KIC Coal and Gas Technologies Report

KIC InnoEnergy · Clean Coal and Gas Technologies01
Clean Coal and Gas Technologies
Future Energy Costs:
Coal and Gas Technologies
How technology innovation is anticipated to reduce
the cost of energy in Europe from new gas CHP plants
and coal plants retro-fitted with upgraded technology

KIC InnoEnergy
Clean Coal and Gas Technologies
Authors
Giles Hundleby, Director, BVG Associates
Bruce Valpy, Managing Director, BVG Associates
Kate Freeman, Junior Associate, BVG Associates
Coordination of the study
Marcin Lewenstein, Thematic Leader, Clean Coal and Gas Technologies, KIC InnoEnergy Poland Plus
Jakub Miler, CEO, KIC InnoEnergy Poland Plus
Section 2 on coal and gas in the EU policy framework was commissioned by KIC InnoEnergy
and written by Maciej Bukowski and Aleksander Sniegocki of WiseEuropa, Warsaw.
BVG Associates
BVG Associates is a technical consultancy with expertise
in wind and marine energy technologies and other clean
energy systems. The team has deep experience of modelling
technology impacts on cost of energy for wind, marine and
solar energy systems. BVG Associates has over 150 combined
years of experience in the clean energy sector, many of these
being “hands on” with system manufacturers, leading RD&D,
purchasing and production departments. BVG Associates has
consistently delivered to customers in many areas of the clean
energy sector, including:
• Market leaders and new entrants in wind and marine
renewables supply chain and UK and EU wind farm
development
• Market leaders and new entrants in clean energy component
design and supply
• New and established players within the clean energy sector
of all sizes, in the UK and on most continents, and
• The Department of Energy and Climate Change (DECC),
RenewableUK, The Crown Estate, the Energy Technologies
Institute, the Carbon Trust, Scottish Enterprise and other
similar enabling bodies.
KIC InnoEnergy
KIC InnoEnergy is the Innovation engine for sustainable
energy across Europe. The challenge is big, but our goal
is simple: to achieve a sustainable energy future for
Europe. Innovation is the answer. New ideas, products
and solutions that make a real difference, new businesses
and new people to deliver them to market.
At KIC InnoEnergy we support and invest in innovation
at every stage of the journey – from classroom to
customers. With our network of partners we build
connections across Europe, bringing together inventors
and industry, entrepreneurs and markets, graduates and
employers, researchers and businesses.
We work in three essential areas of the innovation mix:
• Education to help create an informed and
ambitious workforce that understands
what sustainability demands and industry
needs – for the future of the industry.
• Innovation Projects to bring together ideas, inventors
and industry in collaboration to enable commercially
viable products and services that deliver real results.
• Business Creation Services to help entrepreneurs
and start-ups who are creating sustainable
businesses to grow rapidly to contribute
to Europe’s energy ecosystem.
Together, our work creates and connects the building
blocks for the sustainable energy industry that Europe
needs. With our headquarters in the Netherlands, we
develop our activities through a network of offices
located in Belgium, France, Germany, the Netherlands,
Spain, Portugal, Poland and Sweden.
Future Energy Costs:
Coal and Gas Technologies
How technology innovation is anticipated to reduce
the cost of energy in Europe from new gas CHP plants
and coal plants retro-fitted with upgraded technology

05
Executive summary
As an innovation promoter, KIC InnoEnergy is interested in evaluating the impact of innovations
on the cost of energy from various clean and renewable energy technologies. This analysis
is critical in understanding where the biggest opportunities and challenges are from a
technological point of view.
KIC InnoEnergy is publishing a set of consistent analyses of various technologies that help in the
understanding and definition of innovation pathways that industries could follow to maintain
the competitiveness of the European clean and renewable energy sector in the global market.
KIC InnoEnergy has developed credible future technology cost models for four renewable
energy generation technologies (onshore and offshore wind, solar photovoltaic and solar
thermal energy generation) using a consistent and robust methodology. The purpose of these
cost models is to enable the impact of innovations on the levelised cost of energy (LCOE) to be
explored and tracked in a consistent way.
This report documents the anticipated future cost of energy for new gas combined heat and
power (CHP) projects and coal plant upgrades reaching their financial investment decisions
(FIDs) in 2020 and 2025. It adopts the established modelling approach to explore the impact
of a range of technical innovations and other effects on baseline cases at the start of 2016. For
the coal plants, because these already exist, the model considers the impact of retro-fitting
technology innovations at different FID years to the existing infrastructure. A coal plant after
retro-fitting is referred to here as a clean coal plant.
The report also covers the role of the EU in regulating energy markets and in regulating emissions,
energy policy trends in the EU covering climate change and carbon dioxide emissions, energy
security and air quality.
Industry input has been provided by subject matter experts nominated by KIC InnoEnergy.
These experts provided input on innovations and their impacts, and review and challenge of
the modelling through the project.

KIC InnoEnergy · Clean Coal and Gas TechnologiesFuture Energy Costs: Coal and Gas Technologies 06 07
At the heart of this study is a cost model in which ‘elements’ of baseline Technology Types (the
power plants) are impacted on by a range of technology innovations. These Technology Types
are a 225MWe unit of a coal power plant (also capable of burning other fuels with appropriate
investment) and a 500kWe gas combined heat and power (CHP) plant. The levelised cost of
energy (LCOE) was calculated for projects reaching FID in 2016 (the baseline), 2020 and 2025.
The combined impacts of anticipated technology innovations over the period for these two
Technology Types are presented in Figure 0.1 and Figure 0.2.
The study concludes that LCOE savings of about 17% and 27% in 2025 are anticipated in gas
CHP and coal plants respectively. With both Technology Types, numerous innovations generate
improvementsinLCOEthroughchangesincapitalexpenditure(CAPEX),operationalexpenditure
(OPEX) and annual energy production (AEP).
Gas CHP plant
Figure 0.3 shows that well over two-thirds of the LCOE savings anticipated in the gas CHP plant arise
from innovations in engine design, fuels and combustion (the first four innovations in the figure).
For the gas CHP plant, 12 technology innovations have the potential to cause a substantial
reduction in LCOE through a change in the design of hardware, software or process. Technology
innovations are distinguished from non-technology innovations, which are addressed separately
as Other Effects. Many other technical innovations are in development and so some of those
described in this report may be superseded over time. Overall, however, we anticipate that the
LCOEreductionshownwillbeachieved.Inmostcases,thepotentialimpactofeachinnovationhas
been moderated downwards in order to give overall levels of cost of energy reduction consistent
with past trends. The availability of such a number of innovations with the combined potential to
reduce LCOE more than shown gives confidence that the picture described is achievable.
To calculate a realistic LCOE, costs for increasing emissions charging in excess of the baseline
values have been considered in addition to technology innovations. The effects of supply chain
dynamics, pre-FID risks, insurance, contingency or transmission have not been considered.
Cost of finance is assumed to be at a fixed rate of 10% for all projects.
Improvements in the combustion chamber for lean mixtures are anticipated to reduce LCOE by
about 4% in the period. Savings are due to innovations in combustion chamber shape and/or the
use of pre-chambers. These innovations drive LCOE down through increased AEP. These effects
make improvements in the combustion chamber for lean mixtures the largest contributor to the
overall reduction in LCOE.
Improvements in the engine mechanical design enable increased power output, utilisation and
AEP, which more than outweigh the CAPEX and OPEX increases required and are anticipated to
reduce LCOE by about 3%.
Improvements in the use of alternative gaseous fuels are anticipated to reduce LCOE by about
3% in the period. Savings are due to OPEX reduction.
Figure 0.1 Anticipated impact of all innovations for the gas CHP plant with FID
2025 compared with FID 2016.
100
75
50
25
0
-25
% CAPEX OPEX Net AEP LCOE
Source:BVGAssociates
Figure 0.2 Anticipated impact of all innovations for the coal plant compared at
FID 2025 with baseline.
30
15
0
-15
-30
Figure 0.3 Anticipated impact of technology innovations for a gas CHP plant with FID in 2025, compared with
a baseline gas CHP plant with FID in 2016.
LCOE for a CHP plant with FID in 2016
Improvements in combustion chambers for lean mixtures
Improvements in engine mechanical design
Improvements in use of alternative gaseous fuels in IC engines
Improvements in power per cylinder from IC engines
Improvements in thermodynamic cycles in IC engines
Improvements in structural materials
Improvements in ignition systems
5 other innovations
70% 75% 80% 85% 90% 95% 100%Source:BVGAssociates

Innovations in power per cylinder from internal combustion (IC) engines are anticipated to
reduce LCOE by about 2% in the period. Savings are due to innovations in the combustion air
boosting system to enable increased fuel-air mass per cycle and increased AEP.
Other innovations in other areas are anticipated to reduce LCOE by a further 5%, through a
mixture of CAPEX and OPEX reductions, and AEP increases.
There are innovations not discussed in detail in this report because their anticipated impact is still
negligible on projects reaching FID in 2025. Among these are the use of liquefied natural gas fuel,
combined thermodynamic cycles, fuel-cell hybrids, alternatives to internal-combustion engines
and advanced emissions treatment systems. The unused potential at FID in 2025 of innovations
modelled in the project, coupled with this further range of innovations not modelled, suggests
there are further cost reduction opportunities beyond 2025.
Coal plant
Figure 0.4 shows that well over half of the LCOE savings anticipated for the clean coal plant in
2025 arise from innovations in the modification, pre-treatment and combustion of new fuels
(the first three innovations in the figure).
For the coal plant, 16 technology innovations were modelled as having the potential to cause a
substantial reduction in LCOE through an improvement in the design of hardware, software or
process. Technology innovations are distinguished from non-technology innovations which are
addressed separately in Other Effects. Many other technical innovations are in development and
so some of those described in this report may be superseded over time. Overall, however, we
anticipate that the level of cost of energy reduction shown will be achieved. In most cases, the
potential impact of each innovation has been moderated downwards in order to give overall
levels of cost of energy reduction consistent with past trends. The availability of such a number
of innovations with the potential to reduce LCOE more than shown gives confidence that the
picture described is achievable.
As for the CHP plant, the effects of supply chain dynamics, pre-FID risks, insurance, contingency
or transmission have not been considered. Cost of finance is assumed to be at a fixed rate of 10%
for all projects.
Introduction of thermal pre-treatment of biomass and waste-based fuels is anticipated to reduce
LCOE by over 9% compared to the baseline plant in FID 2025. Savings are due to OPEX reductions
enabled by greater use of these cheaper fuels. This effect makes this the largest contributor to
the overall reduction in LCOE.
Introduction of hybrid fuel combustion is anticipated to reduce LCOE by nearly 6% compared
with the 2025 baseline plant. Savings are due OPEX reductions enabling further increase in the
use of cheaper fuels.
Improvements in fuel modification and switching are anticipated to reduce LCOE by nearly 6%
compared to the baseline plant in FID 2025. Savings are due OPEX reductions through the use
of additives to reduce emissions and other combustion waste products and through enabling
further increase in the use of cheaper fuels.
Improvements in preventative maintenance are anticipated to reduce LCOE compared to the
baseline plant in FID 2025. Savings are due mainly to reduced OPEX and increased AEP through
the avoidance of unexpected failures and downtime.
Other innovations in other areas are anticipated to reduce LCOE by a further 8-9%, through a
mixture of CAPEX and OPEX reductions, and AEP increases.
There are other coal plant innovations not discussed in detail in this report because their
anticipated impact is still negligible on projects reaching FID in 2025. Among these are the
physical pre-treatment of fuels and carbon-dioxide abatement methods. The unused potential at
FID in 2025 of innovations modelled in the project, coupled with this further range of innovations
not modelled, suggests there are further cost reduction opportunities when looking to 2030
and beyond, if coal plants are still a long-term part of the energy mix then.
Figure 0.4 Anticipated impact of technology innovations for a 225MW unit of a coal plant with FID in 2025.
LCOE for a coal plant with FID in 2025 without innovations
Introductionofthermalpre-treatmentofbiomassandwaste-basedfuels
Introduction of hybrid fuel combustion
Improvements in fuels through modification and switching
Improvements in preventive maintenance
Improvements in power plant start-up systems
Improvements in boiler flexibility
Improvements in treatment of coal combustion byproducts
9 other innovations
LCOE for a clean coal plant with FID in 2025 with innovations

Future Energy Costs: Coal and Gas Technologies 10
Glossary
AEP. Annual electrical energy production.
Anticipated impact. Term used in this report to quantify the expected market impact of a
given innovation. This figure has been derived by moderating the potential impact through
the application of various real-world factors. For details of methodology, see Section 2.
Baseline. Term used in this report to refer to “today’s“ technology, as would be incorporated
into a gas CHP project with FID in 2016, or as exists in a typical coal plant today, (and in the
future if it remains unmodified).
Capacity Factor (CF). Ratio of annual energy production to annual energy production if the
power plant is generating continuously at rated power for the whole year (8,760 hours).
CAPEX. Capital expenditure.
FEED. Front end engineering and design.
FID. Final investment decision, defined here as that point of a project life cycle at which
all consents, agreements and contracts that are required in order to commence project
construction have been signed (or are at or near execution form) and there is a firm
commitment by equity holders and in the case of debt finance, debt funders, to provide or
mobilise funding to cover the majority of construction costs.
Generic WACC. Weighted average cost of capital applied to generate LCOE-based
comparisons of technical innovations.
LCOE. Levelised cost of energy, considered here as pre-tax and real in start of 2016 terms. For
details of methodology, see Section 2.
MW. Megawatt.
MWh. Megawatt hour.
OMS. Operations, planned maintenance and unplanned (proactive or reactive) service in
response to a fault.
OPEX. Operational expenditure.
Other Effects. Effects beyond those of power plant innovations, such as supply chain
competition and changes in financing costs.
Potential impact. Term used in this report to quantify the maximum potential technical
impact of a given innovation. This impact is then moderated through the application of
various real-world factors. For details of the methodology, see Section 2.
Scenario-specific WACC. Weighted average cost of capital associated with a specific
Technology Type and year. Used to calculate real-world LCOE incorporating Other Effects.
Technology Type. Term used in this report to describe a representative power plant (suited to
a given application) for which baseline costs are derived and to which innovations are applied.
For details of methodology, see Section 2.
WACC. Weighted average cost of capital, considered here as real and pre-tax.
WCD. Works completion date.
Table of contents
Executive summary 5
1. Introduction 12
2. Coal and gas policy in the EU 15
3. Methodology 24
4. Gas CHP plant 29
4.a. Baseline 29
4.b. Innovations in fuel handling 32
4.c. Innovations in the combustion system 33
4.d. Innovations in the energy conversion system 36
4.e. Innovations in emissions treatment 37
4.f. Innovations in power plant operation, maintenance and service 37
4.g. Summary of innovations and results 40
5. Coal power plant 43
5.a. Baseline 43
5.b. Innovations in fuel handling 45
5.c. Innovations in the combustion system 47
5.d. Innovations in the energy conversion (steam and electrical) system 49
5.e. Innovations in emissions treatment 52
5.f. Innovations in power plant operation, maintenance and service 53
5.g. Summary of clean coal innovations and results 55
6. Conclusions 59
7. About KIC InnoEnergy 60
Appendix A. Further details of methodology 62
Appendix B. Data supporting tables 67
List of figures 70
List of tables 72

1. Introduction
1.1. Framework
As an innovation promoter, KIC InnoEnergy is interested in evaluating the impact of visible
innovations on the cost of energy from various clean and renewable energy technologies. This
type of analysis is critical in understanding where the biggest opportunities and challenges are
from a technological point of view.
KIC InnoEnergy is publishing a set of consistent analyses of various technologies, to define and help
industries understand the innovation pathways they could follow to maintain the competitiveness
of the European clean and renewable energy sector worldwide. In addition, it seeks to help solve
the existing challenges at the European level: reducing energy dependency; mitigating climate
change effects; and facilitating the smooth evolution of the generation mix for the final consumers.
With a temporal horizon out to 2025, this work includes a range of innovations that might
be further from the market than normally considered by KIC InnoEnergy. This constitutes an
approach that is complementary to KIC InnoEnergy technology mapping which focuses on
innovations reaching the market in the short/mid-term (up to five years ahead).
1.2. Purpose and background
The purpose of this report is to document the anticipated future cost of energy from two
Technology Types - coal plants with upgrades and new gas combined heat and power (CHP)
plants - reaching their financial investment decisions (FIDs) in 2020 and 2025, by reference to
robust modelling of the impact of a range of technical innovations and Other Effects on baseline
cases at the start of 2016. This work is based on methodologies established for KIC InnoEnergy
by BVG Associates (BVGA) over four previous projects covering onshore and offshore wind, solar
photovoltaic and solar thermal energy generation. The focus is on the EU market.
Industry input has been provided by subject matter experts nominated by KIC InnoEnergy, and
who have provided input on innovations and their impacts, and review and challenge of the
modelling through the project. These subject matter experts are:
Gas combined heat and power experts
• Dr. Eng. Jacek Kalina, Institute of Thermal Technology, Silesian University of Technology
• Dr. Eng. Marcin Liszka, President of the Management Board, Exergon
• Dr. Eng. Pawel Raczka, Department of Mechanical Engineering, Wroclaw University of Technology
• Dr. Eng. Jakub Tuka, Chief Specialist for Energy Technologies, Exergon
Clean coal experts
• Henryk Kubiczek, Vice Director of Research and Development, EDF Polska
• Associate Prof. Dr. Eng. Halina Pawlak-Kruczek, Institute of Heat Engineering and Fluid
Mechanics, Wroclaw University of Technology
• Associate Prof. Dr. Eng. Sylwester Kalisz, Institute of Power Machines and Equipment, Silesian
University of Technology
The study does not consider the relative market share of the two Technology Types considered.
The actual average levelised cost of energy (LCOE) in a given year and region will depend on the
mix of all projects with FID in that year.
1.3. Structure of this report
Following this introduction, this report is structured as follows:
Section 2. Coal and gas policy in the EU. This Section describes the role of the EU in regulating
energy markets and in regulating emissions, energy policy trends in the EU covering climate
change and carbon dioxide emissions, energy security and air quality.
Section 3. Methodology. This Section describes the scope of the model, project terminology
and assumptions, the process of technology innovation modelling, industry engagement, and
the treatment of risk and health and safety.
Section 4. Gas CHP plant.
Section 4.a. Baseline. This Section summarises the parameters relating to the baseline power plant
for which results are presented. Assumptions relating to this power plant are presented in Appendix A.
The following five sections consider each element of the power plant in turn, exploring the
impact of innovations in that element.
Section 4.b. Innovations in fuel handling. This Section incorporates fuel treatment and
handlingbeforeandafterarrivalatthepowerplant,andincludesallprocessesbeforecombustion
and the use of alternative fuels.
Section 4.c. Innovations in the combustion system. This Section incorporates the
combustion system itself, pistons, cylinder heads, fuel admission systems, the ignition system
and the combustion control aspects of the control system.
Section4.d.Innovationsintheenergyconversionsystem.ThisSectionincorporateschanges
in other parts of the energy conversion system in the power plant and includes hybridisation
with other energy sources, thermodynamic improvements and increase in power density.
Section 4.e. Innovations in emissions system. This Section incorporates primary and
secondary (post combustion) emissions reduction systems and approaches.
Section 4f. Innovations in operation, maintenance and service. This Section incorporates
improvements for reliability as well as design and remote operation and diagnostics.
Section 4.g. Summary of impact of innovations for clean gas. This Section presents the
aggregate impact of all innovations, exploring the relative impact of innovations in different
elements of the gas CHP plant.

15Future Energy Costs: Coal and Gas Technologies 14
Section 5. Coal power plant.
Section 5.a. Baseline. This Section summarises the parameters relating to the baseline power
plant for which results are presented. Assumptions relating to this power plant are presented in
the Appendix.
The following five sections consider each element of the power plant in turn, exploring the
impact of innovations in that element.
Section 5.b. Innovations in fuel handling. This Section incorporates fuel treatment and
handlingbeforeandafterarrivalatthepowerplant,andincludesallprocessesbeforecombustion
and the use of alternative fuels.
Section5.c.Innovationsinthecombustionsystem.ThisSectionincorporatesthecombustion
system itself, improvement in combustion control for start-up and output flexibility, hybrid fuel
combustion systems and combustion waste-heat recovery.
Section 5.d. Innovations in the energy conversion system. This Section incorporates
changes in other parts of the energy conversion system in the power plant and includes the
steam circuit, steam turbine, boiler and downstream waste-heat recovery.
Section 5.e. Innovations in emissions system. This Section incorporates primary and
secondary (post combustion) emissions reduction systems and approaches.
Section 5.f. Innovations in operation, maintenance and service. This Section incorporates
improvements for reliability, preventative maintenance as well as remote operation and
diagnostics.
Section 5.g. Summary of impact of innovations for clean coal. This Section presents the
aggregate impact of all innovations, exploring the relative impact of innovations in different
elements of the coal power plant.
Section 6. Conclusions. This Section includes technology-related conclusions for both types
of power plant.
Appendix A. Details of methodology. This appendix discusses project assumptions and
provides examples of methodology use.
Appendix B. Data tables. This appendix provides tables of data behind figures presented in
the report.
2. Coal and gas policy in the EU
2.1. Introduction
European energy systems have entered a period of rapid transition. This transition is driven
by technological and policy responses to three major inter-connected challenges: avoiding
dangerous climate change; ensuring energy security for the EU; and fostering economic
competitiveness in the EU.
Electricity generation based on fossil fuels is currently a significant element of most
European energy systems, and for many countries domestic production of lignite, hard
coal, and natural gas still contributes to energy independence. In its current form, this
method of electricity generation is not consistent with the long-term goals of EU energy
policy. Coal- and gas-based power generation will have to undergo the greatest changes
as a part of energy transition in the EU, affecting both the technologies used and their
roles in the system.
The EU policy framework sets the stage for this transition, both in short and long term. It is
thus important to take into account its current form and likely future evolution when exploring
the development of novel energy solutions based on fossil fuels. This will ensure that current
innovation effort will meet future market demand, not only in the EU, but also globally. Successful
implementation of new technologies in Europe provides an opportunity to lead by example
and develop products and expertise to sell in other markets.
This Section presents the EU role in regulating energy sector in the member states. Subsections
2.3 and 2.4 provide an overview of current legislative framework in this area and anticipated
future dynamics of the EU policy are covered in subsection 2.5. The Section concludes with a
discussion on implications for energy technologies based on coal and gas (subsection 2.6).
2.2. Coal and gas-fired plants in the EU energy system
The EU electricity production is diverse, with a limited share for each type of energy technology,
and the dependence on fossil fuels varies significantly by member state.

While numerous central European countries rely on domestic lignite deposits, natural gas and
hard coal are vital elements of energy mixes across the EU. Only countries with a significant
hydropower potential and/or ambitious nuclear energy programmes have been so far able to
minimise their reliance on the fossil fuels to produce electricity.
While new energy technologies based on wind and solar energy are being deployed in the EU,
so far the issue of supply variability has not been addressed. Thus, there is still a need for flexible
back-up plants, which should be in line with climate and environmental objectives of the EU
policy.
While the EU as a whole imports most of the natural gas and hard coal it uses, the level of
energy dependence also varies among the member states. Despite the phase-out of hard coal
mining in most of the EU (with Poland remaining the biggest producer), numerous European
countries such as Germany, the Czech Republic, and Greece rely on their domestic lignite
resources. Several member states have enough natural gas deposits to cover a significant
part of domestic demand or even export the fuel abroad (for example, the Netherlands and
Denmark). Thus, while renewables and energy efficiency are crucial for ensuring energy
security for the EU as a whole, there is also a rationale for further development of coal and
gas technologies which will allow to use European indigenous fossil fuels in the cost-efficient
and sustainable way.
2.3. The EU role in regulating the energy sector
The Lisbon Treaty, which came into force in December 2009, introduces shared competence
in the area of energy policy between the member states and the EU. This means that both
the states and the EU institutions have an impact on the regulations shaping the energy
sector. The specific provisions are given in article 194 of the Treaty for the Functioning of the
European Union.
The EU’s aims in the energy sector are to:
• ensure the functioning of the energy market
• ensure security of energy supply in the EU
• promote energy efficiency and energy saving and the development of new and renewable
forms of energy, and
• promote the interconnection of energy networks.
The Treaty assumes that the member states retain the right to determine their own energy
mix. The unanimous support from the states is required for environmental policies affecting
domestic energy use as well as energy taxation. Thus, while the EU institutions have a mandate
to pursue the development of single energy market and decarbonisation of the European
energy system, they cannot directly determine the energy choices on national level. In practice,
however, the European climate and environment protection legislation is a complex set of
rules that significantly limit viable energy options in accordance with the broader sustainable
development goals of the EU. Furthermore, the EU has an exclusive competence in the area of
competition protection. This means that it has a final say on the state aid rules and is able to block
domestic support schemes in the energy sector if they are seen as harming the competition on
the internal market. Other areas of the EU intervention – such as R&D support or cohesion policy –
may also influence energy sector by redirecting the public funds towards development of
preferred elements of the energy mix.
As a result, the EU regulatory framework in the areas of energy, climate, environment and
competition define the prospects for the energy sector in Europe, as shown in Figure 2.1. Power
generation from fossil fuels – notably hard coal, lignite, and natural gas – faces the greatest
challenges. In order to meet the stringent environmental targets, this part of the energy sector
has to transform itself while facing ever more competitive pressure from low-carbon sources.
2.4. Key European regulations affecting coal and gas-fired plants
2.4.1. EU emissions trading scheme
The EU Emission Trading Scheme (EU ETS) is a key instrument for achieving the long-term
greenhouse gas (GHG) reduction targets in the EU. By setting an absolute cap on the
greenhouse gases emitted by the sectors covered (including power generation) and allowing
emitters to trade the resulting limited number of emission allowances, it creates the price
signal to reduce GHG emissions. Gradually decreasing the total GHG limit by reducing the
number of available emission allowances each year increases the pressure to lower emissions
from the energy sector over the long term. From 2013 to 2020, the cap is reducing by 1.74%
per year. From 2021 onwards, the annual reduction will rise to 2.2% in order to meet the goal
of 40% GHG cuts in the EU by 2030.
In the short and medium term, the relevance of EU ETS as a driver of power sector decarbonisation
is unclear, due to oversupply of allowances on the market. This has driven down the costs of
CO2
emissions and weakened the price signal to invest in low-carbon solutions. The EU has
responded by pursuing structural reform of the system. Its key element – the market stability
reserve (MSR) – will start operating in 2019. Each year, 12% of allowances in circulation will be
removed from the market to MSR if the surplus of allowances is higher than a predefined level
(833 million allowances). When the surplus falls below 400 million allowances (or their price rises
sharply), 100 million allowances accumulated in the MSR will be released back to the market
each year. Thus, the MSR is a quantity-based mechanism which aims to stabilise the price of GHG
emissions. It remains to be seen whether and to what extent this goal will be achieved.
Figure 2.1 Key European policy areas influencing the energy sector.
Source:WiseEuropa
Competition
rules
Energy
Environment
/ Climate
Stronger
Member States’
Stronger
EU competency

EU ETS is also intended to provide a source of funding for low-carbon technologies. Regulations
state that at least half of the revenue from national auctions should be used for funding climate
change mitigation and adaptation measures. In addition, after 2020, 400 million allowances will
be used to create an innovation fund, which will support deployment of innovative low-carbon
technologies in the energy sector and wider industry. It will operate in a similar way to the
current NER300 programme, which is focused only on low-carbon energy generation.
EU ETS will finance a modernisation fund, which will support the energy sector transition in
member states with relatively low GDP per person. Most of these countries have already
secured derogation for their energy sectors, allowing free allocation of allowances to electricity
generators in exchange for investments to modernise and reduce carbon emissions. In principle,
all these funds may be used for the development and scaling up of technologies for low-carbon
production of energy from coal and gas technologies, including carbon capture and storage
(CCS) solutions. The current low price of allowances, however, does not provide an adequate
price signal for this technology development as shown in Figure 2.2. Thus, while EU ETS reduces
incentives for the development of conventional coal- and gas-fired- power plants in the long
term, it does not provide sufficient support for the development of clean alternatives based
on fossil fuels to proceed as quickly as it could. The result is investment uncertainty and slower
progress in deployment of technologies including CCS in Europe.
2.4.2. Air quality
EU climate policy is not the only driver of environmental regulations affecting the prospects of
coal- and gas-based power generation in the EU. Another important factor, especially in short
and medium term, is EU legislation related to air quality. The EU Industrial Emissions Directive
(IED) sets mandatory emissions standards for large industrial installations, including power plants,
as shown in Table 2.1. The standards concerning harmful substances such as sulphur or nitrogen
oxides apply to existing installations from January 2016. Numerous derogations give utilities
enough time to retrofit their power plants according to new rules, however. These include plants
that have a limited lifetime and are expected to be decommissioned at the latest by the end of
2023, small systems isolated from the energy network, and plants focused on providing useful
heat to public networks. The derogations end between 2020 and 2023.
The IED introduces the mandatory use of best available techniques (BAT), which means the
ones that offer the greatest (currently feasible) reduction of pollutant emissions and their
impact on the environment. The BATs are defined in BAT reference documents (BREFs),
which will become legally binding in the regulatory framework set by the IED. BATs for large
combustion plants will be applicable to coal- and gas-powered plants. They are expected
not only to tighten the existing standards (such as those for emissions of sulphur and
nitrogen oxides), but also introduce new standards for substances previously not covered by
environmental regulations. This will result in further retrofit needs for existing power plants, as
well as increased investment costs.
Utilities that decide to invest in retrofitting existing coal- and gas-fired power plants face
the risk of not recovering the costs of compliance to new air quality regulations. This is
due to two key factors. Firstly, revenues from the wholesale electricity market do not cover
the fixed costs of conventional plants. While this issue may be eventually addressed by
the energy market reform, there is the second factor: unclear position of retrofitted power
plants in the future merit order (supply curve) due to potential increases in the emission
allowance prices and further growth of renewables. The higher the variable costs of
coal and gas plants relative to other installations in the system, the lower their capacity
utilisation. This, in turn, increases the cost of compliance to emission standards per unit of
energy produced.
2.4.3. State aid rules
The EU Guidelines for State Aid1
is the key document describing state aid rules related to the
energy sector. From the perspective of coal- and gas-based generation, the two key chapters are
those related to generation adequacy (capacity mechanisms) and CCS support. While guidelines
for the latter are relatively clear, allowing both operating and investment aid for CCS if it covers
1 Guidelines on State aid for environmental protection and energy 2014-2020, European Commission, 28 June 2014
Figure 2.2 The role of the EU emissions trading system in stimulating
low carbon investments.
Long-term GHG
target visibilty
Funding for
innovations
Price
signal
Low-carbon investment
Uncertain price developments
Source:WiseEuropa
Table 2.1 EU air quality regulations for coal and gas-fired power plants.
Regulation Timeline
Industrial Emissions Directive (IED) Entry into force: 6 January 2011
Compliance deadline for existing plants: 1 January 2016
IED derogations Transitional National Plans 1 January 2016 – 30 June 2020
Limited life time derogation 1 January 2016 – 31 December 2023
Small isolated systems 1 January 2016 – 31 December 2019
District heating plants 1 January 2016 – 31 December 2022
BAT conclusions concerning 4 years after publication
Large Combustion Plants (LCP) Estimated compliance deadline: 2021
Source:IED Directive,WiseEuropa

the additional costs of the installation compared to conventional plant, the Commission’s
approach to the generation adequacy is more nuanced.
According to the guidelines, various forms of capacity mechanisms (providing remuneration
to utilities for maintaining availability of power plant capacities in order to ensure security
of supply on electricity market) should be introduced only if other options for balancing
supply and demand have failed, as shown in Figure 2.3. Specifically, this includes using the
potential of interconnections between the national energy systems and providing incentives
for electricity users to reduce their consumption at times of peak demand (demand side
response). Furthermore, before adding new mechanisms to the market, improvements to
the existing structure must be explored. One example is removing price caps on wholesale
electricity markets, which should provide additional incentives to maintain existing power
plants and invest in new installations. From the point of view of coal- and gas-based power
plants this means that they will have to compete with alternative options for providing
security of supply in electricity markets.
2.5. Prospects for EU policy
2.5.1. Climate policy after COP21
Since 2005 and the establishment of the ETS, the EU has demonstrated that it is strongly
committed to its climate goals. The COP 21 Paris agreement has reinforced this commitment,
signalling that global and EU climate policy will be tightened over time. Although the
negotiations that concluded during COP21 took a bottom-up approach (each party
declaring its own climate policy targets), the global policy shift towards decarbonisation
has been confirmed. In consequence, calls for upward revision of EU climate and energy
targets for 2030 have re‑emerged. These calls have been largely ignored so far, as the
debate on climate policy within the EU remains largely driven by the internal discussions
on ETS reform.
The key unresolved question concerns the role of the system in the expected decarbonisation
of Europe’s power system and industries. At the same time, the need for technology specific
policies for renewable energy systems, energy efficiency, nuclear or clean coal is often
underlined. In this context the Paris agreement should be seen as a confirmation rather than
an enhancement of European ambitions in the climate protection area. In the future, actions of
third parties including the U.S. and China may put additional pressure on Europe to adopt more
far-reaching commitments.
The long-term viability of coal- and gas-based electricity generation depends on the
technological innovations allowing them to stay in the merit order not only if the EU ETS price
significantly increases, but also if even near-100% carbon emissions reductions targets are
adopted. While the EU provided funding for pilot CCS projects, low ETS prices and investment
uncertainty have resulted in much slower progress than expected in this area. Various measures
to increase the pace of CCS development in Europe are considered for the near future, but no
actions have been undertaken up to date.
On the other hand, without technologies such as CCS (and others such as carbon capture and
utilisation and CO2
enhanced oil recovery), achieving the EU climate targets for 2050 may be
either costly or technically not feasible, especially if process emissions in industry are taken
into account (such as produced from cement or chemical plants). The potential for achieving
“negative emissions” from biomass and CCS plants creates opportunities for future research and
innovations within this area.
2.5.2. Energy security
While the current EU framework prioritises renewables and energy efficiency as long-term
contributors to improved energy security, the role of indigenous fossil fuels (including
coal and shale gas) is also recognised by the Commission, provided their use is in-line with
climate goals and environmental standards. There are major technological and geopolitical
arguments for their continued use in the European energy system even if the ambitions
reduction targets are accepted.
Coal- and gas-fired power plants are still expected to contribute to security of supply,
providing necessary flexibility and predictability for the future energy system. This may
change if technological alternatives in the form of cost-effective energy storage are
developed. It is, however, considered unlikely that this will happen on a system-wide
scale before 2030. Therefore, the EU has undertaken numerous steps towards increasing
gas supply security, including supporting infrastructure developments, promoting
regional approaches to resolving gas supply distortions, and increasing the transparency
of intergovernmental agreements in energy. On the other hand, coal supplies are
considered secure despite the significant dependence of the EU as a whole on imports,
thanks to the diversity in the potential suppliers and high market liquidity. Because of
that, domestic hard coal sources are not perceived by most of the parties (including the
Commission and most member states) as a significant contributor to energy security for
the continent.
2.5.3. Cost of energy, air quality and single energy market
Energy affordability is one of the core objectives of EU energy policy. However, it co-exists with
other goals, notably climate protection and security of supply.
Figure 2.3 EC approach to the capacity mechanisms assessment.
Preferred options Last resort option
Reforming energy
only market
Capacity
mechanismsDemand side
response
Interconnections
Source:WiseEuropa

This means that minimisation of energy costs is constrained by reaching other targets. In
practice, this is seen in the EU preference for market-based mechanisms which are expected to
allow cost-efficient achievement of sustainable, secure energy supply.
Two converging processes are visible:
1. Development of a new energy market design, and
2. Deepening energy market integration under the Third Energy Package.
These are both intended to increase cost-efficiently the security of supply within the EU and – at
thesametime–supportgradualdecarbonisationoftheEuropeanpowersystem.Aconsequence
of these processes is likely to be that coal- and gas-fired plants will face more competition in
each market, through external energy supply and internally through higher levels of renewable
and increased demand response.
At the same time, clean coal technologies and CCS for gas are included in the long-term
energy decarbonisation pathways by the EU and other international institutions, such as the
International Energy Agency (IEA). While more expensive than conventional coal- and gas-
fired power plants, they significantly reduce the costs of the deep decarbonisation policies
in the energy sector and therefore remain an attractive alternative option as part of the
future power mix. In this context more innovative approaches to the integration of clean
coal and gas technologies with renewable generation are required in the longer term to
achieve least-cost operation of the whole energy system (for example to avoid very low
capacity utilisation rates at CCS plants).
An important element of EU energy and environmental policy is air quality. Policy focus in
this respect is gradually moving from industrial emissions (covered by IED) towards pollution
from other sources, such as the transport and residential sectors. In this context, electrification
of transport and development of district heating may contribute to air quality improvement,
while at the same time increasing demand from the power sector. As such, this offers new
opportunities for fossil-fuel-based technologies, provided they are able to reduce their GHG
emissions significantly. This again shows the importance of CCS and other clean coal and gas
technologies for their future in the EU energy system.
CHP production is one of the technological options, providing reduced fuel inputs and CO2
emissions. The use of CHP is promoted by the Energy Efficiency Directive, which requires
a cost-benefit assessment of CHP introduction whenever there is a potential for such
investment (usually when there is new investment or substantial refurbishing of power
plant, industrial facility or district heating network). Nevertheless, coal- and gas-based CHP
plants are under significant regulatory and market pressure. They face challenges related
both to electricity and heat production, such as low wholesale electricity prices, new
emission standards and the need to compete with distributed heat production, which is
often not subject to similar climate and environmental standards. Furthermore, in its Heating
and Cooling Strategy communication released in February 2016, the European Commission
focuses mainly on renewables-based CHP, such as biomass-fired or geothermal installations.
Nevertheless, there are potential synergies between CHP and CCS technologies which may
improve the competitiveness of coal- and gas‑fired plants because the unit costs of capture
and storage of CO2
are reduced, as the investment and operating burden is spread over
higher total energy production.
2.6. Implications for coal and gas-fired energy technology
development
The European regulatory framework puts pressure in three ways on conventional coal- and
gas-based power plants:
• Increased costs related to climate and other environmental externalities
• Limited possibilities for receiving state aid, and
• Increased competition on the single energy market.
Global climate policy leads in the same direction. After the COP21 Paris summit in 2015, it
regained its momentum, casting doubts on the long-term prospects of unabated fossil fuels in
the global energy mix. These processes make conventional coal- and gas-based power plants
largely incompatible with the European and global climate policies in the long-term. Further
development of renewables and energy efficiency measures together with the increase of ETS
allowance prices will gradually decrease the capacity utilisation factors of existing and planned
conventional coal- and gas-fired plants.
At the same time, fossil fuel power plants have distinctive technological features that make them
useful, elements of the modern energy systems. Therefore, the energy transition foreseen by
European policy should not be seen as just a threat for fossil fuels, but also an opportunity to
redefine the place of coal- and gas-fired plants in the broader energy system.
There is an urgent need for low-carbon innovations, as only affordable, near zero-emission
technologies are likely to secure market share for electricity production after 2030. Developing
solutions for near zero-emission fossil fuel plants will significantly decrease the cost of energy
transition, stabilizing the energy system and providing much-needed security of supply.
Market liberalisation and integration mean that innovative coal- and gas-based solutions should
address not only technical, but also market challenges, such as low capacity factors driving up
the average total cost of electricity production. Developing affordable low-carbon options
for fossil fuel use is also important from the global perspective. It will contribute to increased
ambition of climate policies beyond the EU, which is necessary to meet ambitious goals set by
the Paris agreement.

3. Methodology
3.1. Scope of model
The basis of the model is a set of baseline elements of capital expenditure (CAPEX),
operational expenditure (OPEX) and annual energy production (AEP) for two different
representative Technology Types under given conditions, impacted by a range of
technology innovations. Analysis is carried out at two further points in time (years of
FID), thus describing various potential pathways that the industry could follow, each with
an associated progression of LCOE. The model has been successfully used in previous
projects delivered by BVGA for KIC InnoEnergy.
While the baselines each represent a relevant current plant, the innovation impact modelling
and moderation process results in an average impact on LCOE for projects with FID in the year
under consideration.
There is significant variability in costs between projects, due to both supply chain and
technology effects, even within the portfolio of a given power plant developer. As such, any
baseline represents a wide spectrum of potential costs and it is accepted that there will be
actual projects in operation with LCOEs significantly higher and lower than those associated
with these baselines.
Note that the baselines and methodologies are slightly different for the gas CHP plant and the
coal plant, as described below. There are two reasons for this:
• CHP plants generate revenue from heat sales. The revenue from this is included by offsetting it
against fuel usage costs.
• CHP plants are constructed as new projects at each FID year, while the coal plants are existing
infrastructure in most countries and are considered as such in this study. For the coal plants,
because these already exist, the impact modelled is that of retro-fitting technology innovations
at different FID years to the existing infrastructure, and assuming a fixed end of life in 2035. A
coal plant after retro-fitting is referred to here as a clean coal plant.
3.2. Project terminology and assumptions
3.2.1. Assumptions
A detailed set of baseline assumptions were established in advance of modelling. These are
presented in Appendix A, covering technical and non-technical global considerations and
power-plant-specific parameters.
3.2.2. Terminology
For clarity, when referring to the impact of an innovation that lowers costs or the LCOE, terms
such as reduction or saving are used and the changes are quantified as positive numbers. When
these reductions are represented graphically or in tables, reductions are expressed as negative
numbers as they are intuitively associated with downward trends.
Changes in percentages (for example, losses) are expressed as a relative change. For example, if
innovation reduces losses by 5% from a baseline of 10%, then the resulting losses are 9.5%.
3.3. Innovation impact modelling – gas CHP plant
The basis of the model is an assessment of the differing impact of technology innovations in
each of the power plant elements on the baseline power plant, as outlined in Figure 3.1. This
Section describes the methodology for analysis of each innovation in detail. An example is given
in Appendix A.
The baseline power plant is defined in detail in Section 4.a, and represents a typical modern gas
CHP plant for projects reaching FID at the start of 2016 that produces 700kW of heat and 500kW
of electricity.
Where an innovation changes electricity generation efficiency and therefore heat output, the
plant is scaled to deliver the same 700kW heat output as the baseline, as consistent heat delivery
is a priority for a CHP plant. This changes the electrical energy output, and it is assumed that this
can be supplied to the grid at commercial rates.
Figure 3.1 Process to derive impact of innovations on the LCOE. Note that
Technology Type in this study means type of power plant.
Baseline parameters for given power plant
Revised parameters for given power plant
Anticipated technical impact of innovations
for given Technology Type and year of FID

Figure 3.2 summarises this process of moderation.
3.3.1. Maximum technical potential impact
Innovations are considered in clusters of similar technologies or impacts. Each of these may
affect a number of different costs, AEP or losses, as listed in Table 3.1. The maximum technical
potential impact on each of these is recorded for each innovation cluster. Where relevant and
where possible, this maximum technical impact considers timescales that may be well beyond
2025, the final year of FID.
Frequently,thepotentialimpactofaninnovationcanberealisedinanumberofways,forexample
through reduced CAPEX or OPEX, or increased AEP. The analysis uses the implementation
resulting in the largest reduction in the LCOE, which is a combination of CAPEX, OPEX and AEP.
3.3.2. Commercial readiness
In some cases, the technical potential of a given innovation will not be fully realised, even on a
project with FID in 2025. This may be for a number of reasons:
• A long research, development and demonstration period for an innovation
• The technical potential can only be realised through a design’s ongoing evolution based on
feedback from commercial-scale manufacture and operation, or
• The technical potential impact of one innovation is decreased by the subsequent introduction
of another innovation.
This commercial readiness is modelled by defining a factor for each innovation specific to
each year of FID, defining how much of the technical potential of the innovation is available to
projects with FID in that year. If the figure is 100%, this means that the full technical potential
is realised by the given year of FID. For some of the innovations modelled, it is anticipated that
further progress will be made after the last year of FID modelled (2025).
The factor relates to how much of technical potential is commercially ready for deployment in a
commercial plant of the scale defined in the baseline, taking into account not only the offering
for sale of the innovation by the supplier but also the appetite for purchase by the customer.
Reaching this point is likely to have required full-scale demonstration. This moderation does not
relate to the share of the market that the innovation has taken but rather how much of the full
benefit of the innovation is available to the market.
3.3.3. Market share
Each innovation is assigned a market share for each year of FID. This is a market share of an
innovation for a given Technology Type for projects with FID in a given year. It is not a market
share of the innovation in the whole of the market that consists of a range of projects with
different Technology Types.
The market share may be impacted by factors such as the limited availability of low cost fuels,
and takes into account the application of competing technology innovations.
The resulting anticipated impact of a given innovation, as it takes into account the anticipated
market share of this Technology Type in a given year of FID, can be combined with the anticipated
impact of all other innovations to give an overall anticipated impact for this Technology Type
and year of FID. At this stage, the impact of a given innovation is still captured in terms of its
anticipated impact on each cost and operational parameter, as listed in Table 3.1.
These impacts are then applied to the baseline costs and operational parameters to derive the
impact of each innovation on LCOE for each Technology Type and year of FID, using a generic
weighted average cost of capital (WACC).
The aggregate impact of all innovations on each operational and energy-related parameter in
Table 3.1 is also derived, enabling a technology-only LCOE to be calculated for each combination
of Technology Type and FID year.
3.3.4. Treatment of Other Effects
To derive a real-world LCOE, this ‘technology-only’ LCOE is factored to account for the impact of
various other effects, defined for each combination of Technology Type and year of FID as follows:
• Scenario-specific WACC, taking into account risk beyond that covered by contingency
• Increasing costs over time for emitting pollutants (emissions costs in excess of the
baseline costs)
A factor for each of these effects was derived for each specific Technology Type and FID year, as
presented in Appendix A.
The factors are applied as follows:
Figure 3.2 Three-stage process of moderation applied to the maximum potential
technical impact of an innovation to derive anticipated impact on the LCOE.
Anticipated technical impact for a given
Technology Type and year of FID
Technical potential impact for a given Technology
Type and year of FID
Maximum technical potential impact of innovation
under best circumstances
Commercial readiness
Market share
Table 3.1
Information
recorded for each
innovation. (%)
Impact on cost of
• Power plant development and balance of plant
• Fuel handling
• Energy conversion system
• Emissions system
• Power plant operation, maintenance and service
• Fuel usage, and
• Emissions
Impact on
• Gross AEP, and
• Losses

Future Energy Costs: Coal and Gas Technologies 28 29
• Scenario-specific WACC is used in place of the generic WACC to calculate a revised LCOE, and
• The emissions cost factor is applied to this LCOE to derive the real-world LCOE, for example, a
12.0% effect to account for emissions cost is applied as a factor of 1.120.
These factors are kept separate from the impact of technology innovations in order to clearly
identify the impact of innovations, but they are needed in order to be able to compare LCOE for
different years and Technology Types rationally.
The effects of changes in construction time or scheduling are not modelled.
3.4. Innovation impact modelling – coal power plant
The modelling for the coal power plant focuses on a single 225MW unit and is similar to that
described above, with three important differences:
• Compared with the existing installed base, only a small number of new coal plants are
expected to be built in Europe in the period being studied and an alternative method for
setting capital cost baselines was needed. The capital cost baseline for this Technology Type
in 2016 is modelled as the market price for an existing power plant as it currently is. Capital
cost baselines for this Technology Type in 2020 and 2025 are also produced in the same
way assuming no innovations or other upgrades are implemented at earlier points in time.
The CAPEX breakdown is modelled as a nominal split based on experience (rather than by
knowledge of the costs of components produced by the supply-chain as is the case for the
gas CHP plant).
• The power plant is assumed to cease operation in 2035, so in 2016 its life is 19 years, in 2020 its
life is 15 years and in 2025 its life is 10 years.
• The innovations are modelled as being implemented (or retro-fitted) on this baseline power
plant in 2016, 2020 or 2025.
As a result of this approach, although the baseline LCOE increases, the impact of innovations in
reducing the LCOE increases with time, as shown in Figure 3.3.
4. Gas CHP plant
4.a. Baseline
The modelling process described in Section 3 is to:
• Define a set of baseline power plants and derive costs, and energy-related parameters
for each
• For each of a range of innovations, derive the anticipated impact on these same parameters
for each baseline power plant, for a given year, and
• Combine the impact of a range of innovations to derive costs, and energy-related
parameters for each of the baseline power plants for each year.
This Section summarises the costs and other parameters for the baseline gas CHP plant.
This baseline was developed by the subject matter experts in gas CHP systems.
The baseline costs presented in Table 4.1 and Figure 4.1 and Figure 4.2 are nominal contract
values, rather than outturn values, and are for projects with FID in 2016. As such, they
incorporate real-life supply chain effects such as the impact of competition. All results
presented in this report incorporate the impact of technology innovations only, except
for when LCOEs are presented in Section 4.g.3, which also incorporate the Other Effects
discussed in Section 3.3.4.
Figure 3.3 Baseline LCOE for the 225MW unit of a coal plant and LCOE
with innovations.
80
60
40
20
0
LCOE (€/MWh) Coal-16 Coal-20 Coal-25
•LCOE(Withinnovation) •LCOE(Noinnovation)

The baseline plant is assumed to use a reciprocating, spark-ignited internal combustion engine
operating on natural gas from the pipeline grid. It is assumed to operate at 1500 revolutions
per minute, and use turbocharging, aftercooling and a lean-burn combustion strategy with an
excess air ratio of approximately 1.5.1. The electrical rating is 500kW, and the heat output rating
is 700kW, which is typical for industrial and district heating sectors in Europe. 234
Because CHP systems are sized to deliver a certain heat output, if innovations affect electrical
efficiency (and hence energy available as heat changes), then the unit would be re-sized to
keep heat output the same. Any extra electricity generated from this re-sizing would be sold
to the grid.
CAPEX is assumed all to be in the year before start of operation. The value of the heat output is
calculated and used to offset the fuel OPEX.
2 For a CHP plant, the emissions treatment system is integral to the energy conversion system. The CAPEX for emissions treatment is
shown as nil and impacts on the cost of this system are modelled by changes in the CAPEX for the energy conversion system.
3 After allowing for heat sales income of €247,000, based on 5,280MWh per year and €46.8/MWh price for the heat for the 500kW unit.
4 Emission cost from a CHP plant depends on national regulations. In this case it is modelled as the same nominal value as used in
Poland for this plant size.
These baseline parameters are used to derive the LCOE for the baseline plant. The LCOE for the
baseline power plant is presented in Figure 4.3
Figure 4.2 Baseline OPEX and net capacity factor.
250 100
200 80
150 60
100 40
50 20
0 0
CHP-16
Netcapacityfactor(%)
OPEX(€k/MW/yr)
•OMS •Fuelusage •Emissionscost •Netcapacityfactor
Figure 4.1 Baseline CAPEX by element.
1,500
1,000
500
0
Source:BVGAssociatesTable 4.1 Baseline parameters for 500kW gas CHP plant with FID in 2016.
Type Parameter Units 2016 FID
CAPEX Development €k/MW 244
Fuel handling 81
Energy conversion system 1,303
Emissions treatment2
0
OPEX Operations, planned and unplanned Maintenance €k/MW/yr 68
Fuel usage cost (net of heat sales income) 2023
Emissions cost4
1
AEP Gross AEP MWh/yr/MW 7,500
Losses % 2.5
Net AEP MWh/yr/MW 7,312
Net capacity factor % 83.5
CHP-16
€k/MW
•Development •Fuelhandling •Energyconversionsystem •Emissionstreatment
Figure 4.3 LCOE for baseline power plant with Other Effects incorporated.
100 100
80 80
60 60
40 40
20 20
0 0
•LCOEincludingOtherEffects •Netcapacityfactor
CHP-16
LCOE(€/MWh)

4.b. Innovations in fuel handling
4.b.1. Overview
Innovations in fuel handling and usage are anticipated to reduce the LCOE of gas CHP
plants in 2025 by about 4% compared with the baseline 2016 plant. All the savings result
from OPEX reductions.
Table 4.2 and Figure 4.4 show that the innovation with the largest anticipated impact in
FID 2025 is improvements in the use of alternative gaseous fuels in internal combustion
(IC) engines.
4.b.2. Innovations
Innovations in fuel handing and usage generally focus on the use of fuels other than network
natural gas (the normal fuel). A subset of the more important of these has been modelled here.
In addition, an innovation in the use of liquefied natural gas (LNG) as a fuel was considered.
Operation on LNG could reduce the LCOE in niche applications where the engine
otherwise uses diesel fuel, and in applications where the availability of low-temperature
cooling has significant benefit. In most applications, however, this innovation would
increase the LCOE from a baseline system operating on natural gas and so is not included
in the overall analysis.
Practice today: Gas engines in CHP plants are designed for operation on natural gas and,
when demanded, are adjusted for operation on alternative gas fuels. This adjustment
is usually accompanied by engine derating and control problems due to variability in
the gas composition causing differences in fuel energy value and combustion flame
propagation rates.
Innovation: This innovation covers the development of reliable and effective gas engine
technology for utilisation of coke oven gas, biomass gasification gas, and other industrial waste
gasses. Activities are focused on:
• Effective and reliable fuel systems for low calorific and polluted gases (such as coke-oven gas,
blast-furnace gas, tail gas, tar-rich gas, hydrogen-rich purge gases, biogas)
• Power plant integration with electrolysis for hydrogen production and injection into
the engine
• Combustion of hydrogen and natural gas mixtures.
Commercial readiness: 70% of the benefit of these innovations is realisable in 2020, with 100%
realisable by 2025, because, although technology development is required, there is a strong cost
saving driver.
Market share: It is anticipated that this innovation will be implemented on 10% of plants in
2025, due to the limited availability of low-cost alternative gases.
Improvements in use of alternative liquid fuels in IC engines
Practice today: Engines in the CHP sector almost exclusively run on gaseous fuels, due to poor
availability of low-cost liquid fuels.
Innovation: This innovation covers development of engines to use liquid fuels from
biomass conversion processes. This includes bio-oils from pyrolysis, biodiesel, methanol
and ethanol. The innovation concerns combustion system development for full operation
on the liquid fuel and for fuel mixtures (especially liquid biofuels and methanol mixed with
gas in dual-fuel engines).
realisable by 2025, as technology development will be complete, but not all manufacturers may
choose to offer engines with liquid fuel capability.
Market share: It is anticipated that this innovation will be implemented on 5% of plants in 2025,
due to the market being limited by the supply of such fuels.
4.c. Innovations in the combustion system
4.c.1. Overview
Innovations in the combustion system are anticipated to reduce the LCOE of gas CHP
plants in 2025 by over 10% compared with the baseline 2016 plant. All the savings result
from AEP increases.
Table 4.3 and Figure 4.5 show that the innovations with the largest anticipated impact in FID 2025
are improvements in engine mechanical design and improvements in combustion chambers for
lean mixtures. In both cases AEP increases far outweigh CAPEX and OPEX increases.
Figure 4.4 Anticipated and potential impact of fuel handling and usage innovations on LCOE
for a project with FID in 2025.
Improvements in use of alternative liquid fuels in IC engines
Impact on LCOE
•Anticipated •Potential
0% 10% 20% 30% 40% 50%
Table 4.2 Anticipated and potential impact of fuel handling and usage innovations for a project with FID in 2025.
Innovation Maximum technical potential impact Anticipated impact FID 2025
CAPEX OPEX AEP LCOE CAPEX OPEX AEP LCOE
Improvements in use of alternative
gaseous fuels in IC engines -16.0% 100.8% -15.5% 39.8% -1.6% 10.1% -1.6% 3.4%
Improvements in use of alternative
liquid fuels in IC engines -15.9% 48.6% -0.6% 19.6% -0.6% 1.7% 0.0% 0.7%

4.c.2. Innovations
Innovations in the combustion system span a range of technologies from ignition systems to
control and mechanical design. A subset of the more important of these has been modelled here.
Practice today: Gas engines in CHP plants are usually spark ignited. Spark ignition is effective but
limitspeakefficiency due tothetendency ofthegas-airmixturetodetonate.Dualfuel technology,
where a small injection of diesel is used to ignite the gas is available but not widely adopted due
to the higher price of diesel fuel and the additional complexity of a second fuel system.
Innovation: This innovation covers the improvement of engine ignition systems to support
faster combustion and enable operation at higher efficiencies and with lower emissions. The
innovation includes:
• Laser and other high-energy ignition systems for very lean air-fuel mixtures
• Developmentandimplementationofhomogeneouschargecompression-ignitioncombustion
• Furtherdevelopmentofdual-fueltechnologyusingverysmall(pilot)quantitiesofdieseloralternatives.
realisable by 2025 after the development and commercialisation of some of the more advanced
systems is completed.
2025 and focused on the higher-cost systems in applications with higher utilisation.
Practice today: Mechanical design of modern gas CHP engines features reciprocating four
stroke multi-cylinder designs usually in vee or in-line configurations, constructed from a mix of
steels, cast iron and aluminium alloys.
Innovation: This innovation covers two areas:
• Increase in power output through new configurations, such as opposed piston engines,
through new designs of pistons and cylinder heads enabled by new materials and design
methods, and
• Improvement in utilisation by avoiding environmentally-driven downtime through development
of better cooling enclosures for engine and generator and implementation of noise and
vibration reduction systems.
realisable by 2025 onwards, as technology development will be piece-wise.
2025, covering all but the lowest cost gas CHP systems.
Practice today: Today most engines with lean-burn technology operate with an air excess ratio
(lambda) in the range 1.3 to 1.7.
Innovation: An increase in excess ratio is beneficial but is only possible with advanced
ignition technology, combustion control and combustion chamber design. This innovation
focuses on the increase of combustion air excess ratio (up to 2.2) and specific power per
cylinder through the development of pre-chamber technology and/or shape optimisation of
the combustion chamber.
Commercial readiness: 70% of the benefit of these innovations is realisable by 2020 and 100%
by 2025, due to the availability of some technologies already and the expected progress of
development in this area by the engine manufacturers.
Market share: It is anticipated that this innovation will be implemented on 80% of plant in
2025, covering all but the lowest cost gas CHP systems, as it will generally be available with no
additional capital cost.
Improvements in combustion control
Practice today: Advanced combustion control techniques are used in large engines (multi-MW
class). Smaller engines are usually controlled with conventional cylinder pressure and exhaust
gas temperature measurements.
Innovation: This innovation is aimed at meeting emissions regulations more effectively, with
better efficiency and reliability than other methods. The innovation covers three areas:
• Fuel-air mixture composition control (cylinder-by-cylinder)
• New valve designs and control of valve operation for increased volumetric efficiency, and
• Electronics and sensors for better control and increased efficiency at part load.
Commercial readiness: 20% of the benefit of these innovations is realisable by 2020, with 80%
realisable by 2025 onwards, as some of the technology already exists, but will take time to adapt
and optimise for smaller engines.
Figure 4.5 Anticipated and potential impact of combustion system innovations on LCOE for a project with
FID in 2025.
Improvements in combustion control
Impact on LCOE
0% 2% 4% 6% 8% 10% 12%
Table 4.3 Anticipated and potential impact of combustion system innovations for a project with FID in 2025.
Improvements in ignition systems -12.0% -26.8% 22.4% 1.7% -6.0% -13.4% 11.2% 1.0%
Improvements in engine mechanical design -4.0% -20.8% 20.2% 5.6% -2.8% -14.6% 14.1% 4.2%
Improvements in combustion chambers for lean mixtures 0.0% -15.6% 15.1% 5.6% 0.0% -12.5% 12.1% 4.6%
Improvements in combustion control -4.0% -7.7% 7.6% 1.4% -2.2% -4.3% 4.2% 0.8%

4.d. Innovations in the energy
conversion system
4.d.1. Overview
Innovations in the energy conversion system are anticipated to reduce the LCOE of gas CHP
plants in 2025 by nearly 4% compared with the baseline 2016 plant. All the savings result from
AEP increases.
Table 4.4 and Figure 4.6 show that the innovation with the largest anticipated impact in FID 2025
is improvements in power per cylinder from IC engines.
4.d.2. Innovations
Innovations in the energy conversion system span a range of technologies from thermodynamic
cycle improvements to hybridisation and alternatives to the IC engine. A subset of the more
important of these has been modelled here.
Innovations for introduction of combined thermodynamic cycles and for fuel-cell hybrid power
systems were considered. These would increase the LCOE from a baseline system with a single
power unit and a single thermodynamic cycle and so are not included in the overall analysis.
In addition, an innovation for use of alternatives to the conventional internal combustion engine
was considered. This would increase the LCOE from the baseline system in this time frame, and
so is not included in the overall analysis. Alternative prime movers, however, could reduce the
LCOE in applications in the longer term.
Practicetoday:GasenginesinCHPplantsusetheOttocycle,whichisnormalforspark-ignitedICengines.
Innovation: This innovation covers the implementation of modified thermodynamic cycles
such as the Miller cycle which can improve efficiency by changing the relative compression and
expansion ratios in cylinders. This may be achieved by implementation of variable valve timing
systems supported by external air compression. Activities are focused on:
• Development of engine control maps for individual fuels, with adaptive adjustment to site and
fuel conditions, and
• Variable valve timing.
realisable by 2025 onwards, because, although technology development is required, there is a
strong cost saving driver.
2025, covering most gas CHP systems based on new engine designs.
Practice today: Engines in the gas CHP sector operate with a brake mean effective pressure
(BMEP) of between 9 and 17 bar, which limits power per cylinder.
Innovation: This innovation covers increasing the power per cylinder by increasing BMEP
through developments in three main areas:
• Increased turbocharger pressure ratios and improved aftercooling
• New designs of heat exchangers, especially for intake charge cooling, and
• Multi-stage turbocharging.
This innovation is usually implemented alongside lean combustion and combustion control.
realisable by 2025 onwards, as technology development is ongoing currently.
4.e. Innovations in emissions treatment
4.e.1. Overview
Innovations in emissions treatment generally focus on primary and post-combustion reduction
methods and both approached have been considered. They would both increase the LCOE from the
baseline system in the time period up to 2025, and so are not included in the overall analysis. Increases
in the costs for emitting pollutants could, however, reduce the LCOE in applications in the longer term.
4.f. Innovations in power plant operation,
maintenance and service
4.f.1.Overview
Innovations in plant operation, maintenance and service are anticipated to reduce the LCOE of gas CHP plants
in 2025 by over 2% compared with the baseline 2016 plant. Most of the savings result from AEP increases.
Figure 4.6 Anticipated and potential impact of energy conversion system innovations on LCOE for a project
with FID in 2025.
Impact on LCOE
0% 1% 2% 3% 4% 5%
Table 4.4 Anticipated and potential impact of energy conversion system innovations for a project with FID in 2025.
Improvements in thermodynamic cycles in IC engines -4.0% -20.6% 16.0% 2.3% -1.6% -8.2% 6.4% 1.0%
Improvements in power per cylinder from IC engines -8.0% -26.8% 22.4% 3.2% -6.4% -21.4% 17.9% 2.6%

is improvements in structural materials.
4.f.2. Innovations
Innovations in gas CHP plant operations, maintenance and service span a range of technologies
from materials, to lubricants and overall design. A subset of the more important of these has
been modelled here.
Practice today: Cast iron of different grades is typically used in the main structure of an IC
engine with steel and aluminium also being used in other parts.
Innovation: This innovation covers new materials:
• For extended lifetime of hot parts (such as the pre-combustion chamber, spark plugs and gas
injectors; these materials include steel alloys and ceramics)
• For better durability and reliability (materials here include steel and aluminium alloys, plastics
and composites), and
• For lower cost engine peripheral components (materials here includes composites, elastomers
and plastics).
realisable by 2025, as technology development will continue.
2025, because improved materials are straightforward to adopt in many cases.
Introduction of remote control and optimisation
Practice today: Most gas CHP plants are controlled on-site, with remote monitoring (if present)
limited to operational parameters.
Innovation: This innovation covers three areas:
• Remote and automated diagnostic procedures for IC engines
• Improved monitoring systems to support the transition from preventive maintenance to
condition-based maintenance, and
• Development of remote control software and procedures.
realisable by 2025 onwards, as technology and service development is ongoing currently and
market demand is high.
2025, especially those plants with more than one gas CHP system on the same site.
Improvements in lubricants and additives
Practice today: Modern lubricants need changing at regular intervals and do not prevent
deposits in the engine which degrade performance.
Innovation: This innovation covers three areas, which between them reduce OPEX and
downtime and increase reliability:
• Lubricating oil on-line condition monitoring
• New lubricating oils, especially for non-natural gas fuels, and
• Development of air filtration systems.
realisable by 2025 onwards. New technology development will be needed, but the pace of
development can be relatively fast.
2025, due to the ease of implementation.
Improvements in CHP module design for maintenance
Practice today: Engines in the gas CHP sector have high maintenance requirements, which
limit availability to around 92%.
Innovation: This innovation covers better design of the CHP module to shorten service and
maintenance activities and extend availability, and includes packaging and design for better
access to engine components (especially crankshaft, camshaft and cylinder heads).
Commercial readiness:50% of the benefit of these innovations is realisable in 2020, with 100%
realisable by 2025 onwards. Technology development is already underway and market demand
is high for innovation in this area.
Market share: It is anticipated that this innovation will be implemented on 100% of plants
in 2025.
Figure 4.7 Anticipated and potential impact of power plant operation, maintenance and service innovations on
LCOE for a project with FID in 2025.
Introduction of remote control and optimisation
Improvements in lubricants and additives
Improvements in CHP module design for maintenance
Impact on LCOE
0% 1% 2% 3% 4%
Table 4.5 Anticipated and potential impact of plant operation, maintenance and service innovations for a
project with FID in 2025.
Improvements in structural materials -8.0% -10.7% 11.4% 1.7% -4.5% -6.0% 6.4% 1.0%
Introduction of remote control and optimisation -1.6% 3.8% 0.0% 1.4% -0.8% 1.9% 0.0% 0.7%
Improvements in lubricants and additives 0.0% 0.1% 0.0% 0.0% 0.0% 0.1% 0.0% 0.0%
Improvements in CHP module design for maintenance 0.0% 1.2% 0.0% 0.7% 0.0% 1.2% 0.0% 0.7%

4.g. Summary of innovations and results
4.g.1. Combined impact of innovations
Innovations across all elements of the gas CHP plant are anticipated to reduce LCOE by about
17% between projects with FID in 2016 and 2025. Figure 4.8 shows that although the CAPEX and
OPEX increase, there is a larger increase in AEP which is why the LCOE is reduced.
It is important to note that the impact shown in Figure 4.8 is an aggregate (as described in
Section 3.3.3) of the impacts shown in Figure 4.4 to Figure 4.7 and as such exclude any Other
Effects such as WACC and emission costs. These are discussed in Section 4.g.3.
4.g.2. Relative impact of cost of each power plant element
In order to explore the relative cost of each gas CHP plant element, Figure 4.9 shows the cost of all
CAPEX elements and Figure 4.10 shows the same for OPEX elements and the net capacity factor.
These figures show the relative static development and fuel handling CAPEX. The increase in the
energy conversion system CAPEX is a result of investing to deliver higher efficiencies. The CAPEX
increases are exploited to deliver higher AEP. The fuel usage OPEX increases, but not as much
as AEP, and operations, maintenance and service (OMS) OPEX increases only by a small amount.
4.g.3. Levelised cost of energy including impact of Other Effects
In order to compare real LCOE at each FID date, Figure 4.11 also incorporates the Other Effects
discussed in Section 3.3.4. It shows that, despite the effect of emission costs, the LCOE for the
electrical power from the gas CHP plant reduces as the innovations identified have increasing
impact over time.
The contribution of innovations to this LCOE reduction is presented in Figure 4.12. It shows that
well over two-thirds of the LCOE savings anticipated in the gas CHP plant arise from innovations
in engine design, fuels and combustion (the first four innovations in the figure), but innovations
in many other areas are also important.
Figure 4.8 Anticipated impact of all innovations for FID in 2025 compared with FID in 2016.
100
75
50
25
0
-25
Figure 4.9 CAPEX for gas CHP plants with FID in 2016, 2020 and 2025.
2,000
1,500
1,000
500
0
CHP-16 CHP-20 CHP-25€k/MW
Figure 4.10 OPEX and net capacity factor for gas CHP plants with FID in 2016 (baseline), 2020 and 2025.
600 90
400
200
85
0 80
CHP-16 CHP-20 CHP-25
OPEX(€k/MW/yr)
Figure 4.11 LCOE of gas CHP plants with FID in 2016, 2020 and 2025 with Other
Effects incorporated.
100 100
80 80
60 60
40 40
20 20
0 0
•LCOEincludingOtherEffects •Netcapacityfactor
CHP-16 CHP-20 CHP-25
LCOE(€/MWh)

Future Energy Costs: Coal and Gas Technologies 42 43
5. Coal power plant
5.a. Baseline
The modelling process described in Section 3 is to:
• Define a set of baseline power plants and derive costs, and energy-related parameters for each
• For each of a range of innovations, derive the anticipated impact on these same parameters for
each baseline power plant, for a given year, and
• Combine the impact of a range of innovations to derive costs, and energy-related parameters
for each of the baseline power plants for each year.
This Section summarises the costs and other parameters for the baseline coal power plants. The
baselines were developed by the KIC subject matter experts in coal power systems, and relate
to subcritical conventional power plants suitable for retrofitting of technology to improve cost
of energy.
The baseline costs presented in Table 5.1 and Figure 5.1 and Figure 5.2 are nominal contract
values (or current asset values in the case of CAPEX), rather than outturn values, and are for
projects with FID in 2016, 2020 and 2025. As such, they incorporate real-life supply chain effects
such as the impact of competition. All results presented in this report incorporate the impact of
technology innovations only, except for when LCOEs are presented in Figure 5.3 and in Section
5.g.3, which also incorporate the Other Effects discussed in Section 3.3.4.
Figure 4.12 Anticipated impact of technology innovations for a gas CHP plant with FID in 2025, compared
with a baseline gas CHP plant with FID in 2016.
5 other innovations

The baseline is assumed to be a unit of a thermal power plant fired with pulverised hard coal
dust, producing 650t/hour fresh steam output at 130 bar and 540 °C, equipped with selective
catalytic reduction treatment for oxides of nitrogen and wet flue-gas desulphurisation. The
electrical rating is 225MW, which is typical for a small single unit of a power plant in Europe. The
plant is also assumed to be capable of burning other fuels with appropriate investment.
The timing profiles of CAPEX and OPEX are presented in Appendix A.
These baseline parameters are used to derive the LCOE for the three baseline plants. A
comparison of the relative LCOE for each of the baseline power plants is presented in Figure 5.3.
The LCOE increases with time for the baseline plants because of the anticipated reduction in AEP
through reduced demand; increased emissions costs through regulation; increased OMS costs
as the plant ages; and reduction in remaining useful life of the plant.
5.b. Innovations in fuel handling
5.b.1. Overview
Innovations in fuel handling are anticipated to reduce the LCOE of coal plants in 2025 by just
over 15% compared with the baseline 2025 plant. The majority of the savings result from OPEX
reductions (especially from the thermal pre-treatment of biomass and waste-based fuels).
Table 5.1 Baseline parameters for 225MW unit of coal power plants from 2016 to 2025.
Type Parameter Units 2016 FID 2020 FID 2025 FID
CAPEX Development €k/MW 62 60 54
Fuel handling 16 14 12
Energy conversion system 164 141 152
Emissions treatment 81 62 64
OPEX Operations, planned and unplanned maintenance €k/MW/yr 16 17 21
Fuel usage cost 156 128 94
Emissions cost (Polish market) 19 95 104
AEP Gross AEP MWh/yr/MW 6,000 5,000 4,000
Losses % 8.0 8.0 8.0
Net AEP MWh/yr/MW 5,520 4,600 3,680
Net capacity factor % 63.0 52.5 42.0
Figure 5.1 Baseline CAPEX by element.
€k/MW
175
150
125
75
50
25
0
Coal-16 Coal-20 Coal-25
Figure 5.2 Baseline OPEX and net capacity factor.
200 80
150 60
100 40
50 20
0 0
Coal-16 Coal-20 Coal-25
OPEX(€k/MW/yr)
Figure 5.3 LCOE for baseline power plants with Other Effects incorporated.
100
80
60
40
20
0
LCOE (€/MWh)• Coal-16 Coal-20 Coal-25

is introduction of thermal pre-treatment of biomass and waste-based fuels, which improves the
quality of the fuel and allows plants to use greater quantities of biomass and waste-based fuels
in place of higher cost fuels.
5.b.2. Innovations
Innovations in fuel handling include physical and thermal treatment of the fuel, blending and
the use of additives. A subset of the more important of these has been modelled here.
In addition, innovations for improvements in the physical pre-treatment of fuels were considered.
These would increase the LCOE from the baseline system in this time frame, and so are not
included in the overall analysis.
Practice today: Fuel additives are used, but are limited to basic minerals such as kaolinite that
are targeted at reducing slagging and fouling. Fuel blending is practised, but limited to fuels that
are not classified as waste.
• Theuseofadvancedmineralorartificialadditiveswhichreduceashdepositionandinfluenceemissions
such as oxides of nitrogen and mercury, while also reducing high-temperature corrosion, and
• Blending of low quality fuels (including those classified as wastes) with primary fuels up to full
replacement.
realisable by 2020 onwards.
Market share: It is anticipated that this innovation will be implemented on only 40% of plants
in 2025, because of limitations in applicability due to variations in local policy and regulations.
Introduction of thermal pre-treatment of biomass and waste-based5
fuels
Practice today: In the limited proportion of applications using biomass and waste-based fuels,
these are are used without torrefaction or gasification.
• Thermal pre-treatment in the form of torrefaction which upgrades the properties of biomass
and biomass-derived waste fuels. This increases energy density, reduces fuel preparation costs
(grinding), reduces transportation costs and increases the amounts that can be used (which
also reduces emissions cost), but increases processing costs; and
• Gasification, which reduces pollutant emissions when using some solid fuels containing
harmful elements such as trace heavy elements and corrosion-inducers (potassium and
chlorine). Some of these harmful elements are retained in the gasifier rather than passing
through to the power plant, so that emissions costs are reduced and the gas produced is
easier to use than the solid fuel.
realisable by 2020 and 100% by 2025.
2025, because of limitations in applicability due to variations in local policy and regulations.
5.c. Innovations in the combustion system
5.c.1. Overview
Innovations in the combustion system are anticipated to reduce the LCOE of coal plants in 2025
by just over 10% compared with the baseline 2025 plant. The majority of the savings result from
OPEX reductions from hybrid fuel consumption and AEP increases (especially from power plant
start-up and boiler flexibility).
Table 5.3 and Figure 5.5 show that the innovation with the largest anticipated impact in FID 2025 is
improvements in hybrid fuel combustion, which reduced OPEX by enabling use of lower cost fuel.
5 Note that municipal solid waste and refuse-derived fuel are excluded from consideration here, due to the stringent emissions
regulations around incinerator plants that would then apply.
Figure 5.4 Anticipated and potential impact of fuel handling innovations for FID in 2025.
Introduction of thermal pre-treatment of biomass and waste-based fuels
Impact on LCOE
0% 10% 20% 6% 30% 40%
Table 5.2 Anticipated and potential impact of fuel handling innovations for FID in 2025.
Improvements in fuels through modification and switching -2.6% 17.8% 0.0% 14.3% -1.0% 7.1% 0.0% 5.7%
Introductionofthermalpre-treatmentofbiomassandwaste-basedfuels -2.1% 33.6% 5.2% 31.0% -0.6% 10.1% 1.6% 9.6%
Figure 5.5 Anticipated and potential impact of combustion system innovations for FID in 2025.
Improvements in power plant start-up systems
Improvements in boiler flexibility
Introduction of hybrid fuel combustion
Introduction of boiler waste-heat recovery systems
Impact on LCOE
0% 5% 10% 15% 20% 25%
©MichałMajor-EDF

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