EN    EN EN 
 
EN    EN  COMMISSION OF THE E UROPEAN COMMUNITIES 
Brussels, 13.11.2008 
SEC(2008) 2872 
COMMISSION STAFF WORKING DOCUMENT 
 
accompanying the 
COMMUNICATION FROM THE CO MMISSION TO THE EUROPEAN 
PARLIAMENT, THE COUNCIL, THE EUROPEAN ECONOMIC AND SOCIAL 
COMMITTEE AND THE COMMI TTEE OF THE REGIONS 
 
Second Strategic Energy Review 
 
AN EU ENERGY SECURITY AN D SOLIDARITY ACTION PLAN 
  
Energy Sources, Production Costs and Performance of Technologies  
for Power Generation, Heating and Transport  
{COM(2008) 781 final} 
{SEC(2008) 2870} {SEC(2008) 2871} 
 
EN 3   EN TABLE OF CONTENTS 
1. Introduction................................................................................................................ .. 3 
2. Part I: Main Tables....................................................................................................... 3 3. Part II: Methodology and Data..................................................................................... 9 3.1. Energy Technologies for Power Generation................................................................ 9 3.2. Energy Sources for Heating ....................................................................................... 17 3.3. Energy Sources for Transport Fuels........................................................................... 21 4. References.................................................................................................................. 22 
1. I
NTRODUCTION  
Europe needs to act now to deliver sustainable, secure and competitive energy. The inter-
related challenges of climate change, secur ity of energy supply and competitiveness are 
multifaceted and require a profound change in the way Europe produces, delivers and consumes energy. Harnessing technology is vital to achieve the Energy Policy for Europe objectives adopted by the Eur opean Council on 9 March 2007
1.  
This document provides a comparative analys is of energy sources, production costs and 
performance of technologies for power generatio n, heating and transport for use in the Second 
Strategic EU Energy Review (SEER). It builds upon the work performed for the first Strategic 
EU Energy Review COM(2007)1, and relies on the capacity of SETIS, the information 
system of the European Strategic Energy Technology Plan (SET-Plan ). The comparative 
Tables presented in the prev ious SEER exercise have b een updated. The portfolio of 
technologies considered for the power sector  has been also expanded to include carbon 
capture power plants, a large scale oil fired pl ant and an additional bi omass conversion route. 
In addition, two fuel price scenar ios have been considered to re flect variations in the future 
price of energy commodities. All reported values  in the Tables for electricity generation, 
heating and transport fuels have been calcu lated following a consis tent methodology, hence 
they are directly comparable. The calculati ons rely on up-to-date available data and 
information on energy convers ion technology performance. 
This report consists of two parts. Part I includes the three Tables for use in the 2nd SEER. Part 
II provides a comprehensive description of the implemented methodology and includes the 
technology-related data used for the calc ulations, accompanied by a reference list.  
2. PART I: MAIN TABLES  
                                                 
1 European Council conclusions adopted on the basi s of the Commission's Ener gy Package, e.g. the 
Communications: ' An Energy Policy for Europe ' COM(2007)1, ' Limiting Global Climate Change to 2 
degrees Celsius - The way ahead for 2020 and beyond ' COM(2007)2 and ' A European strategic energy 
technology plan (SET-plan) - Towards a low carbon future ' COM(2007)723 
 
EN 4   EN Table 2-1: Energy Technologies for Power Generation – Moderate Fuel Price Scenario (a) 
Production Cost of Electricity (COE) Lifecycle GHG emissions 
State-of-the-
art 2007 Projection for 
2020 Projection for 
2030 Direct (stack) 
emissions Indirect 
emissions Lifecycle 
emissions Energy 
source Power generation technology 
€2005/MWh €2005/MWh €2005/MWh Net efficiency 
2007 
kg CO 2/MWh kg CO 2(eq)/MWh kg CO 2(eq)/MWhFuel price 
sensitivity 
Open Cycle Gas Turbine (GT) - 65 ÷ 75  (b) 90 ÷ 95  (b) 90 ÷ 100  (b) 38% 530 110 640 Very high 
- 50 ÷ 60 65 ÷ 75 70 ÷ 80 58% 350 70 420 Very high Natural gas Combined Cycle Gas Turbine 
(CCGT) CCS n/a 85 ÷ 95 80 ÷ 90 49% (c) 60 85 145 Very high 
Internal Combustion Diesel 
Engine - 100 ÷ 125  (b) 140 ÷ 165  (b) 140 ÷ 160  (b) 45% 595 95 690 Very high 
Oil Combined Cycle Oil-fired 
Turbine (CC)  - 95 ÷ 105  (b) 125 ÷ 135  (b) 125 ÷ 135  (b) 53% 505 80 585 Very high 
- 40 ÷ 50 65 ÷ 80 65 ÷ 80 47% 725 95 820 Medium Pulverised Coal Combustion (PCC) 
CCS n/a 80 ÷ 105 75 ÷ 100 35% (c) 145 125 270 Medium 
Circulating Fluidised Bed Combustion (CFBC) - 45 ÷ 55 75 ÷ 85 75 ÷ 85 40% 850 110 960 Medium 
- 45 ÷ 55 70 ÷ 80 70 ÷ 80 45% 755 100 855 Medium Coal 
Integrated Gasification 
Combined Cycle (IGCC)  CCS n/a 75 ÷ 90 65 ÷ 85 35% (c) 145 125 270 Medium 
Nuclear Nuclear fission - 50 ÷ 85 45 ÷ 80 45 ÷ 80 35% 0 15 15 Low 
Solid biomass - 80 ÷ 195 85 ÷ 200 85 ÷ 205 24% ÷ 29% 6 15 ÷ 36 21 ÷ 42 Medium Biomass Biogas - 55 ÷ 215 50 ÷ 200 50 ÷ 190 31% ÷ 34% 5 1 ÷ 240 6 ÷ 245 Medium 
On-shore farm - 75 ÷ 110 55 ÷ 90 50 ÷ 85 - 0 11 11 Wind Off-shore farm - 85 ÷ 140 65 ÷ 115 50 ÷ 95 - 0 14 14 nil 
Large - 35 ÷ 145 30 ÷ 140 30 ÷ 130 - 0 6 6 Hydro Small - 60 ÷ 185 55 ÷ 160 50 ÷ 145 - 0 6 6 nil 
Photovoltaic - 520 ÷ 880 270 ÷ 460 170 ÷ 300 - 0 45 45 nil Solar Concentrating Solar Power (CSP)  - 170 ÷ 250  (d) 110 ÷ 160  (d) 100 ÷ 140  (d) - 120 (d) 15 135 (d) Low 
(a) Assuming fuel prices as in 'Europe an Energy and Transport: Trends to 2030 - Update 2007' (barrel of oil 54.5$ 2005 in 2007, 61$ 2005 in 2020 and 63$ 2005 in 2030) 
(b) Calculated assuming base load operation 
(c) Reported efficiencies for carbon capture plants refer to first-of-a-kind demonstrati on installations that start operating in 2 015 
(d) Assuming the use of natural gas for backup heat production
 
EN 5   EN Table 2-2: Energy Technologies for Powe r Generation – High Fuel Price Scenario (a) 
Production Cost of Electricity (COE) Lifecycle GHG emissions 
State-of-the-
art 2007 Projection for 
2020 Projection for 
2030 Direct (stack) 
emissions Indirect 
emissions Lifecycle 
emissions Energy 
source Power generation technology 
€2005/MWh €2005/MWh €2005/MWh Net efficiency 
2007 
kg CO 2/MWh kg CO 2(eq)/MWh kg CO 2(eq)/MWhFuel price 
sensitivity 
Open Cycle Gas Turbine (GT) - 80 ÷ 90  (b) 145 ÷ 155  (b) 160 ÷ 165  (b) 38% 530 110 640 Very high 
- 60 ÷ 70 105 ÷ 115 115 ÷ 125 58% 350 70 420 Very high Natural gas Combined Cycle Gas Turbine 
(CCGT) CCS n/a 130 ÷ 140 140 ÷ 150 49% (c) 60 85 145 Very high 
Internal Combustion Diesel 
Engine - 125 ÷ 145  (b) 200 ÷ 220  (b) 230 ÷ 250  (b) 45% 595 95 690 Very high 
Oil Combined Cycle Oil-fired 
Turbine (CC)  - 115 ÷ 125  (b) 175 ÷ 185  (b) 200 ÷ 205  (b) 53% 505 80 585 Very high 
- 40 ÷ 55 80 ÷ 95 85 ÷ 100 47% 725 95 820 High Pulverised Coal Combustion (PCC) 
CCS n/a 100 ÷ 125 100 ÷ 120 35% (c) 145 125 270 Medium 
Circulating Fluidised Bed Combustion (CFBC) - 50 ÷ 60 95 ÷ 105 95 ÷ 105 40% 850 110 960 High 
- 50 ÷ 60 85 ÷ 95 85 ÷ 95 45% 755 100 855 High Coal 
Integrated Gasification 
Combined Cycle (IGCC)  CCS n/a 95 ÷ 110 90 ÷ 105 35% (c) 145 125 270 Medium 
Nuclear Nuclear fission - 55 ÷ 90 55 ÷ 90 55 ÷ 85 35% 0 15 15 Low 
Solid biomass - 80 ÷ 195 90 ÷ 215 95 ÷ 220 24% ÷ 29% 6 15 ÷ 36 21 ÷ 42 Medium Biomass Biogas - 55 ÷ 215 50 ÷ 200 50 ÷ 190 31% ÷ 34% 5 1 ÷ 240 6 ÷ 245 Medium 
On-shore farm - 75 ÷ 110 55 ÷ 90 50 ÷ 85 - 0 11 11 Wind Off-shore farm - 85 ÷ 140 65 ÷ 115 50 ÷ 95 - 0 14 14 nil 
Large - 35 ÷ 145 30 ÷ 140 30 ÷ 130 - 0 6 6 Hydro Small - 60 ÷ 185 55 ÷ 160 50 ÷ 145 - 0 6 6 nil 
Photovoltaic - 520 ÷ 880 270 ÷ 460 170 ÷ 300 - 0 45 45 nil Solar Concentrating Solar Power (CSP)  - 170 ÷ 250  (d) 130 ÷ 180  (d) 120 ÷ 160  (d) - 120 (d) 15 135 (d) Low 
(a) Assuming fuel prices as in DG TREN 'Scenario s on high oil and gas prices' (barrel of oil 54.5$ 2005 in 2007, 100$ 2005 in 2020 and 119$ 2005 in 2030) 
(b) Calculated assuming base load operation  
(c) Reported efficiencies for carbon capture plants refer to first-of-a-kind demonstrati on installations that start operating in 2 015 
(d) Assuming the use of natural gas for backup heat production
 
EN 6   EN Table 2-3: Energy Sources for Heating – Moderate Fuel Price Scenario (a) 
Production Cost of Heat (inc. taxes) Lifecycle GHG emissions 
Fuel retail price 
(inc. taxes) 
Running cost Total cost Direct (stack) 
emissions Indirect 
emissions Lifecycle 
emissions Energy source EU-27 market share by 
energy source 
(residential sector) (b) 
€2005/toe €2005/toe €2005/toe t CO 2 /toe t CO 2(eq)/toe t CO 2(eq)/toe 
Natural gas 45.4% 625 750 ÷ 950 1050 ÷ 1300 2.5 0.7 3.2 
Heating oil 20.0% 640 800 ÷ 1100 1325 ÷ 2025 3.5 0.6 4.1 Fossil fuels 
Coal 3.1% 375 675 ÷ 750 1500 ÷ 1825 5.4 0.7 6.1 
Wood chips 390 700 ÷ 900 1550 ÷ 2650 0.0 0.3 0.3 
Pellets 580 900 ÷ 1300 1675 ÷ 4125 0.0 0.7 0.7 
Solar - 275 ÷ 300 1350 ÷ 9125 0.0 0.3 0.3 Biomass, solar 
and other 
Geothermal 11.6% 
- 525 ÷ 900 1025 ÷ 3625 0.0 0.2 ÷ 5.9 0.2 ÷ 5.9 
Electricity 12.3% 1470 1500 ÷ 1575 1600 ÷ 2475 0.0 0.7 ÷ 15.2 0.7 ÷ 15.2 
(a) Assuming fuel prices as in 'Europe an Energy and Transport: Trends to 2030 - Update 2007' (barrel of oil 54.5$ 2005) 
(b) District heating has an additional share of 7.6% of the market 
 
EN 7   EN Table 2-4: Energy Sources for Heating – High Fuel Price Scenario (a) 
Production Cost of Heat (inc. taxes) Lifecycle GHG emissions 
Fuel retail price 
(inc. taxes) 
Running cost Total cost Direct (stack) 
emissions Indirect 
emissions Lifecycle 
emissions Energy source EU-27 market share by 
energy source 
(residential sector) (b) 
€2005/toe €2005/toe €2005/toe t CO 2 /toe t CO 2(eq)/toe t CO 2(eq)/toe 
Natural gas 45.4% 1010 1125 ÷ 1400 1425 ÷ 1750 2.5 0.7 3.2 
Heating oil 20.0% 1030 1200 ÷ 1600 1775 ÷ 2525 3.5 0.6 4.1 Fossil fuels 
Coal 3.1% 590 975 ÷ 1025 1775 ÷ 2100 5.4 0.7 6.1 
Wood chips 410 725 ÷ 925 1575 ÷ 2675 0.0 0.3 0.3 
Pellets 610 925 ÷ 1350 1700 ÷ 4175 0.0 0.7 0.7 
Solar - 275 ÷ 300 1350 ÷ 9125 0.0 0.3 0.3 Biomass, solar 
and other 
Geothermal 11.6% 
- 650 ÷ 1100 1150 ÷ 3775 0.0 0.2 ÷ 5.9 0.2 ÷ 5.9 
Electricity 12.3% 1875 1925 ÷ 1975 2025 ÷ 2900 0.0 0.7 ÷ 15.2 0.7 ÷ 15.2 
(a) Assuming high fuel prices as in DG TREN 'Scenar ios on high oil and gas prices' (barrel of oil 100$ 2005) 
(b) District heating has an additional share of 7.6% of the market 
 
EN 8   EN Table 2-5: Energy Sources for Road Transport – Moderate and High Fu el Price Scenario 
Cost of Fuels to the EU 
Moderate Fuel Price Scenario (a) High Fuel Price Scenario (b) Lifecycle GHG emissions (c) 
Energy source for road transport 
€2005/toe €2005/toe t CO 2(eq)/toe 
Petrol and diesel 470 675 3.6 ÷ 3.7 
Natural gas (CNG) (d) 500 630 3.0 
Domestic biofuel (e) 725 ÷ 910 805 ÷ 935 1.9 ÷ 2.4 
Tropical bio-ethanol 700 (f) 790 (f) 0.4 
Second-generation biofuel (e) 1095 ÷ 1245 1100 ÷ 1300 0.3 ÷ 0.9  
(a) Values are given for 2015, assuming oil price of 57.9$ 2005/barrel as in 'European Energy and Trans port: Trends to 2030 - Update 2007'  
(b) Values are given for 2015, assuming oil price of 83.3$ 2005/barrel as in DG TREN 'Scenarios on high oil and gas prices' 
(c) Data subject to revision pending on an agreement on an appropr iate methodology for calcula ting indirect land use change 
(d) Requires a specially adapted vehicle, which is  not accounted for in the reported values 
(e)  Ranges is between cheapest wheat-ethanol and biodiesel 
(f) Values are based on an assumed competitive ma rket price of biofuels  imported in the EU 
 
EN 9   EN 3. PART II: METHODOLOGY AND DATA 
3.1. Energy Technologies for Power Generation 
This section describes the methodology and data  used for the comparison Table of energy 
technologies for power generation. Table 3-1, Ta ble 3-2 and Table 3-3 summarise the techno-
economic characteristics of the selected stat e-of-the-art power generation technologies.  
3.1.1.  Technologies 
The technologies addressed are: 
1. Natural gas fuelled 
– Open cycle gas turbine  
– Combined cycle gas turbine 
– Combined cycle gas turbine with carbon capture and storage (CCS) 
2. Oil fuelled 
– Diesel internal combustion engine 
– Oil fired combined cycle 
3. Coal fuelled 
– Pulverised fuel 
– Pulverised fuel with carbon capture and storage 
– Circulating fluidised bed  
– Integrated gasification combined cycle 
– Integrated gasification combined cy cle with carbon capture and storage 
4. Nuclear fission 
– Water cooled reactor 
5. Biomass fuelled 
– Biomass fired combustion steam cycle: large (>10MW e) and small scale 
(≤10MW e) 
– Biogas from co-digestion and landfill gas 
6. Wind 
– On-shore wind 
– Off-shore wind 
7. Hydropower 
– Large scale (>10MW e) 
– Small scale ( ≤10MW e) 
8. Solar power 
– Photovoltaics 
– Concentrating solar thermal power 
 
EN 10   EN It is noted that cogeneration of heat and power is not c onsidered in this analysis. 
3.1.2.  Indicators 
For each technology the followi ng indicators are reported: 
(I) Production cost of electricity (current and projected to 2020 and 2030):  The levelized 
production cost of electricity, e xpressed in constant €(2005)/MWh of net power generated, is 
used to compare the economi c competitiveness among power generation technologies during 
their life time. The reported valu es for the production cost of electricity for each technology 
refer to a state-of-the-art fac ility, assumed to start operating in  the indicated year (2007, 2020 
or 2030), as described in  Table 3-1. The reported range re flects variations in capital costs 
which depend on specific technology choices, plan t location, etc. The re ported range does not, 
however, reflect the variability  in the fuel retail prices between the Member States2.  
The reported production cost values have b een calculated using the following formula: 
()CTS CC FC VOMLFFOM
LFCRF IDC SCICOE ++++⋅+⋅⋅+⋅=8760 87601 
 
Where: 
COE  …is the levelized production co st of electricity, in € 2005/MWh, 
SCI …is the specific overnight capital investment of the power generation facility, 
in € 2005/MW, 
IDC …is the interest dur ing construction, 
CRF  …is the capital recovery factor, 
LF …is the annual load factor of the facility, 
FOM  …refers to the annualized fixed operating costs during the faci lity life time, in 
€2005/MW, 
VOM  …refers to the annualized variable operating costs during the facility life time, 
in € 2005/MWh, 
FC …refers to annualized fuel costs dur ing the facility life time, in € 2005/MWh, 
CC …refers to annualized carbon costs du ring the facility life time, in € 2005/MWh  
CTS …refers to annualized e xpenditures for transport a nd storage of captured CO 2 
during the facility life time, in € 2005/MWh (only applicable to plants with CCS). 
All values are reported in net power capacity (MW) or generated electricity (MWh).  
In more detail, values for SCI were collected from the most recent available literature. The 
reported ranges reflect market variations in i nvestment costs for a give n technology within the 
EU and within a same power class. Values reported in the literature in currency other than euros were converted to euros based on the Eurost at exchange rates for the reference year of 
the data given in the publication and were converted to 2005 euros (€
2005) using the annual 
average inflation rates for the Eu ro area as reported by Eurostat. Finally, to include the recent 
price increases these values were adjusted to January 2007 using the chemical engineering 
                                                 
2 An average European fuel price has been considered as discussed below. 
 
EN 11   EN plant cost index3. The SCI values are shown in Table 3-2. Values for future SCIs were 
calculated on the assumption that current prices will decrease due to learning effects. Hence, based on the technology learning theory, the future specific cost of a technology, SCI
F, was 
calculated using the global installed cap acity as a proxy, based on the formula: 
()
2ln1ln LR
PF
P FCCSCI SCI−
⎟⎟
⎠⎞
⎜⎜
⎝⎛=  
 
Where: 
SCI P …is the current specific capital investment cost, 
CP …is the current global installed capacity, 
CF …is the installed capacit y of the technology in a future time, e.g. in 2020, 
LR …is the learning rate  of the technology. 
Values for CP, CF and LR were collected from the literature  and are also shown in Table 3-3. 
Especially, for fossil fuel power plants with CCS, it was assumed that the first-of-the-kind 
installations will start operating in 2015. Furtherm ore, the global installed capacity of each 
technology is kept constant for the two fossil fuel price scenarios. 
The IDC was calculated considering the constructi on time for each plant (see Table 3-3) and a 
capital expenditure prof ile during construction: 
()()1 11
1− + =−−
=∑k CT CT
kk r W IDC  
 
Where: 
CT …is the construction time, 
Wk …is the fraction of total capital used in year k, 
r …is the interest rate. 
For all technologies an interest rate of 10% was assumed for the calculation of IDC. 
The capital recovery factor ( CRF ) was calculated from the formula: 
()
() 1 11
−++⋅=nn
dd dCRF  
 
Where d is the real discount rate and n is the facility life time.  
For all technologies a real disc ount rate of 10% was assumed. Moreover, it was assumed that 
the economic life time of facility is equal to the technical life time (see Table 3-3). 
It was further assumed that all facilitie s operate in a base-load mode with a LF of 85%, 
including open cycle gas turbines and diesel reci procating engines that are used also to meet 
peak load. The following exceptions were made: 
– Photovoltaics: 11% 
                                                 
3 For more information see: Updating the CE Plant Cost Index, Chemical Engineering, January 2002, p. 
62. 
 
EN 12   EN – Concentrating solar thermal power: 41%4 
– Wind: on-shore 23% and off-shore 39% 
– Landfill: 75%  
– Hydropower: Large scale 50% and Small scale 57%  
FOM  costs account for maintenance, which was calculated as a fr action of the total 
investment costs (calculated us ing the net capacity and SCI valu es from Table 3-1 and Table 
3-2 respectively) based on standard sectoral  costing methodologies; salaries (assuming an 
annual average salary of €55,000 and estimati ng the number of people employed in each 
facility); and overheads (30% of  salaries). The evolution of FOM  costs during the life time of 
a facility (due to learning effects, etc.) was considered through an annualizing process, where 
the annual FOM  values were discounted to the net present value and then multiplied by the 
CRF . VOM  costs account for the cost of consumables, chemicals, auxiliary power, etc. Values 
were obtained from the literature. Table 3-2 sh ows the total operational and maintenance costs 
(OM)5 normalised to the in stalled net capacity. 
Fuel costs  (FC) were calculated for two scenarios, mode rate and high. The fuel prices for the 
moderate scenario are derived from the DG TREN publication 'European Energy and 
Transport: Trends to 2030 - Update 2007'6, while fuel prices for th e high scenario are based 
on DG TREN 'Scenarios on hi gh oil and gas prices'7. Moreover, prices for biomass were 
calculated based on values reported in EUBIONET II8 and adjusted to reflect the biomass 
price trends considered in the previously mentioned DG TREN s cenarios. These values reflect 
the fuel price at the plant ga te. Table 3-2 shows the fuel prices assumed for the years 2007, 
2020 and 2030. The evolution of FC during the life time of a fac ility, due to changes in fuel 
prices, was also considered th rough an annualizing process, as described above for FOM. In 
the case of nuclear energy, the fuel price encompasses the whole fuel cycle including 
provisions for waste management. For concentra ting solar thermal power, FC were calculated 
assuming a constant consumption of natural gas of 385 TJ per year for backup heat production. 
Carbon costs ( CC) were considered only for the project ed costs of elect ricity in 2020 and 
2030. It was assumed that each tonne of CO
2 directly emitted from the facility was charged 
with €41/tCO 2 and €47/tCO 2 in 2020 and 2030 respectively. CC were also annualized 
similarly to FOM. The annual CO 2 emissions during plant opera tion were derived from the 
IPCC Guidelines for Nationa l Greenhouse Gas Inventories9, as explained below. It was 
assumed that concentrating solar ther mal power does not carry carbon costs. 
In the case of power plants with ca rbon capture technolo gy, the cost of CO 2 transport and 
storage costs was also taken into account fo r the calculation of the production cost of 
electricity and was treated as an additional ope rational cost element. A value of €20 per tonne 
of CO 2 captured was assumed to account for the co st of transport and storage of captured 
CO 2. 
Dismantling costs were not considered except in the case of nuclear plants, where the cost of 
decommissioning was included both in SCI and FOM.  
                                                 
4 Including thermal storage and natural gas backup. Load factor is assumed constant over time. 
5 This accounts for FOM and VOM, an d excludes fuel and carbon costs 
6 See reference [80] 
7 To be published 
8 See reference [56] 
9 See reference [127] 
 
EN 13   EN (II) Net efficiency:  The reported values refer to the curr ent state-of-the-art  power generating 
facility with the exception of the CCS plants. Fo r the latter, the reported values refer to first-
of-a-kind demonstration installati ons, assumed to start operati ng in 2015 (for references see 
Table 3-1). These net efficiency values were used for calculating fuel and carbon costs, and 
hence the production cost of electricity. The ne t efficiency values used for calculating the 
projected cost of elec tricity in 2030 are also shown in Table 3-1. 
(III) Life-cycle greenhouse gas emissions:  Values for the life-cycle greenhouse gas (GHG) 
emissions for current state-of-t he-art facilities were obtained from the pertinent literature 
and/or calculated by the JRC based on in-house life cycle assessment data.  
The lifecycle GHG emissions for fossil fuel te chnologies comprise the direct (stack) 
emissions from the combustion/gasification pro cess and the indirect emissions originating 
among others from the fuel supply chain and plant construction. Direct emissions were 
calculated according to IPCC Guidelines. In th e case of carbon capture, the direct emissions 
are the difference between the produced and captured CO 2 amounts. Conservative capture 
rates have been assumed (85% for all CCS technologies), which is the minimum capture 
efficiency proposed by the IPCC Guidelines. The i ndirect emissions of pl ants were based on 
an average value provided by the Ecoinvent Life Cycle Inventory10 for the supply of each type 
of fuel in Europe. Indirect emissions from ot her stages of the life cycle (e.g. construction) 
were obtained based on available data for relevant facilities. Finally, the calculated lifecycle emissions were harmonized with the life cycl e GHG emission values of similar technologies 
available in the Ecoinvent databa se and other relevant literature
11. 
For the non-fossil fuel technol ogies, lifecycle GHG emissions we re obtained directly from 
available references listed in Table 3-3.  
It is noted that the pa thways for the supply of fuel and raw materials, a nd the location of 
power generation facilities have  a significant influence on lifecycle emissions. Table 3-3 
shows the range of values calculated by the JRC or reported in the literature with the 
corresponding references. 
(IV) Fuel price sensitivity:  This refers to the sensitivity of the production cost of electricity 
to changes in fuel prices, which can be estimat ed by the fraction of fuel costs to the total 
production cost of electricity. In the context of this analysis, th e following scale was assumed: 
Sensitivity Fraction of fuel cost to COE - ∆(FC)  
Very high ∆(FC) > 60% 
High 60% ≥ ∆(FC) > 40% 
Medium 40% ≥ ∆(FC) > 20% 
Low ∆(FC) ≤ 20% 
                                                 
10 See reference [95] 
11 See reference [103] and [104] 
 
EN 14   EN Table 3-1: Technology descripti on, installation size, and current and future conversion efficiency 
Net efficiency Net capacity 2007 (2015 for CCS) 2030 Technology Description 
[MW] References [%] References [%] References 
Open Cycle Gas Turbine (GT) Industrial gas turbine 250 [1] 38% [1] 45% [89] 
Combined Cycle Gas Turbine (CCGT) Plant with state-of-art heavy duty industrial turbines, optimised heat 
recovery steam generato r and anti-NOx equipment 650 [1],[5],[24],[91] 58% [1] 65% [89] 
Combined Cycle Gas Turbine with CCS As above, equipped with post-combustion capture base d on MEA scrubbing 550 [7],[5],[97-98] 49% [5] 55% JRC 
Internal Combustion Diesel Engine Heavy duty recipr ocating engine 50 [24] 45% [99] 48% JRC 
Combined Cycle Oil-fired Turbine Plant with state-of-the-art oil-fired industrial turbines  175 [100] 53% JRC 59% JRC 
Pulverised Coal Combustion (PCC) Supercritical power plant, steam at 600 ºC, FGD and SCR 800 [1],[5],[24],[91] 47% [91],[101] 54% JRC 
Pulverised Coal Combustion with CCS As above, equipped with post-com bustion capture based on MEA scrubbing 500 [7],[5],[97] 35% [5] 42% JRC 
Circulating Fluidised Bed Combustion 
(CFBC) Circulating fluidised bed plant 300 [1],][24] 40% [101] 50% [101] 
Integrated Gasificati on Combined Cycle 
(IGCC) Plant with a dry-fed entrained flow ga sifier and state-of-the-art syngas 
turbines 675 [1],[97],[101],
[102],[88],[91] 45% [101],[102] 57% [101] 
Integrated Gasificati on Combined Cycle 
with CCS Mean performance of dry- and slurry-f ed IGCC plants with pre-combustion 
capture using the Selexol process 600 [7],[97],[102] 35% [102] 47% JRC 
Nuclear fission Generation III water cooled reac tor designs (mainly considering 
evolutionary light water reactor designs as EPR and ABWR) 1600 [19],[15],[33-38] 35% [19],[15], 
[33-38] 36% JRC 
Biomass combustion steam cycle  
– small scale Combustion boiler with a steam turbine 5 [54],[55] 24% [42], [54], [55] 25% JRC 
Biomass combustion steam cycle  
– large scale Fluidized bed combustion boiler with a steam turbine 30 [54] 29% [42], [54] 30% JRC 
Biogas plant Farm-scale co-digestion biogas plant 0.3 [41],[42],[113] 31% [41], [43] 32% JRC 
Landfill Gas Landfill with a gas engine 4.4 [41] 34% [41], [42] 36% JRC 
On-shore Wind On-shore wind turbine in a farm configuration 2 [1],[24],[41], 
[64-65],[119] - - - - 
Off-shore Wind Off-shore wind turbine in a farm configuration, located in shallow waters
(up to 30m) 3.6 [1],[24],[41], 
[77-78],[119] - - - - 
20 [41],[63] - - - - 
75 [41],[63] - - - - Hydropower – large scale Hydropower plant above 10 MWe, cons idering different configurations
from the building of a new facility, the extension of an existing facility an d
the powering an existing hydro scheme 250 [41],[63] - - - - 
2 [41],[63] - - - - 
Hydropower – small scale Hydropower plant below 10 MWe cons idering different configurations
from the building of a new facility, the extension of an existing facility an d
the powering an existing hydro scheme 10 [41],[63] - - - - 
Photovoltaics System based on crystalline silicon panels 1 JRC - - - - 
Concentrating Solar Power (CSP) Parabolic trough collector with storag e and natural gas backup power plant 50 [146] - - - - 
 
EN 15   EN Table 3-2: Overnight specific capital inve stment and O&M costs of power  generation technologies, and assumed fuel prices 
SCI P (state-of-the-art, 2007) Annualized O&M costs (VOM+FOM) Fuel prices (Moderate / High) 
[€2005/kW]  [€2005/kW]  [€2005/toe] Technology 
REF Range References REF Range References 2007 2020 2030 
Open Cycle Gas Turbine (GT) 310 200 ÷ 400 [2-3] 10 6 ÷ 13 
Combined Cycle Gas Turbine (CCGT) 635 480 ÷ 730 [1],[5],[24],[91] 25 19 ÷ 26 
Combined Cycle Gas Turbine with CCS 1200 1000 ÷ 1300 [7],[5],[97-98] 40 37 ÷ 44 JRC,[5] 250 L: 300
H: 510 L: 320 
H: 595 
Internal Combustion Diesel Engine 800 550 ÷ 1350 [3],[24] 40 29 ÷ 63 
Combined Cycle Oil-fired Turbine 1000 900 ÷ 1100 [100] 50 48 ÷ 55 JRC 440 L: 550
H: 745 L: 540 
H: 920 
Pulverised Coal Combustion (PCC) 1265 1000 ÷ 1440 [1],[5],[24],[91] 60 50 ÷ 67 
Pulverised Coal Combustion with CCS 2250 1700 ÷ 2700 [92],[94],[97] 90 76 ÷ 101 
Circulating Fluidised Bed Combustion 
(CFBC) 1400 1250 ÷ 1500 [1,24] 70 62 ÷ 71 
Integrated Gasificati on Combined Cycle 
(IGCC) 1550 1400 ÷ 1650 [1],[97],[101],[102],[88],[91] 65 61 ÷ 69 
Integrated Gasificati on Combined Cycle 
with CCS 2100 1700 ÷ 2400 [7],[97],[102] 85 74 ÷ 95 JRC,[5],[94],[102] 90 L: 95 
H: 155 L: 105 
H: 190 
Nuclear fission 2680 1970 ÷ 3380 [8-32],[1] 90 74 ÷ 107 [1],[22-25],[27],[31],[38-39] 33 L: 35 
H: 53 L: 37 
H: 63 
Biomass combustion steam cycle  
– small scale 3800 2900 ÷ 5080 [42],[54],[55],[85],[147] 260 235 ÷ 292 [42],[54],[55],[120],[125] 160 L: 215
H: 235 L: 235 
H: 275 
Biomass combustion steam cycle  
– large scale 2450 2020 ÷ 3220 [54],[42],[55] 135 124 ÷ 161 [54],[55],[120],[125] 90 L: 120 
H: 135 L: 135 
H: 160 
Biogas plant 3140 2960 ÷ 5790 [41],[42],[43],[45], 
[108],[113] 245 237 ÷ 334 [113] 270 270 270 
Landfill Gas 1530 1400 ÷ 2000 [41],[48],[49] 200 199 ÷ 211 [42],[132] 0 0 0 
On-shore Wind 1140 1000 ÷ 1370 [1],[6],[19],[24],[40-42], 
[64-70] 35 33 ÷ 42 [1],[6],[19],[24],[41-42], 
[64-65],[68-70]  -  
Off-shore Wind 2000 1750 ÷ 2750 [1],[6],[19],[24], 
[40-41],[66],[68],[70],[119] 80 71 ÷ 105 [1],[6],[24],[41-42], 
[64-65],[68],[70]  -  
2510 1750 ÷ 4500 75 - [24],[41],[119],[132-134]  -  
1800 1230 ÷ 3650 55 - [24],[41],[119],[121],[132-134]  -  Hydropower – large scale 
1350 900 ÷ 3100 [6],[41],[60],[63],[126] 
40 - [24],[41],[119],[132-134]  -  
4500 2500 ÷ 6600 130 -  -  Hydropower – small scale 2900 2000 ÷ 4800 [6],[41],[60],[63],[126],[147] 85 - [24],[41],[119],[132-134]  -  
Photovoltaics 4700 4100 ÷ 6900 [136],[24],[90],[94] 80 72 ÷ 114 JRC,[92]  -  
Concentrating Solar Power 5000 4000÷6000 [146],[6],[19],[24],[137-143] 115 111÷121 [146],[24],[137],[139-143] 250 (a) L: 300 
H: 510 (a) L: 320 
H: 595 (a) 
(a) Natural gas consumed for backup heat production.
 
EN 16   EN Table 3-3: Construction time and life time of facility, current and future global installed capacity, learning rate and lifecyc le GHG emissions  
Global installed capacity Construct. 
time Life-time CP C2030 Learning 
rate, LR  Lifecycle GHG emission Technology 
[year] [year] [GW] [GW] [%] References tCO2/GWh References 
Open Cycle Gas Turbine (GT) 1 25 225 1110 5.0% [6],[7],[87] 520 ÷ 600 [95],[104] 
Combined Cycle Gas Turbine (CCGT) 3 25 350 790 5.0% [6],[7],[96] 365 ÷ 495 [95],[103-104] 
Combined Cycle Gas Turbine with CCS 4 25 1 61 2.2% [7],[6] 80 ÷ 235 [95],[103-104] 
Internal Combustion Diesel Engine 1 25 200 930 3.0% [87] 670 ÷ 690 [95],[104] 
Combined Cycle Oil-fired Turbine 3 25 350 790 3.0% [6],[7],[96] 570 ÷ 590 [95],[104] 
Pulverised Coal Combustion (PCC) 3 40 300 790 6.0% [6],[7],[96] 800 ÷ 860 [95],[103-104] 
Pulverised Coal Combustion with CCS 4 40 10 235 2.1% [7],[6] 240 ÷ 290 [95],[103-104] 
Circulating Fluidised Bed Combustion 
(CFBC) 3 40 70 230 6.0% [101],[101] 950 ÷ 980 [95],[103-104] 
Integrated Gasificati on Combined Cycle 
(IGCC) 3 40 1 3 11.0% [7] 830 ÷ 860 [95],[103-104] 
Integrated Gasificati on Combined Cycle 
with CCS 4 40 10 235 5.0% [6],[7] 240 ÷ 290 [95],[103-104] 
Nuclear fission 6 40 3 (a) 100 (a) 3.0% [26],[40],[6] 3 ÷ 40 [95],[129-131],[103-104] 
Biomass combustion steam cycle  
– small scale 2 30 12.5% [6],[41] 42 [119] 
Biomass combustion steam cycle  
– large scale 2 30 62 125 
12.5% [6],[41] 21 [119] 
Biogas plant 1 25 12.5% [6],[41],[46],[47] 245 [119] 
Landfill Gas 1 25 4 11 11.0% [6],[41],[46],[47] 6 [119] 
On-shore Wind 1 20 95 960 8.0% [6],[64],[68],[73-76] 7 ÷ 30 [95],[40],[103-104] 
Off-shore Wind 2 20 12 210 8.0% [6],[64],[68],[73-76] 9 ÷ 22 [95],[40],[103-104] 
4 50 
4 50 Hydropower – large scale 
4 50 770 n/a -0.5% per year [6],[41],[73] 3.5 ÷ 40 [95],[119] 
3 50 3.5 ÷ 10 [59],[119],[95] Hydropower – small scale 3 50 75 n/a -1.2% per year [41],[73] 3.5 ÷ 32 [59],[119],[95] 
Photovoltaics 0 25 8 150 23.0% [94],[93],[6],[93] 40 ÷ 110 [40],[95],[103] 
Concentrating Solar Power 2 40 0.4 60 10.0% [6],[138],[144-146]  135 (b) [40] 
(a) Values represent the global installed c apacity of Generation III (and 3+) nuclear re actors only, and not the total installed n uclear capacity operating worldwide (370 GW in 2007). 
(b) This includes 15 t CO2/GWh of indirect emissions and the direct combustion emis sions from natural gas use.  
 
EN 17   EN 3.2. Energy Sources for Heating 
This section describes the methodology and data  used for the comparison Table of energy 
sources for heating. Table 3-4 summarises the techno-economic characte ristics of selected 
current state-of-the-art heat  generation technologies.  
3.2.1.  Technologies 
This analysis focuses on central heating syst ems for households with heat generation 
capacities between 15 kW th and 100 kW th. The technologies addressed are: 
1. Natural gas fuelled boiler 
2. Heating oil fuelled boiler 
3. Coal fuelled boiler 
4. Biomass fuelled boiler: 
– Wood chips 
– Pellets 
5. Solar thermal system 
6. Geothermal with heat pump 
7. Electricity boiler and heater 
District heating and cogeneration of heat and pow er (CHP) are not addressed in this analysis. 
3.2.2.  Indicators 
The methodology used for calculating the cost of heat generation is similar to the one used for 
the calculation of the production co st of electricity. In this s ection, only the main differences 
are described.  
(I) Market share: The market shares reported in the upda ted Table refer to the residential 
sector only. The reported values have been adopted from the publication 'European Energy 
and Transport: Trends to 2030 - Update 2007'12. It is noted that dist rict heating, which has a 
share of 7.6% of the market, has not been considered in the analysis. 
(II) Fuel retail price:  This refers to fuel prices for house holds, including taxes. Fuel costs for 
the moderate fuel price scenario are deri ved from the DG TREN publication 'European 
Energy and Transport: Tre nds to 2030 - Update 2007'13, while fuel costs for the high fuel 
price scenario are based on the DG TREN 'Scenarios on high oil and gas prices'14. Moreover, 
prices for biomass were calculated ba sed on values reported in EUBIONET II15 and adjusted 
to reflect the biomass price trends consid ered in the previously mentioned DG TREN 
scenarios. 
(III) Production cost of heat:  The production cost of heat, e xpressed in constant €(2005)/toe 
in useful heat produced, is used to compare the economic competitiveness among different 
energy sources for heating. The reported values  represent a snapshot of costs in 2007. 
Running costs refer to the annual cost to produce heat without considerin g the initial capital 
costs. Total costs refer to the production cost that includes the reco very of capital. The 
                                                 
12 See reference [80] 
13 See reference [80] 
14 To be published 
15 See reference [56] 
 
EN 18   EN reported values for each energy source refer to a st ate-of-the-art heating facility, as described 
in Table 3-4. The reported range reflects different  technologies and varia tions in capital costs 
but does not reflect the variability in the fuel  retail prices between the Member States. 
The reported running producti on cost values have been calculated using the following 
formula: 
FC VOMLFFOMRCH ++⋅=8760 
 
The reported total produc tion cost values have been calcu lated using the following formula: 
RCHLFCRF SCICOH +⋅⋅=8760 
 
Where: 
RCH  …is the running cost of  heat production, in € 2005/toe, 
COH  …is the total production cost of heat, in € 2005/toe, 
LF …is the annual load factor of the heating system, 
FOM  …refers to the annual fixed operating costs, in € 2005/toe, 
VOM  …refers to the variable operating costs, in € 2005/toe, 
FC …refers to fuel costs, in € 2005/toe, 
SCI …is the specific overnight capital investment, in € 2005/toe, 
CRF  …is the capital recovery factor. 
All values are reported in useful heat produced  
An annual load factor of 10% was used for th e calculations for all technologies except for 
solar where a value of 8% was used to reflect resource constraints. The former load factor 
refers to an average of the a nnual operating time of the heat  production facility at nominal 
capacity to meet the heat demand of a typical European house of about 110 m2 and of a small 
residential building of about 550 m2, based on an average annual outdoor temperature of 
8.8°C and an indoor temperature of 20/19/22°C16.  
FOM  costs account for the service,  maintenance and repair of the heating facility, while VOM  
costs account for the cost of ot her consumables, mainly auxili ary power. Table 3-4 shows the 
total operational and maintenance costs (OM) normalised to the installed net capacity. 
The fuel costs were calculated based on the fu el retail prices as noted above for the two 
scenarios. 
The overnight specific capital investment ( SCI) for each heating facility refers to the price of 
the heating unit and its installation, excluding the cost of additional infrastructure.  
A real discount rate of 15% wa s assumed for all technologies fo r the calculation of the capital 
recovery factor ( CRF ).  
No carbon costs were considered in the calcu lation of the cost of heat generation.  
                                                 
16 See reference [117] 
 
EN 19   EN (IV) Life-cycle greenhouse gas emissions:  Life cycle emissions were calculated following 
the same methodology and databases as for power generation technologies.  
 
EN 20   EN Table 3-4: Technology description, installa tion size, current conversion efficiency, overnight specif ic capital investment, lif e-time and O&M costs of 
heat generation technologies 
Capital costs, 2007 Annual O&M costs 
(VOM+FOM) Capacity Efficiency 
[€2005/kW], VAT excl. [€2005/kW], VAT excl. Life-
time Lifecycle GHG 
emissions Technology Description 
[kW] [%] References REF Range References REF Range References [year] tCO2/toe References 
Natural gas fuelled boiler, large size, combi, 
floorstanding 75 89% [112], [117], 
[116] 110 95 ÷ 135 [112], [118] 9 9 ÷ 10 [112], [118] 17 3.3 [95] 
Natural gas fuelled boiler, medium/small size, 
combi, wall-hung 20 86% [112], [117], 
[116] 125 100 ÷ 130 [112] 13 11 ÷ 14 [112] 17 3.4 [95] Natural gas 
boiler 
Natural gas fuelled condensing boiler, medium 
size, combi, wall-hung 20 104% [112], [117], 
[116] 145 115 ÷ 155 [112] 11 10 ÷ 12 [112] 17 2.9 [95] 
Heating oil fuelled boiler, large size, combi, floor 
standing, with oil reservoir 75 86% [112], [117], 
[116] 190 160 ÷ 240[112], [110], 
[118] 12 11 ÷ 14 [112], [118] 17 4.2 [95] 
Heating oil fuelled boiler, medium/small size, 
combi, floorstanding, with oil reservoir 20 80% [112], [117], 
[116] 325 265 ÷ 355 [112] 18 15 ÷ 19 [112] 17 4.5 [95] Heating oil 
boiler 
Heating oil fuelled condensing boiler, medium 
size, combi, floorstanding, with oil reservoir 20 99% [112], [117], 
[116] 390 310 ÷ 425 [112] 13 11 ÷ 14 [112] 17 3.6 [95] 
Coal boiler Solid fuel fuelled boiler,  large size, with heat 
buffer 50 75% JRC 340 310 ÷ 410 JRC 13 12 ÷ 15 JRC 17 6.1 [95],[103] 
Wood chips fired boiler, large size, with hot water 
reservoir and heat buffer 50 79% [110] 385 325 ÷ 440[109], [110], 
[111] 16 14 ÷ 18 [110] 17 0.3 [59], [95] Wood chips 
boiler Wood chips fired boiler, medium size, with hot 
water reservoir and heat buffer 35 79% [110] 575 490 ÷ 665[109], [110], 
[111] 22 20 ÷ 25 [110] 17 0.3 [59], [95] 
Pellets fired boiler, large size, with hot water 
reservoir and heat buffer, inc. pellets silo 50 84% [110] 355 300 ÷ 410[109], [110], 
[111] 15 13 ÷ 17 [110] 17 0.7 [95] 
Pellets fired boiler, medi um size, with hot water 
reservoir and heat buffer, inc. pellets silo 35 84% [110] 505 430 ÷ 585[109], [110], 
[111] 19 17 ÷ 22 [110] 17 0.7 [95] Pellets boiler 
Pellets fired boiler, small size, with hot water 
reservoir and heat buffer, inc. pellets silo 15 84% [110] 940 800 ÷ 1080[109], [110], 
[111] 34 29 ÷ 38 [110] 17 0.8 [95] 
Solar heat Water heating system 3.5 98% [135] 980 340 ÷ 2800 [92] 16 - [92] 20 0.3 [95] 
Large size electrical operated heat pump with 
geothermal heat source 100 100% [116] 500 200 ÷ 1150 [92] 39 34 ÷ 60 [92] 25 0.2 ÷ 3.7 [95] Geothermal 
heat pump Medium size electrical ope rated heat pump with 
horizontal or water ground heat source 15 100% [116] 640 550 ÷ 720 [115] 55 54 ÷ 69 [112] 17 0.3 ÷ 5.9 [95] 
Electric combi heating/water boiler, medium/small 
size, wall-hung 20 100% JRC 75 65 ÷ 90 JRC 5 - JRC 17 0.7÷14.8 [95] Electrical 
heating Resistance heaters with fa n assisted air circulation 2 97% [123] 140 30 ÷ 300 JRC n/a - [123] 10 0.7÷15.2 [95] 
 
EN 21   EN 3.3. Energy Sources for Transport Fuels 
The techno-economic characteristics of the se lected transport fuels reported have been 
calculated by the JRC based on the methodol ogy developed in the Well to Wheel JRC–
EUCAR-CONCAWE study17, but using the fuel prices used in  this analysis. The time horizon 
considered is 2015. 
Domestic biofuel production encompass ethano l produced from wheat grain with by-product 
credits for animal feed and heat supply from natural gas fired CCGT, and RME biodiesel with 
credits for animal feed. The second generation biofuel pathways are based on ethanol from 
straw and BTL using short rotation forestry as a feedstock. 
                                                 
17 See reference [4] 
 
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