  Oxide  Electrolysis  Cells  (SOEC).  Because  all  three  technologies  are 
modular,  they  can  apply  at  a  small  and  at  a  large  scale.  The  economies  of  scale  are 
however significant.  

Currently the main way to produce electrolytic hydrogen is through Alkaline Electrolysis 
Cells, however they have limited ability to respond to load changes – essential for the 
flexibility  requirements  of  the  power  system,  further  the  design  is  complex  implying 
limited cost reduction options. The PEM electrolysers have a simple design and, crucially 
for the proposed use, are very flexible; they are currently still under demonstration but 
are assumed to have a very high cost reduction potential. The Solid Oxide Electrolysis 
Cells  apply  high  temperature  electrolysis  and  are  at  a  very  early  development  stage, 
thus  are  expected  to  develop  mainly  in  the  long  term.  Theoretically  the  SOEC  is  a 
ground-breaking technology due to the very high efficiency, the ability to recover the 
heat needed to supply  the electrolysis and the possibility to operate in reverse mode 
(regenerative electrolysis). However, the inability to have a flexible load and the high 
degradation of the membranes imply that this technology is still far from maturity. All 
electrolysis  technologies  feature  great  economies  of  scale  not  yet  exploited  in  the 
industry.  

Electrolysers  cannot  yet  compete  with  steam  reforming  for  hydrogen  production 
economically. However, the use of electrolysers is only limitedly to supply hydrogen as 
such: their benefit lies in being able to provide balancing and storage capacity for the 
power  generation  system  where  increasing  shares  of  variable  renewables  require 
significant flexibility mechanisms.  

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To  further  transform  hydrogen  into  hydrocarbons  further  chemical  processes  are 
necessary. The simplest is the methanation which allows for the production of methane 
gas;  this  would  allow  for  a  full  substitution  of  natural  gas  with  a  “clean  gas”.  The 
difficulty lies in the supply of CO2 required, for which several options are available: CO2 
from carbon capture in power and industrial plants – however the process would not be 
carbon free, but implies shifting of emissions; CO2 from biomass, in particular biogas – 
however this would divert limited biomass resources, and it is more efficient to use the 
biomass directly to produce hydrocarbons; CO2 from air capture – this is the only way 
that the gas would effectively be emission free from an accounting perspective but the 
technology is today immature and expensive.  

To produce methane from the mixture of hydrogen and CO2, the technology with the 
biggest potential to reach commercial stage is catalytic isothermal methanation. SOEC 
technology can also directly provide methane in one stack, however it is still far from 
commercial deployment.  

The low overall energy efficiency and the high costs are the limitations of the power-to-
liquid processes. The merit is that they can produce fully fungible liquid hydrocarbons 
using  electricity  via  hydrogen  and  the  conversion  of  syngas  to  complex  organic 
molecules. They can provide a petroleum free energy system. They can also lead to zero 
overall emissions if the power-to-liquid process uses CO2  captured  from ambient air. 
Two  main  technological  routes  are  possible,  namely  the  methanol  and  the  Fischer-
Tropsch routes. Co-electrolysis of hydrogen and carbon dioxide can also be part of the 
process.  

The technologies of the chains are well known but not yet fully mature at an industrial 
scale. They can be so if applied to large-scales.  

The synergies with Power-to-gas and Power-to-liquids fuels 

With regards to power-to-gas technology, methane can be the output of methanation 
that uses hydrogen and carbon dioxide as inputs. The output which is synthetic gas, is 
fully substitutable to natural gas that provides great benefits for continuing the use of 
existing infrastructure of distribution and equipment. Methanation implies a further loss 
in energy efficiency, reaching an overall rate roughly of 60-65%, including electricity to 
capture carbon dioxide from ambient air. However, the output can be fully stored and 
re-electrified in a versatile way.  Thermochemical catalytic technologies for methanation 
are at an advanced stage of deployment.   

With  regards  to  power-to-liquids  (transport  fuels),  several  technologies  are  possible, 
namely: 

▪  Combined electrolysis and carbon dioxide chemical treatment (electro-reduction, co-
electrolysis, reverse water gas shift) which produces methanol, dimethyl ether etc. 
which can be further upgraded to transport fuels (after hydrogenation); 

▪  Fischer-Tropsch conversion of syngas, produced from a treatment of H2 as an output 

of electrolysis and CO2: this can produce hydrocarbon chains of varying lengths 
(gasoline, kerosene, diesel, etc.) 

From a GHG emissions perspective, the origin of CO2 is a challenging issue. Only CO2 
captured from ambient air guarantees full carbon-free fuels. The overall efficiency rate 
of the clean liquid chain is between 40-50%.  

The techno-economic challenges towards a hydrogen economy 

In  the  traditional  bibliography,  hydrogen  economy  refers  to  an  energy  system  where 
hydrogen is the main energy carrier in end-use directly. A modern perspective needs to 
assess which of the hydrogen features (electricity storage, feedstock for hydrocarbons, 

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direct final use) should be predominant in a carbon free strategy. Higher the share of 
hydrogen in direct energy uses, lower the extent of electrification in a near zero carbon 
energy system.  

As mentioned above, in the context of a climate strategy, all future roles of hydrogen 
involve hydrogen production from electrolysis using carbon free electricity as the first 
stage of the chain. The option of using hydrogen as a feedstock also requires capturing 
CO2 from the air to achieve zero carbon emissions.   

The  hydrogen  economy  discussion  is  meaningful  only  in  the  context  of  deep 
decarbonisation of the energy system, as all technology chains involving hydrogen are 
energy  intensive  and  produce  energy  outputs  which  are  significantly  more  expensive 
than  conventional  technologies,  even  if  the  cost  evaluation  included  the  full  learning 
potential. At full learning potential, a carbon price as low as approximately €100 t/CO2 
would suffice to make synthetic fuels competitive. Without learning, carbon prices above 
€1000/tCO2 would be necessary. 

The  exploitation  of  learning  potential  requires  large  scale  installations  and  massive 
production; the critical mass to trigger purely private investment is large, and therefore 
strong  policy  support  is  necessary  to  ensure  the  initial  investments.  The  upfront 
investment  costs  are  significant.  Purely  private  investment  is  surrounded  by  large 
uncertainties. Regulation will need to provide clear and long-term certainty about the 
market prospects of synthetic fuels. The main business model comprises back-to-back 
long term contracts of synthetic fuels producers and utilities providing clean electricity 
at  a  large  scale.  The  economics  of  large  scale  power-to-hydrogen  (or  gas  or  liquid) 
production require the uninterruptible and inexpensive supply of carbon free electricity; 
therefore, extending the necessary interconnections and ensuring fully coupled markets 
assist cost reductions and risk hedging.  

The pathway towards 2050 

The basic decarbonisation scenarios developed using PRIMES in 2016-2017 achieve 80-
85% CO2  emissions  reduction in 2050 compared to 1990. The reduction in 2050 was 
similar  in  the  previous  Energy  and  Climate  Roadmaps  prepared  by  the  European 
Commission  using  PRIMES  in  2011-2012.  In  this  context,  DG-MOVE  proposed  and 
quantified  a  strategy  (using  PRIMES-TREMOVE)  for  the  transport  sector  aiming  at 
reducing  emissions  by  60%  in  2050  compared  to  1990.  Both  the  White  Paper  on 
Transport, published in 2011, and the Communication presented in 2016, confirm the 
60% emissions reduction target.  

The basic decarbonisation scenarios integrate the emissions reduction strategies of the 
sectors and thanks to the modelling provide a sectoral integrating strategy, based on 
the principle of economic efficiency measured as total energy system cost borne by the 
final end-users of energy. To minimize the total costs for the consumers, the modelling 
determines an economic equilibrium in the simultaneous energy markets and in the ETS. 
The sectoral emissions reduction targets derive from this overall least-cost equilibrium.  

As it is well known in numerous studies over the last decade22 low carbon emitting power 
generation is a priority to use electricity as a low carbon carrier to reduce emissions in 
transport  and  heating  where  emissions  reduction  would  be  otherwise  inflexible. 
Electrification  of  road  mobility  based  on  plug-in  hybrids  and  pure  battery  electric 
vehicles and the wide spread of heat pumps are the main technologies. The emissions 
reduction strategy also gives priority to energy efficiency in end-use of energy and to 
renewables. Despite the tremendous transformation required to implement this strategy 

22  Including  The  Role  of  Electricity,  Eurelectric  2008,  The  Power  Choices,  Eurelectric  2012-2014,  the  European 
Commission’s Roadmaps for Energy and the Low Carbon economy of 2011-2012, the Gas Roadmap of Eurogas in 
2015  

January 2018  I  61 

 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

significant amounts of energy-related CO2 remain unabated in 2050. This is mainly due 
to  the  difficulty  of  electrifying  the  entirety  of  stationary  and  mobile  uses  of  energy. 
Examples illustrating this difficulty are the sectors of aviation, long-distance travelling 
vehicles (including trucks) and shipping, as well as special uses of gas in the domestic 
and industrial sectors, as well as in small scale cogeneration. Even in the power sector 
emissions reduction cannot go up to 100% in this strategy, as the large requirements 
of flexibility to balance the increasing production from variable renewables require gas 
power plants. The carbon capture and storage (CCS) technologies for gas power plants, 
which are necessary for flexibility and cogeneration of heat, can reduce the ultimately 
remaining emissions but the reduction cannot go below roughly 90% in a CCS plant. 

Key GHG emissions in Mt CO2-eq - 
EU28 - basic decarbonisation 
scenario revised in 2017 

Total  

2005 
5349.18  1157.45 

2050 

% change in 
2050 from 
2005 
-78.36 

% structure 
in 2050 
100.00 

Energy related CO2 emissions 

4127.13 

670.56 

-83.75 

Industry 
of which energy intensive industries 
Residential 
Tertiary 
Services 
Agriculture 
Transport 
of which Road transport 
of which Aviation 

Supply side 

634.05 
472.23 
484.16 
271.60 
197.29 
74.31 
1079.82 
893.84 
150.18 

1657.50 

Non-energy related CO2 emissions 

282.44 

118.27 
83.57 
64.82 
41.37 
24.05 
17.32 
360.34 
243.57 
101.81 

85.77 

41.23 

-81.35 
-82.30 
-86.61 
-84.77 
-87.81 
-76.69 
-66.63 
-72.75 
-32.21 

-94.83 

-85.40 

Total CO2 emissions 

4409.58 

711.80 

-83.86 

57.93 

10.22 
7.22 
5.60 
3.57 
2.08 
1.50 
31.13 
21.04 
8.80 

7.41 

3.56 

61.50 

Non-CO2 GHGs emissions 
Table 8: Remaining GHG emissions in a basic decarbonisation scenario 

939.60 

445.65 

-52.57 

38.50 

The  basic  decarbonisation  scenarios  seem  to  exhaust  the  possibilities  seen  from  a 
conventional perspective regarding emissions reduction in 2050. The scenario includes 
development  of  bioenergy,  including  new  generation  biofuels  in  transport,  but  the 
limitation in the bioenergy feedstock cannot allow biofuels fully substituting mineral oil 
products. Some amounts of hydrogen and clean methane develop close to 2050 in the 
power sector as a way of providing storage of electricity and producing carbon free fuels 
to  mix  (up  to  a  certain  percentage)  into  gas  distribution  to  reduce  average  carbon 
emissions of the distributed gas.  

Despite these efforts, the basic decarbonisation scenarios leave 1157 Mt GHG unabated 
in 2050 of which 671 Mt CO2 are emissions due to combustion of fossil fuels.  

Table  8  illustrates  that  the  supply  sectors  perform  much  larger  emissions  reduction 
compared to the demand sectors precisely to allow electricity reducing emissions in the 
demand sectors. The same table shows that the most inflexible sector is transport. More 
than half of the remaining emissions in 2050 of the energy sector take place in transport, 
18% in industry, 16% in the domestic sector and 13% in energy supply.  

After  a  closer  look  at  the  remaining  emissions,  and  after  the  use  of  biofuels  and  the 
hydrogen amounts projected in the basic decarbonisation scenarios, it is evident that to 
bring emissions to zero it is necessary to substitute mainly liquid hydrocarbons used in 
transport  (134  Mtoe  in  2050)  and  natural  gas  used  in  various  stationary  uses  and  in 
power generation (84 Mtoe). Table 9 illustrates these numbers. 

January 2018  I  62 

 
 
 
Sectoral integration: long-term perspective in the EU energy system 

Mtoe 

Total 
Solids 

Solids 
in 
CCS 

Total Liquids 
and transport 
biofuels 

Of which 
transport 
biofuels 

Total Gas 

Of which 
Clean 
Gas 

Natural 
Gas in 
CCS 

Industry 

1.3 

 - rest with emissions  1.3 

Buildings 

1.2 

 - rest with emissions  1.2 

Transport 

0.0 

 - rest with emissions  0.0 

Power and Heat 

12.8  12.8 

 - rest with emissions  0.1 

Energy Branch 

0.1 

 - rest with emissions  0.1 

Total energy system  15.4  12.8 

 - rest with emissions  2.7 

3.2 

3.2 

8.6 

8.6 

212.5 

113.2 

0.3 

0.3 

8.8 

8.8 

233.3 

134.0 

99.3 

0.0 

75.9 

38.2 

75.2 

32.9 

10.5 

5.5 

64.4 

1.6 

7.3 

6.0 

37.7 

42.3 

5.0 

13.8 

49.0 

1.3 

99.3 

233.2 

100.0 

49.0 

84.2 

Table 9: Remaining fossil fuels in a basic decarbonisation scenario 

The challenge to bring emissions close to zero is due to the climate change mitigation 
policies at a world level which imply for the OECD countries a  very  restrictive  carbon 
budget post 2050. The OECD countries will need to achieve near zero carbon emissions 
in  the  period  2050-2070  to  allow  the  planet  following  a  2°C  or  even  more  a  1.5°C 
scenario.  It  is  reasonable  to  consider  that  achieving  zero  emissions  after  2050  may 
imply  that  important  strategic  choices  are  decided  early  before  2050  which  influence 
the strategy  of energy  system transition also in the period 2030-2050. Examples are 
the strategic choices regarding the development of infrastructure and the priorities of 
the technology policy.  

This analysis aims at examining whether further reduction of combustion of fossil fuels 
beyond  the  amounts  remaining  in  2050  in  the  basic  decarbonisation  scenario  a)  is 
possible, b) how and when it will be achieved and c) at which cost. 

In a decarbonisation context, the  system must develop in  order to be able to deliver 
zero emissions close to 2050. For the energy system, the highest remaining emission 
are in the transport sector: some transport modes such as aviation or shipping, as well 
as  a  large  part  of  long  distance  heavy  road  transportation  will  continue  to  use  liquid 
fuels because of lack of alternatives. It is improbable that biofuels will be able to fully 
cover this residual demand from transport and synthetic fuels based on hydrogen are 
expected  to  play  an  important  part  in  this  pathway.  Further  hydrogen  or  derived 
methane  gas  can  also  be  used  to  reduce  the  remaining  emissions  in  industry  and  in 
buildings.  

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Sectoral integration: long-term perspective in the EU energy system 

Figure 16: GHG emissions reduction to 2050 

Description of the PRIMES model extension 

A  novel  PRIMES  model  extension  has  been  developed  which  aims  at  capturing  the 
market  penetrations  and  future  role  of  synthetic  fuels,  hydrogen,  electricity,  heat, 
steam, chemical storage, carbon dioxide as a feedstock source, as well as the synergies 
and  competition  between  them.  It  will  have  a  horizon  up  to  2070,  similarly  to  the 
updated main PRIMES model. The model represents the process flow with engineering 
and  economic  details.  It  simulates  hourly  operation  of  a  system  with  electricity, 
hydrogen,  gas,  heat,  steam  and  synthetic  fuels  in  a  synchronised  way  to  be  able  to 
analyse storage and finally the benefits deriving from sectoral integration. 

The  novel  PRIMES  model  extension  includes  an  aggregated  representation  of  the 
electricity, gas, heat and biomass models of PRIMES integrated into the process flow 
modelling. It includes an aggregated way fuel choice in the demand sectors, but demand 
for useful energy is exogenous coming from PRIMES. 

It  includes  alternative  pathways  for  the  production  of  numerous  low  or  zero-carbon 
energy carriers, such as hydrogen, synthetic methane and synthetic liquid hydrocarbons 
produced via Power to X (PtX) routes. At the same time, it includes conventional energy 
carriers  such  as  fossil  hydrocarbons,  biofuels,  electricity,  steam,  heat,  etc.  Given  the 
large  penetration  of  variable  renewables  in  the  future  EU  power  mix,  the  need  for 
electricity storage will become more and more prominent. The new module of PRIMES 
is operating at an hourly resolution and it can capture effectively the operation of large-
scale power storage systems. For example, the module determines the hours of the day 
with excess renewables generation in order to produce energy carriers (e.g. hydrogen) 
that  can  be  used  for  the  production  of  electricity  later  when  renewable  generation  is 
limited (storage).  However, at the same time, the new module is also able to decide 
whether  economics  favour  the  production  of  synthetic  hydrocarbons  (using  e.g. 
hydrogen as feedstock) instead of providing storage services. In this way, it captures 

January 2018  I  64 

 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

competition  for  carriers  that  can  serve  different  purposes  (storage  vs.  feedstock)  for 
different customers (power generator vs. synthetic fuel factories). 

Figure 17: A process flow diagram of the new PRIMES sub-model 

All the aforementioned factors must be considered simultaneously, and along with the 
operation of the rest of energy system (e.g. demand for synthetic kerosene, availability 
of biofuels, etc.). Therefore, the new module includes aggregate representations of the 
electricity, gas, heat and biomass models of PRIMES, integrated into the process flow 
modelling, thus it includes, in an aggregated manner, endogenous fuel choices in the 
demand  sectors.  Demand  for  useful  energy  is  exogenous  coming  from  PRIMES.  The 
remaining models of the PRIMES suite modules are then calibrated so as to reproduce 
the  fuel  mixes  as  calculated  by  the  new  model.  E.g.  PRIMES-TREMOVE  respects  the 
share  of  synthetic  gasoline  vs.  bio-gasoline  (and  petroleum-based  gasoline)  used  by 
cars, as this is calculated by the new model extension.  

The module is pan-European and solves all countries of Europe simultaneously in order 
to capture trade of the carriers, location of new factories and infrastructure (power grids, 
gas,  H2 network and distributed heat). It  optimizes the investments  and operation  of 
the  system  under  perfect  foresight  assumptions.  It  includes  several  non-linear 
mechanisms: 

▪  Cost-potential non-linear curves for exhaustion of resources (increasing slope) 

▪  Non-linear learning curves (technology) and economies of scale (factory), both with 

decreasing slopes  

▪  Uncertainties and heterogeneity implying hidden-perceived costs which non-linearly 

depend on enabling conditions (such as a carbon price). 

In a nutshell, the new model covers the following energy forms: 

▪  Electricity: It can be produced via numerous sources, either fossil or carbon-free. 

Electricity can be stored in a plethora of ways, either directly in batteries, or via the 
conversion to intermediate energy forms (pumped storage, chemical storage as 
hydrogen, methane etc.).  

January 2018  I  65 

 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

▪  Heat and steam: Produced via heat pumps, boilers, CHPs units, for distributed or 

on-site consumption.   

▪  Carbon dioxide: Carbon dioxide serves an important role; it acts as the main 

feedstock source for the production of synthetic hydrocarbons. It can be captured 
from air or via applying CCU technologies to energy and industrial applications. Only 
the former though guarantees that the synthetic fuels produced will be carbon 
neutral (or even providing negative emissions, in case they are combusted in 
biomass fuelled power plants equipped with CCS technology-BECCS). 

▪  Hydrogen: Carbon-free hydrogen is assumed to be produced via electrolysis running 

on renewable electricity. It can serve as an energy carrier (either combusted or 
used in fuel cells in stationary or mobile applications), as feedstock for the 
production of synthetic fuels, or as a means of storage for balancing the generation 
of variable renewables. Hydrogen can be transferred via dedicated pipelines (that 
require investments in infrastructure) or blended in the natural gas stream up to a 
certain share (15%) due to technical limitations.  

▪  Biofuels (liquid and gaseous) – They are produced using feedstock of biomass 

origin. The model distinguishes fungible from non-fungible biofuels. The former can 
fully substitute petroleum products, the latter are blended up to certain shares with 
fossil based gasoline and diesel because of technical limitations. Upgraded biogas 
(bio-methane) can be blended to the natural gas stream.  

▪  Synthetic methane – Synthetic CH4 is an output of a process such as methanation, 

which utilises hydrogen and carbon dioxide as inputs. The process is energy-
intensive, requiring large amounts of electricity. This carrier is usually referred to as 
“clean gas”, since its net carbon intensity is lower than the one of natural gas, and 
the pathways to produce it as Power-2-Gas (P2G, PtG). Depending on the origin of 
CO2 synthetic methane can be considered even as carbon free, if the CO2 is 
captured from ambient air. 

▪  Synthetic liquid hydrocarbons – Usually referred to as Power-2-Liquids (P2L, PtL); 

such fuels can fully substitute petroleum based products in mobile applications with 
no radical changes in ICE powertrains. The conventional powertrains continue to run 
on fuels with characteristics similar to the ones of conventional oil products. Such 
vehicles exhibit no range limitations and therefore synthetic fuels could be more 
easily adapted by transport consumers. The competition with the “electrification of 
the transport system” can hence be assessed by the enhanced PRIMES model 
characteristics. However, PtL fuels would probably find more room for development 
in transport modes, where decarbonisation options are limited (aviation, long 
distances road freight transportation), where they have to compete only with 
advanced biofuels (with limited domestic resources) and/or technologies that are 
currently at low TRL levels (e.g. electric aircrafts). Synthetic hydrocarbons are 
produced in the model with two main pathways whose intermediate products are 
either syngas (blend of CO and H2), or alcohols (methanol). 

▪  Electricity Storage – Although technically, not an energy form, power storage is an 

important element of the new module. Storage can be served either via batteries or 
via the intermediate step of producing hydrogen and/or synthetic methane for later 
use. The operation of the module at an hourly resolution allows capturing the 
appropriate time segments for power injection to storage, and extraction from 
storage at a later time interval. 

▪  Fossil fuels – serving as conventional energy carriers. Their use results in GHG 

emissions.  

January 2018  I  66 

 
 
 
Sectoral integration: long-term perspective in the EU energy system 

Sectoral  integration  in  the  energy  system  towards  2050:  three 
strategies 
In the following we will analyse three strategies which would allow the achievement of 
near  zero  emissions  by  using  hydrogen  as  a  means  for  sectoral  integration.  The 
strategies are extreme in their assumptions in order to highlight the benefits and the 
disadvantages  of  each.  The  following  chapter  then  analyses  three  more  realistic 
scenarios in which the period to 2050 is analysed concretely where options which try to 
take  advantages  of  the  benefits  of  the  analysed  strategies,  while  minimising  the 
disadvantages are constructed.  

As  stated  above  the  achievement  of  near  zero  emissions  goes  beyond  the  analyses 
which  have  until  now  been  undertaken  in  the  existing  roadmaps,  which  all  obtain 
approx. 80-95% emission reductions in 2050 compared to 1990. The changes required 
for going beyond 80-95% emission reduction in the period just after 2050 need to start 
well before 2050, as the technologies and infrastructure required need time to develop 
as  to  achieve  such  deep  reduction  it  is  necessary  to  go  beyond  technologies  mature 
today.  As  the  developments  of  these  technologies  are  uncertain  and  cannot  be 
determined with any certainty today we present three different strategies which allow 
for the achievement of strong emissions reductions. 

The basis for the analysis will be the one of the key scenarios of the Winter Package 
which  is  referred  as  a  basic  decarbonisation  scenario.  The  context  is  therefore  a 
framework which achieves the 2030 objectives and further the reduction of emissions 
by at least 80% in 2050 compared to 1990. The scenario assumes enabling conditions 
for  decarbonisation:  this  implies  that  agents  act  knowing  strong  emission  reductions 
need to be achieved. Technologies are therefore assumed to develop following positive 
assumptions  on  their  learning  curves  and  infrastructure  developments  and  market 
coordination  also  takes  place.    The  additional  condition  for  the  strategies  considered 
here is the requirement to achieve close to zero emissions shortly after 2050. 

As  the  extent  of  technology  and  infrastructure  development  cannot  be  known,  within 
this study we develop three strategies to explore different options of hydrogen based 
on different focuses of technology development:  

▪  Strategy A - H2 as an energy carrier: explores the requirements, and the pros 

and cons of the development of end-use technologies using hydrogen (fuel cells and 
ICEs) in both stationary and mobile uses, exploring the use of hydrogen as an end-
use fuel.  

▪  Strategy B - H2 as feedstock explores the requirements, and the pros and cons of 
the development of power-to-X technologies exploring the use of hydrogen as an 
intermediate storage option and to allow for the decarbonisation of all sectors. 

▪  Strategy C – H2 as a means of electricity storage the requirements, and the 
pros and cons of hydrogen as an enhanced storage option for power generation, 
accompanied by extreme electrification in all sectors.  

All  three  strategies  assume  technology  success  and  adequate  policy  enablers,  which 
differ  for  each  strategy.  The  following  analysis,  founded  on  modelling  results  of  the 
PRIMES modelling suite, will describe the system requirements and analyse the main 
uncertainties and key issues to be resolved for each strategy. 

Common elements of the strategies  

All  strategies  analysed  here  require  sectoral  integration  and  the  use  of  hydrogen  to 
different degrees.  

January 2018  I  67 

 
 
 
Sectoral integration: long-term perspective in the EU energy system 

The first step is therefore the production of carbon-free hydrogen from power: this is 
projected to occur through electrolysis which achieves market maturity within a medium 
time  frame.  A  common  assumption  for  all  strategies  is  therefore  the  need  for  strong 
reduction in the costs of electrolysis cells, particularly PEM-cells, already in the period 
to  2030  for  centralized  production.  Alkaline  cells  currently  have  the  lowest  costs, 
however their cost reduction potential is more limited as is their ability to operate under 
flexible load, therefore the strategies base on the assumption that there will be a large 
diffusion of PEM-electrolysis cells; also SOEC cells have the possibility to strongly reduce 
their  costs,  however  the  current  TRL  level  is  approximately  5  (validated  technology), 
and  the  decrease  in  cost  and  their  market  maturity  is  assumed  to  occur  too  late  for 
applicability within the time period required by climate scenarios to keep within a 2°C 
world.  Alkaline  cells  are  considered  to  have  a  TRL  level  of  9  (industrial  production), 
whereas PEM-cell are at a level of 8, i.e. pre-industrial production.   

As shown in Figure 18, the electrolysis production of hydrogen is less costly than gas 
reforming in a decarbonisation scenario context. Under ultimate learning, the levelized 
unit costs of hydrogen are of the order of €100/MWh when electricity wholesale sales 
are  at  €70/MWh.  The  economies  of  scale  are  small,  roughly  of  the  order  of  20% 
ultimately,  when  comparing  centralised  production  of  hydrogen  and  small  scale 
electrolysis costs on the site of a large refuelling station. 

In  order  for  this  strong  cost  reduction  to  occur,  involved  actors  must  anticipate  the 
requirement to decarbonize the energy system, the increasing flexibility requirements, 
a demand for hydrogen for storage needs, as an energy carrier or feedstock. For this 
purpose,  aside  from  technological  developments,  also  a  regulatory  certainty  must  be 
perceived  by  investors,  in  order  to  achieve  the  economies  of  scale  required  for  the 
developments.  As  will  be  described  below,  dependent  on  the  strategy  such 
developments need to be anticipated in different time periods.  

Figure  18:  Prospects  of  production  cost  of  hydrogen  in  a  decarbonisation 
scenario context 

January 2018  I  68 

48107881311022341089218560133919791188858914918626722995941159090108Gas steam reforming centralised - Large ScaleGas steam reforming centralised - Large Scale with CCSUGas steam reforming de-centralised - Medium ScaleElectrolysis PEM de-centralised at a refueling stationElectrolysis Alcaline de-centralised at a refueling stationElectrolysis SOEC de-centralised at a refueling stationElectrolysis PEM Large ScaleElectrolysis Alcaline Large ScaleElectrolysis SOEC centralisedLevelized unit cost of hydrogen in EUR/MWh of H2>205020302015 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

Strategy A: Hydrogen as an energy carrier 

This strategy explores the possibility of using hydrogen from power directly in end use 
sectors.  It  goes  in  the  direction  of  what  has  sometimes  been  called  a  “hydrogen 
economy”. 

Strategy requirements: key uncertainties and opportunities 

The main idea of this strategy is to produce hydrogen through electrolysis from (mainly) 
renewable electricity, and use the hydrogen directly in end use sectors which will need 
to adapt to using hydrogen. 

This strategy would require two key issues to be resolved positively: 

Development of hydrogen fuel cells: Technological development of fuel cell 
technologies for stationary and mobile uses (high temperature and low 
temperature fuel cells), leading to significant cost reductions. While the use of 
hydrogen would save additional transformation requirements, these 
developments are far from certain, although there are developments for fuel 
cells.  

Development of a hydrogen transportation and distribution network: 
the strategy requires the development of hydrogen infrastructure, however the 
costs for such a development are high. There are several possibilities, however 
each entail also signification drawbacks: 

o  Hydrogen conditioning is necessary but inefficient for energy 

consumption 

o  Compressed hydrogen can be produced directly from electrolysis with 

low additional energy losses from PEM-cells 

o  Producing liquefied hydrogen to transport over long distances implies 

30-40% energy losses in liquefaction 

o  Road or rail transportation of compressed hydrogen is expensive 

o  Pipeline transport of hydrogen needs new infrastructure or retrofitting of 

gas pipelines at significant costs 

o  Hydrogen storage in pressurised tanks and line pack are probably the 

only practical and economic possibilities 

Direct use of hydrogen in stationary and mobile energy applications can use fuel cells 
which  can  either  operate  at  high  temperature  as  small-scale  CHP  units  for  heating 
purposes or lower temperature for mobility. Small scale CHP units are required for use 
in  buildings  (both  residential  and  services),  as  well  as  for  industrial  purposes.  For 
transport, fuel cells can be used for light duty vehicles as well as heavy duty applications 
in road transportation. The use of fuel cells is not yet a proven technology for aviation, 
while use for shipping purposes is possible for short sea shipping and requires further 
technology development to apply to long distance shipping.  

The fuel cells are technically reliable and efficient in energy but are currently expensive; 
the magnitude of learning potential of fuel cells is uncertain. For this strategy to occur 
an optimistic view on fuel cell development needs to be taken, in order for fuel cells to 
become  competitive  with  electric  battery  powered  vehicles.  Until  today,  industry  has 
failed to deliver the promised cost reductions of fuel cells, regularly postponing to the 
future the achievement of market maturity. 

Direct  use  of  hydrogen  for  combustion  in  end-uses  is  possible  but  technological 
adaptations  of  equipment  are  needed.  There  exist  numerous  possible  applications  of 
using hydrogen directly in industrial furnaces and kilns. 

January 2018  I  69 

 
 
 
Sectoral integration: long-term perspective in the EU energy system 

The use of hydrogen at a large-scale in stationary uses of energy requires a development 
of a full scale distribution system based on pipelines. Transport of hydrogen by trucks 
in  compressed  or  liquefied  form  may  be  a  viable  solution  for  refuelling  stations  in 
transport but not for stationary energy uses. Similarly, on-site small scale electrolysis 
is also not viable for stationary uses of hydrogen except in a few large-scale industries. 

the 

therefore 

The  strategy  of  promoting  hydrogen  as  an  energy  carrier  further  requires  a  timely 
recognition of the potential cost reductions of fuel cells for transportation and small scale 
stationary  applications,  and 
timely  development  of  hydrogen 
infrastructure. The use of pure hydrogen as an energy carrier as this strategy foresees, 
requires  the  creation  of  a  dedicated  hydrogen  transportation  and  distribution 
infrastructure for refuelling purposes and for the distribution to the domestic sector and 
industry. The development of hydrogen infrastructure is a timely and costly issue, which 
can  cause  significant  disruptions.  Hydrogen  cannot  use  the  existing  natural  gas 
infrastructure, as the current pipeline design would lead to leaking. Developing a new 
infrastructure  to  the  level  required  for  a  substantial  substitution  of  the  natural  gas 
infrastructure to allow for a “hydrogen economy” will be complicated. However, if it were 
to  develop  a  carbon  free  integrated  energy  system  would  develop  with  a  universal 
energy carrier.  

As  mentioned,  the  energy-carrier  strategy  crucially  relies  on  two  elements:  the 
development of fuel cells and the establishment of a hydrogen infrastructure. While the 
first  element  requires  mainly  technical  development,  the  second  requires  a  policy 
decision  to  establish  such  an  infrastructure.  Obviously  such  a  decision  will  only  take 
place once there is a relative certainty about the development of fuels cells, however 
economies  of  scale  for  fuel  cells  can  only  be  achieved  once  there  is  certainty  of  the 
development of an infrastructure. 

The main advantage of this strategy is the adoption of hydrogen which is a universal 
and flexible fuel which can be applied to all sectors and the maintenance of high energy 
efficiency  thanks  to  the  use  of  fuels  cells  (depending  on  the  hydrogen  distribution 
infrastructure chosen).  

Changes required in the energy system  

A  strategy  founded  on  using  hydrogen  as  an  energy  carrier  throughout  the  energy 
system requires fundamental changes to the energy system as a whole. In the following 
we identify the key changes and challenges that would be required in both the demand 
and supply side sectors.  

For the demand side sectors, the changes are substantial for mobility and challenging 
for the stationary sectors.  

The buildings sector would still be expected to undertake all the energy efficiency effort 
which is projected in a basic decarbonisation scenario context. Almost the entire building 
stock undertakes energetic renovation until 2050, and a very large share of the buildings 
stock would rely on heat pumps powered through electricity. However, the remaining 
buildings using natural gas in a decarbonisation scenario context would be expected to 
switch to using hydrogen. Initially in such a strategy it would be expected that hydrogen 
is mixed with natural gas –to its technical limit- in order to lower its emission factor, 
which would still allow using the same equipment using natural gas. As fuel cells become 
available  (probably  close  to  2050),  equipment  would  need  to  be  shifted  from  natural 
gas  condensing  boilers,  to  fuel  cell  micro-CHPs  which  would  provide  steam/heat  and 
also some/all electricity allowing the houses to reach the aim of being nearly zero energy 
buildings, or even active buildings (Prosumers), possibly even selling electricity to the 
grid. While the changing of equipment from boilers to fuel cells would probably be to a 
large extent similar to switching from oil to gas, as has been occurring and is occurring 
today, the connection to the infrastructure and the switching of the infrastructure is far 

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from trivial. Constructing a parallel infrastructure to the existing natural gas grid would 
be extremely costly, however modifying the natural gas grid is also complex: it would 
require the infrastructure to be  shut down temporarily leaving buildings without their 
main  energy  source  for  heating,  something  which  could  happen  only  outside  of  the 
heating  season  or  possibly  even  when  the  building  dwellers  were  not  there.  Such  a 
complex change would need very careful planning, however it would allow the building 
sector to become emission free and there to be some competition between electricity 
and hydrogen avoiding a mono-fuel solution.  

Also  industry  would  be  required  to  undertake  the  same  significant  energy  efficiency 
developments  as 
in  the  decarbonisation  scenario  context,  however  extreme 
electrification would not be necessary in specific industrial processes, which nonetheless 
cannot cover all applications. The use of high temperature fuel cells with CHP in industry 
would provide steam of high quality for many industrial uses, however, direct injection 
of hydrogen is more appropriate for high temperature applications. There is a market 
scope for clean hydrogen in furnaces, kilns and the blast furnaces, also in calcination 
and  annealing  industrial  processes.  Using  hydrogen  in  these  high  enthalpy  processes 
presents advantages over electrification. The fuel cells as CHP units can compete for the 
medium and low enthalpy uses in industry. From an energy efficiency point of view, the 
optimisation suggests that both electricity and hydrogen keep specific roles and shares 
in  the  industrial  processes.  Full  independence  from  fossil  fuels  is  thus  possible  in 
industry.  

Carbon-free  hydrogen  would  be  readily  available  for  non-energy  uses,  which  today 
already  use  hydrogen  mainly  from  steam  reforming;  this  would  already  significantly 
reduce emissions from industry. These sectors would benefit from the strong reduction 
in electrolysis costs, driven by the economies of scale of large scale hydrogen production 
for the entire energy system.  

With fuel cells expected to develop at a large scale only close to 2050, it is reasonable 
to expect that car electrification will develop earlier in the transport sector, at least as 
a dominant solution for urban areas. In long-distance travelling vehicles the longer term 
maturity  if  fuel  cells  enable  higher  competitiveness  than  the  battery-based  electrical 
vehicles. Therefore, the projections expect that fuel cells develop mainly for heavy duty 
road transportation, coaches and the large vehicles frequently travelling long distance 
trips. Although the fuel cells and hydrogen tanks are heavy, batteries are still expected 
to be more problematic for long distance travelling vehicles. If they are facilitated by a 
sufficient refuelling infrastructure and assuming availability of less expensive fuel cells, 
the projection shows that fuel cells can gain market shares for private cars in the long 
term  (close  to  2050  and  beyond)  and  gradually  substitute  all  kinds  of  the  remaining 
non-electrified  vehicles  still  relying  on  liquid  fuels.  Biofuels  would  still  be  required, 
particularly  for  aviation  purposes  and  in  shipping  for  bunkers.  For  short  sea  shipping 
fuel  cells  would  slowly  penetrate  the  market  and  in  the  longer  term  also  for  medium 
distance travelling ships.  

Although fuel cells are very efficient, the production chain from electricity to hydrogen 
and then the transport  and distribution still  requires  substantial amounts of  energy  – 
electricity in this case. Based on modelling results only for the substitution of remaining 
emitting  fuels,  electricity  consumption  would  increase  by  just  under  80%  in  order  to 
achieve zero emissions, if hydrogen were to be used as an energy carrier in the end use 
sectors directly. An increase of 80% power generation requirements is a further huge 
change in the power sector.  

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Strategy B: Hydrogen as feedstock 

This strategy explores the consequences of using hydrogen as an intermediate storage 
option with the development of power-to-X technologies, which would allow to produce 
fuels chemically equivalent (fungible) to those used today in a carbon free manner.  

Strategy requirements: key uncertainties and opportunities 

The main idea of this strategy is to produce hydrogen from electricity and use it as a 
feedstock to produce gas and liquid hydrocarbons which are substitutable to the fuels 
used  today.  Such  a  strategy  requires  the  development  of  complex  power-to-X  (X: 
hydrogen,  gas,  liquids,  heat)  factories  to  supply  clean  synthetic  methane  and 
hydrocarbons which can use the existing distribution infrastructure, while also providing 
storage to the power system. Electrolysers are required as in all strategies taken into 
consideration. Fuel cells however are not required and could remain a marginal niche 
market  technology,  as  is  the  case  today.  Hydrogen  becomes  a  feedstock  for  the 
production of hydrocarbons (gas and liquids) by combining the hydrogen with carbon 
dioxide. Obviously, as this strategy only substitutes the origin of the hydrocarbons the 
distribution  systems  remain  as  today.  This  is  the  most  notable  advantage  of  this 
strategy. 

The hydrogen-feedstock strategy would require the development of power to gas and 
power to liquid production chains at a large-scale coupled with massive production of 
clean electricity ideally achieving base-load rates of use.  

Power to Gas: Through a process call methanation hydrogen is combined with 
carbon  dioxide  to  produce  methane  gas  -termed  “clean  gas”:  the  great 
advantage of producing methane is that it is fully substitutable with natural gas 
and can be fed into the existing natural gas distribution network with no technical 
limitations. It further can be used in stationary uses, exactly as natural gas. As 
the methane will be a domestic product, the hydrogen-feedstock strategy fully 
solves the security of supply issues related to dependency on gas imports.  

The  methanation  however  implies  a  further  loss  of  energy  efficiency  over  the 
lifecycle, getting to  an overall  rate below 40-50%, but the  output can be fully 
stored and re-electrified in a perfectly versatile way. Thermochemical catalytic 
technologies for methanation are at an advanced stage of development. The unit 
costs of methanation are small and reasonable. However, the costs of capturing 
CO2  from  the  air  are  today  high  and  their  reduction  through  learning  is  quite 
uncertain at present.  

Power to liquids: Further to the production of clean gas another opportunity is 
to use the hydrogen as a feedstock for the production of liquid fuels (Power-to-
liquid).  Several  technologies  are  possible,  which  can  be  classified  into  two 
groups:  

o  combined electrolysis and carbon dioxide chemical treatment (electro-
reduction, co-electrolysis, reverse water gas shift) which produces 
methanol, dimethyl ether etc. that are further upgraded to transport 
fuels after hydrogenation;  

o  Fischer-Tropsch conversion of syngas, produced from a treatment of H2 

as an output of electrolysis and CO2. 

All technology pathways are energy intensive, however they allow for the continued use 
of the existing infrastructure and technologies and importantly provide an alternative to 
excessive production of fuels from bioenergy products, or extreme electrification. As in 
the case of methanation, the capital costs of power to liquid technologies are reasonable 

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but the overall energy  efficiency of the chain is very poor while the  cost of capturing 
CO2 from the air is high and uncertain.  

The origin of CO2 is a crucial element to consider for this strategy: only CO2 captured 
from  ambient  air  guarantees  full  carbon-free  fuels.  This  technology  is  currently  at  a 
demonstration  level  of  development  (TRL  level  6).  For  the  development  of  such  a 
strategy  this  technology  needs  to  become  a  mature  technology  by  following  a  steep 
learning curve before 2050. Using CO2 captured from fossil burning power plants (CCU), 
reduces but cannot eliminate CO2 emissions, as the CO2 is simply emitted at a different 
place (in car exhaust fumes rather than by the power plants directly), and CC technology 
only has a maximal capture efficiency of approx. 90%. For this reason, CO2 captured 
from power plants cannot be considered an option to reach near zero emissions.  

From  a  technical  point  of  view  therefore  crucial  developments  required  for  such  a 
strategy are: 

▪  The development of CO2 capture from ambient air 

▪  Development of combined electrolysis and carbon dioxide chemical treatment 

technologies  

▪  Or alternatively the development of large scale Fischer-Tropsch 

The latter in particular can benefit from the developments in the biofuel industry, where 
F-T synthesis is also a crucial technology for the production of lignocellulosic fuels.  

The  use  of  hydrogen  as  a  feedstock  combined  with  CO2  capture  from  air  is  able  to 
produce  emission free fuels (at a cycle level)  which are  fully substitutable to the  fuel 
currently used, which implies they  can be used in the current infrastructure and with 
current technologies.  

Figure 19: Prospects for clean gas costs in a decarbonisation scenario context 

The  produced  fuels  should  be  used  to  fully  decarbonize  the  industrial  and  buildings 
sectors  through  the  clean  gas,  although  direct  electrification  and  energy  efficiency 
should  continue  to  be  the  keys  means  of  decarbonisation.  For  the  transport  sector 
electrification  of  LDVs  is  assumed  to  occur  nonetheless,  but  the  difficult  to  electrify 
transport  modes,  aviation,  shipping,  and  long-distance  freight  road  transport  are 
assumed to continue using liquid fuels however produced via power to liquid, limiting 
the use of excessive biofuels.  

January 2018  I  73 

239818516528333112141146222132391131132154Fossil natural gas (including carbon emission costs)Clean Gas (via Steam Reforming Natural Gas)Clean Gas (via PEM Electrolysis)Clean Gas (via Alkaline Electrolysis)Clean Gas (via SOEC Electrolysis)Levelized unit cost of methane in EUR/MWh of CH4 >205020302015 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

Figure  20:  Prospects for clean  liquid fuel costs  in  a decarbonisation  scenario 
context 

The Figure 19 shows the projected unit cost of clean gas in a decarbonisation scenario 
context.  Assuming  full  learning  of  the  technologies  and  exploitation  of  economies  to 
scale, the unit cost of clean gas production can reach a level which is comparable to the 
unit  cost  of  natural  gas  in  2050  provided  that  an  adequate  carbon  price  (above 
€100/tCO2) penalises the cost of natural gas. This is remarkable, as it shows that in a 
decarbonisation scenario context there exist an affordable full-scale substitution of the 
remaining  amounts  of  natural  gas  which  at  the  same  time  solves  the  issue  of  the 
remaining emissions from the fossil natural gas and eliminates any threat on security of 
supply stemming from dependence on gas imports.  

The  Figure  20  shows  that  the  economic  competitiveness  of  clean  diesel  compared  to 
fossil diesel is also possible in a decarbonisation scenario context provided that a high 
carbon price penalises the unit cost of fossil diesel. There is uncertainty regarding the 
winning power-to-liquid technology, but the projection shows that the Fischer-Tropsch 
route using PEM electrolysis seems to achieve the lowest costs among the competing 
technologies.  The  main  uncertainty  regards  the  future  costs  of  the  SOEC  electrolysis 
which can support the high temperature power-to-liquid route, which for some authors 
could be the most promising in the future.   

The  production  chain  of  clean  liquid  gas  and  fuels  is  very  inefficient  from  an  energy 
perspective  and  therefore  the  additional  electricity  requirements  are  enormous.  The 
projections show that the power generation system will need to increase between 130-
170%  post  2050  (compared  to  2030)  to  produce  clean  gas  and  liquid  fuels  to  fully 
substitute the fuels remaining in use in the context of a decarbonisation scenario. By 
assuming such a context, it is evident that the amounts of fossil fuels (gas and liquids) 
remaining in use by 2050 are the minimum possible. Despite this, the projected increase 
in  the  power  system  size  is  still  enormous  to  substitute  all  remaining  fuels  by  clean 
ones. Obviously, such an increase in the size of the power system is challenging for the 
power generation resources (including the renewables) and the grids. Large-scale new 
grid  developments  are  necessary  to  link  with  remote  areas  and  transfer  additional 
amounts of renewables. Nuclear can find a favourable business case to develop (much 
above current levels) provided that there exist nuclear sites and appropriate acceptance 
conditions. 

Such  a  strategy  assumes  that  there  is  strong  policy  support  for  the  production  of 
synthetic-clean  fuels  which  provides  regulatory  certainty  for  large  scale  investors.  It 
must be assumed that long term contracts between clean electricity suppliers and fuel 

January 2018  I  74 

0.482.232.272.360.881.781.792.132.371.931.692.27Fossil diesel oil (including carbon emission costs)Clean Diesel via Methanol (via PEM Electrolysis)Clean Diesel via Fischer-Tropsch (via PEM Electrolysis)Clean Diesel via High temperature co-electrolysis andFischer TropschLevelized unit cost of diesel in EUR/lt of diesel>205020302015 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

production  facilities  are  facilitated  which  provide  certainty  to  both  investors.  This 
strategy  requires  strong  coordination  from  actors  across,  implying  that  coordination 
failure is one of the key risks of this strategy.  

Changes required in the energy system  

A  strategy  founded  on  using  hydrogen  as  a  feedstock  to  produce  the  gas  and  liquid 
hydrocarbons fully substitutable to the fuels used today requires significant changes to 
the supply side sectors (power generation and fuel production), while requiring much 
more limited changes in the demand side sectors.   

For  the  demand  side  sectors  changes  beyond  those  assumed  within  a  basic 
decarbonisation  scenario  context  are  limited.  Due  to  the  very  low  efficiency  of  the 
production  chain  of  the  synthetic  fuels  assumed  to  be  produced,  their  use  should  be 
limited by energy efficiency and electrification; however, their availability implies that 
electrification does not need to go beyond technically and economically feasible cases.  

Buildings in such a context should, as in the case in the basic decarbonisation scenario 
context,  undergo  strong  renovation  in  order  to  achieve  significant  improvements  in 
terms of energy efficiency, reducing the consumption of buildings substantially. Further 
electrification by use of heat pumps should continue to make significant insights. The 
then remaining use of hydrocarbon fuels (mainly natural gas) could continue to occur, 
without any changes to end-use equipment or infrastructure as the clean gas produced 
would be chemically fully equivalent to the current natural gas, excluding any impurities.  

For industry, the possibility of using fuels which have no emissions on a life cycle basis, 
but  are  chemically  equivalent  to  today  would  entail  significant  simplifications  from 
today’s perspective. The hydrogen required for non-energy uses could still be produced 
in  a  carbon-free  way,  as  the  electrolysers  are  assumed  to  develop  anyhow  in  this 
scenario.  As  is  the  case  for  buildings,  energy  efficiency  would  still  be  required  to  the 
extreme  as  the  power-to-X  fuels  are  very  inefficient  from  a  system’s  perspective; 
however, the availability of the “carbon free” fuels do not require extreme changes in 
some production chains. Some production changes, e.g. glass production, where a shift 
to electricity would cause changes in the glass composition, would greatly benefit from 
the availability of power-to-X fuels.  

The transport sector and indirectly the biofuel sector (and all its production chain) would 
be the main “beneficiaries” from the availability of power-to-X fuels. Again, because of 
the inefficiency in the production of power-to-X fuels and therefore their high end-user 
cost,  the  transport  sector  would  still  be  required  to  undergo  all  the  changes  towards 
electrification which are projected in the decarbonisation scenario context. For private 
road transportation battery electric vehicles would remain the key technology, as well 
as for urban transportation (freight LDVs, etc.). Power-to-X fuels would enter the market 
along-side fungible biofuels allowing the transport sector to fully decarbonise  without 
needing  to  rely  on  either  very  uncertain  (from  today’s  perspective)  technological 
develops  such  as  fuel  cells  (strategy  A)  or  electric  aviation  (strategy  C),  or  on  the 
excessive use of biofuels, which may lead to sustainability issues.  

While  the  proposed  strategy  of  using  hydrogen  as  a  feedstock  to  produce  fuels  fully 
substitutable  with  today’s  fossil  produced  fuels,  limits  the  required  changes  to  the 
demand side sectors to those projected for the decarbonisation scenario context which 
does  not  achieve  near  zero  emissions,  the  changes  required  on  the  supply  side  are 
immense.  

For the production of the power-to-X fuels an entire new production chain needs to be 
put in place. Large scale factories linked to electrolysers and power producers need to 
be constructed which transform power to hydrogen to hydrocarbons. These are entirely 
new facilities with to a large extent new technologies only used at small scale facilities 

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today.  The  facilities  would  need  to  be  placed  where  the  electrolysers  are  in  order  to 
avoid requirements to transport the intermediate product hydrogen; the electrolysers 
would most probably be placed at the landing points of large DC transmission lines. If 
these places correspond to current industrial sites or new industrial sites entirely would 
need to be constructed, is not the focus of this study, it should however be taken into 
consideration for further assessments, as this could have issues with public acceptance, 
could however on the other hand also provide considerable employment.  

Aside from the huge construction requirements for the facilities to produce the power-
to-X  fuels,  enormous  additional  power  generation  capacity  is  needed,  as  mentioned 
above.  The  inefficiencies  of  the  fuel  production,  due  to  the  numerous  transformation 
processes, imply enormous additional electricity requirements.  

An increase between 130-170% post 2050 (compared to 2030) in the size of the power 
sector  of  Europe  to  produce  the  clean  fuels  using  hydrogen  feedstock  in  a 
decarbonisation scenario context requires significant increase in renewables and nuclear 
energy. The possible increases in  renewables (above the levels projected in the main 
decarbonisation scenario for 2050 and beyond) are mainly from offshore wind located 
in remote areas (North Sea) and by using the floating wind offshore technology, as well 
as from the development of very small scale roof top wind. Increase in installations of 
wave energy are also possible in this context. The development of solar and traditional 
onshore wind energy above the levels of the basic decarbonisation scenario is less likely. 
Nuclear  may  increase  up  to  50%  the  installed  power  capacity  compared  to  present 
levels. This is an important contribution to ensuring adequate supply of electricity in the 
context  of  production  of  clean  gas  and  fuels.  Obviously,  the  additional  power  sector 
developments would require additional interconnections, including reinforcement of DC 
super-grids needed to integrate the large-scale wind offshore production.  

Strategy C: Hydrogen for power storage 

This strategy focuses on the use of hydrogen for power storage only and consequently 
presumes large scale electrification in all sectors.  

Strategy requirements: key uncertainties and opportunities 

Electrification  is  the  key  word  of  this  strategy:  electricity  substitutes  all  other  energy 
carriers  at  a  consumer  level,  as  much  as  current  and  future  technology  permit.  The 
domestic  sector  is  entirely  electrified  and  the  same  occurs  with  industry,  where 
bioenergy is used in the rare cases where electricity cannot be used technically. In the 
transport  sector  also  road  electrification  is  developed  to  the  extreme  including 
technologies for electric trucks (as for example the overhead lines in motorways). Even 
short distance electric aircrafts need to be included among the electrification options in 
transport.  

Nonetheless,  this  strategy  requires  a  modest  increase  in  demand  for  electricity 
compared to the basic decarbonisation scenario. The increase in demand for electricity 
is of the order of 20-30%, which is far less than in the case of using electricity to produce 
the hydrogen carrier or even worse the clean synthetic gas and fuels.  

To minimize electricity price and maximise reliability it is important to complement the 
electrification of end-uses with large-scale electricity storage. This is important also to 
balance the large amounts of variable renewables developed due to the requirement of 
zero emissions electricity, but also to smooth the load curves, which inevitably would 
suffer from higher volatility as electricity penetrates in all end-uses of energy. Electricity 
storage  is  of  higher  importance  in  the  maximum  electrification  scenarios  than  in  the 
previous cases based on hydrogen-carrier or hydrogen-feedstock. Large-scale storage 
of  electricity  is  also  important  for  security  of  supply  as  electricity  becomes  the  only 

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source  of  energy  for  the  consumers  and  all  transport  modes,  and  so  higher  levels  of 
reliability  than  usually  need  to  be  established  in  the  system.  Here  comes  the  role  of 
hydrogen  produced  from  electrolysis  as  a  perfect  and  versatile  electricity  storage 
system. The reliability of storage base on hydrogen, similarly to any kind of chemical 
storage of electricity, is much higher than with other means that require short cycles of 
charging  and  discharging  or  do  not  present  the  flexibility  of  scheduling  charging  and 
discharging  as  the  hydrogen  systems.  Higher  reliability  of  storage  implies  higher 
reliability of the power supply which is a must in the full electrification case, as already 
mentioned.  However,  the  projections  do  envisage  significant  development  of  the 
decentralised storage based on batteries both at the scale of the individual consumer 
and within the substations of the distribution system.   

In the end-uses of energy, the hydrogen-storage strategy requires the development of 
electric end-use technologies in all applications, which is far from certain from today’s 
perspective.  For  transportation  extreme  technical  solutions  are  required  to  fully 
electrify:  electric  airplanes  are  being  prototyped  for  very  short  distance  and  small 
airplanes.  There  is  obviously  competition  between  short  distance  aviation  and  high 
speed  railways.  Biofuels  would  be  utilised  in  such  a  strategy  for  all  uses  where 
electrification  is  impossible,  however  this  will  go  to  the  limits  of  sustainable  biofuel 
production.  

A  strategy  which  uses  hydrogen  as  storage  for  power  and  plans  to  electrify  to  the 
extreme  demand  side  sectors  could  initially  be  seen  as  a  “simpler”  solution  to  the 
problem.  From  the  power  side  this  is  indeed  probably  the  case  however  not  for  the 
demand  side.  For  the  demand  side  sectors,  the  technology  requirements  are 
significantly  more  complex  as  not  all  uses  are  electrifiable  with  technologies  known 
today.  Several  industrial  processes  are  very  difficult  to  electrify  and  technologies  are 
sparse, the quality of the output is affected and the production process might have to 
be altered. For the domestic sector electrification is theoretically possible without major 
drawbacks.  For  the  transport  sector  however  the  situation  is  different:  there  will 
continue to be modes  of transport  which cannot be  electrified.  Private  road transport 
can  be  electrified  to  a  huge  extent,  however  freight  road  transportation  over  long 
distances  is  very  problematic  to  electrify,  as  is  aviation.  For  the  purposes  of  a  full 
electrification strategy even technological solutions such as electric planes (small planes 
for short distances) need to be considered. 

Changes required in the energy system  

While  the  hydrogen-feedstock  and  hydrogen-carrier  strategies  provided  a  “simpler” 
solution for the demand side sectors and a more complex transformation of the supply 
side,  the  strategy  which  uses  hydrogen  only  for  power  storage  purposes  implies 
considerable  changes  in  the  demand  side  that  are  challenging  particularly  from  a 
technical point of view.  

For the demand side sectors  extreme technical solutions are required to allow for full 
electrification.  

For the domestic sector this strategy is challenging but not to the extreme: there are 
few uses in the tertiary sector where electrification is complex and there may be some 
public  acceptance  issues  for  niche  markets  or  users,  but  heating  uses  can  be  mostly 
electrified  without  major  technical  issues.  Energy  efficiency  and  renovation  obviously 
need to  continue to the extent possible in order to minimise the additional electricity 
needs.  

For the industrial sectors electrifying all uses is a complex issue. While again the non-
energy  use  of  hydrogen  can  be  catered  for  as  also  this  strategy  requires  the 
development of electrolysers, other issues are challenging. Some industrial processes 
such as glass production require the modification of the composition of glass in order to 

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work; processes based on chemical reactions at high temperature (kilns, blast furnace) 
and others require development of new technologies to fully electrify. While some actors 
in the industry are trying to adapt to these challenges, it remains unclear in what time 
scales  technical  solutions  can  be  found.  Steam  production  at  the  steam  quality 
requirements for some industrial process requires very high temperatures which imply 
very high electricity consumption which would need to be supplied at low costs.  

The transport sector will have extreme difficulties to fully electrify. Increasing the share 
of  biofuels  significantly  beyond  the  quantities  projected  in  a  basic  decarbonisation 
scenario  context  is  not  considered  a  viable  strategy,  as  sustainability  of  production 
would be jeopardised. While passenger road transportation could be fully electrified and 
rail is considered to be fully electrified, long distance road transportation, aviation and 
shipping cannot be fully electrified. Modal shifts mainly to rail could be considered (and 
are considered within the model), however capacity constraints due to limitations from 
the network do not allow extreme shifting: extreme technical solutions such as electric 
airplanes are therefore required. If short distance aviation is powered by electricity, this 
would shift part of the demand to high speed rail, due to higher tickets of aviation. The 
latter are the result of the needs for on-board battery (which is a significant cost). On 
the other hand, high speed  rail faces  capacity  constraints due to limitations from the 
network.  Biofuels  and  other  uses  of  bioenergy  are  already  high  in  a  decarbonisation 
scenario context and close to what today is considered a sustainable potential, therefore 
it  is  imperative  that  further  electrification  occurs  in  order  to  achieve  nearly  zero 
emissions. 

The supply side sectors require the most limited changes: the refuelling industry will be 
limited to biofuels and everything else will be related to power generation.  

From  a  power  generation  perspective  such  a  strategy  requires  the  least  additional 
capacity and generation (approx. 28%), however it will require additional capacities for 
flexibility  and  storage  as  the  power  system  alone  will  be  responsible  of  supplying 
uninterruptible power supply and follow demand load curves.  

Electricity demand and generation  

To  achieve  zero  emissions,  it  is  certain  that  electricity  generation  must  increase:  the 
magnitude of electricity increase will depend on the strategy followed.  

The  basic  scenarios  for  the  decarbonisation  policy23  project  an  increase  in  electricity 
generation of approx. 65% compared to 2015 in 2050. However, the basic scenario has 
significant  remaining  emissions  in  the  energy  sector  by  2050  and  has  not  dealt  with 
reaching  zero  emissions  after  2050.  In  this  context,  a  large  share  of  electricity 
generation  comes  from  variable  renewable  energy  sources  and  significant  balancing 
power resources need to deploy until 2050.  

The  basic  decarbonisation  scenario  context  is  one  where  the  majority  of  power 
generation (over 70%) comes from renewable energy sources, however also nuclear, 
gas and solids with CCS play a role; further biomass with CCS is included to obtain some 
negative emissions. Scenarios with a more dominant role of nuclear or CCS (either gas 
or solids) could be possible, but have significant drawbacks from a current perspective. 
Nuclear while theoretically able to deliver both no emissions and theoretically hydrogen, 
has issues related to public acceptance, costs and waste management; many Member 
States  are  exiting  nuclear  and  have  banned  new  power  plants.  Carbon  capture  and 
storage  on  the  other  hand,  has  public  acceptance  issues  related  principally  to  the 
storage of carbon and also has remaining emissions as the maximum capture efficiency 
is around 90%. If there were more widespread use of carbon capture and storage the 

23  The  scenarios used  in  the  Winter  Package  proposal  of  the  European Commission  in  November 2016.  The  main 
scenario is referred in the present study as “basic decarbonisation scenario”.  

January 2018  I  78 

 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

remaining emissions would require substantial negative emissions: options would imply 
burning clean gas from air capture or biomass with CCS in order to achieve negative 
emissions.  While  this  option  is  theoretically  possible,  it  is  an  extremely  expensive 
strategy and has a very limited efficiency (approx. 10-15% for the entire cycle). Further 
using biomass with CCS is debatable as sustainable biomass resources are limited and 
can be more efficiently used for the production of biofuels.  

Therefore, serious challenges stem from the significant increase in electricity demand 
involves in the strategies proposed throughout this study, especially for the hydrogen-
carrier  and  the  hydrogen-feedstock  strategies.  The  projections  show  that  the  large 
increase in demand for electricity implies a significant further increase in the deployment 
of  renewable  energy  sources  for  power  generation  (limiting  however  the  use  of 
biomass).  The  projection  finds  particularly  useful  to  using  electrolysis  to  produce 
hydrogen  in  periods  of  excess  production  of  electricity,  which  can  then  be  stored  for 
different  time  frames  for  re-electrification  either  through  fuels  cells  or  modified  gas 
turbines which can burn hydrogen directly.  

But,  the  strong  electricity  demand  cases  implied  by  the  strategies  which  produce 
hydrogen or clean fuels for the end-uses brings renewable production close to maximum 
possibilities, at least with known renewable technologies.  

A doubling of electricity, considering the limitations on nuclear siting and CCS implies a 
huge increase in production from renewable energy: such an increase implies reaching 
limitations of renewable potential within Europe. Such an increase requires additional 
capacity which could be achieved by assuming the development of capacity in remote 
areas  with  the  additional  requirements  for  transmission  lines  (direct  current-DC)  for 
example far offshore in the North Sea or outside of Europe in the Sahara, or alternatively 
by  assuming  development  of  new  materials  for  solar  power  or  which  allow  for  the 
construction  of  higher/larger  wind  turbines  which  would  allow  to  increase  generation 
from already exploited less remote sites.   

Discussion of modelling results 

Achieving a zero emissions scenario from the energy sector is challenging: the reduction 
of  the  remaining  emissions  beyond  the  -80%  GHG  reductions  achieved  in  roadmaps 
developed for the European Commission includes a number of issues to which it is not 
possible to provide conclusive answers with today’s knowledge status.  

It is imperative that already today the discussions are started and progress is obtained 
to facilitate the future achievement of a zero emissions scenario, so that ultimately the 
limitations and uncertainties are resolved.  

All  strategies  presented  within  this  study  are  not  realistic  from  today’s  perspective: 
Technological developments need to occur which are highly uncertain.  However, one of 
the great advantages of such a system which is ultimately based on electricity is that it 
would require very limited or any imports in the long term and security of supply issues 
would not depend on external factors.  

Hydrogen from power has several key benefits: 

▪  Substitution of fossil based H2 production for non-energy purposes 

▪  Provision of flexibility and storage for power generation 

▪  Provision of an energy carrier (either directly or indirectly) for difficult to 

decarbonize energy sectors 

The  projections  of  sectoral  integration  through  hydrogen  focusing  on  the  possible 
different uses of hydrogen have included H2 as a carrier, versus H2 as an intermediate 

January 2018  I  79 

 
 
 
Sectoral integration: long-term perspective in the EU energy system 

form  to  produce  synthetic  fuels  (as  a  feedstock),  and  hydrogen  limited  to  electricity 
storage. 

Below there is a summary of the main advantages and uncertainties of each strategy: 

Main uncertainties 

Main advantages 

H2 as a 
carrier 

▪  Need for a dedicated hydrogen 

▪  H2 is an energy carrier valid for 

distribution and transport 
infrastructure  

▪  Fuel cells development has to 
succeed in reducing costs 

the entire system 

▪  No limitations for car ranges, 
easier applicability to more 
transport modes 

▪  H2 storage at a large-scale 

▪  Significant but manageable 

needs to develop 

increase in power generation  

▪  Lower costs than for hydrogen 

as a feedstock 

▪  Transition phase can use natural 
gas infrastructure that needs 
gradual adjustment and 
upgrading 

H2 as 
feedstock 

▪  CO2 capture from air is 

▪  Continued use of existing 

uncertain technologically and 
economically 

distribution infrastructure for 
gas and liquid fuels 

▪  Extreme increase in demand 

▪  Convenient energy applications, 

for electricity  

equipment and processes 

▪  High unit costs of the clean 
end-products, however 
competitive at high enough 
carbon prices 

▪  Poor overall energy efficiency 

▪  No major disturbance of 

transport system 

▪  Full import independence  

H2 for 
power 
storage  

▪  Electric aircrafts, ships and 

▪  High efficiency of electricity in 

long distance trucks is 
uncertain 

end-uses 

▪  Feasible from power system 

▪  Electrification of all industrial 

perspective 

processes requires new 
technologies 

▪  Electrification of all residential 
energy uses may decrease 
utility compared to the 
convenience of using gas 

▪  Electricity becoming the single 
energy form for consumers 
implies concerns about the 
impact of lack of reliability in 
the power sector 

▪  Power-to-H2 used mainly for 

storage purposes can develop 
without major uncertainties and 
can achieve low costs 

▪  Very affordable at the level of 

the power system 

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A  balanced  sectoral  integration  scenario:  A  realistic  deep 
decarbonisation pathway for the long term to 2050 

Description of the main scenarios analysed in the study 

The  previous  section  of  the  current  chapter  has  presented  a  total  of  three  stylised 
strategies  that  can  provide  incremental  emission  abatement  on  top  of  the  emissions 
reductions achieved in a decarbonisation scenario, as the one used in the preparation 
of the proposals included in the Winter Package.  

Such a basic decarbonisation scenario has been constructed as part of the current 
study.  The  scenario  assumes  that  the  EU  climate  and  energy  targets  for  2030  as 
included in the Winter Package proposals of the EC are met. In order to achieve these, 
the scenario includes several sectoral measures: 

▪  measures for energy efficiency in the buildings sector, 

▪  regulatory emissions standards for LDVs (Light Duty Vehicle) aiming at low 

emissions mobility,  

▪  promotion of best techniques in industry, 

▪  facilitation of renewables in various sectors.  

The scenario also includes ETS as a multi-sectoral market-based measure, but due its 
sectoral scope to the power and heat supply and several industrial sectors, additional 
measures  are  required.  Therefore,  energy  efficiency  enhancement  and  renewable 
energy development are considered the system-wide pillars of the transition towards a 
low-carbon European economy. 

The  main  sectoral  integration  mechanism  included  in  this  scenario  context  is  the 
enhanced role of electricity, for the decarbonisation of end-use sectors that are currently 
largely dependent on fossil fuels, e.g. the transportation sector. The penetration of Low 
Emissions Vehicles in the fleet of cars and vans, driven by the introduction of stricter 
than  today  regulatory  emissions  standards,  and  the  penetration  of  electric  heating 
systems  in  the  building  sectors  (heat  pumps),  offer  opportunities  for  significant  GHG 
emissions  reductions  in  end-use,  however  overall  emission  reductions  can  only  be 
achieved with the power sector heads towards  full decarbonisation. If  the latter does 
not materialise, no net benefits in terms of system-wide GHG emissions will be achieved. 
The development of advanced biofuels is also a sectoral integration means needed to 
complement  road  electrification  and  reduce  emissions  from  the  transport  sector.  An 
intensified  role  of  advanced  biofuels  in  the  transport  system  requires  parallel  and 
coordinated  developments  in  certain  sectors  along  the  full  biomass-to-biofuels 
conversion  chain,  most  notably  in  the  agriculture  sectors  and  fuel  conversion  sector 
(bio-refining).  

The  quantification  of  such  a  scenario,  using  the  PRIMES  energy  systems  model  has 
revealed  that  in  the  long-term  (2050)  important  amounts  of  energy  and  industrial 
process CO2 emissions persist. The majority of unabated emissions originate from the 
transport sector, the industry and the building sectors. Therefore, in order to achieve 
the deep decarbonisation in the EU energy system that would be compatible with the 
pursuit of a 1.5oC target, as indicated by the concluding text of the COP21 meeting in 
Paris in 2015, it is necessary to further augment the intensity of the sectoral measures 
and achieve a higher level of sectoral integration. Such integration can be achieved via 
the  enhanced  role  of  hydrogen  in  the  energy  system  and  its  wide  introduction  as  an 
energy  carrier,  as  a  means  of  energy  storage  and  as  feedstock  element  for  the 
production of synthetic fuels. These three distinct roles of hydrogen have been analysed 
in the three strategies analysed presented in the previous section.  

January 2018  I  81 

 
 
 
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Each  strategy  has  its  own  strengths  and  weaknesses  that  stem  from  the  different 
characteristics  of  the  technologies  that  are  required  to  develop  in  each  strategy,  the 
uncertainty  surrounding  the  pace  of  learning,  the  need  to  upgrade  infrastructure 
networks  for  the  transportation  of  new  energy  carriers,  the  growth  in  electricity 
generation needed under each strategy, etc. All three strategies have the merit to lead 
to  an  almost  emission  free  and  energy  independent  European  Union.  They  are  all 
affordable  in  terms  of  total  energy  system  costs,  provided  that  the  new  technologies 
exploit  their  learning  potential  and  the  infrastructures  develop  without  market 
coordination failures. They can all lead to the EU energy system becoming almost carbon 
free by mid-century.  

However,  the  analysis  of  the  strategies  is  inconclusive  whether  either  one  of  these 
strategies would be a realistic image of the evolution of the future EU energy system in 
the long term, as all strategies contain major uncertainties which cannot be solved at 
the  moment.  For  instance,  the  electrification  of  aircrafts  on  a  massive  scale  is 
questionable,  as  well  as  the  widespread  penetration  of  hydrogen-powered  fuel  cell 
stacks in the buildings sector for heating purposes (along with the development of the 
relevant transportation infrastructure,). As a result, all three cases contain considerable 
uncertainties surrounding their future performance regarding costs, efficiency and the 
timing  of  readiness.  None  of  them  should  be  treated  as  an  optimal  pathway  for  the 
European energy sector; a more balanced approach needs to be adopted, inheriting the 
strong points of each strategy.  

The aforementioned considerations have led to the design of a new scenario which aims 
to optimise to the use of hydrogen and further enhance sectoral integration in a way 
that the advantages of hydrogen both as fuel and feedstock are amplified, in uses that 
are found to be economically viable. This scenario is called the balanced scenario.  

Figure  21:  Development  of  fuel  cell  stack  and  battery  costs  in  the  three 
scenarios considered 

The  balanced  scenario  is  built  on  top  of  the  background  context  underlying  the  basic 
decarbonisation scenario, i.e. it should be seen as an add-on not as an alternative. In 
this perspective, the key pillars remain the same – strong energy savings in buildings 
and industrial sectors driven by energy efficiency policies; very high share of renewables 
in the energy system, especially for power generation; strong push of electrification of 
the light transport sector and stationary applications where applicable; introduction of 
advanced  biofuels  to  decarbonise  non-electrifiable  transport  segments.  Beyond  these 
elements, the balanced scenario assumes that the strengths of hydrogen as analysed in 
the presentation of the three strategies are further exploited: hydrogen is expected to 
penetrate  energy  market  segments  where  it  can  provide  a  cost-effective  solution  to 
further GHG emission reductions.  

January 2018  I  82 

01002003004002020203020402050Euro'13/ kWFuel cell stack costs01002003004005002020203020402050Euro'13/ kWhBattery costsBasicdecarbonisationscenarioBalanced scenarioSensitivityscenario 
 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

The  introduction  of  hydrogen  is  based  on  the  assumption  that  hydrogen  based 
technologies  will  develop  significantly  in  the  coming  years:  electrolysers  for  the 
production of hydrogen, fuels cells particularly for the use in heavy road transportation 
and long distance transportation, as well as for industrial purposes in high temperature 
processes. Fuel cells for heavy road transportation are a key element of the balanced 
scenario  as  they  allow  to  decarbonise  a  difficult  sector  to  electrify  which  in  the  basic 
decarbonisation scenario is responsible for the majority of remaining emissions in 2050. 
In the basic and moderate scenarios, fuel cell costs are assumed to decrease, but to a 
lesser extent. The battery costs assumed for the balanced scenario are also lower than 
those  of the basic decarbonisation, reflecting recent information on learning potential 
and the better focus of battery markets as assumed in the balanced scenario.  

More  precisely,  the  following  uses  of  hydrogen  have  been  found  to  be  efficient  for 
emission  abatement  and  economically  viable,  in  case  hydrogen  technologies  achieve 
both economic and engineering maturity: 

1.  Mix hydrogen up to 15% in the gas distribution grids, together with amounts of 
bio-methane and clean methane (produced from hydrogen and CO2 captured in 
the air); the share of the latter reaching between 15-20% in the long-term. 

2.  Use electrolysis-derived hydrogen to feed fuel-cell powertrains in large vehicles 
(trucks, buses, etc.) and long distance travelling cars (including taxis). Hydrogen 
refuelling  can  benefit  from  returns  to  scale  as  only  a  few  numbers  of  large 
centralised fuelling hubs are required to feed the large vehicles. 

3.  Use hydrogen directly in high temperature furnaces in industry, including in iron- 

and steel-making, the chemical industry and other industrial sub-sectors. 

4.  Develop  power-to-H2  technologies  in  the  power  sector  to  provide  electricity 
storage services at a large-scale, as needed to maximise the use of renewables, 
and produce hydrogen and clean methane used by consumers. 

As already mentioned, the balanced scenario, despite the fact that it targets hydrogen 
to  be  used  only  in  energy  and  industrial  applications  where  it  is  more  economically 
viable, assumes that technologies both on the demand (fuel cells, industrial processes 
involving  hydrogen)  and  supply  side  (electrolysers)  become  fully  mature,  with  their 
efficiencies improving significantly compared to current levels and their cost reducing 
significantly. As the latter can be arguable, a sensitivity analysis has been conducted: 
the sensitivity scenario assumes a less optimistic development of hydrogen technology 
costs. The scenario includes the same developments of hydrogen uses as the balanced 
scenario but at a slightly lower extent due to the higher costs of hydrogen technologies.  

Key scenario results and discussion 

This  section  presents  the  key  findings  of  the  basic  decarbonisation  scenario  and  the 
balanced  scenario,  and  a  comparison  between  them.  The  sensitivity  scenario  is  also 
compared  where  appropriate  with  the  main  scenarios.  In  order  to  provide  more 
insightful results, all scenarios are also compared to the EU Reference Scenario 2016, 
the energy projections of which have also been prepared using the PRIMES model24. In 
brief,  the  latter  scenario  assumes  the  implementation  of  policies  adopted  at  EU  level 
and in the Member States until December 2014 and in addition the ILUC amendment to 
the RES and FQD Directives, as well as the Market Stability Reserve Decision amending 
the ETS Directive. The EU Reference Scenario 2016 (in short Reference scenario) serves 
as a benchmark for policy scenarios. 

24 https://ec.europa.eu/energy/sites/ener/files/documents/20160713%20draft_publication_REF2016_v13.pdf 

January 2018  I  83 

 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

GHG emissions 

The basic decarbonisation scenario achieves 84% CO2 emission reduction in the energy 
and process sectors (including emissions from industrial processes) in 2050 compared 
to 1990 levels, a reduction compatible with the long-term objective of the EU to reduced 
total GHG by at least 80% (in 2050 compared to 1990). This reduction in the EU energy 
system is also consistent with the ambition to limit the global temperature increase to 
2oC  compared  to  pre-industrial  levels.  The  world  leaders  participating  in  the  COP21 
meeting in Paris in December 2015 have also agreed to make best efforts to limit the 
global  temperature  increase  to  1.5oC.  In  order  to  do  so,  further  emissions  reduction 
form  the  EU  energy  system  will  be  required.  The  emissions  savings  achieved  in  the 
balanced  scenario  are  in  line  with  such  a  stricter  trajectory,  the  balanced  scenario 
achieves  a  96%  reduction  of  CO2  emissions  compared  to  the  1990,  therefore  almost 
eliminating  energy  and  process  related  carbon  emissions.  It  is  noted  that  both 
trajectories  achieve  similar  emissions  savings  in  the  mid-term  (2030),  equally 
respecting the EC targets included in the proposals of the Winter Package.  

In absolute terms, around 700 Mt of energy and process related CO2 emissions remain 
unabated  by  2050  in  the  basic  decarbonisation  scenario.  The  remaining  emissions  in 
2050 reduce to less than 200 Mt CO2 in the balanced scenario. In the latter, the transport 
sector  becomes  essentially  carbon-free  by  2050  (compared  to  375  Mt  emitted  in  the 
basic decarbonisation scenario), as it fully utilises carbon-free energy carriers via:  

▪  the maximization of the use of electricity in light transport segments;  

▪  the use of hydrogen for long-distance travelling cars, hydrogen in long-distance 

travelling trucks, buses and coaches; and  

▪  the use of advanced biofuels in aviation and shipping, which can use more biofuels 

than in the basic decarbonisation scenario as the biofuel consumption in road 
transport has been substituted with hydrogen.  

Hydrogen is mainly used for longer distance trips, which otherwise were fulfilled with 
more expensive electric vehicles due to the high battery capacity needed, or continued 
using ICEs. This combines with fuelling hubs which can achieve attractive economies of 
scale, and avoids developing small scale H2 refuelling that is expensive. 

Industrial  emissions,  both  from  combustion  and  processes  are  reduced  further  in  the 
balanced  scenario to less than 30 Mt in 2050, in contrast with roughly 130  Mt in the 
basic decarbonisation scenario. Additional abatement in industrial emissions are due to 
the direct use of hydrogen in high temperature furnaces as reducing agent of iron or in 
other chemical reactions, and as a fuel in other industrial uses. Carbon emissions from 
the domestic sector are further reduced in the balanced scenario, but to a lower extent, 
since small scale fuel-cell stacks are not treated as a favourable option for heating in 
residential,  public  and  commercial  buildings.  The  additional  savings  in  the  balanced 
scenario are due to the higher shares of clean fuels blended in the gas distribution grid 
(mainly hydrogen and synthetic methane) leading to a lower average emission factor 
for distributed gas that is used in domestic boilers. 

Energy  supply  is  the  only  sector  found  to  be  slightly  increasing  its  emissions  in  the 
balanced scenario compared to the basic decarbonisation scenario as power generation 
from  RES  increases  significantly  (see  later  section  on  power  generation)  and  the 
balancing needs augment. Despite the very competitive position of variable RES towards 
the  end  of  the  projection  period  (several  technologies  become  competitive  without 
financial support already in the mid-term), gas-based generation25 is still needed as a 

25 This is an issue for further investigation. Producing hydrogen for balancing and storage requires renewables which 
further require balancing and storage services. The system model finds a balance between the balancing and storage 
options in which there is a noticeable place of gas, which is produced from CCS CCGTs instead of producing hydrogen 
or clean methane and use them in CCGTs. The investigation will have to make sensitivity analysis about the relative 

January 2018  I  84 

 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

means  of  providing  flexibility  and  balancing  services  to  the  power  system.  The  vast 
majority of fossil-fuelled capacity is equipped with CCS technologies in 2050, however, 
the latter technologies still leave a certain share of post-combustion emissions (roughly 
10%)  unabated.  The  combination  of  those  two  elements  (higher  RES  generation 
entailing higher needs for flexibility and balancing and a share of emission of CCS not 
being possible to be fully abated26) leads to CO2 emissions from the energy supply side 
increasing  by  roughly  7  Mt  in  the  balanced  scenario  compared  to  the  basic 
decarbonisation scenario. 

Figure  22.  Evolution  of  CO2  emissions  from  the  energy  sector  and  industrial 
processes in EU28 

Figure 23. Remaining CO2 emissions in EU28 in 2050. 

Given the above, it is apparent that the relative shares of emissions from each sector 
vary significantly between the two decarbonisation scenarios in 2050. For example, the 
transport  sectors  emits  more  than  50%  of  the  remaining  energy  and  process  related 
CO2 emissions in the basic decarbonisation scenario, whereas this share in the balanced 
scenario drops to 5% (see Figure 24). The share of industrial emissions remains roughly 
the same, although the absolute  CO2  emissions decrease significantly. An increase in 
the  share  of  supply  side  emissions  from  12%  to  almost  half  of  the  CO2  emissions  in 

economics  of  these  options  in a  system with above  70%  RES.  There  is  poor  literature  on  this  issue,  in  particular 
regarding system modelling. This is logical as the topic is new in the literature.  
26 A further option would be to use biomass CCS to compensate for the non-abated (10%) emissions of gas-CCGT 
with CCS. The version of the model used in this study has restrictive assumptions about the development of biomass 
CCS before 2050.  

January 2018  I  85 

272220305001000150020002500300020302050CO2 emissions in MtBalanced ScenarioEnergy SupplyTransport SectorDomestic SectorIndustry and ProcessesTotal CO23734272070205001000150020002500300035004000201520302050CO2 emissions in MtBasic Decarbonisation Scenario 
 
 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

2050 (45%) is noted, in emissions however only increase by 8% compare to the basic 
decarbonisation (7Mt CO2).  

Figure 24 shows the shares of the sectors in the emissions remaining in 2050 in the two 
decarbonisation  scenarios.  This  figure  should  be  seen  in  combination  with  Figure  22 
which shows that the amount of remaining emissions in the balanced scenario are far 
lower those of the basic decarbonisation scenario.  

Figure 24. Relative shares of remaining emissions in EU28 in 2050 

The role of hydrogen in the energy mix 

It  has  been  explained  previously  that  the  balanced  scenario  assumes  the  successful 
introduction  and  widespread  adoption  of  hydrogen  as  a  second  level  of  sectoral 
integration in the European energy sector (the first level being the utilisation of carbon-
free  electricity),  but  only  in  sectors  and  end-uses  where  is  has  to  exhibit  strong  and 
robust benefits compared to its carbon-free competitors (electricity, synthetic gas and 
liquids).  Another  important  role  of  hydrogen  is  that  it  serves  as  one  of  the  main 
feedstock elements–the other being carbon obtained from CO2 – for the production of 
synthetic  gas  in  these  scenarios.  The  latter  can  be  considered  a  carbon-free  energy 
source  in  case  the  CO2  used  for  its  production  has  been  obtained  from  non-fossil 
resources.  

Further sectoral integration and deep decarbonisation achieved via an enhanced role of 
hydrogen in the energy sector, leads to important additional energy requirements for 
the supply of the latter. This is exhibited by contrasting the two main scenarios as shown 
in Figure 25. In both scenarios, the penetration of hydrogen in the energy sector initiates 
post-2030, with a much faster pace in the balanced scenario. Consequently, by the end 
of  the  projection  period,  around  55  Mt  of  hydrogen  are  consumed  in  the  basic 
decarbonisation scenario, whereas this figure climbs to roughly 150 Mt in the balanced 
one. The remarkable increase originates from the use of hydrogen as an energy carrier 
for combustion in energy demand and supply sectors (or for direct injection in industrial 
processes), and to a small extent to its role as a feedstock for the production of synthetic 
methane; the share of the latter in overall distributed gas mix remains relatively close 
between the two scenarios.  

January 2018  I  86 

 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

Figure 25. Hydrogen consumption for energy purposes in the EU28 
Note: The figure includes quantities used for energy uses. Non-energy uses for hydrogen 
as feedstock are excluded. 

Figure 26. Consumption of hydrogen as a direct fuel per energy sector in EU28 

The consumption of hydrogen used as an energy carrier for the two main scenarios is 
shown  in  Figure  26.  The  growth  in  the  demand  of  hydrogen  in  the  balanced  case  is 
mainly due to the transport and the industrial sectors and to a far lesser degree from 
energy supply (power generation). 

In transportation, hydrogen is considered an attractive solution for the decarbonisation 
of long-distance  road passenger and freight transportation (trucks and coaches), and 
several  urban  transport  segments,  where  refuelling  times  need  to  be  short  and  bulk 
refuelling in centralised stations within urban areas is possible, as in the case of buses 
and taxis. The rolling out of the infrastructure is assumed to be rapid, as it is assumed 
that  there  will  be  refuelling  stations  mainly  with  local  electrolysers,  limiting  the 
requirements for an extended infrastructure rollout with pipelines. Further the type of 
vehicles  using  hydrogen  allow  to  limit  the  refuelling  infrastructure  to  centralised 
refuelling and refuelling along key transportation routes (TEN-T network), limiting the 
hydrogen infrastructure requirements. For the transition period, decentralised hydrogen 
production  is  a  valid  option  for  private  investment.  The  latter  is  considered  an 
economically viable options as the modular nature of electrolyser units make them cost-
effective also in small scale applications. This could also prove a significant benefit, till 
efficient  logistics  for  the  transportation  of  hydrogen  in  compressed/liquid  forms  are 
developed.  The  massive  adoption  of  hydrogen  in  these  transport  modes  brings  its 

January 2018  I  87 

020406080100120140160BasicDecarbonisationBalancedBasicDecarbonisationBalancedBasicDecarbonisationBalanced203020402050MtoeAs feedstockAs direct fuel020406080100120140203020402050MtoeBasic Decarbonisation Scenario02040608010012014020402050MtoeBalanced ScenarioTransport sectorDomestic sectorIndustryEnergy supply 
 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

consumption up to more than 55 Mtoe in 2050 in the balanced scenario, seven and a 
half times higher than in the case of the basic decarbonisation scenario. 

Regarding its role in decarbonising the industrial sector, hydrogen can serve both as a 
fuel  to  power  a  combustion-based  heater,  which  applies  to  plenty  of  industrial 
subsectors, or as an enabler of chemical reactions in certain industrial processes. Such 
is the case in the iron and steel sector, where hydrogen is used as an enabler of the 
chemical reaction reducing iron ore to iron. In the latter case, the use of high emitting 
fuels like blast-furnace gases used in traditional iron-making can be reduced. Certain, 
similar opportunities for carbon-free hydrogen produced through the use of electrolysers 
are offered also in other industrial subsectors. All the above, complement the current 
role  of  hydrogen  in  non-energy  related  industrial  applications  where  it  has  an 
established market. By 2050, hydrogen can contribute to almost 46 Mtoe of the energy 
needs  of  the  industrial  sector  in  the  balanced  scenario,  compared  to  a  limited 
contribution of roughly 10 Mtoe in the basic decarbonisation scenario. 

Hydrogen also has an important role to serve for the power generation sector. Besides 
its  use  as  a  blend-in  fuel  in  distributed  gas,  in  gas-fuelled  power  plant,  and  even  in 
modified turbines operating on high blends of hydrogen, it provides additional direct and 
indirect  storage  services  to  an  integrated  and  interconnected  power  system  allowing 
access to remotely located renewables and an effective sharing of balancing resources. 
The direct storage refers to the production of hydrogen via electrolysis in order to be 
converted back to  electricity at a later time period; the indirect  storage  refers to the 
possibility to produce hydrogen for the demand sectors. The production of hydrogen can 
be  optimised among power plant  owners and hydrogen producers so that it can take 
place during off-peak hours of low electricity demand (and excess RES production). In 
this respect, the hydrogen-based storage of electricity has a considerable contribution 
to smooth electricity load-curves, being produced in times of excess generation and re-
electrified in times renewables are in deficit.  The maximisation of renewable capacity 
factors, enabled by hydrogen, helps lowering electricity costs.  

Power Generation 

The power generation requirements of the system increase significantly already in the 
basic  decarbonisation  scenario,  as  electricity  is  the  main  sectoral  integration  means 
leading to the reduction of emissions by demand sectors via fuel switching in the end-
uses. Power generation has to increase much further to produce hydrogen (Figure 27). 
The  increment  is  33%  in  2050  and  can  be  higher  if  the  balanced  scenario  developed 
further the clean gas or clean liquid productions. Despite the limited use of clean gas in 
the balanced scenario shown in the figure, the production of hydrogen is sufficient to 
drive the impressive rise of electricity production in 2050.  

By the end of the projection period the gross generation of electricity increases by one 
quarter  in  the  basic  decarbonisation  scenario  compared  to  the  Reference  scenario, 
where decarbonisation is not pursued. When aiming at deep decarbonisation as is the 
case in the balanced scenario the increase of electricity generation is 70% relative to 
the Reference scenario. The high increase stems from the need to provide the electricity 
for the production of hydrogen via electrolysers, as depicted by the share of the energy 
supply sector in total electricity consumption that increases substantially from 25% to 
almost  40%  by  the  end  of  the  projection  period  between  the  balanced  and  the  basic 
decarbonisation scenario (Figure 28). Consequently, hydrogen serves as an additional 
level  of  sectoral  integration,  decarbonising  non-economically  electrifiable  end-uses, 
given its zero-emission footprint when generated via electrolysis. 

January 2018  I  88 

 
 
 
Sectoral integration: long-term perspective in the EU energy system 

Figure 27. Power generation in EU28 

Figure 28. Electricity consumption by sector in EU28 in 2050 

Power  generation  is  almost  carbon  free  by  2050  in  all  scenarios  considered.  The 
structure of power generation in both main scenarios is shown in Figure 29. By the end 
of the projection period, electricity production from RES dominates the power  sector. 
Although, the RES share in generation does not change significantly between the two 
scenarios –they are slightly more than 70% in both cases - an increment of almost 1300 
TWh  in  the  balanced  scenario  is  required  compared  to  the  basic  decarbonisation 
scenario. All other major sources of electricity generation increase their contribution in 
terms of absolute electricity generation in the balanced scenario, but to a lesser extent. 
Nuclear power plants expand their production by 182 TWh (implying the expansion of 
the nuclear fleet by around 23 GW by 2050), a small rise compared to the rise of the 
RES  (1912  GW  in  2050  increment  in  the  balanced  scenario  compared  to  the  basic 
decarbonisation  scenario),  as  the  largest  potential  of  the  sites27  available  for  the 
construction  of  new  nuclear  reactors  have  already  been  exploited  in  the  basic 
decarbonisation scenario leaving small room for additional reactors.  

Generation  from  solids  and  gas  also  increases  but  exclusively  through  CCS  and  for 
balancing purposes. Solids are used for power and heat generation exclusively in power 
plants equipped with CCS, slightly increasing their contribution in the power generation 
mix by mid-century from 59 TWh in the basic decarbonisation scenario, to 82 TWh in 
the balanced scenario. At the same time, gas-fired generation is increases by 164 TWh 

27 The PRIMES model limits the use of nuclear based on the availability of sites (locations) available in the countries 
allowing nuclear.  

January 2018  I  89 

66324979392330003500400045005000550060006500700020152020202520302035204020452050TWh netPower GenerationBalanced ScenarioBasic Decarbonisation ScenarioReferenceIndustry, 1370, 20%Domestic, 2258, 33%Transport, 605, 9%Supply, 2649, 38%Balanced Scenario in 2050 6 882 GWhIndustry, 1342, 27%Domestic, 2019, 40%Transport, 530, 10%Supply, 1184, 23%Basic Decarbonisation Scenario in 20505 150 GWh 
 
 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

as  a  consequence  of  a  number  of  underlying  factors.  Firstly,  gaseous-fuelled  power 
plants utilise mixtures  of gases containing high shares  of carbon-free energy  carriers 
(synthetic methane, hydrogen and biomethane) leading to very low average emission 
factors for the overall mixtures. Secondly, any carbon-rich mixes of gases (containing 
low shares of clean fuels) are exclusively combusted in CCS equipped power plants, with 
low emission footprint. The use of CCS equipped power plants leads to a small part of 
unabated emissions which by that point in time are sufficient to lead to a net increase 
in emission form the energy supply side, as explained earlier (this is also true for CCS 
equipped power fuelled by solids). Lastly, due to the high-ramping rates, the low starting 
and shutdown costs and their low operating costs, gas plants serve as a cheap source 
for the provision of flexibility and balancing services to the power system; this becomes 
more and more important with increasing contribution of (variable) RES in the power 
mix.  

Figure 29. Structure of power generation in EU28 

Transport 

The balanced scenario assumes an increased role for hydrogen in those transport modes 
where limited alternatives to combustion engines are available or where strong business 
cases can  emerge. In particular, hydrogen can achieve a large market share in long-
distance  road  transportation  modes  (trucks  and  coaches)  that  are  more  difficult  to 
electrify than light-duty vehicle transportation, where the strong emergence of EVs is 
anticipated.  Another  market  opportunity  for  hydrogen  is  also  presented  in  urban 
transportation e.g. for buses and taxis for which refuelling can take place in centralised 
stations (a few number per municipality) where it is possible to achieve economies of 
scale  and  short  refuelling  times  that  are  highly  beneficial.  The  roles  of  hydrogen  and 
electricity should be seen hence as complementary, with each one aiming at the markets 
that  better  suit  their  technical  characteristics.  Figure  30  shows  that  the  balanced 
scenario projects that the emissions in the transport sector can be almost fully abated 
(excluding bunkers), if the synergies of the sectoral integration are fully exploited. 

January 2018  I  90 

01000200030004000500060007000201520302050TWh netBasic Decarbonisation Scenario0100020003000400050006000700020302050TWh netBalanced ScenarioFrom RESFromNuclearFrom GasFrom OilFrom Solids 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

Figure 30. CO2 emissions from the transport sector in EU28 

In  the  basic  decarbonisation  scenario  strong  emissions  abatements  in  long-distance 
road transportation can be realised only by the use of advanced biofuels. In the balanced 
scenario the use of hydrogen fuel cells avoids the use of advanced biofuels which can 
therefore  be  used  in  other  transport  segments.  This  is  important  because  there  are 
limitations  to  the  amount  of  advanced  biofuels  that  can  be  produced  in  the  EU 
domestically due to e.g. limited land resources and suitability of land. The amounts of 
advanced biofuels that can be produced domestically in the EU are not enough to fully 
decarbonise  all  the  remaining  non-electrifiable  transport  modes  –heavy  duty  road 
transportation,  aviation  and  shipping-,  in  the  basic  decarbonisation  scenario. 
Consequently, the use of hydrogen in long distance road transport reduces significantly 
the  amounts  of  biofuels  used  in  road  transportation  and  therefore  provides  an 
opportunity  for  the  full  decarbonisation  of  aviation  and  shipping  via  the  use  of  bio-
resources (bio kerosene and other bio-liquids), without the need to depend on additional 
imported fuels or feedstock resources. 

Figure 31. Energy consumption in the transport sector by fuel in EU28 

January 2018  I  91 

02004006008001000120020152020202520302035204020452050Mtons CO2Basic Decarbonisation Scenario02004006008001000120020152020202520302035204020452050Mtons CO2Balanced scenarioInlandnavigationAviationRailHeavy andlight trucksCars, vans,P2WPublic roadtransport05010015020025030035040020302050MtoeBalanced scenarioHydrogenBiofuelsOther fossilKeroseneDieselGasolineElectricity050100150200250300350400201520302050MtoeBasic Decarbonisation Scenario 
 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

Figure 32. Fuel mix in transport in 2050 

The  balanced  scenario  for  the  transport  sector  shows  an  effective  allocation  of  the 
contribution  of  three  alternative  energy  sources  that  effectively  contribute  to  the 
decarbonisation of transport in 2050. Electricity and hydrogen represent 28% and 31% 
of the total energy consumption in the transport in the balanced scenario (Figure 31 and 
Figure 32); biofuels represent an additional 39% of the total final energy demand. 

 Almost negligible quantities of fossil fuels remain in the fuel mix of the transport sector 
by  mid-century.  The  picture  is  different  in  the  basic  decarbonisation  scenario  where 
large  quantities  of  fossil  fuels  remain  by  2050  (approx.  half  of  the  total  final  energy 
demand) which are  responsible for the unabated CO2 emissions in transport. Biofuels 
and electricity (to a lesser extent) hold the remaining shares in the fuel mix in the basic 
decarbonisation scenario in 2050. Hydrogen uptake is negligible in this scenario and its 
fuel share does not exceed 2%. However, the absolute consumption of biofuels in the 
two scenarios is very similar, despite the full substitution of jet fuels by biofuels in the 
balanced scenario. This is due to the savings of biofuels enabled by the use of hydrogen 
in road transport.   

Figure 33. Shares of powertrains in the stock of cars in EU28 

Electro-mobility dominates the car market of the EU28 in the balanced scenario, which 
enhances the developments in the basic decarbonisation scenario. This is due to slightly 
more optimistic assumptions regarding battery costs in the balanced scenario. The more 
optimistic figures are due to recent updates on technology potential costs compared to 
the figures used in the basic decarbonisation scenario back in end 2016. The battery-
based powertrains concentrate in the  market segments of cars travelling in cities and 
up  to  medium  distances.  The  market  focus  can  help  batteries  and  the  power  trains 
achieving further economies of scale.  

January 2018  I  92 

28%2%39%31%16%48%34%2%Fuel mix in transport in 2050 (Mtoe)(outer cycle: basic decarbonisation scenario, inner cycle: balanced scenario)ElectricityFossilBiofuelsHydrogen0102030405060708090100201520302050Basic Decarbonisation Scenario010203040506070809010020302050Balanced scenarioOtherFCEVBEVPlug-in hybridConventional (incl. hyb.) 
 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

Battery electric vehicles hold the 90% of the total cars in the EU28, with the rest of the 
cars being fuel cell powered (Figure 33). The majority of the transport users are using 
battery  electric  vehicles  for  commuting  and  short-distant  trips.  Fuel  cells  occupy  the 
market of transport users performing frequent long-distance driving or as vehicles with 
high  daily  utilisation  (e.g.  taxis).  Similar  developments  are  projected  for  buses  and 
coaches  and  in  general  for  heavy  duty  utility  vehicles.  In  this  way,  the  two  vehicle 
powertrains represent two complementary options for the future private transportation. 
The  stronger  reduction  in  the  battery  costs  of  the  BEVs  from  2030  onwards  in  the 
balanced scenario relative to the basic decarbonisation scenario, is considered a major 
driver for their market. Hydrogen fuel cell cars also reach commercial level of maturity 
with a total cost of ownership similar to that of a conventional car, approaching 2050 
(see Figure 35).  

The balanced scenario shows that hydrogen can substantially contribute to the reduction 
in  the  CO2  emissions  from  road-freight  transport  by  2050.  The  uptake  of  hydrogen 
increases  significantly  from  2035  onwards  and  dominates  the  segment  of  the  heavy 
duty trucks (i.e. commercial vehicles above 3.5 tons) by 2050. First, hydrogen displaces 
consumption of diesel in the segment of long-haul trucks with high annual mileages on 
the  European  motorways.  As  approaching  2050,  other  truck  types  such  as  regional 
trucks or lighter ones operating in urban areas are also all switching to hydrogen (Figure 
34). The uptake of hydrogen in the balanced scenario saves around 30 Mtoe of biofuels 
in 2050 that otherwise would be utilised by trucks, as shown in the basic decarbonisation 
scenario. These biofuel quantities that are being freed in the balanced scenario are used 
in other relatively inflexible to decarbonise transport sectors, such as aviation and ships.  

Figure 34. Fuel mix in trucks in EU28 

The levelized  costs  of an average vehicle trip (as presented in  Figure  35) include the 
annuity payment  for the purchasing  of the vehicle and the annual running costs (i.e. 
consumption of electricity, hydrogen or diesel).  

January 2018  I  93 

01020304050607080201520302050MtoeBasic Decarbonisation Scenario0102030405060708020302050MtoeBalanced scenarioHydrogenBiofuelsNatural GasOil productsElectricity 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

Figure  35.  Levelized  and  running  costs  for  an  average  medium-size  car 
operating with conventional and advanced powertrains 

Final consumption and gross inland consumption 

The  developments  discussed  in  various  subsectors,  especially  in  industry  and 
transportation,  lead  to  a  completely  different  energy  mix  in  end-use  sectors  in  the 
balanced  scenario  compared  to  the  basic  decarbonisation  scenario  by  the  end  of  the 
projection period (Figure 36). The demand sectors in the basic decarbonisation scenario 
are projected to consume 220 Mtoe of fossil based liquids in 2050; more than half (120 
Mtoe) are still being using for energy applications (the remaining are used as feedstock 
for the production of chemicals, they are not combusted and hardly cause emissions). 
The respective figure for liquids used in energy applications in the balanced scenario is 
only 5 Mtoe, therefore oil products are almost eliminated from energy processes. Natural 
gas is the only carbon-emitting fuel that continues being used in significant quantities 
in 2050 (155 Mtoe and 130 Mtoe in the basic decarbonisation and the balanced scenario 
respectively), however, a considerable portion of it is carbon-neutral synthetic methane 
(17 and 23 Mtoe respectively). The remaining fossil methane is mainly used in industrial 
plants that are equipped with CCS/CCU technologies, therefore emitting small amounts 
of CO2 and in the domestic sector, where some emissions remain unabated.  

Direct use of renewables (mainly biomass) and waste in final energy shrinks by 35 Mtoe 
between  the  two  scenarios  as  the  increase  of  hydrogen  displaces  large  volumes  of 
advanced biofuels from the transport sector; fuel-cell powered engines are also more 
efficient  than  the  respective  conventional  powertrains  by  a  factor  of  two  on  average, 
contributing to this outcome, in final energy terms. 

Figure 36. Total final consumption by fuel in EU28 

January 2018  I  94 

3333333333333340363131313030594945423935342020202520302035204020452050Levelised cost (EUR/100km)Conventional vehicleElectric vehicleHydrogen fuel cell vehicle9.710.010.210.19.89.910.04.24.24.33.43.43.43.35.93.93.63.33.13.02.92020202520302035204020452050Running cost (EUR/100km)Conventional vehicleElectric vehicleHydrogen fuel cell vehicle020040060080010001200140020302050MtoeBalanced ScenarioElectricitySteamHydrogenRenewablesand wasteGasLiquidsSolids0200400600800100012001400201520302050MtoeBasic Decarbonisation Scenario 
 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

Hydrogen and electricity are two energy carriers presenting the largest increase in their 
absolute contribution to the final energy mix in the balanced scenario compared to the 
basic one, increasing by 80 Mtoe and 30 Mtoe respectively. Hydrogen is widely adopted 
in certain industrial applications and transport segments, while electricity dominates the 
domestic demand and light road transportation. Hydrogen expands its role in this latter 
transport  segment,  however  the  increase  is  less  prominent.  Overall,  total  final 
consumption of all fuels decreases by 65 Mtoe between the two scenarios in 2050 (being 
lower in the balanced scenario), a result of the efficiency gains due the switch towards 
more efficient powertrains utilising clean fuels in transport. 

Figure 37. Gross Inland Consumption by fuel in EU28 

Despite  the  decrease  in  total  Final  Energy  Consumption  due  to  efficiency  gains  in 
transportation, Gross Inland Consumption28 of all primary energy sources used in EU28 
increases  slightly  in  2050  in  the  balanced  scenario  compared  to  the  basic 
decarbonisation  scenario  (Figure  37).  This  is  an  outcome  of  the  high  increase  in 
electricity  demand,  including  for  hydrogen  production,  and  consequently  in  the 
consumption of primary fuels need for its generation. As it has been mentioned in the 
power generation sector analysis, the majority of the incremental demand is covered by 
increased generation from RES and nuclear and to a lesser extent from gas and solids. 
The same is also evident in Gross Inland Consumption of those sources. As oil is used 
solely of non-energy purposes in the balances, its overall demand shrinks by more than 
50%. 

Gas,  and  more  generally  gaseous  fuels,  undergo  a  significant  transition  towards 
becoming low-carbon foot-print. At present, the vast majority of gaseous fuels are fossil 
methane (>93%), with the remaining gaseous fuels being coal-derived gases (5%) used 
in power generation and industry, and biogas (less than 2%). Only biogas is considered 
a carbon neutral energy carrier, therefore the gaseous fuel mix is quite carbon-intensive. 
By 2050, carbon-free energy carriers are blended in the distributed gas, or used directly 
in industry and power generation, leading to the gaseous fuel mix becoming significantly 
less  carbon  intensive  (Figure  38).  In  the  basic  decarbonisation  scenario,  carbon-free 
gaseous  energy  carriers  reach  a  share  of  roughly  30%  in  the  overall  gaseous  fuel 
demand, and this share climbs to 45% in the case of the balanced scenario, mainly due 
the contribution of hydrogen. This trend has significant implications also for the supply 
of gaseous fuels. The European Union currently imports more than 65% of its gas. The 
introduction  of  gaseous  fuels  produced  via  chemical  pathways  (hydrogen,  synthetic 
methane) brings the share of imports in the gaseous fuel mix down to 55% in the basic 

28 Gross Inland Consumptions is the sum of the fuel demand in end-uses sector and the energy supply sectors. 

January 2018  I  95 

0200400600800100012001400160020302050MtoeBalanced ScenarioRenewablesNuclearNatural gasOilSolids020040060080010001200140016001800201520302050MtoeBasic Decarbonisation Scenario 
 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

decarbonisation scenario and almost down to 42% in the balanced scenario by 2050. 
The latter is  even more remarkable, should one consider that the overall demand for 
gaseous fuels remains stable between 2015 and 2050 in the balanced scenario, while it 
was  shrinking  by  20%  in  the  main  decarbonisation  scenario.  In  this  scenario,  the 
amounts of gaseous fuels produced domestically in the EU in 2050, become comparable 
to  the  amounts  of  natural  gas  imported  from  outside  EU  (140  Mtoe  and  170  Mtoe 
respectively). 

Figure 38. Gaseous fuel demand in EU28 in 2015 and 2050 

Figure 39. Gaseous fuel supply in EU28 in2015 and 2050 

Implications for imports and energy security 

The substitution of fossil fuels has tremendous consequences on the EU trade balance, 
which however differs by scenario. The need for imports from outside the EU decreases 
over  time  in  both  the  main  decarbonisation  scenario  and  the  balanced  one.  But,  the 
elimination of oil from the transport sector and almost all energy applications, except in 
non-energy uses, by 2050 in the balanced scenario leads to a dramatic fall of imports 
of liquids, standing at less than 170 Mtoe in 2050; they are used almost exclusively for 
non-energy uses in the chemical industry. For comparison, oil imports stood at roughly 
550 Mtoe in 2015 and are projected to be 280 Mtoe by 2050 in the basic decarbonisation 
scenario (Figure 40). The oil import bill reduces by 93 billion € by 2050 in the balanced 
scenario compared to the basic decarbonisation scenario. 

January 2018  I  96 

Natural Gas, 226, 71%Clean Gas, 20, 6%Hydrogen, 28, 9%BioCH4, 43, 14%2050Basic DecarbonisationScenario321 MtoeNatural Gas, 219, 54%Clean Gas, 28, 7%Hydrogen, 114, 28%BioCH4, 42, 11%2050Balanced Scenario404 MtoeNatural Gas, 388, 93%BioCH4, 8, 2%Derived gas from coal, 19, 5%2015 415 MtoeProduction, 20, 5%Primary Energy, 126, 30%Net Imports, 269, 65%2015 415 MtoeProduction, 142, 35%Primary Energy, 93, 23%Net Imports, 168, 42%2050Balanced Scenario404 MtoeProduction, 48, 15%Primary Energy, 91, 29%Net Imports, 178, 56%2050Basic Decarbonisation Scenario321 Mtoe 
 
 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

Imports  of  natural  gas  remain  at  the  same  level  in  2050  across  the  two  scenarios, 
despite  the  higher  demand  for  gaseous  fuels  in  the  balanced  scenario,  as  the 
incremental demand is covered by hydrogen and synthetic methane that are produced 
domestically within the EU. The imports of biomass are lower in the balanced scenario 
compared  to  the  basic  decarbonisation  scenario,  but  in  both  cases  the  amounts  of 
biomass  are  small  compared  to  the  domestic  production.  Both  scenarios  produce 
reasonable amounts of biomass domestically, and respect sustainability criteria and land 
use restrictions.  

The overall reduction of net imports significantly improves the energy security position 
of the EU (Table 10) in the balanced scenario. 

Figure 40. Net imports of fuels in the EU28 

Import Dependency  

2015 

2020 

2030 

2040 

2050 

Balanced Scenario 

56% 

55% 

54% 

39% 

27% 

Basic Decarbonisation Scenario 

56% 

55% 

54% 

46% 

37% 

Table 10. EU dependency on imports 

Economic considerations  

The basic decarbonisation and the balanced scenario have been compared in terms of 
their  relative  cost  performance.  Despite  the  fact  that  the  balanced  scenario  achieves 
higher  emissions  reductions,  involves  a  significant  increase  in  power  generation  and 
includes a higher share of more expensive fuels in the gas mix compared to the basic 
decarbonisation scenario, it is found to be less expensive than the latter regarding total 
energy system costs. In essence, the balanced scenario benefits from the availability of 
the hydrogen technology options and the reduced cost of fuel cells which by assumption 
were not available in the context of the basic decarbonisation scenario.  In this sense, 
the two scenarios are not fully comparable regarding total cost performance. The merit 
of the sectoral integration enabled by hydrogen is that it enables stronger abatement 
and  lower  costs,  just  because  this  option  has  not  been  considered  in  the  basic 
decarbonisation scenario.  

Another economic benefit, of a lesser extent, comes from a more optimised allocation 
of  emissions  reduction  effort  across  the  sectors  and  the  focused  use  of  technologies. 

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020040060080010001200BasicDecarbonisationBalancedBasicDecarbonisationBalanced201520302050MtoeSolidsOilGasBiomass-WasteTotal 
 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

This has been possible in the balanced scenario again thanks to the availability of the 
sectoral integration through hydrogen.  

Both scenarios perform similarly in terms of both the average (and total) costs of the 
energy system and the average unit cost of emissions reduction up to 2030. In the long-
term, the balanced scenario performs better in both regards. The average annual energy 
system  costs  in  the  period  2031-2050  is  €2  444  billion  in  the  basic  decarbonisation 
scenario, whereas this drops to €2 360 billion in the balanced scenario. In other words, 
in the balanced scenario, the EU needs to spend on average €85 billion less than in the 
main  decarbonisation  scenario,  every  year  for  20  years.  The  average  CO2  abatement 
cost  is  €88/t  CO2  (in  the  period  2031-2050),  compared  to  €182/t  CO2  in  the  basic 
decarbonisation  scenario.  The  lower  cost  is  achieved  thanks  to  the  introduction  of 
hydrogen  as  an  intermediate  fuel  and  its  particular  role  in  transport;  the  scenario 
benefits from the assumed techno-economic developments of the fuel cell technology, 
from €300/kW today to €44/kW in 2050 and the reduced costs of batteries.  

The  investment  expenditures  needed  in  power  generation  in  order  to  produce  the 
amounts  of  electricity  required  for  the  production  of  the  incremental  demand  of 
synthetic  fuels  in  the  balanced  scenario  (compared  to  the  basic  decarbonisation 
scenario)  require  an  increase  in  the  cumulative  investment  expenditure  of  the  power 
sector  of  roughly  50%  in  the  period  2031-2050.  In  the  same  period,  cumulative 
expenditure of €1.8 trillion are required for the additional investments in power plants, 
while the additional investments for the expansion of transmission and distribution grids 
is almost higher by two and a half times (€4.6 trillion). Despite the remarkable increase 
in power investment expenditure in the 20-year period prior to mid-century, the average 
electricity prices in the EU do not increase (Figure 42). On the contrary, marginal price 
decreases are observed as the power system benefits from increasing sales volumes. 

Figure  41.Average  annual  energy  system  cost  (left)  average  unit  cost  of 
emission reduction (right) in EU28 for the two main scenarios 

January 2018  I  98 

19501950244423600500100015002000250030003500400045005000Basic DecarbonisationScenarioBalanced Scenariobillion EURAverage annual energy system cost13213318288050100150200250300350Basic DecarbonisationScenarioBalanced ScenarioEUR per tCO2 abated cumulativelyAverage unit cost of emissions reduction2031-20502021-2030 
 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

Figure 42. Average prices of electricity in EU28 

Figure 43. Investment expenditure in power generation 

As it has pointed out in several other parts of the study, in order for any business model 
to  be  successful  in  the  long  term,  the  entire  chain  of  users-producers-infrastructure 
should be available (almost) simultaneously. Such models are therefore vulnerable to 
market coordination failure: decentralised production in the initial expansion phase is 
less  vulnerable,  but  for  the  development  of  the  extent  of  hydrogen  availability  as 
envisaged in the strategies, successful market coordination is essential. Coordination is 
meant between infrastructure developers, technology and research providers, upstream 
hydrogen producers and end-use consumers. As the actors have different aspirations, 
long  term  anticipation  and  regulatory  certainty  are  of  utmost  importance  for  market 
coordination. Consequently, without the successful coordination of the aforementioned 
market  players,  the  optimality  and  cost-effectiveness  of  the  balanced  scenario  is  far 
from guaranteed. 

January 2018  I  99 

 
 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

Sensitivity analysis 

The  balanced  scenario  assumes  that  hydrogen  technologies  are  used  both  on  the 
demand side (fuel cells, industrial applications utilising hydrogen) and the supply side 
(electrolysers for the production of hydrogen), taking advantage of learning effects both 
due to R&D and accumulated experience (learning-by-research and learning-by-doing). 
The intensity and successfulness of the learning remains however uncertain. Therefore, 
the  effectiveness  of  the  strategic  pathway  presented  in  the  balanced  scenario  is 
validated using a sensitivity analysis assuming less optimistic developments in the costs 
of hydrogen technologies. The sensitivity scenario includes the same developments of 
hydrogen uses as in the balanced scenario albeit at a lower degree due to the higher 
costs of hydrogen technologies.  

Due  to  the  higher  costs  associated  with  its  supply  and  demand,  the  penetration  of 
hydrogen  in  the  sensitivity  scenario  is  lower  by  the  end  of  the  projection  period.  In 
industry hydrogen covers 15% of the energy needs of the sector in 2050 in the balanced 
scenario. The higher prices of hydrogen, resulting from the higher production costs, lead 
to this share dropping to 12% in the sensitivity scenario. More prominent is the drop in 
the share of hydrogen used in transportation. In the balanced scenario, the reduction in 
the  costs  of  fuel  cells,  make  it  possible  for  hydrogen  to  reach  a  30%  share  in  the 
transport energy mix, a share that drops close to 12% in case fuel-cell powered vehicles 
do not obtain full technological maturity (Figure 44). The total amount of hydrogen used 
in the EU either as a fuel or as feedstock for the production of synthetic methane in this 
scenario is 100 Mtoe, down from 150 Mtoe in the balanced one.  

Figure 44. Final consumption by fuel in industry (left-hand side) and transport 
(right hand side) in EU28 

These  developments  lead  to  significant  amounts  of  CO2  remaining  unabated  in  the 
sensitivity scenario, with the impact being higher in the transport sector where 150 Mt 
of CO2 more than in the case of the balanced scenario are emitted. The industrial sector 
emits 35 Mt CO2 more and the remaining sectors around 30 Mt CO2 due the higher costs 
of hydrogen that lead in turn to lower production of synthetic methane (Figure 45). The 
sensitivity  scenario  achieves  a  90%  decrease  in  energy  and  process  related  CO2 
emissions in 2050, compared to 1990 levels. 

January 2018  I  100 

050100150200250300350Basic decarbonisationscenarioBalancedscenarioSensitivityscenarioMtoeIndustry050100150200250300350Basic decarbonisationscenarioBalancedscenarioSensitivityscenarioMtoeTransportElectricitySteamHydrogenRenewablesand wasteGasLiquids 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

Figure  45.  CO2  emissions  from  the  energy  sector  and  industrial  processes  n 
EU28 

Figure  46.Average  annual  energy  system  cost  (left)  average  unit  cost  of 
emission  reduction  (right)  in  EU28  for  the  two  main  scenarios  and  the 
sensitivity scenario 

The higher  costs  of hydrogen technologies lead to the cost  of the sensitivity scenario 
being higher than the balanced scenario but still lower than the basic decarbonisation 
scenario (Figure 46). On average, the sensitivity scenario requires additional average 
expenditures on the  energy system of around  45 billion per  year in the period 2031-
2050,  placing  it  in  between  the  two  main  scenarios  in  terms  of  costs.  As  far  as  the 
average unit cost of emission abatement is concerned, these, although higher than in 
the  balanced  scenario,  remain  much  lower  than  the  basic  decarbonisation  scenario, 
indicating that emission reductions around 90% are possible, at affordable costs, even 
with  less  optimistic  developments  of  hydrogen  related  technologies,  however  more 
optimistic than the basic decarbonisation scenario. 

If  hydrogen  related  technologies  (both  on  the  demand  and  supply  side)  reduce 
significantly  in  costs  compared  to  today,  they  can  become  a  key  technology  to  help 
reduce emissions beyond the levels achieved in the basic decarbonisation scenario and 
at  affordable  costs.  In  order  to  achieve  emission  reductions  beyond  the  80%  it  is 
paramount that such technologies develop.  

January 2018  I  101 

1950195019522444236024050500100015002000250030003500400045005000BasicDecarbonisationScenarioBalanced ScenarioSensitivity Scenariobillion EURAverage annual energy system cost13213313918288131050100150200250300350BasicDecarbonisationScenarioBalanced ScenarioSensitivityScenarioEUR per tCO2 abated cumulativelyAverage unit cost of emissions reduction2031-20502021-2030 
 
 
 
 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

Conclusions and recommendations 
Roadmaps  for  the  European  Union,  such  as  those  quantified  by  the  PRIMES  energy 
systems model for the European Commission, show that planned and existing measures 
take  us  a  long  way  towards  significantly  decarbonising  the  European  energy  system, 
however  emissions  remain  mainly  in  transport,  the  domestic  sector  and  in  industry. 
Abating these remaining emissions is complex and costly. Current polices and measures 
in  place  are  sector  specific  (e.g.  CO2  standards  for  vehicles,  or  energy  efficiency 
measures) or cover at maximum a selected number of sectors (ETS).  In order to abate 
the  remaining  emissions,  measures  across  sectors  are  required,  therefore  sectoral 
integration becomes necessary.  

Strategies which allow for deep decarbonisation require sectoral integration policies and 
involve going beyond the role of electricity and considering using hydrogen as an energy 
carrier in various roles in the energy system. In this study, hydrogen is envisaged as a 
key element for the sectoral integration with different possible roles:  

(A) carbon-free hydrogen as an energy carrier and end use fuel,  

(B) hydrogen  as  a  feedstock  for  the  production  of  carbon-free  gas  and  liquid 

hydrocarbons, and  

(C) hydrogen as a versatile power storage while electricity as a carrier is fully used 

in the energy consumption sectors.  

In  this  study  we  have  presented  three  strategies  to  elucidate  the  advantages  and 
disadvantages  of  the  use  of  hydrogen  in  these  three  roles.  All  strategies  require 
ramping-up the production of hydrogen but differ in the way they foresee it being used. 
The strategies therefore require technologies producing carbon free hydrogen, and then 
the development of technologies which are strategy specific: strategy (A) requires fuel 
cells, strategy (B) power-to-liquid and power-to-gas technologies, and strategy (C) the 
development  of  electric  end  –use  technologies  for  all  sectors,  including  e.g.  aviation. 
These  technological  developments  are  not  mature  today;  the  timing  of  their 
development and future costs are difficult to estimate.  

The  study  has  reviewed  in  a  bottom-up  manner  a  number  of  hydrogen-related  and 
power-to-hydrogen  technologies  and  assesses  the  market  potential  for  carbon-free 
(green) hydrogen, as well as the use of electricity in mobility, industry and the domestic 
sector. 

The study finds that there are options to use both hydrogen based and electricity based 
options  for  transport  depending  on  the  transport  mode:  thanks  to  their  relative 
strengths  there  could  be  markets  for  both  technologies,  depending  on  the  market 
segment, or transport mode.  

For industry the use of carbon-free hydrogen, allows for the elimination of emissions in 
non-energy uses. For  energy combustion for high temperature uses hydrogen can be 
directly injected in order to reduce emissions. Fuel cells, while not being applicable to 
high  temperature  uses,  can  provide  an  option  to  heat-pumps  for  low  and  medium 
enthalpy heat uses. Both heat-pumps and fuel cells can be used also for the domestic 
sectors:  the  former  are  reaching  market  maturity,  whereas  fuel  cells  are  still  very 
expensive. To be widely used as an end use fuel, hydrogen requires  –aside from fuel 
cells-  also  the  development  of  a  transmission  and  distribution  infrastructure.  The 
adaptation of the natural gas infrastructure is possible, it is however a time consuming 
and expensive endeavour.  

A  common  element  for  all  strategies  is  the  production  of  carbon  free  hydrogen 
production:  as  steam  reforming  is  not  carbon  free,  the  production  of  hydrogen  must 
take  place  through  electrolysis.  There  are  three  major  technologies  available  for  the 
production of carbon-free hydrogen: alkaline electrolysis, Polymer Electrolyte Membrane 

January 2018  I  102 

 
 
 
Sectoral integration: long-term perspective in the EU energy system 

(PEM) electrolysis, and Solid Oxide Electrolyser Cell (SOEC). The former two are at a 
sufficient  TRL  and  further  cost  reductions  are  possible  if  developed  at  a  large  scale. 
SOEC technologies are a promising technology, however they have currently at low TRL.   

Storage of hydrogen is also a requirement for all strategies, to a lesser or larger extent 
depending on the strategy. The study has divided storage options into large and small. 
Large storage systems are required together with a large scale distribution system, in 
case hydrogen becomes a universal energy carrier, whereas smaller scale systems are 
appropriate for small and medium scale applications, in particular for facilities containing 
electrolysis plants and in large-scale hydrogen refuelling stations. Small scale systems 
are  also  technically  and  economically  viable  business  cases  for  the  transition  period, 
while large scale development is underway.  

A concrete business case for hydrogen  –from today’s perspective- has been analysed 
within  this  study:  hydrogen  used  to  absorb  excess  electricity  production  from 
renewables  and  use  of  hydrogen  within  the  same  region.  Regions  have  been  studied 
where there are times of excess electricity production and possibility for hydrogen uses 
nearby.  These  areas  can  be  forerunners  and  test  sites  for  larger  and  long-term 
developments.  

From a general perspective two business models are found to be viable for hydrogen 
production: decentralised hydrogen production close to end use or centralised hydrogen 
production.  Decentralised  options  are  adequate  in  the  transition  period.  For  the 
development of any business model, it is required that the development of demand and 
supply,  as  well  as  distribution,  is  performed  almost  simultaneously.  For  this  reason 
market  coordination  failure  is  the  highest  risk  for  the  development  of  the  strategies; 
long term anticipation and regulatory certainty are the key factors to develop positive 
market coordination, for all strategies analysed. 

Each one of the three strategies proposed has its merits and drawbacks. Strategy A – 
developing hydrogen as a universal energy carrier - has the advantage of one energy 
carrier which can be used in numerous applications. For transport it solves issues related 
to range limitations. Fuel cells can also be applied easier than electricity to a variety of 
modes including long-distance road transportation. However, the scenario relies on the 
uncertain development of fuel cells, at a large scale, for all transport segments and the 
development  of  a  large-scale  hydrogen  infrastructure  network  of  pipeline  for  the 
transportation of hydrogen to all end-uses, including households. Strategy B –hydrogen 
as a feedstock for power-to-gas and power-to-liquids- allows for the continued use of 
existing  technologies  in  the  demand  side  for  transport  modes  that  are  difficult  to 
decarbonise,  specific  industrial  applications,  as  well  as  parts  of  the  domestic  sector. 
However, the scenario requires the development of carbon capture from air technologies 
in  order  for  the  fuel  production  to  be  carbon  neutral,  as  well  as  a  high  increase  in 
electricity  generation  since  the  fuel  production  chains  are  inefficient.  Strategy  C  – 
hydrogen  as  storage-  proposes  to  use  hydrogen  as  a  storage  for  excess  electricity 
production and to electrify all end-uses in order to decarbonise them. While this strategy 
requires the least additional electricity production, it relies on the electrification of all 
end-use sectors, including transport modes such as aviation and industrial sectors where 
the chemical composition of outputs might need to be modified. 

Each  strategy  is  in  itself  a  stylised  case  with  extreme  measures  to  highlight  its 
advantages and disadvantages. However, a more likely outcome is a pathway that tries 
to take advantage of the positive aspects of each strategy without  requiring extreme 
measures, therefore attempting to minimise the disadvantages of each strategy.  

Such a balanced scenario could have the following characteristics: 

▪  Hydrogen is mixed in natural gas uses up to the maximum technical feasibility 
(15%); further bio-methane and synthetic methane gas (produced using CO2 

January 2018  I  103 

 
 
 
Sectoral integration: long-term perspective in the EU energy system 

obtained via air capture) are also being blend in distributed gas streams, at share of 
15-20% in the long term; 

▪  introduction of hydrogen fuels cells in transport modes which cannot electrify such 
heavy duty vehicles and complimentary to vehicles travelling long annual mileages 
(e.g. taxis) or long-distances; 

▪  use of direct injection of hydrogen in industry for high temperature furnaces, 

including in iron and steel, chemicals and other industrial sectors; 

▪  power-to-H2 technologies develop in order to a) provide storage services at large 
scale to the power sector, maximizing in this way the use of renewables and b) 
produce hydrogen and clean methane for utilization by end-use consumers. 

In the balanced scenario, hydrogen fuel cells are exploiting their learning potential and 
thanks  to  development  of  optimized  scale  hydrogen  fuelling  hubs  they  can  conquer 
those transport modes which are difficult to electrify, in particular heavy duty vehicles 
and generally any vehicle with high annual mileage. The development of refuelling hubs 
is  economically  appropriate  for  these  market  segments,  and  avoid  deployment  small 
scale refuelling of hydrogen that is expensive. The hubs can be placed in selected city 
areas and on major highways. The combination of hydrogen and electricity, limits the 
use of biofuels to sectors which cannot use either technologies therefore mainly aviation 
and navigation. These transport modes can therefore switch to much higher shares of 
biofuels, as quantities are freed from long distance road transportation. 

For  buildings  energy  efficiency  and  electrification  will  significantly  reduce  the 
consumption of natural gas and the remaining quantities will be covered by the mixture 
of hydrogen and bio-methane, as well as clean gas in the distribution of gas to reduce 
average emissions of the gaseous fuel.  

For industry the strategy requires the use of hydrogen wherever possible to be directly 
injected  to  high  temperature  processes  in  order  to  minimize  emissions.  This  is 
economically efficient also because hydrogen transport can focus on specific industrial 
areas.  

In  this  way,  the  balanced  scenario  achieves  95%  CO2  emission  reductions  in  2050 
relative to 1990, compared to 84% of the basic decarbonisation scenario. A sensitivity 
with  less  optimistic  assumptions  about  the  development  of  hydrogen  related 
technologies, shows that emission reductions around 90% are nonetheless possible, at 
affordable costs.  

Electricity  generation  increases  by  around  35%  in  2050  compared  to  the  basic 
decarbonisation scenario: thanks to the assumptions about full market integration and 
the  interconnected  system  which  allows  to  take  advantage  of  remote  locations  for 
renewables,  the  average  electricity  price  remain  at  the  same  levels  as  in  the  basic 
decarbonisation scenario, presenting even a marginal drop. The hydrogen based storage 
of electricity makes a considerable contribution to the smoothing of load and therefore 
allows to fully take advantage of overproduction and compensates for production deficit, 
maximizing the load factors of the renewables.  

The average CO2 abatement cost is €88/t CO2 (cumulatively in the period 2031-2050, 
compared  to  €182/t  CO2  in  the  basic  decarbonisation  scenario.  The  lower  cost  is 
achieved thanks to the introduction of hydrogen as an intermediate fuel, its particular 
role  in  transport;  the  scenario  benefits  from  the  assumed  techno-economic 
developments of the fuel cell technology, from €300/kW today to €44/kW in 2050, as 
well as the ones in battery cells. The average annual energy system costs in the period 
2031-2050  is  in  the  balanced  scenario  3.4%  lower  than  in  the  basic  decarbonisation 
scenario. If hydrogen technologies would be more expensive in the long term, as in the 
sensitivity  analysis,  the  energy  system  costs  would  still  be  lower  in  the  balanced 
scenario compared to the basic decarbonisation scenario, but by 1.6% only. The average 

January 2018  I  104 

 
 
 
Sectoral integration: long-term perspective in the EU energy system 

CO2 abatement cost would be €131/t CO2 in the sensitivity scenario (cumulatively in the 
period 2031-2050). 

The balanced scenario benefits from the availability of the hydrogen technology options 
and the reduced cost of fuel cells which by assumption were not available in the context 
of  the  basic  decarbonisation  scenario.    In  this  sense,  the  two  scenarios  are  not  fully 
comparable  regarding  total  cost  performance.  The  merit  of  the  sectoral  integration 
enabled by hydrogen is that it enables stronger abatement and lower costs, just because 
this option has not been considered in the basic decarbonisation scenario.  

The balanced scenario considerably reduces the import dependency to 27% due to two 
main reasons: gas use decreases significantly and almost half of the gas consumption 
is  covered  by  hydrogen,  clean  gas  and  bio-methane;  the  remaining  liquid  fuel 
requirements  in  transport  are  covered  mainly  by  advanced  biofuels.  The  remaining 
imports of oil products are largely used for non-energy purposes (approx. 87%). The 
incremental  energy  required  for  the  scenario  is  provided  almost  exclusively  by 
renewables which are projected to be domestic. 

The  key  technological  achievements  required  for  the  balanced  scenario  are  hydrogen 
electrolysis,  fuel  cells  and  industrial  uses  of  hydrogen,  as  well  as  air  capture.  It 
minimizes the requirements for large scale additional infrastructure and excessive use 
of technologies which are at low TRL. 

Although  the  balanced  strategy  is  more  conservative  in  terms  of  innovation 
requirements and finally emission reductions, all strategies presented within this study 
are  not  realistic  from  today’s  perspective:  technological  developments  need  to  occur 
which are highly uncertain. It is imperative however that already today the discussions 
are  started  and  progress  is  obtained  to  facilitate  the  future  achievement  of  a  zero 
emissions scenario, so that ultimately the limitations and uncertainties are resolved. If 
hydrogen  related  technologies  (both  on  the  demand  and  supply  side)  reduce 
significantly  in  costs  compared  to  today,  they  can  become  a  key  technology  to  help 
reduce emissions beyond the levels achieved in the basic decarbonisation scenario and 
at  affordable  costs.  In  order  to  achieve  emission  reductions  beyond  the  80%  it  is 
paramount that such technologies develop in a timely manner.  

Why does the discussion need to start today? The role out of the infrastructure and the 
emergence  of such business models is expected to last over 10 years. Undertaking a 
back-casting  exercise  starting  from  the  assumption  that  the  aim  is  to  achieve  zero 
emissions by 2060, this would imply that already in 2050 very significant development 
needs  to  have  taken  place.  Therefore,  large  scale  roll-out  of  infrastructure  and 
technologies need to have started by 2040 the latest. This again implies that already in 
2030 a strategy needs to have been defined and the correct signals sent to the R&D and 
their investors to develop the required technologies. The financial requirements of each 
strategy are such that parallel developments are deemed not possible. The strategies 
require  competing  technologies  that  need  such  economies  of  scale  that  could  not  be 
warranted with parallel developments. 

It  is  not  necessary  to  decide  on  the  strategy  today,  but  the  discussion  and  research 
needs to initiate. On the practical side, an acceleration of R&D is required in order to be 
able to understand and foresee with higher certainty which technologies will most likely 
be mature in the timeframe required, in order to decide on a strategical direction before 
2030. 

This study is a first scoping exercise which needs to be complemented by full energy 
systems  analysis,  studies  to  assess  the  financing  needs,  as  well  as  the  opportunities 
arising  from  the  developments  of  such  strategies  for  the  European  economy  for 
exporting  or  for  job  creation.  An  assessment  of  energy  policy  instruments  which  will 
facilitate  the  development  of  strategies  towards  a  more  sustainable  energy  system, 

January 2018  I  105 

 
 
 
Sectoral integration: long-term perspective in the EU energy system 

along  the  lines  described  in  this  study  are  also  required  in  order  to  enable  the 
development and deployment of technologies and to underpin the market coordination 
requirements.  

As  a  next  step,  not  addressed  in  this  study,  we  put  emphasis  on  the  assessment  of 
suitable energy policy instruments which will enable emergence and wide spread of the 
technologies and facilitate market coordination. Further steps are also required to assess 
the sectoral integration strategies from a financing perspective and evaluate the impacts 
on industry, exports and employment in the EU. Further analysis of possible integration 
of clean hydrogen in the industrial processes and the produced materials also requires 
more in depth insights. 

January 2018  I  106 

 
 
 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

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[Online]. 

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January 2018  I  108 

 
 
 
Sectoral integration: long-term perspective in the EU energy system 

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[Accessed 

[45]  Life 'N Grab Hy, “Clean cities, clean air, with garbage trucks on hydrogen,” Life 
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Sectoral integration: long-term perspective in the EU energy system 

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[47]  Linde, “Frankfurt and Wiesbaden: New Hydrogen refuelling stations link north and 
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healthcare.be/nl/news_and_media/press_releases/news_20170614.html. 
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Available: 

[Online]. 

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[Online]. 

EVEER 

2017. 

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Available: 

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December 2017]. 

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networks for the Dutch underground storage,” 2017. 

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[Online]. 

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Available: 
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Information  Trends,”  29  November  2017. 

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[Online].  Available: 

Says 
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December 2017]. 

[56]  De 

Lijn, 

“CO2-uitstoot 

voertuigen,”  De 

lijn, 

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[Online]. 
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Available: 

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JU, 

“H2Future,” 

FCH 

JU, 

2017. 

[Online]. 

Available: 

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manufacturing-value-chains. [Accessed 12 December 2017]. 

[60]  ArcelorMittal, 

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Products/Hamburg/. [Accessed 12 December 2017]. 

[Online].  Available: 

January 2018  I  110 

 
 
 
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

APPENDIX: Technical and economic data 
Technical and  economic data which are currently in consultation. The last columns  of 
the data indicatively calculate a levelized cost of output. This calculation is not as such 
in the model, which performs more de-tailed economic calculations of costs taking into 
account  all  aspects  of  the  energy  system.  The  levelized  costs  serve  only  illustration 
purposes. 

For illustration only, the tables below also provide calculation of levelized unit costs for 
the output of se-lected value chains regarding distribution of end products. 

The data in these tables are subject to change in the near future, as data collection and 
consultations continue. 

January 2018  I  111 

 
 
 
Conversion technologies 

Hydrogen from natural gas steam reforming 
centralised - Large Scale (per 1 kW or 1 MWh H2 
HHV) 

Hydrogen from natural gas steam reforming 
centralised - Large Scale with CCU (per 1 kW or 1 
MWh H2 HHV) 

Hydrogen from natural gas steam reforming de-
centralised - Medium Scale (per 1 kW or 1 MWh 
H2 HHV) 

Hydrogen from low temperature water electrolysis 
PEM centralised - Large Scale (per 1 kW or 1 MWh 
H2 HHV) 

Hydrogen from low temperature water electrolysis 
PEM de-centralised at a refuelling station  (per 1 
kW or 1 MWh H2 HHV) 

Hydrogen from low temperature water electrolysis 
Alkaline centralised - Large Scale  (per 1 kW or 1 
MWh H2 HHV) 

Hydrogen from low temperature water electrolysis 
Alkaline de-centralised at a refuelling station  (per 
1 kW or 1 MWh H2 HHV) 

Hydrogen from low temperature water electrolysis 
SOEC centralised  (per 1 kW or 1 MWh H2 HHV) 

Hydrogen from low temperature water electrolysis 
SOEC de-centralised at a refuelling station  (per 1 
kW or 1 MWh H2 HHV) 

Sectoral integration: long-term perspective in the EU energy system 

Investment cost 
per unit of capacity 
(EUR/kW-output) 

Fixed O&M costs 
(EUR/kW-output) 

Capital and fixed 
cost per unit of 
output (EUR/MWh-
output) 

Variable, fuel and 
emissions cost per 
unit of output 
(EUR/MWh-output 
or per tCO2) 

Total cost per unit 
of output 
(EUR/MWh-output 
or per tCO2) 

2015  2030 

Ulti-
mate 

2015  2030 

Ulti-
mate 

2015  2030 

Ulti-
mate 

2015  2030 

Ultim
ate 

2015  2030 

Ulti-
mate 

550 

500 

450 

22 

20 

18 

11.8 

10.7 

9.7 

36 

49 

176 

48 

60 

186 

900 

850 

800 

36 

34 

32 

19.3 

18.3 

17.2 

88 

115 

249 

107 

133 

267 

1978  1598  1450 

57 

31 

28 

48.0 

36.2 

33.0 

40 

55 

196 

88 

91 

229 

2000 

340 

200 

50 

15 

10 

35.5 

6.9 

4.2 

72 

78 

86 

108 

85 

90 

3000 

750 

350 

70 

34 

18 

52.6 

15.2 

7.3 

78 

82 

87 

131 

97 

95 

1100 

300 

180 

28 

14 

9 

19.5 

6.1 

3.8 

73 

83 

87 

92 

89 

90 

1650 

380 

300 

41 

17 

15 

29.3 

7.7 

6.3 

73 

83 

88 

102 

91 

94 

5000  2500 

950 

175 

113 

62 

94.9 

50.6 

21.6 

90 

98 

87 

185 

149 

108 

7500  4375  1188 

263 

197 

77 

142.3  88.5 

27.0 

91 

100 

88 

234 

188 

115 

January 2018  I  112 

 
 
 
  
  
Sectoral integration: long-term perspective in the EU energy system 

Conversion technologies 

Methanation (per 1 kW or 1 MWh CH4 
HHV) 

CH4 Liquefaction plant (per 1 kW or 1 
MWh gas HHV) 

Gas Liquefaction plant (per 1 kW or 1 
MWh gas HHV) 

Regasification Plant including LNG storage 
(per 1 kW or 1 MWh gas HHV) 

Power to liquid via the methanol route 
(per 1 kW or 1 MWh CH4 HHV) 

Power to liquid via the Fischer Tropsch 
route  (per 1 kW or 1 MWh CH4 HHV) 

Power to liquid via High temperature co-
electrolysis and Fischer Tropsch (per 1 kW 
or 1 MWh CH4 HHV) 

Capture CO2 from air (Absorption 
technology) (per 1 tCO2) 

Capture CO2 from air (Adsorption 
technology) (per 1 tCO2) 

Investment cost per 
unit of capacity 
(EUR/kW-output) 

Fixed O&M costs 
(EUR/kW-output) 

Capital and fixed 
cost per unit of 
output (EUR/MWh-
output) 

Variable, fuel and 
emissions cost per 
unit of output 
(EUR/MWh-output 
or per tCO2) 

Total cost per unit 
of output 
(EUR/MWh-output 
or per tCO2) 

2015  2030 

Ulti-
mate 

2015  2030 

Ulti-
mate 

2015  2030 

Ulti-
mate 

2015  2030 

Ulti-
mate 

2015  2030 

Ulti-
mate 

1200  633 

263 

42 

22 

9 

22.8  12.0 

5.0 

1 

1 

1 

23 

13 

6 

450 

450 

450 

18 

18 

18 

7.7 

7.7 

7.7 

9 

13 

40 

17 

20 

47 

200 

200 

200 

20 

20 

20 

4.8 

4.8 

4.8 

2 

3 

4 

7 

8 

9 

175 

175 

175 

5 

5 

5 

2.7 

2.7 

2.7 

0 

0 

2 

3 

3 

5 

1000  620 

364 

50 

31 

18 

20.9  12.9 

7.6 

7 

10 

34 

28 

23 

41 

1556  1143  673 

54 

40 

24 

29.5  21.7  12.8 

2 

2 

6 

31 

24 

19 

2332  1511  965 

163 

106 

68 

54.5  35.3  22.5  111 

118 

165 

165 

153 

188 

770 

648 

335 

27 

23 

12  116.9  98.4  50.8  0.18  0.15  0.17  117 

99 

51 

1260  894 

270 

44 

31 

9 

191.3  135.8  41.0  0.06  0.08  0.22  191 

136 

41 

CO2 Liquefaction plant (per 1 ton CO2) 

174 

174 

174 

3 

3 

3 

3.2 

3.2 

3.2 

0.01  0.01  0.02 

3 

3 

3 

January 2018  I  113 

 
 
 
  
  
 
 
Sectoral integration: long-term perspective in the EU energy system 

 Refuelling technologies 

Investment cost per 
unit of capacity 
(EUR/kW-output) 

Fixed O&M costs 
(EUR/kW-output) 

Capital and fixed cost 
per unit of output 
(EUR/MWh-output) 

2015 

2030 

Ulti-
mate 

2015 

2030 

Ulti-
mate 

2015 

2030 

Ulti-
mate 

Variable, fuel and 
emissions cost per unit 
of output (EUR/MWh-
output or per tCO2) 
Ulti-
mate 

2015 

2030 

Total cost per unit of 
output (EUR/MWh-
output or per tCO2) 

2015 

2030 

Ulti-
mate 

H2 compression station  (per 1 kW or 1 MWh H2 HHV) 

114 

102 

91 

0.4 

0.4 

0.4 

2.3 

2.1 

1.8 

3.6 

4.6 

5.1 

5.9 

6.6 

7.0 

Hydrogen Liquefaction plant  (per 1 kW or 1 MWh H2 
HHV) 

H2 liquid to gas refuelling station  (per 1 kW or 1 MWh 
H2 HHV) 

H2 refuelling station Small  (per 1 kW or 1 MWh H2 
HHV) 

H2 refuelling station Medium  (per 1 kW or 1 MWh H2 
HHV) 

H2 refuelling station Large  (per 1 kW or 1 MWh H2 
HHV) 

ELC recharging points - Semi Fast recharging  (per 1 kW 
or 1 MWh ELC) 

ELC recharging points - Fast recharging  (per 1 kW or 1 
MWh ELC) 

761 

635 

457 

23.0 

23.0 

23.0 

12.1 

10.6 

8.4 

1.1 

1.4 

1.5 

13.2 

11.9 

9.9 

855 

759 

568 

1.6 

1.4 

1.1 

16.9 

15.0 

11.2 

3.7 

4.6 

5.2 

20.6 

19.6 

16.4 

1009 

867 

822 

4.1 

4.1 

4.1 

20.3 

17.6 

16.7 

3.6 

4.6 

5.1 

24.0 

22.2 

21.8 

542 

412 

379 

1.7 

1.7 

1.7 

10.8 

8.3 

7.6 

3.6 

4.6 

5.1 

14.5 

12.9 

12.8 

325 

247 

151 

0.7 

0.7 

0.7 

6.4 

4.9 

3.1 

3.6 

4.6 

5.1 

10.1 

9.5 

8.2 

240 

240 

240 

9.6 

9.6 

9.6 

5.8 

5.8 

5.8 

0.0 

0.0 

0.0 

5.8 

5.8 

5.8 

900 

900 

900 

36.0 

36.0 

36.0 

21.7 

21.7 

21.7 

0.0 

0.0 

0.0 

21.7 

21.7 

21.7 

CNG compression station  (per 1 kW or 1 MWh gas HHV) 

89 

89 

89 

5.7 

5.7 

5.7 

2.7 

2.7 

2.7 

1.2 

1.5 

2.0 

3.9 

4.2 

4.7 

CNG refuelling station  (per 1 kW or 1 MWh gas HHV) 

197 

197 

197 

4.3 

4.3 

4.3 

6.8 

6.8 

6.8 

0.0 

0.0 

0.0 

6.8 

6.8 

6.8 

LNG refuelling station  (per 1 kW or 1 MWh gas HHV) 

120 

120 

120 

3.9 

3.9 

3.9 

4.5 

4.5 

4.5 

0.0 

0.0 

0.1 

4.5 

4.5 

4.6 

January 2018  I  114 

 
 
 
  
 
 
Sectoral integration: long-term perspective in the EU energy system 

 Distribution technologies 

Investment cost per unit of 
capacity (EUR/kW-output) 

Fixed O&M cost per unit of 
capacity (EUR/kW-output) 

Variable Cost EUR/MWh 

Levelized cost per unit of 
product transported 
(EUR/MWh-output) 

NGS Transmission Network  (per MWh )  (per MWh ) 

NGS Distribution Network  (per MWh) 

H2 pipeline 60bar  (per  MWh H2 HHV) 

H2 pipeline 10 bar  (per MWh H2 HHV) 

CO2 Transmission network (per tCO2) 

Road transport of liquid H2 

Road transport of gaseous H2 

2015 

2030 

126 

552 

178 

723 

126 

552 

173 

723 

Ultim-
ate 

126 

552 

166 

723 

2015 

2030 

5 

22 

7 

29 

5 

22 

7 

29 

Ulti-
mate 

5 

22 

7 

29 

2015 

2030 

Ulti-
mate 

2015 

2030 

Ulti-
mate 

0.7 

3.2 

1.0 

4.1 

0.7 

3.2 

1.0 

4.1 

0.7 

3.2 

1.0 

4.1 

2.7 

2.7 

2.7 

19.2 

19.2 

19.2 

3.8 

3.7 

3.6 

25.2 

25.2 

25.2 

Investment cost per unit of 
capacity (EUR/ton CO2 per 
year) 

Fixed O&M cost per unit of 
capacity (EUR/ton CO2 per 
year) 

Variable Cost EUR/kWh 

Levelized cost per unit of 
product transported 
(EUR/ton CO2) 

2015 

2030 

23 

23 

Ulti-
mate 

23 

2015 

2030 

1.3 

1.3 

Ulti-
mate 

1.3 

2015 

2030 

Ulti-
mate 

2015 

2030 

Ulti-
mate 

1.0 

1.0 

1.0 

4.3811 

4.3811 

4.3811 

Investment cost per unit of 
capacity (EUR/kW-output) 

Fixed O&M cost per unit of 
capacity (EUR/kW-output) 

Variable Cost EUR/kWh 

2015 

2030 

74 

344 

68 

324 

Ulti-
mate 
55 

284 

2015 

2030 

7 

58 

7 

58 

Ulti-
mate 
7 

58 

2015 

2030 

0.3 

3.6 

0.3 

3.6 

Ulti-
mate 
0.3 

3.6 

Levelized cost per unit of 
product transported 
(EUR/ton CO2) 

2015 

2030 

3.0 

19.0 

2.8 

18.5 

Ulti-
mate 
2.5 

17.5 

January 2018  I  115 

 
 
 
 
  
 
 
 
  
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

Storage technologies 

Investment cost per unit of 
energy stored per year 
(EUR/MWh) 
2030 

2015 

Ultimate 

Fixed O&M costs (EUR/kW) 

2015 

2030 

Ultimate 

Variable, fuel and emissions 
cost per unit of stored energy 
(EUR/MWh) 
2030 

Ultimate 

2015 

Compressed Air Energy Storage  (per 1 kW or 1 MWh 
electricity) 

125000 

112500 

110931 

38.5 

34.7 

34.2 

Flywheel  (per 1 kW or 1 MWh electricity) 

1750000  1575000  1553029 

52.5 

47.3 

46.6 

Large-scale batteries  (per 1 kW or 1 MWh electricity) 

600000 

253000 

225484 

40.5 

15.0 

13.1 

Small-scale batteries  (per 1 kW or 1 MWh electricity) 

270000 

114000 

101619 

16.9 

6.3 

5.5 

Pumping  (per 1 kW or 1 MWh electricity) 

100000 

90000 

88745 

22.5 

20.3 

20.0 

Underground Hydrogen Storage  (per 1 kW or 1 MWh 
H2) 

Pressurised tanks -  Hydrogen storage  (per 1 kW or 1 
MWh H2) 

Liquid Hydrogen Storage - Cryogenic Storage  (per 1 kW 
or 1 MWh H2) 

Metal Hydrides - Hydrogen Storage  (per 1 kW or 1 
MWh H2) 

7200 

7200 

7200 

6000 

4800 

4659 

8455 

6800 

4000 

12700 

11430 

11271 

0.0 

0.0 

0.0 

0.0 

0.0 

0.0 

0.0 

0.0 

0.0 

0.0 

0.0 

0.0 

Thermal Storage Technology  (per 1 kW or 1 MWh Heat) 

100000 

90000 

88745 

100.0 

97.2 

95.8 

LNG Storage Gas  (per 1 kW or 1 MWh Gas) 

Underground NGS Storage  (per 1 kW or 1 MWh Gas) 

135 

33 

135 

33 

135 

33 

0.0 

0.0 

0.0 

0.0 

0.0 

0.0 

0.0 

0.0 

0.0 

0.0 

0.0 

0.6 

0.6 

0.7 

0.5 

0.0 

0.6 

0.6 

0.0 

0.0 

0.0 

0.0 

0.0 

0.7 

0.7 

0.9 

0.7 

0.0 

0.7 

0.7 

0.0 

0.0 

0.0 

0.0 

0.0 

0.8 

0.8 

1.0 

0.8 

0.0 

0.8 

0.8 

Total cost per unit of stored 
energy (EUR/MWh) 

2015 

2030 

Ultimate 

225 

203 

200 

1127 

1015 

1000 

311 

122 

108 

74 

155 

4.7 

3.0 

4.1 

5.7 

31 

140 

4.9 

2.7 

3.6 

5.3 

27 

138 

5.0 

2.7 

2.6 

5.3 

78.6 

70.7 

69.7 

1.9 

4.4 

2.1 

4.5 

2.1 

4.6 

Liquid CO2 storage tank 

1000 

1000 

1000 

15 

15 

15 

      3.18  

      3.18  

      3.18  

      4.14  

      4.43  

      4.02  

Investment cost per ton CO2 
stored per year (EUR/tCO2) 

Investment cost per ton CO2 
(EUR/tCO2) 

EUR/tCO2 liquefaction cost 

EUR/tCO2 

January 2018  I  116 

 
 
 
 
  
  
 
 
Sectoral integration: long-term perspective in the EU energy system 

Value Chains  
Levelized costs 
EUR/MWh of CH4 

Hydrogen feedstock 

Methanation 

CO2 captured 

CO2 emission 

Total 

2015 

2030 

Ulti-
mate 

2015 

2030 

Ulti-
mate 

2015 

2030 

Ulti-
mate 

2015 

2030 

Ulti-
mate 

2015 

2030 

Ultim-
ate 

Fossil natural gas 

1.4 

6.2 

103.2 

23.2 

33.1 

132.0 

Synthetic Gas (via Steam Reforming Natural Gas) 

60.8 

76.6 

237.2 

23.3 

12.7 

5.7 

11.9 

14.6 

16.2 

1.9 

8.0 

132.1 

98.0 

111.9 

391.2 

Synthetic Gas (via PEM Electrolysis) 

137.9 

108.3 

115.2 

23.3 

12.7 

5.7 

23.4 

19.7 

10.2 

0.0 

0.0 

0.0 

184.6 

140.7 

131.2 

Synthetic Gas (via Alkaline Electrolysis) 

117.9 

113.8 

115.7 

23.3 

12.7 

5.7 

23.4 

19.7 

10.2 

0.0 

0.0 

0.0 

164.6 

146.2 

131.6 

Synthetic Gas (via SOEC Electrolysis) 

236.1 

190.0 

138.5 

23.3 

12.7 

5.7 

23.4 

19.7 

10.2 

0.0 

0.0 

0.0 

282.8 

222.3 

154.4 

Levelized costs 
 EUR/MWh of Liquid fuel 

Hydrogen feedstock 

Methanol route 

CO2 captured 

CO2 emission 

Total 

2015 

2030 

Ulti-
mate 

2015 

2030 

Ulti-
mate 

2015 

2030 

Ulti-
mate 

2015 

2030 

Ulti-
mate 

2015 

2030 

Ulti-
mate 

Fossil diesel oil 

0.0 

0.0 

0.0 

0.0 

0.0 

0.0 

0.0 

0.0 

0.0 

1.9 

8.2 

137.2 

45.2 

82.1 

220.6 

Synthetic Liquid via Methanol (via PEM 
Electrolysis) 

Synthetic Liquid via Methanol (via Alkaline 
Electrolysis) 

Synthetic Liquid via Methanol (via SOEC 
Electrolysis) 

Synthetic Liquid via Fischer-Tropsch (via PEM 
Electrolysis) 

Synthetic Liquid via Fischer-Tropsch (via Alkaline 
Electrolysis) 

Synthetic Liquid via Fischer-Tropsch (via SOEC 
Electrolysis) 

Synthetic Liquid via High temperature co-
electrolysis and Fischer Tropsch 

150.6 

118.3 

125.8 

28.0 

22.8 

41.4 

29.6 

24.9 

12.9 

208.2 

166.0 

180.1 

128.7 

124.3 

126.3 

28.0 

22.8 

41.4 

29.6 

24.9 

12.9 

186.3 

172.0 

180.5 

257.8 

207.4 

151.2 

28.0 

22.8 

41.4 

29.6 

24.9 

12.9 

315.4 

255.2 

205.4 

150.6 

118.3 

125.8 

31.4 

24.2 

18.9 

29.6 

24.9 

12.9 

211.6 

167.3 

157.6 

128.7 

124.3 

126.3 

31.4 

24.2 

18.9 

29.6 

24.9 

12.9 

189.7 

173.3 

158.0 

257.8 

207.4 

151.2 

31.4 

24.2 

18.9 

29.6 

24.9 

12.9 

318.8 

256.5 

182.9 

54.5 

45.9 

23.8 

219.8 

198.9 

211.7 

January 2018  I  117 

 
 
 
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
 
 
 
Sectoral integration: long-term perspective in the EU energy system 

Distribution of Hydrogen 

LCOE EUR/MWh distributed hydrogen 

Distribution of gaseous H2 

Electrolyzer 

H2 Compression 

H2 pipeline HP 

H2 pipeline LP&MP 

Total 

2015 

2030 

92 

89 

Ult-
imate 
90 

2015 

2030 

5.9 

6.6 

Ulti-
mate 
7.0 

2015 

2030 

3.8 

3.7 

Ulti-
mate 
3.6 

2015 

2030 

25.2 

25.2 

Ulti-
mate 
25.2 

2015 

2030 

127 

125 

LCOE EUR/MWh distributed hydrogen 

Distribution of Liquid H2 

Electrolyzer 

H2 Liquefaction 

Liquid H2 truck and Liquid 
H2 Tank 

Liquid H2 terminal and 
refuelling 

2015 

2030 

92 

89 

Ulti-
mate 
90 

2015 

2030 

13.2 

11.9 

Ulti-
mate 
9.9 

Electrolyzer 

H2 Compression 

Ulti-
mate 
2.5 

2015 

2030 

3.0 

2.8 
H2 Tube and H2 
pressurized tank 

2030 

2015 

Ulti-
mate 
20.6 
16.4 
19.6 
Compressed H2 terminal 
and refuelling 

Total 

2015 

2030 

129 

123 

Total 

LCOE EUR/MWh distributed hydrogen 

2015 

2030 

Distribution of Compressed H2 

92 

89 

Ulti-
mate 
90 

2015 

2030 

5.9 

6.6 

Ulti-
mate 
7.0 

2015 

2030 

19 

19 

Ulti-
mate 
18 

2015 

2030 

14.5 

12.9 

Ulti-
mate 
12.8 

2015 

2030 

132 

127 

Ulti-
mate 
126 

Ulti-
mate 
119 

Ulti-
mate 
128 

January 2018  I  118 

 
 
 
Sectoral integration: long-term perspective in the EU energy system 

GETTING IN TOUCH WITH THE EU 

In person 

All over the European Union there are hundreds of Europe Direct information centres. 
You can find the address of the centre nearest you at: https://europa.eu/european-
union/contact_en 

On the phone or by email 

Europe Direct is a service that answers your questions about the European Union. You 
can contact this service: 

– by freephone: 00 800 6 7 8 9 10 11 (certain operators may charge for these calls), 

– at the following standard number: +32 22999696 or  

– by email via: https://europa.eu/european-union/contact_en 

FINDING INFORMATION ABOUT THE EU 

Online 

Information about the European Union in all the official languages of the EU is 
available on the Europa website at: https://europa.eu/european-union/index_en 

EU publications 

You can download or order free and priced EU publications at: 
https://publications.europa.eu/en/publications. Multiple copies of free publications 
may be obtained by contacting Europe Direct or your local information centre (see 
https://europa.eu/european-union/contact_en). 

EU law and related documents 

For access to legal information from the EU, including all EU law since 1952 in all the 
official language versions, go to EUR-Lex at: http://eur-lex.europa.eu 

Open data from the EU 

The EU Open Data Portal (http://data.europa.eu/euodp/en) provides access to 
datasets from the EU. Data can be downloaded and reused for free, for both 
commercial and non-commercial purposes. 

January 2018  I  119