(...PICT...)|COMMISSION OF THE EUROPEAN COMMUNITIES|

Brussels, 13.11.2008

SEC(2008) 2872

COMMISSION STAFF WORKING DOCUMENT accompanying the

COMMUNICATION FROM THE COMMISSION TO THE EUROPEAN PARLIAMENT, THE COUNCIL, THE EUROPEAN ECONOMIC AND SOCIAL COMMITTEE AND THE COMMITTEE OF THE REGIONS Second Strategic Energy Review AN EU ENERGY SECURITY AND 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}

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. Introduction

Europe needs to act now to deliver sustainable, secure and competitive energy. The inter-related challenges of climate change, security 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 European Council on 9 March 2007 European Council conclusions adopted on the basis of the Commission's Energy 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 . [1]

European Council conclusions adopted on the basis of the Commission's Energy 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

This document provides a comparative analysis of energy sources, production costs and performance of technologies for power generation, 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 previous SEER exercise have been 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 plant and an additional biomass conversion route. In addition, two fuel price scenarios have been considered to reflect variations in the future price of energy commodities. All reported values in the Tables for electricity generation, heating and transport fuels have been calculated following a consistent methodology, hence they are directly comparable. The calculations rely on up-to-date available data and information on energy conversion technology performance.

This report consists of two parts. Part I includes the three Tables for use in the 2 nd SEER. Part II provides a comprehensive description of the implemented methodology and includes the technology-related data used for the calculations, accompanied by a reference list.

2. Part I: Main Tables

Table 2 1 : Energy Technologies for Power Generation – Moderate Fuel Price Scenario (a)

||State-of-the-art 2007|Projection for 2020|Projection for 2030||Direct (stack) emissions|Indirect emissions|Lifecycle emissions||

||€ 2005 /MWh|€ 2005 /MWh|€ 2005 /MWh||kg CO 2 /MWh|kg CO 2 (eq)/MWh|kg CO 2 (eq)/MWh||

Natural gas|Open Cycle Gas Turbine (GT)|-|65 ÷ 75 (b)|90 ÷ 95 (b)|90 ÷ 100 (b)|38%|530|110|640|Very high|

|Combined Cycle Gas Turbine (CCGT)|-|50 ÷ 60|65 ÷ 75|70 ÷ 80|58%|350|70|420|Very high|

||CCS|n/a|85 ÷ 95|80 ÷ 90|49% (c)|60|85|145|Very high|

Oil|Internal Combustion Diesel Engine|-|100 ÷ 125 (b)|140 ÷ 165 (b)|140 ÷ 160 (b)|45%|595|95|690|Very high|

|Combined Cycle Oil-fired Turbine (CC) |-|95 ÷ 105 (b)|125 ÷ 135 (b)|125 ÷ 135 (b)|53%|505|80|585|Very high|

Coal|Pulverised Coal Combustion (PCC)|-|40 ÷ 50|65 ÷ 80|65 ÷ 80|47%|725|95|820|Medium|

||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|

|Integrated Gasification Combined Cycle (IGCC) |-|45 ÷ 55|70 ÷ 80|70 ÷ 80|45%|755|100|855|Medium|

||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|

Biomass|Solid biomass|-|80 ÷ 195|85 ÷ 200|85 ÷ 205|24% ÷ 29%|6|15 ÷ 36|21 ÷ 42|Medium|

|Biogas|-|55 ÷ 215|50 ÷ 200|50 ÷ 190|31% ÷ 34%|5|1 ÷ 240|6 ÷ 245|Medium|

Wind|On-shore farm|-|75 ÷ 110|55 ÷ 90|50 ÷ 85|-|0|11|11|nil|

|Off-shore farm|-|85 ÷ 140|65 ÷ 115|50 ÷ 95|-|0|14|14||

Hydro|Large|-|35 ÷ 145|30 ÷ 140|30 ÷ 130|-|0|6|6|nil|

|Small|-|60 ÷ 185|55 ÷ 160|50 ÷ 145|-|0|6|6||

Solar|Photovoltaic|-|520 ÷ 880|270 ÷ 460|170 ÷ 300|-|0|45|45|nil|

|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 'European 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 demonstration installations that start operating in 2015

(d) Assuming the use of natural gas for backup heat production Table 2 2 : Energy Technologies for Power Generation – High Fuel Price Scenario (a)

||State-of-the-art 2007|Projection for 2020|Projection for 2030||Direct (stack) emissions|Indirect emissions|Lifecycle emissions||

||€ 2005 /MWh|€ 2005 /MWh|€ 2005 /MWh||kg CO 2 /MWh|kg CO 2 (eq)/MWh|kg CO 2 (eq)/MWh||

Natural gas|Open Cycle Gas Turbine (GT)|-|80 ÷ 90 (b)|145 ÷ 155 (b)|160 ÷ 165 (b)|38%|530|110|640|Very high|

|Combined Cycle Gas Turbine (CCGT)|-|60 ÷ 70|105 ÷ 115|115 ÷ 125|58%|350|70|420|Very high|

||CCS|n/a|130 ÷ 140|140 ÷ 150|49% (c)|60|85|145|Very high|

Oil|Internal Combustion Diesel Engine|-|125 ÷ 145 (b)|200 ÷ 220 (b)|230 ÷ 250 (b)|45%|595|95|690|Very high|

|Combined Cycle Oil-fired Turbine (CC) |-|115 ÷ 125 (b)|175 ÷ 185 (b)|200 ÷ 205 (b)|53%|505|80|585|Very high|

Coal|Pulverised Coal Combustion (PCC)|-|40 ÷ 55|80 ÷ 95|85 ÷ 100|47%|725|95|820|High|

||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|

|Integrated Gasification Combined Cycle (IGCC) |-|50 ÷ 60|85 ÷ 95|85 ÷ 95|45%|755|100|855|High|

||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|

Biomass|Solid biomass|-|80 ÷ 195|90 ÷ 215|95 ÷ 220|24% ÷ 29%|6|15 ÷ 36|21 ÷ 42|Medium|

|Biogas|-|55 ÷ 215|50 ÷ 200|50 ÷ 190|31% ÷ 34%|5|1 ÷ 240|6 ÷ 245|Medium|

Wind|On-shore farm|-|75 ÷ 110|55 ÷ 90|50 ÷ 85|-|0|11|11|nil|

|Off-shore farm|-|85 ÷ 140|65 ÷ 115|50 ÷ 95|-|0|14|14||

Hydro|Large|-|35 ÷ 145|30 ÷ 140|30 ÷ 130|-|0|6|6|nil|

|Small|-|60 ÷ 185|55 ÷ 160|50 ÷ 145|-|0|6|6||

Solar|Photovoltaic|-|520 ÷ 880|270 ÷ 460|170 ÷ 300|-|0|45|45|nil|

|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 'Scenarios 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 demonstration installations that start operating in 2015

(d) Assuming the use of natural gas for backup heat production Table 2 3 : Energy Sources for Heating – Moderate Fuel Price Scenario (a)

|||Running cost|Total cost|Direct (stack) emissions|Indirect emissions|Lifecycle emissions|

||€ 2005 /toe|€ 2005 /toe|€ 2005 /toe|t CO 2 /toe|t CO 2 (eq)/toe|t CO 2 (eq)/toe|

Fossil fuels|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|

|Coal|3.1%|375|675 ÷ 750|1500 ÷ 1825|5.4|0.7|6.1|

Biomass, solar and other|Wood chips|11.6%|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|

|Geothermal||-|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 'European 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

Table 2 4 : Energy Sources for Heating – High Fuel Price Scenario (a)

|||Running cost|Total cost|Direct (stack) emissions|Indirect emissions|Lifecycle emissions|

||€ 2005 /toe|€ 2005 /toe|€ 2005 /toe|t CO 2 /toe|t CO 2 (eq)/toe|t CO 2 (eq)/toe|

Fossil fuels|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|

|Coal|3.1%|590|975 ÷ 1025|1775 ÷ 2100|5.4|0.7|6.1|

Biomass, solar and other|Wood chips|11.6%|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|

|Geothermal||-|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 'Scenarios on high oil and gas prices' (barrel of oil 100$ 2005 )

(b) District heating has an additional share of 7.6% of the market

Table 2 5 : Energy Sources for Road Transport – Moderate and High Fuel Price Scenario

Energy source for road transport|Cost of Fuels to the EU|Lifecycle GHG emissions (c)|

|Moderate Fuel Price Scenario (a)|High Fuel Price Scenario (b)||

|€ 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 Transport: 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 appropriate methodology for calculating 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 market price of biofuels imported in the EU|

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 , Table 3 2 and Table 3 3 summarise the techno-economic characteristics of the selected state-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 cycle 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

It is noted that cogeneration of heat and power is not considered in this analysis.

3.1.2. Indicators

For each technology the following indicators are reported:

(I) Production cost of electricity (current and projected to 2020 and 2030): The levelized production cost of electricity, expressed in constant €(2005)/MWh of net power generated, is used to compare the economic competitiveness among power generation technologies during their life time. The reported values for the production cost of electricity for each technology refer to a state-of-the-art facility, assumed to start operating in the indicated year (2007, 2020 or 2030), as described in Table 3 1 . The reported range reflects variations in capital costs which depend on specific technology choices, plant location, etc. The reported range does not, however, reflect the variability in the fuel retail prices between the Member States An average European fuel price has been considered as discussed below. . [2]

An average European fuel price has been considered as discussed below.

The reported production cost values have been calculated using the following formula:

(...PICT...)

Where:

COE … is the levelized production cost of electricity, in € 2005 /MWh,

SCI … is the specific overnight capital investment of the power generation facility, in € 2005 /MW,

IDC … is the interest during 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 facility 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 during the facility life time, in € 2005 /MWh,

CC … refers to annualized carbon costs during the facility life time, in € 2005 /MWh

CTS …refers to annualized expenditures for transport and 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 investment costs for a given 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 Eurostat 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 Euro area as reported by Eurostat. Finally, to include the recent price increases these values were adjusted to January 2007 using the chemical engineering plant cost index For more information see: Updating the CE Plant Cost Index, Chemical Engineering, January 2002, p. 62. . The SCI values are shown in Table 3 2 . Values for future SCI s 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 capacity as a proxy, based on the formula:[3]

For more information see: Updating the CE Plant Cost Index, Chemical Engineering, January 2002, p. 62.

(...PICT...)

Where:

SCI P …is the current specific capital investment cost,

C P …is the current global installed capacity,

C F …is the installed capacity of the technology in a future time, e.g. in 2020,

LR …is the learning rate of the technology.

Values for C P , C F 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. Furthermore, the global installed capacity of each technology is kept constant for the two fossil fuel price scenarios.

The IDC was calculated considering the construction time for each plant (see Table 3 3 ) and a capital expenditure profile during construction:

(...PICT...)

Where:

CT …is the construction time,

W k …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:

(...PICT...)

Where d is the real discount rate and n is the facility life time.

For all technologies a real discount 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 facilities operate in a base-load mode with a LF of 85%, including open cycle gas turbines and diesel reciprocating engines that are used also to meet peak load. The following exceptions were made:

– Photovoltaics: 11%

– Concentrating solar thermal power: 41% Including thermal storage and natural gas backup. Load factor is assumed constant over time.[4]

Including thermal storage and natural gas backup. Load factor is assumed constant over time.

– 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 fraction of the total investment costs (calculated using the net capacity and SCI values 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 estimating 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 shows the total operational and maintenance costs (OM) This accounts for FOM and VOM, and excludes fuel and carbon costs normalised to the installed net capacity.[5]

This accounts for FOM and VOM, and excludes fuel and carbon costs

Fuel costs ( FC ) were calculated for two scenarios, moderate 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' See reference [80] , while fuel prices for the high scenario are based on DG TREN ' Scenarios on high oil and gas prices ' To be published . Moreover, prices for biomass were calculated based on values reported in EUBIONET II See reference [56] and adjusted to reflect the biomass price trends considered in the previously mentioned DG TREN scenarios. These values reflect the fuel price at the plant gate. 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 facility, due to changes in fuel prices, was also considered through 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 concentrating solar thermal power, FC were calculated assuming a constant consumption of natural gas of 385 TJ per year for backup heat production.[6][7][8]

See reference [80]

To be published

See reference [56]

Carbon costs ( CC ) were considered only for the projected costs of electricity 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 operation were derived from the IPCC Guidelines for National Greenhouse Gas Inventories See reference [127] , as explained below. It was assumed that concentrating solar thermal power does not carry carbon costs.[9]

See reference [127]

In the case of power plants with carbon capture technology, the cost of CO 2 transport and storage costs was also taken into account for the calculation of the production cost of electricity and was treated as an additional operational cost element. A value of €20 per tonne of CO 2 captured was assumed to account for the cost 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.

(II) Net efficiency: The reported values refer to the current state-of-the-art power generating facility with the exception of the CCS plants. For the latter, the reported values refer to first-of-a-kind demonstration installations, assumed to start operating 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 net efficiency values used for calculating the projected cost of electricity 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-the-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 technologies comprise the direct (stack) emissions from the combustion/gasification process and the indirect emissions originating among others from the fuel supply chain and plant construction. Direct emissions were calculated according to IPCC Guidelines. In the 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 indirect emissions of plants were based on an average value provided by the Ecoinvent Life Cycle Inventory See reference [95] for the supply of each type of fuel in Europe. Indirect emissions from other 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 cycle GHG emission values of similar technologies available in the Ecoinvent database and other relevant literature See reference [103] and [104] .[10][11]

See reference [95]

See reference [103] and [104]

For the non-fossil fuel technologies, lifecycle GHG emissions were obtained directly from available references listed in Table 3 3 .

It is noted that the pathways for the supply of fuel and raw materials, and 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 estimated by the fraction of fuel costs to the total production cost of electricity. In the context of this analysis, the 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%

Table 3 1 : Technology description, installation size, and current and future conversion efficiency

Technology|Description|Net capacity|Net efficiency|

|||2007 (2015 for CCS)|2030|

||[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 generator 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 based on MEA scrubbing|550|[7],[5],[97-98]|49%|[5]|55%|JRC|

Internal Combustion Diesel Engine|Heavy duty reciprocating 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 º C, FGD and SCR|800|[1],[5],[24],[91]|47%|[91],[101]|54%|JRC|

Pulverised Coal Combustion with CCS|As above, equipped with post-combustion 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 Gasification Combined Cycle (IGCC)|Plant with a dry-fed entrained flow gasifier and state-of-the-art syngas turbines|675|[1],[97],[101], [102],[88],[91]|45%|[101],[102]|57%|[101]|

Integrated Gasification Combined Cycle with CCS|Mean performance of dry- and slurry-fed IGCC plants with pre-combustion capture using the Selexol process|600|[7],[97],[102]|35%|[102]|47%|JRC|

Nuclear fission|Generation III water cooled reactor 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]|-|-|-|-|

Hydropower – large scale|Hydropower plant above 10 MWe, considering different configurations from the building of a new facility, the extension of an existing facility and the powering an existing hydro scheme|20|[41],[63]|-|-|-|-|

||75|[41],[63]|-|-|-|-|

||250|[41],[63]|-|-|-|-|

Hydropower – small scale|Hydropower plant below 10 MWe considering different configurations from the building of a new facility, the extension of an existing facility and the powering an existing hydro scheme|2|[41],[63]|-|-|-|-|

||10|[41],[63]|-|-|-|-|

Photovoltaics|System based on crystalline silicon panels|1|JRC|-|-|-|-|

Concentrating Solar Power (CSP)|Parabolic trough collector with storage and natural gas backup power plant|50|[146]|-|-|-|-|

Table 3 2 : Overnight specific capital investment and O&M costs of power generation technologies, and assumed fuel prices

Technology|SCI P (state-of-the-art, 2007)|Annualized O&M costs (VOM+FOM)|Fuel prices (Moderate / High)|

|[€ 2005 /kW]||[€ 2005 /kW]||[€ 2005 /toe]|

|REF|Range|References|REF|Range|References|2007|2020|2030|

Open Cycle Gas Turbine (GT)|310|200 ÷ 400|[2-3]|10|6 ÷ 13|JRC,[5]|250|L: 300 H: 510|L: 320 H: 595|

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|||||

Internal Combustion Diesel Engine|800|550 ÷ 1350|[3],[24]|40|29 ÷ 63|JRC|440|L: 550 H: 745|L: 540 H: 920|

Combined Cycle Oil-fired Turbine|1000|900 ÷ 1100|[100]|50|48 ÷ 55|||||

Pulverised Coal Combustion (PCC)|1265|1000 ÷ 1440|[1],[5],[24],[91]|60|50 ÷ 67|JRC,[5],[94],[102]|90|L: 95 H: 155|L: 105 H: 190|

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 Gasification Combined Cycle (IGCC)|1550|1400 ÷ 1650|[1],[97],[101],[102],[88],[91]|65|61 ÷ 69|||||

Integrated Gasification Combined Cycle with CCS|2100|1700 ÷ 2400|[7],[97],[102]|85|74 ÷ 95|||||

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: 120H: 135|L: 135H: 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]||-||

Hydropower – large scale|2510|1750 ÷ 4500|[6],[41],[60],[63],[126]|75|-|[24],[41],[119],[132-134]||-||

|1800|1230 ÷ 3650||55|-|[24],[41],[119],[121],[132-134]||-||

|1350|900 ÷ 3100||40|-|[24],[41],[119],[132-134]||-||

Hydropower – small scale|4500|2500 ÷ 6600|[6],[41],[60],[63],[126],[147]|130|-|[24],[41],[119],[132-134]||-||

|2900|2000 ÷ 4800||85|-|||-||

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. Table 3 3 : Construction time and life time of facility, current and future global installed capacity, learning rate and lifecycle GHG emissions

Technology|Construct. time|Life-time|Global installed capacity|Learning rate, LR||Lifecycle GHG emission|

|||C P|C 2030||||

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 Gasification Combined Cycle (IGCC)|3|40|1|3|11.0%|[7]|830 ÷ 860|[95],[103-104]|

Integrated Gasification 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|62|125|12.5%|[6],[41]|42|[119]|

Biomass combustion steam cycle – large scale|2|30|||12.5%|[6],[41]|21|[119]|

Biogas plant|1|25|4|11|12.5%|[6],[41],[46],[47]|245|[119]|

Landfill Gas|1|25|||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]|

Hydropower – large scale|4|50|770|n/a|-0.5% per year|[6],[41],[73]|3.5 ÷ 40|[95],[119]|

|4|50|||||||

Hydropower – small scale|3|50|75|n/a|-1.2% per year|[41],[73]|3.5 ÷ 10|[59],[119],[95]|

|3|50|||||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 capacity of Generation III (and 3+) nuclear reactors only, and not the total installed nuclear capacity operating worldwide (370 GW in 2007).

(b) This includes 15 t CO2 /GWh of indirect emissions and the direct combustion emissions from natural gas use.

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 characteristics of selected current state-of-the-art heat generation technologies.

3.2.1. Technologies

This analysis focuses on central heating systems 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 power (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 cost of electricity. In this section, only the main differences are described.

(I) Market share: The market shares reported in the updated 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' See reference [80] . It is noted that district heating, which has a share of 7.6% of the market, has not been considered in the analysis.[12]

See reference [80]

(II) Fuel retail price: This refers to fuel prices for households, including taxes. Fuel costs for the moderate fuel price scenario are derived from the DG TREN publication 'European Energy and Transport: Trends to 2030 - Update 2007' See reference [80] , while fuel costs for the high fuel price scenario are based on the DG TREN 'Scenarios on high oil and gas prices' To be published . Moreover, prices for biomass were calculated based on values reported in EUBIONET II See reference [56] and adjusted to reflect the biomass price trends considered in the previously mentioned DG TREN scenarios.[13][14][15]

See reference [80]

To be published

See reference [56]

(III) Production cost of heat: The production cost of heat, expressed 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 considering the initial capital costs. Total costs refer to the production cost that includes the recovery of capital. The reported values for each energy source refer to a state-of-the-art heating facility, as described in Table 3 4 . The reported range reflects different technologies and variations in capital costs but does not reflect the variability in the fuel retail prices between the Member States.

The reported running production cost values have been calculated using the following formula:

(...PICT...)

The reported total production cost values have been calculated using the following formula:

(...PICT...)

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 the 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 annual operating time of the heat production facility at nominal capacity to meet the heat demand of a typical European house of about 110 m 2 and of a small residential building of about 550 m 2 , based on an average annual outdoor temperature of 8.8°C and an indoor temperature of 20/19/22°C See reference [117] . [16]

See reference [117]

FOM costs account for the service, maintenance and repair of the heating facility, while VOM costs account for the cost of other consumables, mainly auxiliary 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 fuel 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% was assumed for all technologies for the calculation of the capital recovery factor ( CRF ).

No carbon costs were considered in the calculation of the cost of heat generation.

(IV) Life-cycle greenhouse gas emissions: Life cycle emissions were calculated following the same methodology and databases as for power generation technologies.

Table 3 4 : Technology description, installation size, current conversion efficiency, overnight specific capital investment, life-time and O&M costs of heat generation technologies

||||[€ 2005 /kW], VAT excl.|[€ 2005 /kW], VAT excl.|||

||[kW]|[%]|References|REF|Range|References|REF|Range|References|[year]|t CO2 /toe|References|

Natural gas boiler|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 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 boiler|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 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 boiler|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 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 boiler|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, medium 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 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]|

Geothermal heat pump|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]|

|Medium size electrical operated 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]|

Electrical heating|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]|

|Resistance heaters with fan assisted air circulation|2|97%|[123]|140|30 ÷ 300|JRC|n/a|-|[123]|10|0.7÷15.2|[95]|

3.3. Energy Sources for Transport Fuels

The techno-economic characteristics of the selected transport fuels reported have been calculated by the JRC based on the methodology developed in the Well to Wheel JRC–EUCAR-CONCAWE study See reference [4] , but using the fuel prices used in this analysis. The time horizon considered is 2015.[17]

See reference [4]

Domestic biofuel production encompass ethanol 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.

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[1] European Council conclusions adopted on the basis of the Commission's Energy 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

[2] An average European fuel price has been considered as discussed below.

[3] For more information see: Updating the CE Plant Cost Index, Chemical Engineering, January 2002, p. 62.

[4] Including thermal storage and natural gas backup. Load factor is assumed constant over time.

[5] This accounts for FOM and VOM, and excludes fuel and carbon costs

[6] See reference [80]

[7] To be published

[8] See reference [56]

[9] See reference [127]

[10] See reference [95]

[11] See reference [103] and [104]

[12] See reference [80]

[13] See reference [80]

[14] To be published

[15] See reference [56]

[16] See reference [117]

[17] See reference [4]

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