COMMISSION STAFF WORKING DOCUMENT Technology Assessment Accompanying the document COMMUNICATION FROM THE COMMISSION TO THE EUROPEAN PARLIAMENT, THE COUNCIL, THE EUROPEAN ECONOMIC AND SOCIAL COMMITTEE AND THE COMMITTEE OF THE REGIONS Energy Technologies and Innovation
Date: 2013-05-02
Institutions: European Commission
Subjects: clean technology, development plan, electrical energy, energy market, energy technology, hard energy, innovation, new technology, nuclear energy, soft energy

EUROPEAN 
COMMISSION 

Brussels, 2.5.2013  
SWD(2013) 158 final 

COMMISSION STAFF WORKING DOCUMENT 

Technology Assessment  

Accompanying the document 

COMMUNICATION FROM THE COMMISSION TO THE EUROPEAN 
PARLIAMENT, THE COUNCIL, THE EUROPEAN ECONOMIC AND SOCIAL 
COMMITTEE AND THE COMMITTEE OF THE REGIONS 

Energy Technologies and Innovation 

{COM(2013) 253 final} 
{SWD(2013) 157 final} 

EN 

   EN 

 
 
 
 
  
 
 
Energy technology developments beyond 2020 for the transition to a decarbonised 

European energy system by 2050 

Table of Contents 

1. 

2. 

3. 

4. 

5. 

6. 

7. 

8. 

9. 

10. 

11. 

12. 

13. 

14. 

15. 

16. 

Introduction .................................................................................................................. 2 

Setting the Scene: energy technologies in 2030........................................................... 4 

Photovoltaic Solar Electricity ...................................................................................... 8 

Concentrated Solar Power Generation ....................................................................... 12 

Wind Energy .............................................................................................................. 16 

Biomass / waste Power Generation............................................................................ 21 

Carbon capture and storage........................................................................................ 27 

Nuclear Fission Energy .............................................................................................. 32 

Advanced Fossil Fuel Technologies .......................................................................... 36 

Marine (Wave & Tidal) Energy ................................................................................. 41 

Fuel Cells and Hydrogen............................................................................................ 45 

Electricity Storage Technologies ............................................................................... 51 

Electricity Networks Technologies ............................................................................ 56 

Energy intensive industries ........................................................................................ 60 

Buildings and Energy................................................................................................. 67 

Smart Cities and Communities................................................................................... 70 

1 

 
 
 
 
1. 

INTRODUCTION 

Continuous innovation on energy technologies is a prerequisite for Europe to achieve its long 
term  sustainability  goals,  such  as  the  decarbonisation  of  the  society  and  economic  growth. 
This was already recognised in 2006, when the European Commission proposed a European 
Strategic  Energy  Technology  Plan  (SET-Plan),  aimed  at  accelerating  the  large  scale 
deployment  of  selected  low  carbon  energy  technologies  by  intensifying  research  and 
development  (R&D)  and  demonstration  activities,  which  in  turn  would  advance  their 
commercialisation.  The  ultimate  benefits  include  reduction  of  greenhouse  gas  emissions, 
improvement  of  the  security  of  energy  supply,  development  of  technology  export 
opportunities and hence economic growth and new highly-skilled jobs. 

The  SET-Plan  in  its  current  form  targets  the  2020  energy  policy  goals.  The  current  need  to 
prepare for the 2050 vision creates an impetus to plan energy technology development beyond 
2020.  This  goes  hand-in-hand  with  a  long-term  vision  for  the  financial  and  organisational 
framework for energy technology R&D and demonstration. The need to intensify coordinated 
activities  at  European  level  has  become  even  more  important  against  the  backdrop  of  the 
financial crisis. 

This report presents the potential cost-effectiveness and scale of deployment of a portfolio of 
energy technologies. It examines their possible roles in the post-2020 European energy system 
as foreseen in the Energy Roadmap 2050, drawing on data from the European Commission’s 
Strategic Energy technologies Information System (SETIS). Particular attention is given to: 

• 

• 

the longer-term evolution of cost and performance of energy technologies 

technological bottlenecks and other barriers to cost-reduction and commercialisation, and, 

•  R&D and demonstration priorities for exploiting the full potential for each technology. 

This report demonstrates that focused R&D and demonstration can help reducing significantly 
the  cost  of  low  carbon  energy  technologies,  up  to  30-80%  from  current  levels  by  2050,  see 
Figure 1.1. This in turn will have a large positive impact on the cost of energy in Europe, and 
hence on the quality of life and industrial competitiveness. 

(a) 

2 

 
 
 
Figure 1.1. Capital cost reductions for selected energy technologies: (a) in absolute values, (b) 
relative reductions from 2010 cost levels. Source: JRC-SETIS analysis 

(b) 

3 

 
 
2. 

SETTING THE SCENE: ENERGY TECHNOLOGIES BEYOND 2020 

2.1. 

Evolution of Europe's energy system 

The EU objective of reducing domestic greenhouse gas emissions by 80-95% by 2050 requires a 
major transformation of the European energy system. The power sector in particular needs structural 
change: according to the decarbonisation scenarios of the Energy Roadmap 2050, it needs to achieve 
significant reductions in greenhouse gas emissions already in 2030 (57-65%) and to reach near-
complete decarbonisation by 2050 (96-99%). The projected structure of the energy system for two of 
the scenarios is shown in Figure 2.1. 

Net generation capacity for 2 scenarios of the "Energy Roadmap 2050"

e

W
G

1800
1600
1400
1200
1000
800
600
400
200
0

Ref 2010

Ref 2030

Ref 2050

DST 2010

DST 2030

DST 2050

RES

Nuclear

CCS

Fossil

Figure 2.1. Evolution of net electricity capacity in the EU between 2010 and 2050 according to two 
scenarios from the Energy Roadmap 2050: the Reference (Ref) and the ‘Diversified Supply 
Technologies’ (DST) scenarios 

In both the ‘Reference’ and the ‘Diversified Supply Technologies’ (DST) scenarios1, electrification of 
the energy system is a major trend, resulting in much larger electricity generation capacities by 2030 
and 2050 compared to today. Fossil-fuel capacity without carbon capture is slowly phased out and 
growth at the 2030 horizon is concentrated in solar, biomass/waste and wind and some other 
renewable energy sources (RES). By 2050 there is also a substantial role for carbon capture and 
storage (CCS).  

1  The  analysis  herein  builds  upon  two  of  the  scenarios  of  the  2050  Energy  Roadmap:  the  Reference  scenario, 
which reflects a business-as-usual trajectory for the energy system and  the DST scenario, which is the 
most technology-neutral amongst the decarbonisation scenarios considered in the Roadmap,  

4 

 
 
 
 
 
                                                            
2.2. 

The need for innovation in energy technologies 

The large-scale deployment of low-carbon energy technologies beyond 2020, as needed for meeting 
the vision for decarbonisation by 2050 requires that the costs of these technologies decrease 
substantially compared to the current levels. This requires large-scale innovation in low-carbon 
technologies as well as removal of non-technological barriers. 

Of all the technologies addressed by the SET-Plan only wind and solar power in favourable locations 
can currently compete in the market without some form of economic incentive for power generation 
or grid access. This implies that substantial innovation and therefore investment to trigger and 
sustain it will be needed to reduce costs and realise the economics of scale associated with large 
scale deployment. The challenges however differ from technology to technology: the need for 
innovation is more critical when large-scale deployment of that technology is foreseen (and/or 
targeted). In addition, the need for innovation is also higher if the potential for future cost reductions 
of that technology is large.  

This is illustrated herein using the results from the DST scenario of the Energy Roadmap and in 
particular the needs for investment in new capacities per technology, although similar conclusions 
can be drawn if other decarbonisation scenarios were considered. Preliminary calculations show that 
the total undiscounted cost savings could reach 350 billion euro during the period 2010 – 2050, once 
the capital cost reductions estimated in this report are realised, as a result of research & innovation 
and market measures. More than half of these savings will be realised after 2020. Most of these 
savings will come from initiatives in the wind and solar energies, followed by nuclear energy, CCS, 
bioenergy and marine energy. It is noted that no significant cost savings are expected from the 
conventional fossil fuel sector, although research & innovation are required to continuously improve 
environmental and operational performance. These results are summarised in Figure 2.2. 

5 

 
 
 
(a) 

(b) 

Figure 2.2. Reduction of capital costs of power generation technologies in absolute (a) and relative 
(b) terms. The size of ‘bubbles’ indicate the savings achieved by the reduction of capital costs of each 
technology per decade, demonstrating the impact of research, development and innovation in 
energy on the capital investments for the development of a decarbonised energy system. 

Energy technology policy in the EU should therefore address a broad portfolio of technologies: 

– 

Solar,  which  is  deployed  at  very  large  scale  and  has  the  potential  for  a  large  cost 

decrease; 

–  Wind, which is also deployed at very large scale, and requires a continuation of ongoing 

innovation, especially offshore; 

–  Biomass / waste, which requires innovation in order to sustain deployment throughout 

the 2010-2050 period; 

–  CCS,  which  will  be  deployed  mostly  after  2030,  but  requires  innovation  also  before 

2030 in order to make the technology ready for the market; 

–  Nuclear,  which  continues  to  play  a  role  due  to  large  replacement  investments  both 

before and after 2030; 

–  Advanced fossil fuel technologies, due to their bridging role up to the 2050 horizon; 

–  Marine energy, which will be deployed at smaller scale than wind or solar, but require 
large  cost  reductions  to  improve  competitiveness  in  order  to  harvest  the  enormous 
marine energy potential. 

6 

 
 
  
–  Energy  efficiency  technologies  for  both  the  domestic/tertiary  and  industrial  sectors, 

which are crucial for reducing the European needs for energy 

– 

System  enabling  technologies,  such  as  electricity  networks  and  electricity  storage 
technologies, which will facilitate the large scale deployment of RES technologies 

The  following  chapters  discuss  these  technologies  in  detail,  in  particular  with  regard  to  the 
research, development and demonstration/deployment (RD&D) actions that need to be taken 
to  shape  the  post-2020  European  energy  system  in  line  with  the  2050  vision  for  a 
decarbonised economy. 

7 

 
3. 

PHOTOVOLTAIC SOLAR ELECTRICITY 

3.1.  Market evolution  

Photovoltaic (PV) power generation capacity has grown rapidly over the last ten years and at 
the end of 2012 the cumulative installed PV capacity worldwide exceeded 100 GW. The EU 
has played a key role in this development with a cumulative installed capacity of 69 GW. As 
shown  in  Fig.  3.1,  this  growth  considerably  exceeds  the  trend  foreseen  in  the  national 
renewable action plans (NREAPa) and in the scenarios used for the Energy Roadmap 2050. 
The industry's baseline scenario now forecasts 333 GW by 20302, well above that predicted in 
the 2050 Energy Roadmap "high RES" scenario. It is clear that there are huge opportunities 
for  photovoltaics  in  the  future,  accompanied  by  substantial  evolution  of  the  product,  the 
power distribution system itself and the market. PV technology and its deployment is a now 
global business with both high innovation and market turnover. Since 2009, China (including 
Taiwan) is leading production, now providing about 70% of PV modules for the world-wide 
market, closely followed by Europe. Japan and USA are catching up. At the same time R&D 
in  all  parts  of  the  world  is  increasing,  focussing  on  reducing  costs,  increasing  conversion 
efficiency and improving large-scale manufacturing processes.  

Fig  3.1 Scenarios for the future growth of PV generation capacity in the EU 

3.2. 

Technology needs 

To improve the cost structure and cost competitiveness of the European PV industry, research along 
the whole value chain from raw material processing, cell and module manufacturing to power 
electronics and system integration including local storage options is required. Besides the 
improvements of solar cells and modules, innovation in the "upstream industry" (e.g. materials, 
polysilicon production, equipment manufacturing), as well as the downstream industry (e.g. 
inverters, BOS components, system development, installations and integration into the existing or 

2 EPIA, Connecting the Sun, 2012. 

8 

 
 
 
 
                                                            
future electricity infrastructure) in required to enable PV technology to contribute as a major 
electricity source in the future. 

Research in photovoltaic devices over the last few years has seen major advances in efficiency, 
reliability and reproducibility, but it is clear that there is the potential for further progress, both in 
terms of existing device structures and in relation to new device topologies. Key to those advances is 
an understanding of material properties and fabrication processes. Research is required for specific 
aspects of device design and fabrication, together with consideration of the new production 
equipment necessary to transfer these results into the fabrication processes. In parallel, advances in 
the system architecture and operation will allow the increases in cell efficiency to be reflected in the 
energy output of the system. Innovative manufacturing technologies for PV electricity fall under the 
headings of:  

1)  Printed  Solar  Cells:  Further  cost  reduction  in  solar  cell  manufacturing  needs  new  and 
innovative  technologies,  which  offer  the  possibility  to 
lower  capital  costs  of  new 
manufacturing  plants,  increase  throughput  and  yield  and  provide  flexible  design  options  to 
create new products for the building industry in Europe. Such production technologies also 
offer substantial reductions in energy payback time, reinforcing the industry's credentials as 
an  environmentally  sustainable  electricity  source.  The  leading  role  of  Europe  in  PV 
technology  development,  nanotechnology  and  manufacturing  systems  engineering  offers  a 
unique opportunity to lead innovation in the PV industry and to regain European leadership 
in high value, customer adapted PV component manufacturing.  

2)  PV  modules  as  building  materials:  Building  markets  are  dominated  by  local  regulations  and 
building  codes,  but  the  building  material  market  can  develop  to  a  world-wide  market  with 
huge opportunities for the European industry. The development of PV modules as a standard 
building  material  for  roof  or  wall  elements  needs  a  multidisciplinary  research  and 
development programme involving the PV manufacturing, the building materials industry as 
well as certification bodies.  

3)  Buildings  as  smart  grid  elements:  The  combination  of  localised  PV  electricity,  storage  and 
local supply and demand management makes buildings the smallest independent unit which 
need  a  smart  grid.  Once  the  necessary  technology  and  control  mechanisms  are  developed, 
the  step  of  linking  multiple  smart  buildings  could  lead  to  a  widespread  deployment  of  the 
smart grid technology. If Europe were to develop such an innovative concept, it could take 
the industrial leadership for driving the development and industrialisation of this technology.  

Besides fostering such innovation in the longer term, European PV research should help the existing 
industry to stay at the cutting edge of a wide range of technologies in commercial production and in 
the laboratory. No clear technological “winners” can yet be identified, as reflected by the 
investments being made worldwide in production capacity for many different technologies, and in 
the numerous concepts with large commercial potential being developed in laboratories. Therefore, 
it is important to support the development of a broad portfolio of options rather than a limited set. 
Common topics for all this research needs can be summarised as: 

1)  Efficiency,  energy  yield,  stability  and  lifetime:  Since  research  is  primarily  aimed  at  reducing 
the  cost  of  PV  electricity  it  is  important  not  to  focus  solely  on  initial  capital  investments 
(€/Wp), but on the energy yield (kWh/Wp) over the economic or technical lifetime.  

2)  High productivity manufacturing, including in-process monitoring & control: Throughput and 
yield are important parameters in low-cost manufacturing and essential to achieve the cost 
targets.  

9 

 
3)  Environmental  sustainability:  The  energy  and  materials  requirements  in  manufacturing  as 
well  as  the  possibilities  for  recycling  are  important  for  the  overall  environmental  quality  of 
the product.  

4)  Applicability:  Moving  towards  the  standardisation  and  harmonisation  in  the  physical, 
mechanical and electrical characteristics of PV modules can contribute to reducing the costs 
of  installation.  Ease  of  installation  and  the  aesthetic  quality  of  modules  (and  systems)  are 
important if they are to be used on a large scale in the built environment.  

3.3. 

Cost reductions  

Over the last two decades PV system prices have decreased all over the world, significantly 
driven  by  technology  and  market  developments  (Fig.  3.2).  The  change  of  the  market  from 
supply  restricted  to  demand-driven,  and  the  resulting  overcapacity  for  solar  modules  has 
resulted  in  a  dramatic  price  reduction  of  PV  systems  of  more  than  50%  over  the  last  four 
years. In the fourth quarter of 2012, the average system price for systems smaller 10 kWp was 
in the range of 1.75 €/Wp in Germany and 2.10 
€/Wp in Italy. Quotes for large systems are 
already much lower, with turnkey system prices of 1€/Wp reported for projects to be finished 
in  20133.  These  developments  suggest  that  the  PV  Technology  Platform's  strategic  research 
agenda's  target  for  2030  of  1  €/kW  for  turnkey  100  kW  system  (in  2011  euro,  excluding 
VAT)  may  well  be  a  reality  already  by  2020.  Long  term  potential  for  substantial  further 
reductions  remains,  as  indicated  by  Fig.  3.2,  showing  capital  cost  trends.  In  this  respect,  it 
should  be  borne  in  mind  that  future  PV  systems  are  likely  to  be  highly  sophisticated  and 
multi-functional,  integrating  storage  capabilities  with  a  sophisticated  interface  to  the  grid. 
Electrical  batteries  are  becoming  increasingly  interesting,  especially  for  small-scale  storage 
solutions in the low-voltage distribution grid. Net electricity system prices should fall to 0.046 
€/kWh in 2020. With levelised costs of electri city (LCOE) from PV systems moving below 
0.10 €/kWh in the near future, the additional stor age cost already makes sense in markets with 
high peak costs in the evening, where only a shift of a few hours is required. 

Fig. 3.2 Capital cost trends for PV systems. 

3 Bloomberg New Energy Finance, PV Market Outlook Q3 2012, 7 August 2012 

10 

 
 
 
 
                                                            
3.4. 

Soft measures influencing deployment 

After the massive cost reductions for the technical components of PV systems like modules, inverters 
BOS, etc., the next challenge is to lower the soft costs of PV system installations, like the permitting 
or financing costs. Despite the fact that PV system components are world-wide commodity products, 
the actual price for installed PV systems differs significantly (Fig. 3.3). The reason for these 
differences are manifold and vary from different legal requirements for permitting, licensing and 
connection to the grid to the different levels of maturity of the local PV market with impacts on 
competition between system developers and installers. A convergence of PV system prices in Europe 
is happening fast and it can be expected that this will open new opportunities for PV generated 
electricity to increase its share in European electricity generation. 

Fig.3.3: Variation of PV system prices in 2011 (source IRENA)4 

4 IRENA, 2012, RENEWABLE ENERGY TECHNOLOGIES: COST ANALYSIS SERIES, Volume 1, Power 

Sector, Vol4/5, Solar Photovoltaics. 

11 

 
 
 
 
 
 
 
                                                            
4. 

CONCENTRATED SOLAR POWER GENERATION 

4.1.  Market evolution 

Between  1985  and  1991,  the  Solar  Energy  Generating  Systems  (SEGS)  I  through  IX 
(parabolic trough), with a total capacity of 354 MW5, were built in the Mohave Desert, USA. 
After  more  than  15  years,  the  first  new  major  capacities  of  concentrated  solar  power  (CSP) 
Plants came online with Nevada One (64 MW, USA) and the PS 10 plants (11 MW, Spain) in 
the first half of 2007.  

At the end of January 2013, CSP plants with a cumulative capacity of about 1.9 GW were in 
commercial operation in Spain, which corresponds to about 69% of the worldwide capacity of 
2.74 GW. Together with those plants under construction and those already registered for the 
feed-in tariff this should bring Spain's CSP capacity to about 2.5 GW by the end of 2013. This 
capacity is equal to 60 plants which are eligible for the feed-in tariff. In total, projects with a 
total capacity of 15 GW have applied for interconnection. This is in line with the European 
solar  industry  initiative,  which  aims  at  a  cumulative  installed  CSP  capacity  of  30  GW  in 
Europe, out of which 19 GW would be in Spain.  

In  the  USA  more  than  4.5 GW  of  CSP  are  currently  under  power  purchase  agreement 
contracts,  which  specify  when  the  projects  have  to  start  delivering  electricity  between  2010 
and 2014. More than 100 projects are currently in the planning phase mainly in Spain, North 
Africa,  India  and  the  USA.  In  December  2009,  the  World  Bank's  Clean  Technology  Fund 
(CTF)  Trust  Fund  Committee  endorsed  a  CTD  resource  envelope  for  projects  and 
programmes  in  five  countries  in  the  Middle  East  and  North  Africa  to  install  more  than 
1.1 GW of CSP by 2020.  

4.2. 

Technology needs 

Increased R&D efforts and strategic alignment of national and EU programmes are necessary 
to realise all the potential embedded in technology innovation. Demonstrating next generation 
CSP  technologies  is  critical  to  address  medium-  to  long-term  competitiveness.  The 
implementation  plan  of  the  Solar  Europe  Industry  Initiative  (SEII)  describes  the  strategic 
RD&D components to boost innovation and reach competitive levels in the energy market.  

Despite entering a commercial ramp-up phase, CSP technology is still in a development stage, 
displaying high potential for technical improvements. The industry is already focused on the 
R&D of the next stage of technology improvements, which shall have great impact on costs 
and efficiency of CSP plants. These improvements, which can be either technology specific or 
horizontal to most technologies, are centred on three main areas:  

• 

Increase power generation efficiency, mainly through the rise of the operating temperature 
leading to higher turbine efficiency, but also through improvements in reflecting facets6 and 
receivers 

•  Reduce solar field costs by minimizing costs and through design optimization that can lead to 

more cost effective solar fields deployment 

•  Reduce  internal  resource  consumption  through  reduction  of  needed  water  and  auxiliary 

parasitic consumption7 

5 The capacity figures given are MWel (electric) not MWth (thermal) 
6 Mirror’s capacity to reflect sun radiation 
7  Plant  operations  require  consumption  of  electricity  (e.g.  to  pump  fluids).  This  type  of  consumption  is  called 
parasitic consumption 

12 

 
 
                                                            
Key components to reduce the solar field cost are support structures, including foundations, 
mirrors  and  receivers.  These  costs  will  tend  to  decline  over  time  as  the  overall  volume 
increases.  For  the  support  structures,  developers  are  looking  at  reducing  the  amount  of 
material  and  labour  necessary  to  provide  accurate  optical  performance8  and  to  meet  the 
designed  “survival  wind  speed”.  Given  that  the  support  structure  and  foundation  can  cost 
twice as much as the mirrors themselves, improvements here are very important.  

For mirrors, cost reductions may be accomplished by moving from heavy silver-backed glass 
mirror  reflectors  to  lightweight  front-surface  advanced  reflectors  (e.g.  flexible  aluminium 
sheets  with  a  silver  covering  and  silvered  polymer  thin  film)9.  The  advantages  of  thin-film 
reflectors  are  that  they  are  potentially  less  expensive,  will  be  lighter  in  weight  and  have  a 
higher  reflectance.  They  can  also  be  used  as  part  of  the  support  structure.  However,  their 
long-term performance needs to be proven. Ensuring that the surface is resistant to repeated 
washing  will  require  attention.  In  addition  to  these  new  reflectors,  there  is  also  work 
underway to produce thinner, lighter glass mirrors.  

Currently  operating  parabolic  trough  plants  use  a  synthetic  aromatic  fluid  (SAF)  as  heat 
transfer  fluid.  This  fluid  is  organic  (benzene)  based  and  as  such  cannot  reach  temperatures 
above  400ºC  with  acceptable  performance  due  to  its  decomposition  at  higher  temperatures. 
This  limited  temperature  range  is  capping  overall  steam  cycle  efficiency.  To  overcome  this 
obstacle, developers are focusing on the development of alternative fluid technology, namely: 
molten  salt,  direct  steam  generation,  nanotechnology  improved  fluids  and  alternative 
inorganic fluids.  

Today’s state-of-the-art thermal energy storage solution for CSP plants is a two-tank molten 
salt  thermal  energy  storage  system.  The  salt  itself  is  the  most  expensive  component  and 
typically accounts for around half of the storage system cost, while the two tanks account for 
around  a  quarter  of  the  cost.  Improving  the  performance  of  the  thermal  energy  system,  its 
durability and increasing the storage temperature hot/cold differential will bring down costs. 
For solar towers, increasing the hot temperature of the molten salt storage system should be 
possible  (up  to  650°C  from  around  560°C),  but  will  require  improvements  in  design  and 
materials  used.  The  development  of  heat  transfer  fluids  that  could  support  even  higher 
temperatures would reduce storage costs even further and allow even higher efficiency, but it 
remains  to  be  seen  if  this  can  be  achieved  at  reasonable  cost.  If  direct  steam  towers  are 
developed,  current  storage  solutions  will  need  to  be  adapted,  if  the  capacity  factor  is  to  be 
increased and some schedulable generation made available.  

4.3. 

Cost reduction 

The current CSP market is dominated by the parabolic trough technology. More than 80% of 
the CSP power plants in operation or under construction are based on this technology. As a 
consequence, most of the available cost information refers to parabolic trough systems. The 
cost data for parabolic trough systems are also the most reliable, although uncertainties still 
remain, because it is the most mature CSP technology.  

8 Flexing of the support structures in windy conditions can have a negative impact on the concentration of 
sunlight on the receivers. 
9 Silver-backed glass mirrors are highly specular, that is to say they concentrate the sun’s rays into a narrow cone 
to intersect the receiver. Any new reflector solutions need to also be highly specula. 

13 

 
 
 
                                                            
The  current  investment  cost  for  parabolic  trough  and  solar  tower  plants  without  storage  are 
between 3500 €/kW and 5500 €/kW 10. Fig. 4.1 illustrates the development of the capital cost 
experience  curve  to  date,  while  Fig.  4.2  shows  the  future  trend.  CSP  plants  with  thermal 
energy storage tend to be significantly more expensive, but allow higher capacity factors, the 
shifting  of  generation  to  when  the  sun  does  not  shine  and/or  the  ability  to  maximise 
generation at peak demand times.  

Fig. 1: CSP historical cost data, cumulative capacity growth and experience curve (Source IRENA) 

W
k
/
)
0
1
0
2
€(

X
E
P
A
C

6,000

5,000

4,000

3,000

2,000

1,000

0

2010

2020

2030

Year

2040

2050

Fig 2: Capital cost estimates to 2050 for concentrated solar power plants. 

10 Source: IRENA, 2012, RENEWABLE ENERGY TECHNOLOGIES: COST ANALYSIS SERIES, Volume 1, 

Power Sector, Vol4/5,  CSP 

14 

 
 
 
 
 
                                                            
4.4. 

Soft measures influencing deployment 

The cost-competitiveness of CSP plants is a key barrier. There is a strong need for developing 
long  term  policy  frameworks  to  foster  and  secure  CSP  technology  developments  and 
investments worldwide. On the technology front, component improvements and scaling-up of 
first  generation  technologies  are  necessary  for  cost  reduction.  The  demonstration  of  new 
technologies at system level and relevant scale is also crucial for CSP cost-competitiveness on 
the  long  term.  However,  these  R&D  and  innovation  activities  are  not  covered  by  industrial 
and private funds. As a result, there is a current shortage of equity capacity. This situation is 
also  relevant  for  today's  technology.  The  necessary  work  on  critical  elements  for  first 
generation  technologies  such  as  adjustment  of  steam  turbine  to  CSP  specification  is  not 
performed  today.  Reaching  a  critical  mass  among  players  is  an  essential  ingredient.  Yet,  a 
structuring of the CSP industry as well as an expertise broadening is on-going, but it is still in 
its  infancy.  Finally,  the  development  of  specific  enabling  technologies,  for  example,  grid 
infrastructure  for  importing  CSP  energy  from  neighbouring  countries,  is  an  important  focus 
for the sector developments. Hydrogen production is a potential industrial field for synergies 
with CSP technologies. Although these concepts are at an R&D phase, current developments 
on the heliostat or other heat transfer components will certainly benefit this field. In the short 
term,  shared  developments  can  be  envisaged  with  concentrated  photovoltaics  as  their 
concentrators  respond  to  the  same  kind  of  usage.  Other  areas  of  developments  besides 
electricity production are district cooling and water desalinisation.  

15 

 
 
5. 

WIND ENERGY 

5.1. 

Technological evolution 

Wind power is a mature technology in that it already contributes with a significant share in the 
European energy generation: there are 106 GW of wind capacity installed at the end of 2012 
generating 210 TWh during an average year, or 6.5% of the European total11. However, the 
technology is still improving and costs will decrease –especially in offshore applications. 

Global installations grew in 2012 by 12% to 45.5 GW, up from 40.5 GW in 2011, and reached 285 GW. 
The Chinese market shrank for the first time (from about 18 GW in 2010/11 to 14 GW annually), the 
Spanish market consolidated its reduction, the German market improved and the US market 
boomed. The new installations in the UK reached 1.9 GW of which nearly 1 GW was offshore About 
1 GW was installed in the (so considered) emerging markets of Sweden, Poland, Romania, Brazil, 
Canada and Mexico. In Europe, markets that performed better than their historical averages include 
Italy (1.3 GW), Austria and Belgium (300 MW each), Norway and Ukraine. Outside Europe, there was 
a remarkable capacity growth in India (2.3 GW). 

Wind is mostly a global market with a strong local influence: evidence suggests that the turbine 
manufacturer ranking depends strongly on how their home market performs. For example, in 2012 
none of the Chinese manufacturers nor Gamesa (ES) were in the top-5: Instead, General Electric (US) 
topped a list where Siemens and Enercon (DE) and Suzlon (IN/DE) climbed as well. Most European 
manufacturers and GE cover different world markets whereas Chinese ones only recently started 
expanding overseas, with support of the European technology of the companies that they bought, or 
that they licensed. 

2500

2000

1500

1000

500

0

2012 and projected cumultative installed capacity (GW)

Offshore

Onshore

5,4

278

11

134

5,0
101

13

399

33

182

50

665

118

232

250

1215

550

1940

228

272

EU

Global

EU

Global

EU

Global

EU

Global

EU

Global

2012

2015

2020

2030

2050

Figure  5.1:  Projections  of  installed  capacity  to  2050,  onshore  and  offshore,  for  the  EU  and 
globally. Source: JRC analysis. 

11 JRC calculations based on a 23% capacity factor, which is the 2011 average figure for Europe  

16 

 
 
 
 
                                                            
New European installations are slightly growing at a steady pace. In the last four years between 9.5 
and 11.5 GW of wind was added per year, mainly in Germany, in emerging markets and the offshore 
sector. Figure 5.1 shows current installed capacity and projections for the EU and the world. This 
scenario is broadly similar to the energy efficiency scenario of the Energy Roadmap 2050, and it 
differs in that it takes into account the delays to grid extensions that have surfaced recently and 
which will affect connection of offshore wind farms during the current decade. 

5.2. 

Technology needs 12 

Wind turbines are evolving towards larger rotors, taller towers, lighter nacelles, and more reliable 
components requiring less maintenance. This evolution requires trade-offs: for example blades are 
becoming larger and heavier in the quest for larger rotors, but they must become lighter (per unit of 
length or rotor are) in order for rotors to grow more. The end goal is the reduction in the cost of 
energy from wind. 

Wind power actual (2002-11) and projected capacity factor (EU-27)

)

%

(

r
o
t
c
a
f

y
t
i
c
a
p
a
C

40%

35%

30%

25%

20%

15%

20.5%

19.7%

22.87%

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2015

2020

2025

2030

2035

2040

2045

2050

CF plus projection

CF - weighted average 2002-11

CF + offshore factor

Figure 5.2: Evolution of capacity factors (CF) of the European wind turbine fleet 2002-2011, 
and projections to 2050. Source: JRC analysis based on data from Eurostat 

Wind farms have to improve their efficiency of energy capture, and this is reflected on their capacity 
factors. Figure 5.2 shows that the actual capacity factor of the EU wind power fleet had an upward 
trend from 2002 to 2011. This trend will continue to 2050 (blue line). In addition, the brown dotted 
line takes into account the increased share of offshore installations in the future European fleet. 
Evidence from Danish offshore wind farms shows capacity factors in the range of 40 – 50%, which are 
significantly higher than the EU average. 

Technological needs include: 

12  Some  of  the  technologies  currently  in  the early  stages of  development  such  as  kites,  those undergoing  slow 
proof of concept (e.g. vertical-axis wind turbines), or not even thought of nowadays, could become mainstream 
in  the  2030-2050  period.  However,  given  the  uncertainties  in  their  success  of  commercialisation,  these 
technologies have not been considered in this report. 

17 

 
 
 
 
 
                                                            
 
 
Materials13 

•  Development of superconducting materials to enable their use in electricity generators. 

•  New blade materials that, at affordable cost, are stiffer but lighter, resist fatigue better and are 

recyclable. 

•  Blade  coatings  that  decrease  sand  and  water  droplet  erosion  and  increase  UV  light  resistance, 

with self cleaning capability and ice shedding efficiency. 

•  For towers and foundations, high-strength steels of heavy gauge (thickness above 30mm), with 
superior  toughness  suited  for  welding  technology  and  sustain  high  loads,  at  more  affordable 
price levels. 

•  Also  for  towers,  specialised  pre-stressed  concrete  and  innovative,  better-performance  mortars 
that can be worked out at a large range of temperatures, very liquid but of quick hardening and, 
overall, high strength and with other improved specifications. 

•  Better performing magnets in particular at higher operating temperatures, with higher magnetic 

power and less use of rare earths. 

•  High-temperature superconducting (HTS) wire and the corresponding cryogenic materials. 

•  Silicon carbide (SiC) as a much (energy-) denser base material for power electronics components 

should reach commercialisation at a reasonable cost. 

Models 

•  Better  knowledge  of  loads,  load  effects,  and  electrical  effects  in  the  electrical  and  mechanical 

parts of the turbine. Separation of load from torque. Appropriate load models. 

•  Micro-  and  meso-mechanic  modelling  on 

fibre/interface  and  on  fibre  arrangements; 
phenomenological and analytical material models based on damage mechanics to include effects 
of manufacturing defects and fatigue damage on the complex stress states notably in blades. 

Components 

•  New sensors to support non-destructive condition monitoring. 

• 

Innovative  offshore  foundations  that  reduce  costs  of  both  manufacturing  and  installation.  This 
should  be  treated  in  a  holistic  way  that  includes  foundation  and  turbine  installation  and  the 
vessels needed for it. 

•  Substation  connections:  switchgear,  transformers,  cables,  circuit  breakers,  etc.,  for  DC 

substations and for 66 kV AC inter-array cabling. 

•  SiC switches (IGBTs, thyristors) up to 15 kV. 

Processes 

•  Manufacture facilities for larger forgings. 

•  Design for manufacture, transport and installation; and for turbine assembly. 

• 

Increase series manufacturing, including automation of manufacturing processes esp. for blades. 

•  New recycling processes for blade materials at affordable costs. 

•  Automatic or robotised gas-metal arc welding procedures. 

13  For  more  information:  Scientific  Assessment  in  support  of  the  Materials  Roadmap  enabling  Low  Carbon 
Energy Technologies. Joint Research Centre, European Commission, ISBN 978-92-79-22936-7, 2012. 

18 

 
                                                            
•  Foundry technology for dross-free ductile iron with higher strength and very high wall thickness. 

•  New  surface  treatments  such  as  PVD  coatings,  nitriding  treatments  and  laser  treatment  to 

improve gear teeth properties. 

Offshore wind is at a stage to strongly benefit from learning-by-doing. Support should include first-
of-a-kind sub-structures (foundations) and new cable installations processes, as well as support for 
the two-four subsequent installations. 

5.3. 

Cost reductions 

As any mature technology, the evolution of capital cost in wind installations depends on the market 
forces more than on technological evolution. Still, in particular for offshore wind, innovation-based 
cost reductions will have a significant impact in global cost reductions. 

Estimated capital cost evolution (€/kW)

5000

4500

4000

3500

3000

2500

2000

1500

1000

500

0

5000

4500

3500

2400

2000

1580

920

2900

2200

2000

1400

870

3800

2600

1900

1800

1300

840

3500

2400

1800

1700

1200

800

3300

2300
1700

1600

1100
770

2010

2020

2030

2040

2050

Onshore, 
medium

Onshore, 
high

Onshore, 
low

Offshore, 
low

Offshore, 
medium

Offshore, 
high

Figure  5.3:  Expected  evolution  of  capital  cost  for  new  wind  power  installations,  for  low, 
medium and high cost ranges. Source: JRC estimates. 

Figure 5.3 shows the expected evolution of capital costs, offshore and onshore, according to the 
JRC14. The base onshore low figure corresponds to an average of countries with traditional low prices 
such as China and India; onshore high estimates are based on an average of high-cost countries such 
as Japan and Canada; finally, the onshore medium figure and estimated are based on the average of 
project costs reported to IEAWind, plus figures for the UK from other sources. 

14 Onshore figures are based on prices reported by IEAWind members, on data from Bloomberg’s database, on 
other industry intelligence and on information collected from industry directly by the JRC 

19 

 
 
 
 
 
 
                                                            
5.4. 

Soft measures influencing deployment 

The application of the latest technological evolutions, providing the lowest cost, is sometimes 
restricted by local or country regulations, for example mandating shorter towers –which sometimes 
indirectly limit rotor size- in the building permit. Spatial planning authorities of the Member States 
could plan long-term, e.g. the ultimate practical potential for wind installations and, as a result, a 
reasonable deployment path. This would improve the processes of developing wind farms, which can 
currently take from one to ten years. National and regional authorities could also facilitate project 
planning. For example, for prospective offshore developments the authorities could, in agreement 
with developers, set up wind measurement equipment ahead of the consent process so that longer-
term data are available which reduce the uncertainty of energy production. With less uncertainty, 
developers can obtain better debt conditions and the most appropriate turbine and foundations. 

The reduction of risks and risk perception reduces LCoE without impacting public budgets. In effect, 
the interests borne by developers on capital cost borrowing are, in particular for offshore wind, 
strongly affected by the risk perception that lenders have of the regulatory framework. Where the 
perception is of regulatory insecurity, i.e. that the government can change the way wind electricity is 
paid for (e.g. feed-in-tariffs) retrospectively, lenders require higher interest rates and developers 
require higher returns on investment. 

As wind reaches competitiveness with fossil-fuel-produced electricity, the way wind electricity is paid 
for will need to be reviewed. Variable renewables, and in particular wind and solar, have the 
particularity that the more the resource is available the more they push down wholesale market 
prices. Windy/sunny days thus result in high wind/solar electricity produced and, if sold at the 
market price, developers fail to recover the investment. 

As variable renewables increase its penetration of the electricity mix there will be increasing pressure 
on their integration. The main options to smooth this integration are energy storage, improved 
interconnections, more flexible conventional power generation plants, and demand management 
through smart grids. All those options will need to be pursued in parallel because none of them is the 
perfect solution and because electricity systems are more robust when using a larger mix of both 
generation and grid management resources that include these. 

20 

 
 
6. 

BIOMASS / WASTE POWER GENERATION 

6.1. 

Technological evolution 

Biomass plays an important role in energy generation in the EU, with 7.7 % of the EU gross energy 
demand covered by biomass resources in 2010. The contribution of biomass was more than two 
thirds (68 %) of all renewable primary energy consumption in 2010 and is expected to reach about 57 
% of the renewable energy in 2020. Primary energy production from biomass reached 118 Mtoe in 
2010 and should increase to about 180 Mtoe in 2020, according to projections from the national 
renewable action plans (NREAPs). The total use of biomass is expected to rise significantly until 2050 
in the various scenarios of the Energy Roadmap 2050. The biomass use in the reference scenario 
should reach about 186 Mtoe in 2050. In the decarbonisation scenarios, biomass consumption 
should reach between 260 and 275 Mtoe in 2050, while in the high RES scenarios the biomass use 
amounts to around 320 Mtoe. The key issue for bioenergy development is related to the availability 
of biomass. About 236 Mtoe of sustainably produced biomass could be available in the EU in 2020 
and 295 Mtoe by 2030, according to the European Environment Agency, while, according to AEBIOM, 
the contribution of biomass could reach 220 Mtoe in 2020. The sustainable biomass potential was 
estimated by the Biomass Futures project at 375 Mtoe in 2020 and 353 Mtoe in 2030. The largest 
potential is in the agricultural residues (manure, straw and cutting and prunings from permanent 
crops), followed by forest biomass and waste.  

Bioenergy installed capacity in different scenarios in the EU

W
G

180

160

140

120

100

80

60

40

20

0

2010

2020

2030

2040

2050

Reference Scenario
Energy Efficiency
High Renewables
Low Nuclear

Current Policy Initiatives
Diversified Supply Technologies
Delayed CCS

Figure 6.1. Projections of the bioenergy installed plant capacity in the European Union 

Biomass electricity in the EU increased from 69 TWh in 2005 to 123 TWh in 2010 and is expected to 
reach 232 TWh in 2020. The contribution to electricity made by bioenergy will reach 19 % of RES 
electricity in 2020, according to the aggregated data of the NREAPs. The biomass electricity 
production should significantly grow to 360 TWh in 2050 in the reference scenario and to 460 – 494 
TWh in 2050 in decarbonisation scenarios. Biomass electricity contribution could rise from 2.6% 
share in power generation in 2005 and 3.7% in 2010 to 7.3% in 2050 in the reference scenario and 

21 

 
 
 
 
9.3-10.9% in decarbonisation scenarios. In the EU, the installed bioenergy power capacity in 2010 
was 29 GW. The installed bioenergy power capacity in EU is expected to reach 43 GW in 2020, see 
Figure 6.1. The installed biomass capacity increases significantly in all scenarios until 2050. Significant 
growth in biomass power capacity is expected to reach 87 GW in the reference scenario. The growth 
in biomass installed capacity is much higher in different decarbonisation scenarios, which should 
reach between 106 and 163 GW in 2050. This is an increase of 3 to 5 times the current (2010) 
biomass power generation capacity.  

Currently bioheat is the main bioenergy market, accounting for 73 Mtoe (75 % of the total 
bioenergy), more than 90% of renewable heating and 13.5 % of total heat generation in the EU in 
2010. Biomass will still have the major contribution with 81 % (90 Mtoe) for heating and cooling in 
2020. The contribution of biomass used in households is expected to have a moderate increase from 
27.0 Mtoe in 2005 to 35.0 Mtoe in 2020, accounting for about 38 % of the biomass used for heating. 
Direct use of biomass for heating, is expected to rise from approx. 13.5% in 2010 to approx. 33% in 
2050 in the High RES scenario. The share of renewables in transport is expected to reach 11% in 2020 
in all decarbonisation scenarios and it is expected to rise to 19-20% in 2030 and to 62-73% in 2050. 
Biofuel consumption rises from 3.1 Mtoe in 205 and 13 Mtoe in 2010 to reach about 18 Mtoe in 2030 
and 37-39 Mtoe in 2050 under current policies scenarios. Biofuels contribution to transport sector in 
decarbonisation scenarios, imply an increase to 25-36 Mtoe in 2030 and 68-72 Mtoe in 2050, with 
the highest levels being reached in the High RES and Diversified Supply Technology scenarios. 

6.2. 

Technology needs  

There are several biomass conversion technologies at different stages of development, based 
on  thermo-chemical  (combustion,  gasification  and  pyrolysis)  and  biochemical/biological 
(digestion and fermentation) processes.  

Biomass  combustion.  Bioenergy  production  is  largely  based  on  mature  direct  combustion 
boiler  and  steam  turbine  systems  at  small-  and  large-scale  for  residential  and  industrial 
applications. The scale of biomass plants is often limited by available biomass resources, local 
heat  demand  and  its  seasonal  variation.  Biomass  use  in  small  and  medium-scale  requires 
further development towards low emission stoves and boiler systems. Future research should 
focus  on  the  development  of  advanced  control  systems  and  better  design.  Stirling  Engine 
technology  is  currently  at  the  pilot-to-demonstration.  The  Organic  Rankine  Cycle  (ORC) 
engine  can  offer  technical  and  economic  advantages  for  small  plant  capacities  and  low 
operating  costs.  However,  electric  efficiency  is  limited,  and  specific  investment  costs  are 
high. The biomass ORC process has been demonstrated and is now commercially available. 

Waste.  Several  technologies  are  available  for  waste  conversion,  including  thermal  or 
biological  treatment.  Energy  recovery  from  waste  requires  certain  steps  including  pre-
treatment,  waste  conversion  and  energy  conversion.  Waste  gasification  with  gas  cleaning 
enables energy generation with improved efficiency, in combined cycle applications or syngas 
reforming.  Incineration  of  MSW  is  a  commercial  technology,  with  effective  emissions 
control.  Waste-to-energy  plants  provide  an  important  contribution  to  the  energy  supply. 
Energy recovery improvements can be achieved through the increase of electrical efficiencies 
and  increased  heat  utilisation.  The  major  challenges  for  waste  combustion  relate  to  the 
heterogeneous nature of waste, low heating value and high corrosion risk in boilers.  

Biomass co-firing. Biomass co-firing with coal is the most cost-effective and efficient option 
of bioenergy production. Direct co-firing with up has been successfully demonstrated with a 

22 

 
 
wide range of biomass feedstocks. However, feeding, fouling and ash disposal pose technical 
challenges that reduce reliability and lifetime of coal plants. Higher co-firing mix will require 
more  sophisticated  boiler  design,  process  control  and  fuel  handling  and  control  systems. 
Higher percentages of biomass can be used in co-firing with extensive biomass pre-treatment 
(i.e. torrefaction) with minor changes in the handling system. Co-firing of waste poses both a 
legal barrier and a technical challenge. Waste combustion may only take place in a plant that 
conforms to the requirements of the Waste Incineration Directive 2000/76/EC (WFD).  

Anaerobic digestion. Anaerobic digestion is a commercial and suitable technology for a range 
of  biomass  feedstocks.  Digestion  plants  are  limited  in  scale  due  to  feedstock  availability. 
Cleaning of biogas is required before use; biogas can also be upgraded to natural gas quality 
for  injection  into  the  natural  gas  grid  or  for  direct  use  in  gas  engine  vehicles.  The  main 
challenges  for  the  use  of  biomethane  are  the  gas  purity  requirements,  infrastructure,  supply 
and  gas  quality  standardization.  The  main  technological  development  needed  is  to  increase 
performance  and  cost  effectiveness,  enlarge  feedstock  basis,  improve  biodegradability, 
optimise  conversion,  improve  design  and  process  integration.  More  research  is  needed  on 
methods  to  process  difficult  to  degrade  feedstocks  and  the  development  of  new  techniques, 
enzymes and substrates, such as micro and macro algae (freshwater and marine). Anaerobic 
digestion and gas upgrading can be integrated into new biorefinery concepts.  

Landfill  gas  utilisation.  Landfill  sites  are  a  specific  source  of  methane  rich  gas,  providing 
methane  emissions  from  MSW.  Landfill  sites  can  produce  gas  over  a  20-25  year  lifetime. 
Collecting  this  gas  can  contribute  significantly  to  the  reduction  of  methane  emissions  and, 
after  cleaning,  provides  a  fuel  for  heat  and/or  electricity  production.  However,  due  to  the 
requirements to minimise landfilling of organic waste and increase levels of re-use, recycling 
and energy recovery (Landfill Directive 1999/31/EC), landfill gas is expected to decrease over 
time in the EU. The plant capacity of landfill gas collection varies from a few tens of kW to 4-
6 MW, depending on the size of the landfill site.  

Biomass gasification. Gasification is a highly versatile process for biomass conversion to fuel 
gas (syngas). Biomass gasification is still in the demonstration phase and faces technical and 
economic  challenges.  There  are  several  gasification  concepts  available,  depending  on  the 
gasification  medium,  operating  pressure  and  type.  Syngas  can  be  used  for  heat  and/or 
electricity  production,  or  for  synthesis  of  biofuels,  e.g.  hydrogen,  methanol,  DME  and 
synthetic  diesel  via  Fischer-Tropsch  process,  biomethane  and  chemicals.  The  BIGCC  is  a 
promising high-efficiency concept, although more complex that needs further development. A 
sophisticated gas purification is needed. The biomass gasification-hydrogen route could be a 
promising  technology  for  energy  production  in  Integrated  Gasification  Fuel  Cell  (IGFC) 
systems. Although gasification technologies are commercially available, more research needs 
to be done to achieve large scale commercial use. The key technical challenges and needs for 
research  include  process  integration  and  control,  gas  upgrading,  fuel  flexibility,  reducing 
complexity  and  costs,  improving  performance  and  efficiency.  The  critical  factors  for 
gasification are the reliability of the gasifier and the cost of the biomass supply. Significantly 
more RD&D is needed to develop, demonstrate and commercialise IGFC systems. 

Pyrolysis.  Fast  pyrolysis  is  the  conversion  of  biomass  to  a  liquid  bio-oil,  solid  and  gaseous 
components.  There  are  several  technical  challenges  to  the  use  of  bio-oil.  More  research  is 
needed  for  improving  the  quality  the  pyrolysis  oil  as  bio-oils  must  be  treated  before  use  as 
fuel and can  be  upgraded into higher value  fuels.  However, pyrolysis  and  bio-oil upgrading 
technology is not commercially available, although several pilot and demonstration plants are 
in operation. Research is needed on the conversion process, on the quality and use of the bio-
oil,  control  of  bio-oil  composition,  thermal  stability  and  process  reliability.  The  main 
challenges  concern  the  development  of  new  techniques  and  catalysts  for  bio-oil  up-grading. 

23 

 
Further  development  is  needed  for  process  integration;  maximize  bio  oil  yield;  maximize 
energy recovery; emissions of pyrolysis oil combustion; cost efficiency.  

Torrefaction.  Torrefaction  produces  higher  quality  solid  feedstock  (bio-char),  with  high 
energy  density  and  more  homogeneous  composition.  Torrefied  biomass  can  create  new 
markets and trade flows as commodity fuel and increase the feedstock basis. No commercial 
torrefaction  plant  exists  today,  but  demonstration  projects  are  on  the  way.  Further 
development  of  torrefaction  is  needed  to  overcome  certain  technical  and  commercial 
challenges.  Additional  fuel  properties  (e.g.  degree  of  torrefaction,  grindability,  hydrophobic 
properties,  resistance  against  biodegradation)  must  be  defined  in  a  product  standard. 
Development  and  standardisation  of  dedicated  analysis  and  testing  methods  are  needed  for 
assessment of end-use performance.  

Biorefineries. A key factor in the transition to a bio-based economy will be the development 
of  biorefinery  systems.  Biorefineries  are  a  promising  integrated  approach  for  the  co-
production  of  both  value-added  products  (chemicals,  materials,  food,  feed)  and  bioenergy 
(biofuels,  biogas,  heat  and  electricity)  and  more  efficient  use  of  resources.  Biorefineries  are 
largely at the conceptual stage, with potentially interesting new products, routes and process 
configurations being currently developed. Biorefinery platforms can produce a wide range of 
marketable  products  using  various  thermal,  biological  and  chemical  processes.  The 
deployment of the new biorefinery concepts will rely on the technical maturity of a range of 
processes to produce bio-based materials, bio-chemicals and energy.  

Hydrogen from biomass. There are several routes for the conversion of biomass to hydrogen, 
including chemical, thermo-chemical and biological, at different level of development and not 
yet  economically  viable.  Processes  for  hydrogen  production  include:  gasification;  pyrolysis; 
photolytic biological hydrogen; biomass conversion to hydrogen. Photo-biological processes 
are at a very early stage of development and have obtained low conversion efficiencies. Better 
understanding  of  the  enzymatic  pathways  of  hydrogen  formation  is  needed.  Research  is 
needed  to  identify  more  oxygen-tolerant  enzymes  and  new  strains  of  bacteria  producing 
hydrogen. There is a need for significant improvement of conversion efficiency. Further R&D 
is  particularly  needed  on  hydrogen  gas  separation  and  purification,  for  the  development  of 
catalysts,  adsorption  materials  and  gas  separation  membranes.  Hydrogen  storage  requires 
research  effort  on  new  materials,  adsorption  and  desorption,  recharging.  Major  challenges 
refer to the safety issues and developing a hydrogen infrastructure. 

6.3. 

Cost reductions 

Several biomass power generation technologies are mature, but most of biomass technologies have 
difficulties to compete with fossil fuels for a number of reasons. Biomass plants, using complex pre-
treatment, handling and feeding systems for biomass feedstock have higher capital and operating 
costs. Feedstock costs can represent up to 40 % to 50 % of the total cost of electricity produced. 
Bioenergy is a competitive option wherever low-cost feedstock (e.g. agricultural, forestry, pulp and 
paper residues, manure or sewage sludge, etc.) and/or when carbon tax or incentives are available. 
The cost and efficiency of bioenergy generation varies significantly by technology, configuration, 
complexity and level of maturity. Plant capacity influences the efficiency and cost effectiveness. 
Bioenergy technologies are at different states of commercialisation from the pilot, R&D or 
demonstration stage to commercial. Even for individual technologies, different configurations, 
feedstocks, fuel handling and gas clean-up requirements can lead to very different capital costs and 
plant efficiency.  

24 

 
 
The potential for cost reductions of biomass power generation varies, depending on the technology 
and potential for improvement (Figure 6.2). Many bioenergy technologies are mature and are not 
likely to undergo significant technological change as there is no much scope for improvement, and 
cost reductions through scale-up will be modest. The new technologies (gasification, pyrolysis, ORC) 
that are emerging and have not yet been deployed on a large scale, show significant potential for 
further cost reduction. Capital cost reductions for biomass co-firing, stand-alone direct combustion 
technologies (grate/BFB/CFB boilers) will be more modest. AD technologies could benefit from 
greater commercialisation and some process improvements. The co-production of chemicals, 
materials, food and feed in biorefineries can generate additional economic benefits for the 
production of lignocellulosic biofuels, biogas, heat and electricity.  

Projected capital cost for bioenergy technologies

W

l
/

R
U
E

9000

8000

7000

6000

5000

4000

3000

2000

1000

0

2010

2020

2030

2040

2050

co-firing

BIGCC

electricity

CHP

CFB CHP

gasification

AD

landfill gas

MSW

ORC

Figure 6.2. Trends in capital costs of bioenergy technologies  

6.4. 

Soft measures influencing deployment 

The main barriers to widespread use of biomass for bioenergy are cost competitiveness with 
fossil  fuels  and  feedstock  availability  at  low  cost.  Beyond  the  R&D  and  demonstration 
initiatives  described  above,  additional  support  measures,  such  as  feed-in  tariffs  and  carbon 
taxes would be critical for the trade-off of advanced technologies. 

The  main  issue  regarding  the  viability  of  bioenergy  lies  in  the  development  of  a  reliable 
supply chain. Secure, long-term supplies of low-cost, sustainable feedstock is essential to the 
economics  of  bioenergy  plants.  While  feedstock  cost  may  be  low,  increased  demand  for 
bioenergy  can  lead  to  price  increases  when  competition  for  feedstock  arises.  Availability  of 
sustainable biomass production of feedstocks is a critical factor for large scale deployment of 
bioenergy.  Promotion  of  energy  crops  (e.g.  SRC/SRF  and  energy  grasses)  with  high  yields 
could increase biomass supply, provided that land-use issues are adequately addressed.  

Biomass  shows  a  large  variability  of  physical  and  chemical  properties,  making  handling, 
transport, storage and feeding systems more complex and more expensive than for fossil fuels. 
Additional pre-treatment might be required to meet the quality requirements. Additional fuel 

25 

 
 
 
 
properties must be defined in a product standard for pre-treaded biomass, such as wood pellets 
(process  on  going)  and  torrefied  biomass.  Development  and  standardisation  of  dedicated 
analysis and testing methods are needed for assessment of end-use performance.  

Competition between alternative use of biomass for food, feed, fibre and fuel is a major issue 
for bioenergy deployment. Additional measures are needed to encourage the extension of the 
feedstock  base,  such  as  micro  and  macro  algae  (freshwater  and  marine),  to  develop  new 
strains and enzymes and new substrates, and to encourage the use of all residues  and  waste 
streams.  Given  the  limited  amount  of  biomass,  the  most  efficient  use  of  biomass  resources 
should be pursued.  

Various  concerns  were  recently  expressed  on  several  sustainability  aspects.  Sustainability 
certification  of  biofuels  and  bioliquids  as  well  as  solid  and  gaseous  biomass  should  play  to 
play  a  positive  role  addressing  both  direct  and  indirect  effects  of  bioenergy  production. 
Sustainable  land  use  planning  can  play  a  significant  role  in  this  issue.  The  work  should 
continue for the development of harmonised, global accepted sustainability system covering 
not only biofuels and solid and gaseous biomass, but also agriculture and forestry. This will 
contribute also to the public acceptance of bioenergy production. 

26 

 
 
 
7. 

CARBON CAPTURE AND STORAGE 

7.1.  Market evolution 

The deployment of carbon capture and storage (CCS) technologies is considered to be the only 
solution for reconciling the continuous use of fossil fuels, especially for power generation, with the 
need to reduce greenhouse gas emissions. The important role of CCS in the future European energy 
system is reflected on the European Energy Roadmap 2050, where it is shown that the lowest cost 
pathways to decarbonisation require the large-scale deployment of CCS in Europe as of 2030, when 
the technology is expected to become commercially competitive. Indeed, once CCS technology 
becomes commercialized, it will draw almost all new investment on fossil fuel power generation, see 
Figure 7.1. Installed capacity will grow from 3 GW in 2020 to 3 – 8 GW in 2030, 22 – 129 GW in 2040 
and approx 50 – 250 GW in 2050, depending on the path of evolution of the energy system, as 
depicted by the decarbonisation scenarios of the Energy Roadmap 2050. The contribution of CCS in 
gross electricity generation will rise from 1-3% in 2030 to approximately 5-20% in 2040 and 7-32% in 
2050, see Figure 7.2, depending on the shares of RES and nuclear energy in the technology mix:  CCS 
will fill in the gap in baseload power generation in the case of reduced nuclear power capacities (as 
reflected on the ‘low nuclear’ scenario, while the very large-scale deployment of RES may hinder CCS 
deployment (‘high RES’ scenario). Hence, irrespective of the specific path that the evolution of the 
energy system will follow, CCS will be an essential ingredient of the post-2020 European power 
generation technology portfolio. Beyond the power sector, the application of CCS to industrial 
sectors (e.g. steel, cement, refining) is expected to deliver, according to IEA, half of the global 
emission reductions required by 2050 from CCS15.  

Europe has been at the forefront of CCS technology development; however is lagging behind in terms 
of demonstration. According to GCCSI16, eight of the 16 large-scale CCS integrated projects in 
construction or operation in the world are located in USA but only two in Europe. However, of the 59 
projects under identification, evaluation or definition in the world by January 2013, 17 are located in 
Europe, 15 in the USA, 11 in China, 4 in Australia and 3 each in Canada and Middle East.  

Net coal power capacity investment per decade (GW)
Diversified supply technologies scenario

CCS
Conventional

40

35

30

25

20

15

10

5

0

2011-2020

2021-2030

2031-2040

2041-2050

Figure 7.1: Share of CCS capacity in new coal power plants, under the diversified supply technologies 
scenario of the energy roadmap 2050. Once CCS is commercialized in 2030, it will attract practically 
all new investment in fossil fuel technologies. 

15 IEA CCS Technology Roadmap, 2009. 
16 GCCSI, The global status of CCS, January 2013 update.  

27 

 
 
                                                            
CCS share in gross el. generation

Reference
CPI
EE
DST
High RES
Delayed CCS
Low nuclear

2015

2020

2025

2030

2035

2040

2045

2050

35

30

25

20

15

10

5

)

%

(

0
2010

Figure 7.2: Share of CCS in gross electricity generation in Europe according to the scenarios in the 
Energy Roadmap 2050 (CPI: current policy initiatives, EE: energy efficiency, DST: diversified supply 
technologies) 

7.2. 

Technology needs  

A prerequisite for the commercial deployment of CCS as of 2030 is the demonstration of the 
technical and economical feasibility of existing technologies in fully integrated up-scaled value 
chains, that comprise CO2 capture from power stations and large industrial installations; CO2 
transport via a pipeline network (or ship); and its safe and permanent underground storage in 
suitable geological formations, such as depleted hydrocarbon reservoirs or deep saline aquifers. A 
successful demonstration programme will pave the way for the construction of first-of-a-kind types 
of plant in the early/mid-2020’s, laying the foundations for the large-scale roll-out of the technology 
in 2030 along the timelines envisioned in the Energy Roadmap 2050. One billion euro of funding has 
already been made available for 6 demonstrations projects by the EU via the European Energy 
Programme for Recovery (EEPR) and further funding for CCS demonstration may become available 
from the proceeds of the second call of the NER 300 programme.  

Beyond  the  ongoing  demonstration  programme,  targeted  research  and  innovation  activities 
will be required so that CCS technologies reach and maintain such a level of competitiveness 
so that the penetration levels described in the Energy Roadmap 2050 are realised: 

•  The  development  of  innovative  capture  concepts  will  pave  the  way  for  the  second  and  third 
generations of CO2 capture technologies, marked by improved performance (i.e. lower efficiency 
penalty and cost of capture), which will result in further reductions of electricity costs to levels 
comparable  to  or  lower  than  those  associated  with  other  future  low-carbon  technologies. 
Already, alternatives such as ionic liquid solvents, enzymatic separation and physical separation 
are  emerging.  R&D  and  demonstration  priorities  should  include:  the  development  of  more 
efficient  solvent  systems  and  processes  for  post-combustion  capture,  e.g.  phase  change  and 
enhanced  carbonate  systems;  sorption-enhanced  water  gas  shift  and  novel  CO2/H2  separation 
systems  (e.g.  membranes)  for  integrated  pre-combustion  capture  installations;  large-scale 
demonstration  of  oxyfuel  boilers  for  both  the  power  and  the  heavy  industry  sectors  and 
development  of  second-  and  third-generation  systems  like  high  efficiency  circulating  fluidised 
bed  reactors  and  chemical  looping.  The  optimisation  of  such  capture  technologies  for  other 

28 

 
 
 
carbon-intensive  sectors  such  as  the  cement,  refineries  and  the  iron  and  steel  industries,  will 
enable the European industry to meet its CO2 emission reduction targets with the lowest possible 
impact on competitiveness. 

•  Pilots  will  lead  the  development  of  second-  and  third-generation  technologies  that  will  reduce 
further the investment and operating costs, as well as the associated energy penalty. They will 
focus on the testing of new / optimised solvents, sorbents and membranes, new process designs 
and  novel  power  plant  integration  schemes  for  all  three  capture  pathways,  post-combustion, 
pre-combustion and oxy-fuel. These pilots will also address crosscutting issues, such as capture 
plant  flexibility,  so  that  fossil  fuel  power  plants  can  operate  in  tandem  with  intermittent 
renewable energy sources.  

•  Demonstration  of  feasibility  of  bio-CCS,  i.e.  using  biomass  as  feedstock,  will  enhance  the  CO2 

reducing potential of CCS17.  

•  The development of concepts for CO2 transport will enhance safety and hence public acceptance. 
These include the design of materials suitable for pipelines handling CO2 at various compositions, 
avoiding pipeline rupture and longitudinal cracking. 

•  Better assessment of storage potential and site characterisation, especially of saline aquifers, will 
increase the safety of operations and contribute to the optimisation of infrastructure. Activities 
will  include  large  scale  storage  demonstrators  and  pilots  and  development  of  models  for  the 
behaviour of injected CO2 at various timescales.  

•  Development  of  methodologies  for  pressure  management  will  enable  optimal  use  of  the 
subsurface storage space,  co-optimisation of EOR and CO2 storage, and improved prediction of 
geologically controlled CO2 leakage mechanisms, which in turn will lead to safe and efficient CO2 
storage exploitation. 

•  The  development  of  more  refined  and  cost-effective  monitoring  and  modelling  techniques  will 
contribute  to  the  assessment  of  CO2  migration,  diffusion,  fluid-rock  interactions,  and  cap  rock 
integrity  for  verifying  storage  security.  This  will  lead  to  enhanced  leakage  detection  and 
measurement, both in-situ and by remote sensing. 

•  Development  of  economically  viable  technologies,  which  can  use  captured  CO2  as  feedstock  for 
the  production  of  synthetic  fuels  and  chemicals,  will  improve  the  economics  of  CCS  (CO2 
utilisation –CCUS-). 

•  The  further  improvements  of  the  efficiency  of  power  plants  and  industrial  processes  will 
enable  the  deployment  of  CO2  capture  technologies  at  a  minimum  overall  efficiency 
penalty. This is addressed in Chapter 9 of this report.  

7.3. 

Cost reductions 

Since CCS technologies have not yet been demonstrated on a commercial scale in the power sector, 
all reported cost figures are only estimates, based on scaling-up of smaller similar components and 
facilities used in other sectors (e.g. chemical and petro-chemical industry) or on manufacturers’ 
expert judgment. As such, there is a significant uncertainty about near-, medium- and long-term 
technology costs. A recent cost analysis by ZEP ETP18 give estimates of the capital costs of power 
plants equipped with early generations of CCS technology. The costs of a coal plant range from 2450 

17  ZEP  ETP  and  the  European  Biofuels  Technology  Platform,  Biomass  with  CO2  Capture  and  Storage  (Bio-
library/publication/206-biomass-with-co2-capture-and-

CCS),  http://www.zeroemissionsplatform.eu/ 
storage-bio-ccs-the-way-forward-for-europe.html 

18  ZEP  ETP,  The  costs  of  CO2  capture,  http://www.zeroemissionsplatform.eu/library/publication/166-zep-cost-

report-capture.html 

29 

 
 
                                                            
€/kW (plant with post-combustion capture) to 3325 €/kW (oxyfuel plant). On average, the first 
generation CCS coal power plant is expected to be about 60-100% more expensive than a similar 
conventional plant, depending on the capture technology selected, i.e. post-, pre-, or oxyfuel 
combustion; while the capital cost of a natural gas plant with post-combustion capture can be twice 
of that of a conventional gas plant with the same capacity. It has been estimated that once CCS 
power plants start being deployed, costs will decrease at a rate of 12% per doubling cumulative 
installed capacity, benefiting from R&D activities and the building of economies of scale. Of the CO2 
capture technologies, the costs of oxyfuel-based systems may decrease faster since the industry 
expects new designs soon after first commercialisation, at a cost of about 2200 €/kW. Figure 7.3 
shows the reduction of specific capital investment (SCI) of CCS power plants in the period 2020-2050. 
It is expected that by 2050, the capital costs of pre- and post-combustion coal plants with CCS will be 
reduced by almost 20% from those of first market entrants. The corresponding reduction for gas 
plants is expected to be around 10%.The cost of CO2 capture for industrial applications will also vary 
according to application, but may, in many cases, be lower than for power generation due to a higher 
concentration of CO2 in the flue gas.  

Capital cost reductions for CCS power plants

3500

3000

2500

2000

1500

)

W
k
/
)
0
1
0
2
(
R
U
E

(

I

C
S

1000

500

0
2020

SC Coal (post-combustion)

SC Coal (pre-combustion)

SC Coal (oxy-fuel)

CC Gas (post-combustion)

2030

2040

2050

Figure 7.3: Trends in capital costs of supercritical (SC) coal and combined cycle (CC) natural gas power 
plants with CCS technology (Source: JRC estimates) 

7.4. 

Soft measures influencing deployment 

Beyond  R&D  and  demonstration  initiatives  to  address  technological  gaps,  additional 
measures will be required to facilitate the timely deployment of CCS. The most pressing issue 
to be addressed is the lack of business case. The current low ETS prices and the lack of any 
other  legal/regulatory  constraint,  or  incentive,  hinders  investments  in  CCS,  both  in 
demonstration  and  in  bridging  the  gap  to  commercialisation,  since  there  is  no  financial 
compensation for the additional capital and operating costs associated with CCS, despite the 
savings  that  come  from  buying  fewer  ETS  quotas.  This  is  especially  true  for  the  heavy 
industry, which faces a high risk of ‘carbon leakage’ due to the global trade of their products. 
The  lack  of  political  commitment  to  CCS  by  some  Member  States,  as  reflected  on  the 
outcome  of  the  first  call  of  the  NER300  programme,  triggered  by  the  current  economic 
environment,  problems  in  permitting  procedures  and  public  opposition  only  adds  to  the 

30 

 
 
 
 
difficulty  of  CCS  projects  to  secure  public  and  private  financing.  Additional  financial 
incentives are hence needed as well as a stable policy/regulatory environment to make a CCS 
investment as commercially attractive as a conventional fossil fuel plant. It is noted however 
that the key regulatory issues related to permit/licensing procedures for storage sites and long-
term  liability  have  already  been  addressed  by  the  CCS  Directive  (2009/31/EC).  Securing 
public  confidence  in  many  Member  States  is  another  key  social  and  political  challenge,  as 
confirmed by a Eurobarometer survey on CCS. While nearly half of the respondents agreed 
that CCS could help to combat climate change, the survey observed that 61% of people would 
be  worried  if  an  underground  storage  site  for  CO2  were  to  be  located  within  5  km  of  their 
home.  As  a  result  of  public  opposition,  a  number  of  projects  that  envisaged  CO2  storage  in 
land  have  been  cancelled.  This  barrier  was  overcome  in  same  cases  when  extensive 
information  campaigns  took  place,  or  when  CO2  will  be  stored  offshore.  Since  public 
perception  will  have  a  significant  role  to  play  in  CCS  deployment,  measures  relating  to 
education on climate change and communication of the main technical economic and social 
aspects are needed.  

31 

 
8. 

NUCLEAR FISSION ENERGY 

8.1.  Market evolution 

In the Energy Roadmap 2050 six policy scenarios were studied. In the ‘current policy scenario’ the 
share of nuclear power is projected to reduce from 30.5 to 20.7% of the gross electricity production 
in 2030 and to 20.6% in 2050. For the four decarbonisation scenarios, the share of nuclear in the 
gross electricity generation varies from 13.4 to 21.2% in 2030 and 2.5 to 19.2% in 2050. For most 
other recent scenario studies concerning EU-27, the share of nuclear is forecasted to be either stable 
or slightly reduced by 2050. The construction of new nuclear will vary significantly between Member 
States. Presently, for example France, Finland, the UK, and Czech Republic plan construction of new 
reactors, whereas other countries have decided to phase out or stop their nuclear programs, e.g. 
Germany and Italy.  

AREVA is the only European vendor of nuclear reactors. It is one of the global leaders in the industry. 
Two of its European pressurised reactors (EPRs) are under construction in Finland and France, and 
two EPRs are under construction in China. Worldwide there are 68 reactors under construction. 
AREVA is currently competing to sell reactors in the UK, Czech Republic, USA, India etc. Other major 
vendors competing globally include Westinghouse, GE Energy, Atomstroyexport, Mitsubishi Heavy 
Industries, AECL, and KHNP. Competition from Chinese vendors as well as from private enterprises 
selling Small and Medium sized Reactor (SMR) concepts are expected to increase in the future.  

Europe and particularly France have large experience with Sodium-cooled Fast Reactors (SFR). 
Outside Europe, fast reactor programs are pursued in Russia, Japan, India, and China. These countries 
invest large resources, but Europe has an opportunity to construct the first fast reactor that meets 
the Generation IV design criteria19.  

8.2. 

Technology needs  

Often nuclear reactor designs are categorised in Generation II, III and IV according to their 
evolutionary improvements or developments. Most of the reactors operating globally are of 
Generation II type. Two Generation III rectors are under construction in the EU-27, while Generation 
IV plants are to be commercially deployed around 2040. Some of the general technology and 
research needs as well as the specific needs for each Generation of nuclear power are presented 
below. 

General needs 

After Fukushima it became apparent that more focus is needed on extreme and rare external safety 
hazards and the interaction between units on one site in such events20. Examples of general 
technology/research needs are: 

19 GIF, 2002, A Technology Roadmap for Generation IV Nuclear Energy Systems, pp.6, available at: 

http://www.gen-4.org/PDFs/GenIVRoadmap.pdf 

20SNETP, 2011, Implications of the Fukushima accident for SNETP, available at: 

http://www.snetp.eu/www/snetp/images/stories/Docs-
Newsflash/Implication_of_Fukushima_SNETP.pdf 

32 

 
 
                                                            
•  Systematic approach for the determination of safety margins and the risk of occurrence of cliff-

edge effects for extreme events beyond the design basis. 

•  Methodologies to identify extreme and rare events potentially leading to common mode failures 

of multiple plants system. 

•  Further  develop  and  validate  advanced  models  and  simulation  platforms  for  the  analysis  of 

severe accident. 

Generation II  

The bulk of the Generation II Light Water Reactors (LWR) were commissioned during the 1980's and 
unless they are granted life time extensions they will be decommissioned in the 2020's, see Figure 
8.1. It is expected that most nuclear power plants will extend their operating life time to 50-60 years, 
as is often the case with similar reactors around the world (e.g. in the USA). 

16

14

12

10

8

6

4

2

0

1970

1980

1990

2000

2010

2020

2030

2040

2050

Start operation

Phase out year w/o Plant Life EXtension

Figure 8.1. Start of operation and planned phase out without plant life extension for nuclear power 
plants in EU-27 

In the period 2010-2030, the successful operation and management of Gen II LWRs beyond their 
originally foreseen lifetime will be an important driver for R&D21.  

Important issues to be addressed are:  

• 

Increase understanding of ageing mechanisms of materials 

•  Development best practise guidelines for ageing prevention and mitigation 

•  Further development and validation of modern computer codes for assessing loading 

Generation III 

21 SNETP, 2009, Strategic Research Agenda, available at: http://www.snetp.eu/www/snetp/images/stories/Docs-

AboutSNETP/sra2009.pdf 

33 

 
 
 
 
 
                                                            
The Generation III LWR reactors are the state of the art of nuclear reactor technology and they are 
currently being deployed. The designs will be further refined with time based on feedback from 
operating experience and improvements through R&D.  

Generation IV  

Within the European Sustainable Nuclear Industrial Initiative (ESNII) three fast reactor concepts are 
developed. The French project called ASTRID concerns the sodium-cooled fast reactor (SFR). A 
prototype is planned after 2020 and commercial deployment after 2040. The MYRRHA project of 
Belgium on a lead-bismuth cooled accelerator driven system plans a demonstrator by 2022. MYRRHA 
feeds into the development of the lead-cooled fast reactor (LFR) concept. The LFR is expected to be 
commercially deployed around 2050. A gas-cooled fast reactor (GFR) is also being investigated, but it 
requires more R&D on fuel and materials, and thus its commercial deployment would be farther in 
the future. 

To achieve commercial availability of SFR by 2040 and LFR by 2050, some of the technology needs 
identified are22:  

•  Structural  materials  and  innovative  fuels  that  can  support  high  fast  neutron  fluxes,  high 

temperatures, and guarantee a plant lifetime of 60 years 

• 

Improved  safety,  and  robustness  against  severe  damage,  e.g.  core  designs  with  moderate  void 
effect and other favourable reactivity feedback effects 

•  Development  of  European  codes  and  standards  to  be  used  for  future  construction  of  Gen  IV 

reactors 

•  More  advanced  physical  models  and  computational  approaches  to  achieve  more  accurate  and 

detailed modelling benefiting from the increase of computational power 

• 

Improved sustainability through a better use of fissile materials, reduction of proliferation risks, 
and minimisation of long lived radioactive waste. 

Nuclear cogeneration using (Very) High Temperature Reactors is another potential area where 
nuclear power can play a role in decarbonising both the electricity and heat markets23. An industrial 
initiative is being prepared, but since no significant projects exists yet it is not treated further here. 

8.3. 

Cost reductions 

Generation III: At Olkiluoto the originally planned start in 2009 of the first of a kind EPR has been 
delayed by seven years, whereas construction at Flamanville is four years behind schedule. The long 
delays have caused significant cost overruns. The costs for EPR at Olkiluoto and Flamanville are now 
estimated at 8.5 billion Euro (5300 Euro/kWe), which is more than twice their original costs. On the 
other hand, two EPRs are under construction in China using the experiences learned from the 
constructions in Europe. The Chinese EPRs are on schedule to be constructed in 46 months. It is likely 

22 SNETP, 2009, Strategic Research Agenda, available at: http://www.snetp.eu/www/snetp/images/stories/Docs-

AboutSNETP/sra2009.pdf 

23 SNETP, 2009, Strategic Research Agenda, available at: http://www.snetp.eu/www/snetp/images/stories/Docs-

AboutSNETP/sra2009.pdf 

34 

 
 
 
                                                            
that delays and cost overruns would be significantly reduced for the next construction of an EPR in 
the EU too, see Figure 8.2. In the long term the capital costs are expected to be around 3500 
EUR/kWe. The designs will be refined with time to improve economic competitiveness. 

Generation IV: According to the Key Performance Indicators indicated by ESNII, the capital cost is 
expected to be around 4000 EUR/kWe for the LFR for the Nth-of-a-kind (NOAK) reactors. The aim is to 
keep capital costs down by plant simplifications and by the use of inherent and passive safety 
systems. The SFR is expected to have a similar capital costs as the LFR. It should be recognised that 
for projects of this size and complexity, the uncertainties of these estimates are not negligible. 

6000

5000

4000

3000

2000

1000

e
W
k
/
€
,

X
E
P
A
C

0
2000

2010

2020

2030
Year

2040

2050

2060

Gen III LWR

Gen IV SFR

Figure 8.2. Capital cost trends for Generation III and IV nuclear reactors. 

8.4. 

Soft measures influencing deployment 

Non-technological measures could have an important effect for the market trajectories of nuclear 
power. The following areas would help the nuclear industry: 

•  Access  to  favourable  financing  to  increase  certainty  for  investors  and  make  more  resources 

accessible to research programmes. 

•  Streamline  the 

licensing  process 

in  the  Member  States  through  common  regulatory 

requirements, which could shorten the time from investment decision until reactor operation. 

•  Harmonisation of European plant life extension justification methodologies. 

•  Harmonisation of European methodologies for a new type of probabilistic safety assessment, e.g. 

extreme events like earthquakes, and sharing of data. 

•  Extend training of qualified engineers and scientists in the nuclear domain. 

.  

35 

 
 
 
 
9. 

ADVANCED FOSSIL FUEL TECHNOLOGIES 

9.1.  Market evolution  

Coal and gas fired power stations will likely remain in the European generation technology portfolio, 
with the latter having a higher potential if a safe and secure extraction of hydrocarbons from 
unconventional resources will become possible, even in scenarios with a very high share of RES-E 
generation24. Their role will be to provide backup in times of no supply from variable RES-E as well as 
flexibility in case of rapid supply and demand changes. The technology portfolio consists of 
continuously improved steam and gas turbines (and combinations thereof as e.g. CCGTs). On a 
worldwide level, fossil fuels are expected to remain the most important source of power generation 
representing more than 40% of capacity additions by 2035 and providing well over 50% of electricity 
in 203525. Only 9% of these additions are expected to happen in the EU. Scenarios taking into account 
a decarbonisation of the European power system assume no more growth in global installed capacity 
post 2030 reducing the market to replacement installations which however remains significant. 
Roughly 1,300 GW of coal and 1,200 GW of gas plant capacity will be added between 2012 and 2035 
representing about half of the then installed total capacity. The European and – to a lesser degree – 
the global fossil fuel mix are expected to continue shifting from coal to gas which is expected to 
overtake coal in terms of installed capacity by 2030. 

Global Fossil Fleet

Gas
Coal

d

5,000

4,500

4,000

3,500

3,000

2,500

2,000

1,500

1,000

500

-

]

W
G

[
y
t
i
c
a
p
a
C
d
e

l
l

a
t
s
n

I

2010
World EU

2020
World EU

2030
World

EU

2040
World

2050
World

Source: JRC elaboration on IEA WEO 2012, New Policies Scenario; IEA ETP 2012, 4DS26 

9.2. 

Technology needs  

Stream turbines for coal plants 

24 See e.g. EWI: ‘Flexibility options in European electricity markets in high RES-E  scenarios, Study on behalf 

of the International Energy Agency (IEA), Cologne 2012. 

25 World Energy Outlook 2012, New Policies Scenario, page 182 
26 IEA Energy Technology Perspectives 2012 

36 

 
 
 
 
 
 
                                                            
Today, the majority of the European fleet of coal power stations still uses subcritical steam turbines 
that have thermal efficiencies of below 40% (LHV). No new deployment of this technology is 
expected in Europe apart from selected cases of retrofitting or reactivating mothballed stations. 
During the last decade27, 92% of new coal plants in Germany and 53% of new coal plants in Poland 
were built using supercritical technologies reaching thermal efficiencies of 45% and 43% in case of 
hard coal and lignite fuel respectively. Outside Europe, subcritical technology still enjoys a market 
share above 50% of new builds in China, India and the United States. 

The next evolutionary step in the development of steam turbines for coal power stations is to raise 
the steam temperature to 700°C achieving a thermal efficiency of up 50%. The 700°C technology 
necessitates the switch from iron-based to nickel-based alloys as only the latter are able to withstand 
the higher temperatures. A number of pilot projects to test components under real life conditions 
have been initiated within projects funded by the EU and member states, such as e.g. the 
COORETEC28 program. The full commercialisation is not expected before the decade of 2020-30. 

Integrated Gasification Combined Cycle (IGCC) 

IGCC is a technology originally developed for the treatment of refinery residues and not with a focus 
on power generation. Worldwide, only 17 of the currently operating 137 IGCC plants29 are used for 
power generation and only 6 of these use coal as their primary feedstock.  

A number of new projects with a capacity above 500 MW, i.e. double the size of currently deployed 
plants, have recently been announced in Europe30 but no final investment decision has been 
communicated so far. In the USA, one large scale project began test operation in 201231. IGCC 
technology is currently disadvantaged by higher costs and the lack of a comparable experience 
(compared with the coal steam turbine plants). The prime objective of R&D is the demonstration of 
the commercial viability of this (otherwise mature) technology for power generation from coal.  

Once the large scale deployment track for this technology takes off, an improvement of the power 
block would be a main target as current plants in general use less advanced gas turbines compared to 
state of the art combined cycle natural gas (CCGT) plants. A roadmap is currently developed by the 
European Turbine Network within the FP7 project H2-IGCC32 with the aim of integrating most recent 
(H-class) gas turbines into an IGCC allowing a net thermal efficiency of up to 50%. A recent study by 
Shell33, one of the leading providers of gasifier technology, suggests thermal efficiencies of 48.5% for 
new built projects. 

27 Finkenrath, Smith, Volk: CCS Retrofit – Analysis of Globally Installed Coal-Fired Power Plant Feet, IEA 

2012 

28 www.cooretec.de 
29 According to the US DOE database on gasification plants, located at 

www.netl.doe.gov/technologies/coalpower/gasification/worlddatabase/ 

30 Christer Björkqvist, European Turbine Network-ETN, Progress Towards Implementation of IGCC-CCS in 

Europe, ICEPAG, 2010 

31 Duke Energy, Sustainability Report 2011-12 
32 www.h2-igcc.eu 
33 Prins et. al: Technological Developments IGCC for Carbon Capture, Chemical Engineering Technology 2012, 

35, No3, p. 413-419 

37 

 
 
 
                                                            
Gas/oil steam turbine power plants 

Gas power plants with steam turbines have also been deployed in Europe mainly in the 1970s but 
their relatively low thermal efficiency of ca. 40% challenges their competitively against CCGTs or even 
open cycle gas turbines. This can be observed by decisions of some European utilities to mothball 
such units34. Plant manufacturers have moved to gas turbine technology since the 1990s. 

Gas turbines and combined cycle gas turbine plants (CCGT) 

Gas turbines have been used for more than 50 years, mainly for peak power generation but also in 
combination with combined heat and power systems. Investments in open cycle gas turbines are 
ongoing in Europe.  

The CCGT combines two building blocks: a gas and a steam turbine. In current CCGTs, the steam is 
generated by the exhaust gases of the gas turbine. The deployment of combined cycle gas turbine 
power plants gained significant momentum in the 1990s when progress in materials allowed gas 
turbines to achieve temperatures exceeding 1500°C allowing this combined process. The 
performance of gas turbines and the CCGT plants using these turbines has continuously improved 
since then. Thermal efficiencies of gas turbines deployed in the 1990s are typically around 35%, 
resulting in a CCGT efficiency of up to 55%. Gas turbines of this type are still used for open cycle gas 
turbine applications today. Today’s most advanced gas turbines have a power rating of 375 MW and 
thermal efficiencies of 46%, allowing CCGT efficiencies above 60%. The bulk of investment projects 
today however use improved F-class gas turbines resulting in slightly lower CCGT efficiencies of ca. 
58%.  

Research and development towards higher efficiencies is ongoing in different industrial initiatives. 
The goal for a CCGT is to reach a combined thermal efficiency of 63% by 2020. The future 
development of gas turbines is expected to take place in a competitive market environment including 
public R&D support as e.g. within the ‘AG Turbo’ or the US DOE gas turbine programme. Closely 
related to this are activities with the aim to adapt newest generation (H-class) gas turbines to syngas 
in IGCCs (see the abovementioned H2-IGCC-project). 

9.3. 

Cost reductions  

Steam turbines 

Stable capital costs can be expected for new build steam turbines for both hard coal and lignite 
plants. The technology is mature and it shows a rather small learning rate of ca. 5% per doubling of 
capacity35. Improvement of technology (such as an increase in steam parameters) is happening 
incrementally and the rate of new deployment is relatively constant. As the global cumulated 
capacity of deployed coal plants (including all technologies such as e.g. IGCC) is expected to double 
by 2030, a 5% reduction in capital costs could be expected by then. Constant costs of 1700 €2012/kW 

34 

See 

e.g. 

the 

decision 

by 

Statkraft 

to  mothball 

the  Emden 

unit 

in  Germany: 

http://www.statkraft.com/presscentre/press-releases/statkraft-adjust-generation-in-germany.aspx 
35  Junginger  (Editor)  et.  al.:  Technology  Learning  in  the  Energy  Sector,  Lessons  for  Policy,  Industry  and 

Science, 2010 

38 

 
 
 
                                                            
and 1850€2012/kW for coal and lignite respectively are however assumed for the European Union 
anticipating more ambitious environmental targets and taking into account a more expensive and 
highly qualified workforce.  

IGCC 

As the potential for improvement of the compound IGCC system is the result of the potentials of its 
components (gasifier, gas cleaning unit and power block), learning rates similar to CCGT technology, 
i.e. a 10% reduction of capital costs per doubling of capacity, can be assumed given similar 
components. Taking into account the very small installed base of plants today such a learning rate 
would lead to a significant cost reductions. Two scenarios are presented in Figure 9.1: the high cost 
scenario assumes an IPCC share of 5% of all new coal plants, the low cost scenario a share of 25% of 
all new coal plants by 2035. It is further assumed that learning would take place in a single 
investment wave starting past 2020. No further reduction in costs is assumed between 2030 and 
2050. It can be seen that IGCC costs could fall below those of coal plants equipped with steam 
turbines however only if every fourth project would make use of this technology. 

Fossil Power Plant Costs

]

W
k
/
R
U
E

[

X
E
P
A
C
c
i
f
i
c
e
p
S

3000

2500

2000

1500

1000

500

0

Coal IGCC (High)
Coal ST
Coal IGCC (Low)

CCGT

Gas Turbine

2010

2020

2030

2040

2050

Figure 9.1: Capital cost trends for conventional fossil fuel power plants (Source: JRC estimates) 

Gas turbines and CCGT 

Large gas turbines suited for combined cycle plants are a mature technology but provided only by a 
limited number of European, American and Japanese manufacturers. Observed learning rates have 

39 

 
 
 
 
 
 
 
stabilised at 10% per doubling of capacity after a phase of more rapid price declines observed in the 
1990s36.  

The cumulated capacity of deployed gas fired plants (including CCGTs and OCGTs) is expected to 
grow in most energy scenarios. According to the New Policy Scenario of the IEA World Energy 
Outlook, the cumulated installed capacity will double by 2035. This would result in a cost reduction 
of 10% (on world markets). As in the case of steam turbines, constant specific capital costs are 
assumed postulating higher than average environmental requirements and higher labour costs for 
Europe. 

9.4. 

Soft measures influencing deployment 

Investment decisions by utilities as well as R&D decisions by manufacturers related to fossil fuel 
plants have so far been made purely on competitive grounds. Key drivers for future directions will be 
given by the commodity markets and energy system requirements, such as: 

•  Gas  and  carbon  emission  prices  determining  whether  gas-fired  plants  will  be  designed  for 

baseload, cycling or backup generation. 

•  The total system intermittency resulting from RES-E penetration levels and integration measures 

such as storage deployment, larger scale interconnection and demand response measures 

•  The total generation mix including the share of coal, nuclear and hydro power stations 

The challenging business case for new build fossil power plants in markets with an increasing level of 
RES-E, depressed power prices and low running hours and a reduced investment appetite from the 
side of utility investors faced with strained balance sheets might lead to a lack of investments even in 
capacity that is needed from a system security of supply perspective. A number of Member States 
have started to address this problem by considering the introduction of capacity payments to plants 
and the European Commission has launched a public consultation on that matter37. A reform of 
power markets allowing both RES-E and conventional generation to compete on a level playing field 
will be one of the regulatory challenges for a high RES-E system. 

All abovementioned barriers could be overcome by the end of the decade when demand for new 
generation capacity can be expected to pick up again and strong price signals for CO2 would provide a 
competitive advantage to low carbon investments.  

36  Junginger  (Editor)  et.  al.:  Technology  Learning  in  the  Energy  Sector,  Lessons  for  Policy,  Industry  and 

Science, 2010 

37 http://ec.europa.eu/energy/gas_electricity/consultations/20130207_generation_adequacy_en.htm 

40 

 
 
 
 
 
                                                            
10. 

MARINE (WAVE & TIDAL) ENERGY 

10.1.  Market evolution 

Currently, the installed capacity of marine (wave and tidal) energy technologies on the global level is 
limited to few MW (excluding tidal barrage projects). These installations are demonstration projects. 
Table 10.1 gives an example of marine energy technologies installed in European waters.  

Table 10.1: Examples of marine energy technologies installed in European waters 

Developer 

Projects to date 

Pelamis Wave Power, UK 

2 Units of 750 kW at EMEC, UK 

Ocean Power Technologies, USA 

2 Units of 40 kW in the USA and 150 kW unit is Scotland 

Seabased, Sweden 

Multiple 30 kW devices in Sweden 

Aquamarine Power Oyster, UK 

One unit of 315 kW and another of 800 kW at EMEC, UK 

AW Energy WaveRoller, Finland 

One unit of 300 kW in Portugal 

Voith Hydro Wavegen, UK and 
Germany 

One unit of 300 kW in Mutriku, Spain and 500 kW unit in the 
UK 

WavEC, Spain 

One WavEC Pico Plant of 400 kW in Azores 

Dave Dragon, Denmark 

One unit of 20 kW in Denmark 

Wello Oy, Finland 

One Penguin WEC unit of 500 kW at EMEC, UK 

The installed capacity of marine energy technologies in the EU in 2020 will reach 2253 MW, 
according to the National Renewable Energy Action Plans: 1300 MW in the UK, 380 MW in France 
(including the 250 MW La Rance tidal barrage plant), 250 MW in Portugal, 100 MW in Spain, 135 MW 
in Portugal, 75 MW in Ireland, 10 MW in Finland and 3 MW in Italy.  

In the longer term, it is estimated that marine energy would cover 5% of the EU power generation in 
2050, i.e. approximately 250 TWh of marine energy electricity. Assuming that such plants operate on 
average during 3500 hours a year, the required installed capacity of marine energy in the EU could 
reach 71 GW in 2050. The 2030 installed capacity would be around 15 GW and the capacity in 2040 
around 35 GW. 

10.2.  Technology needs 

The potential of marine energy is undeniable. Wave and tidal energy can play an important role in 
Europe's future electricity supply as it relies on vast resources and a low-carbon footprint. Moreover, 
its development would contribute significantly to the economic growth of coastal regions, and 
represents an opportunity for the European industry for technology exports. Nevertheless, the very 
early stage of marine energy technologies implies that many technological challenges lie ahead. 

41 

 
 
 
 
Research has already led to the development of a wide variety of marine energy conversion 
technologies. This is an on-going effort and new concepts can be expected in the future. Many 
proposed systems have not yet been tested under real operation conditions. The evolution from 
design to lab and from lab to the water will allow a variety of technologies to compete and eventually 
to bring viable marine energy systems to the market. The priority of the sector is the demonstration 
of concepts, which should include testing of single units under real operation conditions, but also up-
scaling to the array level. Accumulation of short- and long-term operation data, such as performance, 
component and system reliability, operating and maintenance needs, etc,. is a required input for 
design optimization and cost savings. 

Europe is currently world leader in marine energy development and demonstration. This includes the 
development of marine energy conversion concepts, system design and engineering, and single- and 
multiple-device testing, aiming to demonstrate commercial viability. The European test centres, e.g. 
the European Marine Energy Centre (EMEC), the Wave Hub, the Biscay Marine Energy Platform 
(BiMEP) and the Danish Wave Energy Centre (DanWEC), are state of the art facilities. However efforts 
have to intensify to accelerate development and eventually deployment of marine energy in Europe. 

According to CarbonTrust, the capital cost breakdown for a tidal energy device in a medium- or large-
scale farm would be as follows: 30% for the rotor and power train, 25% for the structure, 16% for 
installation, 13% for off-board electrical equipment, 12% for generator and other on-board electrical 
equipment and 4% for design, engineering, management and insurance. The capital cost breakdown 
for a wave energy device in a medium- or large-scale farm would be as follows: 41% for the device, 
17% for installation, 14% for transmission, 10% for decommissioning, 7% for moorings, 4% for 
commissioning, 5% for design, engineering and management and 2% for insurance. R&D activities to 
achieve cost reductions should focus on the components with the highest costs. 

Another R&D priority for marine energy technologies is the increase of capacity factors. The capacity 
factor of current technologies is roughly around 2000 full operation hours a year. It is estimated that 
R&D and demonstration can increase annual operating hours to 3000 in 2020 and on the longer run a 
typical range would be 3500-4000 h/y. Once such capacity factors are achieved, the cost of 
generated electricity will decrease to levels that make the technology competitive with other low-
carbon technologies. System viability is also very relevant as off-shore operation and maintenance is 
very costly. Hence, R&D needs to focus on this issue. 

Accurate resource assessment is also necessary for the successful deployment of marine energy in 
Europe. There is a need for a high resolution, accurate European marine energy atlas, which should 
be updated regularly. 

10.3.  Cost reductions 

The current costs of both wave and tidal energy are considerably higher than conventional and other 
renewable energy generation technologies. This is not surprising, given the early stage of 
technological maturity of these technologies, particularly since projects are constrained to 
demonstration of individual devices and thus there are very limited economies of scale. According to 

42 

 
 
CarbonTrust38, the current costs are due to high uncertainties and lack of know how. The cost of 
devices decreases through deployment at choice sites or dedicated test sites. Reduction cost efforts 
are focused on new generation devices by means of increasing the energy yield in deeper waters and 
greater swept area per unit of support structure and foundation and per unit of capital costs and 
operating and maintenance costs. 

Cost reduction in wave and tidal energy will be achieved through design improvement, optimizations 
in applied materials and mass production. These factors will lead to significant reductions in 
investment costs, increase of the capacity factor, higher reliability and extended lifetime. 

At the current early stage, wave and tidal technologies still offer a wide variety of different designs. 
For instance, current wave energy converter technologies include the following types: attenuator, 
point absorber, oscillating wave surge converter, oscillating water column, overtopping, pressure 
differential, bulge wave and the rotating mass type, among others. Tidal energy converts include, 
among others: horizontal and vertical axis turbines, oscillating hydrofoil, enclosed tips, helical screw 
and tidal kite. In the future, it is expected that the current technological diversity on the R&D and 
demonstration level will crystallize to standard solutions with strong synergies so that significant cost 
reduction through the learning rate would be achieved with the increase in the cumulative installed 
capacity.  

Figure 10.1 presents the cost reduction curve for wave and tidal energy during the period 2010 to 
2050, based on JRC estimates.  

Figure 10.1: Estimated trends in capital costs of marine energy technologies 

38  Carbon  Trust  2011,  “Accelerating  marine  energy”, 

July  2011,  http://www.carbontrust.co.uk 

/publications/pages/publicationdetail.aspx?id=CTC797 

43 

 
 
 
 
                                                            
10.4. 

Soft measures influencing deployment 

Once marine energy technologies are demonstrated, subsidies or feed-in tariffs will be required. 
These should target the acceleration of the deployment of marine energy technologies in Europe. 
This acceleration would bring cost reductions and lead eventually to the emancipation of the 
technology from financial support. 

The deployment of marine energy in Europe will necessitate new infrastructure, such as the upgrade 
and extension of the grid and the building of ports and maintenance vessels. Thereby the synergies 
with other offshore energy technologies (offshore wind, offshore oil and gas platforms) have to be 
assessed and implemented, while the coexistence with other marine activities like marine transport 
and fishing should be harmonized. Legislative measures to provide the needed infrastructure, 
facilitate grid-connection and feed-in priority for marine power generation are also required as 
marine energy systems do not provide electricity on demand. 

44 

 
11. 

FUEL CELLS AND HYDROGEN 

11.1.  Market evolution  

Commission roadmaps do not present penetration figures by 2030 and 2050 for fuel cell and 
hydrogen (FCH) technologies, nor is such information readily available from literature. Market 
evolution numbers are based on projections of the evolution of the energy, transport, industrial and 
residential systems, based on assumed scenarios towards a low-carbon economy. In these 
projections, FCH technologies, with zero CO2 performance at the point of use and high energy 
efficiency, are recognized as essential contributors to the required decarbonisation in all economy 
sectors, yet deployment projections of FCH technologies have only been found in the IEA Energy 
Technology Perspectives39. The numbers in Table 11.1 comply with a scenario that ensures an 80% 
chance of limiting long-term global temperature increase to 2°C, and assume a high penetration of 
hydrogen (2DS hi-hy scenario). 

Table 11.1: FCH projections according to the IEA 2DS hi-hy scenario 

Share of H2 in energy mix in industry sector (%) 

Share of H2 in energy mix in buildings (%) 

H2 as fuel for transport (%) 

FCEV in passenger vehicle stock (%) 

2030 

2050 

0 

0 

0 

2 

7 

5 

15 

25 

In addition to the applications listed in this table, hydrogen is expected to play an increasing role in 
large-scale energy storage in grids to balance the intermittent nature of renewable electricity. 
Projected market deployment figures for large scale hydrogen storage are not available at present.  

The rate of progress in FCH technology deployment is complex as it varies across a range of 
technology applications and geographical regions with different policies and incentives for promoting 
market penetration. In the last years, fuel cell markets for stationary generation, backup power, and 
material-handling applications continued to expand as the operational effectiveness and efficiency of 
the technologies increases. Industrial interest is steadily rising for other applications where FCH 
technologies still need to improve performance and reduce cost to be competitive with the 
capabilities and cost of incumbent technologies. A 2012 McKinsey survey among EU stakeholders40 
identifies the following years for “major FCH applications to become commercial”: 

39 IEA, Energy Technology Perspectives 2012 – Pathways to a Clean Energy System 
40 Survey results on the trends in terms of investments, jobs and turnover in the Fuel Cells and Hydrogen sector – 

McKinsey, Oct. 2012 

45 

 
 
 
 
 
 
                                                            
transport 

cars 

buses 

material handling vehicles 

auxiliary power units 

refuelling stations 

energy 

power generation 

industrial CHP 

domestic CHP 

backup/UPS 

portable 

H2 production  

large scale electrolysis 

from biofuels 

from conventional fuels 

H2 storage 

mass storage for electricity 

2015 

2016 

2014 

2017 

2015 

2016 

2017 

2017 

2013 

2015 

2015 

2016 

2016 

2018 

Respondents to the survey indicated that the expected turnover till 2020 will grow strongest in the 
area of hydrogen production and storage. 

In line with these expected dates of commercialisation, industry has started transitioning away from 
primarily R&D-based to becoming commercial. In 2012 the global turnover for fuel cells and 
hydrogen has reached more than US$ 1 billion41, up from US$300 million in 200542, with the highest 
growth in the stationary sector. The market is expected to be worth $15.7 billion in 201743, and a 
recent US study estimates that the global market could be between US$ 43 billion and US$ 139 
billion annually over the next 10 to 20 years44.. In the market segment with the highest visibility, 
namely passenger vehicles, a recent study45 shows the following figures: 

41 Pike Research, The Fuel Cells and Hydrogen Industries: 10 trends to Watch in  2013 and Beyond 
42 2007 FCH JTI Impact Assessment 
43 Pike Research, Fuel Cells Annual Report 2012 
44 US DoE Hydrogen and Fuel Cells Program Plan, September 2011  
45 Polymer Fuel Cells – cost reduction and market potential, Carbon Trust, Sept. 2012 

46 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
                                                            
2020 

2030 

2040 

Number FCEV EU 

0.44-0.9 M 

9.0-16.0 M 

66.1-92.4 M 

(0.1-0.3%) 

(3.4-6.0%) 

(24.7-34.5%) 

Number FCEV global 

1.9-3.8 M 

43-77 M 

491-691 M 

(0.1-0.3%) 

(3.3-6.0%) 

(24.4-34.4%) 

PEMFC market value EU 

$bn 1.14-1.5 

$bn 14.2-19.5 

$bn 30.6-34.5 

PEMFC market value global 

$bn 4.1-6.1 

$bn 68-94 

$bn 231-261 

11.2.  Technology needs 

FCH technologies are not stand-alone technologies, but performant enablers for energy generation, 
conversion and use processes in the power, transport and industrial sectors. Because of their cross-
cutting application potential, and the associated need for including them in the relevant energy 
chains, it is very difficult to quantify the contributions of FCH technologies to the market trajectories 
for 2020, 2030 and 2050 of energy technologies covered in the SET-Plan.  

As indicated above, commercial roll-out of a number of FCH technologies is expected in the 2015-
2020 time frame. Evolution beyond 2020 is assessed through technology forecasting: integrating 
growth models with bibliometric analysis of publications and patent data available till end-2008, 
development curves (growing-maturing-saturating) obtained for “generic” FCH technologies are 
shown in the figure below46. 

2040
2040

2020
2020

2000
2000

1980
1980

1960
1960

growing
growing

maturing
maturing

saturating
saturating

H2 generation
H2 generation

H2 storage
H2 storage

PEMFC
PEMFC

SOFC
SOFC

In line with present experts’ assessments of the status of FCH technologies, the analysis shows that 
fuel cells have progressed further in their development, whereas hydrogen production, and 
particularly hydrogen storage still have a way to go. Considering the model-extrapolated date for 

46 Chen et al., IJHE, 36(2011)6957-6969 

47 

 
 
 
 
 
 
                                                            
reaching saturation, fuel cell technologies, resp. hydrogen technologies are expected to reach 
volume market penetration in the 2020, resp. 2030 time frame.  

To achieve volume market penetration, the technology advances needed are both incremental and 
stepwise. Incremental performance improvements are required in electric conversion efficiency and 
durability of fuel cells and in efficiency of conventional hydrogen production, both for central and for 
distributed generation. For hydrogen transport and delivery, energy requirements for compression 
and/or liquefaction should decrease and material compatibility issues addressed. To reduce costs, 
these incremental performance improvements must be accompanied by the establishment of large-
number manufacturing capabilities.  

Step-increases in capacity and performance are needed for hydrogen production methods. This 
covers the application of CCS to production from fossil fuels, biomass gasification, new emission-free 
production processes such as low temperature solar, fermentation and photo-electrochemical 
processes, as well as efficient MW-size electrolysers for intermittent large-scale hydrogen production 
from excess renewable energy. Also for on-board hydrogen storage incremental progress is unlikely 
to be successful: novel on-board storage technologies (hybrid gas and solid state, cryocompressed) 
are needed for meeting costs and energy density targets in order for FCEVs to become fully 
competitive with future efficient passenger cars.  

With maturity of FCH technologies expected to be reached in the 2020-2030 time frame, moving 
towards the 2050 deployment status will primarily depend on a timely and successful integration of 
hydrogen and fuel cells in appropriate locations of the energy, transport and industry chains, and in 
their contribution in facilitating the interconnection of these chains (e.g. power2gas). The 
identification and exploitation of the integration potential of FCH technologies in linking these chains 
require a regionally-diversified systems approach and consideration and exploitation of other 
technologies, in particular ICT. 

11.3.  Cost reductions  

Cost reductions go hand in hand with progress in performance and with technology learning. In 
terms of efficiency, durability, safety and emissions, FCH technologies are already competitive with 
incumbent technologies in a number of applications. However, notwithstanding considerable 
progress over the last years, cost-competitiveness has not yet been achieved and cost reduction is 
now a major driver in technology development. Expected cost evolutions for major FCH technologies 
compiled from different sources are shown in Figure 11.1. The projected cost reductions are related 
to incremental technology performance improvements in efficiency and durability and level off as 
technology maturity is reached. Cost reduction factors of 2-3 from the current level are expected, 
with further cost decreases relying on large-number manufacturing. Cost projections cannot be 
included for technologies which still require a step-increase in capacity and performance.  

48 

 
 
 
Evolution of capital costs for hydrogen production

2030 projected costs for centralised hydrogen production
2030 projected costs for centralised hydrogen production

5.00

4.00

3.00

2.00

)
y
a
d

/
t
(
/

M

1.00

0.00

2005

2010

2015

2020

2025

centralised reforming 200t/d

centralised electrolysis

small scale electrolysis

small scale reforming biogas

2
2
H
H
-
-
g
g
k
k
€/
€/

6
6

5
5

4
4

3
3

2
2

1
1

0
0

SMR
SMR

SMR with
SMR with
CCS
CCS

IGCC with
IGCC with
CCS
CCS

coal
coal
gasification
gasification
with CCS
with CCS

alkaline
alkaline
electrolysis
electrolysis

range for
range for
plant gate 
plant gate 
costs
costs

cost evolution H2 delivery

fuel cell system cost for stationary applications

18

16

14

12

10

8

6

4

2

2
H

-
g

k

/

0
2005

centralised: prod+storage+distr

centralised: total plant gate costs

decentralised electrolysis: prod

decentralised electrolysis: plant
gate

decentralised reforming: prod

decentralised reforming: plant gate 

2010

2015

2020

2025

2030

2035

DoE target ($/kg)

10000

8000

6000

4000

2000

0
2005

MCFC (€/kW)

PEMFC (€/kW)

AFC (€/kW)

industrial, H2 (€/kW)

industrial, NG (€/kW)

stationary ($/kW)

industrial CHP ($/kW)

residential (€/kW)

resid., PEM, NG ($/kW)

resid., SOFC, NG ($/kW)

back-up (€/kW)

2010

2015

2020

2025

2030

2035

Figure 11.1: Trends in cost reductions for FCH technologies 

11.4. 

Soft measures influencing deployment 

Accompanying measures, in addition to support for research, development and technology 
innovation, are needed to address barriers and/or challenges faced by FCH industries, which lie at 
four main levels: 

•  The  potentially  huge  environmental  and  energy  security  benefits  of  FCH  applications  accrue  to 
society  at  large  and  are  difficult  to  be  monetized  by  individual  technology  providers  and 
consumers.  

•  FCH  technologies  must  compete  globally  with  well-established 

incumbent  technologies. 
Continued cost reduction for enlarging market share requires significant investment in advanced 
manufacturing  processes.  Consequently  the  financial  risk  for  early  movers  is  high  and  lack  of 
cash-flow during the first phase of deployment is to be expected.  

•  The  FCH  sector  is  dispersed  across  different  activity  areas  (energy,  transport,  industry, 
residential),  actors  and  countries,  which  hampers  the  build-up  of  critical  mass  needed  for  self-
sustained commercial activity.  

•  Mass  volume  deployment  of  FCH  technologies  beyond  2030  critically  depends  on  their  timely 
and  successful  integration  in  energy,  transport  and  industrial  chains.  In  particular,  the 
deployment  of  large-scale  hydrogen  storage  within  the  power  generation  system  is  considered 
very challenging.  

Market forces alone are insufficient to overcome these barriers. Hence a purpose-oriented coherent 
framework consisting of tailored and time-phased actions, policies and incentives that target public 
and private market actors, is needed. The following components of such a framework can be 
identified: 

49 

 
€
 
 
€
 
 
 
 
•  Globally harmonised standards and regulations to ensure safe, compatible and interchangeable 

technologies and systems. This will also contribute to cost reduction.  

• 

Increased awareness among the public, among private and public actors in the energy, transport, 
industrial  and  residential  sectors,  and  among  policy-makers  at  local,  regional,  national  and  EU 
level, of the performance potential and societal benefits that hydrogen as flexible energy carrier 
and  fuel  cells  as  modular  and  highly  efficient  energy  converters  offer  over  incumbent 
technologies. 

•  Policy  measures  that  value  the  societal  benefits  and  ensure  a  level  playing  field  enabling  the 
uptake  of  FCH  technologies,  including  public  financial  support,  in  particular  for  infrastructure 
development in the energy and transport sectors.  

• 

Improved  alignment  of  views  and  coordination  of  activities  of  private  FCH  stakeholders  and 
public institutions, aiming at equitable risk-sharing particularly in the stages of initial commercial 
roll-out. 

•  New business models that allow the deployment of large scale hydrogen storage in future smart-

grid based energy systems 

50 

 
12. 

ELECTRICITY STORAGE TECHNOLOGIES 

12.1.  Market evolution 

The market for electricity storage can be broadly divided in two segments: large scale storage 
used  for  energy  time  shifting  on  transport  grid  level  and  decentralised  storage  supporting 
services  on  distribution  grid  level.  Currently,  the  market  is  comprised  mainly  of  the  first 
segment which is dominated by the mature technology of pumped hydro. The equally mature 
compressed air energy storage (CAES) has not yet been deployed on a large scale. Roughly 
42  GW  of  pumped  hydro  storage  are  currently  installed  in  Europe  (EU  combined  with 
Switzerland,  Norway  and  Turkey)47  with  an  additional  capacity  of  5.5  GW  under 
construction.48 Only two CAES facilities exist worldwide of which one is located in the EU 
(Huntorf, Germany build in 1978); and the second one was built in Alabama, USA in 1991. 
Three  new  grid  scale  CAES  projects,  one  of  which  in  the  EU  are  in  an  advanced  state  of 
development or have secured financing. The potential for new pumped hydro or compressed 
air  energy  storage  in  Europe  could  be  more  than  four  times  the  current  capacity49.  Market 
needs  however  are  likely  to  be  smaller  if  competing  sources  of  flexibility  are  taken  into 
account: studies see an additional 50% 50 to 100% of installed capacity by 205051 i.e. 20 – 40 
GW of additional bulk storage for Europe. 

The currently less developed market for decentralised storage technologies such as batteries is 
driven by developments on the level of power distribution and consumption. A trigger for the 
mass  deployment  of  (Li-ion)  batteries  would  be  the  electrification  of  road  transport.  This 
could  make  battery  storage  available  for  grid  applications:  both  directly  in  the  form  of 
vehicle-to-grid concepts or in form of grid-connected Li-ion (or more conservative lead acid) 
batteries.  Other  \technologies  such  as  NaS  batteries,  Redox-flow  batteries,  or  flywheels  are 
currently deployed in pilot projects competing with lead-acid and Li-ion systems for provision 
of  grid  services.  Even  though  hydrogen  does  not  play  a  significant  role  in  the  current 
electricity  system,  it  offers  the  broadest  spectrum  of  potential  applications  of  all  storage 
technologies:  from  stand  alone  systems  comprised  of  electrolysers  and  fuel  cells  to  an 
integrated  power-to-gas  concept  allowing  the  transport  and  storage  of  wind  energy  from 
coastal regions to the inland consumption centres 52. 

12.2.  Technology needs  

Pumped Hydro storage 

Pumped hydro storage, as well as hydropower in general, is a mature technology, now used 
for more than 100 years. It is the only storage technology deployed on a large scale today.  

Compressed Air Energy Storage (CAES) 

47 Eurelectric: Hydro in Europe, powering renewables 
48 Source: Platts 
49 The  STORE project identifies 180 GW of additional PHS capacity in Europe, www.store-project.eu 
50  EWI:  ‘Flexibility  options  in  European  electricity  markets  in  high  RES-E  scenarios,  Study  on  behalf  of  the 

International Energy Agency (IEA), 2012. 

51 Eurelectric Power Choices 
52 See e.g. the Power to Gas Initiative launched by the German Energy Agency dena: 

http://www.powertogas.info 

51 

 
 
 
 
 
                                                            
CAES  is  a  technology  made  of  mature  building  blocks.  The  concept  is  based  on  the 
compression of air by means of electric energy, storing the compressed air in an underground 
cavern and expanding the air, now mixed with natural gas in a combustion chamber to drive a 
gas  turbine.  Alternatively,  in  an  adiabatic  CAES,  the  expanding  air  recovers  the  heat 
generated  during  compression  from  a  thermal  storage  so  no  natural  gas  is  needed  in  the 
process.  Demonstrating  the  Adiabatic  CAES  on  large  scale  is  the  main  R&D  target  for  this 
technology.  The  ADELE  project  (located  in  Stassfurt,  Germany)  aims  at  developing  a  360 
MW generation plant with 3h of storage.  

Batteries 

Storage  in  form  of  electrochemical  batteries  is  occasionally  deployed  in  electricity  grids, 
mainly for short time action such as frequency control. There is a large variety of mature to 
innovative  technologies  that  can  be  classified  by  their  chemical  composition.  The  most 
prominent of these are: 

-  Lead-acid batteries are a mature technology mainly found as starter batteries in car. This 
technology is increasingly deployed for power grid applications such as capacity firming or 
spinning  reserve.  The  main  R&D  goal  is  to  improve  the  lifetime  in  terms  of  discharge 
cycles. 

-  Li-ion  batteries  represent  the  state  of  the  art  in  small  rechargeable  batteries.  They  are 
widely used in consumer electronic devices, such as computers, digital cameras, and cell 
phones,  as  well  as  military,  space  and  electric  vehicles.  Recently,  Li-ion  systems  in  the 
range of up to 1 MW have been installed by ENDESA to provide frequency control in the 
Canary Islands53.  

-  NaS  batteries  are  used  for  stationary  grid  applications.  A  system  with  1MW  is  currently 
tested in the Pegase demonstration project on Reunion Island, launched in 2011. The aim is 
to provide mainly frequency control to a system with a high share of PV and wind power 
generation. 

-  Flow  batteries  (Zn-Br,  Vanadium  Redox)  separate the electrolyte from the  cell  stack and 
thus  decouple  the  power  system  from  the  energy  capacity.  The  storage  capacity  can  be 
increased  by  adding  more  electrolytes  allowing  discharge  rates  of  up  to  10  hours.  This 
technology  could  therefore  also  be  a  candidate  for  time  shifting  services.  A  total  of  54 
demonstrator  projects55  have  already  been  deployed  in  Europe,  the  US,  Japan,  Australia 
with 7 more projects to be realised, all of them located in the USA.  

Hydrogen 

R&D  measures  focus  on  the  entire  hydrogen  value  chain.  The  main  goals  are  the 
demonstration  of  feasibility,  optimisation  of  possible  concepts  and  most  important  the 
achievement of cost competitiveness. Further details are given in the chapter on hydrogen and 
fuel cell technologies. 

Flywheels 

53 http://www.endesa.com/en/saladeprensa/noticias/Documents/agosto12-Proyecto%20Store1%20(DEF)-en.pdf 
54 Source: Bloomberg New Energy Finance 
55 Source: Bloomberg New Energy Finance 

52 

 
 
 
 
                                                            
Flywheels  for  electricity  grids  are  currently  a  niche  technology.  They  store  energy  in 
mechanical form, i.e. in rotating masses. With storage capacities typically in the range of 15 
min  and  almost  immediate  response  capability,  they  are  suitable  for  frequency  control.  One 
particular  application  is  in  small  or  remote power  systems  with  intermittent  RES-E.  Endesa 
initiated  the  construction  of  a  flywheel  in  the  Canary  Islands  with  a  maximum  power  of 
0.5MW providing 18MWs of energy as a complement to the abovementioned Li-ion storage 
project.  

Other storage technologies 

Further  storage  technologies  are  superconducting  magnetic  energy  storage  and  super 
capacitors. The first technology stores energy in magnetic, the second in electric fields. The 
advantage  of  both  technologies  is  to  store  electricity  directly  allowing  very  fast  response 
times. Those technologies are in early phases of demonstration. 

12.3.  Cost reductions 

The  Figure  12.1  shows  the  current  range  of  costs  (in  €/kW  of  rated  power)  for  storage 
technologies  in  different  stages  of  maturity  distinguished  between  power  generation, 
transmission  &  distribution  and  end-user  application.  Additional  costs  (not  shown  in  the 
Figure)  arise  from  the  energy  reservoir  of  the  storage  and  are  given  in  €/kWh.  Costs  for 
mature technologies are rather well understood while technologies that were only occasionally 
deployed  in  the  past  or  are  in  different  stages  of  demonstration  phases  bear  a  high  level  of 
uncertainty. 

Figure 12.1: Cost of storage technologies. Source: SETIS Technology Map – 2011 update 

Pumped Hydro storage 

Costs for pumped hydro stations are in the range of 500 -3600 €/kW for the power production 
equipment  and  60  –  150  €/kWh  for  the  reservoir.  The  large  range is given by costs  of  civil 

53 

 
 
 
  
works  which  may  vary  depending  on  the  geographical  conditions.  Stable  costs  can  be 
assumed as this is a mature technology. 

Compressed Air Energy Storage 

The costs of this technology are given by the compressor and turbine and the excavation of 
the storage cavern. Estimates range between 400 - 1150 €/kW for the power conversion unit 
and 10 – 120 €/kWh for the storage unit. All co mponents of such a system are mature today, 
however the system integration may leave room for cost improvements over time. 

Batteries 

Lead-acid batteries are the most economically attractive technology for decentralised storage 
with power costs of 200 - 650 €/kW and energy co sts of 50 - 300 €/kWh. The maturity of the 
basic  concept  and  the  dependency  on  lead  as  a  commodity  leaves  room  for  cost  reductions 
mainly in the power electronics block so assuming constant cost would be safe. 

With power costs of 700 – 3000 €/kW and en ergy cost of 200-1800 €/kWh, Li-ion batteries 
cost more than double than lead-acid batteries with estimates spreading widely. Prices are set 
on a highly competitive market. Some financial analysts see prices to fall to the lower end of 
the  range  implying  current  overcapacities  and  anticipating  a  shakeout  resulting  in  a  further 
market consolidation56. 

As  NaS  batteries,  flow  batteries,  hydrogen  systems  and  flywheels  –  while  commercially 
available - are currently restricted to a very limited market.  

12.4. 

Soft measures influencing deployment 

R&D support for storage technology 

Direct  financial  support  would  help  develop  less  mature  technologies  and  unlock  their 
untapped  technological  potential.  Different  storage  technologies  are  not  necessarily  in 
competition with each other if they are able to provide different services and in particular if 
they can be used in different value chain steps of the power system, The dynamic evolution of 
the future power system including more intelligent and complex distribution networks could 
benefit from a portfolio of storage technologies. For this reason an equal and fair support to 
less  mature  technologies  according  to  cost-efficiency  criteria  could  be  beneficial  for  the 
development of technologies.  

Support to large scale storage investments 

In  the  current  environment  consisting  of  depressed  demand,  relatively  low  commodity  and 
carbon  prices  and  an  increasing  supply  of  RES-E,  the  arbitrage  business  case  faces  severe 
challenges  such  as  investments  in  peak  power  generation  in  general.  Also  lower  prices  for 
natural  gas  over  longer  time  periods  could  challenge  the  time  shifting  business  as  storage 
competes with gas turbines for a number of services. The currently strained finances of some 
potential investors combined with a regulatory framework that does not always recognise the 
role  of  storage  in  the  transition  to  a  decarbonised  power  system,  are  a  major  barrier  to  the 
deployment of this technology. For this reason direct support to investments, together with the 
setting up of market mechanisms to recover investments, e.g. capacity payments, could lower 

56 http://www.rolandberger.com/media/pdf/Roland_Berger_Li_Ion_Batteries_Bubble_Bursts_20121019.pdf 

54 

 
 
 
 
 
                                                            
the burden for investment decisions. A number of Member States have started to address this 
problem  by  considering  the  introduction  of  capacity  payments  to  plants  and  the  European 
Commission has launched a public consultation on that matter57. Moreover, revisited RES-E 
incentive  schemes  that  adapt  dynamically  with  progressive  high  RES  deployment  and  take 
power system needs into account could be an additional measure.  

Competition of storage with other solutions 

Storage is one of several instruments able to provide flexibility to a system with a high share 
of RES-E. It competes with other technologies such as flexible fossil fuel generation, demand-
side response technologies, grid extension allowing power flows over larger regions, or a non 
usage of some of the excess RES-E as anticipated by a number of studies on systems with a 
very  high  degree  of  RES-E58.  Competition  in  this  sector  is  a  source  of  efficiency,  which 
would  benefit  from  a  level  playing  field  for  the  different  technologies.  Market  distortions, 
resulting  from  support  of  particular  technologies  to  the  detriment  of  others  bear  the  risk  to 
promote and perpetuate sub-optimal technological solutions.. 

Regulatory ambiguities 

One  particular  challenge  originates  from  the  fact  that  storage  can  provide  a  number  of 
different services for both generation (e.g. peak shaving through arbitrage) and transmission 
(e.g.  reserve  power,  congestion  management).  Storage thus falls into both the regulated and 
the  unregulated  domain  of  European  energy  markets.  The  risk  that  storage  installations 
providing  services  to  the  regulated  domain  would  act  as  a  non-regulated  agent  (and  vice 
versa)  has been  identified and addressed by different stakeholders59.  Adequate measures  for 
promoting  storage  need  to  be  created  if  such  conflicts  of  interest  are  to  be  avoided,  in 
particular: regulate potential cases of abuse of asymmetric information e.g. from transmission 
and distribution system operators, and guarantee the unbundling of the power system. 

57 http://ec.europa.eu/energy/gas_electricity/consultations/20130207_generation_adequacy_en.htm 
58 See e.g. abovementioned EWI-IEA study 
59  See  e.g.  http://www.eurelectric.org/media/53340/eurelectric_decentralized_storage_finalcover_dcopy-2012-

030-0574-01-e.pdf 

55 

 
 
                                                            
13. 

 ELECTRICITY NETWORKS TECHNOLOGIES 

13.1.  Market evolution 

The  electrical  network  is  usually  divided  into  the  longer  distance  and  higher  voltage 
transmission network and the medium distance and lower voltage distribution network. In this 
framework, the synergies in the evolution towards a smart distribution grid and to a smarter 
transmission network are crucial, considering the steep changes to occur at distribution level, 
simultaneously  with  the  introduction  of  new  technologies  and  the  development  of  further 
interconnections  at  transmission  level.  Therefore,  in  order  to  take  advantage  of  those 
synergies, the coordination of their evolution is crucial.  

Advanced electricity networks not only allow for a higher intake of variable RES generation, 
but  also  entail  an  increase  in  energy  efficiency,  thanks  to  the  effective  integration  of  ICTs. 
Smart grids provide, in this framework, critical options for the development of the present and 
future  European  energy  infrastructure60.  Advanced  electricity  networks  will  require  the 
deployment  of  many  different  technologies:  from  power  electronics  to  communications 
protocols. Smart meters, which provide utilities with a secure, two-way flow of data, are a key 
component for smart grids, but alone do not assure its development. 

Furthermore, it is worth noting that electricity networks should be considered in the context of 
the  relative  markets  and  the  various  stakeholders  interconnected.  Smart  grids  support  the 
development  of  the  electricity  markets,  enabling  the  unbundling  of  the  operators,  providing 
more capable cross-border links, and supporting the involvement of all the stakeholders, down 
to  the  consumer/prosumer  level.  Moreover,  they  create  establish  a  platform  for  the  existing 
and future entrants in the market to develop innovative energy services. 

The evolution of electricity networks in the next decades will be determined by several factors 
(which at the same time will be enabled by suitable networks): 

o 

o 

o 

the deployment of sustainable energy resources, given that the share of renewable energy 
sources  (RES)  in  EU-27  gross  power  generation  is  expected  to  more  than  double,  from 
14.3% to 36.1%, between 2005 and 2030; 

the optimal integration of distributed generation (DG), distributed energy storage systems 
(DESS) and demand side management (DSM) systems. 

the  integration  of  electric  vehicles  (EV),  their  magnitude  in  terms  of  load  and  general 
energy consumption, and their potential use as a storage medium 

13.2.  Technology needs 

In terms of the several components for smart grids, the maturity of the industrial proposals has 
been  expanding  in  the  last  few  years.  The  most  immediate  challenges  are:  1)  the  smart 
integration  of  distributed  renewables  and  the  empowerment  of  open  and  dynamic  retail  and 
services  markets  at  the  distribution  level,  and  2)  the  reliable  long-distance  transport  and 
balancing  of  massive  amounts  of  renewable  electricity  at  the  transmission  level.  From  the 
viewpoint of technologies, the following appear to play a decisive role: 

1.  Technologies  for  long-distance  connections,  including  High  Voltage  Direct  Current 
(HVDC) grid technologies. HVDC, has advantages over high voltage alternating current 
in  terms  of  long  distance  and  underwater  transmission,  featuring  few  losses,  increase  in 
transmission  capacity,  quick  change  in  power  flow  direction,  and  no  increase  of  short-

60 European Commission, 2010a. COM(2010) 677 final - Energy infrastructure priorities for 2020 and beyond - 
A Blueprint for an integrated European energy network, European Commission, 2010. 

56 

 
 
                                                            
circuit  power  at  the  connection  points.  HVDC,  both  point-to-point  and  the  under-
development  multi-terminal  HVDC,  are  building  blocks  needed  for  the  development  of 
future electricity networks, enabling e.g. offshore wind farms. 

2.  Technologies  for  increasing  the  controllability  of  the  networks,  including  Flexible  AC 
Transmission Systems (FACTS), which are advanced power electronics devices that allow 
increased  efficiency  at  several  levels  (e.g.,  transmission  capacity,  power  flow  control, 
losses reduction, voltage support). FACTS, already in use in transmission lines, are in the 
process of being deployed also at distribution level under the designation of D-FACTS or 
Custom  Power.  In  terms  of  synergies  between  technologies,  the  case  of  the  joint 
deployment  of  energy  storage  and  FACTS  is  well  documented.  This  synergy  allows  the 
optimization of the power transfer capacity ratings and higher flexibility in the network. 

3.  Technologies for enabling new grid and consumer-driven services, including: 

includes 

a)  ICT/telecom  networks,  essential  for  the  deployment  of  smart  grids,  since  they 
empower  the  effective  communication  between  all  interconnected  actors  and 
technologies, 
components.  It 
centralised or decentralised data management systems and solutions for the processing 
of  metering  data.  An  enhanced  data  exchange,  with  dedicated  ICT  platforms 
supervising  the  information  flows  between  the  electricity  system  players,  may 
strengthen the capabilities for fault prevention, asset management, generation control 
and demand side participation, among others. 

telecommunication  and  remote  control 

b)  Smart  metering,  which  empower  both  distribution  utilities  and  producers-consumers 
(prosumers),  who  can  gain  greater  awareness  of  their  consumption  and  generation. 
Positive  results  are  more  efficient  consumption,  e.g.  benefiting  of  real  time  price 
responsiveness,  and  in  load  shifting  according  to  the  needs  of  the  power  system. 
Installation of smart meters coupled with Demand Side Management (DSM) enables 
the rationalisation of energy consumptions, supporting a more responsive and flexible 
load. DSM will play an important role in load shifting and peak shaving; it demands 
bidirectional communication and a partial control of some of the customer resources, 
usually  heavy  loads.  The  deployment  of  DSM  is  an  important  step  for  the 
economically  sustainable  power  balancing  of  the  future  smart  grids,  particularly  in 
extreme situations. 

4.  Future planning, operation and maintenance approaches, including: 

a)  Innovative  smart  grid  architectures  such  as  active  distribution  networks,  microgrids, 
and  virtual  power  plants.  These  have  different  characteristics,  which  may  overlap 
sometimes.  Active  distribution  networks,  including  microgrids,  include  DG,  ICT 
technologies,  distributed  energy  storage,  appropriate  protection  schemes,  power 
electronics,  such  as  D-FACTS,  and  demand  side  management.  Microgrids  present 
black start capability and/or intentional islanding mode features. Virtual Power Plants 
(VPP) can be divided in two subtypes. The technical virtual power plant (TVPP) uses 
resources  either  physically  connected  by  the  local  distribution  network  or  located  in 
the  same  geographical  area.  The  commercial  virtual  power  plant  (CVPP)  integrates 
resources that can be more dispersed, and that may even be linked to each other only 
at transmission level, being thus housed in separate distribution networks.  

b)  Technologies  and  business  processes  for  the  integration  of  Distributed  Generation 
(DG), renewable electricity, demand response, storage and electric vehicles, including 
new  market  architectures,  and  off-line  tools  for  forecasting,  asset  management,  grid 
development planning, development of emergency responses and training of operators. 
This should include relevant standards to ensure interoperability. Of relevance will be 

57 

 
multi-energy  grids  (e.g.  interconnecting  electricity,  gas,  heat).  DG’s  output  is  not 
constant  as  it  may  vary  with  natural  resources  changes  or  with  the  thermal  output 
desired for combined heat and power (CHP) systems. 

13.3.  Expected cost and benefits 

The  evolution  of  the  power  networks  in  support  of  the  European  strategy  towards  a  low-
carbon energy future will require significant investments. Given the economic potential of the 
Smart  Grid  and  the  substantial  investments  required,  there  is  a  need  for  a  methodological 
approach to estimate the costs and benefits of Smart Grids, based as much as possible on data 
from Smart Grid pilot projects.  

The Commission ‘Proposal for a Regulation of the European Parliament and of the Council 
on Guidelines for Trans-European Energy Infrastructure’ (Com/2011/658) proposed as one of 
the  criteria  of  eligibility  for  Smart  Grid  projects  their  economic,  social  and  environmental 
viability,  which  calls  for  a  definition  of  a  comprehensive  impact  assessment  methodology, 
including a CBA. The survey on Smart Grid projects across Europe carried out by the JRC in 
2011 and 2012 concluded that there are only a few projects that have conducted some form of 
CBA.  Though  many  studies  have  touched  upon  the  subject  of  Smart  Grid  benefits,  it  is 
difficult  to  find  studies  which  have  attempted  to  develop  a  systematic  approach  to  the 
definition  and  evaluation  of  the  costs  and  benefits  of  Smart  Grid  projects  and  which  have 
tested their approach on real case studies. 

While some projects may not have shared their data for confidentiality reasons, many others 
simply did not have such data because a detailed CBA was beyond the scope of the project, 
which  often  predominantly  focused  on  evaluating  technologies,  applications  and  solutions. 
Another reason may be the lack of an established CBA methodology for Smart Grid projects. 
For  that  reason  JRC  issued  in  2012  “Guidelines  for  conducting  a  Cost-Benefit  Analysis  of 
Smart Grid projects”. 

This  lack  of  formal  evaluation  of  Smart  Grid  projects  based  on  their  investment  needs  and 
resulting benefits has been linked to three main reasons61: 

o  Smart  Grid  projects  are  typically  characterised  by  high  initial  costs  and  benefit  streams 
that  are  uncertain  and  often  long  term  in  nature.  In  fact,  many  Smart  Grid  benefits  are 
systemic in nature, i.e. they only come into play once the entire smart electricity system is 
in place and new market players have successfully assumed their roles.  

o  Smart  Grid  assets  provide  different  types  of  functions  to  enable  Smart  Grid  benefits.  A 
variety of technologies, software programs and operational practices can all contribute to 
achieving a single Smart Grid benefit, while some elements can provide benefits for more 
than one Smart Grid objective in ways that often impact each other. 

o  The  active  role  of  customers  is  essential  for  capturing  the  benefits  of  many  Smart  Grid 
solutions.  Especially  at  this  early  stage  of  the  Smart  Grid  development,  consumer 
participation  and  response  are  still  uncertain  and  relevant  behavioural  information  (e.g. 
load profiles) is often not (yet) accessible to utilities. 

61  Jackson,  J.,  2011.  “The  Utility  Smart  Grid  Business  Case:  Problems,  Pitfalls  and  Ten  Real-World 
Recommendations”. Prepared for the 2nd Annual Evaluating the Business Case for Smart Grid Investments, 
20-21 October 2011, Orlando, US 

58 

 
 
 
                                                            
13.4. 

Soft measures – How to overcome the barriers to large-scale deployment 

Whilst  the  smart  grids  deployment  is  at  its  first  stage  in  Europe,  stakeholders  and  market 
players perceive multiple uncertainties and barriers. 

Standards are crucial for the evolution of the market of electricity networks. It is expected that 
the  common  European  framework  that  will  result  from  the  mandate  M/490,  given  by  the 
European Commission to the European Standardization Organisations CEN, CENELEC and 
ETSI, will establish or update a set of consistent standards. This framework should integrate a 
variety  of  digital  computing  and  communications  technologies  and  electrical  architectures, 
and associated processes and services, achieving interoperability and enabling or facilitating 
the  implementation  in  Europe  of  the  different  high  level  Smart  Grid  services  and 
functionalities.  Resulting  from  the  mandate  M/490,  the  standardization  bodies  developed  a 
technical reference architecture, a first set of Use Cases mapped against standards, and a first 
set  of  consistent  standards.  These  standards  (with  reference  to  24  types  of  Smart  Grid 
systems,  including  more  than  400  standard  references,  and  coming  from  more  than  50 
different bodies). are a key step for the deployment of smart grids in Europe. 

Technically,  now  that  standards  have  been  identified,  there  is  an  increasing  need  for  the 
demonstration  of  the  interoperability  among  the  several  components  constituting  a  Smart 
Grid. From the smart meter, to the interaction between electricity grid and electric vehicles, 
full  interoperability  will  ensure  that  any  new  device  can  be  integrated  into  the  Smart  Grids 
system. 

The  regulatory  framework  is  also  perceived  as  a  significant  barrier  to  the  large  scale 
deployment  of  smart  grids:  it  is  generally  agreed  that  a  stable  and  predictable  regulatory 
context  would  allow,  among  others,  the  development  of  a  sound  financing  environment  for 
smart grid initiatives. This would also pave the way for new business models involving wider 
participation of consumers and prosumers in the market. Uncertainty and the need of building 
confidence  in  future  business  models  may  therefore be another consequence  of  a regulatory 
framework  that  presents  space  for  a  future  inclusion  of  smart  grid  features.  Moreover,  it  is 
possible  to  identify  a  debate  arising  amongst  several  market  stakeholders  concerning  the 
control of the different assets involved. Furthermore, regulation can also mitigate the impact 
of high level initial costs, which hinder the short term deployment of smart grids, due, among 
others,  to  the  traditional  conservative  approach  from  utilities.  To  solve  this  issue  a  more 
secure  investment  environment  for  utilities  with  long-term  quantifiable  benefits,  including 
revenues coming from grids enhancement, would be helpful.  

Social barriers, besides technological and regulatory barriers, aggravate the general situation. 
On  one  hand,  there  is  a  need  for  information  about  smart  grids  and  their  features  that  can 
trigger  consumer  awareness  and  engagement,  which  in  turn  can  enable  faster  and  more 
effective  deployment  of  smart  grids  (as  an  exemplary  initiative,  a  smart  grid  contest  was 
launched in 2011 to “accelerate and encourage open innovation and build up the international 
Smart Grid community”). On the other hand, concerns about consumers’ protection, both in 
terms  of  privacy  and  security  need  to  be  taken  in  consideration.  The  expected  roll  out  of 
extensive smart grid programmes in Europe calls for a continuous development of skills and 
knowledge,  through  a  wide  and  effective  communication  to  the  public  and  the  workforce. 
Finally,  efforts  in  overcoming  the  barriers  perceived  would  be  vain  without  coordination 
among  all  the  actors  involved  (policy-makers,  researchers,  industry  and  finance  players, 
consumers). 

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14. 

ENERGY INTENSIVE INDUSTRIES 

Technology developments can assist the European energy intensive industry to reduce its energy 
consumption and carbon footprint. This chapter focuses on three important European industries, the 
iron & steel, the pulp & paper and the cement sectors.  The greenhouse gas (GHG) emissions from 
the iron and steel industry during the period 2005 to 2008 on average amounted to 252.5 Mt CO2 eq. 
In 2008 the CO2 emissions from the pulp and paper and in the cement industry amounted to 38 Mt 
and 157.8 Mt CO2, respectively. The emissions of these three energy intensive industries represented 
9% of the total CO2 emissions of the EU, or 44% of total CO2 emissions of the industry sector. 

14.1.  Market evolution 

14.1.1.  The iron and steel industry 

There are two main routes to produce steel. The first route is called the "integrated route", which is 
based on the production of iron from iron ore. The second route called “recycling route”, uses scrap 
iron as the main iron-bearing raw material in electric arc furnaces. In both cases, the energy 
consumption is related to fuel (mainly coal and coke) and electricity. The recycling route has 
significantly lower energy consumption (by about 80%).  

The "integrated route" relies on the use of coke ovens, sinter plants, blast furnaces and basic oxygen 
furnace converters. Current energy consumption for the integrated route is estimated to lie between 
17 and 23 GJ per tonne of hot-rolled product. The lower value is considered by the European sector 
as a good reference value for an integrated plant. A value of 21 GJ/t is considered as an average 
value throughout the EU. The “recycling route” converts scrap iron in electrical arc furnaces. Current 
energy consumption for this case is estimated to lie between 3.5 - 4.5 GJ per tonne of hot-rolled 
product. The lower value corresponds to a good reference plant. The higher value corresponds to 
today's average value within the EU.  

Alternative  product  routes  to  the  two  main  routes  are  provided  by  direct-reduced  iron 
technology (which produces substitutes for scrap) or the smelting reduction (which like the 
blast  furnace  produces  hot  metal).  The  advantage  of  these  technologies  compared  with  the 
integrated route is that they do not need raw material beneficiation, such as coke making and 
sintering and that they can better adjust to low-grade raw materials. On the other hand, more 
primary fuels are needed, especially natural gas for direct reduced iron technology and coal 
for smelting reduction.  

The growth of the EU27 iron and steel production can be estimated to be 1.18% per year up to 2030. 
This would imply a production of around 260 Mt crude steel in 2030. The increase in the production 
is estimated to be covered mainly by an increase in the recycling route. The production from the 
integrated route will stay around their current values. 

Today, over 40% of steel is traded internationally and over 50% is produced in developing countries. 
In 1998, the EU was responsible for 23% of global steel consumption, whereas in 2008 its share in 
consumption had dropped to 16% due to the increase in the demand for steel in the developing 
countries (i.e. China, India and Russia). Apparent crude steel consumption in the EU increased at an 
average rate of 2% in the period of 2000-2008, but it fell drastically in 2009 by around 30% due to the 
financial crisis. The production of crude steel in the EU in 2008 was 198 Mt, representing 14.9% of 

60 

 
 
the total world production (1327 million tonnes of crude steel). Ten years earlier, with a slightly 
lower production (191Mt crude steel), the same European countries accounted for a 24.6% share. 
The main difference is that the Chinese production grew more than fourfold over this period (from 
114 Mt to 500 Mt crude steel).  

14.1.2.  The pulp and paper industry  

There are two main routes to produce different types of pulp: from virgin wood or from recycled 
material. The pulp produced in either way is subsequently processed into a variety of paper products. 
For virgin pulp making, two main kinds of processes are used – chemical and mechanical pulp 
making. 

Recycled fibres are the starting point for the recycling route. Europe has one of the highest recovery 
and utilisation rates of fibres in the world (66.7% in 200862). There are large variations on the energy 
profiles for different technologies. Raw wood use differs by almost four times between the different 
paper grades, and energy use differs by a factor of two. However, in general terms, it can be said that 
mechanical pulp making is more electricity-intensive and less heat intensive than chemical pulping. 
The electricity/steam consumption ratio at paper mills enables an efficient use of co-generation of 
heat and power (CHP). Nowadays its electricity production amounts to almost 46% of its electrical 
consumption. 

Specific primary energy consumption in 2008 was 13.4 GJ/t, based on the overall totals of energy and 
production data, this specific consumption includes 2.04 GJ/t of specific net bought electricity. Half of 
the energy used by the industry (54.4% in 2008) comes from biomass and approximately 38% from 
natural gas.  

In a business-as-usual scenario, there is still some room for improvement because the average values 
of the 10% of best performers (benchmark levels) have 50% and 30% lower specific CO2 emissions 
than the highest values and the average, respectively. However, tapping this potential improvement 
requires the replacement of today’s machines by new ones. However, due to the high cost of new 
machines, this will take time and is dependent on machine age, investment cycles, sector 
developments and availability of capital. The prime candidates for improvements are the boilers 
followed by the most energy-intensive part of the paper production, the drying of the paper.  

In 2008, the EU paper and board production (reported by the 19 CEPI-associated countries63) 
accounted for 25.3% (98.9Mt) of world production (North America 24.5% and Asia 40.2%). Europe 
also represents about 21.6% (41.6 Mt) of the world’s total pulp production. From 1991 to 2008, the 
EU pulp and paper production (in CEPI countries) had an average annual growth of 0.4% and 1.9% for 
pulp and paper respectively, whereas the number of pulp and paper mills has decreased around 40%. 
This process of consolidation of the sector has led to fewer and larger companies with a large 
number of relatively small plants specializing in niche markets. Overall, the pulp and paper sector 
keeps growing at a steady pace with a changing product mix and new grades developing as a 

62 Recycling rate: “Recovered Paper Utilization + Net Trade”, compared to Paper and Board Consumption  
63 CEPI is the Confederation of European Paper Industries (CEPI), and its mission is to promote the member’s 
business sector by taking specific actions notably, by monitoring and analyzing activities and initiatives 
in the areas of industry, environment, energy, forestry, recycling, fiscal policies and competitiveness in 
general.  Its  associated  countries  are:  Austria,  Belgium,  Czech  Republic,  Finland,  France,  Germany, 
Hungary,  Italy,  The  Netherlands,  Norway,  Poland,  Portugal,  Romania,  Slovak  Republic,  Slovenia, 
Spain, Sweden, Switzerland, United Kingdom  

61 

 
                                                            
consequence of long-term societal changes (tissue, because of the ageing population and hygiene 
needs, packaging, etc.). The situation of the sector in the future will also depend largely on the extent 
to which export markets advance, e.g. the competitiveness of the sector in a global perspective.  

14.1.3.  The cement industry  

Clinker, the main component of cement, is obtained throughout the calcination of limestone. 63% of 
the CO2 emissions emitted during the fabrication of cement come from the calcination process, while 
the rest (37%) is produced during the combustion of fossil fuels to feed the calcination process. Four 
processes are currently available to produce the clinker: wet, semi-wet, semi-dry and dry. The heat 
consumption of a typical dry process is currently 3.38 GJ/t clinker where 1.76 GJ/t clinker is the 
minimum energy consumption for the thermodynamic process, about 0.2 to 1.0 GJ/t clinker is 
required for raw material drying (based on a moisture content of 3 to 15%), and the rest are thermal 
losses. This amount (3.38 GJ/t clinker) is a little more than half of the energy consumption of the wet 
process (6.34 GJ/t clinker). The average heat consumption of the EU industry was 3.69 GJ/t clinker in 
2006. The average thermal energy value in 2030 can be expected to decrease to a level of 3.3 to 3.4 
GJ/t of clinker; this value can be higher if other measures to improve overall energy efficiency are 
pursued (cogeneration of electric power may need additional waste heat).  

Current European average of electrical consumption is 111 kWh/t cement, most of it (around 80%) 
consumed for grinding processes. The main users of electricity are the mills (grinding of raw 
materials, solid fuels and final grinding of the cement) that account for more than 60% of the 
electrical consumption and the exhaust fans (kiln/raw mills and cement mills) which together with 
the mills account for more than 80% of electrical energy usage. The uptake of CCS technology by the 
cement industry would mean a significant increase of power consumption. 

The alternative fuels consumption increased from 3% of the heat consumption in 1990 to almost 18% 
in 2006. If the current trends remain, the substitution rate could reach 49% in 2030 with savings of 
0.30 EJ (7.3 Mtoe) in 2030. The achievement of a clinker to cement ratio of 0.70 in 2030 (possible if 
current trends are held) would mean savings of 0.054 EJ (1.3 Mtoe) in 2030. Taking into account all 
these trends, it is estimated that between 2006 and 2030, the cost effective implementation of 
remaining technological innovation can reduce thermal energy consumption by 10% and CO2 
emissions by 4%.  

The EU cement industry production in 2006 (267.5Mt) represented 10.5% of the total world 
production, the weight of European cement industry in 2008 decreased to a 9% of world production 
(254.7Mt),. The cement consumption in Europe peaked in 2006 with 265.9Mt. In 2008 consumption 
decreased to around 2005 (246.6Mt) level. In the former EU15 the number of cement plants with 
kilns decreased by 31 between 1995 and 2006, while the number of grinding plants in the same 15 
countries increased by 19 over the same period. These numbers reflect the competition faced by the 
European industry: in 10 years 12 % of the cement plants with kilns closed and the number of 
grinding plants (to convert imported clinker into cement) increased by 28 %.  

62 

 
 
 
14.2.  Technology needs 

14.2.1.  The iron and steel industry 

Exploiting the advantages of the recycling route (with direct CO2 emissions an order of magnitude 
lower than the integrate route) will require an outstanding end-of-life management to ensure that all 
steel contained in scrap can be recycled in an effective way. 

An early market roll out after 2020 of the first technology considered in the ultra low CO2 steelmaking 
project (ULCOS project, supported by the EU) could further reduce CO2 emissions. The ULCOS project 
is the flagship of the industry to reach a decrease of over 50% of CO2 emissions in the long term. The 
first phase of ULCOS had a budget of € 75 million. As a result of this first phase, four main processes 
have been earmarked for further development: 

•  Top  gas  recycling  blast  furnace  is  based  on  the  separation  of  the  off-gases  so  that  the  useful 
components  can  be  recycled  back  into  the  furnace  and  used  as  a  reducing  agent;  and  in  the 
injection  of  oxygen  instead  of  preheated  air  to  ease  the  CO2  capture  and  storage  (CCS).  The 
implementation of the top gas recycling blast furnace with CCS will cost about € 590 million for 
an  industrial  demonstrator  producing  1.2  Mt  hot  metal  per  year.  The  tentative  timeline  to 
complete the demonstration programme is about 10 years, allowing further market roll-out post 
2020.  

•  The HIsarna technology combines preheating of coal and partial pyrolysis in a reactor, a melting 
cyclone  for  ore  melting  and  a  smelter  vessel  for  final  ore  reduction  and  iron  production.  The 
market  roll-out  is  foreseen  for  2030.  Combined  with  CCS  the  potential  reduction  of  CO2 
emissions of this process is 70-80%. A pilot plant (8t/h, without CCS) was commissioned in 2011 
in Ijmuiden, the Netherlands.  

•  The ULCORED (advanced direct reduction with CCS) iron is produced from the direct reduction 
of iron ore by a reducing gas produced from natural gas. The reduced iron is in solid state and 
will  need  an  electric  arc  furnace  for  melting  the  iron.  An  experimental  pilot  plant  is  being 
planned  in  Sweden,  with  market  roll-out  foreseen  in  2030.  The  potential  reduction  of  CO2 
emissions of this process is 70-80%.  

•  ULCOWIN and ULCOSYS are electrolysis processes to be tested on a laboratory scale. There is a 
need  to  support  this  ULCOS  research  effort  with  a  high  share  of  public  funds,  and  to  lead  the 
global  framework  market  towards  conditions  that  ease  the  prospective  deployment  of  these 
breakthrough technologies. 

It is important to notice that, compared to the conventional blast furnace, the first two 
breakthroughs ULCOS-BF and HISARNA would result in a reduction of CO2 emissions of 50-80% and at 
the same time a reduction of energy consumption by 10-15%. One important synergy in the quest to 
curb prospective CO2 emissions through the ULCOS project is the share of innovation initiatives 
within the power sector or with any other (energy-intensive) manufacturing industries that could 
launch initiatives in the field of CCS (e.g. cement industry). 

14.2.2.  The pulp and paper industry 

There are potential emerging and breakthrough technologies in the pulp and paper industry, 
although most are currently at a standstill. These can be grouped in the following families: 

• 

The  bio-route  is  the  route  towards  integrated  bio-refinery  complexes  producing  bio-pulp,  bio-
paper,  bio-chemicals,  bio-fuels,  bio-energy  and  possibly  bio-Carbon  Capture  and  Storage  (bio-

63 

 
 
CCS). Some of the bio-route concepts are in the European Industrial Bioenergy Initiative (EIBI). In 
fact,  as  part  of  this  initiative,  there  is  a  first  large-scale  demonstrator,  a  bio-DME  (dDimethyl 
ether) plant in connection to a pulp mill, under construction in Sweden. Also, one of the flagships 
planned for this Initiative is led by a Finnish pulp and paper company, Part of this route is also the 
further  development  of  gasification  of  black  liquor,  which  aims  at  producing  a  combustible 
mixture of raw gases on the one hand and separating out the inorganic pulping chemicals on the 
other  hand  for  their  subsequent  use  in  the  pulping  processes.  Lignoboost,  another  bio-route 
concept, is a complete system that extracts lignin, a component of wood from kraft black liquor. 
This lignin can be used as a biofuel with a relatively high heating value and could also be used as 
feedstock to produce innovative chemicals.  

• 

Innovative  drying  technologies.  Some  drying  technologies  such  as  “impulse  drying”,  the 
“Condebelt”  process,  or  the  “steam  impingement  drying”  have  only  had  a  first-of-a-kind 
implementation,  and  have  not  been  replicated.  The  first  European  commercial  facility  with  a 
condebelt® process entered in operation in 1996 at the Pankaboard mill in Pankakoski, Finland. 
There  is  a  second  case  of  implementation  of  this  technology  in  1999  in  South  Korea.  Research 
and demonstration regarding innovative drying technologies seems to be at a standstill. 

•  Mechanical  pulping.  There  is  ongoing  work,  at  laboratory  studies  level,  to  optimise  the 
production of mechanical pulp focusing mainly on the wood yield preparation and more efficient 
refiner plates (less energy consumption at the same productivity levels).  

Under the European Commission’s Sustainable Bio refineries call, the European Union is contributing 
to the four projects funded under the European Commision’s Sustainable Biorefineries Call (Star-
COLIBRI, SUPRABIO, EuroBioRef and BIOCORE) with € 51.6 million of a total budget of € 79.1 million. 
Also, part of the support needed to develop the bio-route can be channeled through the European 
Industrial Bioenergy Initiative with projects. However, the large investments needed for the 
transition from pilot plant to full scale application may require an additional push to allow the 
industry to cross the apparent “valley of death” in which much of the research is at present. A 
number of these investments bring financial risks that mills cannot take in the current economic 
conditions and for which assistance is needed. Furthermore, several large scale technologies are 
competing in the same field, where it is not clear yet which one will be the winning technology. For 
those commercially-available drying technologies, the market seems to doubt their potential so far, 
since very few new machines have been deployed. Next to the investment cost factor, trust or 
reliability of new technologies seems to be an issue.  

One important synergy in the quest to curb CO2 emissions could be exploited through sharing 
innovation initiatives with the power sector or with any other (energy-intensive) manufacturing 
industries that could launch initiatives in the field of CCS (e.g. iron and steel industry, cement 
industry…). 

14.2.3.  The cement industry 

As a mature industry, no breakthrough technologies in cement manufacture are foreseen that can 
reduce significantly thermal energy consumption. Alternative technologies are currently being 
researched such as the fluidized bed technology; however, although improvements can be expected, 
it is not foreseen that such technologies will cover the segment of big kiln capacities. On the other 
hand, CCS has been identified as a prominent option to reduce CO2 emissions from cement 
production in the medium term. Currently, the main evolution of the sector to improve its energy 
and environmental performance is towards higher uses of clinker substitutes in the cement, higher 

64 

 
 
use of alternative fuels such as waste and biomass and the deployment of more energy efficiency 
measures. A significant number of energy efficiency measures are currently being proposed; however 
their deployment is quite site-specific rendering difficult an assessment of the gains that can be 
expected. It is noted that many thermal energy reducing measures can increase the power 
consumption.  

14.3.  Cost reductions 
According to the ETP 201264, achieving in the EU from today to 2050 their 2DS scenario would require 
an additional investment of € 7.8 trillion (35%) more than under a scenario (6DS) in which controlling 
carbon emissions is not a priority. The IEA’s 2DS scenario aims to reduce energy-related carbon 
dioxide (CO2) emissions by 50%, compared to 2005 levels. During this period the additional 
investments of the European’s industry is € 265 billion, (3.4% of the additional € 7.2 trillion). To 
achieve the 2DS scenario, the total investments needed in the European industry reach € 331 billion 
in the first 10 years (€ 32 billion more than the investments required under the 6DS scenario). The 
difference in the requirement of investments in both scenarios is increased after 2030 due to the 
higher costs of reducing emissions intensity, particularly with the implementation of CCS. These 
investments are the requirements in industrial production plants for the five most energy-intensive 
sectors (iron and steel, pulp and paper, cement, aluminium and chemicals and petrochemicals). 

The additional investment needs offer significant fuel savings as a result of investment in low-carbon 
technologies. In the industry sector, the fuel savings are estimated at 6 times the additional 
investments costs. In the EU, up to 2050, the total additional savings amount to € 1.59 trillion. 

Some examples of technological options that can become a reality by 2020 for marginal abatement 
costs of the order of 40-60 €/t CO2 are the remaining BATs in all sectors of the industry. That price 
can also trigger the implementation of top-gas recycling blast furnace in the iron and steel industry. 
Marginal costs around 100-130 €/t CO2 by 2030 can set off black liquor gasification in the pulp and 
paper industry. Values of 140-170 €/t CO2 could bring about CCS in the cement industry. Eventually, 
by 2050, marginal cost of 170-200 €/t CO2 could lead to new cement types and to hydrogen smelting 
and molten oxide electrolysis in iron and steel. 

14.4. 

Soft measures influencing deployment 

The three energy intensive industries considered in this chapter are affected by risks of carbon 
leakage under the terms of the former European Union Greenhouse Gas Emission Trading System 
(EU ETS). The revised Directive provides for 100% of allowances allocated free of charge, at the level 
of the benchmark to the sectors exposed. However, even with this new provision the industry is still 
calling for new measures to level the global playfield.  

Despite the high penetration of cogeneration in some of the industries considered in this chapter, 
there are sectors with a high potential to tap, For example, in the pulp and paper industry, it is 
estimated that only 40% of CHP potential capacity has been installed. The barriers to the further 

64  Energy  Technology  Perspectives  2012.  Pathways  to  a  clean  Energy  System.  International  Energy  Agency, 

2012. 

65 

 
 
 
                                                            
expansion of CHP are common to all the industries. One of those barriers is the ‘spread price’, the 
difference between the price of the fuel used by the CHP and the price of the electricity generated.  

In the iron and steel industry, no significant advance to decrease CO2 emissions is possible without 
the development of breakthrough technologies, as proposed by ULCOS. The main lever of energy 
savings for steel production is led by further increases in the recycling rate. However, further 
increases in the recycling rate beyond the 60% in 2030 will be stifled by the availability of scrap. Such 
high recycling values will increase the impurities and reduce the overall steel quality. Recycling has 
high emissions of heavy metals and organic pollutants due to the impurities of scrap. These issues 
will become a more pressing issue to be solved urgently. 

In the pulp and paper industry, in the short and long term perspectives, the availability of raw 
materials (wood and recycled fibre) will be crucial. Currently, there is an increasing pressure on 
biomass availability. For their main virgin feedstock, wood, the pulp and paper industry is competing 
with other bioenergy producers; almost 5% of the EU gross energy demand is covered by biomass 
resources. In fact, the biomass was almost two thirds (65.6%) of all renewable primary energy 
consumption in 2007. At the same time, waste paper is exported at large scale mainly to China, 
where new large paper mills use this resource. This leads to shortages in recycled fibres for some 
European paper producers. Also, the trend by many municipalities to decrease the availability of 
waste to be recycled by the energy intensive industries may further hamper reaching higher levels of 
efficiency. 

In the cement industry, one of the main barriers to the deployment of energy efficiency measures 
and CO2 mitigation technologies in the cement industry in Europe is related to energy prices. High 
energy price favors investment in energy efficiency and CO2 emissions abatement, however at the 
same time higher energy prices may lead towards more and more imports from non EU countries to 
the detriment of a European production. The market penetration of cements with a decreasing 
clinker to cement ratio will depend on six factors, i) availability of raw materials, ii) properties of 
those cements, ii) price of clinker substitutes, iii) intended application, iv) national standards and vi) 
market acceptance. It is noted that a cement that can be fit for purpose in one country can often not 
be placed in some other countries due to differences in national application documents of the 
European concrete standard. Therefore a way to encourage the use of these cements would be the 
promotion of standard harmonization at the EU level.  

66 

 
 
15. 

BUILDINGS AND ENERGY  

The building sector is associated with around 39% of the final energy consumption in Europe. Several 
studies65 have shown that the energy saving potential of this sector is substantial and can bring 
significant benefits at individual, sectoral, national and international levels. In line with the European 
Commission's objective to move towards a low-carbon economy, an array of European Directives 
(EPBD 2002/91/EC, EESD 2006/32/EC, RESD 2009/28/EC, EPBD 2010/31/EU, EED 2012/27/EU) is in 
place in order to exploit this potential. This policy framework can act as a catalyst for the market 
transformation in the building sector and can offer great opportunities for various technologies to be 
widely deployed in the market. 

15.1.  Market evolution 

More stringent building energy codes, as a result of the first Energy Performance of Buildings 
Directive (Directive 2002/91/EC), mean that the market can shift its focus to more sustainable 
construction techniques and materials, energy efficient building components and designs. As energy 
codes have adopted a performance-based perspective (as opposed to a prescriptive one, based on 
individual measures), integrated solutions and packages can be better promoted in buildings. 
Moreover, the cost optimality methodology – introduced as part of the recast Directive 2010/31/EU 
– is expected to shift current building code requirements to cost-optimal levels, taking into account 
the whole lifecycle of measures. This can help transform the current industry's conservative 
approach for short-term profit maximization, which acts unfavourably towards energy efficient 
components.    

Nearly zero energy buildings – a requirement of the recast Directive 2010/31/EU for all new 
constructions by 2020 – mean that a combined deployment of high performance constructions, 
energy efficient installations and renewable energy measures should take place at a large scale. The 
experience gained from current exemplary voluntary standards66 acting as leading market concepts 
can be used to draw lessons and prepare the grounds for the necessary market transformation. 
Recommendations are given in the JRC report “Evaluating and Modelling Near-Zero Energy Buildings; 
are we ready for 2018.” Technologies based on fossil fuels will progressively have a lesser importance 
in buildings, while improving the skills of the workforce and ensuring high compliance levels will be a 
prerequisite for the successful realisation of these nearly zero energy buildings. 

Estimates show that 75% of the existing stock in the developed countries will still be used in 2050.  A 
large share of these buildings is inefficient, and reducing the energy use of the overall stock in the 
long term critically depends on the measures taken in these buildings. This highlights the need of 
boosting the renovation market. In light of the new Energy Efficiency Directive (2012/27/EU), 
Member States should renovate at least 3% of the surface of their central government building stock 
as well as establish roadmaps for mobilising investment in the refurbishment of their national 

65  E.g.,  Fraunhofer-ISI,  2009.  Study  on  the  Energy  Savings  Potentials  in  EU  Member  States,  Candidate 
Countries  and  EEA  Countries  -  Final  Report,  s.l.:  European  Commission;  WBCSD,  2009.  Energy 
Efficiency  in  Buildings,  Transforming  the  Market.  ,  s.l.:  World  Business  Council  for  Sustainable 
Development;  Urge-Vorsatz,  D.  et  al.,  2012.  Best  Practice  Policies  for  Low  Energy  and  Carbon 
Buildings.  A  Scenario  Analysis.  Research  Report  Prepared  for  the  Global  Best  Practice  Network  for 
Buildings, s.l.: Central European University (CEU) and Global Buildings Performance Network. 

66 Examples include the German PassivHaus, the Swiss Minergie and French Effinergie standards 

67 

 
 
                                                            
building stock. This process would mean that more collaboration between different companies and 
industry actors should be established in order to join forces and offer combined or holistic 
renovation packages.  

15.2.  Technology needs 

There is a wide range of technological solutions that can be used to drastically reduce the energy 
consumption of the building stock. The energy consumption of a building is influenced by several 
factors, such as geometry and orientation of the building, performance of building envelope, 
efficiency of building installations as well as usage patterns, energy management and occupancy 
behaviour. The philosophy that supports the reduction of energy consumption in buildings can be 
followed in three steps:  

1.  Application of energy saving measures (e.g. improve insulation of building envelope). 

2.  Increase  of  energy  efficiency  of  building  installations  and  use  of  renewable  energy 

resources to cover remaining energy needs. 

3.  Optimization of usage patterns and occupancy behaviour. 

It is widely accepted by the expert community that existing technologies can already reach significant 
energy reduction levels. Instead, it is rather non technological barriers which prohibit the 
deployment of energy efficient measures as buildings are complex systems, involving and a large 
number of actors and a variety of technologies. 

Step 1 

The building envelope (i.e. building shell) plays a key role in reducing the energy demand of a 
building. It is the interface of the outdoor climate conditions (temperature, solar radiation and wind) 
during summer/winter months with the indoor climate (comfort level, air quality and light), thus 
affecting the living and working conditions inside a building. A building designed with a low 
compactness ratio, optimum orientation combined with passive heating and cooling techniques 
benefits from reduced summer heat gains and winter heat losses. Moreover, the use of daylight can 
significantly reduce lighting needs. The heat transfer through the building envelope can be optimised 
by applying the right level of insulation, where low U-values (high thermal resistance) of 0.1-0.15 
W/m2K can be reached. The avoidance of thermal bridges – junction points where insulation is 
discontinuous – at the design level is a critical structure design option which minimises the risk of 
additional heat loss or condensation. Multiple (air- or argon-filled) glazing can reduce thermal 
transmittance to 0.7 W/m2K. Improved building envelope air-tightness in combination with heat 
recovery ventilation systems can obtain levels of 0.4 – 0.6 ACH (air changes per hour) with an energy 
efficiency of the installation over 80 %.  

Step 2 

Building installations should include a highly efficient generation system, an effective and efficient 
distribution system as well as effective controls on both generation and distribution systems. 
Condensing boilers offer a high thermal efficiency (at least 85%) compared to non-condensing 
boilers, while biomass boilers may offer an alternative option.  Measures such as heat recovery 

68 

 
 
 
systems can reduce the energy consumption of HVAC systems as they use heat exchangers to 
recover heat or cold air from the ventilation exhaust and supply it to the incoming fresh air. 

The integration of renewable energy technologies (solar, biomass, geothermal) has also an important 
role in buildings. Renewable energy technologies such as active solar thermal and solar electrical 
systems should be favoured and in addition to biomass boilers, heat pumps, whose main operating 
principle is to absorb heat from a cold place and release it to a warmer one, can be used for space 
heating and hot water purposes. Solar thermal collectors can convert incoming solar radiation into 
heat for space heating or hot water purposes, while roof-top photovoltaic installations (solar 
electrical) can produce electricity to cover the remaining energy needs in a building. 

Step 3 

Smart technologies entering the built environment range from control automisation to smart 
metering devices for increased communication with utilities and end-users. Numerous applications 
for innovation and requested technologies for the built environment offer opportunities to reduce 
the energy consumption and to control the energy demand/supply balance through intelligent 
management (ICT). The building will be considered as the cornerstone of the future energy system in 
our society. Proper integration of renewable energy technologies and electrical vehicles in this built 
environment will lead to a more efficient use of available energy resources.  

Further technological developments will increase the availability of options while allow even higher 
performance levels to be achieved in buildings. Innovative integrated technologies (ventilated 
facades and windows, solar chimney and new insulation materials) can also contribute to a further 
decrease in overall energy consumption. Up-scaling the diffusion of current energy efficiency 
technologies in the market can help foster the penetration of promising new innovating 
technologies. 

69 

 
 
 
 
 
16. 

SMART CITIES AND COMMUNITIES 

16.1. 

Introduction 

In the EU in 2011, Eurostat reports that "68% of the population lives in urban areas, which 
consumes 70% of energy"67, accounting for 75% of the EU's total greenhouse gas emissions 
(GHG)68.  In  the  world,  more  than  half  of  the  mankind  is  living  in  urban  areas  and  it  is 
estimated  that  cities  will  host  70%  of  the  world  population  by  205069.    This  evolution  will 
inevitably put pressure on resource consumption and environmental issues in urban areas.  

However, cities are becoming active in developing strategies for better and more sustainable 
living conditions.  Indeed, Smart Cities are commonly defined as an evolution of the present 
cities,  where  the  increased  inclusion  of  technology  and  of  information  and  communication 
technologies (ICT) in particular, drives towards more sustainable growth and better quality of 
life for the citizens70. 
According  to  a  2007  research  paper71,  smart  cities  can  be  ranked  along  six  smart  axes: 
economy, mobility, environment, people, living, governance. Energy and energy technologies 
underpin  most  of  them,  and  energy  efficient  technologies  will  play  a  fundamental  role  in 
shaping the cities of the future. 
Although  there  are  no  smart  cities  yet72,  urban  areas  are  evolving  into  smart  cities  from 
different angles: for the energy point of view, utilities and energy actors are engaging in smart 
energy services and networks; from the transport point of view, cities are supporting electro-
mobility  and  public  transport  companies  are  experimenting  smart  systems  to  improve  their 
services;  from  the  building  side,  energy  efficiency,  including  more  efficient  heating  and 
cooling systems, is strongly promoted in new and renovated buildings.  Overall,  information 
and communication technologies are pivotal and they play a central role in the integration of 
the various city networks and services.  

Estimations of the benefits achievable through the deployment of smart cities in the coming 
decade  anticipate  up  to  50%  reduction  in  energy  consumption,  20%  decrease  in  traffic  and 
80% improvement in water usage73. 

16.2.  Technology needs 

Smart  Cities  technology  is  not  a  single  technology  but  rather  the  combination  of  multiple, 
existing technologies. Smart Cities are at the intersection of ICT, energy and transport. They 
boost  the  adoption  of  more  efficient  energy  technologies:  in  buildings,  with  more  efficient 
buildings  see  Chapter  15,  like  nZEB  (near  zero  energy  buildings),  improved  electrical 
appliances,  as  well  as  heating  and  cooling  systems;  in  the  electricity  distribution  grid  that 
becomes a smart grid, see Chapter 13; in transport, with the introduction of electrical mobility 
solutions  and  the  necessary  infrastructure.  Multiple  technologies  are  integrated  through 
information  and  communication  technology,  which  is  the  main  enabler  of  the  smart  cities 
evolution, based on existing technologies and developing new and innovative cross-functional 

67 Eurostat (2011) Regional yearbook 2011: European cities. Urban areas are over 10 000 inhabitants. 
68 C(2012) 4701 final, COMMUNICATION FROM THE COMMISSION SMART CITIES AND COMMUNITIES - 
EUROPEAN INNOVATION PARTNERSHIP  
69 UN (2004), World Population to 2300 
70 Intelligent Operations Centre for Smart Cities (IBM, 2011), Integrated City Management Platform (Schneider Electric 
2012), Urban Interoperability Platform (Indra, 2013), Connected Urban Development concept (Cisco, 2009), Intelligent City 
Network concept (Accenture, 2009), Oracle City Platform (Oracle, 2013).  
71 Giffinger (2009) Smart cities Ranking of European medium-sized cities 
72 Hollands (2008) Will the real smart city please stand up?, City, 12 (3), p. 303-320. 
73 Elfrink (Cisco) (2012) Interview with McKinsey's Rik Kirkland, www.mckinsey.com 

70 

 
 
                                                            
applications and services for the benefit of the citizens and the environment. A large number 
of sensors, as well as monitoring and communication technologies will be deployed, that will 
reinforce the need for data analysis systems and capabilities, cloud computing facilities, data 
centres, servers, etc. Moreover, increased numbers of devices will be in exchanging data via 
M2M  (machine-to-machine)  communication  and  leading  to  the  future  "Internet  of  things". 
Due  to  the  expected  fast  speed  of  deployment  of  ICT,  improving  their  energy  efficiency  is 
becoming crucial. The European Commission supports and promotes voluntary agreements to 
increase energy efficiency in ICT, such as the codes of conduct which includes, among others, 
data centres, digital TV, broadband communication equipment, external power supplies74.  

The Commission proposed to set up a European Innovation Partnership (EIP) on Smart Cities 
and Communities in 201275. A high level group, supported by a sherpa group, has been set up 
with representatives from industry, cities, regulators, the bank-sector and other stakeholders, 
The  high  level  group  will  advise  the  commissioners  for  Energy,  Transport  and  the  Digital 
Agenda on and should agree on a Strategic Implementation Plan for the EIP in the autumn of 
2013.  The  combination  of  technology  development  and  innovation  with  the  EIP  as  a 
deployment  mechanism  will  result  in  a  pipeline  of  long-term,  sustainable  solutions  for 
European cities 

Furthermore, the Smart Cities Stakeholder Platform, gathering a multitude od stakeholders is 
preparing  the  Ten  Years  Rolling  Vision  along  four  main  axes:  energy  efficiency  and 
buildings, energy supply and networks, mobility and transport, finance and planning. EERA 
Smart  Cities  (the  alliance  of  European  research  organizations)  is  developing  the  research 
activities of Joint Research Programme that focuses on energy efficiency and the integration 
of renewable energy sources,. 

In  addition  technology  requirements  are  increasingly  defined  at  local  level  by  the  cities 
leaders.  This  bottom-up  trend  is  also  confirmed  by  the  success  achieved  by  voluntary 
programmes  like  the  Covenant  of  Mayors  initiative  or  the  Green  Digital  Charter76  .  These 
projects are landmarks for the sustainable development of cities, promoting at city level the 
2020 European energy and climate targets and the adoption of the Green Digital Charter.  

Smart Cities are complex systems; many technological challenges are foreseeable. However, 
it is recognised that one major technological challenge is the adoption of standards to ensure 
connectivity and interoperability and to stimulate industrial competition. Moreover, it is also 
imperative  for  the  future  of  smart  cities  to  demonstrate  the  potential  for  scaling  successful 
pilot projects up to the citywide scale and to replicate results.  

16.3.  Market evolution 

The Smart cities market is not just one single market, but rather the convergence of several 
existing  markets,  such  as  buildings  and  home  appliances,  energy  management,  industrial 
automation, services to the citizens, transport and security, with the common denominator of 
information  and  communication  technology  for  their  integration.  Consequently,  the  main 
smart cities market players come from the ICT sector or from the infrastructure sector.  

Worldwide,  pilot  projects  are  on-going  (Amsterdam,  Malaga,  Dubai)  that  address  specific 
areas of the future cities. According to recent studies, the smart cities market is expected to 
grow steadily. Pike Research estimates a growth in annual spending from $ 6.1 billion today 

74 http://iet.jrc.ec.europa.eu/energyefficiency/ict-codes-conduct/data-centres-energy-efficiency 
75 C(2012) 4701 final, - Communication on Smart Cities and Communities European Innovation Partnership  
76  The  Covenant  of  Mayors  (  www.covenantofmayors.eu  )  ,  the  Green  Digital  Charter  (  www.greendigitalcharter.eu  ) 
Efficiency, 
(Networking 

intelligent 

Energy 

Cities 

for 

supported 
http://www.greendigitalcharter.eu/niceproject ). 

project 

NiCE 

the 

by 

71 

 
 
                                                            
to  $  20.2  billion  in  202077,  with  half  of  the  growth  expected  in  developing  countries;  ABI 
Research  evaluates  the  smart  cities  market  value  at  $  8.1  billion  annually  in  2010  and  will 
reach  $  39  billion  by  201678  and  a  cumulative  spending  of  $  116  billion  between  2010  and 
201679.  

16.4. 

Soft measures 

The potential for development of smart cities not only relies on technology evolution. Non-
technical  issues  also  need  particular  attention.  Because  of  the  complex  mix  of  technologies 
and networks involved, it is crucial for instance that a forward-looking vision is developed by 
the  city  administrators,  along  with  the  integrated  planning  of  networks  and  services  and  a 
consistent  long-term  ICT  plans.  A  long-term  planning  is  an  opportunity  to  support  the 
creation of new "ecosystems", where different actors are brought together to cooperate and to 
combine assets and knowhow for more sustainable solutions at city level. 

Regulation  will  also  play  a  strategic  role.  It  is  expected  to  promote  the  development  and 
adoption of standards for an open and constructive competition. Particular emphasis should be 
put  on  data  issues,  in  order  to  improve  and  secure  data  exchanges.  Moreover  a  forward 
looking regulation is expected to pave the way towards the definition and the application of 
favourable incentive schemes.  

On  the  financing  side,  smart  cities  projects  require  massive  funding.  Public-private 
partnerships are proposed as valuable options that not only bring together the large financing 
means needed to wide scale smart cities projects but also combine the different stakeholders 
and contributions needed for successful smart cities projects.  

77 Pike Research (2013) Smart cities report 
78 Differences in figures are the results of the different interpretations of the smart city and confirm that there is a need for 

common definitions and standards. 

79 ABIresearch (2011), Smart city data 

72