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# 52013SC0158

**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 /\* SWD/2013/0158 final \*/**

  

Energy technology developments beyond
2020 for the transition to a decarbonised European energy system by 2050

Table of Contents

1........... Introduction. 2

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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)

(b)

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

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.

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) scenarios[1], 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).

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.

(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.

–
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.

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 2030[2], 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 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.

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 2013[3].
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 electricity (LCOE) from PV
systems moving below 0.10 €/kWh in the near future, the additional storage 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.

3.4.        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.           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 MW[5], 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 facets[6]
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
consumption[7]

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 performance[8] 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.

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)

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

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.

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 total[11].
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.

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

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.

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:

Materials[13]

·
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.

·
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.

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 JRC[14].
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.

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.

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.

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 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 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. 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.

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.

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 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.

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 CCS[15].

Europe has been at
the forefront of CCS technology development; however is lagging behind in terms
of demonstration. According to GCCSI[16],
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.

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.

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 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 CCS[17].

·
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 ETP[18] 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 €/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.

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 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.

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 criteria[19].

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 events[20].
Examples of general technology/research needs are:

·
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).

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&D[21].

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

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 are[22]:

·
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 markets[23]. 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 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.

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.

.

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 generation[24]. 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 2035[25]. 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.

Source:
JRC elaboration on IEA WEO 2012, New Policies Scenario; IEA ETP 2012, 4DS[26]

9.2.        Technology needs

Stream turbines for coal plants

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 decade[27],
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
COORETEC[28]
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 plants[29] 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 Europe[30]
but no final investment decision has been communicated so far. In the USA, one large scale project began test operation in 2012[31].
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-IGCC[32]
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 Shell[33], one of the leading
providers of gasifier technology, suggests thermal efficiencies of 48.5% for
new built projects.

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 units[34].
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
capacity[35].
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
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.

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
stabilised at 10% per doubling of capacity after a phase of more rapid price
declines observed in the 1990s[36].

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 matter[37]. 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.

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.

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
CarbonTrust[38],
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

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.

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 Perspectives[39]. 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

|| 2030 || 2050

Share of H2 in energy mix in industry sector (%) || 0 || 7

Share of H2 in energy mix in buildings (%) || 0 || 5

H2 as fuel for transport (%) || 0 || 15

FCEV in passenger vehicle stock (%) || 2 || 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 stakeholders[40]
identifies the following years for “major FCH applications to become
commercial”:

transport || cars || 2015

|| buses || 2016

|| material handling vehicles || 2014

|| auxiliary power units || 2017

|| refuelling stations || 2015

energy || power generation || 2016

|| industrial CHP || 2017

|| domestic CHP || 2017

|| backup/UPS || 2013

|| portable || 2015

H2 production || large scale electrolysis || 2015

|| from biofuels || 2016

|| from conventional fuels || 2016

H2 storage || mass storage for electricity || 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 billion[41], up from US$300 million
in 2005[42],
with the highest growth in the stationary sector. The market is expected to be
worth $15.7 billion in 2017[43],
and a recent US study estimates that the global market could be between US$ 43
billion and US$ 139 billion annually over the next 10 to 20 years[44]..
In the market segment with the highest visibility, namely passenger
vehicles, a recent study[45]
shows the following figures:

|| 2020 || 2030 || 2040

Number FCEV EU || 0.44-0.9 M (0.1-0.3%) || 9.0-16.0 M (3.4-6.0%) || 66.1-92.4 M (24.7-34.5%)

Number FCEV global || 1.9-3.8 M (0.1-0.3%) || 43-77 M (3.3-6.0%) || 491-691 M (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 below[46].

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 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.

||

||

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:

·
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

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 capacity[49]. 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 2050[51] 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)

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 Islands[53].

-
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 projects[55] 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

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 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 components 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 costs 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
energy 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 consolidation[56].

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 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 matter[57]. 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-E[58]. 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 stakeholders[59].
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.

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 infrastructure[60]. 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
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;

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

o
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-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:

a) ICT/telecom networks, essential for the deployment of smart grids, since
they empower the effective communication between all interconnected actors and
components. It includes telecommunication and remote control technologies, 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.

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 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 reasons[61]:

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.

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).

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 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 2008[62]).
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 countries[63]) 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 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 %.

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-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 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 2012[64], 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 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.

15.         Buildings
and Energy

The building sector is associated with
around 39% of the final energy consumption in Europe. Several studies[65] 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
standards[66]
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 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 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.

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 2050[69].  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 citizens[70].

According to a 2007 research paper[71],
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 yet[72],
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 usage[73].

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 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
supplies[74].

The Commission proposed
to set up a European Innovation Partnership (EIP) on Smart Cities and Communities in 2012[75].
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 Charter[76] .
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 to $
20.2 billion in 2020[77], 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 2016[78]
and a cumulative spending of $ 116 billion between 2010 and 2016[79].

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.

[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,

[2] EPIA, Connecting the Sun, 2012.

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

[4] IRENA, 2012, RENEWABLE ENERGY TECHNOLOGIES: COST ANALYSIS SERIES,
Volume 1, Power Sector, Vol4/5, Solar Photovoltaics.

[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

[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.

[10] Source: IRENA, 2012, RENEWABLE ENERGY TECHNOLOGIES: COST ANALYSIS
SERIES, Volume 1, Power Sector, Vol4/5,  CSP

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

[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.

[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.

[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

[15] IEA CCS Technology Roadmap, 2009.

[16] GCCSI, The global status of CCS, January 2013 update.

[17] ZEP ETP and the European Biofuels
Technology Platform, Biomass with CO2 Capture and Storage (Bio-CCS),
http://www.zeroemissionsplatform.eu/
library/publication/206-biomass-with-co2-capture-and-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

[19] GIF, 2002, A Technology Roadmap for Generation IV Nuclear Energy
Systems, pp.6, available at: http://www.gen-4.org/PDFs/GenIVRoadmap.pdf

[20]SNETP, 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

[21] SNETP, 2009, Strategic Research Agenda, available at:
http://www.snetp.eu/www/snetp/images/stories/Docs-AboutSNETP/sra2009.pdf

[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

[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

[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

[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

[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

[38] Carbon Trust 2011, “Accelerating marine energy”, July 2011,
http://www.carbontrust.co.uk
/publications/pages/publicationdetail.aspx?id=CTC797

[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

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

[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

[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

[56] http://www.rolandberger.com/media/pdf/Roland\_Berger\_Li\_Ion\_Batteries\_Bubble\_Bursts\_20121019.pdf

[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

[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.

[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

[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

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

[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] 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

[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
) supported by the NiCE project (Networking intelligent Cities for Energy
Efficiency, http://www.greendigitalcharter.eu/niceproject
).

[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

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