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European Commission

Analysis of the Impacts of Various Options to Control Emissions from the Combustion of Fuels in Installations with a Total Rated Thermal Input below 50 MW Revised Final Report

February 2014

AMEC Environment & Infrastructure UK Limited

© AMEC Environment & Infrastructure UK Limited February 2014 S:\Projects\33006 PPAQ EC Small Combustion Plants IA\C Client\Reports\Revised Final Report 2\33006 Revised Final Report_(2)_20140212.docx

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Third-Party Disclaimer Any disclosure of this report to a third party is subject to this disclaimer. The report was prepared by AMEC at the instruction of, and for use by, our client named on the front of the report. It does not in any way constitute advice to any third party who is able to access it by any means. AMEC excludes to the fullest extent lawfully permitted all liability whatsoever for any loss or damage howsoever arising from reliance on the contents of this report. We do not however exclude our liability (if any) for personal injury or death resulting from our negligence, for fraud or any other matter in relation to which we cannot legally exclude liability.

Document Revisions

No. Details Date

1 Draft final report outline for client comment

2 November 2012

2 Draft final report 17 April 2013

3 Final report 15 May 2013

4 Revised final report including additional modelling results

10 September 2013

5 Revised final report taking into account client comments

17 January 2014

6 Revised final report 12 February 2014

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Executive Summary

Introduction

AMEC Environment and Infrastructure UK Limited (‘AMEC’) were contracted by the Commission to undertake the following study: “Analysis of the impacts of various options to control emissions from the combustion of fuels in installations with a total rated thermal input below 50 MW”. A lot of work has already been undertaken looking at installations less than 50 MWth. Therefore this study aimed to build on the data gathered previously by supplementing it with new information focussed on the key gaps identified in previous studies.

This final report provides a summary of the additional data that was gathered from the Member States and industry and the main findings of the analysis. This includes the development and final composition of the EU27 database of combustion installations less than 50 MWth, the options considered and associated compliance and administrative costs and emission reductions.

This report also includes the results of some additional modelling undertaken by AMEC to support the Commission’s development of a draft Impact Assessment of proposals to control emissions from these installations.

Data gathering and compilation

A dataset of numbers, capacities and emissions estimates for combustion plants between 1 and 50 MWth was developed under a previous study (AMEC, 2012). Adjustments and additions were made during its development to ensure the dataset was representative for the EU to support an assessment of the total EU potential costs and benefits for controlling emissions from these plants. Gaps that were identified were filled, and partial information submitted were adjusted and / or supplemented when necessary.

The previous study’s dataset was used as a starting point for this study. The aim was to improve the data, which included consultations with stakeholders and requesting updates and feedback from Member States on the gap filling techniques and the assumptions applied. Section 2 of this report describes our approach for data gathering including the stakeholder consultation and a summary of the data received.

Although more complete than the dataset compiled for AMEC (2012), some gaps still remained. In particular, no data was provided for Bulgaria, Greece, Lithuania, Luxembourg and Portugal. Italy, Ireland and Slovenia indicated they were not in a position to submit any new information. Spain and the United Kingdom each provided information for only one region and Romania only commented on the terms of reference of this project issued by the Commission. Section 3 of this report describes how the updated dataset has been developed, including the gap filling that has been undertaken.

The table below provides an overview of the resulting EU27 dataset with all of the amendments, additions, updates and assumptions as described in the report.

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Table 1 Summary of EU27 Dataset

Datum 1-5 MWth 5-20 MWth 20-50 MWth

Number of plants 113,809 23,868 5,309

Capacity of plants (GWth) 273,714 232,367 177,099

Fuel consumption:

Biomass (PJ) 163 160 182

Other solid fuel (PJ) 49 46 74

Liquid fuel (PJ) 213 290 206

Natural gas (PJ) 1,268 1,704 844

Other gaseous fuel (PJ) 277 125 104

Total fuel consumption (PJ) 1,971 2,325 1,410

SO2 emissions (kt) 103 130 68

NOx emissions (kt) 210 227 117

Dust emissions (kt) 17 20 16

Options for the control of emissions from combustion installations less than 50MWth

The table below provides a high level summary of the main regulatory options considered in this study.

Table 2 Overview of Regulatory Options

Regulatory Option Summary

A. “Permitting”:

This could operate in two main ways: i. Integrated permit regulating installations similarly as IED installations under Chapter II and Annex I (permit, BAT). ii. Light permit similar as above but without public participation.

B. “Non-permitting”:

Regulating air emissions from installations via EU wide ELVs, but without a full permitting regime and without BAT obligations. As for the permitting option, this could operate in two ways: i. All plants must provide a notification to the Competent Authority who will maintain a database of plants. ii. No notification to the Competent Authority.

The main difference between the two options from the table above, namely the “permitting” (regulatory option A) and “non-permitting” (regulatory option B) options is in relation to the administrative approach and the way in which combustion installations would be regulated i.e. permitting versus non-permitting regimes.

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For each of these options we have applied a range of differing levels of ELVs to evaluate environmental and economic impacts. The Primary NOx, IED 50-100 MW and Most Stringent MS scenarios have been assessed on the basis that the ELVs would apply to all plants within scope in a given year, without differentiating between the ages, operating profile or sector of the plant or the timescales for when limits have to be met. For the Gothenburg and SULES scenarios, differentiation is made between new and existing plants with new plants being required to meet more stringent ELVs than existing plants. The timescale for implementation for these two options is also different, with compliance modelled for new plant from 2018 and existing plant from 2022. This will allow a longer time period for existing plant to retrofit abatement measures within normal investment cycles, and potentially encourage early replacement of aging plant. Furthermore, these two scenarios incorporate an exemption for plant operating less than 300 hours per year. A proportion of plant of the 1-50 MW size range are stand-by or back up plant and are therefore likely to operate for a small number of hours per year. For such plant, the installation cost of abatement technology is disproportional to the total annual emissions reduced due to the low utilisation.

The ELVs applied in the modelling are summarised in the table below (further details of the individual ELVs applied for the baseline and different scenarios are provided in Section 4 for the Most Stringent MS, IED 50-100MW and Primary NOx options and in Section 9 for the Gothenburg and SULES options).

Table 3 Overview of ELV Options

ELV Option Summary

Most Stringent MS The ELVs for this option have been set to be equal to the most stringent ELVs in MS national legislation for each fuel and technology type and plant capacity.

IED 50-100MW The ELVs for this option have been set to be equal to those for existing 50-100 MWth combustion plants in the IED.

Primary NOx A less stringent set of limits for NOX which have been set at a level to only require the uptake (if at all) of primary abatement measures have been modelled, for both regulatory options, as a further sensitivity. The ELVs for SO2 and dust are the same as under the IED 50-100 MW scenario.

Gothenburg A variant of the Primary NOx scenario where the ELVs for NOX have been aligned to those set out in the amended Gothenburg Protocol (these affect new “others”). The ELVs for SO2 and PM are the same as under the IED 50-100 MW scenario.

SULES The ELVs for existing plant are as in the Gothenburg scenario, whereas the ELVs for new plant have been set at the level of the most stringent MS existing or future ELV.

Overall assessment framework

A description of the overall assessment framework applied in this study is provided in Section 5. Additional details of the way in which the Gothenburg and SULES scenarios have been assessed are provided in Section 9. This includes a summary of the key input data to the model and a description of the way in which the main outputs (emissions, compliance and administrative costs) have been calculated. Impacts have been assessed using the base 2010 dataset and then projected based on growth factors which have been developed using PRIMES 2012 data on

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fuel consumption per GAINS sector for 2010, 2025 and 2030. Other relevant environmental, economic and social impacts have been assessed in line with the Commission’s Impact Assessment Guidelines and associated guidance and toolkits. All impacts are presented relative to the baseline, which represents existing Member State national legislation targeted at these combustion installations.

Environmental impacts

Sections 6 (Primary NOx, IED 50-100MW and Most Stringent MS scenarios) and 9 (Gothenburg and SULES scenarios) of the report summarises the key environmental impacts identified and assessed during the study focusing on emissions of SO2, NOX and dust

The figures below present the emission forecasts from 1-50 MWth plants for EU27 in 2025 for each ELV option considered in 2025.

Figure 1 SO2 emissions (2025) Figure 2 NOx emissions (2025)

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50

100

150

200

250

300

350

BAU

IED

50-1

00 M

W

Mos

t str

inge

nt M

S

Goth

enbu

rg

SULE

S

2010 2025 2025 2025 2025 2025

(kto

nnes

)

20-50 MW

5-20 MW

1-5 MW

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100

200

300

400

500

600 B

AU

Prim

ary

NO

x

IED

50-

100

MW

Mos

t str

inge

nt M

S

Got

henb

urg

SULE

S

2010 2025 2025 2025 2025 2025 2025

(kto

nn

es)

20-50 MW

5-20 MW

1-5 MW

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Figure 3 Dust emissions(2025)

Economic impacts

The assessment of economic impacts is described in Section 7 of this report. The proposed options to control emissions from combustion plants less than 50 MWth will lead to compliance and administrative costs for operators and competent authorities; these were the main focus of the economic impact assessment. The figures below present the total compliance costs by pollutant and by size category for 2025.

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10

20

30

40

50

60

BAU

IED

50-

100

MW

Mos

t str

inge

nt M

S

Got

henb

urg

SULE

S

2010 2025 2025 2025 2025 2025

(kto

nnes

)

20-50 MW

5-20 MW

1-5 MW

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Figure 4 Total Compliance Costs by pollutant Figure 5 Total Compliance Costs by Size Category

The figure below presents compliance and administrative costs combined for each of the ELV scenarios and regulatory options.

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500

1,000

1,500

2,000

2,500

3,000

3,500

Prim

ary N

Ox

IED

50-1

00 M

W

Mos

t str

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nt M

S

Goth

enbu

rg

SULE

S

2025 2025 2025 2025 2025

(€m

/yea

r)

PM

NOX

SO2

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500

1,000

1,500

2,000

2,500

3,000

3,500

Prim

ary N

Ox

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50-1

00 M

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Goth

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SULE

S

2025 2025 2025 2025 2025

(€m

/yea

r)

20-50 MW

5-20 MW

1-5 MW

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Figure 6 Total Annualised Costs (2025)

In addition to compliance and administrative costs, economic impacts on the following were also assessed: (1) small and medium size enterprises (SMEs); (2) competition; and (3) competitiveness. These are described in Sections 7.3 (and 9.3.3 for the Gothenburg and SULES scenarios), 7.4 and 7.5 of this report, respectively, and summarised briefly below:

• The SME assessment has revealed that a relatively high proportion of 1-50 MWth combustion plants are operated by SMEs. Furthermore, smaller enterprises in particular could be affected most from a financial perspective relative to medium and large enterprises. A number of possible options for mitigating measures are described and discussed in Section 7.3.5 of the report. In addition, for the Gothenburg and SULES scenarios, the modelling has included differentiated ELVs and phased implementation for new and existing plants as well as a low annual operating hour exemption all of which are intended to reduce unnecessary burden on all plants including SMEs. Table 4 below summarises the impact of the options on small and medium enterprises as a proportion of Gross Operating Surplus (GOS).

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500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

Primary NOx IED 50-100 MW

Most stringent MS

Gothenburg SULES Primary NOx IED 50-100 MW

Most stringent MS

Gothenburg SULES

Non-Permitting Permitting

(€m

/yea

r)

ELV scenarioAdmin scenario

Compliance cost 1-5 MW Compliance cost 5-20 MW Compliance cost 20-50 MW

Admin cost 1-5 MW Admin cost 5-20 MW Admin cost 20-50 MW

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Table 4 Total Annual Compliance and Administrative Costs per Enterprise as a Proportion of GOS in 2025 (Average Percentage)

Enterprise Size

ELV option Primary NOx IED 50-100 MWth ELVs

Most stringent MS

Gothenburg SULES

Regulatory option Permit Non-

Permit Permit Non-Permit Permit Non-


Permit

Small 1-5 MWth 1% 0% 2% 3% 3% 3% 1% 0% 1% 1%

5-20 MWth 2% 2% 10% 10% 14% 13% 2% 2% 4% 3%

20-50 MWth 2% 2% 12% 12% 22% 21% 2% 2% 5% 5%

Medium 1-5 MWth 0% 0% 1% 0% 1% 1% 0% 0% 0% 0%

5-20 MWth 0% 0% 2% 2% 3% 3% 0% 0% 1% 1%

20-50 MWth 1% 1% 3% 3% 6% 5% 1% 1% 1% 1%

Note: total annual costs per enterprise consist of annualised compliance costs (i.e. annualised capital costs plus annual operational costs) and annual administrative costs. Administrative costs only include those for operators.

• The overall effect on competition within and between sectors is relatively modest. This is because of the general applicability of the proposed regulation, which brings smaller combustion installations more in line with the requirements already imposed on larger installations. Clearly, the absolute impacts would be influenced by the scale of additional costs associated with a particular option.

• There could be some impact on competitiveness, particularly for the industry, food and – possibly – greenhouse sectors. These sectors face stiff competition from outside the EU. It is likely that at least a sub-set of these users will have difficulty in passing on costs (cost pass through) to their current markets and in the case of greenhouses there are well established competitors ready to compete from outwith the EU. Possible mitigation could focus on actions targeted at the specific sectors most likely to face international competition and are likely to be similar to the measures considered for reducing impacts on SMEs.

Social impacts

The policy options to control emissions from combustion installations <50MWth are likely to result in public health benefits and positive impacts on the level of employment in abatement technology suppliers, while there may be some negative implications for employment in sectors affected by additional compliance and administrative costs.

Public health benefits have not been quantified or assessed within this study as they have been modelled separately as part of the wider modelling exercise for the TSAP Review.

Employment and labour markets impacts are considered in Section 8.3 of this report. Implementation of regulations requiring fitting of abatement technology will lead to costs for the firms affected whilst also representing income for firms that manufacture and install these technologies. The scale of employment effects from proposed regulation can reasonably be expected to be in relation to the overall cost of regulation, and the detailed option chosen i.e. those options imposing the greatest additional costs would be expected to have the greatest impact (both positive and negative effects). The relative scale of combustion plant within the overall operations of the enterprise will have a significant impact on the ability of the enterprise to absorb costs. Moving

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down the plant size categories to the smallest plant (i.e. 1-5MWth) would appear to have the effect of imposing costs on a greater number of smaller enterprises and this is discussed in detail in the SME section.

Comparison of options

The examination of current national legislation in place in the Member States for regulating combustion installations less than 50MWth highlighted that many already regulate these plants to some extent. However, there are a number of Member States who do not regulate these installations and, even for those that do, the level at which any ELVs are set and/or the types and sizes of plants affected varies considerably.

The assessment of possible options for the control of emissions from these plants has shown there is significant potential for emissions reduction of all three pollutants, albeit with varying associated compliance and administrative costs. The table below present a summary of the cost effectiveness of the ELV scenarios for 2025 (calculated as the compliance cost divided by the associated emissions reduction for each pollutant). These costs represent compliance costs; the cost of installing and operating abatement measures targeted at reducing emissions of the corresponding pollutant.

Table 5 Abatement cost (€) per tonne of Pollutant Reduced (2025)

Pollutant ELV options Primary NOX IED 50-100MWth Most stringent MS Gothenburg SULES

SO2 1-5 MW 1,900 1,900 4,100 1,800 2,100

5-20 MW 1,300 1,300 2,100 1,300 1,500

20-50 MW 800 800 1,300 800 900

1-50 MW 1,400 1,400 2,600 1,400 1,500

NOX 1-5 MW 700 7,100 8,400 900 3,200

5-20 MW 400 5,900 6,900 700 2,600

20-50 MW 400 5,700 7,400 600 2,900

1-50 MW 500 6,300 7,600 800 2,900

Dust 1-5 MW 4,100 4,100 5,900 3,700 3,800

5-20 MW 2,300 2,300 4,200 2,200 2,300

20-50 MW 2,300 2,300 5,900 2,100 2,500

1-50 MW 2,900 2,900 5,200 2,500 2,800

As with any study of this nature, there are a number of uncertainties and limitations which should be taken into account when reviewing the results of the assessment. These are described in Section 9.2 disaggregated by those related to the input data itself and those related to the modelling approach.

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Glossary

AT Austria

BAT Best Available Techniques

BDEW German Association of Energy and Water Industries

BE Belgium

BG Bulgaria

BREF BAT reference document

CAPEX Capital costs

CHP Combined Heat and Power

CY Cyprus

CZ Czech Republic

DE Germany

DK Denmark

EE Estonia

EL Greece

ELV Emission limit values

EPPSA European Power Plant Suppliers Association

ES Spain

EU European Union

EU27 27 Member States of the EU1

FGD Flue-gas desulphurisation

FI Finland

FR France

GOS Gross operating surplus

HU Hungary

IA Impact Assessment

IE Ireland

IED Industrial Emissions Directive

IPPC Integrated Pollution Prevention and Control Directive

IT Italy

LT Lithuania

LU Luxembourg

LV Latvia

MS Member State

MT Malta

MWth Mega Watt (rated thermal input)

NL The Netherlands

NOX Nitrogen oxides

OPEX Operational costs

1 Due to the timescales of the study and focus of earlier work on these plants, the scope of the study was limited to the EU27 Member States and Croatia was not included in the analysis.

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PL Poland

PM Particulate matter (dust)

PT Portugal

RO Romania

SBS Structural Business Statistic

SCR Selective catalytic reduction

SE Sweden

SI Slovenia

SK Slovakia

SME Small and medium enterprises

SNCR Selective non-catalytic reduction

SO2 Sulphur dioxide

UK United Kingdom

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Contents

1. Project Understanding 1

1.1 This Report 1 1.2 Project Context 1 1.2.1 IED Background 1 1.2.2 Combustion Installations and Plants less than 50 MWth 2 1.3 Objectives 3 1.4 Structure of this Report 4

2. Data Collection 5

2.1 Overview 5 2.1.1 AMEC (2012) Dataset 5 2.2 Approach to Stakeholder Consultation 6 2.2.1 Member States 6 2.2.2 Other Consultees 6 2.2.3 Status of Data Collection 7 2.3 Summary of Data Gathered 10 2.4 Overview of Current Regulation of Combustion Plants/Installations less than 50 MWth 10 2.4.1 EU Legislation 10 2.4.2 Gothenburg Protocol and Revision 13 2.4.3 Member States’ National Legislation 14

3. Baseline Development 18

3.1 Overview 18 3.2 Gap Filling 18 3.2.1 Adjusting Partially Complete Data Gathered 18 3.2.2 Supplementing with Existing Data 19 3.2.3 Extrapolating to Missing Member States and Capacity Classes 19 3.3 Overview of Resulting EU27 Dataset 24

4. Options for the Possible Control of Emissions from Combustion Installations less than 50 MW 28

4.1 Overview of Options 28 4.2 Business as Usual Emission Levels 29 4.3 EU Wide Scenario Limit Values 32

5. Overall Assessment Framework 37

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5.1 Overview 37 5.2 Compliance Costs 38 5.2.1 Overview 38 5.2.2 Abatement Matrices 38 5.3 Administrative Costs 39 5.3.1 Overview 39 5.3.2 Regulatory Option A (Permitting) 40 5.3.3 Regulatory Option B (Non-Permitting) 43 5.3.4 Key Assumptions 44 5.4 Emissions Reductions 46 5.4.1 Overview 46 5.4.2 Projections 46

6. Environmental Impacts 48

6.1 Overview 48 6.2 Emissions 48 6.2.1 SO2 Emissions 48 6.2.2 NOX Emissions 49 6.2.3 Dust emissions 50 6.3 Changes in Fuel Consumption 51 6.4 Emissions of CO2 52

7. Economic Impacts 53

7.1 Overview 53 7.2 Compliance and Administrative Costs 53 7.2.1 Compliance Costs 53 7.2.2 Administrative Costs 57 7.2.3 Total Costs 58 7.3 SMEs 62 7.3.1 Definitions and the ‘SME’ Test 62 7.3.2 Consultation with SME Representatives 63 7.3.3 Preliminary Assessment of Businesses likely to be affected 63 7.3.4 Measurement of the Impact on SMEs 66 7.3.5 Assessment of Alternative Options and Mitigating Measures 69 7.4 Competition 71 7.4.1 Defining Competition Effects 71 7.4.2 Rules on Liberalisation 71 7.4.3 Measures Raising or Lowering the Barriers to Entry or Exit 71

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7.4.4 Rules Introducing Special Commercial Rights 72 7.4.5 Sectoral Rules 72 7.4.6 General Rules 72 7.4.7 Analysis of Market Sectors 72 7.4.8 Analysis of Member State Impacts 73 7.4.9 Analysis of Supply of Abatement Technology 75 7.4.10 Conclusions 75 7.5 Competitiveness, Trade and Investment Flows 76 7.5.1 Definitions and the Testing Competitiveness, Trade and Investment Effects 76 7.5.2 Differences between the Regulatory Regime faced by EU Companies and Competitors in Non-EU

Countries 76 7.5.3 EU firms compared to their International Competitors 77 7.5.4 Relocation of Economic Activity to or from Non-EU Countries 77 7.5.5 Boost cleaner Companies and Sectors either Directly or Indirectly through Shift of Demand Away from

Polluting Companies and Sectors 78 7.5.6 Help or Hinder Trade and Cross-border Investment into the EU or from the EU to Third Countries 78 7.5.7 Have an Impact on WTO Obligations of the Community 78 7.5.8 Generate a ‘First-mover’ Advantage with Other Countries likely to follow 78 7.5.9 Sector Specific Analysis 78 7.5.10 Conclusions 93

8. Social Impacts 94

8.1 Overview 94 8.2 Public Health Benefits 94 8.3 Employment and Labour Markets 94

9. Additional modelling support 96

9.1 Overview 96 9.2 Approach 97 9.2.1 Baseline 97 9.2.2 Costs 98 9.2.3 Scenarios 98 9.2.4 SME impacts 99 9.3 Results 99 9.3.1 Emissions 100 9.3.2 Compliance costs 101 9.3.3 SME impacts 105

10. Discussion 106

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10.1 Overview 106 10.2 Comparison of options 112 10.3 Uncertainties and Limitations 115

11. References 118

11.1 Overview 1 11.2 Literature review 1 11.2.1 Definition of efficiency 1 11.2.2 LCP BREF 1 11.2.3 Commission Decision 2011/877/EU 6 11.2.4 EU ETS 7 11.2.5 Energy Efficiency Directive 9 11.2.6 JRC report - Best available technologies for the heat and cooling market in the European Union 10 11.2.7 JRC report – Small combustion installations: Techniques, emissions and measures for emission reduction11 11.2.8 US EPA national emission standards for hazardous air pollutants for major sources: Industrial,

commercial and institutional boilers and process heaters 11 11.2.9 US EPA – Climate leaders greenhouse gas inventory protocol, Offset project methodology for project

type: Industrial Boiler Efficiency 12 11.2.10 Environment Agency and DECC - EU emissions trading system: Benchmarking as an allocation

methodology for heat from 2013 13 11.2.11 IPCC- Climate change 2007: Working Group III: Mitigation of climate change 13 11.2.12 Measures to improve efficiency of combustion units 14 11.3 Legislation review 14 11.4 Consultation 16 11.5 Conclusions 19

Table 1 Summary of EU27 Dataset ii Table 2 Overview of Regulatory Options ii Table 3 Overview of ELV Options iii Table 4 Total Annual Compliance and Administrative Costs per Enterprise as a Proportion of GOS in 2025 (Average

Percentage) viii Table 5 Abatement cost (€) per tonne of Pollutant Reduced (2025) ix Table 2.1 Summary of the Information Provided by other Consultees 6 Table 2.2 Overview of data received from Member States (including data provided during consultation for AMEC 2012) 9 Table 2.3 Summary of EU Level Policies other than IED with Implications for Combustion Installations less than 50 MWth 11 Table 2.4 Summary of National Legislation Regulating Combustion Plants less than 50 MWth. 15 Table 3.1 Assumed Average Capacity per Plant 19 Table 3.2 Ratio of Numbers of Plants at each Capacity Class 20 Table 3.3 Assumed Sectoral Distribution 21 Table 3.4 Ratio of Capacity of Plants at each Capacity Class 21 Table 3.5 Average Load Factors for Each Capacity Class 22 Table 3.6 Specific Flue Gas Volumes Assumed in this Study 23 Table 3.7 Proportion of Reported Combustion Plants below 50MWth that are considered to be covered by the IED as Directly

Associated Activities 24 Table 3.8 Summary of EU27 Dataset 24 Table 4.1 Overview of Regulatory Options 28 Table 4.2 Overview of ELV Options 28

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Table 4.3 General Case Emission Levels (applied in the absence of Member State-Specific ELVs) 31 Table 4.4 EU Wide ELVs applied in this Study for most Stringent Member State Option 33 Table 4.5 EU Wide ELVs applied in this Study for IED 50-100MWth Option 34 Table 4.6 EU Wide ELVs applied in this Study for Primary NOx Option 35 Table 4.7 Reference Exhaust Oxygen Content 35 Table 5.1 Summary of Assessment Framework 37 Table 5.2 Regulatory Option A (Permitting): Costs applied for Calculating the Administrative Costs for Operators and

Authorities (High scenario, assuming public participation) 41 Table 5.3 Regulatory Option B (Non-Permitting): costs applied for calculating the administrative costs for operators and

authorities (High scenario assuming notification) 44 Table 5.4 Different Components of Administrative Costs included in the Assessment 45 Table 6.1 SO2 Emissions (ktonnes) 48 Table 6.2 NOX Emissions (ktonnes) 49 Table 6.3 Dust Emissions (ktonnes) 51 Table 6.4 Changes in Fuel Consumption 52 Table 6.5 Total CO2 Emission Reductions (kt) by Policy Option 52 Table 7.1 Typical Techniques assumed to be applied to meet the Hypothetical EU-Wide ELVs for Plants Modelled as having

Emission Levels exceeding the Limits 53 Table 7.2 Average total Annualised Compliance Costs (€m/year) 54 Table 7.3 Annualised Administrative Costs for Operators and Authorities under Regulatory Option A (Permitting) and B (Non-

Permitting), including Monitoring Survey Costs (€m per year, 2012 prices, figures rounded for presentation purposes) 57

Table 7.4 Annualised Administrative Costs for Operators and Authorities under Regulatory Option A (Permitting) and B (Non-Permitting), excluding Monitoring Survey Costs (€m per year, 2012 prices, figures rounded for presentation purposes) 58

Table 7.5 Total Annualised Costs (€m/year, Figures Rounded for Presentation Purposes) 59 Table 7.6 Total Costs per Plant (€/year, figures rounded for presentation purpose) 61 Table 7.7 Definition of SME 62 Table 7.8 Enterprise Size Categories per Sector in 2010 for EU27 63 Table 7.9 Enterprise Size Categories per Sector and Number of SMEs per Combustion Plant Capacity Categories assumed

for the Analysis 65 Table 7.10 Weighted Average Gross Operating Surplus (GOS) per Enterprise by Capacity and by Size Category (€ per

Operator) in 2010 for EU-27 67 Table 7.11 Total Annual Compliance and Administrative Costs per Enterprise as a Proportion of GOS in 2025 (Average

Percentage) 68 Table 7.12 Potential Mitigation Measures 69 Table 7.13 Turnover by “Sector” by Scale (Number of Employees) 73 Table 7.14 Exposure to International Competition 77 Table 7.15 Analysis of the Average Gross Operating Surplus (GOS) per Sector 79 Table 7.16 EU Refineries by Region, by Number and Capacity 92 Table 8.1 Employment on Key Economic Sectors at NACE Level 2 (Eurostat) 95 Table 9.1 General Case Emission Levels (applied in the absence of Member State-Specific ELVs) 97 Table 9.2 Overview of ELV Options 98 Table 9.3 Revised Most Stringent Member State ELVs used in the SULES Option 99 Table 9.4 SO2 Emissions (ktonnes) 100 Table 9.5 NOX Emissions (ktonnes) 100 Table 9.6 Dust Emissions (ktonnes) 100 Table 9.7 Average total annualised compliance costs (€m/year) 101 Table 9.8 Average total annualised compliance costs disaggregated by new and existing plants and by plant type for 2025

(€m/year) 103 Table 9.9 Average total annualised compliance costs per plant in 2025 (€/plant) 104 Table 9.10 Total Annual Compliance and Administrative Costs per Enterprise as a Proportion of GOS in 2025 (Average

Percentage) 105 Table 10.1 SO2, NOx and Dust Emissions (ktonnes) 107 Table 10.2 Average total annualised compliance costs for 2025 (€m/year) 109 Table 10.3 Total Annualised Costs for 2025 (€m/year, Figures Rounded for Presentation Purposes) 110 Table 10.4 Total Annual Compliance and Administrative Costs per Enterprise as a Proportion of GOS in 2025 (Average

Percentage) 111 Table 10.5 Emission reduction compared to baseline for 2025 (kt/year) 112 Table 10.6 Abatement cost (€) per tonne of Pollutant Reduced (2025) 112 Table 11.1 Thermal efficiencies of gas-fired power plants 2 Table 11.2 Levels of thermal efficiency associated with the application of BAT measures for coal and lignite fired combustion

plants 4 Table 11.3 Levels of thermal efficiency associated with the application of BAT measures for peat and biomass fired combustion

plants 4 Table 11.4 Efficiency of gas-fired combustion plants associated with the application of BAT 4 Table 11.5 Harmonised efficiency reference values for separate production of electricity according to Commission

Implementing Decision 2011/877/EU 6

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Table 11.6 Harmonised efficiency reference values for separate production of heat (%) 7 Table 11.7 Efficiencies reported in the impact assessment accompanying the Commission Decision on determining the rules for

harmonised free allocations 8 Table 11.8 Typical efficiencies of industrial CHP installations 9 Table 11.9 Efficiency of industrial boilers by type of fuel 10 Table 11.10 Industrial Boiler Efficiency and Emissions with Optional Components 12 Table 11.11 GHG emission reduction measures with relevant efficiency improvement 14 Table 11.12 Emissions limit values and thermal efficiency for stationary combustion sources – proposed for revision of Clean Air

Act No.309/1991Coll for new plants (in Ng/m3) 15 Table 11.13 Minimum efficiency coefficient for fuels 15 Table 11.14 Emission limit values and minimum degrees of efficiency for single room firing installations for solid fuels

(requirements for the type test) in Germany 16 Table 11.15 Overview of the consultees and information received 16

Figure 1 SO2 emissions (2025) iv Figure 2 NOx emissions (2025) iv Figure 3 Dust emissions(2025) v Figure 4 Total Compliance Costs by pollutant vi Figure 5 Total Compliance Costs by Size Category vi Figure 6 Total Annualised Costs (2025) vii Figure 1.1 Schematic of (A) Boilers Exhausting via (B) Flues in a (C) Common Stack 2 Figure 3.1 Number of Plants per Capacity Class in each Member States 26 Figure 3.2 Total Capacity in MWth per Capacity Class in each Member State 26 Figure 3.3 EU27 Fuel Consumption per Capacity Class 27 Figure 3.4 EU27 Emissions per Capacity Class 27 Figure 6.1 SO2 Emission Projections to 2030 49 Figure 6.2 NOx Emission Projections to 2030 50 Figure 6.3 Dust Emission Projections to 2030 51 Figure 7.1 Compliance Costs (SO2) 55 Figure 7.2 Compliance Costs (NOX) 55 Figure 7.3 Compliance Costs (dust) 56 Figure 7.4 Total Compliance Costs by Size Category 56 Figure 7.5 Total Compliance Costs by Pollutant 56 Figure 7.6 Total Annualised Costs in 2025 60 Figure 7.7 Average Annual Cost per Plant for each MS in 2025 (€k per Plant per Year) 74 Figure 7.8 Trade Balance of Live Plants and Products of Floriculture, 2012 (€k) 81 Figure 7.9 Average Growth of Production Value per Year, Producer Price (Fruits and Vegetables, 2001-2009)14 82 Figure 7.10 Share of Fruit and Vegetables in Regional Agricultural Production 83 Figure 7.11 EU27 Imports of Steel 85 Figure 7.12 EU27 Exports of Steel 86 Figure 7.13 EU27 Chemicals Sector Trade Balance 88 Figure 7.14 Evolution of EU Net Imports in Key Petroleum Products, 2000-2008 89 Figure 7.15 EU Refinery Margins for Eight Combinations of Region, Crude Feedstock and refining Process (in $/bbl) 90 Figure 7.16 EU Refinery Margins, Cracking and Hydroskimming Averages and Linear Trends (in $/bbl) 91 Figure 7.17 EU27 Refineries Numbers and Capacity, in Million Tonnes per Year, by Member State 92 Figure 9.1 Year on year emission reductions for new and existing plant under Gothenburg scenario 101 Figure 9.2 Year on year compliance costs for new and existing plant under Gothenburg scenario 102 Figure 10.1 SO2 emissions (2025) 106 Figure 10.2 NOx emissions (2025) 106 Figure 10.3 Dust emissions(2025) 107 Figure 10.4 Total Compliance Costs by pollutant 108 Figure 10.5 Total Compliance Costs by Size Category 108 Figure 10.6 Total Annualised Costs (2025) 110 Figure 10.7 Costs of achieving SO2 reduction in 2025 (€/tonne) 113 Figure 10.8 Costs of achieving NOX reduction in 2025 (€/tonne) 114 Figure 10.9 Costs of Achieving Dust Reduction in 2025 (€/tonne) 114

Appendix A Abatement Matrices Appendix B Emissions by MS Appendix C Costs by Member State Appendix D Summary of Information Received by MS Appendix E Collated Member State Data Appendix F Adjustments made to Data provided by Member States Appendix G Energy Efficiency

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1. Project Understanding

1.1 This Report AMEC Environment and Infrastructure UK Limited (‘AMEC’) were contracted by the Commission to undertake the following study: “Analysis of the impacts of various options to control emissions from the combustion of fuels in installations with a total rated thermal input below 50 MW”.

This final report provides a summary of the additional data that was gathered from the Member States and industry and the main findings of the analysis. This includes the development and final composition of the EU27 database of combustion installations less than 50 MWth, the options considered and associated compliance and administrative costs and emission reductions. The report has been updated (September 2013) to include the results of some additional modelling undertaken by AMEC to support the Commission’s development of a draft Impact Assessment of proposals to control emissions from these installations. This additional modelling has been undertaken as part of a follow on contract to the main study and is therefore reported here for consistency.

1.2 Project Context

1.2.1 IED Background

Directive 2010/75/EU on industrial emissions was formally adopted on 24 November 2010 and published in the Official Journal on 17 December 2010. It entered into force on 6 January 2011.

The Directive places a number of requirements on the European Commission to undertake additional actions. The key requirements from the IED of relevance to this study on combustion installations with a rated thermal input below 50 MWth are:

Recital (28)

The combustion of fuel in installations with a total rated thermal input below 50 MW contributes significantly to emissions of pollutants into the air. With a view to meeting the objectives set out in the Thematic Strategy on Air Pollution, it is necessary for the Commission to review the need to establish the most suitable controls on emissions from such installations. That review should take into account the specificities of combustion plants used in healthcare facilities, in particular with regard to their exceptional use in the case of emergencies.

and

Article 73 Review

2. The Commission shall by 31 December 2012, review the need to control emissions from:

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(a) the combustion of fuels in installations with a total rated thermal input below 50 MW;

The Commission shall report the results of that review to the European Parliament and to the Council accompanied by a legislative proposal where appropriate.

On 17 May 2013, the Commission adopted a Report to the European Parliament and the Council on this review2, in which it concluded that a clear potential for cost-effective abatement of air emissions from medium combustion plants was demonstrated. Furthermore, it announced that that as a next step options for potential regulatory action would be further assessed in an impact assessment supporting the review of the Thematic Strategy on Air Pollution.

1.2.2 Combustion Installations and Plants less than 50 MWth

It is important to make clear the distinction between a combustion plant and a combustion installation before describing further the legislative requirements in place. A combustion plant is considered under the IED as being defined with the ‘common stack’ approach, i.e. that one chimney or stack (regardless of the number of flues contained therein) is one ‘plant’. Individual combustion units will discharge exhaust gases via flues that are contained within the chimney. The figure below represents these three levels of aggregation. A combustion installation (as defined in the IED) is a site on which there may be multiple combustion plants (i.e. stacks) for one industrial complex.

Figure 1.1 Schematic of (A) Boilers Exhausting via (B) Flues in a (C) Common Stack

2 Report from the Commission on the reviews undertaken under Article 30(9) and Article 73 of Directive 2010/75/EU on industrial emissions addressing emissions from intensive livestock rearing and combustion plants (COM(2013)286final, 17.5.2013)

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The IED regulates combustion installations and plants through the following provisions:

• Article 3 of the IED defines an installation as including “any other directly associated activities on the same site which have a technical connection with the activities listed in those Annexes and which could have an effect on emissions and pollution”;

• Article 10 of the IED sets the scope of coverage of Chapter II of the IED to the activities listed in Annex I. The relevant combustion activity is “1.1. Combustion of fuels in installations with a total rated thermal input of 50 MW or more” i.e. the provisions of Chapter II of the IED (permitting, permit conditions, monitoring, BREFs, BAT) apply to combustion installations ≥50 MWth.;

• Chapter III (and the associated Annex V) of the IED has its scope set out in Article 28 which states that it applies to “combustion plants, the total rated thermal input of which is equal to or greater than 50 MW”. Article 29 defines the aggregation rules ("common stack" and "de minimis" approaches), which are to be applied for the purpose of Chapter III.

In terms of combustion plants ("common stack" level) less than 50 MWth, Chapter II of the IED will regulate such plants in two instances:

i. In the case of combustion installations with a total rated thermal input equal to or greater than 50 MW also containing combustion plants less than 50 MWth.

ii. In the case of an installation operating an activity listed in Annex I, to which a combustion plant of less than 50 MW operated on the same site is directly associated and has a technical connection (see definition of "installation" in IED article 3(3).

It should be noted that combustion plants ("common stack" level) of less than 50 MWth are not regulated under Chapter III, while combustion units of less than 50 MWth being part of a combustion plant of 50 MWth or more may be.

1.3 Objectives A lot of work has already been undertaken looking at installations less than 50 MWth as well as the development of product standards for a range of different products. The overall objectives of this contract were to build on this work with the aim of providing the Commission with:

an in-depth comprehensive assessment of the environmental, economic and social impacts of a number of defined options to control emissions (of SO2, NOX and dust as well as other relevant pollutants) from the combustion of fuels with a total rated thermal input below 50 MW.

This should enable the Commission to develop an impact assessment (IA, in line with the relevant guidelines) and provide the evidence to enable a decision to be made on a preferred option. The outputs of this study will feed into the overall IA planned for the review of the Thematic Strategy on Air Pollution in 2013.

The study should build on the data gathered previously but supplement it with new information available from a targeted consultation with key stakeholders including Member States, industry representatives, equipment

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manufacturers/suppliers and other relevant experts. This data gathering focussed on the key gaps identified in the recent study.

The analysis looked at a range of options disaggregating impacts between the same capacity classes as the previous AMEC (2012) study (described below, <5, 5 to <20 and 20 to 50 MWth). Domestic heating appliances with a thermal input of less than 500 kW were excluded.

1.4 Structure of this Report This report is structured as follows:

• Section 2 of this report describes the approaches for data collection;

• Section 3 describes the development of the baseline for the study including the approaches employed for gap filling;

• Section 4 describes the options developed for the control of emissions from combustion installations less than 50 MWth;

• Section 5 describes the overall assessment framework applied in the study;

• Section 6 describes the main environmental impacts associated with the options;

• Section 7 describes the main economic impacts associated with the options;

• Section 8 describes the main social impacts associated with the options;

• Section 9 describes the findings of the additional modelling undertaken as part of a follow on contract;

• Section 10 presents the overall summary for the study as well as the key uncertainties and limitations;

• Appendix A presents the abatement matrices applied in the study;

• Appendix B presents emissions by Member State for each option;

• Appendix C presents costs by Member State for each option;

• Appendix D presents a summary of the responses received from Member States during the consultation;

• Appendix E presents a collated summary of the numerical data returned by Member States during this and the AMEC (2012) study;

• Appendix F presents the adjustments made to data provided by Member States.

• Appendix G presents a summary of the research undertaken looking at energy efficiency of these plants.

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2. Data Collection

2.1 Overview The study aimed at gathering additional new data on combustion installations less than 50 MWth to support the analysis of possible options to control emissions from this sector at an EU level. Due to the work previously undertaken on this subject (AMEC, 2012), a dataset was already available. In this study, we have focused on improving the existing dataset with new or additional data from Member States.

This chapter summarises the status and the process of collection of information from Member States on the following, in relation to combustion plants <50 MWth:

• Numbers;

• Capacity;

• Technology type (boilers, engines, turbines and others);

• Sectoral distribution;

• Fuel consumption;

• Emissions;

• Abatement measures;

• Legislation currently in place, including information on product standards.

2.1.1 AMEC (2012) Dataset

As part of the AMEC (2012) study, data on combustion plants less than 50 MWth was gathered directly from the Member States. This included data on numbers, capacities, fuel consumption and emissions from the plants, as well as information on relevant national legislation (where applicable), combustion techniques used, abatement measures typically applied, and the degree to which the combustion plants may already be regulated under the IED as directly associated activities.

Where necessary (and possible), the data gathered were supplemented with data from a range of existing sources and studies. From these data, an EU wide dataset of combustion plants of capacities between 1MWth and 50 MWth was developed through use of extrapolation and other assumptions in an attempt to compile a sufficiently complete dataset with which to assess possible control options. This gap filling was necessary as there were a number of significant data gaps that remained following the consultation with Member States that would have made it impossible to undertake an EU level analysis. The dataset was separated into three capacity classes of rated thermal inputs 1-5 MW, 5-20 MW and 20-50 MW.

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A number of assumptions were made in extrapolating data to be considered representative of the EU27, which has led to a number of uncertainties and limitations in the underlying dataset (as described in AMEC, 2012) which must be considered when assessing the results of the assessment of control options. The report recommended that, considering these limitations, additional work should be undertaken to improve data capture on the combustion plants, in particular for the smallest capacity class 1 to 5 MWth (hence this study).

2.2 Approach to Stakeholder Consultation

2.2.1 Member States

All Member States have been consulted as part of this study. The consultation involved the development of a data collection spreadsheet that was distributed to all Member States. Follow-up communications by email and telephone were made with the Member State representatives by AMEC. The data collection spreadsheet included the existing dataset that was developed as part of the AMEC (2012) study. Member States were asked to update the information relevant to their country and to provide feedback on the gap-filling techniques and assumptions that were applied in the previous report.

2.2.2 Other Consultees

The consultation with stakeholders other than Member States focussed on gathering the views of a selection of European-wide trade associations. Information and comments on the previous report and aims of the new study were received from BDEW, Eurelectrics, Euromot, EPPSA, EU Turbines and Orgalime. A short summary of the comments received is included in the table below.

Table 2.1 Summary of the Information Provided by other Consultees

Industry Association Main Comments provided

BDEW (German Association of Energy and Water Industries)

Comment on the assumption that all gaseous and liquid-fuel fired combustion plants are boilers can distort significantly the pursued cost-benefit-analysis with respect to the administrative costs, applicable ELVs, abatement cost and resulting emissions. Comment on the estimation of administrative costs illustrated by the German example. Comment on the estimation of abatement costs that in their view do not take into account factors such as the existence of different units, stacks and plants types. Comment on the derogation and specifications of the IED, that in their view have not been taken into account in the cost-benefit analysis.

EPPSA (European Power Plant Suppliers Association)

Information on CAPEX and OPEX for different abatement techniques (dry FGD, SNCR and SCR) and their associated emission reductions

Eurelectric Comments on the estimation of administrative costs that does not seem to include some elements. Comment on the derogation and specifications of the IED, that in their view have not been taken into account in the cost-benefit analysis. Comment on the ‘do nothing’ option that was used to compared other options against. They recommended the use of a ‘business as usual’ option which would be consistent with the existing legislation and associated co-benefits and drawbacks of climate policy on community level.

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Industry Association Main Comments provided

Euromot Comments on pollutants and abatement techniques and associated BAT. Comment on the derogation allowed by Gothenburg Protocol that in their view are not taken into account.

EU Turbines Information on number of turbines and fuel use. Information provided on NOx and CO emissions. Comment that the majority of turbines are natural gas fired, the main abatement techniques are DLE, SCR, CO oxidation catalyst.

Orgalime Comment on administrative burden and expected negative impacts on competitiveness from the regulation of small combustion plants at EU level.

As part of the additional modelling follow on contract, we also held follow-up discussions with a number of the trade bodies consulted as part of the main contract as well as other trade bodies and combustion unit manufacturers. Due to the limited time of the consultation period, only limited information was received mainly from the Association of European Heating Industry (EHI).

2.2.3 Status of Data Collection

Overview

The consultation with Member States provided additional data to fill some of the gaps that were identified in the previous study. In particular new data were provided from Denmark, Hungary, Latvia and Malta. These Member States did not submit information during the previous consultation exercise. A response was also received from Austria, Belgium, Cyprus, Czech Republic, Estonia, Finland, France, Germany, the Netherlands, Poland, Slovakia, Sweden and the United Kingdom. For Germany, information provided by BDEW was used to supplement information provided by the national authority. As part of the additional modelling follow-on contract, the Netherlands also provided additional information regarding various studies that had been completed reviewing various aspects of their own legislation targeted at these combustion installations.

Although more complete than the dataset compiled for the previous study, there are still gaps remaining. In particular no data has been provided for Bulgaria, Greece, Lithuania, Luxembourg and Portugal. Italy, Ireland and Slovenia indicated to not be in a position to submit any new information. Spain and the United Kingdom each provided information for only one region and Romania only commented on the terms of reference of this project issued by the Commission.

A table summarising the data that Member States have provided in relation to key parameters such as number of plants, capacities, technology, sectoral distribution and legislative requirements is presented below. Note that the table includes data submitted during the consultation for AMEC 2012) and data that were gathered through the review of reports available. This table provides an overview of the data available for each Member State using a ‘traffic light’ system to assess the data for each parameter, according to the following key.

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Full dataset on this parameter provided by Member State

Some data concerning this parameter provided by Member State

No data on this key parameter provided by Member State

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Table 2.2 Overview of data received from Member States (including data provided during consultation for AMEC 2012)

Data Requested MWth AT BE BG CY CZ DE DK EE EL ES FI FR HU IE IT LT LU LV MT NL PL PT RO SE SI SK UK

Number of combustion plants 1-5

5-20

20-50

Capacity (MWth) 1-5

5-20

20-50

Technology types used 1-5

5-20

20-50

Sectoral distribution 1-5

5-20

20-50

Fuel consumption split by fuel type 1-5

5-20

20-50

Emissions of key pollutants - quantities

1-5

5-20

20-50

Existing coverage as directly associated activities

1-5

5-20

20-50

Legislative requirements

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2.3 Summary of Data Gathered A summary of the data gathered from each Member State is provided on a Member State basis in the appendices. This includes the data returned by Member State for this study (Appendix D) as well as a summary of all of the data returned for each Member State during this and AMEC (2012) (Appendix E). This summary includes a high level indication of the completeness and/or quality of the data utilising the following traffic light colour coding:

The data appear complete, i.e. they represent the entire capacity class with no known omissions

The data appear to be partially complete and not fully representative, e.g. they are known to exclude certain plants

The data appear to be extremely limited, i.e. it is not possible to extrapolate complete data from them

2.4 Overview of Current Regulation of Combustion Plants/Installations less than 50 MWth

2.4.1 EU Legislation

The table below (Table 2.3) provides a summary of some of the key EU legislation other than the IED that could affect combustion plants less than 50 MWth.

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Table 2.3 Summary of EU Level Policies other than IED with Implications for Combustion Installations less than 50 MWth

Policy Summary Relevant Scope

Relevant Timescales

Requirements Implication for Business as usual Trends of Combustion Plants below 50 MWth

EU ETS Directive (2003/87/EC) as amended by Directive 2009/29/EC

GHG emissions trading scheme for the largest emitting industrial sectors.

Installations >20 MWth in any sector (aggregation rules exclude combustion units <3MWth and units which exclusively use biomass).

Phase II currently in force. Phase III (2013-2020) will significantly restrict the allocation of free allowances.

Submit allowances to cover GHG emissions.

Increases financial incentives for installations to invest in GHG abatement measures. This will - Encourage more efficient combustion plants; - Encourage fuel-switching to natural gas and biomass / other biofuels.

Renewable Energy Directive 2009/28/EC

Directive 2009/28/EC establishes a common framework for the production and promotion of energy from renewable sources. Introduces national targets for the share of energy produced from renewable sources.

Targets are set at Member State level and implicitly include combustion plants <50 MWth.

Targets are set for 2020. No direct requirements for individual installations.

- Reduce the number of combustion plants below 50 MW due to encouragement of generation from non-combustion renewable sources. Subsequent reduction in fuel consumption and emissions. - Increase in uptake of biomass, biofuel and biogas (either for new installations or fuel switching at existing plants). The impact on emissions to air will depend on the fuel types being switched from/to.

Effort Sharing Decision 406/2009/EC

Establishes binding national GHG emissions targets for non-ETS sectors (relevant examples: buildings, agriculture).

Targets are set at Member State level and implicitly include combustion plants <50 MWth.

Targets are set for the period 2013-2020.

No direct requirements for individual installations.

More efficient heating systems will be encouraged. Increased uptake of renewable fuels.

CHP Directive 2004/8/EC

Promotes cogeneration based on useful heat demand.

All CHP plants (and all plants which could be converted to CHP).

Implemented in 2004. Encourages the introduction of subsidies and removal of barriers for cogeneration at a Member State level.

Increase the number of CHP SCPs. Increase combustion efficiency, reducing fuel consumption and emissions.

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Policy Summary Relevant Scope

Relevant Timescales

Requirements Implication for Business as usual Trends of Combustion Plants below 50 MWth

Eco-Design of Energy Using Products Directive 2009/125/EC

Provides consistent EU-wide rules for improving the environmental performance of energy related products (ERPs) through ecodesign. Described in more detail in product related option section

Energy-using products (EUPs), which use, generate, transfer or measure energy, such as boilers.

Preparatory studies on different product groups are produced over time. The boilers preparatory study was finalised in 2007.

Encourage the selection of more efficient EUPs.

Considered to be small as the largest category of boiler considered in the preparatory study (2007) was <1MW. The Ecodesign Directive by itself does not provide binding requirements for specific products, but provides the framework and defines conditions and criteria for introducing directly binding requirements (Implementing Measures). Steam boilers below 50 MWth have been included in the Second working plan, which identify priority energy-using products for which implementing measures need to be adopted.

Energy Efficiency Directive 2012/27/EC

Establishes a common framework of measures for the promotion of energy efficiency within the Union to ensure the achievement of the Union’s 2020 20 % headline target on energy efficiency and to pave the way for further energy efficiency improvements beyond that date.

Member States are expected to develop a Roadmap by 2015 on efficient use of buildings, including commercial, public and private households

To be implemented by April 2013

No direct requirement yet

No implication yet, the content of the Roadmap may affect the number of combustion plants below 50 MWth

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2.4.2 Gothenburg Protocol and Revision

The 1979 Convention on Long-Range Transboundary Air Pollution, was established within the framework of the United Nations Economic Commission for Europe (UNECE), entered force in 1983 and has since been extended by eight specific protocols. The most recent protocol3, is commonly referred to as the Gothenburg protocol and entered force in 2005.

In June 2012, agreement was reached in revising the Gothenburg Protocol. Certain aspects of the revision widen the Protocol’s scope in relation to combustion plants less than 50 MWth. The elements of the newly revised protocol which are relevant to combustion plants between 1 MWth and 50 MWth can be summarised as follows:

• Annex II sets national SO2, NOX, NH3 and VOC emissions ceilings for 2010 until 2020 and emission reduction commitments (additionally for PM2.5) for 2020 and beyond for signatories to the protocol. These ceilings and reduction commitments are not sector specific but may influence the need to control emissions from combustion plants between 1 MWth and 50 MWth;

• Annexes IV, V, VI and X (new) specify limit values for emissions of sulphur, nitrogen oxides, volatile organic compounds and particulate matter respectively from stationary sources. For combustion plants with a rated thermal input between 1 MWth and 50 MWth, the following provisions are relevant:

- Annex IV (SO2): limit for sulphur content of gas oil at <0.1% by January 2008;

- Annex V (NOx): limit values for new stationary engines which run for more than 500 hours per year, differentiated by fuel, size and combustion type, as follows: specifically for gas engines and dual fuel engines greater than 1MWth, and diesel engines greater than 5 MWth;

Gas (Otto) engines >1MWth 95-190 mg NOx/Nm3

Dual-fuel engines (in gaseous mode) >1MWth 190 mg NOx/Nm3

Dual-fuel engines (liquid mode): 1-20 MWth and >20 MWth 225 mg NOx/Nm3

Slow / medium speed (<1,200 rpm) diesel engines (heavy fuel oil and bio-oils)

5-20 MWth 225 mg NOx/Nm3

>20 MWth 190 mg NOx/Nm3

Slow / medium speed (<1,200 rpm) diesel engines (light fuel oil and natural gas)

>5 MWth 190 mg NOX/Nm3

All high speed (>1,200 rpm) diesel engines 190 mg NOX/Nm3

- Annex X (particulate matter): recommended but not binding dust limit values for solid and liquid fuel-fired boilers and process heaters with rated thermal input from 1 MWth to 50 MWth

3 ‘Protocol to the 1979 Convention on long-range transboundary air pollution to abate acidification, eutrophication and ground-level ozone’. Available from: http://www.unece.org/fileadmin/DAM/env/lrtap/full%20text/1999%20Multi.E.Amended.2005.pdf

http://www.unece.org/fileadmin/DAM/env/lrtap/full%20text/1999%20Multi.E.Amended.2005.pdf

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New solid and liquid fired >1-50 MWth 20 mg dust/m3

Existing solid and liquid fired >1-5 MWth 50 mg dust/m3

>5-50 MWth 30 mg dust/m3

• In addition, these limit values are not the only option for compliance; new stationary sources may alternatively ‘apply different emission reduction strategies that achieve equivalent overall emission levels for all source categories together’;

• A provision to review an evaluation of mitigation measures for black carbon emissions;

• Lastly, the protocol states, ‘Each Party should apply best available techniques (…) to each stationary source covered by annexes IV, V, VI and X, and, as it considers appropriate, measures to control black carbon as a component of particulate matter, taking into account guidance adopted by the Executive Body’.

2.4.3 Member States’ National Legislation

The table below (Table 2.4) summarises information gathered on Member States national legislation concerning combustion installations with a rated thermal input less than 50 MWth. The table is based on information received during AMEC (2012) study on Member States’ national legislation and has been updated with any further information submitted by Member States during the consultation for this study. This information has been used in this study to help develop possible options for the control of emissions from these plants as well as to understand which plants may already be able to meet any minimum ELVs if they were to be set at an EU level. When we identified gaps or incomplete information was provided, some assumptions and generalisations have been applied as follow:

• Austria’s legislation requires continuous monitoring except for ‘exceptions’ which we assumed to be smaller combustion units (i.e. <5MWth);

• For Belgium, it was assumed that the Walloon Region was similar to Bruxelles and the Flanders Regions;

• Spain sets requirements at the autonomous community level, it was assumed for this Member State that no general permitting or monitoring requirements were in place;

• Monitoring requirements in Ireland and Sweden are site specific; monitoring every three years was taken as the assumption;

• In the Netherlands monitoring is required once ELVs have entered into force and then every four years;

• Some Member States did not provide information on these specific points (i.e. legislation, permitting and monitoring) so for them it was assumed that no permitting or monitoring requirements were in place;

• No distinction is made between boilers and others.

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Table 2.4 Summary of National Legislation Regulating Combustion Plants less than 50 MWth.

Member State

Legislation Legislation Scope

Includes ELVs?

Permit required?

Specific Monitoring requirements?

Austria BGBI.II Nr. 312/2011 concerning furnaces which are not steam boilers and BGBI Nr.19/1989 idf. BGBL. II Nr. 153/2011 concerning steam boilers and gas turbines <50 MW.

Yes

Yes

No Continuous monitoring, every three years for ‘exceptions’

Belgium - Flanders

VLAREM II (Order of the Flemish Government of 1 June 1995 concerning General and Sectoral provisions relating to Environmental Safety). Legislative requirements for combustion installations are described in chapter 43 and for stationary engines in chapter 31 of VLAREM II.

Yes

Yes

Yes

Continuous for bigger plants (20-50 MWth), for others twice per year

Belgium – Brussels

‘Ordonnance relative au permis d'environnement (1997)’ http://www.ejustice.just.fgov.be/cgi_loi/change_lg.pl?language=fr&la=F&cn=1997060533&table_name=loi

‘Arrêté Chaudière’ (on permitting)

Yes

Not known Yes for 5-50 MWth

Not known

Belgium - Walloonia

No information received

Bulgaria No information received

Cyprus The Control of Atmospheric Pollution (Non Licensable Installations) Regulation of 2004 (P.I. 170/2004)» and «The Control of Atmospheric Pollution (Non Licensable Installations) (Amendment) Regulations of 2008 (P.I. 198/2008)

Yes

Yes

No Continuous monitoring, annual monitoring for 1-5 MWth

Czech Republic

Government Ordinance No. 146/2007 Coll. In wording No. 476/2009 Coll. (ELVs) Decree No. 205/2009 Coll. In wording No. 17/2010 Coll. (Monitoring) Decree. No. 415/2012 Coll., Decree concerning the permissible level of pollution and its detection

Yes

Yes

Yes for 5-50 MWth

Every three years

Denmark No details on name of legislation Yes

Yes

Yes for 5-50 MWth

Continuous monitoring, except twice per year for 1-5 MWth

Estonia No information received

Finland Environmental Protection Act Government Decree on environmental protection requirements for energy production installations with a total fuel capacity below 50 MW

Yes for 5-50 MWth

Not known Yes for 5-50 MWth

Not known for smaller installations, continuous for 5-50 MWth

http://www.ejustice.just.fgov.be/cgi_loi/change_lg.pl?language=fr&la=F&cn=1997060533&table_name=loi

http://www.ejustice.just.fgov.be/cgi_loi/change_lg.pl?language=fr&la=F&cn=1997060533&table_name=loi

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Member State


Includes ELVs?

Permit required?


France (Note 1)

Inspection des Installations Classees (Permitting – separate regimes for 2-20 MWth and 20-50 MWth) NOR: ATEP9760321A Version consolidée au 15 décembre 2008 (ELVs 2-20 MWth)

ELVs for >20 MWth (various regulations, depending on age of plant)

Yes

Yes

Yes for 20-50 MWth

Every three years, except continuous for 20-50 MWth,

Germany Erste Verordnung zur Durchführung des Bundes-Immissionsschutzgesetzes (Verordnung über kleine und mittlere Feuerungsanlagen - 1. BImSchV) (ELVs) First General Administrative Regulation Pertaining the Federal Immission Control Act (Technical Instructions on Air Quality Control – TA Luft) (24 July 2002) (Monitoring)

Yes

Yes

Yes

Every three years except continuous for 5-50 MWth,

Greece No information received

Hungary No details on name of legislation Yes Yes No Annual monitoring only for 5-50 MWth

Ireland Air Pollution Act 1987 (if the combustion plant is associated with an activity licensable under the Act)

Yes Not known No Monitoring requirements are site specific

Italy No information received

Latvia Cabinet Regulation No. 1082, Adopted 30 November 2010 (Permitting) Cabinet Regulation No.379, Adopted 20 August 2002, "Procedures to prevent, restrict and control air pollutant emissions from stationary pollution sources", Cabinet regulation No.1015, Adopted 14 December 2004 (small boilers) Cabinet Regulation No.158, Adopted 17 February 2009 (monitoring)

Yes Yes Yes Every three years

Lithuania No information received

Luxembourg No information received

Malta Legal Notice 478 of 2010, Ambient Air Quality Regulations, 2010 (Based on TA Luft)

Yes Yes Yes No monitoring

The Netherlands

BEES-B (Existing installations <50 MWth) BEMS (New installations; and from 2017 (2019 in some cases) will replace BEES-B in covering existing installations)

Yes Yes Yes Once the activity starts and then every four year.

Poland Environmental Protection Law (Permits) Regulation of 22 April 2011 on emission standards from installations (Dz. U. Nr 95, poz. 577 (ELVs for 1-50 MWth) ROZPORZÑDZENIE MINISTRA ÂRODOWISKA (Monitoring)

Yes Yes Yes for 5-50 MWth (some plants below 10 & 15MWth also excluded)

Twice per year

17


Member State


Includes ELVs?

Permit required?


Portugal Decree-Law 78/2004, April 3rd (http://dre.pt/pdf1s/2004/04/080A00/21362149.pdf) Ordinance 675/2009, June 23rd (http://dre.pt/pdf1sdip/2009/06/11900/0410804111.pdf)

No Yes for 20-50 MWth

No Not known

Romania Ministerial Order no 1798/2007 for the approval of the procedure of issuing the environmental permit ELVs in accordance with Ministerial Order no. 462/1993 – Technical conditions regarding air protection, Annex 2

No Not known No Not known

Slovenia UREDBO o emisiji snovi v zrak iz malih in srednjih kurilnih naprav (based on TA Luft)

Yes Yes Yes for 5-50 MWth

Continuous for 5-50 MWth

Slovakia No details on name of legislation No Yes No Not known

Spain Requirements are sets at the Autonomous Community leve

Sweden Requirements are set on a case by case basis

United Kingdom

Environmental Permitting, England and Wales (2010) – Part B Regulations apply to boilers 20-50 MWth (England and Wales only)

Yes for 20-50 MWth

Yes for 20-50 MWth

Yes for 20-50 MWth

Continuous for 20-50 MWth

Note 1: New legislation targeted at combustion plants <50MWth was adopted in France in mid-2013 but was not available in time for inclusion in this study.

http://dre.pt/pdf1s/2004/04/080A00/21362149.pdf

http://dre.pt/pdf1sdip/2009/06/11900/0410804111.pdf

http://dre.pt/pdf1sdip/2009/06/11900/0410804111.pdf

18


3. Baseline Development

3.1 Overview As identified in Section 2 the supplementary information received in this study does not provide a complete baseline. Appendix D summarises the information submitted by Member States during the consultation stage of this study.

In order to obtain a representative dataset of estimates of combustion plants between 1 and 50 MWth (numbers, capacities and emissions) and to be able to assess the total EU potential costs and benefits for controlling their emissions, adjustments and additions were made during the development of the dataset in AMEC (2012). Gaps that were identified were filled, and partial information submitted were adjusted and / or supplemented when necessary. For this study we used as a starting point the previous study dataset and improved the data, asking feedback from Member States on our gap filling techniques and the assumptions we applied.

This chapter summarises the status and the process of extrapolation and gap filling to develop a complete dataset, and a summary of this dataset. Appendix F provides an explanation of the approach taken for each specific Member State for which adjustments were made.

3.2 Gap Filling A number of gap filling techniques have been used to make the necessary adjustments and additions to the data gathered from the Member States during this and AMEC (2012).Three mains sets of amendments have been carried out:

i. Adjustment of data gathered from Member States in instances where the data have been flagged by the Member State or AMEC as being only partially complete.

ii. Supplementing the data gathered from Member States with existing data from the previous study in order to fill the gaps.

iii. Extrapolating the adjusted new and supplemented existing data to cover those Member States and/or parameters for which no data (new or existing) are available.

3.2.1 Adjusting Partially Complete Data Gathered

This step involves the use of factors to adjust the data provided by Member States for those instances in which the data have been indicated by the Member State – or identified by AMEC – as being only partially complete. Typically, partially complete has meant, for example, that the data provided cover only some of the plants within a particular capacity class. If no adjustments were made to such partially complete data, the assessment of potential costs and benefits may be under estimated.

19


Each of the partially complete data has been adjusted on the basis of the specifics of the particular data gap. Appendix E presents the issues and resolutions adopted for each Member State for adjusting partially complete data received.

3.2.2 Supplementing with Existing Data

Data submitted by Member States during this consultation were supplemented using the existing dataset developed for AMEC (2012). The dataset developed in that study incorporated the following sources to supplement the gaps:

i. AMEC (then Entec) undertook a previous study for the Commission to gather data on combustion installations of capacities 20 MWth to 50 MWth as a support contract during the negotiation of the IE Directive (Entec, 2009).

ii. Preceding Entec (2009) was AEA (2007) which provided background material to the Commission for the proposal for the IED extending to cover 20 to 50 MWth installations.

iii. AMEC (as Entec) has undertaken for Defra in the UK an impact assessment for the initially proposed IED, which included an assessment of the impacts on combustion installations 20 to 50 MWth (Entec 2008).

Although the distinction between combustion plants and installations has previously been recognised, due to the need to draw on additional data whilst retaining a pragmatic approach, it has been necessary to neglect the differences and utilise the data for combustion installations interchangeably with combustion plant. Consequently there is uncertainty over the number of combustion plant presented in this assessment.

3.2.3 Extrapolating to Missing Member States and Capacity Classes

Number of Plants

In some cases (Denmark, Greece, Ireland, Luxembourg), it was necessary to estimate the number of plants in the 20 to 50 MWth capacity class from data on total capacity. This was undertaken by dividing the capacity by the EU average size of plant in the category (Table 3.1). The average plant size in each capacity class was determined from complete data gathered from Member States on both numbers and capacity of plant.

Table 3.1 Assumed Average Capacity per Plant

Capacity Class Assumed EU Average Plant Capacity (MWth)

1-5 MWth 2.4

5-20 MWth 9.5

20-50 MWth 33

20


Estimates for the number of plants in the capacity classes 1 to 5 MWth and 5 to 20 MWth were derived from the numbers in the capacity class 20 to 50 MWth by utilising average ratios between the number of plants in the smaller capacity classes and the 20-50 MWth category, shown below in Table 3.2. These ratios were derived from the updated data provided by Member States.

Table 3.2 Ratio of Numbers of Plants at each Capacity Class

Capacity Class Number of Plants at Each Capacity Class as a Function of the Number of 20-50 MWth Plants

1-5 MWth 23

5-20 MWth 5.9

20-50 MWth 1

Sectoral Distribution of Plants

A small sample of Member States provided information during the consultation for this study or in AMEC (2012), on the sectoral distribution of these combustion plants. Where Member States provided an estimate of the percentage distribution of 1-50 MWth plants across different sectors this is applied (this is the case for Estonia, the Netherlands, Malta and Slovakia). In a number of cases, the number of plant per sector has been provided for only a proportion of the total number of 1-50 MWth plants (this is the case for Austria, Denmark and Germany). In these cases scaling has been applied in a similar way to adjustments made to plant numbers as described above. For the remaining Member States, where no indication of the distribution of plants between sectors has been provided, a weighted average sectoral distribution (Table 3.3) is applied, based on the countries for which data are available. As only limited data was available on the sectoral distribution of these plants then care should be taken when considering this breakdown. In particular, some of the values such as the proportion of greenhouses in the 5-20MWth category (40%), for example, appear to be too high. This is because the calculated average values are based on a small number of Member States and may not necessarily be representative of the EU as a whole4.

4 For example, the NL has reported that 90% of plant in the 5-20 MWth are in the greenhouses sector. The other Member States that have provided sector breakdown, AT, DK, EE and SK have all reported 0% of plant in greenhouses. The average, weighted by number of plant, of 40% is clearly dominated by NL.

21


Table 3.3 Assumed Sectoral Distribution

Capacity class

Public electricity generation

Public heat generation

Tertiary (i.e. non-residential)

Hospitals

Green-houses

Food industry

Industry

Others

University

Others C

HP

Others

1-5 MWth 11% 25% 5% 6% 13% 4% 18% 5% 1% 11%

5-20 MWth 8% 29% 2% 1% 40% 3% 14% 0% 0% 3%

20-50 MWth 16% 40% 0% 2% 4% 6% 28% 1% 0% 3%

Technology Type

As indicated in Section 2.3, a small sample of Member States provided information, during the consultation for this study or in AMEC (2012), on the proportion or number of plant by technology type. A similar approach as taken for the sector breakdown is also applied for gap filling the split in number of plant by technology type. Data was collected for four technology types; boilers, turbines, engines and others (furnaces, heaters, dryers etc.). However, very limited information was provided, and there was significant variation for the Member States that have provided an indication of the split. Due to this limitation the technology type has been categorised into only two groups; boilers and others. For Member States where no indication of the distribution between these two categories has been identified, the split has been assumed to be 80:20 boilers to others, for each of the three size categories (based approximately on the average of the data that is available.

Capacity of Plants

The estimation of the total capacity of combustion plants in the 1 to 5 MWth and 5 to 20 MWth capacity classes has been undertaken using the average capacity per plant shown above in Table 3.1 multiplied by the numbers of plants.

As a measure of sensitivity, it is also possible to switch the dataset to deriving capacity for the 1-5 MWth and 5-20 MWth categories from the capacity of plants in the 20-50 MWth capacity class. This, if selected, is undertaken by utilising average ratios of the capacity of plants in the smaller capacity classes to the capacity of plants in the 20-50 MWth category, shown below in Table 3.4. These ratios were derived from complete data provided by Member States.

Table 3.4 Ratio of Capacity of Plants at each Capacity Class

Capacity Class Capacity of Plants at each Capacity Class as a Function of the Capacity of 20-50 MWth Plants

1-5 MWth 1.2

5-20 MWth 1.4

22


Capacity Class Capacity of Plants at each Capacity Class as a Function of the Capacity of 20-50 MWth Plants

20-50 MWth 1

Fuel Consumption of Plants

Percentage Fuel Mix

For those Member States for which fuel mix data were not gathered or gap filled using existing data, additional assumptions were necessary on the average fuel mix across the five fuel types of biomass, other solid fuels, liquid fuels, natural gas and other gaseous fuels. This in-filling was necessary for the fuel mix of 1-5 MWth and 5-20 MWth capacity categories. It was assumed that the fuel mix in these smaller capacity classes was the same as that in the 20 to 50 MWth capacity class.

Total Fuel Consumption

Where data have not already been gathered, the total fuel consumption of plants has been estimated in the central case by using average load factors together with the capacity data. The average load factors have been calculated separately for each capacity class from those data provided by Member States which were considered complete. The derived average load factors are shown below in Table 3.5. These load factors are similar to the range of load factors assumed in AEA (2007) of 1000 to 3000 annual operating hours.

Table 3.5 Average Load Factors for Each Capacity Class

Capacity Class Load Factor (%) Load Factor (Hours/ Year)

1-5 MWth 21% 1847

5-20 MWth 34% 2945

20-50 MWth 22% 1894

As a sensitivity, it is also possible to switch the dataset to estimating fuel consumption for the 1-5 MWth and 5-20 MWth capacity classes from the fuel consumption of plants in the 20-50 MWth capacity class. This, if selected, is undertaken by utilising the average ratios of the capacity of plants in the smaller capacity classes to the capacity of plants in the 20-50 MWth category that were shown above in Table 3.4

SO2, NOX and Dust Emissions of Plants

Where no emissions data had been gathered, annual mass emissions of SO2, NOX and dust were estimated using the fuel consumption (FC) for each fuel type, together with the fuel-specific flue gas volume (FGV) and the estimated emission level (EL) for each fuel type f, according to the following equation:

23


( )∑ ××f

fff FGVELFC

It is worth noting that throughout this report, it is assumed that no SO2 emissions arise from natural gas and that gaseous fuels do not give rise to emissions of dust.

The fuel-specific flue gas volumes assumed in this study have been taken from a study on large combustion plants from AMEC (2012b), assuming gaseous plants are primarily boilers, and are reproduced in Table 3.6.

Table 3.6 Specific Flue Gas Volumes Assumed in this Study

Fuel Specific Flue Gas Volume Excess Air (% Oxygen)

Biomass 331 6%

Other solid fuels 370 6%

Liquid fuels 279 3%

Natural gas (boilers) 251 3%

Natural gas (engines) 760 3%

Other gaseous fuels 251 3%

The emission levels are assumed, in the central case, to be at the same level as the identified emission limit value applied by that Member State, or in the absence of national legislation prescribing limit values for the particular capacity class in question, at the same level as a determined general EU case emission level.

Degree to which the Combustion Installations below 50 MWth may be already covered under IED

Article 3(3) of Directive 2010/75/EU on industrial emissions (IED) defines an installation as, ‘a stationary technical unit within which one or more activities listed in Annex I or in Part VII are carried out, and any other directly associated activities on the same site which have a technical connection with the activities listed in those Annexes and which could have an effect on emissions and pollution’.

Therefore combustion units with a rated thermal input less than 50MWth may already be regulated under IED as part of installations where the aggregated combustion capacity on site is at least 50 MWth or where combustion is a directly associated activity with a technical connection to the IED activity. Competent authorities were requested to estimate the number of combustion units in each capacity class which are already regulated under the IED. The response from competent authorities was limited and is summarised in Table 3.7 below.

24


Table 3.7 Proportion of Reported Combustion Plants below 50MWth that are considered to be covered by the IED as Directly Associated Activities

Member State Actual Data/ Estimate Proportion of Plants <50MWth covered by IED as DAAs

1-5MWth 5-20MWth 20-50MWth

Cyprus Actual Data 23% 19% 100%

Czech Republic Estimate (not split by capacity class) 20 – 30%

Finland Actual Data 0% 1% 77%

France Estimate 15% (combined 1-20MWth) 46%

Malta Actual Data 22% 43% 0%

Netherlands Estimate 27 installations or fewer (In industry only)

Portugal Actual data no data no data 24%

For the data received for the seven Member States listed in the table, it is apparent that a greater proportion of 20 to 50 MWth combustion plants may be covered as directly associated activities with IED installations than plants less than 20MWth. It is not considered sufficiently robust to try to estimate the proportions covered as directly associated activities from supplied sectoral information.

The following EU level assumptions have been made for the Member States not listed in the table: 5% of plants in 1-5 MWth capacity class, 10% of plants in 5-20 MWth capacity class and 40% of plants in 20-50 MWth capacity class. These assumptions feed into the estimation of administrative costs. The figure of 40% of plants in the 20-50MWth category being directly associated activities is consistent with the limited data on the subject presented in AEA (2007).

3.3 Overview of Resulting EU27 Dataset The tables below provide an overview of the resulting EU27 dataset with all of the amendments, additions, updates and assumptions as described above.

Table 3.8 Summary of EU27 Dataset


Number of plants 113,809 23,868 5,309

Sectoral distribution1

Public electricity generation 11% 8% 16%

Public heat generation 25% 29% 40%

Tertiary (i.e. non-residential) 5% 2% 0%

Hospitals 6% 1% 2%

25



Greenhouses 13% 40% 4%

Food industry 4% 3% 6%

Industry 18% 14% 28%

Others (University) 5% 0% 1%

Others (CHP) 1% 0% 0%

Others 11% 3% 3%

Technology type2

Boilers 80% 82% 81%

Engines / turbines / others 20% 18% 19%

Capacity of plants (GWth) 273,714 232,367 177,099

Fuel consumption:

Biomass (PJ) 163 160 182

Other solid fuel (PJ) 49 46 74

Liquid fuel (PJ) 213 290 206

Natural gas (PJ) 1,268 1,704 844

Other gaseous fuel (PJ) 277 125 104

Total fuel consumption (PJ) 1,971 2,325 1,410

SO2 emissions (kt) 103 130 68

NOx emissions (kt) 210 227 117

Dust emissions (kt) 17 20 16

Note 1: The sectoral distribution is a weighted average derived from a small sample of Member States which reported this information. Note 2: The technology type split is significantly influenced by the 80:20 assumption which has been used to fill the majority of Member States, for which this information was not available.

Plant Numbers and Capacity

The figures below present for each Member State the number of combustion installations and the total capacity for each of the three capacity class.

26


Figure 3.1 Number of Plants per Capacity Class in each Member States

Figure 3.2 Total Capacity in MWth per Capacity Class in each Member State

Fuel Type and Consumption

The figure below presents the baseline fuel consumption for EU27 by fuel type for each capacity class.

-

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

AT BE BG CY CZ DE DK EE EL ES FI FR HU IE IT LT LU LV MT NL PL PT RO SE SI SK UK

Num

ber o

f pla

nts

20-50 MW

5-20 MW

1-5 MW

-

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000


Tota

l cap

acity

(M

Wth

)

20-50 MW

5-20 MW

1-5 MW

27


Figure 3.3 EU27 Fuel Consumption per Capacity Class

Baseline Emissions

The figure below presents the baseline emissions for EU27 for SO2, NOX and PM, for each capacity class. A breakdown of emissions by Member State is presented in Appendix B.

Figure 3.4 EU27 Emissions per Capacity Class

0

500

1,000

1,500

2,000

2,500

1-5 MWth 5-20 MWth 20-50 MWth

PJ

Other gaseous fuel (PJ)

Natural gas (PJ)

Liquid fuel (PJ)

Other solid fuel (PJ)

Biomass (PJ)

0

50

100

150

200

250

1-5 MWth 5-20 MWth 20-50 MWth

kt

SO2

NOx

Dust

28


4. Options for the Possible Control of Emissions from Combustion Installations less than 50 MW

4.1 Overview of Options The table below provides a high level summary of the main regulatory options considered in this study.

Table 4.1 Overview of Regulatory Options

Regulatory Option Summary

A. “Permitting”:

This could operate in two main ways: i. Integrated permit regulating installations similarly as IED installations under Chapter II and Annex I (permit, BAT). ii. Light permit similar as above but without public participation.

B. “Non-permitting”:

Regulating air emissions from installations via EU wide ELVs, but without a full permitting regime and without BAT obligations. As for the permitting option, this could operate in two ways: i. All plants must provide a notification to the Competent Authority who will maintain a database of plants. ii. No notification to the Competent Authority.

The analysis described in this report focuses on the first two options from the table above, namely the “permitting” (regulatory option A) and “non-permitting” (regulatory option B) options. The main difference between these two options is in relation to the administrative approach and the way in which combustion installations would be regulated i.e. permitting versus non-permitting regimes.

For both of these options we have applied the same two main sets of ELVs for evaluating compliance costs as neither option excludes applying EU wide minimum ELVs or the level at which they are set. A further sensitivity for NOx has also been modelled for both options. The ELVs applied in the modelling are summarised in the table below (further details of the individual ELVs applied are provided later in this section).

Table 4.2 Overview of ELV Options

ELV Option Summary

Most Stringent MS The ELVs for this option have been set to be equal to the most stringent ELVs in MS national legislation for each fuel and technology type and plant capacity.

IED 50-100MW The ELVs for this option have been set to be equal to those for existing 50-100 MWth combustion plants in the

29


ELV Option Summary

IED.

Primary NOx As a further sensitivity we have also modelled, for both regulatory options, a less stringent set of limits for NOx which have been set at a level to only require the uptake (if at all) of primary abatement measures. For this sensitivity the ELVs for SO2 and dust have been set in line with the IED 50-100MWth ELVs.

Further details of the assumptions made for each of these options for evaluating compliance and administrative costs are described in the following sections.

It should be noted that for modelling purposes we have simply assumed that a given set of ELVs would apply to all existing plants (i.e. those already in operation) in a given year. However, in reality it is possible that different sets of ELVs and/or timescales for compliance could be introduced for new (i.e. more stringent and/or compliance required sooner) versus existing plants. This is already the case in a lot of national legislation as well as existing EU policy e.g. IED. For example, in the Netherlands the BEMS legislation and its associated requirements (including ELVs) has applied to new plants from 2010 whereas existing plants do not have to meet the limits until 2017 (or slightly later in some specific cases). This is to give sufficient time for existing plants to adapt their operations and install suitable abatement, where necessary. Any EU policy could adopt a similar approach whereby new plants would need to meet ELVs (possibly more stringent) in a short period of time (say from 2018, for example) whereas existing plants would have a longer timeframe to comply (say by 2025, for example). A staggered approach such as this should give operators more time to decide which approach would be most beneficial for them i.e. whether to keep running an existing plant and retrofit to meet limits or to purchase a new plant which meets the limits. The additional cost of a new plant with suitable abatement to meet certain limits (versus a new plant without abatement) should be lower overall than the cost of retrofitting an existing plant so total costs associated with the policy could perhaps be reduced. Furthermore, benefits could be realised in a shorter period of time although such an approach could also create a perverse incentive for operators to delay purchasing a new plant until the limits apply for existing plants possibly resulting in higher emissions in the short term.

For these reasons, a follow-on contract to this study has focussed on applying disaggregated ELVs and timescales for new and existing plants. The approach and findings of this follow-on contract are described separately in Section 9.

4.2 Business as Usual Emission Levels Business as usual emission levels – per capacity class/ fuel/ technology type/ Member State combination – are assumed to be the same as the ELVs applicable to existing plants in current national legislation or, in the absence of national legislative ELVs, the same as the assumed general case emission levels.

The general case ELVs have been defined, in most cases, as the highest ELV in existing Member State current national legislation. For certain pollutant/capacity class/fuel ELVs the highest existing ELV was very high and was

30


not considered as being representative5. Its use would have distorted the estimate of current emissions, therefore in these instances the next highest value was used, or for SO2 emissions from biomass the CORINAIR Guidebook upper emission factor for small combustion was applied. For the ‘other’ technology category, the ELVs for boilers are applied where there are no existing ELVs for this category. The general case emission levels are reproduced in the table below.

.

5 For example, in one instance the highest MS ELV for one pollutant was only applicable for back-up plants operating a very small number of hours (and therefore not important sources of emissions).

31


Table 4.3 General Case Emission Levels (applied in the absence of Member State-Specific ELVs)

Technology and Capacity Class

SO2 Emission Levels (mg/Nm3) NOX Emission Levels (mg/Nm3) Dust Emission Levels (mg/Nm3)

Biomass Other Solid Fuel

Liquid Fuel

Other Gaseous

Fuel


Liquid Fuel

Natural Gas

Other Gaseous

Fuel


Liquid Fuel

Boiler

1-5 MWth 151a 3206 1700 800 978 1226 900 400 400 376 b 376 b 150

5-20 MWth 151 a 2559 1700 800 978 978 900 400 400 376 b 376 b 100

20-50 MWth 151 a 2559 1700 800 978 978 694b 694 350 376 b 376 b 208

Other

1-5 MWth 151c 3206 c 1700 800 450 1226 c 900 400 400 150 376 b 150

5-20 MWth 151 c 2559 c 1700 800 300 978 c 900 400 400 100 376 b 100

20-50 MWth 151 c 2559 c 1700 800 300 978 c 694 b 500 350 40 376 b 150

a: CORINAIR guidebook upper range emission factor for small combustion of biomass. b: Second highest existing national ELV. c: Set the same as for boilers in absence of any MS ELVs.

32


4.3 EU Wide Scenario Limit Values EU-wide ELVs would most likely need to be set separately for different fuel and technology types, and potentially for different capacity classes, depending on what, if any, threshold would be applied. The introduction of EU-wide ELVs would increase harmonisation across the EU (allowing Member States to apply more stringent limit values) and would impact on some Member States more than others depending on the level and stringency of Member States’ existing national legislation. There would be a need for the Commission to determine what limit values would be seen as representing BAT, to be conceptually in-line with the IED e.g. via the development of a new BREF or revision of the existing combustion plant BREF.

As described in Section 4.1 above, three potential ELV scenarios were initially assessed in this study. In one case, the EU wide ELVs are set at the level of the most stringent national legislation (at each capacity class, fuel and technology type) for existing plants. A second scenario has been run in which the EU wide ELVs are set at the level of the ELVs applied in the IED for 50 to 100 MWth existing large combustion plants. A third scenario has been performed in which the ELVs for NOX have been set so as to be achievable through take up of primary NOX abatement measures (i.e. combustion modification rather than end of pipe measures). This last scenario has been modelled as follows:

• NOX ELVs have been calculated and set so that MSs with General Case emission levels under BAU will be required to take up combustion modification in order to comply with the scenario NOX ELVs;

• For MSs with known BAU ELVs which are more stringent than these low ambition scenario NOX ELVs no abatement measures will need to be taken up;

• For MSs with known BAU ELVs which are between the low ambition scenario NOX ELVs and the General Case emission levels, combustion modification will be required to comply with the scenario ELVs;

• For MSs with known BAU ELVs which are less stringent than the General Case emissions levels, the model would by default pick abatement measures such as SNCR and SCR which can achieve greater emissions reduction than combustion modification in order to comply with the scenario ELVs. In these cases the model has been over-ridden so that only combustion medication is taken up. Consequently, plant in these MSs will reduce emissions but not to a level sufficient to comply with the scenario ELVs;

• ELVs for SO2 and PM are set as for IED 50-100 MWth, therefore abatement measures applied for these pollutants are unchanged, and consequently emission reductions and compliance costs are also unchanged. These are therefore not presented in this document.

The ELVs applied in the three scenarios are listed in the tables below.

33


Table 4.4 EU Wide ELVs applied in this Study for most Stringent Member State Option

Option MWth SO2 ELVs (mg/Nm3) NOX ELVs (mg/Nm3) Dust ELVs (mg/Nm3)

Biomass

Other Solid Fuel

Liquid Fuel

Other Gaseous

Fuel


Liquid Fuel

Natural Gas

Other Gaseous

Fuel


Liquid Fuel

Boiler

Most stringent national MS legislation

1-5 200 200 200 5 200 100 120 70 150 8 5 5

5-20 200 200 200 5 145 100 120 70 164 5 5 5

20-50 200 200 200 5 145 100 120 70 164 5 5 5

Corresponding MS

1-5 FI,FR,NL NL NL PL NL NL NL NL PL HU NL NL

5-20 FI,LV,NL NL NL PL NL NL NL NL DK NL NL NL

20-50 FI,FR,NL NL NL PL NL NL NL NL DK NL NL NL

Other


1-5 200 200 200 5 450 100 46 33 48 150 5 3

5-20 200 200 200 5 300 100 46 33 33 40 5 3

20-50 200 200 200 5 300 100 46 33 33 40 5 3

Corresponding MS

1-5 * * * PL BE * NL NL AT BE * AT

5-20 * * * PL BE * NL AT,NL NL BE * AT

20-50 * * * PL BE * NL AT,NL NL BE * AT

*No MS ELVs for Other plant therefore same values as for Boilers have been applied.

34


Table 4.5 EU Wide ELVs applied in this Study for IED 50-100MWth Option


Biomass

Other solid fuel

Liquid fuel

Other gaseous

fuel

Biomass Other solid fuel

Liquid fuel

Natural gas

Other gaseous

fuel

Biomass Other solid fuel

Liquid fuel

Boiler

As per IED 50-100 MWth existing plants

1-5 200 400 350 35 300 300 450 100 200 30 30 30

5-20 200 400 350 35 300 300 450 100 200 30 30 30

20-50 200 400 350 35 300 300 450 100 200 30 30 30

Other

As per IED 50-100 MWth existing plants

1-5 200 400 350 35 450 300 450 75 110 150 30 30

5-20 200 400 350 35 300 300 450 75 110 40 30 30

20-50 200 400 350 35 300 300 450 75 110 40 30 30

35


Table 4.6 EU Wide ELVs applied in this Study for Primary NOx Option

Option MWth NOX ELVs (mg/Nm3)


Liquid Fuel

Natural Gas

Other Gaseous

Fuel

Boiler

Primary NOx 1-5 700 880 650 290 290

5-20 680 680 630 280 280

20-50 680 680 490 490 250

Other

Primary NOx 1-5 280 510 470 250 210

5-20 190 410 560 250 210

20-50 190 410 430 310 250

In some Member States, ELVs are set with different reference exhaust oxygen content. In such cases the ELV value has been converted to align with the reference oxygen content indicated in the table below. Furthermore, for completeness, where no ELVs are provided in the IED for certain fuel/ pollutant/technology type then they have generally been set to be the same as either the equivalent ELV for boilers or the most stringent MS ELV. Table 4.7 presents the reference exhaust oxygen content that were applied per type of technology and fuel. The Member State ELVs could then be compared on an equivalent basis in order to identify the most stringent.

Table 4.7 Reference Exhaust Oxygen Content

Technology Fuel Reference Exhaust Oxygen Content

Boiler Biomass 6%

Boiler Other solid fuels 6%

Boiler Liquid fuels 3%

Boiler Natural gas 3%

Boiler Other gaseous fuels 3%

Other Biomass n.a

Other Other solid fuels n.a

Other Liquid fuels 15%

Other Natural gas 15%

Other Other gaseous fuels 15%

36


The EU-wide dust ELVs applied for boilers under the IED ELV scenario are 30 mg/Nm3 for all capacity classes and fuel types. This is largely in-line with the newly adopted ‘recommendatory’ limit values of the revised Gothenburg Protocol for solid and liquid fired boilers and process heaters of thermal input 1 MWth to 50 MWth: 20 mg/m3 for new plant, 50 mg/m3 for existing plant 1-5 MWth and 30 mg/m3 for existing plant 5-50 MWth.

37


5. Overall Assessment Framework

5.1 Overview This section provides an overview of the main assessment framework developed initially in AMEC (2012) and further developed in this study for assessing some of the main impacts of potential options, namely costs and emission reductions. The table below provides a summary of the key inputs and outputs from the model.

Table 5.1 Summary of Assessment Framework

Input Data (Note 1) Outputs

1. Data on combustion installations <50 MWth broken down by following size categories - <5, 5-20 and 20-50:

• Numbers

• Capacity

• Fuel mix and consumption

• Emissions

• Average load factors (for gap filling)

• Flue gas volumes (for gap filling)

• Combustion plant type (Note 2) 2. Abatement matrices – details of applicable abatement measures for each plant category (size and type) and pollutant (SO2, NOx and dust) including data on:

• Applicability

• Abatement efficiency

• Costs (capex and opex) 3. National legislation including details on ELVs and legislative approach e.g. permitting or non-permitting. 4. Details on numbers/proportion of plants that are directly associated activities i.e. part of an IED installation. 5. Costs associated with a permitting and non-permitting regime including monitoring.

Compliance costs: To estimate the potential cost impacts of introducing EU wide limit values, emission levels for each capacity class in each Member State are compared against the scenario limit values to determine the required emission reductions (taking into account daily ELVs being 10% higher than annual ELVs) and consequently if additional abatement measures would need to be implemented in the Member State to meet the scenario limit values. The compliance costs for implementing the abatement measures are looked up in the abatement matrices and applied (per plant) utilising the numbers of plants for each fuel type. The number of plants using each fuel type in a Member State is estimated simply using the percentage fuel mix applied to the total number of plants. Administrative costs: Administrative costs are estimated separately for a permitting and non permitting regime taking into account those plants that are already directly associated with an IED regulated activity as well as the current requirements in any national legislation. Emission reductions: To estimate the potential emissions (benefits) impacts of introducing EU wide limit values, a first step is undertaken to split out reported total emissions at each capacity class into emissions associated with each fuel combusted. This step utilises the assumed emission level associated with each fuel and the fuel consumption for each fuel type together with the fuel-specific flue gas volumes. The abatement efficiencies of the abatement measure selected by the model for compliance are applied to the fuel-specific emissions to estimate total emissions reduced of SO2, NOx and dust.

Note 1: As highlighted earlier in the report some of this data is based on a number of assumptions, extrapolations etc. due to a lack of available data from Member States. Note 2: For the main assessment in AMEC (2012) it was assumed that all plants were boilers. However, a sensitivity assessment was also undertaken assuming that all plants were engines and an updated set of abatement matrices were applied. For this study the assessment has been undertaken separately for boilers and others (i.e. including engines, turbines and others).

38


5.2 Compliance Costs

5.2.1 Overview

To estimate the potential compliance cost impacts of introduction of EU wide limit values, current emission levels for each capacity class in each Member State are compared against the scenario limit values to determine the required emission reductions. This indicates whether additional abatement measures would need to be implemented in the Member State to meet the scenario limit values. The compliance costs for implementing the abatement measures are identified in the abatement matrices and applied (per plant) utilising the numbers of plants for each fuel type. The number of plants using each fuel type in a Member State is estimated simply using the percentage fuel mix applied to the total number of plants. The average of the high and low cost range is then projected for 2025 and 2030 as described in Section 5.4.2.

5.2.2 Abatement Matrices

A number of literature sources have been reviewed in order to compile information on the most pertinent and applicable abatement measures for combustion plants less than 50 MWth (including assessments of BAT for such plants) and associated pollution abatement efficiencies and costs. The following sources have been reviewed:

• JRC (2007) Small combustion installations: Techniques, emissions and measures for emission reduction. Joint Research Centre;

• AEA (2007);

• (Summary of) Best Available Techniques in Small 5-50 MW Combustion Plants in Finland;

• EGTEI (2010) Options for limit values for emissions of dust from small combustion installations < 50 MWth;

• VITO (2011) Beste Beschikbare Technieken (BBT) voor nieuwe, kleine en middelgrote stookinstallaties, stationaire motoren en gasturbines gestookt met fossiele brandstoffen;

• ECN (2008) Onderbouwing actualisatie BEES B: Kosten en effecten van de voorgenomen wijziging van het besluit emissie-eisen stookinstallaties B;

• AMEC’s multi pollutant abatement measures database.

The majority of the costs have been taken from VITO (2011) with some additional costs taken from AEA (2007) and AMEC (2013) with figures inflated to 2012 prices in all cases6. The literature sources include a range of costs for measures, which represent the uncertainty around the cost estimates for the abatement measures and variation in installation specific variables, and so a low and high range of costs are used in this analysis. For some abatement

6 Capital (CAPEX) and operational (OPEX) costs have been identified in the reference sources to allow for flexibility in annualising the data; default values of a 4% discount rate and an annualisation period of 15 years have been used in the central case.

39


measures the low and high costs are the same, which is assumed to reflect a single underlying cost data source, whilst for other abatement measures (SCR and SNCR in particular) there is a significant difference between the low and high costs.

The cost data for fuel switching from coal to natural gas are taken from AEA (2007). The data for this abatement measure do appear to be high. No supporting information is included in AEA (2007) to describe what elements the cost data assume, but considering that almost all the total annualised cost for this measure is from the operating costs, it is assumed that the costs for this measure embody the additional commodity cost premium of natural gas over coal. The costs used may not remain representative for the EU.

The abatement measure for the reduction of SO2 emissions from the combustion of other gaseous fuels is assumed to be as per the installation of end of pipe SO2 treatment at liquid-firing plants (wet and dry FGD). It is known however that some of the plants firing other gases will be at refineries and steelworks where it may be more cost effective to desulphurise fuel feedstocks rather than fit end-of-pipe SO2 abatement. As such, for this measure, the costs that have been assumed may be an overestimate.

A summary of this information is presented in the abatement matrices for each of the 1-5 MWth, 5-20 MWth and 20-50 MWth capacity classes, for boilers and for other 1-50 MWth plant technologies, in Appendix A. Expanded versions of these abatement matrices are used within the model to automatically identify which abatement measure would be required to achieve compliance with the scenario ELVs. A threshold has been set at 10% emission reduction, below which it is assumed modifications to existing equipment and operating practice can be implemented to achieve the necessary reduction with no additional cost. If an emission reduction of greater than 10% is required then the lowest cost measure which can achieve the required reduction is selected.

5.3 Administrative Costs

5.3.1 Overview

As described in Section 4, medium scale combustion plants can be regulated in different manners in order to ensure that the emission limit values imposed are implemented and complied with. Regulatory options A (“permitting”) and B (“non-permitting”) differ in the way the administrative procedures for regulating the installations are set up and hence will result in different administrative costs for both the operators and authorities involved.

Regulatory option A (Permitting) would require operators to submit an application to obtain a permit for a new installation, with a competent authority determining whether or not to grant a permit. Sub-options include whether or not public participation is required in the permitting process (i.e. High scenario assumes public participation, and Low scenario does not). Regulatory option B (Non-Permitting) would not require such a permitting procedure but apply general rules to regulate emissions instead. Sub-options include whether or not an operator would have to notify the Competent Authority that it falls under the legislation and is in compliance with the ELVs and whether the Competent Authority would maintain a database of regulated plants (i.e. High scenario assumes notification and database of regulated plants, and Low scenario does not). Under both options we have assumed varying requirements in relation to monitoring of emissions.

40


It should be noted that the administrative cost assessment included costs of periodic monitoring, which are not, in the strictest sense administrative costs. However, these are closely linked to the administrative regime assumed under each of the policy options and therefore discussed in this section of the report.

5.3.2 Regulatory Option A (Permitting)

Under this option it is assumed that plant operators would have to apply for, and maintain, a permit in line with current approaches for existing IED regulated industries. As well as conditions related to emissions to air, the operator would also have to comply with a wider BAT regime which could include additional conditions related to e.g. emissions to water or soil. These additional requirements would be determined on a site by site basis taking into account the site location, activities and potential impacts. Two sub-options have been considered varying in terms of whether or not public participation is required for the permitting process (i.e. High scenario assumes public participation, and Low scenario does not). Unlike a number of other industrial activities, most of these combustion plants are relatively simple in terms of their potential impacts in that emissions to air are the primary concern. Therefore, for this assessment we have focussed on the administrative costs associated with obtaining, and maintaining, a permit in general.

For assessing the cost impacts of this option, the following elements have been considered.

• Cost of bringing installations under the regulation: includes both the costs to operators and authorities. This is a one-off cost at the point of a permit is applied/ granted.

- Operators: costs incurred by operators in understanding the legal requirements, preparing applications, responding to requests for information from regulators, etc.

- Authorities: costs of producing application materials (forms, guidance, etc.), consulting the public (if necessary), determining the application, etc.

• Cost of periodic reconsideration of permits: includes both the costs to operators and authorities. This is a one-off costs at the point of a permit is reconsidered.

• Ongoing subsistence costs: includes ongoing administrative costs to operators and authorities. This is annual, or per monitoring event if monitoring is less frequent than once a year.

- Operators: administrative costs (i.e. non-technical) of providing monitoring reports, accommodating site visits by inspectors, reporting changes in operation, etc.

- Authorities: costs of checking compliance, maintaining systems to make information available to the public (if necessary), updating permit conditions (without amounting to a full reconsideration of the permit), etc.

• Soil and groundwater baseline survey: includes cost for operator to carry out this survey (if required). This is a one-off cost at the point of applying for a permit.

• Ongoing emission monitoring cost: includes ongoing monitoring costs to operators (i.e. services fees for an accredited consultant to conduct the monitoring surveys and preparing monitoring survey report to the operator).

41


Under the IED, and its predecessor the IPPC Directive, a number of Member States operate full cost recovery regulatory regimes whereby operators are charged application (one-off) and subsistence (annual) fees to cover the costs of the authorities’ time. Whilst a similar approach might be taken for the permitting of medium scale combustion plants, this would be a decision for each of the Member States’ competent authorities. Therefore, for the analysis the costs associated with time spent by competent authorities reviewing and processing permit applications have been allocated to the authorities rather than the operators.

A summary of costs applied for calculating the administrative costs for operators and authorities under the Regulatory Option A (Permitting) is provided in Table. For the costs of bringing installations under the regulation, periodic reconsideration of permits and annual subsistence costs, these figures are mainly based on the information given in Annex 8 (“Background data concerning administrative burdens related to permitting and reporting”) of the European Commission’s Impact Assessment for the Proposal for a Directive on industrial emissions (EC, 2007). The cost data presented in the IED impact assessment have been uplifted to 2012 prices from assumed 2006 price levels, and it was assumed that the costs reported in Annex 8 for the installations covered by the IED (>50 MWth) would be the same for 20-50 MWth combustion plants (i.e. 100%). For smaller combustion plants the costs were assumed to be lower; with 80% of this cost applied for 5-20 MWth combustion plants and 60% for 1-5 MWth combustion plants.

The costs presented in Table 5.2 assume that public participation would be required (i.e. High scenario). For the sub-option assuming no public participation (i.e. Low Scenario) it has been assumed that costs of bringing installations under the regulation, costs of periodic reconsideration of permits and subsistence costs would be 25% lower.

Table 5.2 Regulatory Option A (Permitting): Costs applied for Calculating the Administrative Costs for Operators and Authorities (High scenario, assuming public participation)

Administrative Costs Size Category

Costs (€2012 per Installation Unless Stated)

Reference Notes

Cost of bringing installations under the regulation (one-time)

Operator time 20-50 MWth 23,200 EC (2007) p. 158

5-20 MWth 18,500 Assumed to be 80% of costs for 20-50MWth


Authorities 20-50 MWth 10,900 EC (2007) p. 158



Cost of periodic reconsideration of permits (one-time i.e. if operator already has a permit)

Operator time 20-50 MWth 2,900 EC (2007) EC (2007) assumes that the costs for operators is 50% of costs for authorities



42



Costs (€2012 per Installation Unless Stated)

Reference Notes

Authorities 20-50 MWth 5,800 EC (2007) p. 160



Subsistence Costs (ongoing – annual, or per monitoring event if monitoring is less frequent)

Operator time 20-50 MWth 3,500 EC (2007) This includes reporting costs (non-technical costs) only.



Authorities 20-50 MWth 6,900



Soil & Groundwater Baseline Survey

Operator All 4,400 per survey

SAGTA (2004) and EPA (2010)

Average of costs reported in SAGTA (2004) and EPA (2010). SAGTA (2004) suggests a soil & groundwater baseline survey costs involve 4 trial pits, 4 boreholes and 4 location analysis costs. EPA (2010) suggests developing geochemical baseline survey using 4 samples.

Periodic Monitoring

Costs of emissions monitoring and preparation of monitoring reports

20-50 MWth 7,200 per monitoring

event

Independent estimate (2013)

Figures provided by MCERTS accredited monitoring consultancy (anonymous for commercial confidentiality). Assumed average plant size of 35MWth, 4 hours of measurements for NOx and SO2, 3 samples for dust and other parameters also measured (oxygen, temperature and pressure). For natural gas fired plant only monitoring of NOX is necessary, in which case only 50% of the costs is assumed.


event


Reference as above. Assumed average plant size of 12.5MWth, 2 hours of measurements for NOx and SO2, 3 samples for dust and other parameters also measured (oxygen, temperature and pressure). For natural gas fired plant only monitoring of NOX is necessary, in which case only 50% of the costs is assumed.


event


Reference as above. Assumed average plant size of 3MWth, 1 hour of measurements for NOx and SO2, 3 samples for dust and other parameters also measured (oxygen, temperature and pressure). For natural gas fired plant only monitoring of NOX is necessary, in which case only 50% of the costs is assumed.

Note: costs quoted in EC (2007) were adjusted to 2012 prices (and rounded for presentation in this table).

43


5.3.3 Regulatory Option B (Non-Permitting)

Under this option plant operators would not need to apply for, and maintain, a permit. Therefore, no administrative costs are associated with permit application and reconsideration. Furthermore, as only air emissions would be regulated under this option, administrative costs related to other environmental media (in particular the soil report) would not occur. However, given that some form of periodic emission monitoring would be required and consequently some administrative costs associated with preparing, reporting and reviewing of the monitoring reports would be borne by operators and authorities. Two sub-options have been considered varying in terms of whether or not an operator is required to notify the Competent Authority that it falls under the legislation and is in compliance with the ELVs and whether the Competent Authority would maintain a database of regulated plants (i.e. High scenario assumes notification and database of regulated plants, and Low scenario does not).

For assessing the cost impacts of this option, only the following elements have therefore been considered.

• Ongoing subsistence costs: same as for Regulatory Option A (Permitting).

• Ongoing emission monitoring cost: same as for Regulatory Option A (Permitting).

A summary of costs applied for calculating the administrative costs for operators and authorities under the non-permitting option is provided in Table. For the annual subsistence costs, the costs and assumptions described in Annex 8 (“Background data concerning administrative burdens related to permitting and reporting”) of the European Commission’s Impact Assessment accompanying the IED have been applied (EC, 2007). This suggests that administrative burden for installations operating under a permit-based system are approximately €6,000 per year, per installation. In comparison, administrative burden for installations under a non-permitting regime is between €700 (for smaller and simpler facilities) and €2,100 (for large facilities). Based on these figures, it is assumed that annual subsistence costs for a non-permitting option would be 35% (2,100/6,000) of the annual subsistence cost under the permitting regime for 20-50 MWth combustion plants, and 12% (700/6,000) for 1-5 MWth plants. For the 5-20 MWth plants, the average of these figures was assumed. The costs presented in Table 5.3 assume that notification would be required (i.e. High scenario). For the sub-option assuming no notification (i.e. Low Scenario) it has been assumed that subsistence costs would be 25% lower.

As for the Regulatory Option A, the cost data presented in the IED impact assessment have been uplifted to 2012 prices from assumed 2006 price levels.

44


Table 5.3 Regulatory Option B (Non-Permitting): costs applied for calculating the administrative costs for operators and authorities (High scenario assuming notification)


Costs (€2012 per installation unless stated)

Reference Notes

Subsistence Costs (ongoing)

Operator time 20-50 MWth 1,800 EC (2007) EC (2007) suggests that administrative burden for installations under a permit-based system is approx €6,000 per year. In comparison, administrative burden for installations under a non-permitting regime is €700 for smaller and simpler facilities and €2,100 for large facilities. Based on these, it is assumed that annual subsistence costs for a non-permitting option is 35% (€2,100 / €6,000) of the annual subsistence cost under the permitting regime for 20-50 MWth (see Table 5.2 for detail), 12% (€700 / €6,000) for 1-5 MWth. For 5-20 MWth installations, an average of these figures was assumed.

5-20 MWth 1,000

1-5 MWth 400

Authorities 20-50 MWth 2,700

5-20 MWth 1,400

1-5 MWth 500

Periodic Monitoring

Costs of emissions monitoring and preparation of monitoring reports


event


Same as Table 5.2


event


event

Note: costs quoted in EC (2007) were adjusted to 2012 prices (and rounded for presentation in this table).

5.3.4 Key Assumptions

When calculating total administrative costs per Member State based on the abovementioned costs per plant, account has been taken of the extent to which those installations would already be covered by permitting or monitoring regimes under national legislation currently in place. In addition, lower administrative requirements were assumed for the plants that have a direct technical connection (directly associated activity) to installations already covered by the IED. This is summarised in Table 5.4.

45


Table 5.4 Different Components of Administrative Costs included in the Assessment

Should the following administrative costs be applied?

No national Legislation

National Legislation Installations Technically

Connected to IED Installations

With Permitting Without Permitting

Regulatory Option A (Permitting)

Permit Application Costs

Yes 75% for Low scenario

100% for High scenario No

Yes [1] 38% for Low scenario 50% for High scenario

No

Permit Revision Costs No Yes

75% for Low scenario 100% for High scenario

No Yes


Subsistence Costs under a Permitting Regime


100% for High scenario No

Yes[1]


No

Soil & groundwater baseline survey

No for Low scenario Yes for High scenario



No

Monitoring Yes Dependent on requirements in national legislation

Regulatory Option B (Non-Permitting)

Subsistence Costs under a Non-permitting Regime


100% for High scenario No No No

Monitoring Yes Dependent on requirements in national legislation

Note [1]: For Member States with national legislation without permitting, permit application fees and subsistence costs under Regulatory Option A (Permitting) were assumed to be 50% less compared to Member States without national legislation. This is taking into consideration that operators and authorities in these Member States with national legislation already incur some level of costs associated with the regulations.

For the Regulatory Option A (permitting), public participation was assumed for the High scenario but not for the Low scenario. Likewise, for the Regulatory Option B (non-permitting) notification to the competent authorities was assumed for the High scenario but not for the Low scenario. For Low scenarios without public participation or notification, administrative costs were assumed to be lower.

Based on a review of available information from existing national legislation as well as the IED requirements for 50-100MW combustion plants, only periodic monitoring was assumed to be required as the costs of continuous monitoring are considered prohibitively expensive. The monitoring frequency applied under Option A and Option B was every three years for all size categories for a Low scenario. For a High scenario under Option A and Option B, the monitoring survey frequency applied was annual for 20-50 MWth combustion plants and every three years for the 5-20 MWth and 1-5 MWth combustion plants. Subsistence costs have been assumed to be incurred with the same frequency as monitoring.

It was assumed that a new permit application would be required every 20 years. Therefore, the one-time costs of bringing installations under the regulation, periodic reconsideration of permits and the soil and groundwater baseline survey have been annualised over 20 years. Periodic monitoring costs have been annualised as well. The

46


annualised cost of periodic monitoring is one third of the cost per survey if the monitoring requirement is every three years.

5.4 Emissions Reductions

5.4.1 Overview

To estimate the potential emissions impacts (benefits) of introducing EU wide limit values, a first step was undertaken to split out reported total emissions (E) at each capacity class into emissions associated with each fuel combusted (Ef). This step utilises the assumed emission level associated with each fuel (ELf) referred to in Section 4.2 and the fuel consumption for each fuel type (FCf) together with the fuel-specific flue gas volumes (FGVf, Table 3.6) according to the following equation:

∑ ××

×××=

ffff

ffff FGVFCEL

FGVFCELEE

)(

The abatement efficiencies of the abatement measure selected by the model for compliance are applied to the fuel-specific emissions to estimate total emissions reduced of SO2, NOX and dust.

5.4.2 Projections

Emissions and costs have been modelled under three scenarios; business as usual (current ELVs), most stringent MS ELVs and IED 50-100 MWth ELVs. Additionally, a further sensitivity has been modelled for a primary NOX scenario (see Section 4.1). The assessment has been performed separately for boilers and other technology types, to reflect differences in ELVs and abatement technologies for these different technologies. The emission reductions and costs have then been combined to provide the overall impact on 1-50 MWth plants. The emissions and costs have then been estimated projecting forward to 2025 and 2030.

Growth factors have been developed using PRIMES 2012 data on fuel consumption per GAINS sector for 2010, 2025 and 2030. Data have been provided by IIASA (2013) by MS, sector and fuel type. The sectors containing 1-50 MWth plants have been identified in agreement with IIASA and the fuel type categories have been mapped against the categories used in this assessment. The total fuel consumed across all of the sectors of interest, has been calculated for each Member State by fuel type. The growth factor is calculated as the difference between the fuel consumption in the projection year (2025 and 2030) and the baseline year (2010), and can be negative7.

The baseline dataset collated for this study has been compiled from sources dating from 2008 to 2012. This has therefore been taken to represent 2010. The analysis to assess the abatement measures uptake, annualised compliance costs and emission reduction under each of the two ELV scenarios has been performed on this 2010

7 The fuel consumption projections incorporate projections of improvements in efficiency and turn-over of 1-50 MWth plants.

47


baseline. The 2025 and 2030 forecasts for annualised compliance cost and emissions have been estimated by scaling the 2010 results by Member State, fuel type specific growth factors.

Fuel consumption by 1-50 MWth plants has been assumed to change in direct proportion to changes in fuel consumption for the relevant sectors as a whole. Therefore the 1-50 MWth plant fuel consumption projection has been calculated by multiplying the 1-50 MWth plant fuel consumption collated in the baseline for this study by the Member State, fuel specific growth factor. The analysis indicates that a cost efficient abatement measure for complying with certain emission limit values can be fuel switching (for example, from other solid fuels to biomass or from liquid fuels to natural gas). For fuel switching to be reflected in the projections, the growth factor has first been applied to the 2010 fuel consumption, and then the relevant proportion of the projected fuel consumption has been switched.

48


6. Environmental Impacts

6.1 Overview This section summarises the environmental impacts identified during the study, in particular:

• Emissions of SO2, NOX and dust;

• Changes in fuel consumption; and

• Emissions of CO2.

6.2 Emissions

6.2.1 SO2 Emissions

Table 6.1and Figure 6.1 present the SO2 emission forecasts from 1-50 MWth plants for EU27 for each scenario. The current legislation scenario indicates that under business as usual SO2 emissions are projected to decrease by 46% from 2010 levels by 2030, due to change in fuel mix and activity. If control measures are introduced for 1-50 MWth plants this reduction in emissions could be 90%.

Table 6.1 SO2 Emissions (ktonnes)

2010 2025 2030

Capacity Class

Current Legislation

Current Legislation

IED 50-100 MW

Most Stringent MS

Current Legislation

IED 50-100 MW

Most Stringent MS

1-5 MW 103 61 13 9 56 12 9

5-20 MW 130 72 17 12 65 16 12

20-50 MW 68 48 17 14 45 15 13

TOTAL 1-50 MW 301 181 47 35 166 44 34

49


Figure 6.1 SO2 Emission Projections to 2030

6.2.2 NOX Emissions

Table 6.2 and Figure 6.2 present the NOX emission forecasts from 1-50 MWth plants for EU27 for each scenario. The current legislation scenario indicates that under business as usual SO2 emissions are projected to decrease by 16% from 2010 levels by 2030, due to change in fuel mix and change in activity. If control measures are introduced for 1-50 MWth plants this reduction in emissions could be 79%.

Table 6.2 NOX Emissions (ktonnes)

2010 2025 2030

Capacity Class

Current Legislation

Current Legislation

Primary NOx

IED 50-100 MW

Most Stringent

MS

Current Legislation

Primary NOx

IED 50-100 MW

Most Stringent

MS

1-5 MW 210 179 140 63 46 175 136 61 45

5-20 MW 227 194 149 62 47 192 147 61 47

-

50

100

150

200

250

300

350

BAU IED 50-100 MW

Most stringent

MS

BAU IED 50-100 MW

Most stringent

MS

2010 2025 2025 2025 2030 2030 2030

(kto

nnes

)

20-50 MW

5-20 MW

1-5 MW

50


2010 2025 2030

Capacity Class

Current Legislation

Current Legislation

Primary NOx

IED 50-100 MW

Most Stringent

MS

Current Legislation

Primary NOx

IED 50-100 MW

Most Stringent

MS

20-50 MW 117 97 90 42 24 97 89 41 24

TOTAL 1-50 MW 554 470 379 167 117 463 372 163 116

Figure 6.2 NOx Emission Projections to 2030

6.2.3 Dust emissions

Table 6.3 and Figure 6.3 present the dust emission forecasts from 1-50 MWth plants for EU27 for each scenario. The current legislation scenario indicates that under business as usual dust emissions are projected to decrease by 19% from 2010 levels by 2030, due to change in fuel mix and change in activity. If control measures are introduced for 1-50 MWth plants this reduction in emissions could be 95%.

-

100

200

300

400

500

600

BAU

Prim

ary N

Ox

IED

50-1

00 M

W

Mos

t str

inge

nt M

S

BAU

Prim

ary N

Ox

IED

50-1

00 M

W

Mos

t str

inge

nt M

S

2010 2025 2025 2025 2025 2030 2030 2030 2030

(kto

nnes

)

20-50 MW

5-20 MW

1-5 MW

51


Table 6.3 Dust Emissions (ktonnes)

2010 2025 2030

Capacity Class

Current Legislation

Current Legislation

IED Most Stringent MS

Current Legislation

IED Most Stringent MS

1-5 MW 17 16 2 1 16 2 1

5-20 MW 20 19 2 1 19 2 1

20-50 MW 16 14 2 1 13 2 1

TOTAL 1-50 MW 53 48 6 3 48 6 3

Figure 6.3 Dust Emission Projections to 2030

6.3 Changes in Fuel Consumption As indicated above, one of the potential abatement measures which the modelling has indicated could be adopted to comply with ELVs is fuel switching. Standard efficiencies for plant using different fuel type are different, so the

-

10

20

30

40

50

60

BAU IED 50-100 MW

Most stringent

MS

BAU IED 50-100 MW

Most stringent

MS

2010 2025 2025 2025 2030 2030 2030

(kto

nnes

)

20-50 MW

5-20 MW

1-5 MW

52


fuel switching does not result in a like for like change in energy terms. Table 6.4 below presents the resulting change in fuels consumption (biomass, natural gas and other solid fuel) under the three different options.

Table 6.4 Changes in Fuel Consumption

Capacity Class

Primary NOx IED 50-100 MWth Most Stringent ELVs

Changes in Natural Gas (TJ)

Changes in Other Solid Fuel (TJ)





1-5 MWth Total in TJ 0.7 - 0.7 0.7 - 0.7 670.8 - 686.7

% 0.00% 0.00% 0.00% 0.00% 0.00% - 4.00%

5-20 MWth Total in TJ - - - - - -

% - - - - - -

20-50 MWth Total in TJ 3.2 - 3.3 3.2 - 3.3 4.1 - 4.2

% 0.00% -0.01% 0.00% -0.01% 0.00% 0.00%

1-50 MWth Total in TJ 3.9 - 4.0 3.9 - 4.0 674.8 - 690.9

% 0.00% -0.01% 0.00% -0.01% 0.00% -1.00%

Note:”0.0%” indicates there is a change of less than 0.0%. “-“ indicates there is no change.

6.4 Emissions of CO2 The table below (Table 6.5) presents the quantity of CO2 emissions reduced under the two scenarios, as a result of fuel switching. The most CO2 emission reductions are achieved under the most stringent ELVs scenario as this scenario leads to most uptake of fuel switching.

Table 6.5 Total CO2 Emission Reductions (kt) by Policy Option

Capacity Class Primary NOx IED 50-100 MWth Most Stringent ELVs

1-5 MWth - 0.0 - 0.0 - 29.9

5-20 MWth - - -

20-50 MWth - 0.1 - 0.1 - 0.2

Total - 0.2 - 0.2 - 30.1

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7. Economic Impacts

7.1 Overview The proposed policy options to control emissions from combustion installations less than 50 MWth will lead to compliance and administrative costs for operators and competent authorities. These were the main focus of the economic impact assessment, of which the assessment methodology is described in detail in Section 5. In addition, based on a review of the Commission’s Impact Assessment Guidelines the following additional economic impacts were also assessed: (1) small and medium size enterprises (SMEs); (2) competition; and (3) competitiveness.

7.2 Compliance and Administrative Costs

7.2.1 Compliance Costs

The possible techniques that are assumed to be taken up in order to meet the ELVs are set out in Table 7.1. More details on individual abatement techniques are described in Section 5.2.2 and Appendix A.

Table 7.1 Typical Techniques assumed to be applied to meet the Hypothetical EU-Wide ELVs for Plants Modelled as having Emission Levels exceeding the Limits

Pollutant Abatement Measures Fuel IED 50-100 MW Most Stringent MS

SO2 abatement measures

Biomass Wet FGD Wet FGD

Other solid fuel Wet FGD, Dry FGD Wet FGD, Dry FGD

Liquid fuels Wet FGD, Dry FGD Fuel Switch to 0.1% Gas Oil

Wet FGD, Dry FGD Fuel Switch to 0.1% Gas Oil

Other gaseous fuels Wet FGD Wet FGD

NOx abatement measures

Biomass SCR SNCR

SCR Combustion Modification – assumed EGR SNCR

Other solid fuel SCR SCR Combustion Modification – assumed EGR, Fuel Switch to Natural Gas

Liquid fuels SCR Water Injection

SCR Water Injection

Natural gas SCR Low NOx burner / Advanced Lean Burn, Water Injection

SCR SNCR, Water Injection

54


Pollutant Abatement Measures Fuel IED 50-100 MW Most Stringent MS

Other gaseous fuels SCR SCR Low NOx burner / Advanced Lean Burn

Dust abatement measures

Biomass Fabric filter Cyclone

Fabric filter Cyclone

Other solid fuels Fabric Filter Fuel Switch to Natural Gas


Liquid fuels Fabric filter ESP


Table 7.2 and subsequent figures present a summary of the average, total compliance costs for EU 27 for each of the three scenarios. This shows that compliance with the most stringent MS ELVs could cost around 50% more than compliance with the IED ELVs. In either scenario, the cost of complying with NOX ELVs is considerably higher than the cost of complying with SO2 or dust ELVs. This is related to both the stringency of the ELVs assessed as well as the fact that natural gas makes up a significant proportion of fuel consumed by these combustion installations i.e. only NOx emissions have to be reduced.

Table 7.2 Average total Annualised Compliance Costs (€m/year)

Pollutant 2025 2030

Capacity Class

Primary NOx

IED 50-100 MW

Most Stringent MS

Primary NOx

IED 50-100 MW

Most Stringent MS

SO2 1-5 MW 90 90 210 86 86 188

5-20 MW 68 68 123 64 64 113

20-50 MW 27 27 44 25 25 40

TOTAL 1-50 MW

185 185 377 174 174 341

NOX 1-5 MW 27 821 1,119 27 811 1,075

5-20 MW 18 785 1,018 18 773 994

20-50 MW 3 311 543 3 314 534

TOTAL 1-50 MW

48 1,918 2,680 48 1,898 2,603

Dust 1-5 MW 55 55 84 53 53 82

5-20 MW 41 41 77 41 41 75

20-50 MW 27 27 77 26 26 75

TOTAL 1-50 MW

123 123 239 121 121 232

Total 1-5 MW 171 966 1,413 166 950 1,345

55


Pollutant 2025 2030

Capacity Class

Primary NOx

IED 50-100 MW

Most Stringent MS

Primary NOx

IED 50-100 MW

Most Stringent MS

5-20 MW 127 895 1,218 123 878 1,183

20-50 MW 57 365 665 54 365 649

TOTAL 1-50 MW

355 2,225 3,296 343 2,193 3,176

Figure 7.1 Compliance Costs (SO2) Figure 7.2 Compliance Costs (NOX)

-

50

100

150

200

250

300

350

400

IED 50-100 MW

Most stringent

MS

IED 50-100 MW

Most stringent

MS

2025 2025 2030 2030

(€m

/yea

r)

-

500

1,000

1,500

2,000

2,500

3,000

Primary NOx

IED 50-100 MW

Most stringent

MS

Primary NOx

IED 50-100 MW

Most stringent

MS

2025 2025 2025 2030 2030 2030

(€m

/yea

r)

56


Figure 7.3 Compliance Costs (dust) Figure 7.4 Total Compliance Costs by Size Category

Figure 7.5 Total Compliance Costs by Pollutant

Compliance costs are presented disaggregated by Member State in Appendix C.

-

50

100

150

200

250

300

IED 50-100 MW

Most stringent

MS

IED 50-100 MW

Most stringent

MS

2025 2025 2030 2030

(€m

/yea

r)

PM

20-50 MW

5-20 MW

1-5 MW

-

500

1,000

1,500

2,000

2,500

3,000

3,500

Primary NOx

IED 50-100 MW

Most stringent

MS

Primary NOx

IED 50-100 MW

Most stringent

MS

2025 2025 2025 2030 2030 2030

(€m

/yea

r)

20-50 MW

5-20 MW

1-5 MW

-

500

1,000

1,500

2,000

2,500

3,000

3,500

Primary NOx

IED 50-100 MW

Most stringent

MS

Primary NOx

IED 50-100 MW

Most stringent

MS

2025 2025 2025 2030 2030 2030

(€m

/yea

r)

PM

NOX

SO2

57


7.2.2 Administrative Costs

The results of the administrative cost assessment, showing the sum of annualised costs of administrative burden for operators under Regulatory Option A (Permitting) and B (Non-Permitting), are provided in Table 7.3 and Table 7.4. As expected, Regulatory Option A (Permitting) is approximately 7 to 15 times more expensive than Regulatory Option B (Non-Permitting), as the operators are required to apply for a new permit or revise an existing permit and have to incur a greater level of annual subsistence costs compared to the non-permitting option. In both cases, monitoring requirements are identical and thus the costs are the same.

Table 7.3 Annualised Administrative Costs for Operators and Authorities under Regulatory Option A (Permitting) and B (Non-Permitting), including Monitoring Survey Costs (€m per year, 2012 prices, figures rounded for presentation purposes)

Regulatory Option A (Permitting) Regulatory Option B (Non-Permitting)

Average Range Average Range

Operators

1-5 MWth 111 83 - 139 19 18 - 19

5-20 MWth 33 26 - 40 9 8 - 9

20-50 MWth 7 3 - 11 3 1 - 5

TOTAL 1-50 MWth 151 112 - 189 31 28 - 34

Authorities

1-5 MWth 91 78 - 104 6 5 - 6

5-20 MWth 28 24 - 31 4 3 - 4

20-50 MWth 7 4 - 9 2 1 - 2

TOTAL 1-50 MWth 125 105 - 144 11 9 - 13

TOTAL

1-5 MWth 202 160 - 243 25 23 - 26

5-20 MWth 61 50 - 71 12 11 - 13

20-50 MWth 13 7 - 19 5 2 - 8

TOTAL 1-50 MWth 275 217 - 333 42 36 - 47

58


Table 7.4 Annualised Administrative Costs for Operators and Authorities under Regulatory Option A (Permitting) and B (Non-Permitting), excluding Monitoring Survey Costs (€m per year, 2012 prices, figures rounded for presentation purposes)

Regulatory Option A (Permitting) Regulatory Option B (Non-Permitting)

Average Range Average Range

Operators

1-5 MWth 96 67 - 124 4 3 - 4

5-20 MWth 27 20 - 34 3 2 - 3

20-50 MWth 5 3 - 7 1 0 - 2

TOTAL 1-50 MWth 127 90 - 164 8 6 - 9

Authorities

1-5 MWth 91 78 - 104 6 5 - 6

5-20 MWth 28 24 - 31 4 3 - 4

20-50 MWth 7 4 - 9 2 1 - 2

TOTAL 1-50 MWth 125 105 - 144 11 9 - 13

TOTAL

1-5 MWth 187 145 - 228 9 8 - 10

5-20 MWth 55 44 - 66 7 6 - 7

20-50 MWth 11 6 - 15 3 1 - 4

TOTAL 1-50 MWth 252 195 - 309 18 14 - 22

Total EU27 energy consumption in 1-50 MWth plants is projected to decrease by 13% between 2010 and 2030. For this assessment it is assumed that this decrease is predominantly as a result of improvements in energy efficiency. On this basis the number of plants, and therefore the administrative cost, is forecast to be constant.

7.2.3 Total Costs

Combining the compliance costs and the administrative costs under the four assessment scenarios demonstrates that the administrative costs represents between 1% and 45% of the total costs. A summary of the costs is presented in Table 7.5 and Figure 7.6.

59


Table 7.5 Total Annualised Costs (€m/year, Figures Rounded for Presentation Purposes)

Year 2025 2030

ELVs Primary NOx IED 50-100 MW Most Stringent MS Primary NOx IED 50-100 MW Most Stringent MS

Admin Scenario Permit. Non-

Permit. Permit. Non-Permit. Permit. Non-


Permit. Permit. Non-Permit.

1-5 MW Admin cost[1] 200 20 200 20 200 20 200 20 200 20 200 20

Compliance cost

170

170

970

970

1,410

1,410

170

170

950

950

1,340

1,340

Total cost 370

200

1,170

990

1,620

1,440

370

190

1,150

970

1,550

1,370

5-20 MW Admin cost[1] 60 10 60 10 60 10 60 10 60 10 60 10

Compliance cost

130

130

890

890

1,220

1,220

120

120

880

880

1,180

1,180

Total cost 190

140

960

910

1,280

1,230

180

130

940

890

1,240

1,190

20-50 MW Admin cost[1] 10 0 10 0 10 0 10 0 10 0 10 0

Compliance cost

60

60

360

360

660

660

50

50

370

370

650

650

Total cost 70

60

380

370

680

670

70

60

380

370

660

650

TOTAL 1-50 MW

Admin cost[1] 280 40 280 40 280 40 280 40 280 40 280 40

Compliance cost

360

360

2,230

2,230

3,300

3,300

340

340

2,190

2,190

3,180

3,180

Total cost 630

400

2,500

2,270

3,570

3,340

620

390

2,470

2,230

3,450

3,220

Note [1]: Administrative costs include those for both operators and authorities.

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Figure 7.6 Total Annualised Costs in 2025

The table below present the combined compliance and administrative costs per plant.

-

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

Primary NOx IED 50-100 MW Most stringent MS Primary NOx IED 50-100 MW Most stringent MS


(€m

/yea

r)




61


Table 7.6 Total Costs per Plant (€/year, figures rounded for presentation purpose)

Total (€/year)

Number of Plant 2025 2030

ELVs Primary NOx IED 50-100 MW Most stringent MS

Primary NOx IED 50-100 MW Most stringent MS




Permit. Permit. Non-Permit.

1-5 MW Admin cost[1] 1,000

200

1,000

200

1,000

200

1,000

200

1,000

200

1,000

200

113,800 Compliance cost

1,500

1,500

8,500

8,500

12,400

12,400

1,500

1,500

8,300

8,300

11,800

11,800

Total cost 2,500

1,700

9,500

8,600

13,400

12,600

2,400

1,600

9,300

8,500

12,800

12,000

5-20 MW Admin cost[1] 1,400

400

1,400

400

1,400

400

1,400

400

1,400

400

1,400

400


5,300

5,300

37,500

37,500

51,000

51,000

5,100

5,100

36,800

36,800

49,600

49,600

Total cost 6,700

5,700

38,900

37,800

52,400

51,400

6,500

5,500

38,200

37,100

50,900

49,900

20-50 MW Admin cost[1] 1,300

600

1,300

600

1,300

600

1,300

600

1,300

600

1,300

600


10,700

10,700

68,700

68,700

125,200

125,200

10,200

10,200

68,800

68,800

122,200

122,200

Total cost 12,000

11,300

70,000

69,300

126,500

125,800

11,500

10,800

70,100

69,300

123,500

122,800

TOTAL 1-50 MW 143,000

Admin cost[1] 1,100

200

1,100

200

1,100

200

1,100

200

1,100

200

1,100

200

Compliance cost

2,500

2,500

15,600

15,600

23,000

23,000

2,400

2,400

15,300

15,300

22,200

22,200

Total cost 3,500

2,700

16,600

15,800

24,100

23,300

3,500

2,600

16,400

15,600

23,300

22,400

Note [1]: Administrative costs include only those for operators. Administrative costs for authorities are excluded.

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7.3 SMEs

7.3.1 Definitions and the ‘SME’ Test

The Commission recognises small and medium enterprises (SMEs) as playing a central role in the European economy and of being major sources of jobs, growth and competitiveness. However, they can also be less well equipped than large companies to deal with regulatory requirements and changes, and therefore may stand to be disproportionately affected by them. For these reasons, the 2009 Impact Assessment Guidelines8 require that Impact Assessments “analyse whether SMEs are disproportionately affected or disadvantaged compared to large companies” by potential actions or regulatory changes.

The current definition of “SME” was set out in the 2003 Commission Recommendation concerning the definition of micro, small and medium-sized enterprises9. The definition distinguishes between micro, small and medium enterprises according to a combination of staff headcount and either turnover or balance sheet total, as presented in Table 7.7.

Table 7.7 Definition of SME

Enterprise Category Ceilings

Staff Headcount (Number of Persons Expressed in Annual Work Units)

Turnover or Balance Sheet Total

Medium-sized < 250 ≤ € 50 million ≤ € 43 million

Small < 50 ≤ € 10 million ≤ € 10 million

Micro < 10 ≤ € 2 million ≤ € 2 million

Source: Commission Staff Working Document on the implementation of Commission Recommendation of 6 May 2003 concerning the definition of micro, small and medium-sized enterprises, SEC(2009) 1350 final

Annex 8.4 of the 2009 Impact Assessment Guidelines10 provides guidance on the recommended analytical steps to assess impacts on SMEs (the ‘SME-test’) and on possible mitigation measures. In particular, specific guidance is provided on four key analytical steps:

• Consultation with SMEs representatives;

• Preliminary assessment of businesses likely to be affected;

8 SEC(2009) 92 9 Commission Recommendation 2003/361/EC 10 SEC(2009) 92

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• Measurement of the impact on SMEs; and

• Assessment of alternative options and mitigating measures.

Each of these key steps is considered in turn below.

7.3.2 Consultation with SME Representatives

The Guidelines provide suggestions as to how to include SME representatives as part of a more general consultation of interested parties. These were considered for the consultation carried out for this study, but were not deemed relevant to achieve the key aims of the consultation, which were to gather information from Member States to fill the gaps relating to the mapping of combustion plants with < 50 MWth by territory, nor feasible within the short timescales available. Due to the nature of the information required, consultation was limited to representatives from Members State authorities, as well as from a selection of European-wide trade associations.

The sectoral distribution data gathered as part of this consultation can be combined with sectoral enterprise size data from Eurostat to allow for a preliminary assessment of the extent to which SMEs might be affected.

7.3.3 Preliminary Assessment of Businesses likely to be affected

The preliminary assessment of businesses likely to be affected was primarily based on sectoral data obtained from consultation with Member States and trade associations. As described in section 0, combustion plants with <50 MWth operate in a broad range of sectors. For some of these sectors, Eurostat Structural Business Statistics (SBS) provides sectoral data on enterprise size categories (Table 7.8), thus allowing for a preliminary assessment of SME-relevance to be made.

Table 7.8 Enterprise Size Categories per Sector in 2010 for EU27

Sector Micro Small Medium Large Note

Public Electricity Generation 94% 3% 2% 1% Electricity sector (NACE Rev. 2 D.35.11)

Public Heat Generation 71% 17% 9% 2% Steam and air conditioning supply sector (NACE Rev. 2 D.35.3)

Tertiary (non-residential) 88% 6% 4% 2% Combined facilities support activities (NACE Rev. 2 D.81.1)

Food Industry 79% 17% 4% 1% Manufacture of food products sector (NACE Rev. 2 C10)

Industry 82% 14% 3% 1% Weighted average of three manufacturing sectors: coke and refined petroleum products; chemicals and chemical products; and basic metals (C19; C20; and C24)

Hospitals, Greenhouses, Universities, Others CHP and Others Not available in Eurostat

Note: Number of enterprises per size category, available in Eurostat Structural Business Statistics (SBS) for various sectors in year 2010, was used to estimate the proportions of different enterprise size categories for the sectors considered in this report.

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However, a number of factors limited the possibility of a full sectoral mapping by enterprise size:

• Overall, very limited information was received from Member States relating to specific sectoral composition of these combustion plants. For a large number of Member States, an EU average split (based on the limited data that was returned during the consultation) was applied for sectoral breakdown;

• Eurostat SBS does not provide sectoral enterprise size data for some sectors (i.e. Hospitals, Greenhouses, Universities, Others CHP and Others), thus limiting the analysis;

• For those sectors where Eurostat provides enterprise size categories, it is extremely unlikely that the sector-wide average proportion of micro-size enterprises (i.e. 71% to 94%) would be observed for 1-50 MWth combustion plants. It is anticipated that this high proportion of micro enterprises relate to much smaller combustion plants (i.e. <1 MWth) which are outside of the scope of the options considered in this study although some might operate in the smallest capacity class considered (i.e. 1-5 MWth). Furthermore, in a number of cases, such combustion plants are typically a part of a bigger complex requiring more than 9 employees to maintain and operate, and therefore it is highly unlikely that any micro-size enterprises would operate them;

• Whilst combustion plants with < 50 MWth thermal input are used in many sectors, they can in some cases be operated and owned by specialist companies providing such services. As such, the size of the organisation(s) using the output of a combustion plant (e.g. a hospital) may not be the same as the size of the enterprise operating it, again making the analysis of SME-relevance less straightforward;

• In addition, whilst the dataset developed in this study is based on numbers of combustion plants, in many cases an enterprise will own and operate more than one combustion plant. However, no data is available on the average spread of numbers of individual plants by enterprise. This may mean that the numbers of SMEs potentially affected is likely to be overstated.

For these reasons, it was challenging to assess what proportion of the affected operators would be micro, small or medium-size enterprises and caution should be taken in interpreting the results of the analysis. Nevertheless, AMEC applied the following methodological approach to estimate the number of SMEs in each combustion plant capacity category given the available data, and the results are provided in Table 7.9:

• Enterprise size categories per sector assumed for the analysis:

- It was assumed that no plant operators are micro-sized enterprises based on the reasoning presented above. Subsequently, for sectors where Eurostat has information, the number of enterprises in size categories small, medium and large was used to estimate proportions of small, medium and large-size enterprises for the whole sector. Whilst a small proportion of enterprises operating combustion installations in the 1-5 MWth capacity range might be micro enterprises this is expected to be very small. Whilst they have been excluded from the analysis for these reasons, the range of possible mitigation measures discussed later in this section would be of relevance for micro enterprises as well as small and medium enterprises.

- For Hospitals and Universities, it was assumed that all operators would be large enterprises considering hospitals and universities typically employ a large number of people and those with a combustion plant are likely to be larger than average size hospitals and universities.

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- For the remaining sectors, the proportions of different enterprise size categories of a related sector were assumed (i.e. Food Industry for Greenhouses; Industry for Others; and weighted averages from Public Electricity Generation and Public Heat Generation for Others CHP).

• Number of SMEs per combustion plant size categories:

- A number of the plants for each capacity category (1-5, 5-20, 20-50 MWth) are directly associated (i.e. technical connection) to an IED regulated installation, which is extremely unlikely to be an SME (in the absence of Member State specific information, an EU average – based on the Member State data that was available – was applied of 5%, 10% and 40% of 1-5, 5-20 and 20-50 MWth plants, respectively). Furthermore, 20-50 MWth plants are captured under the EU ETS. Therefore, all combustion plants less than 50 MWth directly associated to an IED regulated installations were assumed to be large-size enterprises.

- For the remainder of combustion plants, the aforementioned enterprise size categories per sector were applied to the number of combustion plants per sector.

Table 7.9 Enterprise Size Categories per Sector and Number of SMEs per Combustion Plant Capacity Categories assumed for the Analysis

Sector Small Medium Large Total

Enterprise size categories per sector

Public Electricity Generation 55% 27% 17% 100%

Public Heat Generation 60% 33% 7% 100%

Tertiary (non-residential) 50% 36% 15% 100%

Hospitals; Other University 0% 0% 100% 100%

Food Industry; Greenhouses 78% 18% 4% 100%

Industry; Others 62% 28% 10% 100%

Other CHP 57% 29% 14% 100%

Number of SMEs per combustion plant capacity categories

1-5 MWth 59,548 26,342 27,918 113,808

52% 23% 25% 100%

5-20 MWth 14,281 5,269 4,319 23,869

60% 22% 18% 100%

20-50 MWth 1,862 870 2,577 5,309

35% 16% 49% 100%

TOTAL 1-50 MWth 75,691 32,481 34,814 142,986

53% 23% 24% 100%

Note: These figures include combustion plants that are directly associated to IED regulated installations. However, these are assumed to all be operated by large companies.

66


As seen above, about 75% of the combustion plants considered in this analysis can be assumed to be SMEs. This varies between around 50% for 20-50 MWth plants to more than 80% of 5-20 MWth plants. It should be noted that the differences in sectoral breakdown across capacity categories lead to different assessment of how these are distributed among enterprise size categories.

7.3.4 Measurement of the Impact on SMEs

The direct economic impacts of potential regulation on SMEs relates to whether an operator is able to meet the costs of compliance i.e. costs associated with making any technical changes such as installing abatement as well as the administrative costs associated with the regulation such as applying for a permit. This can be assessed by comparing the compliance cost per plant against the level of financial resources available to the operator for investment.

Information available in Eurostat Structural Business Statistics includes gross operating surplus (GOS), which is the capital available to companies which allows them to repay their creditors, to pay taxes and eventually to finance all or part of their investment11. Considering that GOS can be used for financing investment, we compared the compliance costs per plant against GOS per operator to assess the economic impacts of potential regulation of SO2, NOx and dust emissions.

Eurostat provides GOS per enterprise size category (i.e. micro, small, medium versus large-sized enterprises) in the EU27 in 2010 for sectors comparable to Public Electricity Generation, Public Heat Generation and Food Industry. Where this was not available (i.e. Tertiary and Industry), we used the sector-wide GOS and apportioned it among enterprise size categories according to the data available for value added at factor cost per enterprise size category. This was selected because value added at factor cost is GOS plus personnel cost, and thus assumed to be similarly distributed across enterprise size categories. For some sectors where sector-wide GOS was not available, GOS per operator of a related sector was assumed (i.e. Food Industry for Greenhouses; Industry for Others; and weighted averages from Public Electricity Generation and Public Heat Generation for Others CHP). For Hospitals and Other University, there was no information on either GOS or value added at factor cost for these sectors or related sectors in Eurostat so these sectors were not included in the analysis. However, it is assumed that there are a limited number of SMEs in these sectors so exclusion of these sectors should not present a significant gap in the assessment of impacts on the SMEs.

For each enterprise size category and per sector, GOS was divided by the number of operators to estimate the level of capital available at the operator level on an annual basis. Then the weighted average of GOS per operator per capacity category was estimated based on the number of installations per sector and sector-specific GOS per operator.

11 http://epp.eurostat.ec.europa.eu/statistics_explained/index.php/Glossary:Gross_operating_surplus_(GOS)_-_NA

http://epp.eurostat.ec.europa.eu/statistics_explained/index.php/Glossary:Gross_operating_surplus_(GOS)_-_NA

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Table 7.10 Weighted Average Gross Operating Surplus (GOS) per Enterprise by Capacity and by Size Category (€ per Operator) in 2010 for EU-27

Sector Small Medium Large

1-5 MWth 480,000 1,939,000 31,872,000

5-20 MWth 384,000 1,928,000 26,600,000

20-50 MWth 588,000 2,309,000 31,688,000

To provide an indication of the regulatory burden per size class, these GOS estimates per enterprise by capacity and size category can be directly compared with compliance cost estimates, as presented in Section 7.2.

To begin with, the expected total annual costs per plant per capacity were considered to be equivalent to annual costs per operator by assuming one plant per operator12. These consist of:

• Annualised compliance costs, which is the sum of:

- Annualised capital costs; and

- Annual operating costs;

• Annual administrative costs.

This was carried out for both Regulatory Option A (Permitting) and B (Non-Permitting) and looked at the three emission reduction scenarios evaluated.

It was then possible to divide these total annual costs per enterprise per capacity by the GOS per enterprise per size class to provide the former as a percentage of the latter, and hence an indication of the regulatory burden in general and for SMEs in particular.

12 It is of course the case that some operators may operate more than one plant. However, in the absence of any information on this, one plant per operator was assumed. Clearly, the regulatory burden will be proportionally greater for those operators with more than one plant.

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Table 7.11 Total Annual Compliance and Administrative Costs per Enterprise as a Proportion of GOS in 2025 (Average Percentage)

Enterprise Size Primary NOx IED 50-100 MWth ELVs Most stringent MS

Permitting Non-Permitting Permitting Non-

Permitting Permitting Non-Permitting

Small 1-5 MWth 1% 0% 2% 3% 3% 3%

5-20 MWth 2% 2% 10% 10% 14% 13%

20-50 MWth 2% 2% 12% 12% 22% 21%

Medium 1-5 MWth 0% 0% 1% 0% 1% 1%

5-20 MWth 0% 0% 2% 2% 3% 3%

20-50 MWth 1% 1% 3% 3% 6% 5%


From this, it can be seem that the expected annual compliance and administrative cost per enterprise corresponds to 0%-22% of the average GOS of SMEs across the affected sectors, depending on the emission reduction scenario in question and the administrative regime. Key observations are:

• Small companies operating relatively large plants (20-50 MWth) stand to be significantly affected, with annual costs equivalent to 12-22% of GOS under IED 50-100 MWth ELVs and Most Stringent MS scenarios. This will also be the case for small companies operating combustion plants in the 5-20 MWth range (10-14% of GOS);

• Generally, total annual costs for small companies will be roughly three to five times more burdensome than for medium companies (as a proportion of GOS), for any given combustion plant capacity;

• As would be expected, Most Stringent MS scenario is more burdensome than the IED 50-100 MWth ELV scenario, although the difference between the two is only potentially significant (i.e. a difference of more than 2%) for small companies operating combustion plants in the 5-20 MWth or 20-50 MWth ranges and medium-sized companies operating combustion plants in the 20-50 MWth ranges.

It should be noted that an equivalent assessment for large enterprises results in a burden that is very small, estimated at less than 0.5% of GOS in all cases. In this respect, it can be concluded that SMEs do stand to be disproportionately affected by all potential regulatory changes under considerations relative to larger plants.

In addition to this, as discussed earlier it should also be noted that there may be more than one combustion plant per operator. In such cases, the financial burden to comply with the regulation would be greater than the circumstances described above (although an operator with more than one combustion plant is also less likely to qualify as a micro or small and, possibly even, medium sized enterprise as the number of staff required to maintain and operate them will be higher).

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7.3.5 Assessment of Alternative Options and Mitigating Measures

As identified in the previous sections, a relatively high proportion of SMEs could be captured by any options to control emissions from 1-50 MWth combustion plants. Furthermore, smaller enterprises in particular (and possibly micro if relevant) could be affected most from a financial perspective relative to medium and large enterprises. Where SMEs are predicted to face a relatively higher burden than a large enterprise then the Commission’s Impact Assessment Guidelines require the consideration of alternative options and mitigating measures. The Guidance lists a number of possible measures to be considered including:

• Complete or partial size related exemptions for SMEs or micro-businesses;

• Temporary reduction or exemptions;

• Tax reductions or direct financial aid;

• Reduced fees;

• Simplified reporting obligations for SMEs;

• Specific information campaigns or user guides, training and dedicated helpdesks/offices;

• Systematically consider general simplification initiatives which can particularly benefit SMEs.

The table below sets out possible options for mitigating the impacts on SMEs (and others) that are considered appropriate for the options under consideration. This is based on a review of these suggested measures from the Guidance, a review of measures in other emissions regulations and examples already being applied in national legislation for these plants. It should be noted that whilst these measures are presented in the context of reducing impacts on SMEs, some may also reduce burdens on other larger enterprises e.g. where requiring them to make costly upgrades to plants would not lead to cost-effective emission reductions.

Table 7.12 Potential Mitigation Measures

Type of Measure Description Implications for Costs and Benefits

Complete or partial size related exemptions for SMEs or micro-businesses

Enterprises could be exempted on the basis of their size. This could apply to the smallest (i.e. micro) enterprises only or include others within the SME definition.

Costs will broadly reduce in line with numbers of plants exempted (although will of course depend on where these plants are located, national regulations and current status of plant in terms of emissions). Emissions reductions will be dependent on their operational profile. If a plant has a similar operational profile to other sized plants then emissions will also be impacted in a similar way to costs. However, if these plants have lower than average emission then it could be expected for costs to reduce further than benefits.

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Type of Measure Description Implications for Costs and Benefits

Exemptions for plants with low operating hours and/or low emissions

A number of MSs exempt combustion plants under national legislation if they operate a low number of hours e.g. <200-300 hours per year. The aim of this is to exempt back-up and emergency plants from having to make costly upgrades and incurring administrative burden with limited environmental benefit. The IED includes a number of flexibilities for LCPs with low operating hours e.g. less stringent ELVs. In addition, the EU ETS includes, through Article 27, the possibility for Member States to exclude certain small emitting installations from the requirements of the EU ETS, after agreement on proposals with the Commission. The provision for allowing such exclusions is important to avoid small emitters facing disproportionate administrative costs. In the UK small emitters and hospitals have been excluded from the EU ETS via this Article.

Exempting plants with low emissions will reduce overall costs with limited impacts on benefits. If SMEs were to be exempted purely based on size rather than operating hours or emissions then both costs and benefits would be reduced.

Reduced fees Administrative costs associated with a non-permitting approach are significantly lower relative to the IED permitting approach and involve limited fees for all operators (depending on MS implementation). This could be taken one step further and SMEs could be given discounts on any fees payable under either administrative approach. For example, the Commission has recently announced fees paid by SMEs for registering a substance under the REACH chemicals regulation will be cut by 35-95% depending on the size of the firm.

Reduced administrative costs with no impacts on benefits.

Simplified MRV requirements

For both of the administrative scenarios we have considered two monitoring scenarios, both requiring periodic monitoring: once every 6 months or once every two years. In some MSs, less stringent requirements are applied e.g. in the Netherlands, periodic monitoring is required every 4 years thus reducing the costs for all operators.

Reduced administrative costs with no impacts on benefits (unless simplifying MRV requirements leads to an increase in non-compliance).

Phased implementation A long lead in time for existing plants to comply should ensure that sufficient time is available to integrate any upgrades within normal investment timescales. For example, in the Netherlands whilst new plants have had to comply with the new BEMS requirements since their introduction in 2010, existing plants have a seven year transitional phase before compliance is required.

Delay in both costs and benefits.

Information resources Support could be provided by the Commission, MSs and/or industry in the form of guidance, template application/reporting forms and/or help desks to help SMEs understand how to comply and make decisions on what changes to make e.g. an abatement technology supplier list could be established.

Unlikely to be any impacts on costs and benefits.

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7.4 Competition

7.4.1 Defining Competition Effects

This section assesses the key potential competition effects from the introduction of EU regulation on combustion installations below 50MWth. The analysis seeks to focus on those factors that would act against the interests of free competition between member states or might create unfair competitive benefits on one sector over another.

Our approach to this task is to follow the Impact Assessment guidelines as well as the additional guidance prepared by DG COMP. In line with the guidelines, we provide an initial screening of each policy option to identify if they include:

• rules on liberalisation (of formerly monopolised network utilities such as electricity, telecoms, postal sector, public transport, etc.) and internal market measures;

• measures raising or lowering the barriers to entry or exit, making it harder or easier for firms to enter or leave the market;

• rules introducing special commercial rights (e.g. IPRs) or exempting certain activities from the application of the competition rules;

• sectoral rules pursuing economic, environmental or regional policy goals;

• general rules (e.g. corporate law) governing economic activity.

In terms of the impact on the operation of individual installations and firms, both permitting and non-permitting options would have the effect of imposing similar costs on regulated firms (as two sets of minimum ELVs have been modelled for both options). Therefore, the requirement to fit abatement technology or upgrade equipment would in essence be the same. The principal difference in impact would be on administrative costs and burdens (as described in earlier sections). The following analysis therefore considers the Competition impacts of both options compared with no new regulation.

7.4.2 Rules on Liberalisation

The proposed regulation should have only very limited effects on liberalisation rules. Some of the installations (Public Electricity and Public Heating) are within formerly monopolised public network utilities, however the proposed regulation would in effect bring smaller scale combustion processes in line with regulation for combustion plant greater than 50 MWth, thereby reducing any (potential) perverse effect on these installations at the threshold above and below 50 MWth.

7.4.3 Measures Raising or Lowering the Barriers to Entry or Exit

Increasing capital costs, particularly for new plants, may have a small impact in terms of increasing barriers to entry. However, this is not thought to be significant because the costs would be faced broadly equally between

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existing and new operators (compliance costs would in fact be lower for new operators if ELVs are the same between existing and new operators, due to the likely cost savings of constructing a plant with abatement as opposed to retrofitting an existing plant).

7.4.4 Rules Introducing Special Commercial Rights

The proposed regulation would have no effect on commercial rights. The suppliers of abatement technology are distributed throughout the European Union (and internationally) and the requirements would not impose a need for specific proprietary products.

7.4.5 Sectoral Rules

It is not envisaged that the proposed regulation would impact on sectoral rules, unless if specific exemptions were proposed. Application of the rules across the board would impose similar constraints on all operators. The proposal to regulate combustion plants of less than 50 MWth may have the effect of removing a potential comparative disadvantage faced by sectors and operators of plants greater than 50 MWth compared to the rest of their sector or with other sectors where smaller installation sizes are more prevalent.

7.4.6 General Rules

Neither approach to regulation would appear to interfere with existing rules or corporate law. The framework within which the permitting or non-permitting approaches would operate would be consistent with existing regulatory approaches and obligations rather than creating conflicts with existing rules.

7.4.7 Analysis of Market Sectors

The market sectors affected are identified above (see Section 5.2). Each faces slightly different market structures. In the table below we set out information on the structure of each affected sector, identifying the turnover associated with each firm of different scales (by number of employees). In this case, many of the largest firms will already be within the scope of the existing regulation (including IED and EU ETS) and may therefore be relatively unaffected by the regulations proposed.

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Table 7.13 Turnover by “Sector” by Scale (Number of Employees)

Sector

Average Turnover per Company (€M)

Average All Companies

0-9 Employees

10-19 Employees

20-49 Employees

50-249 Employees

250+ Employees

Manufacture of food products 3.1 0.3 1.5 5.2 23.9 176.0

Industry (an aggregate of coke production, refineries, chemicals and basic metals sub sectors) 27.8 0.8 2.2 5.0 41.5 616.7

Electric power generation, transmission and distribution (a proxy for public electricity generation) 21.1 1.5 25.7 70.9 242.5 1,469.6

Steam and air conditioning supply (a proxy for Public heat generation) n/a 1.9 n/a 6.6 n/a 173.4

Source: Generated from Eurostat database query on turnover and number of enterprises for NACE Rev. 2 codes C10, C19, C20, C24, D35.1 and D35.3. 2010 values used.

As can be seen from the above table, the turnover of the largest firms in electric power generation is far higher than for the other sectors/ uses identified. This reflects the concentration of the industry in a small number of substantial operators and a larger number of relatively small (possibly niche) operators. Greenhouses are a use within (principally) agriculture, but disaggregating agricultural statistics to provide comparative analysis is not practical. However, we are able to provide a little more analysis of greenhouse use below.

7.4.8 Analysis of Member State Impacts

Overall, the different MSs are affected in a similar way. In the figure below, we set out the relative impacts on each MS by assessing average costs per plant (based on the compliance and administrative costs presented previously). Impacts at a MS level are influenced by a number of factors, including the total number of plants operating in a particular MS, the split between the different size classes, the overall fuel mix and existing national level legislation. Any national level legislation will influence both the compliance costs (depending on the level at which any ELVs are set) and the administrative burden (depending on the approach taken e.g. permitting), as modelled in this study. In addition, those MSs with a higher number of larger plants (i.e. 20-50MWth) relative to smaller plants will have higher average costs per plant (and vice-versa) due to the increased costs of installing abatement techniques on larger plants.

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Figure 7.7 Average Annual Cost per Plant for each MS in 2025 (€k per Plant per Year)

Note: These expected costs are averages across all plant capacities (i.e. 1-50 MWth). The actual costs per plant will differ according to plant size. The distribution of plants by size also differs across Member States. This can lead to some Member States having relatively larger average costs if they have a greater proportion of larger plants, as is the case with Finland.

Some MSs have previously made more progress with reducing emissions from combustion plants than others through the introduction of national legislation. The relative costs take no real account of historic efforts and pre-existing regulation in different MSs would make the additional burden of introducing the proposed regulation relatively modest. There is insufficient data to allow a presentation of the total costs in each MS of achieving the proposed standards (i.e. including historic efforts) but the base assumption would be that, starting from the same level, each country’s average cost would be approximately the same, and that the differences are largely attributable to levelling up from a low base rather than any intrinsic country effect.

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7.4.9 Analysis of Supply of Abatement Technology

A brief analysis of the supply of abatement technology has been included in order to assess if there is the potential for a single supplier or single MS to benefit from enactment of the proposed regulation. If the regulation were found to favour one particular supply company sector or member state this might be regarded as implying an (unintended) competition impact that would warrant further exploration.

Abatement technologies to reduce air emissions are manufactured by a range of companies ranging from the engineering or chemical companies to the energy specialist. For example, the energy giants Siemens (DE), Hitatchi (DE) and Alstom (FR) all provide multiple abatement techniques for various pollutants (NOx, SOx, dust and others). Other leading engineering European companies such as ABB (CH), Andritz (AT) and Fluor (UK) provide a wide range of abatement technologies such as SCR, FGD and electrostatic precipitators (ESP).

Some manufacturers are more specialised. This is the case of the Belgium Carmeuse, which is specialised in limestone product used for sulphur abatement, as well as the Italian company Ansaldo, which is specialised in in-furnace emission reduction systems (low NOx burners, air staging etc.). CMI (BE) is specialised in the design and construction of heat recovery steam generators. Similarly, Howden (UK) is a leading provider of rotary regenerative heat exchangers which are used for FGD and SCR. The British company Johnson Matthey is a leader in providing chemical catalysts. Finally, the Swiss Hug Engineers is a leader in diesel particulate filters and catalytic exhausts. All of these companies are large and have multiple offices in and, for some, outside of the European Union. Whilst a majority of the abatement technologies manufacturers are large companies, there is a significant number of SMEs involved in the installations or the fitting of these technologies. Moreover, some more specific (specialist) technologies, particularly relevant for combustion engines, may be developed by smaller manufacturers.

Furthermore, the options considered within the analysis would entail the establishment of minimum EU-wide ELVs without specifying any particular abatement technique(s) that would need to be installed. It would be in line with existing regulations in this field such as the IED itself.

This brief analysis supports the general conclusion that there is no one dominant supplier or dominant approach across the installations captured by the proposed regulation.

7.4.10 Conclusions

This section has explored the effect on competition (principally within the EU) of the application of proposed rules. Although there are additional costs, the overall effect on competition within and between sectors is relatively modest. This because of the general applicability of the proposed regulation, which brings smaller combustion plant more in line with the constraints already imposed on larger installations. Clearly, the absolute impacts would be influenced by the scale of impacts of a particular option, namely the levels at which any ELVs are established and the regulatory approach taken. Competitiveness impacts are explored further in the section that follows.

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7.5 Competitiveness, Trade and Investment Flows

7.5.1 Definitions and the Testing Competitiveness, Trade and Investment Effects

Competitiveness is a measure of an economy’s ability to provide its population with high and rising standards of living and high rates of employment on a sustainable basis. In this analysis the concern is to establish the extent to which the proposed regulation will (or could) impact on the competitive position of firms within the EU compared with firms operating in the rest of the world. In some cases, firms operate both within and outside the EU. If the proposed regulation were likely to encourage those firms to switch production outside of the EU, that would be considered a weakening of the EU’s competitive position. The key concepts under consideration are whether the proposed regulation:

• Increases or reduces differences between the regulatory regime faced by EU companies and competitors in non-EU countries;

• Places EU firms at an advantage or disadvantage compared to their international competitors;

• Contributes to the relocation of economic activity to or from non-EU countries.

In addition, we briefly explore the extent to which the proposed regulation has an impact to:

• Boost cleaner companies and sectors either directly or indirectly through shift of demand away from polluting companies and sectors;

• Help or hinder trade and cross-border investment into the EU or from the EU to third countries;

• Have an impact on WTO obligations of the Community;

• Generate a ‘first-mover’ advantage with other countries likely to follow.

The following analysis briefly explores each of those issues and identifies a number of sectors with the potential to be impacted competitively. These sectors are explored in more detail.

7.5.2 Differences between the Regulatory Regime faced by EU Companies and Competitors in Non-EU Countries

Outside of the EU, there is a range of regulatory systems affecting combustion plants. Some of the most rigorous might be found in places like California (USA), where air quality concerns have a very high profile, while they may be considerably less stringent in other areas and countries where such concerns are lower. The effect of the proposed regulation would be to increase the differences between the regulatory regime faced by EU companies and competitors in non EU countries.

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7.5.3 EU firms compared to their International Competitors

The principal consideration of the impact of the proposed regulation on EU firms compared to their international competitors stems from the extent to which the affected firms are exposed to international competition. This has been assessed in the table below to illustrate the extent to which the sectors concerned are operating in internationally competitive markets.

In general those sectors that operate in local markets are capable of passing costs on to their customers and are likely to be the least affected (although customers always face choices about consumption and there may be important effects felt even where trade is very localised).

Table 7.14 Exposure to International Competition

Sector Use Nature of Markets/ Exposure to International Competition

Notes

Public electricity generation Limited – markets are local and limited opportunities to trade outside EU

International competition is increasing through the use of interconnectors although trade from outside EU is limited

Public heat generation Very limited local markets

Tertiary Local site specific facilities serving a very local needs

Hospitals Locally specific services with limited international trade

Some growing interest in medical tourism might make this significant in a small number of specific cases

Food industry Certain sub sectors are very strongly traded internationally and may be subject to significant international price pressures

Part of the food industry market is very locally specific and may be largely unaffected

Greenhouses Much greenhouse production is for international trade and competition comes from hot countries outside of the EU

Industry Certain sub sectors face significant international trade both within and outside of the EU

Other CHP It is assumed that this will be similar to local electricity and heat supply

Our assessment therefore is that firms in the Food industry, Greenhouses (agricultural sector) and Industry sectors are likely to face international competiveness impacts, and these are explored in more detail below.

7.5.4 Relocation of Economic Activity to or from Non-EU Countries

The majority of installations below 50 MWth are used in local contexts meeting local heat and/or energy needs and are therefore unlikely to directly face relocation to non EU countries. The three sectors identified above as facing intentional competition are the most likely to face the threat of relocation to non EU countries, and these are explored in more detail below.

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7.5.5 Boost cleaner Companies and Sectors either Directly or Indirectly through Shift of Demand Away from Polluting Companies and Sectors

The use of combustion installations arises where a local supply of heat and/or energy is desirable (for a variety of reasons) rather than using an alternative means of providing power or heat such as the main grid (although in some cases these plants also input to the grid). These comparative advantages (between combustion plant and electric heating for example) are likely to remain even in the face of some increased costs. The general applicability of the proposed regulation is unlikely to result in a significant shift in demand between sectors, although relative prices of some goods and services are likely to rise as a result of new regulatory burdens. However, the proposed regulation brings smaller installations into line with larger installations, thus potentially correcting an existing market and sectoral distortion (around the existing 50MWth threshold).

7.5.6 Help or Hinder Trade and Cross-border Investment into the EU or from the EU to Third Countries

The proposed regulation is unlikely to have any significant impact on cross border trade or investment.

7.5.7 Have an Impact on WTO Obligations of the Community

There do not appear to be any WTO obligation impacts.

7.5.8 Generate a ‘First-mover’ Advantage with Other Countries likely to follow

There may be a small beneficial effect for the suppliers of abatement technology, since the market will grow. However, there would be little ‘first-mover’ advantage per se, since the likely technological solutions to abatement control are already well established. Nonetheless, there might be a future benefit to EU companies as non EU countries improve their regulatory regimes, thus providing EU suppliers with opportunities to share technologies and technical expertise.

7.5.9 Sector Specific Analysis

Overview

Potentially significant competitiveness effects are assumed to be felt most significantly in sectors where international competition is greatest, specifically;

• Food and Drink;

• Industry; and

• Greenhouses (agriculture).

These sectors (users) are therefore assumed to be the most appropriate for further quantitative analysis

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The following table illustrates the scale of the impact for the three sectors of interest: greenhouses, food industry and industry. These are broken down by size of enterprise (Small, Medium and Large). Gross Operating Surplus (GOS)13 is used as a measure of the profitability per company and of the potential resources available for responding to further regulatory measures, the assumption being that the larger the GOS the greater the capacity to invest in improvements. The figures represent the average GOS for the sector multiplied by the number of firms affected by proposed regulatory changes. This is a slightly crude metric but provides an approximation of the total GOS for the affected firms.

Table 7.15 Analysis of the Average Gross Operating Surplus (GOS) per Sector

Greenhouses Food Industry Industry

Number of Plants

Total GOS for affected

Companies (€ Million)

Number of Plants


Companies (€ Million)

Number of Plants


Companies (€ million)

Small 17,951 3,834 3,916 836 14,145 961

Medium 4,059 6,795 881 1,475 6,489 648

Large 2,815 42,712 699 10,606 4,549 15,900

TOTAL 24,825 53,341 5,496 12,917 25,183 17,509

Analysis is provided in an earlier section about the potential impacts on SME’s so turning to Large firms it would appear that greenhouses (agriculture) might have the largest capacity for investment while industry might be relatively constrained (this may be a measure of the competitiveness of the different markets or an artefact of scale).

Food Industry

The food industry is an unusual sector inasmuch as it combines commodity produce with very distinctive specialist produce with strong regional specialism and strong premium brands.

The commoditisation of food makes it most susceptible to international competition. In much of Europe, the concentration of food processing and food retail within a relatively small group of big companies drives further highly price sensitive competition, along with willingness to source and import on the basis of very small improvements in margins.

13 Eurostat (glossary) defines GOS as “the excess amount of money generated by incorporated enterprises' operating activities after paying labour input costs. In other words, it is the capital available to financial and non-financial corporations which allows them to repay their creditors, to pay taxes and eventually to finance all or part of their investment.”

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Selected data illustrate this concentration in the retail markets across Europe14:

• Food retail indicative large retailers fruit & veg. market share:

- UK: 75%

- France: 75%

- Italy: 50%

- Spain : 40%

- NL supermarkets : 75%

• Sweden and Denmark top 3 importers-wholesalers: 80%

• Spain top 5 supermarkets: 66%

• Netherlands top 5 supermarkets: 66%

This trend of concentration of retail is dominant in Northern Europe but increasingly spreading across all of Europe.

Concentration and consolidation have been strong features of the food production sector and the strong position of a few firms in the supply chain feeds through to basic food production costs and practices.

These features of the market faced by the food industry exacerbate pressures in international competition, although the food industry is generally not considered significantly at risk of leakage.

Greenhouses (Agriculture)

Exploring the nature of greenhouses in more detail reveals some important characteristics of the sector15:

• Total production area for flowers and ornamental plants: estimated at 200 thousand hectares (in 2010);

• Production as proportion of world production: approximately 44%;

• Production value: estimated € 19.8 billion, concentrated in the Netherlands, Italy, Germany and France;

• Value of total imports of live plants and products of floriculture: € 1.55 billion. Imports came mainly from Kenya, Ethiopia, Ecuador, Israel, Colombia, Costa Rica and USA;

14 Bijman, J. (2012). Support for Farmers’ Cooperatives; Sector Report Fruit and Vegetables. Wageningen: Wageningen UR

15 http://ec.europa.eu/agriculture/flowers/index_en.htm

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• Value of total exports of live plants and products of floriculture to non EU countries: € 1.75 billion. Primary destinations were Russia, Switzerland, USA, Norway and Japan;

• Trade surplus in live plants and products of floriculture trade with non EU countries: € 194 million.

The competitive position is well illustrated by this graphic from a recent EU working document for the EU as a whole:

Figure 7.8 Trade Balance of Live Plants and Products of Floriculture, 2012 (€k)

Source: http://ec.europa.eu/agriculture/fruit-and-vegetables/product-reports/flowers/statistics-2012_en.pdf

In addition to flowers and plants, greenhouses are used in the production of fruits and vegetables, particularly soft fruits and extended seasonal vegetables. The majority of other fruit and vegetable produce is unlikely to require greenhouses and certainly, apples, oranges and pears for example will be grown in the open. The greenhouse using portion of the overall fruit and vegetable market will be limited but it is nevertheless worth noting14:

• The most important vegetables, in terms of volume harvested products (2010 figures), are tomatoes (16.1 million tons), carrots (5.1 million tons), and onions (5.4 million tons). For fruits, the main products are apples (10.4 million tons), oranges (6.3 million tons) and pears (2.5 million tons).

• Fruit and vegetables are characterised by the perishability and seasonability of the products, but also by the variation in quantity and quality (due to natural conditions), which has implications for logistics in the supply chain. Both the variation in supply and the variation in demand (e.g. due to weather) lead to price volatility. Furthermore, in the consumer market fruits and vegetables are substitutes in that, depending on the price, consumers can shift to buying other fruits or vegetables.

http://ec.europa.eu/agriculture/fruit-and-vegetables/product-reports/flowers/statistics-2012_en.pdf

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As the following figure illustrates, there has been year on year growth in the value of output in most EU member states, indicating the strength of the sector and the competitiveness of EU producers.

Figure 7.9 Average Growth of Production Value per Year, Producer Price (Fruits and Vegetables, 2001-2009)14

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The map below illustrates those regions within Europe where fruit and vegetable production represents a high proportion of agricultural produce. It will be seen that in general it is the southern parts of Europe (and to lesser extent the southern parts of each country) where fruit and vegetable production is concentrated. This is reflective of the benefits of warmer temperatures in fruit and vegetable production, which potentially reduces the dependence on combustion plants as a source of heat. This southern shift of fruit and vegetable production might be expected to continue with additional cost for heating as a result of proposed regulation.

Figure 7.10 Share of Fruit and Vegetables in Regional Agricultural Production

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Produce from Greenhouses therefore can be seen as being both important in international export (from the EU) and of particular importance to some MSs such as the Netherlands and, to a lesser extent, Italy, France and Germany for fresh flowers and live plants. Competition for fresh flowers, plants and out of season vegetables comes from geographies with a particular advantage in terms of heat and sunlight (but which might lack technology, processes and other natural endowments such as water).

These issues and competitiveness factors are suggestive of a sector where cost passed through will be difficult for some segments of the market, and additional costs could impact competitiveness directly. The countervailing pressure of transport costs and produce freshness militate against distant non EU competition remaining at a disadvantage in local markets, thus reducing the overall strength of any effect.

It should also be noted that whilst combustion plants provide greenhouses with heat and/or power, the exhaust gases are often pumped back into the greenhouse to elevate CO2 levels and speed up growth. However, to do so the gases must first be stripped of harmful pollutants including NOx, SO2 and dust. Therefore, impacts of the potential options considered in this study might be lower than modelled due to this existing uptake of abatement measures for operational reasons.

Industry

Amongst the sub-sectors of industry that could be impacted by the proposed regulation; chemicals, metals and refineries are identified as exposed to significant risk of carbon leakage. Exploring these sub sectors in a little more detail seems justified and the following section provides a further discussion on the nature and competitive position they face.

Metals; Steel

Employment in the steel sector reached a peak of around 1 million in the EU during the 1970’s. Employment has declined to just over 400,000 in 2008 and the sector continues to faces stiff competition from the new global steel producers of Eastern Europe, notably Korea and China. In spite of this stiff competition, Steel exports exceed imports. Basic data on the EU steel industry follows16:

• EU steel exports in 2010 were 33.7 million tonnes (€32 billion) whilst imports were 26.8 million tonnes (€18 billion);

• EU share of global steel exports (top ten exporters) in 2010: 14 %;

• Biggest markets for EU steel exports in 2010 (in decreasing order of importance): Turkey, USA, Algeria, Switzerland, Russia, India;

• Employment in the steel sector has contracted steadily in recent decades from 1 million people working in the sector in 1970, to around 408 000 employed in the sector in 2008. The number of

16 http://ec.europa.eu/trade/creating-opportunities/economic-sectors/industrial-goods/steel/#stats

http://ec.europa.eu/trade/creating-opportunities/economic-sectors/industrial-goods/steel/#stats

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Europeans working in downstream industries dependent on domestically-produced or imported steel is in the millions;

• EU steel imports fell by about 50% from 40.2 million tonnes in 2008 to 20.7 million tonnes in 2009. In comparison, the steel exports from the EU only fell by 11% from 35 million tonnes in 2008 to 31 million tonnes in 2009, thus turning the EU steel trade balance to surplus after several years of deficit. In 2010 this surplus halved when imports grew by 30% to almost 27 million tonnes and exports increased only by 5% to 33.7 million tonnes in total.

The above data indicates that the average value of steel imported was around €670 per tonne (value divided by tonnage) while the value of steel exported was nearly 1,000 € per tonne. This is a strong indicator that the steel exported is of a higher quality (perhaps because of finishing or fabrication differences) than imported steel. Some of the decline in steel imports may be attributable to economic downturn, although as can be seen exports held up comparatively well.

The following figures show steel imports and exports from 2006 projected forward to 2014. The EU has since 2009 maintained a healthy trade surplus in steel but it is also apparent that it is a globally traded commodity that has the potential to be impacted by price. It is likely that in general steel producers in the EU are price takers and therefore have limited capacity for passing cost, although the EU does have specialist steel fabrication facilities and these may provide some shelter from non EU competition.

Figure 7.11 EU27 Imports of Steel

Source : Eurofer, 2013: http://www.eurofer.org/index.php/eng/Issues-Positions/Economic-Development-Steel-Market

http://www.eurofer.org/index.php/eng/Issues-Positions/Economic-Development-Steel-Market

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Figure 7.12 EU27 Exports of Steel

Source : Eurofer, 2013: http://www.eurofer.org/index.php/eng/Issues-Positions/Economic-Development-Steel-Market

Non-ferrous metals

Non ferrous metals (principally aluminium, copper and zinc) are important in the manufacturing and production supply chains. The EU has limited raw material and mineral deposits, and the principal source is waste and scrap recycling (for which combustion plants provide energy inputs). The EU has developed considerable specialism in these areas but the demand for such metals is greater than can be met through these routes. As a result the EU imports some €8 billion more than it exports (2009 figures). Basic data on the EU non ferrous metals sector follows17:

• Imports (2009): €34 billion / Exports (2009): €26 billion (trade balance: - €8 billion);

• The share of the non-ferrous metals sector in EU manufacturing value added is 1.37 % (€23.4bn.);

• The share in employment is 1.0 % (334 800 people);

• Turnover of the sector was €139 billion (2.0 %);

17 http://ec.europa.eu/trade/creating-opportunities/economic-sectors/industrial-goods/non-ferrous-metals/

http://www.eurofer.org/index.php/eng/Issues-Positions/Economic-Development-Steel-Market

http://ec.europa.eu/trade/creating-opportunities/economic-sectors/industrial-goods/non-ferrous-metals/

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• Employment has remained stable between 2003 and 2006, whereas productivity has increased.

Chemicals

The chemicals sector is one of Europe's most competitive industrial sectors. Its work is focused on the manufacture of chemicals and the chemical transformation of materials into new substances or products. It covers a huge range of operations from basic organic and inorganic chemical products, through fertilizers, basic plastics, synthetics, rubbers, paints and varnishes to highly specialized consumer chemicals and polymers. Basic data on the EU chemicals sector follows18:

• EU chemicals exports in 2009: €118 billion;

• EU chemicals imports in 2009: €75 billion;

• Biggest markets for EU chemical exports: US, Canada, Switzerland, Asia (China, India, Japan and ASEAN countries);

• Accounting for around 30% of the total world chemicals production, the EU is the world's most important producer of chemicals. In 2008 it produced €566 billion worth of chemicals. More than one third of world's top thirty chemical companies have their headquarters in the EU. The largest European producer of chemicals is Germany, which accounts for about 25% of EU production. Around 30,000 chemical companies employ a total staff of about 1.2 million people in the EU. Another three million employees work in sectors using output of the chemical industry and thus depend on its competitiveness;

• The EU trades more than 40% of all chemicals traded globally, compared with circa 15% for the NAFTA countries and circa 30% for Asia.

The figure below shows the growing importance of chemicals in the EU economy with both imports and exports growing progressively since 1999.

18 http://ec.europa.eu/trade/creating-opportunities/economic-sectors/industrial-goods/chemicals/

http://ec.europa.eu/trade/creating-opportunities/economic-sectors/industrial-goods/chemicals/

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Figure 7.13 EU27 Chemicals Sector Trade Balance

Source: Cefic (2012) http://www.cefic.org/Documents/FactsAndFigures/2012/International-Trade/Facts-and-Figures-2012-Chapter-International-Trade.pdf

Refineries

Refineries process crude oil, breaking it down into various constituent parts. The market for refineries therefore depends on the individual markets for the different products obtained from crude. These include19:

• Light distillates, which include gasoline (mainly used as a motor fuel), LPG (liquid petroleum gas – used as a heating fuel) and naphta (used as feedstock for petrochemicals such as plastics and fibres);

• Middle distillates, which include gasoil (heating fuel), diesel (motor fuel), kerosene and jet fuel (aviation);

• Heavy distillates, which are primarily used as heavy fuel oil for industrial applications and bunker fuel for shipping;

19 Commission Staff Working Paper on refining and the supply of petroleum products in the EU, SEC(2010) 1398 final.

http://www.cefic.org/Documents/FactsAndFigures/2012/International-Trade/Facts-and-Figures-2012-Chapter-International-Trade.pdf

http://www.cefic.org/Documents/FactsAndFigures/2012/International-Trade/Facts-and-Figures-2012-Chapter-International-Trade.pdf

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• Speciality products, such as bitumen (used for road asphalt and building materials), waxes, lubricants and greases, as well as coke.

The refining of crude oil will necessarily produce several of these products, in proportions that depend primarily on the crude oil grade and composition (mainly determined by the geographical origin of the crude) and may not reflect local market demand. As such, there is “no one market for all oil products, but rather separated markets with seasonal variations”20.

The trade in refined oil products is therefore important in balancing regional/national refinery supply with demand. Historically, the EU has been a net importer of gasoil/diesel, kerosene/jet fuel and naphta, while it has been a net exporter of gasoline (Figure 7.14). It is thought that this pattern is partially driven by prevalent taxation patterns in the EU, which tend to favour diesel over gasoline21. For heavy fuel oils, the pattern is more complex, with the EU going from net importer in the early to 2000’s to net exporter currently. It is thought this pattern is driven by a change in legislation relating to the sulphur content of marine fuel oil in the Baltic and North Sea, leading to a shift away from heavy fuel oil towards middle distillate grades in European shipping.

Figure 7.14 Evolution of EU Net Imports in Key Petroleum Products, 2000-2008

Source: Commission Staff Working Paper SEC (2010) 1398 final

This trade pattern shows that refining is subject to important international trade, with the EU’s main trade partner being the US. However, this relationship has been under pressure recently as US demand for imported gasoline has decreased due to a range of factors:

• Increasing vehicle efficiency standards in the US;

20 De Boncourt (2013) The European refining crisis: what is at stake for Europe? Ifri actuelles, Paris, March 2013. 21 http://ec.europa.eu/energy/observatory/oil/doc/refining/refining_swp_presentation_141210.pdf

http://ec.europa.eu/energy/observatory/oil/doc/refining/refining_swp_presentation_141210.pdf

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• Increasing use of biogasoline, partly in response to the 2007 US Energy Independence and Security Act;

• Greater US gasoline fuel self-sufficiency deriving from the development of shale gas (cheaper energy for US refineries) and shale oil (high quality feedstock).

For this reason, EU refineries have sought new markets for excess gasoline in Asia, Africa and the Middle East. However, there is doubt as to whether the demand for gasoline will grow sufficiently in these markets to absorb the entire European surplus. Similarly, as demand in these markets increases, so does investment in local refining capacity, thus limiting market opportunities for EU refineries.

Simultaneously, there has been a reported contraction in EU demand for oil products in the EU itself, partly due to greater fuel efficiency standards and exacerbated by the financial crisis8. This has had a negative impact on EU refineries margins, which have also been affected by the EU Emissions Trading System (EU ETS), with refineries using about 25% of CO2 permits8. The ongoing reduction in EU refinery margins is illustrated in Figure 7.15 and Figure 7.16.

Figure 7.15 EU Refinery Margins for Eight Combinations of Region, Crude Feedstock and refining Process (in $/bbl)

Source: IEA

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Figure 7.16 EU Refinery Margins, Cracking and Hydroskimming Averages and Linear Trends (in $/bbl)

Source: Author’s calculations from IEA data

These decreasing margins partially linked to a combination of decreasing domestic demand, overcapacity and over production of gasoline, increasing international competition from both existing producers (US) and emerging ones (Asia, Middle East) has led to some analysts describing the EU refining sector as being in “crisis”, with a reported eleven refineries shutting down and seventeen changing ownership in the last five years8.

As such, it is thought that the international competitiveness of the EU refining industry would stand to be negatively affected by the proposed change in regulation.

To assess the number of potentially affected enterprises, there were 104 refineries in the EU in 2010, with a total refining capacity of 778 million tonnes per year (15.5 million barrels per day), equivalent to 18% of global capacity7. The distribution of these across EU regions is presented in Table 7.16, with Member State figures in Figure 7.17.

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Table 7.16 EU Refineries by Region, by Number and Capacity

Number of Refineries Capacity (mt/year) Capacity (Mbbl/day)

Capacity (% of Total)

North West Europe (NWE) 56 465 9.3 60

Mediterranean (MED) 31 212 4.2 27

Central and Eastern Europe (CEE) 17 101 2 13

TOTAL 104 778 15.5 100

Source: Commission Staff Working Paper SEC(2010) 1398 final

Figure 7.17 EU27 Refineries Numbers and Capacity, in Million Tonnes per Year, by Member State

Source: Commission Staff Working Paper SEC(2010) 1398 final

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7.5.10 Conclusions

There could be some impact from regulating emissions of medium combustion plants on competitiveness, particularly for the industry, food and – possibly – greenhouse sectors. These uses are in sectors that face stiff competition from outside the EU. It is likely that at least a sub-set of these users will have difficulty in passing on costs (cost pass through) to their current markets and in the case of greenhouses there are well established competitors ready to compete from outwith the EU. In food production the increasing commoditisation of the industry creates pressures for some producers and increases in costs will be difficult to pass on, although for both these users relatively high operating surpluses would indicate that there may be some headroom to absorb costs.

Possible mitigation could focus on actions targeted at the specific sectors most likely to face international competition and are likely to be similar to the measures considered for reducing impacts on SMEs. Applying certain exemptions to those sectors / uses facing the greatest international competition could be an option, although quality and product differentiation may protect food and industry from some of the competition. Those arguments may be harder to make for greenhouses who compete with producers in areas with abundant natural sunshine and warmth.

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8. Social Impacts

8.1 Overview The policy options to control emissions from combustion installations <50MWth are likely to result in public health benefits and positive impacts on the level of employment in abatement technology suppliers. There may also be negative implications for employment in the sectors affected as a result of new costs for compliance (including administrative).

8.2 Public Health Benefits Emissions of air pollutants lead to negative impacts on human health and the environment. These impacts have not been assessed within this study as they have been modelled separately by IIASA as part of the wider modelling exercise for the TSAP Review.

8.3 Employment and Labour Markets Implementation of regulations requiring fitting of abatement technology will lead to costs for the firms affected whilst also representing income for firms that manufacture and install these technologies. As discussed in an earlier section considering the supply of abatement technologies, the EU has a well established abatement technology supply chain as the majority of the technologies currently being applied by LCPs are also relevant for these smaller plants.

Where firms are able to pass on costs this will nevertheless have an impact on an overall basket of goods and services that can be consumed for a given level of income and an increase in prices may lead to a decrease in consumption for the good in question and for other unrelated goods because of (effectively) lower incomes. Any reduction in consumption is suggestive of a reduction in employment.

It is unclear how these two effects will balance out but it might be a reasonable assumption that the effect will in aggregate be fairly neutral. Where firms are unable to pass on costs and suffer declines in international competitiveness (see Section 6.1.2) the overall effects are likely to be more pronounced and reduction of production within the EU would imply a reduction of employment also.

These effects are likely to be most pronounced for greenhouse users, the food industry and other industry (coke, metals and chemicals). The table below indicates the scale of employment in the sectors of interest that are identifiable through Eurostat.

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Table 8.1 Employment on Key Economic Sectors at NACE Level 2 (Eurostat)

Sector (NACE Level 2) Employment (Thousands, 2009)

Manufacturing 31,000

Manufacture of food products 4,174

Manufacture of coke and refined petroleum products 133

Manufacture of chemicals and chemical products 1,180

Manufacture of basic metals 1,030

Electric power generation, transmission and distribution 886

As identified above in the discussion of competitiveness (section 6.1.2) key sub sectors such as chemicals have supply chains in the EU and any impact on the sector will affect these supply chains also.

The scale of employment effects from proposed regulation can reasonably be expected to be in relation to the overall cost of regulation, and the detailed option chosen. Options imposing greatest cost having the greatest impact (both positive and negative effects). Attempting to use previous studies exploring the employment effects of, for example, IED and emissions trading run into the difficulty of scale. Previous studies have explored larger scale operations (although ETS applies to many of the >20 MWth plant included in this study) and therefore larger scale operations in predominantly larger firms. The relative scale of combustion plant within the overall operations of the enterprise will have a significant impact on the ability of the enterprise to absorb costs. Moving down the scale to smaller plant would appear to have the effect of imposing costs on more smaller enterprises and this is discussed in detail in the SME section.

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9. Additional modelling support

9.1 Overview The Primary NOx, IED 50-100 MW and Most Stringent MS scenarios, presented in earlier sections, have been assessed on the basis that the ELVs would apply to all plants within scope in a given year, without differentiating between the ages, operating profile or sector of the plant or the timescales for when limits have to be met. Further consideration of this assessment indicated that such an undifferentiated approach may not be optimal in terms of cost-effectiveness or burden sharing amongst plant types. Therefore, additional modelling and analysis has been performed to better understand the potential to reduce the costs and burden on certain groups of plants, while maintaining an environmentally sound outcome.

One aspect of this additional modelling has been to differentiate between new and existing plants. In the two additional scenarios presented in this section, new plants would be required to meet more stringent ELVs than existing plants. The timescale for implementation is also different for new and existing plant, with compliance modelled for new plant from 2018 and existing plant from 2022. These proposals would allow a longer time period for existing plant to retrofit abatement measures within normal investment cycles, and potentially encourage early replacement of aging plant.

The second aspect of additional modelling has been to incorporate an exemption for plant operating less than 300 hours per year. A proportion of plant in the 1-50 MW size range are stand-by or back up plant and are therefore likely to operate for a small number of hours per year. For these plants, the cost of any additional abatement technology at the installation is disproportional to the total annual emissions produced due to the low utilisation. A number of other possible options for exemptions have been investigated as part of this review, including SME based exemptions or derogations and a carbon leakage risk-type approach based on the EU ETS. Low operating hours was selected for quantitative modelling as it has a significant impact on improving cost effectiveness and is consistent with existing exemption options available for LCPs in the IED.

The additional modelling has only assessed the changes in impacts on costs and emissions: wider social and economic impacts are not considered for these scenarios beyond an assessment of how SMEs may be affected by these options (in line with the assessment undertaken for the other options as described in Section 7.3).

In addition to the above, some limited research was undertaken looking at the energy efficiency of different types of combustion plants below 50MWth. This research is presented in Appendix G.

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9.2 Approach

9.2.1 Baseline

MS ELVs were revisited in order to distinguish between ELVs applied for new or existing plant and also to distinguish between ELVs currently imposed and those to be implemented in future years, where such information was available. The general case ELVs were also adjusted, as presented in the following table.

Table 9.1 General Case Emission Levels (applied in the absence of Member State-Specific ELVs)

Technology and Capacity Class

SO2 Emission Levels (mg/Nm3) NOX Emission Levels (mg/Nm3) Dust Emission Levels (mg/Nm3)


Liquid Fuel

Other Gaseous

Fuel


Liquid Fuel

Natural Gas

Other Gaseous

Fuel


Liquid Fuel

Boiler

1-5 MWth 151a 3206 1700 800 978 1226 900 400 400 376 b 376 b 150

5-20 MWth 151 a 2559 1700 800 978 978 900 400 400 376 b 376 b 100

20-50 MWth 151 a 2559 1700 800 978 978 694b 400d 350 376 b 376 b 100d

Other

1-5 MWth 60 c 1270

c 560 264 450 485 c 350 229 233 149 149 b 150

5-20 MWth 60 c 1013

c 560 264 450 387 c 350 229 233 149 149 b 100

20-50 MWth 60 c 1013

c 560 264 450 387 c 229 b 229 233 149 149 b 100

a: CORINAIR guidebook upper range emission factor for small combustion of biomass. b: Second highest existing national ELV. c: Set the same as for boilers, adjusted for the difference in reference O2% (see Table 4.7), in absence of any MS ELVs. d:Adjusted from previous scenario baseline, to ensure larger installations do not have a less stringent ELV than smaller installations.

The baseline emissions were recalculated based on these revised ELVs. The baseline emissions have been calculated for three plant profiles: current-existing, future-existing and future-new. The baseline has been projected forward to 2025 and 2030, combining the relative proportion of each plant profile as relevant for the projection year, by considering plant turnover rates. In order to do so we have assumed an average plant lifetime of 30 years which equates to an annual replacement rate (plant turnover) of 3.3%.

This more detailed approach has resulted in the revised baseline emissions being a little lower than the baseline applied in modelling the previous scenarios. This is due to the more stringent ELVs which are applied in certain MSs for new plant and in future years.

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9.2.2 Costs

The cost differential of installing abatement measures on new plant compared to retrofitting on existing plant has been factored into the compliance costs. In the analysis of the previous scenarios the abatement costs are mid range values which have been assumed to be representative of costs of fitting abatement to existing plant. For the additional scenarios, in which new and existing plant are differentiated, these abatement costs have been reduced when applied to new plant. For primary measures, such as combustion modification, the costs are assumed to be 60% lower for new installations than when retrofitted. For secondary, end-of-pipe, measures the cost for new plant is assumed to be 40% lower than when retrofitted, aligning with the retrofit scaling factor applied for the power sector in the GAINS model.

Administrative costs are assumed to be the same as described previously and have therefore not been revisited as part of this additional modelling exercise.

9.2.3 Scenarios

Two additional scenarios have been modelled.

Table 9.2 Overview of ELV Options

ELV Option Summary

Gothenburg A variant of the Primary NOx scenario where the ELVs for NOX have been aligned to those set out in the amended Gothenburg Protocol (these affect new “others”). The ELVs for SO2 and PM are the same as under the IED 50-100 MW scenario.

SULES The ELVs for existing plant are as in the Gothenburg scenario, whereas the ELVs for new plant have been set at the level of the most stringent MS existing or future ELV.

In each, the main differences compared to the previous scenarios are:

• ELVs for new plant enter force in 2018 and a longer implementation deadline of 2022 is set for existing plant.

• Plant operating less than 300 hours per annum are exempt from complying with the ELVs.

• The lower cost of installing abatement to new plant compared to retrofitting to existing plant is accounted for.

For the previous modelling, the MSs existing ELVs were extracted so as to be used to develop the baseline. The previous MS most stringent ELVs were based on the existing ELVs. There are lower future ELVs, therefore the revised most stringent MS ELVs used for the SULES scenario are lower than those used for the MS most stringent scenario presented in the previous sections.

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Table 9.3 Revised Most Stringent Member State ELVs used in the SULES Option


Biomass

Other Solid Fuel

Liquid Fuel

Other Gaseous

Fuel


Liquid Fuel

Natural Gas

Other Gaseous

Fuel


Liquid Fuel

Boiler


1-5 151 a 200 200 5 200 100 120 70 70 b 8 5 b 5

5-20 151 a 200 200 5 145 100 120 70 70 b 5 5 b 5

20-50 151 a 200 200 5 145 100 120 70 70 b 5 5 b 5

Other


1-5 n/a n/a 66 2 n/a n/a 46 33 48 n/a n/a 3

5-20 n/a n/a 66 2 n/a n/a 46 33 33 n/a n/a 3

20-50 n/a n/a 66 2 n/a n/a 46 33 33 n/a n/a 3

a: aligned to general case ELV.

b: revised to correspond with more stringent future/new ELV.

In each of these two scenarios a derogation to exempt plant operating for less than 300 hours per year has been modelled. In order to assess the impact of this derogation, assumptions have been made for the average operating hours of plants, distinguishing between those which operate under 300 hours and those which are not exempt. We have assumed 17.5% of plants would be eligible for this exemption, based on estimates made from UK and NL data. This leads to a reduction in costs of this same percentage, whereas emission reductions only decrease (as a result of not having to meet the scenario ELVs) by 1% based on our modelling.

9.2.4 SME impacts

A full assessment of potential impacts of these additional scenarios on SMEs has not been undertaken as the main impacts are already described in Section 7.3. However, the inclusion of a derogation for low annual operating hour plants and phased implementation for new and existing plants in these two scenarios should reduce overall impacts on all plants, including SMEs. Whilst we have not undertaken a new assessment as such, a comparison of potential costs associated with each option relative to gross operating surplus (GOS) has been carried out (in line with the assessment undertaken for the other options as described in Section 7.3).

9.3 Results The emissions and costs results in this section are presented for the year 2025. As already indicated, these additional two scenarios apply different compliance start dates of 2018 and 2022 for new and existing plant respectively. Therefore, to assess this impact the cumulative costs and benefits for the transition period, or a year on year summary of the impacts, need to be considered. Therefore graphs are also presented to show the annual impacts.

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9.3.1 Emissions

A summary of the remaining EU emissions arising from 1-50 MW combustion plant under each of the additional two scenarios, adjusted for the exclusion of plant with low annual operating hours, are presented in the following tables. The emissions calculated for the revised baseline (“Current Legislation”) are also presented.

Table 9.4 SO2 Emissions (ktonnes)

2025

Capacity Class Current Legislation Gothenburg SULES

1-5 MW 58 13 11

5-20 MW 67 13 12

20-50 MW 49 14 13

TOTAL 1-50 MW 174 39 37

Table 9.5 NOX Emissions (ktonnes)

2025

Capacity Class

Current Legislation Gothenburg SULES

1-5 MW 170 131 112

5-20 MW 188 140 119

20-50 MW 98 78 66

TOTAL 1-50 MW 455 348 297

Table 9.6 Dust Emissions (ktonnes)

2025

Capacity Class Current Legislation Gothenburg SULES

1-5 MW 13 1 1

5-20 MW 20 1 1

20-50 MW 15 1 1

TOTAL 1-50 MW 49 4 3

The following graph presents the year on year impact on SO2 emissions for the Gothenburg scenario. There is an equivalent relationship between new and existing plant over these years for NOX and PM, and the SULES scenario.

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Figure 9.1 Year on year emission reductions for new and existing plant under Gothenburg scenario

9.3.2 Compliance costs

A summary of the costs for the additional two scenarios, adjusted for the exclusion of plant with low annual operating hours, is presented in the following table.

Table 9.7 Average total annualised compliance costs (€m/year)

Pollutant 2025

Capacity Class Gothenburg SULES

SO2 1-5 MW 83 100

5-20 MW 72 80

20-50 MW 28 30

TOTAL 1-50 MW 183 210

NOX 1-5 MW 36 187

5-20 MW 36 178

20-50 MW 12 91

TOTAL 1-50 MW 83 456

Dust 1-5 MW 46 46

5-20 MW 42 45

0

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80

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120

140

160

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2018

2019

2020

2021

2022

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2027

2028

2029

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2035

2036

2037

2038

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2040

2041

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2046

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2049

2050

SO2

emiss

ions

red

uctio

n (k

tonn

es/y

ear)

Existing New

102


Pollutant 2025

Capacity Class Gothenburg SULES

20-50 MW 28 35

TOTAL 1-50 MW 115 125

Total 1-5 MW 164 332

5-20 MW 149 302

20-50 MW 68 156

TOTAL 1-50 MW 382 791

The figure below presents the year on year compliance costs for the Gothenburg scenario. Total compliance costs increase slightly each year as existing plants are replaced by new plants as the ELVs for new plants are more stringent.

Figure 9.2 Year on year compliance costs for new and existing plant under Gothenburg scenario

The costs are further disaggregated by new and existing plants and by combustion plant type in the table below.

0

50

100

150

200

250

300

350

400

450

500

2017

2018

2019

2020

2021

2022

2023

2024

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2027

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2046

2047

2048

2049

2050

Tota

l ann

ualis

ed c

osts

(€m

/yea

r)

Existing New

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Table 9.8 Average total annualised compliance costs disaggregated by new and existing plants and by plant type for 2025 (€m/year)

Pollutant / Scenario Category New boilers Existing

boilers New engines

& turbines Existing engines

& turbines Total

NOx

Gothenburg

1-5 MW 3 6 19 7 36

5-20 MW 2 6 21 7 36

20-50 MW 1 2 7 2 12

TOTAL 1-50 MW 7 13 47 16 83

SULES

1-5 MW 148 6 26 7 187

5-20 MW 138 6 28 7 179

20-50 MW 73 2 15 2 91

TOTAL 1-50 MW 359 13 68 16 456

SO2

Gothenburg

1-5 MW 12 47 5 19 83

5-20 MW 12 41 4 15 72

20-50 MW 5 15 2 7 28

TOTAL 1-50 MW 29 103 11 41 183

SULES

1-5 MW 25 47 8 19 100

5-20 MW 18 41 6 15 80

20-50 MW 6 15 2 7 30

TOTAL 1-50 MW 50 103 16 41 210

PM

Gothenburg

1-5 MW 8 26 3 10 46

5-20 MW 7 22 2 9 42

20-50 MW 5 15 2 7 28

TOTAL 1-50 MW 20 63 7 26 115

SULES

1-5 MW 8 26 2 10 46

5-20 MW 11 22 2 9 45

20-50 MW 12 15 1 7 35

TOTAL 1-50 MW 32 63 5 26 125

Note figures rounded.

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The average costs per plant are summarised in the table below. It should be noted that these figures are for the EU as a whole, the actual costs per plant will wary considerably depending on any actions already taken e.g. in response to existing national legislation.

Table 9.9 Average total annualised compliance costs per plant in 2025 (€/plant)

Pollutant / Scenario Category New boilers Existing

boilers New engines

& turbines Existing engines

& turbines Average

NOx

Gothenburg

1-5 MW 140 90 3,100 440 310

5-20 MW 440 410 16,000 2,000 1,500

20-50 MW 1,100 590 25,100 2,400 2,300

AVERAGE 1-50 MW 220 160 6,100 780 580

SULES

1-5 MW 6,000 90 4,200 440 1,600

5-20 MW 26,900 410 21,600 2,000 7,500

20-50 MW 63,300 590 51,200 2,400 17,100

AVERAGE 1-50 MW 11,600 160 8,900 780 3,200

SO2

Gothenburg

1-5 MW 470 710 810 1,200 730

5-20 MW 2,400 2,900 3,100 4,300 3,000

20-50 MW 4,200 4,800 6,000 8,600 5,300

AVERAGE 1-50 MW 930 1,200 1,400 2,000 1,300

SULES

1-5 MW 1,000 710 1,300 1,200 880

5-20 MW 3,600 2,900 4,500 4,300 3,300

20-50 MW 5,500 4,800 7,400 8,600 5,700

AVERAGE 1-50 MW 1,600 1,200 2,100 2,000 1,500

PM

Gothenburg

1-5 MW 310 390 450 580 400

5-20 MW 1,400 1,600 1,900 2,700 1,700

20-50 MW 4,100 4,900 6,700 8,500 5,300

AVERAGE 1-50 MW 630 760 920 1,200 810

SULES

1-5 MW 340 390 360 580 400

5-20 MW 2,200 1,600 1,300 2,700 1,900

20-50 MW 10,700 4,900 3,000 8,500 6,600

AVERAGE 1-50 MW 1,000 760 610 1,200 880

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9.3.3 SME impacts

An assessment of how compliance and administrative costs of these additional scenarios compare to GOS for small and medium sized enterprises has been undertaken in line with the assessment described in Section 7.3. The results are presented in the table below. It should be noted that administrative costs applied in these calculations (associated with permitting and non-permitting options) are the same as calculated for the previous scenarios.


Enterprise Size Gothenburg SULES

Permitting Non-Permitting Permitting Non-Permitting

Small 1-5 MWth 1% 0% 1% 1%

5-20 MWth 2% 2% 4% 3%

20-50 MWth 2% 2% 5% 5%

Medium 1-5 MWth 0% 0% 0% 0%

5-20 MWth 0% 0% 1% 1%

20-50 MWth 1% 1% 1% 1%


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10. Discussion

10.1 Overview The figures below present the emission forecasts from 1-50 MWth plants for EU27 in 2025 for each ELV option considered in 2025. For SO2, all of the options considered are predicted to reduce emissions significantly from the baseline (BAU) with the Most Stringent MS scenario leading to the lowest emissions. A similar picture is shown for dust. For NOx, however, there is considerably more variation between scenarios reflecting the differences in stringency of the ELVs assumed in the modelling. For both the Most Stringent MS and IED 50-100 MW scenarios, emissions are considerably lower than the other scenarios.

Figure 10.1 SO2 emissions (2025) Figure 10.2 NOx emissions (2025)

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BAU

IED

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00 M

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1-5 MW

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Figure 10.3 Dust emissions(2025)

The table below presents the same data but in tabular form.

Table 10.1 SO2, NOx and Dust Emissions (ktonnes)

2010 2025

Capacity Class

Current Legislation

Current Legislation

(Note 1)

Primary NOx

IED 50-100 MW

Most Stringent

MS

Gothenburg SULES

S02

1-5 MW 103 61 13 13 9 13 11

5-20 MW 130 72 17 17 12 13 12

20-50 MW 68 48 17 17 14 14 13

1-50 MW 301 181 47 47 35 39 37

NOX

1-5 MW 210 179 140 63 46 131 112

5-20 MW 227 194 149 62 47 140 119

20-50 MW 117 97 90 42 24 78 66

1-50 MW 554 470 379 167 117 348 297

Dust

1-5 MW 17 16 2 2 1 1 1

5-20 MW 20 19 2 2 1 1 1

20-50 MW 16 14 2 2 1 1 1

1-50 MW 53 48 6 6 3 4 3

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1-5 MW

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Note 1: The Current Legislation scenario differs slightly for the Gothenburg and SULES scenarios due to updates to the modelling to split out new and existing plants in the assessment year. See Section 9 for further details.

The figures below present the total compliance costs by pollutant and by size category for 2025. The Most Stringent MS ELV scenario is the most costly by far relative to the other options (over €3 billion per year) with the IED 50-100 MW ELV scenario next at over €2 billion per year. For both of these options the costs are dominated by the costs of compliance with the NOx ELVs reflecting the fact that they would require more costly secondary abatement measures to comply. The remaining ELV scenarios are considerably cheaper as the limits for NOx (at least for existing plants) have been set at a level where primary measures are expected to be sufficient to achieve compliance. The SULES scenario includes a requirement for new plants to meet more stringent ELVs than the Primary NOx or Gothenburg scenarios hence why costs are higher.

Figure 10.4 Total Compliance Costs by pollutant Figure 10.5 Total Compliance Costs by Size Category


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2025 2025 2025 2025 2025

(€m

/yea

r)

PM

NOX

SO2

-

500

1,000

1,500

2,000

2,500

3,000

3,500

Prim

ary N

Ox

IED

50-1

00 M

W

Mos

t str

inge

nt M

S

Goth

enbu

rg

SULE

S

2025 2025 2025 2025 2025

(€m

/yea

r)

20-50 MW

5-20 MW

1-5 MW

109


Table 10.2 Average total annualised compliance costs for 2025 (€m/year)

Capacity Class Primary NOx IED 50-100 MW Most Stringent MS

Gothenburg SULES

SO2

1-5 MW 90 90 210 83 100

5-20 MW 68 68 123 72 80

20-50 MW 27 27 44 28 30

1-50 MW 185 185 377 183 210

NOx

1-5 MW 27 821 1,119 36 187

5-20 MW 18 785 1,018 36 178

20-50 MW 3 311 543 12 91

1-50 MW 48 1,918 2,680 83 456

Dust

1-5 MW 55 55 84 46 46

5-20 MW 41 41 77 42 45

20-50 MW 27 27 77 28 35

1-50 MW 123 123 239 115 125

Total

1-5 MW 171 966 1,413 164 332

5-20 MW 127 895 1,218 149 302

20-50 MW 57 365 665 68 156

1-50 MW 355 2,225 3,296 382 791

The figure below presents compliance and administrative costs combined for each of the ELV scenarios and regulatory options. Administrative costs for the non-permitting administrative scenario are small relative to the compliance costs for each of the ELV scenarios. However, for the permitting scenario, administrative costs contribute a much greater proportion to total costs, particularly for those ELV scenarios where compliance costs are lowest i.e. Primary NOx, Gothenburg and SULES. For example, for both the Primary NOx and Gothenburg ELV scenarios administrative costs contribute more than 40% towards total costs.

110


Figure 10.6 Total Annualised Costs (2025)


Table 10.3 Total Annualised Costs for 2025 (€m/year, Figures Rounded for Presentation Purposes)

ELVs Primary NOx IED 50-100 MW Most Stringent MS Gothenburg SULES




Permit.

1-5 MW Admin cost[1] 200 20 200 20 200 20 200 20 200 20

Compliance cost

170

170

970

970

1,410

1,410 160 160 330 330

Total cost 370

200

1,170

990

1,620

1,440 360 180 530 350

5-20 MW Admin cost[1] 60 10 60 10 60 10 60 10 60 10

Compliance cost

130

130

890

890

1,220

1,220 150 150 300 300

Total cost 190

140

960

910

1,280

1,230 210 160 360 310

-

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000


Most stringent MS

Gothenburg SULES Primary NOx IED 50-100 MW

Most stringent MS

Gothenburg SULES


(€m

/yea

r)




111


ELVs Primary NOx IED 50-100 MW Most Stringent MS Gothenburg SULES




Permit.

20-50 MW Admin cost[1] 10 0 10 0 10 0 10 0 10 0

Compliance cost

60

60

360

360

660

660 70 70 160 160

Total cost 70

60

380

370

680

670 80 70 170 160

TOTAL 1-50 MW

Admin cost[1] 280 40 280 40 280 40 280 40 280 40

Compliance cost

360

360

2,230

2,230

3,300

3,300 380 380 790 790

Total cost 630

400

2,500

2,270

3,570

3,340 660 420 1,070 830

Note [1]: Administrative costs include those for both operators and authorities.

The SME assessment has revealed that a relatively high proportion of 1-50 MWth combustion plants are operated by SMEs. Furthermore, smaller enterprises in particular could be affected most from a financial perspective relative to medium and large enterprises. A number of possible options for mitigating measures are described and discussed in Section 7.3.5 of the report. In addition, for the Gothenburg and SULES scenarios, the modelling has included differentiated ELVs and phased implementation for new and existing plants as well as a low annual operating hour exemption all of which are intended to reduce unnecessary burden on all plants including SMEs. The table below summarises the impact of the options on small and medium enterprises as a proportion of Gross Operating Surplus (GOS)


Enterprise Size

ELV option Primary NOx IED 50-100 MWth ELVs

Most stringent MS

Gothenburg SULES

Regulatory option Permit Non-



Permit

Small 1-5 MWth 1% 0% 2% 3% 3% 3% 1% 0% 1% 1%

5-20 MWth 2% 2% 10% 10% 14% 13% 2% 2% 4% 3%

20-50 MWth 2% 2% 12% 12% 22% 21% 2% 2% 5% 5%

Medium 1-5 MWth 0% 0% 1% 0% 1% 1% 0% 0% 0% 0%

5-20 MWth 0% 0% 2% 2% 3% 3% 0% 0% 1% 1%

20-50 MWth 1% 1% 3% 3% 6% 5% 1% 1% 1% 1%


112


10.2 Comparison of options The previous section provides an overview of total emissions and costs for each of the ELV and administrative options. The table below provides a summary of the emission reductions associated with each ELV option relative to the baseline for 2025 i.e. no EU action. For both SO2 and dust, all of the options considered are predicted to reduce emissions from the baseline (BAU) by similar amounts with the Most Stringent MS scenario resulting in the greatest reductions. For NOx, however, there is considerably more variation between scenarios reflecting the differences in stringency of the ELVs assumed in the modelling. For both the Most Stringent MS and IED 50-100 MW scenarios, emission reductions are two to three times greater than those for other scenarios.

Table 10.5 Emission reduction compared to baseline for 2025 (kt/year)

Pollutant Primary NOx IED 50-100 MW Most Stringent MS

Gothenburg SULES

SO2 134 134 145 135 137

NOx 92 304 353 107 159

Dust 43 43 46 45 45

Table 10.6 presents a summary of the cost effectiveness of the ELV scenarios for 2025 (calculated as the compliance cost divided by the associated emissions reduction for each pollutant). These costs represent compliance costs; the cost of installing and operating abatement measures targeted at reducing emissions of the corresponding pollutant. Administrative costs are not included as these costs would be applicable for the three pollutants.

Table 10.6 Abatement cost (€) per tonne of Pollutant Reduced (2025)


SO2 1-5 MW 1,900 1,900 4,100 1,800 2,100

5-20 MW 1,300 1,300 2,100 1,300 1,500

20-50 MW 800 800 1,300 800 900

1-50 MW 1,400 1,400 2,600 1,400 1,500

NOX 1-5 MW 700 7,100 8,400 900 3,200

5-20 MW 400 5,900 6,900 700 2,600

20-50 MW 400 5,700 7,400 600 2,900

1-50 MW 500 6,300 7,600 800 2,900

Dust 1-5 MW 4,100 4,100 5,900 3,700 3,800

5-20 MW 2,300 2,300 4,200 2,200 2,300

113



20-50 MW 2,300 2,300 5,900 2,100 2,500

1-50 MW 2,900 2,900 5,200 2,500 2,800

The figures below present the abatement cost per tonne of pollutant associated with the reductions of SO2, NOX and dust which could be achieved under each ELV scenario.

Figure 10.7 Costs of achieving SO2 reduction in 2025 (€/tonne)

-

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500


Most stringent MS

Gothenburg SULES

€/to

nne

1-5 MW

5-20 MW

20-50 MW

114


Figure 10.8 Costs of achieving NOX reduction in 2025 (€/tonne)

Figure 10.9 Costs of Achieving Dust Reduction in 2025 (€/tonne)

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000


Gothenburg SULES

€/to

nne

1-5 MW

5-20 MW

20-50 MW

0

1,000

2,000

3,000

4,000

5,000

6,000


Gothenburg SULES

€/to

nne

1-5 MW

5-20 MW

20-50 MW

115


The cost effectiveness for SO2 and PM emissions for the Primary NOx, IED 50-100 MW, Gothenburg and SULES scenarios are relatively which is to be expected considering the similarity in ELVs applied for these pollutants for these options. The significant difference is for NOX, where the cost effectiveness of the Primary NOx and Gothenburg are considerably lower than for the other options. The IED 50-100 MW and Most Stringent MS scenarios are significantly higher than all options with the SULES option in between these more costly options and the cheapest ones (Primary NOx / Gothenburg).

10.3 Uncertainties and Limitations As with any study of this nature, there are a number of uncertainties and limitations which should be taken into account when reviewing the results of the assessment. These are described below against the key areas.

Input Data

Inevitably, the development of a dataset on combustion plants 1-50 MWth that is based only partially on data provided by Member States and has necessarily relied on extrapolation to cover missing Member States and other data points has a number of uncertainties and limitations associated with it. The principle points to note which should be considered when reviewing the results of the assessment of control options are:

• Greater uncertainty is associated with the data and results for smaller capacity classes due to their reliance on a greater proportion of extrapolation;

• Some Member States provided data that was marked as being rough or approximate and in some cases is questionable over the realism of the figures. Gross estimates for some of the larger Member States of the EU could have a disproportionate effect on the overall figures (which are presented at EU level), and may unfortunately mask figures that may be more robust for some of the EU’s smaller Member States;

• Very limited information has been provided on sectoral breakdown and technology split so for many MSs an average split has had to be applied;

• In a number of cases the ELVs that have been provided by certain Member States have been defined for technology / capacity / fuel categories which do not directly match those used in this assessment. Therefore these ELVs have been mapped against the categories used in this study as far as possible;

• Certain similar abatement techniques were combined into one group and the range of data for all sub-types used to establish the data for the abatement technique (e.g. different types of combustion modification have been grouped into one measure). For certain plant one sub-type may be more suitable than another from within the group.

Modelling

In addition to the input data, the modelling approach has had to involve a number of assumptions in order to evaluate the different options:

116


• A simplistic approach to estimating potential abatement costs has been applied using average technology values for different size plants. As with any abatement techniques, costs can vary significantly for an individual plant depending upon its unique circumstances.

• Simplistic approach for projecting emission reductions and costs:

- A relatively simplistic approach has been adopted to develop projections at short notice for feeding into IIASA’s GAINS model which is being used to investigate the overall costs and benefits of a range of options as part of the overall review of the TSAP. As described in Section 5.4.2, all of the modelling of costs and emission reductions has been done on a current estimated plant stock (numbers, capacity, emissions etc.) dataset and then these have been projected forward to 2025 and 2030 using PRIMES 2012 fuel consumption data for GAINS sectors.

- As a result of the approach described above, future ELVs being introduced by some MSs for existing plant (e.g. NL) were not taken into account in the base year for the modelling undertaken during the initial main contract (as they do not yet apply). Under a particular scenario, a MS may be modelled to require emission reductions and associated costs even though its future ELVs might be in line with, or tighter than, the scenario limits. The result of this is that the overall costs and benefits may be overstated for some MSs in terms of allocation to the options considered in this report (although they would still need to be incurred by operators). However, as part of the additional modelling follow-on contract (described in Section 9) this was updated so that these latter scenarios do take into account future MS ELVs that may apply.

• The sectoral and technology type breakdown of potential impacts is based on very limited data provided by a small number of MSs;

• The administrative cost assessment assumes a static number of plants from now until 2030 in the absence of any data on how this may change (total fuel consumption decreases by 13% over this period using the PRIMES 2012 / GAINS data for combustion overall but this has been assumed to be related to energy efficiency improvements rather than a decline in plant numbers). Some MSs have reported that they expect the number of smaller plants to increase as there is a push for more decentralised heat and power supply. This could lead to an underestimation of the potential administrative costs;

• No account has been taken for stand-by or back up plant being included in the numbers of plant used in the scenarios assessed in the main contract. Such plants contribute to a small proportion of emissions due to their limited operating hours. Installing abatement on such plant will therefore result in limited emission reduction, however the cost of installing the abatement measure will be similar to when fitted to plant with higher operating time. If such plants are exempt from complying with the ELVs, as is the case under certain Member State legislation, then installation of abatement would not be required. In which case the overall cost associated with compliance will reduce, whereas the change in emission reduction will be lower. If this was factored into the assessment the EU-wide cost per tonne of pollutant would be lower than presented in Table 10.6. As part of the additional modelling follow-on contract (described in Section 9) we have attempted to model the potential impacts of a derogation for plants operating less than 300 hours per year and this has been taken into account in the results presented for those two scenarios (Gothenburg and SULES).

The estimated costs and benefits identified are presented as indicative figures but which are known to not take all possible costs and benefits into account. For example, the assessment of the IED option does not consider the additional costs to installations of meeting IED requirements wider than those associated with emissions to air (e.g.

117


emissions to water, soil contamination) beyond the possible need for undertaking a soil and groundwater baseline survey when applying for a permit. However, it is considered that the primary costs for the installations considered will be associated with the regulation of emissions to air.

118


11. References

AEA (2007) Assessment of the benefits and costs of the potential application of the IPPC Directive (EC/96/61) to industrial combustion installations with 20-50 MW rated thermal input. Final Report to the European Commission. Available from: http://www.cafe-cba.org/assets/ippc_ec_thernal_input.pdf

AMEC (2013) Multi Pollutant Measures Database. Currently being revised. Last published version available at http://archive.defra.gov.uk/environment/quality/air/airquality/publications/airqual-climatechange/documents/measures-database.pdf

AMEC (2012) Collection and analysis of data to support the Commission in reporting in line with Article 73(2)(a) of Directive 2010/75/EU on industrial emissions on the need to control emissions from the combustion of fuels in installations with a total rated thermal input below 50 MW. Final Report for the European Commission.

AMEC (2012b) Analysis and summary of the Member States' emission inventories 2007-2009 and related information under the LCP Directive (2001/80/EC). Final Report for the European Commission.

ECN (2008) Onderbouwing actualisatie BEES B: Kosten en effecten van de voorgenomen wijziging van het besluit emissie-eisen stookinstallaties B. Available from: http://www.ecn.nl/docs/library/report/2008/e08020.pdf

EGTEI (2010) Options for limit values for emissions of dust from small combustion installations < 50 MWth. Available from: http://www.unece.org/fileadmin/DAM/env/documents/2010/eb/wg5/wg47/Informal%20documents/Info.%20doc%209_Options%20for%20PM%20ELVs%20for%20SCI%20%20final.pdf

Entec (2009) Study to inform on-going discussions on the proposal for a Directive on industrial emissions. Part 1: Combustion Activities. Final Report to the European Commission.

Finland’s environmental administration (2003) (Summary of) Best Available Techniques in Small 5-50 MW Combustion Plants in Finland. provided by personal communication with Competent Authority, 22.12.2008. Available in Finnish at http://www.environment.fi/default.asp?contentid=23847&lan=fi

IIASA, 2013, Personal Communication 25/01/13

JRC (2007) Small combustion installations: Techniques, emissions and measures for emission reduction. Joint Research Centre. Available from: http://publications.jrc.ec.europa.eu/repository/handle/111111111/229

VITO (2011) Beste Beschikbare Technieken (BBT) voor nieuwe, kleine en middelgrote stookinstallaties, stationaire motoren en gasturbines gestookt met fossiele brandstoffen. Available from: http://www.emis.vito.be/bbt-studie-stookinstallaties-en-stationaire-motoren-nieuwe-kleine-en-middelgrote

A1


Appendix A Abatement Matrices

The following tables present information used in this assessment on the abatement measures potentially available for reducing emissions of SO2, NOX or PM from combustion plant.

Table A.1 Abatement matrix for boilers 1-5 MWth plants

Fuel(s) Pollutant Measure SO2 abatement

(%)

NOX abatement

(%)

Dust abatement

(%)

Total annualised cost

LOW (€/plant)


HIGH (€/plant)

Biomass Dust Cyclone 0% 0% 65% € 2,699 € 2,811

Biomass Dust Fabric filter 0% 0% 99% € 2,768 € 6,617

Biomass NOX Combustion modification - assumed EGR

0% 30% 0% € 834 € 834

Biomass NOX SNCR 0% 35% 0% € 576 € 3,666

Biomass NOX SCR 0% 80% 0% € 720 € 32,588

Biomass SO2 Wet FGD 94% 0% 100% € 8,624 € 8,624

Liquid fuels Dust Cyclone 0% 0% 65% € 1,645 € 2,753

Liquid fuels Dust Fabric filter 0% 0% 99% € 2,740 € 5,080

Liquid fuels NOX

Combustion modification - assumed EGR

0% 30% 0% € 834 € 834

Liquid fuels NOX SNCR 0% 35% 0% € 455 € 3,666

Liquid fuels NOX SCR 0% 80% 0% € 607 € 29,935

Liquid fuels SO2 Dry FGD 70% 0% 0% € 2,291 € 2,384

Liquid fuels SO2

Fuel switch to 0.1% gas oil 90% 0% 0% € 38,356 € 38,356

Liquid fuels SO2 Wet FGD 94% 0% 99% € 10,280 € 10,280

Natural gas NOX Low NOx burner 0% 30% 0% € 207 € 207

Natural gas NOX SNCR 0% 35% 0% € 251 € 3,666

Natural gas NOX SCR 0% 80% 0% € 546 € 24,844

A2



(%)

NOX abatement

(%)

Dust abatement

(%)


LOW (€/plant)


HIGH (€/plant)

Other gaseous fuels

NOX Low NOx burner 0% 30% 0% € 207 € 207

Other gaseous fuels

NOX SNCR 0% 35% 0% € 235 € 3,666

Other gaseous fuels

NOX SCR 0% 80% 0% € 546 € 24,435

Other gaseous fuels

SO2 Dry FGD 70% 0% 0% € 1,053 € 1,137

Other gaseous fuels

SO2 Wet FGD 94% 0% 100% € 11,027 € 11,027

Other solid fuels Dust Cyclone 0% 0% 65% € 2,699 € 2,811

Other solid fuels Dust Fabric filter 0% 0% 99% € 2,768 € 6,617

Other solid fuels NOX


0% 30% 0% € 834 € 834

Other solid fuels NOX SNCR 0% 35% 0% € 771 € 3,666

Other solid fuels NOX SCR 0% 80% 0% € 805 € 37,324

Other solid fuels SO2 Co-fire biomass 20% 0% 0% € 14,952 € 14,952

Other solid fuels SO2

Fuel switch to low sulphur coal 50% 0% 0% € 5,360 € 5,360

Other solid fuels SO2 Dry FGD 70% 0% 0% € 4,431 € 4,554

Other solid fuels SO2 Wet FGD 94% 0% 100% € 9,946 € 9,946


Fuel switch to natural gas 100% 50% 99% € 80,887 € 80,887

A3




(%)

NOX abatement

(%)

Dust abatement

(%)


LOW (€/plant)


HIGH (€/plant)




0% 30% 0% € 5,121 € 5,121

Biomass NOX SNCR 0% 40% 0% € 3,682 € 32,997

Biomass NOX SCR 0% 85% 0% € 4,603 € 154,034




Liquid fuels NOX


0% 30% 0% € 834 € 834

Liquid fuels NOX SNCR 0% 40% 0% € 2,910 € 32,997

Liquid fuels NOX SCR 0% 80% 0% € 3,880 € 137,066


Liquid fuels SO2



Natural gas NOX Low NOx burner 0% 30% 0% € 832 € 832

Natural gas NOX SNCR 0% 40% 0% € 1,574 € 32,997

Natural gas NOX SCR 0% 80% 0% € 3,714 € 101,900

Other gaseous fuels

NOX Low NOx burner 0% 30% 0% € 832 € 832

Other gaseous fuels

NOX SNCR 0% 40% 0% € 1,574 € 32,997

Other gaseous fuels

NOX SCR 0% 80% 0% € 3,714 € 101,900

Other gaseous fuels

SO2 Dry FGD 75% 0% 0% € 6,736 € 7,270

A4



(%)

NOX abatement

(%)

Dust abatement

(%)


LOW (€/plant)


HIGH (€/plant)

Other gaseous fuels

SO2 Wet FGD 94% 0% 99% € 51,977 € 51,977





0% 30% 0% € 5,121 € 5,121

Other solid fuels NOX SNCR 0% 40% 0% € 4,116 € 32,997

Other solid fuels NOX SCR 0% 85% 0% € 5,145 € 162,937








A5



Fuel(s) Pollutant

Measure SO2 abatement

(%)

NOX abatement

(%)

Dust abatement

(%)


LOW (€/plant)


HIGH (€/plant)




0% 30% 0% € 11,834 € 11,834

Biomass NOX SNCR 0% 45% 0% € 8,191 € 185,659

Biomass NOX SCR 0% 90% 0% € 10,239 € 403,498




Liquid fuels NOX


0% 30% 0% € 834 € 834




Liquid fuels SO2



Natural gas NOX Low NOx burner 0% 30% 0% € 2,877 € 2,877



Other gaseous fuels

NOX Low NOx burner 0% 30% 0% € 2,877 € 2,877

Other gaseous fuels

NOX SNCR 0% 45% 0% € 3,100 € 185,659

Other gaseous fuels

NOX SCR 0% 85% 0% € 7,764 € 281,014

Other gaseous fuels

SO2 Dry FGD 80% 0% 0% € 14,983 € 16,172

A6


Fuel(s) Pollutant

Measure SO2 abatement

(%)

NOX abatement

(%)

Dust abatement

(%)


LOW (€/plant)


HIGH (€/plant)

Other gaseous fuels

SO2 Wet FGD 94% 0% 100% € 57,970 € 57,970





0% 30% 0% € 11,834 € 11,834









Fuel switch to natural gas 100% 50% 99% € 1,150,444 € 1,150,444

A7


Table A.4 Abatement matrix for other technologies for 1-5 MWth plants


(%)

NOX abatement

(%)

Dust abatement

(%)


LOW (€/plant)


HIGH (€/plant)



Biomass NOX SNCR 0% 35% 0% € 333 € 3,666


0% 40% 0% € 4,724 € 5,362

Biomass NOX SCR 0% 90% 0% € 607 € 29,935


Liquid fuels

Dust Cyclone 0% 0% 65% € 1,645 € 2,753

Liquid fuels

Dust Fabric filter 0% 0% 95% € 2,124 € 6,517

Liquid fuels

Dust ESP 0% 0% 97% € 15,854 € 16,030

Liquid fuels

NOX SNCR 0% 35% 0% € 455 € 3,666

Liquid fuels

NOX Water injection 0% 60% 0% € 4,724 € 5,362

Liquid fuels

NOX SCR 0% 85% 0% € 607 € 29,935

Liquid fuels

NOX NSCR 0% 94% 0% € 1,973 € 1,973

Liquid fuels

SO2 Dry FGD 70% 0% 0% € 1,983 € 2,076

Liquid fuels

SO2 Fuel switch to 0.1% gas oil 90% 0% 0% € 38,356 € 38,356

Liquid fuels

SO2 Wet FGD 94% 0% 99% € 9,971 € 9,971

Natural gas

Dust ESP 0% 0% 97% € 15,854 € 16,030

Natural gas

NOX SNCR 0% 35% 0% € 446 € 3,666

Natural gas

NOX Low NOx burner / Advanced lean burn

0% 50% 0% € - € 1,668

Natural gas

NOX Water injection 0% 60% 0% € 4,724 € 5,362

Natural gas

NOX SCR 0% 70% 0% € 1,653 € 24,844

Natural gas

NOX NSCR 0% 94% 0% € 2,951 € 4,864

A8



(%)

NOX abatement

(%)

Dust abatement

(%)


LOW (€/plant)


HIGH (€/plant)

Other gaseous fuels

NOX SNCR 0% 35% 0% € 713 € 3,666

Other gaseous fuels

NOX Low NOx burner / Advanced lean burn

0% 40% 0% € - € 1,668

Other gaseous fuels

NOX SCR 0% 70% 0% € 1,653 € 31,865

Other gaseous fuels

NOX NSCR 0% 94% 0% € 2,951 € 4,864

Other gaseous fuels

SO2 Dry FGD 70% 0% 0% € 9,102 € 9,355

Other gaseous fuels

SO2 Wet FGD 94% 0% 100% € 16,539 € 16,539

Other solid fuels

Dust Cyclone 0% 0% 65% € 2,699 € 2,811

Other solid fuels

Dust Fabric filter 0% 0% 99% € 2,768 € 6,617

Other solid fuels

NOX SNCR 0% 35% 0% € 771 € 3,666

Other solid fuels

NOX Combustion modification - assumed EGR

0% 50% 0% € 1,052 € 1,052

Other solid fuels

NOX SCR 0% 80% 0% € 805 € 37,324

Other solid fuels

SO2 Co-fire biomass 20% 0% 0% € 14,952 € 14,952

Other solid fuels

SO2 Fuel switch to low sulphur coal 50% 0% 0% € 5,360 € 5,360

Other solid fuels

SO2 Dry FGD 70% 0% 0% € 2,062 € 2,185

Other solid fuels

SO2 Wet FGD 94% 0% 100% € 9,946 € 9,946

Other solid fuels

SO2 Fuel switch to natural gas 100% 50% 99% € 80,887 € 80,887

A9


Table A.5 Abatement matrix for other technologies for 5-20 MWth plants


(%)

NOX abatement

(%)

Dust abatement

(%)

Total annual cost LOW

(€/plant)

Total annual cost HIGH

(€/plant)



Biomass NOX SNCR 0% 40% 0% € 1,691 € 32,997

Biomass NOX Combustion

modification - assumed EGR

0% 50% 0% € 6,459 € 6,459

Biomass NOX SCR 0% 85% 0% € 4,603 € 101,643




Liquid fuels Dust ESP 0% 0% 97% € 15,854 € 16,030


Liquid fuels NOX Water injection 0% 60% 0% € 4,724 € 5,362


Liquid fuels NOX NSCR 0% 94% 0% € 12,615 € 12,615


Liquid fuels SO2 Fuel switch to 0.1%

gas oil 90% 0% 0% € 38,356 € 38,356


Natural gas Dust ESP 0% 0% 97% € 15,854 € 16,030


Natural gas NOX Low NOx burner /

Advanced lean burn

0% 40% 0% € - € 7,384

Natural gas NOX Water injection 0% 60% 0% € 4,724 € 5,362


Natural gas NOX NSCR 0% 94% 0% € 18,869 € 31,102

Other gaseous

fuels NOX

Low NOx burner / Advanced lean

burn 0% 40% 0% € - € 7,384

Other gaseous

fuels NOX SNCR 0% 40% 0% € 3,379 € 32,997

Other gaseous

fuels NOX SCR 0% 75% 0% € 7,411 € 164,605

Other gaseous

fuels NOX NSCR 0% 94% 0% € 18,869 € 31,102

A10



(%)

NOX abatement

(%)

Dust abatement

(%)


(€/plant)


(€/plant)

Other gaseous

fuels SO2 Dry FGD 64% 0% 0% € 20,395 € 22,013

Other gaseous

fuels SO2 Wet FGD 94% 0% 99% € 61,903 € 61,903





Combustion modification -

assumed EGR 0% 50% 0% € 6,459 € 6,459









A11


Table A.6 Abatement matrix for other technologies 20-50 MWth plants


(%)

NOX abatement

(%)

Dust abatement

(%)


(€/plant)


(€/plant)



Biomass NOX Combustion

modification - assumed EGR

0% 40% 0% € 10,742 € 10,742

Biomass NOX SNCR 0% 45% 0% € 3,762 € 185,659

Biomass NOX SCR 0% 90% 0% € 10,239 € 286,958




Liquid fuels Dust ESP 0% 0% 97% € 15,854 € 16,030


Liquid fuels NOX Water injection 0% 60% 0% € 4,724 € 5,362


Liquid fuels NOX NSCR 0% 94% 0% € 28,062 € 28,062


Liquid fuels SO2 Fuel switch to 0.1% gas oil 90% 0% 0% € 38,356 € 38,356


Natural gas Dust ESP 0% 0% 97% € 15,854 € 16,030

Natural gas NOX Low NOx burner /

Advanced lean burn

0% 40% 0% € - € 31,471


Natural gas NOX Water injection 0% 60% 0% € 4,724 € 5,362


Natural gas NOX NSCR 0% 94% 0% € 41,972 € 69,184

Other gaseous

fuels NOX

Low NOx burner / Advanced lean

burn 0% 40% 0% € - € 31,471

Other gaseous

fuels NOX SNCR 0% 45% 0% € 9,387 € 185,659

Other gaseous

fuels NOX SCR 0% 88% 0% € 23,509 € 373,489

Other gaseous

fuels NOX NSCR 0% 94% 0% € 41,972 € 69,184

A12



(%)

NOX abatement

(%)

Dust abatement

(%)


(€/plant)


(€/plant)

Other gaseous

fuels SO2 Dry FGD 80% 0% 0% € 45,740 € 49,434

Other gaseous

fuels SO2 Wet FGD 94% 0% 100% € 80,049 € 80,049



Other solid fuels NOx

Combustion modification -

assumed EGR 0% 30% 0% € 10,742 € 10,742

Other solid fuels NOx SNCR 0% 45% 0% € 9,156 € 185,659

Other solid fuels NOx SCR 0% 90% 0% € 11,445 € 423,302







Fuel switch to natural gas 100% 50% 99% € 1,044,253 € 1,044,253

B1


Appendix B Emissions by MS

The following section provides a summary of the estimated emissions by each Member State for each pollutant and plant capacity under each scenario.

Emissions (kt)

Table B.1 SO2

MS

Size 2010 2025 2030

Current Legislation

IED 50-100 MW

Most Stringent

MS

Gothenburg SULES Current Legislation

IED 50-100

MW

Most Stringent

MS

AT 1-5 MW 2.1 2.2 0.2 0.2 0.2 0.2 2.1 0.2 0.2

AT 5-20 MW 0.1 0.1 0.1 0.0 0.0 0.0 0.0 0.0 0.0

AT 20-50 MW 0.1 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0

BE 1-5 MW 5.1 3.6 0.3 0.3 0.3 0.3 3.7 0.3 0.3

BE 5-20 MW 6.6 4.7 1.1 0.5 0.5 0.5 4.8 1.1 0.5

BE 20-50 MW 3.6 2.6 0.3 0.2 0.3 0.2 2.6 0.3 0.2

BG 1-5 MW 3.3 0.9 0.3 0.3 0.3 0.3 0.8 0.3 0.3

BG 5-20 MW 5.4 1.5 0.5 0.5 0.5 0.5 1.4 0.6 0.6

BG 20-50 MW 1.6 0.4 0.2 0.2 0.1 0.1 0.4 0.2 0.2

CY 1-5 MW 0.6 0.1 0.0 0.0 0.0 0.0 0.1 0.0 0.0

CY 5-20 MW 0.4 0.1 0.0 0.0 0.0 0.0 0.1 0.0 0.0

CY 20-50 MW 0.5 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

CZ 1-5 MW 1.8 1.7 0.2 0.1 0.2 0.2 1.8 0.2 0.1

CZ 5-20 MW 1.2 1.5 0.1 0.1 0.1 0.1 1.6 0.1 0.1

CZ 20-50 MW 4.1 3.4 0.4 0.2 0.4 0.3 3.5 0.3 0.2

DE 1-5 MW 26.0 18.6 6.0 2.5 5.6 4.7 17.9 5.5 2.3

DE 5-20 MW 10.2 7.3 2.3 0.9 2.2 1.8 7.0 2.1 0.8

DE 20-50 MW 8.1 5.9 1.7 0.6 1.6 1.3 5.6 1.5 0.6

DK 1-5 MW 11.5 4.7 0.6 0.6 0.4 0.4 5.2 0.7 0.7

DK 5-20 MW 19.1 7.8 1.3 1.3 1.1 1.1 8.6 1.4 1.4

DK 20-50 MW 4.5 1.8 0.4 0.4 0.4 0.4 2.0 0.5 0.5

EE 1-5 MW 4.4 3.3 0.2 0.2 0.2 0.2 3.0 0.2 0.2

B2


MS

Size 2010 2025 2030

Current Legislation

IED 50-100 MW

Most Stringent

MS


IED 50-100

MW

Most Stringent

MS

EE 5-20 MW 0.6 0.5 0.2 0.1 0.1 0.1 0.5 0.2 0.1

EE 20-50 MW 4.0 3.8 0.3 0.3 0.2 0.2 3.5 0.3 0.3

EL 1-5 MW 0.5 0.1 0.0 0.0 0.0 0.0 0.1 0.0 0.0

EL 5-20 MW 0.8 0.2 0.0 0.0 0.0 0.0 0.2 0.0 0.0

EL 20-50 MW 0.2 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0

ES 1-5 MW 7.5 3.9 0.5 0.5 0.4 0.4 2.9 0.4 0.4

ES 5-20 MW 12.5 6.5 1.0 1.0 0.9 0.9 4.8 0.9 0.9

ES 20-50 MW 1.5 0.8 0.8 0.2 0.2 0.2 0.6 0.6 0.1

FI 1-5 MW 0.6 0.4 0.2 0.2 0.2 0.2 0.4 0.2 0.2

FI 5-20 MW 1.8 1.2 0.5 0.4 0.4 0.4 1.1 0.5 0.4

FI 20-50 MW 3.7 2.4 0.9 0.8 0.8 0.7 2.1 0.8 0.7

FR 1-5 MW 9.8 5.4 2.4 2.3 2.5 2.5 4.7 2.2 2.1

FR 5-20 MW 8.7 4.8 4.2 2.0 2.2 2.2 4.2 3.6 1.9

FR 20-50 MW 8.0 7.8 7.6 6.9 6.0 6.0 7.5 7.3 6.7

HU 1-5 MW 1.6 1.4 0.1 0.1 0.1 0.1 1.4 0.1 0.1

HU 5-20 MW 2.6 2.3 0.4 0.2 0.2 0.2 2.4 0.4 0.2

HU 20-50 MW 2.1 1.9 0.1 0.1 0.1 0.1 1.9 0.2 0.2

IE 1-5 MW 5.3 4.8 0.7 0.7 0.6 0.6 4.3 0.7 0.7

IE 5-20 MW 8.8 8.0 1.3 1.3 1.2 1.2 7.2 1.4 1.4

IE 20-50 MW 2.1 1.9 0.5 0.5 0.5 0.4 1.7 0.5 0.5

IT 1-5 MW 9.4 1.1 0.1 0.1 0.1 0.1 1.0 0.1 0.1

IT 5-20 MW 15.6 1.8 0.2 0.2 0.2 0.2 1.7 0.2 0.2

IT 20-50 MW 3.7 0.4 0.1 0.1 0.1 0.1 0.4 0.1 0.1

LT 1-5 MW 2.2 1.6 0.1 0.1 0.1 0.1 1.7 0.2 0.2

LT 5-20 MW 3.7 2.7 0.3 0.3 0.3 0.3 2.8 0.3 0.3

LT 20-50 MW 0.9 0.6 0.1 0.1 0.1 0.1 0.7 0.1 0.1

LU 1-5 MW - - - - 0.0 0.0 - - -

LU 5-20 MW - - - - 0.0 0.0 - - -

LU 20-50 MW - - - - 0.0 0.0 - - -

LV 1-5 MW 0.9 1.0 0.5 0.5 0.4 0.4 1.0 0.5 0.5

LV 5-20 MW 1.3 1.4 0.7 0.7 0.7 0.7 1.5 0.8 0.8

LV 20-50 MW 0.5 0.6 0.3 0.3 0.3 0.3 0.6 0.4 0.4

B3


MS

Size 2010 2025 2030

Current Legislation

IED 50-100 MW

Most Stringent

MS


IED 50-100

MW

Most Stringent

MS

MT 1-5 MW 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

MT 5-20 MW 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

MT 20-50 MW - - - - 0.0 0.0 - - -

NL 1-5 MW 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

NL 5-20 MW - - - - 0.0 0.0 - - -

NL 20-50 MW - - - - 0.0 0.0 - - -

PL 1-5 MW 0.8 0.6 0.1 0.1 0.1 0.1 0.5 0.1 0.1

PL 5-20 MW 13.0 10.7 0.8 0.8 0.8 0.8 9.3 0.8 0.8

PL 20-50 MW 11.0 9.1 1.8 1.8 1.8 1.8 7.9 1.6 1.6

PT 1-5 MW 1.7 1.2 0.3 0.3 0.2 0.2 1.3 0.3 0.3

PT 5-20 MW 2.9 2.1 0.5 0.5 0.5 0.5 2.1 0.5 0.5

PT 20-50 MW 1.0 0.7 0.3 0.3 0.3 0.3 0.7 0.3 0.3

RO 1-5 MW 0.7 0.7 0.1 0.1 0.1 0.1 0.7 0.2 0.2

RO 5-20 MW 2.0 2.0 0.5 0.5 0.4 0.4 1.8 0.5 0.5

RO 20-50 MW 1.5 1.4 0.4 0.3 0.3 0.3 1.3 0.4 0.4

SE 1-5 MW 0.2 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1

SE 5-20 MW 2.2 0.8 0.8 0.2 0.2 0.2 0.7 0.7 0.2

SE 20-50 MW 0.7 0.2 0.0 0.0 0.0 0.0 0.2 0.0 0.0

SI 1-5 MW 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

SI 5-20 MW 0.2 0.1 0.1 0.0 0.1 0.1 0.1 0.1 0.0

SI 20-50 MW 0.1 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0

SK 1-5 MW 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

SK 5-20 MW 0.2 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

SK 20-50 MW 0.2 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

UK 1-5 MW 7.0 3.0 0.3 0.1 0.2 0.2 1.1 0.2 0.1

UK 5-20 MW 9.4 4.1 0.4 0.4 0.4 0.4 1.6 0.2 0.2

UK 20-50 MW 4.0 2.2 0.3 0.2 0.2 0.2 1.3 0.1 0.1

B4


Figure B.1 SO2 emissions by Member State

-

5.0

10.0

15.0

20.0

25.0

30.0

35.0

40.0

45.0

50.0


1-50 MWth total: SO2 emissions

2010 2025 BAU 2025 IED 50-100 MW 2025 Most stringent MS 2025 Gothenburg 2025 SULES 2025 SULES

B5


Table B.2 NOX

MS Size 2010 2025 2030

Cur

rent

Le

gisl

atio

n

Prim

ary

NO

x

IED

50-

100

MW

Mos

t St

ringe

nt

MS

Got

henb

urg

SULE

S

Cur

rent

Le

gisl

atio

n

Prim

ary

NO

x

IED

50-

100

MW

Mos

t St

ringe

nt

MS

AT 1-5 MW 1.8 1.6 1 0.8 0.4 1.3 1.1 1.5 1 0.8 0.3

AT 5-20 MW 1.5 1.2 1.2 0.8 0.3 1.1 1.0 1.1 1.1 0.7 0.3

AT 20-50 MW 2.5 2.1 1.9 1.5 1.0 2.0 1.8 2.0 1.9 1.5 1.0

BE 1-5 MW 15.3 14.9 9.8 3.3 3.2 9.7 8.1 14.3 9.4 3.2 3.1

BE 5-20 MW 19.9 19.4 13.7 4.8 3.9 12.8 10.7 18.6 13.1 4.6 3.7

BE 20-50 MW 10.9 10.7 7.3 1.6 1.5 6.8 5.5 10.2 6.9 1.5 1.5

BG 1-5 MW 4.1 4.6 3.1 1.1 1.1 2.9 2.4 4.0 2.7 0.9 0.9

BG 5-20 MW 6.7 7.6 5.2 1.5 1.5 4.8 3.9 6.6 4.5 1.3 1.3

BG 20-50 MW 2.4 2.9 2.0 0.5 0.4 1.4 1.1 2.5 1.7 0.4 0.4

CY 1-5 MW 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

CY 5-20 MW 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

CY 20-50 MW 2.0 0.1 0.0 0.0 0.0 0.0 0.0 0.1 0.0 0.0 0.0

CZ 1-5 MW 1.9 1.9 1.9 1.9 1.5 2.0 1.9 1.7 1.7 1.7 1.3

CZ 5-20 MW 2.0 2.0 2.0 2.0 2.0 2.0 2.0 1.8 1.8 1.8 1.8

CZ 20-50 MW 2.2 2.0 1.9 0.9 0.4 1.9 1.6 1.9 1.8 0.9 0.3

DE 1-5 MW 76.0 62.8 54.5 24.5 14.9 50.2 43.1 60.9 52.7 23.0 14.5

DE 5-20 MW 29.9 25.0 21.8 9.2 7.0 20.1 17.0 24.2 21.0 8.6 6.7

DE 20-50 MW 23.6 19.8 19.6 7.7 4.4 15.9 13.2 19.1 18.9 7.3 4.2

DK 1-5 MW 8.5 6.0 4.1 3.1 2.2 2.8 2.6 8.5 5.7 4.4 3.2

DK 5-20 MW 11.3 7.5 6.0 4.7 2.6 4.6 4.1 10.6 8.4 6.5 3.8

DK 20-50 MW 8.8 6.0 6.0 1.9 0.9 4.2 3.4 8.4 8.4 2.3 1.2

EE 1-5 MW 0.6 0.6 0.6 0.4 0.3 0.5 0.5 0.5 0.4 0.3 0.2

EE 5-20 MW 0.8 0.9 0.8 0.5 0.2 0.7 0.6 0.6 0.6 0.4 0.1

EE 20-50 MW 0.5 0.6 0.6 0.4 0.3 0.6 0.5 0.5 0.5 0.3 0.2

EL 1-5 MW 0.6 0.6 0.4 0.1 0.1 0.4 0.3 0.7 0.5 0.2 0.2

EL 5-20 MW 1.0 1.0 0.6 0.2 0.2 0.6 0.5 1.2 0.8 0.2 0.2

EL 20-50 MW 0.4 0.4 0.4 0.1 0.1 0.3 0.2 0.5 0.5 0.1 0.1

ES 1-5 MW 12.1 10.9 7.2 2.5 2.4 6.7 5.6 10.2 6.8 2.3 2.3

ES 5-20 MW 20.1 18.1 12.3 3.7 3.6 11.0 9.1 16.9 11.5 3.4 3.4

ES 20-50 MW 4.1 3.8 3.8 2.5 1.0 3.6 3.1 3.5 3.5 2.4 0.9

B6


MS Size 2010 2025 2030

C

urre

nt

Legi

slat

ion

Prim

ary

NO

x

IED

50-

100

MW

Mos

t St

ringe

nt

MS

Got

henb

urg

SULE

S

Cur

rent

Le

gisl

atio

n

Prim

ary

NO

x

IED

50-

100

MW

Mos

t St

ringe

nt

MS

FI 1-5 MW 1.7 1.6 1.2 0.7 0.4 1.2 1.0 1.5 1.2 0.7 0.4

FI 5-20 MW 1.9 1.6 1.4 1.1 0.3 1.3 1.1 1.5 1.4 1.0 0.3

FI 20-50 MW 4.4 3.7 3.3 2.4 0.6 3.1 2.5 3.4 3.1 2.2 0.5

FR 1-5 MW 19.2 15.8 14.0 9.8 6.3 15.6 13.8 14.8 13.1 9.3 6.2

FR 5-20 MW 17.0 14.3 14.3 10.3 5.9 14.9 12.8 13.5 13.5 9.8 5.7

FR 20-50 MW 10.3 8.5 8.5 7.6 6.5 8.4 8.5 8.0 8.0 7.1 6.1

HU 1-5 MW 2.9 2.5 1.9 0.6 0.5 1.7 1.4 2.2 1.6 0.6 0.5

HU 5-20 MW 4.7 4.2 3.1 1.0 0.8 2.9 2.4 3.6 2.7 0.9 0.7

HU 20-50 MW 2.7 2.4 2.4 0.5 0.4 1.7 1.4 2.1 2.0 0.5 0.3

IE 1-5 MW 4.3 4.0 2.6 1.0 0.9 2.5 2.1 4.3 2.9 1.1 1.0

IE 5-20 MW 7.1 6.5 4.4 1.4 1.3 4.2 3.4 7.0 4.7 1.5 1.4

IE 20-50 MW 2.2 1.8 1.7 1.3 0.3 1.7 1.4 2.0 1.8 1.4 0.3

IT 1-5 MW 12.9 9.2 6.1 2.0 2.0 5.6 4.6 9.1 6.0 2.0 2.0

IT 5-20 MW 21.5 15.3 10.4 3.1 3.1 9.2 7.6 15.1 10.3 3.0 3.0

IT 20-50 MW 9.1 7.0 7.0 1.1 1.1 4.6 3.7 7.0 7.0 1.1 1.0

LT 1-5 MW 2.2 2.1 1.4 0.5 0.5 1.3 1.1 2.1 1.4 0.5 0.5

LT 5-20 MW 3.7 3.5 2.3 0.7 0.7 2.1 1.7 3.5 2.3 0.7 0.7

LT 20-50 MW 1.3 1.3 1.3 0.4 0.3 0.9 0.7 1.3 1.3 0.4 0.3

LU 1-5 MW 0.2 0.1 0.1 0.0 0.0 0.1 0.1 0.1 0.1 0.0 0.0

LU 5-20 MW 0.4 0.2 0.1 0.0 0.0 0.1 0.1 0.2 0.1 0.0 0.0

LU 20-50 MW 0.2 0.1 0.1 0.0 0.0 0.0 0.0 0.1 0.1 0.0 0.0

LV 1-5 MW 1.7 1.9 1.5 0.6 0.5 1.4 1.2 2.0 1.6 0.6 0.5

LV 5-20 MW 2.6 2.8 2.4 0.7 0.6 2.2 1.9 3.0 2.5 0.7 0.6

LV 20-50 MW 1.5 1.6 1.6 0.8 0.3 1.3 1.1 1.7 1.7 0.9 0.3

MT 1-5 MW 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

MT 5-20 MW 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

MT 20-50 MW - - - - - 0.0 0.0 - - - -

NL 1-5 MW 8.6 5.5 5.4 1.9 1.3 5.1 4.4 5.0 5.0 1.8 1.2

NL 5-20 MW 11.7 7.3 7.3 2.0 1.5 6.8 5.8 6.8 6.8 1.9 1.4

NL 20-50 MW 1.6 1.0 1.0 0.6 0.2 0.9 0.8 0.9 0.9 0.6 0.2

PL 1-5 MW 9.4 12.8 9.0 2.6 2.6 5.7 5.1 12.9 9.1 2.6 2.6

PL 5-20 MW 18.7 24.8 17.4 4.9 4.9 17.5 14.2 24.8 17.4 4.9 4.9

B7


MS Size 2010 2025 2030

C

urre

nt

Legi

slat

ion

Prim

ary

NO

x

IED

50-

100

MW

Mos

t St

ringe

nt

MS

Got

henb

urg

SULE

S

Cur

rent

Le

gisl

atio

n

Prim

ary

NO

x

IED

50-

100

MW

Mos

t St

ringe

nt

MS

PL 20-50 MW 5.4 5.4 4.8 3.6 0.7 4.9 3.8 5.1 4.4 3.2 0.7

PT 1-5 MW 2.4 1.6 1.1 0.4 0.4 1.0 0.9 1.8 1.2 0.4 0.4

PT 5-20 MW 3.9 2.6 1.8 0.5 0.5 1.3 1.1 2.9 2.0 0.6 0.6

PT 20-50 MW 2.6 1.4 1.1 0.3 0.2 1.2 0.9 1.7 1.3 0.4 0.3

RO 1-5 MW 1.4 1.2 0.8 0.3 0.3 0.8 0.7 1.3 0.8 0.3 0.3

RO 5-20 MW 3.8 3.4 2.3 0.7 0.7 2.1 1.7 3.4 2.3 0.7 0.7

RO 20-50 MW 3.7 3.0 2.1 0.5 0.5 1.4 1.2 3.1 2.1 0.5 0.5

SE 1-5 MW 1.8 1.5 1.4 0.4 0.4 1.2 1.1 1.5 1.4 0.4 0.4

SE 5-20 MW 5.6 3.8 3.6 3.3 1.1 3.5 3.0 3.6 3.4 3.2 1.0

SE 20-50 MW 3.5 3.7 3.5 3.7 2.3 3.6 3.4 3.7 3.4 3.6 2.2

SI 1-5 MW 1.4 1.6 1.6 1.2 0.5 2.5 2.1 0.9 0.9 0.7 0.3

SI 5-20 MW 0.2 0.3 0.3 0.3 0.3 0.6 0.6 0.2 0.2 0.2 0.2

SI 20-50 MW 0.5 0.6 0.5 0.1 0.1 0.4 0.4 0.4 0.3 0.1 0.1

SK 1-5 MW 0.7 0.6 0.6 0.1 0.1 0.5 0.4 0.6 0.6 0.2 0.1

SK 5-20 MW 1.1 0.9 0.9 0.2 0.2 0.8 0.7 1.0 1.0 0.2 0.2

SK 20-50 MW 1.2 1.3 1.3 0.8 0.2 1.2 1.0 1.5 1.5 0.9 0.2

UK 1-5 MW 18.7 12.6 8.3 2.8 2.9 7.8 6.4 12.4 8.2 2.7 2.8

UK 5-20 MW 30.1 20.4 13.9 4.1 4.1 12.4 10.2 20.2 13.8 4.0 4.0

UK 20-50 MW 9.0 6.0 6.0 1.6 0.9 5.6 4.8 5.9 5.9 1.5 0.9

B8


Figure B.2 NOX Emissions by Member State

-

20.0

40.0

60.0

80.0

100.0

120.0

140.0


1-50 MWth total: NOX emissions

2010 2025 BAU 2025 Primary NOx 2025 IED 50-100 MW 2025 Most stringent MS 2025 Gothenburg 2025 SULES

B9


Table B.3 PM

MS Size 2010 2025 2030

Current Legislation

IED 50-100 MW

Most Stringent

MS


IED 50-100

MW

Most Stringent

MS

AT 1-5 MW 0.1 0.1 0.0 0.0 0.0 0.0 0.1 0.0 0.0

AT 5-20 MW 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

AT 20-50 MW 0.1 0.1 0.1 0.0 0.1 0.1 0.1 0.1 0.0

BE 1-5 MW 1.4 1.1 0.0 0.0 0.0 0.0 1.1 0.0 0.0

BE 5-20 MW 1.9 1.4 0.0 0.0 0.0 0.0 1.4 0.0 0.0

BE 20-50 MW 1.0 0.8 0.0 0.0 0.0 0.0 0.8 0.0 0.0

BG 1-5 MW 0.5 0.6 0.1 0.1 0.0 0.0 0.7 0.1 0.1

BG 5-20 MW 0.7 0.9 0.0 0.0 0.0 0.0 1.1 0.0 0.0

BG 20-50 MW 0.3 0.3 0.0 0.0 0.0 0.0 0.3 0.0 0.0

CY 1-5 MW 0.6 0.3 0.0 0.0 0.0 0.0 0.3 0.0 0.0

CY 5-20 MW 0.3 0.1 0.0 0.0 0.0 0.0 0.1 0.0 0.0

CY 20-50 MW 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

CZ 1-5 MW 0.3 0.3 0.0 0.0 0.0 0.0 0.3 0.0 0.0

CZ 5-20 MW 0.3 0.4 0.0 0.0 0.0 0.0 0.4 0.0 0.0

CZ 20-50 MW 0.2 0.2 0.0 0.0 0.0 0.0 0.2 0.0 0.0

DE 1-5 MW 2.5 1.8 0.8 0.2 0.6 0.5 1.8 0.8 0.3

DE 5-20 MW 1.0 0.7 0.3 0.1 0.2 0.2 0.6 0.3 0.1

DE 20-50 MW 0.8 0.5 0.2 0.0 0.2 0.2 0.5 0.2 0.0

DK 1-5 MW 1.5 1.0 0.2 0.2 0.0 0.1 1.1 0.2 0.2

DK 5-20 MW 2.0 1.6 0.1 0.1 0.0 0.0 1.7 0.1 0.1

DK 20-50 MW 1.2 0.8 0.0 0.0 0.0 0.0 0.8 0.0 0.0

EE 1-5 MW 1.1 1.2 0.0 0.0 0.0 0.0 1.0 0.0 0.0

EE 5-20 MW 1.0 1.1 0.0 0.0 0.0 0.0 0.9 0.0 0.0

EE 20-50 MW 1.4 1.3 0.0 0.0 0.0 0.0 1.1 0.0 0.0

EL 1-5 MW 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

EL 5-20 MW 0.1 0.1 0.0 0.0 0.0 0.0 0.1 0.0 0.0

EL 20-50 MW 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

ES 1-5 MW 1.0 0.9 0.1 0.1 0.0 0.0 0.8 0.1 0.1

ES 5-20 MW 1.3 1.2 0.0 0.0 0.0 0.0 1.2 0.0 0.0

ES 20-50 MW 0.4 0.3 0.1 0.0 0.0 0.0 0.3 0.0 0.0

FI 1-5 MW 0.2 0.3 0.0 0.0 0.0 0.0 0.2 0.0 0.0

FI 5-20 MW 0.3 0.3 0.0 0.0 0.0 0.0 0.3 0.0 0.0

B10


MS Size 2010 2025 2030

Current Legislation

IED 50-100 MW

Most Stringent

MS


IED 50-100

MW

Most Stringent

MS

FI 20-50 MW 0.3 0.2 0.1 0.0 0.1 0.1 0.2 0.1 0.0

FR 1-5 MW 2.0 2.0 0.9 0.3 0.1 0.3 1.9 0.8 0.3

FR 5-20 MW 1.8 1.7 0.7 0.3 0.5 0.4 1.6 0.7 0.3

FR 20-50 MW 2.5 2.2 0.8 0.2 0.7 0.6 2.1 0.8 0.2

HU 1-5 MW 0.1 0.1 0.0 0.0 0.0 0.0 0.1 0.0 0.0

HU 5-20 MW 0.1 0.1 0.0 0.0 0.0 0.0 0.1 0.0 0.0

HU 20-50 MW 0.3 0.2 0.0 0.0 0.0 0.0 0.2 0.0 0.0

IE 1-5 MW 0.7 1.2 0.1 0.1 0.0 0.1 1.4 0.1 0.1

IE 5-20 MW 0.9 1.7 0.0 0.0 0.0 0.0 2.1 0.1 0.1

IE 20-50 MW 0.6 0.8 0.0 0.0 0.0 0.0 0.9 0.0 0.0

IT 1-5 MW 0.8 0.1 0.0 0.0 0.0 0.0 0.1 0.0 0.0

IT 5-20 MW 0.9 0.1 0.0 0.0 0.0 0.0 0.1 0.0 0.0

IT 20-50 MW 0.7 0.1 0.0 0.0 0.0 0.0 0.1 0.0 0.0

LT 1-5 MW 0.3 0.2 0.0 0.0 0.0 0.0 0.2 0.0 0.0

LT 5-20 MW 0.3 0.3 0.0 0.0 0.0 0.0 0.3 0.0 0.0

LT 20-50 MW 0.2 0.2 0.0 0.0 0.0 0.0 0.2 0.0 0.0

LU 1-5 MW - - - - 0.0 0.0 - - -

LU 5-20 MW - - - - 0.0 0.0 - - -

LU 20-50 MW - - - - 0.0 0.0 - - -

LV 1-5 MW 1.5 2.4 0.1 0.1 0.0 0.0 2.6 0.1 0.1

LV 5-20 MW 1.8 2.8 0.1 0.1 0.0 0.0 3.1 0.1 0.1

LV 20-50 MW 0.5 0.7 0.0 0.0 0.0 0.0 0.8 0.0 0.0

MT 1-5 MW 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

MT 5-20 MW 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

MT 20-50 MW - - - - 0.0 0.0 - - -

NL 1-5 MW 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

NL 5-20 MW - - - - 0.0 0.0 - - -

NL 20-50 MW - - - - 0.0 0.0 - - -

PL 1-5 MW 0.3 0.2 0.0 0.0 0.0 0.0 0.2 0.0 0.0

PL 5-20 MW 2.0 1.8 0.0 0.0 0.0 0.0 1.6 0.0 0.0

PL 20-50 MW 4.0 3.3 0.0 0.0 0.0 0.0 3.0 0.0 0.0

PT 1-5 MW 0.5 0.5 0.0 0.0 0.0 0.0 0.5 0.0 0.0

PT 5-20 MW 0.8 0.8 0.0 0.0 0.0 0.0 0.8 0.0 0.0

B11


MS Size 2010 2025 2030

Current Legislation

IED 50-100 MW

Most Stringent

MS


IED 50-100

MW

Most Stringent

MS

PT 20-50 MW 0.4 0.4 0.0 0.0 0.0 0.0 0.4 0.0 0.0

RO 1-5 MW 0.1 0.3 0.0 0.0 0.0 0.0 0.3 0.0 0.0

RO 5-20 MW 0.3 0.7 0.0 0.0 0.0 0.0 0.8 0.0 0.0

RO 20-50 MW 0.3 0.6 0.0 0.0 0.0 0.0 0.6 0.0 0.0

SE 1-5 MW 0.3 0.3 0.1 0.1 0.0 0.0 0.3 0.1 0.1

SE 5-20 MW 0.5 0.5 0.2 0.0 0.1 0.1 0.5 0.2 0.0

SE 20-50 MW 0.2 0.2 0.2 0.0 0.2 0.2 0.2 0.2 0.0

SI 1-5 MW 0.1 0.1 0.0 0.0 0.0 0.0 0.1 0.0 0.0

SI 5-20 MW 0.1 0.1 0.0 0.0 0.0 0.0 0.1 0.0 0.0

SI 20-50 MW 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

SK 1-5 MW 0.2 0.2 0.0 0.0 0.0 0.0 0.2 0.0 0.0

SK 5-20 MW 0.1 0.1 0.0 0.0 0.0 0.0 0.1 0.0 0.0

SK 20-50 MW 0.1 0.1 0.0 0.0 0.0 0.0 0.2 0.1 0.0

UK 1-5 MW 1.0 0.5 0.0 0.0 0.0 0.0 0.3 0.0 0.0

UK 5-20 MW 1.6 0.8 0.0 0.0 0.0 0.0 0.5 0.0 0.0

UK 20-50 MW 0.6 0.3 0.0 0.0 0.0 0.0 0.2 0.0 0.0

B12


Figure B.3 Dust emissions by Member State

-

1.0

2.0

3.0

4.0

5.0

6.0

7.0


1-50 MWth total: PM emissions

2010 2025 BAU 2025 IED 50-100 MW 2025 Most stringent MS 2025 Gothenburg 2025 SULES

C1


Appendix C Costs by Member State

Compliance Costs (€million per year)

Table C.1 SO2

Member State

2025 2030

ELVs IED 50-100 MW Most Stringent MS Gothenburg SULES IED 50-100

MW Most Stringent

MS

AT 1-5 MW 7.2 7.2 5.2 5.2 6.8 6.8

AT 5-20 MW - 0.1 0.1 0.1 - 0.1

AT 20-50 MW 0.0 0.0 0.0 0.0 0.0 0.0

BE 1-5 MW 4.0 4.0 3.0 3.0 4.0 4.0

BE 5-20 MW 2.2 4.7 4.1 4.1 2.2 4.7

BE 20-50 MW 0.8 1.4 0.7 0.7 0.8 1.4

BG 1-5 MW 0.8 0.9 0.6 0.6 0.7 0.7

BG 5-20 MW 0.8 0.8 0.7 0.7 0.7 0.7

BG 20-50 MW 0.1 0.1 0.1 0.1 0.1 0.1

CY 1-5 MW 0.4 0.4 0.3 0.3 0.3 0.3

CY 5-20 MW 0.3 0.3 0.3 0.3 0.3 0.3

CY 20-50 MW 0.0 0.0 0.0 0.0 0.0 0.0

CZ 1-5 MW 1.3 1.6 1.1 1.2 1.4 1.6

CZ 5-20 MW 0.5 0.6 0.4 0.4 0.6 0.6

CZ 20-50 MW 2.3 2.9 1.8 1.9 2.3 2.7

DE 1-5 MW 37.7 145.7 38.0 54.4 37.4 134.9

DE 5-20 MW 21.7 66.9 19.7 26.7 21.5 62.1

DE 20-50 MW 7.0 18.2 6.2 7.8 6.7 16.9

DK 1-5 MW 5.8 5.8 4.1 4.1 6.4 6.4

DK 5-20 MW 5.8 5.8 4.8 4.8 6.4 6.4

DK 20-50 MW 0.8 0.8 0.7 0.7 0.9 0.9

EE 1-5 MW 3.1 3.1 2.2 2.2 2.6 2.6

EE 5-20 MW 0.5 1.0 1.2 1.2 0.5 0.9

EE 20-50 MW 1.6 1.6 1.2 1.2 1.3 1.3

EL 1-5 MW 0.2 0.2 0.1 0.1 0.1 0.1

C2


Member State

2025 2030


MW Most Stringent

MS

EL 5-20 MW 0.2 0.2 0.1 0.1 0.1 0.1

EL 20-50 MW 0.0 0.0 0.0 0.0 0.0 0.0

ES 1-5 MW 4.9 4.9 3.6 3.6 3.5 3.5

ES 5-20 MW 4.9 4.9 4.0 4.0 3.5 3.5

ES 20-50 MW - 0.7 0.5 0.5 - 0.5

FI 1-5 MW 0.1 0.1 0.2 0.2 0.1 0.1

FI 5-20 MW 0.7 1.0 1.0 1.0 0.6 0.9

FI 20-50 MW 1.5 1.7 1.6 1.6 1.3 1.5

FR 1-5 MW 7.0 7.5 11.6 11.6 6.8 7.2

FR 5-20 MW 4.3 8.2 12.1 12.1 4.6 7.7

FR 20-50 MW 0.9 4.2 5.3 5.4 0.9 4.1

HU 1-5 MW 1.8 1.8 1.4 1.4 1.9 1.9

HU 5-20 MW 1.7 2.2 1.8 1.8 1.8 2.3

HU 20-50 MW 0.5 0.5 0.4 0.4 0.5 0.5

IE 1-5 MW 5.9 5.9 4.4 4.4 5.1 5.1

IE 5-20 MW 5.9 5.9 4.9 4.9 5.1 5.1

IE 20-50 MW 0.8 0.8 0.7 0.7 0.7 0.7

IT 1-5 MW 1.4 1.4 1.1 1.1 1.3 1.3

IT 5-20 MW 1.4 1.4 1.2 1.2 1.3 1.3

IT 20-50 MW 0.2 0.2 0.2 0.2 0.2 0.2

LT 1-5 MW 2.1 2.1 1.5 1.5 2.2 2.2

LT 5-20 MW 2.1 2.1 1.7 1.7 2.2 2.2

LT 20-50 MW 0.3 0.3 0.2 0.2 0.3 0.3

LU 1-5 MW - - 0.0 0.0 - -

LU 5-20 MW - - 0.0 0.0 - -

LU 20-50 MW - - 0.0 0.0 - -

LV 1-5 MW 0.5 0.5 0.4 0.4 0.5 0.5

LV 5-20 MW 0.4 0.4 0.4 0.4 0.4 0.4

LV 20-50 MW 0.1 0.1 0.2 0.2 0.1 0.1

MT 1-5 MW 0.0 0.6 0.1 0.1 0.0 0.6

MT 5-20 MW 0.0 0.0 0.0 0.0 0.0 0.0

MT 20-50 MW - - 0.0 0.0 - -

C3


Member State

2025 2030


MW Most Stringent

MS

NL 1-5 MW - - 0.0 0.0 - -

NL 5-20 MW - - 0.0 0.0 - -

NL 20-50 MW - - 0.0 0.0 - -

PL 1-5 MW 0.9 0.9 0.7 0.7 0.8 0.8

PL 5-20 MW 8.2 8.2 6.3 6.3 7.2 7.2

PL 20-50 MW 8.4 8.4 6.8 6.8 7.4 7.4

PT 1-5 MW 1.4 1.4 1.0 1.0 1.4 1.4

PT 5-20 MW 1.4 1.4 1.1 1.1 1.4 1.4

PT 20-50 MW 0.2 0.2 0.2 0.2 0.2 0.2

RO 1-5 MW 1.0 1.0 0.7 0.7 0.9 0.9

RO 5-20 MW 1.8 1.8 1.5 1.5 1.6 1.6

RO 20-50 MW 0.4 0.5 0.4 0.4 0.3 0.4

SE 1-5 MW 0.0 0.0 0.0 0.0 0.0 0.0

SE 5-20 MW 0.0 1.8 2.0 2.0 0.0 1.6

SE 20-50 MW 0.2 0.2 0.2 0.2 0.1 0.1

SI 1-5 MW - 0.0 0.0 0.0 - 0.0

SI 5-20 MW - 0.1 0.0 0.0 - 0.0

SI 20-50 MW 0.0 0.0 0.0 0.0 0.0 0.0

SK 1-5 MW 0.1 0.9 0.1 0.2 0.1 0.8

SK 5-20 MW 0.2 0.2 0.1 0.1 0.1 0.1

SK 20-50 MW 0.0 0.1 0.0 0.0 0.0 0.1

UK 1-5 MW 2.2 12.3 1.6 1.6 1.2 4.2

UK 5-20 MW 3.4 3.4 2.5 2.5 1.6 1.6

UK 20-50 MW 0.7 1.0 0.6 0.6 0.5 0.5

C4


Figure C.1 Compliance Costs (SO2) by Member State

0

50

100

150

200

250


(€m

/yea

r)

Compliance costs for 1-50 MWth total: SO2

2025 IED 50-100 MW 2025 Most stringent MS 2025 Gothenburg 2025 SULES

C5


Table C.2 NOX

Member State

2025 2030

ELVs

IED 50-100

MW Primary

NOx Most

Stringent MS

Gothenburg SULES IED 50-100 MW

Primary NOx

Most Stringent MS

AT 1-5 MW 8.6 0.2 23.8 0.1 3.6 8.3 0 22.5

AT 5-20 MW 3.9 0.0 12.7 0.1 2.0 3.7 0.0 12.0

AT 20-50 MW 4.5 0.2 10.5 0.5 1.6 4.2 0.2 9.9

BE 1-5 MW 36.6 1.5 37.4 2.0 6.3 35.0 1.5 35.8

BE 5-20 MW 45.8 1.2 53.4 2.8 8.8 43.7 1.1 51.2

BE 20-50 MW 24.7 0.8 25.4 1.0 3.6 23.6 0.7 24.3

BG 1-5 MW 23.7 1.1 23.8 1.3 4.1 20.7 1.1 20.9

BG 5-20 MW 28.6 1.0 28.9 1.8 5.1 25.1 1.0 25.3

BG 20-50 MW 13.8 0.5 14.1 0.7 2.2 12.0 0.5 12.3

CY 1-5 MW 0.5 - 0.6 0.0 0.1 0.5 - 0.6

CY 5-20 MW 0.5 - 0.6 0.0 0.1 0.5 - 0.6

CY 20-50 MW 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

CZ 1-5 MW 0.0 - 0.8 0.0 0.1 0.0 - 0.7

CZ 5-20 MW - - 0.0 0.0 0.0 - - 0.0

CZ 20-50 MW 16.2 0.0 24.1 0.3 3.5 14.5 0.0 22.2

DE 1-5 MW 205.8 6.3 397.5 8.8 61.5 206.0 6.4 377.7

DE 5-20 MW 87.3 1.5 149.8 3.2 28.7 87.5 1.5 143.9

DE 20-50 MW 61.6 0.2 99.4 1.8 16.4 61.3 0.2 95.3

DK 1-5 MW 21.3 2.2 33.4 2.1 5.0 30.6 2.9 45.4

DK 5-20 MW 17.2 1.1 43.8 1.3 7.6 26.0 1.5 59.3

DK 20-50 MW 24.7 - 30.7 0.5 4.4 37.0 - 43.6

EE 1-5 MW 3.4 0.1 5.6 0.2 1.0 2.0 0.0 3.9

EE 5-20 MW 5.5 0.1 12.9 0.3 2.1 3.3 0.1 9.2

EE 20-50 MW 1.2 - 2.2 0.0 0.4 0.7 - 1.6

EL 1-5 MW 3.1 0.1 3.1 0.2 0.5 3.8 0.1 3.8

EL 5-20 MW 3.7 0.1 3.8 0.2 0.6 4.6 0.1 4.6

EL 20-50 MW 1.6 - 1.7 0.0 0.3 2.1 - 2.1

ES 1-5 MW 66.5 2.8 67.5 3.5 11.4 62.1 2.5 62.8

ES 5-20 MW 79.8 2.2 81.5 4.6 13.8 74.7 2.1 75.9

ES 20-50 MW 14.5 - 25.7 0.0 3.4 13.8 - 24.4

FI 1-5 MW 0.7 0.1 1.8 0.1 0.3 0.7 0.1 1.7

C6


Member State

2025 2030

ELVs

IED 50-100

MW Primary

NOx Most

Stringent MS


Primary NOx

Most Stringent MS

FI 5-20 MW 2.0 0.0 7.8 0.3 1.4 1.9 0.0 7.3

FI 20-50 MW 6.0 0.1 19.8 0.5 3.5 5.8 0.1 18.3

FR 1-5 MW 59.7 0.9 101.5 4.1 23.4 54.4 0.8 90.6

FR 5-20 MW 51.6 - 89.2 2.6 20.4 46.9 - 79.9

FR 20-50 MW 1.5 - 54.2 2.5 11.0 1.4 - 49.4

HU 1-5 MW 18.0 0.5 22.1 1.1 3.7 15.5 0.4 19.3

HU 5-20 MW 18.5 0.4 26.6 1.5 4.5 16.1 0.4 23.3

HU 20-50 MW 11.4 0.0 12.9 0.3 1.9 9.7 0 11.2

IE 1-5 MW 17.1 1.8 18.3 1.5 3.7 18.3 2.0 19.3

IE 5-20 MW 20.2 1.0 22.2 1.4 4.2 21.8 1.2 23.5

IE 20-50 MW 1.9 0.0 9.7 0.3 1.6 2.1 0.0 10.3

IT 1-5 MW 55.5 1.6 55.8 2.6 9.0 54.9 1.6 55.1

IT 5-20 MW 66.8 1.6 67.3 3.7 11.0 66.0 1.6 66.5

IT 20-50 MW 32.7 - 33.0 0.7 5.0 32.5 - 32.7

LT 1-5 MW 10.6 0.6 11.0 0.7 2.0 10.6 0.6 11.0

LT 5-20 MW 12.6 0.4 13.3 0.7 2.3 12.6 0.4 13.3

LT 20-50 MW 4.3 - 5.5 0.1 0.9 4.2 - 5.5

LU 1-5 MW 0.9 0.0 0.9 0.0 0.1 0.8 0.0 0.8

LU 5-20 MW 1.1 0.0 1.1 0.1 0.2 0.9 0.0 0.9

LU 20-50 MW 0.6 0.0 0.6 0.0 0.1 0.5 0.0 0.5

LV 1-5 MW 9.0 0.5 9.8 0.3 1.6 9.5 0.6 10.3

LV 5-20 MW 9.5 0.2 10.3 0.3 1.7 10.0 0.2 10.8

LV 20-50 MW 2.2 - 5.5 0.2 0.9 2.2 - 5.7

MT 1-5 MW - - 0.0 0.0 0.1 - - 0.0

MT 5-20 MW 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

MT 20-50 MW - - - 0.0 0.0 - - -

NL 1-5 MW 44.0 0.1 48.4 0.1 7.4 41.1 0.1 45.3

NL 5-20 MW 60.4 - 83.5 0.3 12.3 56.5 - 78.1

NL 20-50 MW 5.2 - 9.4 0.0 1.3 4.9 - 8.8

PL 1-5 MW 98.6 1.7 98.6 0.2 14.5 99.3 1.7 99.3

PL 5-20 MW 107.3 2.2 107.3 1.6 18.0 107.2 2.2 107.2

PL 20-50 MW 12.1 0.2 45.9 0.1 7.6 12.2 0.2 42.2

C7


Member State

2025 2030

ELVs

IED 50-100

MW Primary

NOx Most

Stringent MS


Primary NOx

Most Stringent MS

PT 1-5 MW 6.9 0.7 7.2 0.6 1.4 7.7 0.7 8.0

PT 5-20 MW 8.3 0.5 8.8 0.0 1.3 9.2 0.5 9.7

PT 20-50 MW 3.3 0.1 3.9 0.2 0.7 3.8 0.1 4.4

RO 1-5 MW 9.2 0.6 9.4 0.6 1.7 9.4 0.6 9.6

RO 5-20 MW 20.0 0.8 20.6 1.3 3.7 20.4 0.8 20.9

RO 20-50 MW 14.9 0.6 16.1 0.8 2.5 15.3 0.6 16.4

SE 1-5 MW 10.6 0.8 11.0 0.6 2.0 10.3 0.7 10.6

SE 5-20 MW 1.4 0.6 39.0 1.2 6.7 1.3 0.6 37.4

SE 20-50 MW 1.6 0.4 18.3 1.0 3.5 1.6 0.4 17.9

SI 1-5 MW 3.4 - 23.2 0.7 5.1 1.8 - 12.3

SI 5-20 MW - - - 0.0 0.5 - - -

SI 20-50 MW 3.8 0.1 3.9 0.2 0.6 2.1 0.0 2.2

SK 1-5 MW 17.2 0.0 18.3 0.1 2.8 17.7 0.0 18.7

SK 5-20 MW 24.2 0.0 24.2 0.1 3.9 25.2 0.0 25.3

SK 20-50 MW 6.0 0.0 16.3 0.2 2.5 6.0 0.0 18.6

UK 1-5 MW 90.6 2.6 87.9 4.1 14.6 89.6 2.5 88.8

UK 5-20 MW 109.2 2.8 109.2 6.2 18.1 108.1 2.7 108.1

UK 20-50 MW 40.4 0.0 54.6 0.3 7.0 40.6 0.0 54.2

C8


Figure C.2 Compliance costs (NOx) by Member State

0

100

200

300

400

500

600

700


(€m

/yea

r)

Compliance costs for 1-50 MWth total: NOX

2025 Primary NOx 2025 IED 50-100 MW 2025 Most stringent MS 2025 Gothenburg 2025 SULES

C9


Table C.3 Dust

Member State

2025 2030

ELVs IED 50-100 MW

Most Stringent MS


Most Stringent MS

AT 1-5 MW 0.6 0.6 0.5 0.5 0.5 0.6

AT 5-20 MW - 0.4 0.0 0.1 - 0.4

AT 20-50 MW - 1.7 0.1 0.3 - 1.7

BE 1-5 MW 1.8 2.7 2.1 2.1 1.8 2.7

BE 5-20 MW 2.4 2.4 1.8 1.8 2.4 2.4

BE 20-50 MW 1.1 1.1 0.9 0.9 1.1 1.1

BG 1-5 MW 1.5 1.7 1.4 1.4 1.7 1.8

BG 5-20 MW 1.8 1.8 1.6 1.6 2.0 2.0

BG 20-50 MW 0.8 0.8 0.7 0.7 0.9 0.9

CY 1-5 MW 0.2 0.2 0.1 0.1 0.2 0.2

CY 5-20 MW 0.2 0.2 0.1 0.1 0.2 0.2

CY 20-50 MW 0.0 0.0 0.0 0.0 0.0 0.0

CZ 1-5 MW 0.8 0.8 0.7 0.7 0.8 0.9

CZ 5-20 MW 0.3 0.3 0.2 0.2 0.3 0.3

CZ 20-50 MW 1.5 2.3 1.3 1.4 1.6 2.2

DE 1-5 MW 13.5 22.8 13.9 14.1 13.2 22.1

DE 5-20 MW 1.7 10.2 3.3 4.1 1.6 10.0

DE 20-50 MW 0.6 6.0 1.6 2.1 0.6 5.8

DK 1-5 MW 3.5 6.4 3.3 3.6 3.8 7.1

DK 5-20 MW 4.4 4.4 3.8 3.8 4.8 4.8

DK 20-50 MW 2.1 2.1 1.8 1.8 2.3 2.3

EE 1-5 MW 1.5 1.5 1.2 1.2 1.3 1.3

EE 5-20 MW 1.6 1.6 1.2 1.2 1.4 1.4

EE 20-50 MW 0.6 0.6 0.4 0.4 0.5 0.5

EL 1-5 MW 0.1 0.2 0.1 0.1 0.1 0.1

EL 5-20 MW 0.2 0.2 0.1 0.1 0.1 0.1

EL 20-50 MW 0.1 0.1 0.1 0.1 0.1 0.1

ES 1-5 MW 3.1 4.2 2.6 2.7 2.6 3.5

ES 5-20 MW 3.6 3.6 3.0 3.0 3.1 3.1

ES 20-50 MW 0.7 1.7 0.8 0.9 0.7 1.4

FI 1-5 MW 0.3 0.4 0.3 0.3 0.3 0.4

FI 5-20 MW 1.1 1.6 1.0 1.0 1.0 1.5

C10


Member State

2025 2030

ELVs IED 50-100 MW

Most Stringent MS


Most Stringent MS

FI 20-50 MW 0.1 3.9 0.5 0.9 0.1 3.5

FR 1-5 MW 11.9 23.5 6.3 6.0 11.3 21.9

FR 5-20 MW 3.5 20.4 5.5 7.6 3.3 19.5

FR 20-50 MW 3.2 29.1 6.3 9.6 3.0 27.6

HU 1-5 MW 0.3 0.7 0.8 0.8 0.3 0.7

HU 5-20 MW 0.2 0.6 0.9 0.9 0.2 0.6

HU 20-50 MW 0.3 0.5 0.4 0.4 0.3 0.5

IE 1-5 MW 4.1 5.5 2.7 2.7 4.3 5.5

IE 5-20 MW 4.8 4.8 4.0 4.0 5.1 5.1

IE 20-50 MW 2.2 2.2 1.9 1.9 2.3 2.3

IT 1-5 MW 0.6 0.9 0.4 0.5 0.5 0.8

IT 5-20 MW 0.6 0.6 0.5 0.5 0.6 0.6

IT 20-50 MW 0.3 0.3 0.2 0.2 0.3 0.3

LT 1-5 MW 1.0 1.5 0.8 0.9 1.1 1.6

LT 5-20 MW 1.2 1.2 0.9 0.9 1.2 1.2

LT 20-50 MW 0.6 0.6 0.5 0.5 0.6 0.6

LU 1-5 MW - - 0.0 0.0 - -

LU 5-20 MW - - 0.0 0.0 - -

LU 20-50 MW - - 0.0 0.0 - -

LV 1-5 MW 1.7 1.8 1.3 1.3 1.9 2.0

LV 5-20 MW 1.8 1.9 1.6 1.6 2.0 2.1

LV 20-50 MW 1.0 1.1 0.9 0.8 1.2 1.2

MT 1-5 MW 0.0 0.0 0.0 0.0 0.0 0.0

MT 5-20 MW 0.0 0.0 0.0 0.0 0.0 0.0

MT 20-50 MW - - 0.0 0.0 - -

NL 1-5 MW 0.1 0.4 0.1 0.1 0.1 0.3

NL 5-20 MW - - 0.0 0.0 - -

NL 20-50 MW - - 0.0 0.0 - -

PL 1-5 MW 0.4 0.4 0.3 0.3 0.3 0.3

PL 5-20 MW 2.9 2.9 2.2 2.2 2.7 2.7

PL 20-50 MW 8.6 8.6 6.6 6.6 7.6 7.6

PT 1-5 MW 1.5 1.8 1.3 1.4 1.5 1.8

PT 5-20 MW 1.8 1.8 1.6 1.6 1.8 1.8

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Member State

2025 2030

ELVs IED 50-100 MW

Most Stringent MS


Most Stringent MS

PT 20-50 MW 0.8 0.8 0.7 0.7 0.8 0.8

RO 1-5 MW 1.0 1.2 0.8 0.9 1.0 1.3

RO 5-20 MW 2.1 2.1 1.8 1.8 2.3 2.3

RO 20-50 MW 1.5 1.5 1.3 1.3 1.6 1.6

SE 1-5 MW 2.3 2.6 2.2 2.2 2.3 2.6

SE 5-20 MW 1.4 10.3 3.4 3.5 1.4 9.9

SE 20-50 MW 0.0 8.8 0.2 1.7 0.0 8.7

SI 1-5 MW 0.6 0.9 0.8 0.8 0.6 0.9

SI 5-20 MW 0.4 0.4 0.3 0.3 0.3 0.3

SI 20-50 MW 0.0 0.1 0.1 0.1 0.0 0.1

SK 1-5 MW 0.9 0.9 0.7 0.7 1.1 1.1

SK 5-20 MW 1.8 1.8 1.4 1.4 2.2 2.2

SK 20-50 MW 0.3 2.8 0.3 0.7 0.3 3.5

UK 1-5 MW 1.1 0.5 0.9 0.9 0.6 0.5

UK 5-20 MW 1.4 1.4 1.1 1.1 0.8 0.8

UK 20-50 MW 0.6 0.6 0.5 0.5 0.3 0.3

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Figure C.3 Compliance Costs (Dust) by Member State

0

10

20

30

40

50

60

70

80


(€m

/yea

r)

Compliance costs for 1-50 MWth total: PM

2025 IED 50-100 MW 2025 Most stringent MS 2025 Gothenburg 2025 SULES

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Appendix D Summary of Information Received by MS

Austria

New data has been received from the authorities.

Existing combustion installations

Comments on key assumptions applied in previous study

No comments received from competent authority

Short summary of any new quantitative data including any updates for regulatory regime for existing combustion installations <50 MWth

The competent authority has provided an updated data set including data on:

• The type of plants (boilers, turbines, engines, etc...) and on their sectoral breakdown. These data were not available for 1-5 MW;

• Fuel consumption;

• Emissions of SO2, NOx and Dust (incomplete set for 1-5 MW);

• Data provided on the number of plants and their capacity can be summarised as:

Capacity Class Summary of Data Provided Additional Comments

1-5 MWth Number of installations: 71

Total capacity of plants:148 (MWth)

The total number of installations in this category only reflects combustion of biomass and is indicated as a representative sample. There is no data available for gas and liquid-fuelled boilers <10 MW.


Total capacity of plants: 2003 (MWth)

The total number of installations in this category only includes steam boilers only (including gas turbines with heat recovery boiler). There is no data available for gas and liquid-fuelled boilers <10 MW.


Total capacity of plants: 3124 (MWth)

The total number of installations in this category only includes steam boilers only (including gas turbines with heat recovery boiler). There is no data available for gas and liquid-fuelled boilers <10 MW.

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Austria’s competent authority provided new information on the relevant regulatory regime: small combustion plants < 50 MWth are regulated through two pieces of national legislation22, which came into force in 2011. The competent authority has provided an updated set of ELVs which applies to new and existing plants.

Product standards for combustion installations 1-5 MWth

Information on sales of combustion unit <5 MWth

None received from competent authority

Current product standard legislative requirements for combustion unit < 5 MWth


Belgium

The competent authorities have provided one spreadsheet for the Flanders Region and two spreadsheets for Brussels. No information was submitted for the Walloon region.

Flanders Region





None received from competent authority as no change since previous consultation





Flanders competent authorities provided information on the existing legislation stipulating specific product standards for combustion units under 5 MW thermal input. Since 2004, legislation applies to oil and gas fired

22 BGB.II Nr.312/2011 concerns furnaces which are not steam boilers and BGBI.II Nr.153/2011concerning steam boilers and gas turbines < 50 MW.

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combustion units23. It was also reported that in 2010 a new legislation has been adopted for solid-fuels fired combustion units ranging from 50 to 300 kW thermal input24.

Brussels Region



The competent authority provided a list of the existing combustion plants within the Brussels Region. The list contains details on the capacity of the plants, the fuels used and the sector that the plant belongs to (i.e. tertiary, industry etc.). The listing provided also makes a distinction between combustion plants and combined heat and power plants





The competent authority reported that no sales data was available.


The following information was provided:

• There is no product standard legislation in place at a national level that applies to emissions from combustion units below 5 MW;

• However, there is existing legislation25 that includes minimum energy performance requirements. However no further details were provided on these requirements.

Bulgaria

No information has been received from the competent authority to date

23 Royal Decree of 8 January 2004 regulating the nitrogen oxides (NOx) and carbon monoxide (CO) emission levels for the oil-and gas-fired boilers and burners, with a rated thermal input equal to or less than 400 kW. It was modified by the Royal Decree of 17 July 2009 amending the Royal Decree of 8 January 2004 on regulation of nitrogen oxides (NOx) and carbon monoxide (CO) emission levels for the oil-and gas-fired boilers and burners, with a rated thermal input equal to or less than 400 kW 24 Royal Decree of 12 October 2010 regulating the minimum requirements of efficiency and emission levels of pollutants for heating appliances for solid fuel 25 Arrêté Chauffage, adopted 3 June 2010

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Cyprus



Cyprus commented on the assumptions applied in the previous study. In particular it commented on the split in two categories of the data they reported on fuel consumption for a global capacity class of 1-20 MWth. They stated that this number could not be split into the two separate classes of 1-5 MWth and 5-20 MWth in accordance with the ratio of the capacity classes as no detailed information on combustion plants was available;


Cyprus commented on the following data:

• The data provided for biomass (2580 tn) for the year 2009 has been given by mistake for the range 1-20 MWth. It was found recently that all the biomass is used in combustion plants with a capacity below 1 MWth; and

• The data provided for LPG (5160 tn) for the year 2009 actually refers to the 1-5 MWth class.



No information was provided by the competent authority



Czech Republic



No comment was provided on key assumptions applied


The competent authority noted that Czech Republic sent a detailed dataset for the previous study and that no update on data was available.

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However, it was reported that a new decree has entered in force 1 December 2012 and includes emission limit values for combustion installations between 0.3 and 50 MWth as well as requirements for the quality of fuel 26.



The competent authority reported that no information on sales was available. However, they provided a link to an inventory managed by a business association that collects and publishes detailed annual data on the development of the market for boilers below 50 kW27.


In Czech Republic, product standard assessment for combustion units is required since 1997 28. A new legislation has recently been adopted that states minimum emission standards for solid fuels combustion sources from 10 to 300 kW. This act will apply from 201629. The legislation targets all types of combustion units (boilers, turbines, furnaces etc) and all types of fuels. It applies to domestic and non-domestic combustion units.

The competent authority stated that Czech Republic has existing emissions standards for all combustion plants under 50 MWth. They are materialised as product standards below 0.3 MW, and over 0.3 MW and up to 50 MW they are emission standards.

The competent authority provided a lot of details on specific legislation applying to limit emissions from SO2, NOx, dust, chlorine and heavy metals. It also provides information on the monitoring requirements included in the legislation. Finally, it provides a detailed list of standards that are referred to in the product standard legislation in order to assess the emissions limit values and the minimum energy performance requirements.

Denmark



The following information was provided for boilers in 2010:

• Updated number of boilers, the data were obtained from the national database increased by 10%;

• Updated capacity estimates;

• Updated data on fuel consumption;

26 Decree No.415/2012 Coll. 27 The website is available at the following link: http://vytapeni.tzb-info.cz/zdroje-tepla/8720-prodeje-kotlu-v-roce-2011 28 Act No.22/1997 Coll. 29 Act. 201/2012 Coll.

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These data can be summarised as in the table below:



Total capacity of plants (MWth):2,898 Total fuel (TJ):12,378

The total number of installations in this category only reflects boilers and is indicated as being obtained from national database plus 10%


Total capacity of plants (MWth): 7,757 Total fuel (TJ):33,131



Total capacity of plants (MWth): 5,346 Total fuel (TJ):22,834


The competent authority also provided information on:

• Updated emissions data calculated from Danish emissions factors; and

• Information on the sectoral breakdown of the plants.

This information can be presented as in the table below:

Capacity class

% boilers

% engines

% turbines

% other

% public electricity

% public heat

% tertiary

% industry

1-5 MWth 56 41 1 2 41 47 1 11

5-20 MWth 75 21 2 2 23 65 1 11

20-50 MWth 80 14 4 2 22 65 0 13


The Danish competent authority submitted an additional document detailing the emission limits values per type of combustion units (i.e. boilers, engines and gas-turbines) and per type of fuels (i.e. LPG, biomass, natural gas, hard coal etc.). The emissions limits values applied are detailed per category: below 2 MW, from 2 to 5 MW and from 5 to 50 MW (following the split adopted in the Danish legislation).



D7





Estonia

No additional information was provided by the competent authority. Estonia sent a copy of the proforma that was sent during the previous consultation and stated that all the information was verified.

Finland



No comment was provided by the competent authority


Finland commented that no changes had been brought to their national legislation. They also warned that it was unlikely that they would be able to provide any data.





The competent authority commented that no product standard is available for boilers.

France



No comment was provided by the competent authority


D8


France reported that the legislation setting emissions limit values for combustion installations from 2 to 50 MWth is currently being revised. Possible future ELVs were provided for example, however due to the fact that the legislation is still being negotiated they were not integrated in our analysis.

The competent authority also provided updated data for the total number of plants in 2012 for 2-20 MW and 20-50 MW. France highlighted that no data was available below 2 MWth.

The data provided can be summarised as below:

Capacity Class Summary of Data provided Additional Comments

1-5 MWth Number of installations: - Data are not available below 2 MWth

5-20 MWth Number of installations: 13,000 The number of plants is based on estimation which has been reviewed since last year. The number of 13,000 plants correspond to plants from 2 to 20 MWth

20-50 MWth Number of installations: 1,600



France reported that no data was available on the sales of combustion unit below 5 MWth. The only data available are for domestic heaters below 1 MWth.


France’s competent authority commented that no product standard requirements were available in French legislation.

Germany



The competent authority made comments on assumptions applied:

• The emission limit values are not the same for all plants as they vary according to the fuel type and the plant capacity. Consequently, splitting the emission data across the three capacity sub-classes masks these differences and in some cases is not correct. For example the emission limit values for NOx from Light fuel oil and natural gas below and above 10 MW are different.

• Germany has a significant number of biogas engines. It was requested that these installations would be considered separately when assessing the options to reduce emissions. Specific data on biogas engines were provided.

D9



The competent authority reported that no new legislation had been introduced recently.

Updated data were provided for the emissions of SO2, NOx and dust per types of fuels. The data provided are for the whole1-50 MWth range. A summary of the data provided is included below:

Emissions in kt

SO2 from solid fuel

SO2 from liquid fuel

SO2 from other gaseous fuel

NOx from biomass

NOx from other solid fuel

NOx from liquid fuel

NOx from natural gas

NOx from other gases

Dust from biomass

Dust from other solid fuels

Dust from liquid fuels

Capacity

1-50 MWth 20,863 6,522 0,418 14,164 7,707 6,310 35,675 1,168 3,173 0,540 0,262

An additional document was provided, including updated information on:

• Emission data split up according to fuel types;

• Data on stationary engines; and

• Data on biomass CHP plants.



No information was provided by the competent authority.


Germany reported to have specific legislative product standard since 1998, and that the legislation had been amended in 201030. The legislation applies to natural gas and light fuel oil fired combustion units up to 10 MWth and prescribes specific emission limits values for NOx emissions.

In addition, a telephone conversation was held and the German competent authority provided detailed explanation on its national system and its products standard requirements.

Greece


30 BlmSch V

D10


Hungary



The competent authority commented on the fact that they did not have the capacity to check the data and assumptions applied in the previous study. Hungary is currently in the process of harmonising different existing databases in order to have more reliable data.


Information was provided in a separate document on applicable ELVs and the relevant legislation. There is applicable legislation for combustion plants between 140 KW to 50 MW 31 and for stationary gas engines 32. Details on the general monitoring requirements were also included.






Ireland

The competent authority did not have any comments and was not in measure to update or provide further information.

Italy

The competent authority did not have any comments and was not in measure to update or provide further information.

31 KöM Ministerial Decree 23/2001.(XI.13.) on the emission limit values of certain pollutants into the air from combustion plants with a rated thermal input between 140 kWth and 50 MWth 32 KTM Ministerial Decree 32/1993.(XII.23.) on the emission limit values of certain pollutants into the air from stationary gas engines

D11


Latvia



The competent authority did not provide any comments on the key assumptions applied in the previous study.


The competent authority provided updated quantitative data including:

• Updated number of plants;

• Updated total capacity of plants.

Capacity clas$s Summary of data provided Additional Comments


Total capacity of plants:1,923 (MWth)

The total number of installations concerns only boilers


Total capacity of plants: 1,898 (MWth)



Total capacity of plants: 1,157 (MWth)


Latvia’s competent authority also provided detailed information on its legislative framework and the applicable emission limit values. Installations are classified in categories according to criteria defined in the national law 33 and specific emissions limit value applies in function of the category the installation falls into. A specific legislation has been adopted for smaller units34. The requirements for monitoring and reporting the emissions are described in a separate Regulation35.

Permitting is required for the following combustion plants:

33 Cabinet Regulation No. 1082, Adopted 30 November 2010, "Procedure by Which Polluting Activities of Category A, B and C Shall Be Declared and Permits for the Performance of Category A and B Polluting Activities Shall Be Issued 34 Cabinet regulation No.1015, Adopted 14 December 2004, "Environmental requirements for small boiler houses", 35 Cabinet Regulation No.158, Adopted 17 February 2009, "Regulations on requirements for environmental monitoring and procedures for carrying out monitoring, development of pollutant release register and public access to information"

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• Installations with thermal input from 5-50 MW, if biomass (also wood and peat) or gaseous fuel is used ;

• Installations with thermal input from 0,5 – 50 MW, if liquid fuel (excluding fuel oil) is used;

• Installations with thermal input from 5-50 MW, if liquid fuel or fuel oil is used in grain dryer;

• Installations with thermal input from 0,2 – 50 MW, if coal is used.; and

• All installations in which fuel oil is used.





The competent authority reported that there is no existing product standard legislation.

Lithuania


Luxembourg

No information has been received from the competent authority to date.

Malta



In the previous study due to the absence of data reported by Malta, it was assumed that Malta was similar to Cyprus. The competent authority sent an updated set of data.


A set of data has been provided for Malta, it is specified that it is to be considered as a representative sample as it is only based on data provided by registered plants. The data includes:

• Number of installations;

• Total capacity of the plants;

D13


• Total fuel consumption;

• Percentage of installations already covered by the IED as ‘directly associated activity’

This information can be summarised as below:



Total capacity of plants (MWth):78 Total fuel consumption (TJ): 513

All of the data are representative data based on registered plants only. No aggregation has been applied.


Total capacity of plants (MWth): 48 Total fuel consumption (TJ): 57



Total capacity of plants (MWth): 0 Total fuel consumption (TJ): 0


Additionally, the competent authority provided information on:

• Sectoral breakdown of the installations;

• Technology type breakdown of the installations.

Capacity Class

% Boilers

% Engines

% Turbines

% Other

% Public Electricity

% Public Heat

% Food Industry

% Industry

1-5 MWth 75 25 0 0 0 0 9 91

5-20 MWth 100 0 0 0 0 0 29 71

20-50 MWth 0 0 0 0 0 0 0 0

Information was also provided on the applicable legislation. Malta has enacted a national law to control emissions from combustion installations36. The law foresees that industrial combustion plants falling outside the scope of the IPPC/IED needs to be registered and permitted. The permit includes specific emission limits values and monitoring requirements. However, the ELVs are not specified in the national law and the authorities are using the ELVs in the German legislation TA Luft37.

36 Legal Notice 478 of 2010, Ambient Air Quality Regulations, 2010 37 First General Administrative Regulation Pertaining the Federal Immission Control Act (Technical Instructions on Air Quality Control – TA Luft) of 24 July 2002

D14







The Netherlands



The competent authority commented on some ELVs that were used in the previous study that are not corresponding to the ELVs included in the national legislation.


The Netherlands have provided an almost complete dataset during the previous consultation, so few gaps were left. The competent authority sent an update of the applicable emission limit values as modified by a recently adopted legislation that came into force on 1 January 2013.

Additional data were sent on:

• The sectoral breakdown of the installations; and

• An estimate of dust emissions and SO2.

The data provided can be summarised as in the table below:

Capacity Class Public Electricity CHP Hospitals Greenhouses Food Industry Other

1-5 MWth 5 90 1800 2400 300 700 1700

5-20 MWth 5 5 30 2000 40 120 50

20-50 MWth 0 0 0 60 10 40

Estimate Dust Emissions (PM 10) Estimate SO2 Emissions

1 PJ * 0.015=0.015 kton pm10 1 PJ * 0.013=0.013 kton

D15




The competent authority reported that this information was not available



Poland



The competent authority reported that operators of installations between 1-5 MWth do not have to report information on their installations. So the competent authority does not have a complete set of data against which the data used in the previous study could be checked.


The competent authority provided a complete update including for each capacity class:

• Total number of installations,

• Total capacity of the installations;

• Types of combustion units,

• Emissions estimates of PM, SO2 and NOx; and

• Fuels characteristics.

The information provided can be summarised as below:


1-5 MWth Number of installations: 307 Total capacity of plants (MWth): 726 Emissions of PM (kt):0,257 Emissions of SO2 (kt):0,514 Emissions of NOx (kt):0,454 Technology type of installations: Boilers

The data in this category are incomplete as the reporting of data is voluntary

D16



5-20 MWth Number of installations: 258 Total capacity of plants (MWth): 3,005 Emissions of PM (kt):1,981 Emissions of SO2 (kt):4,367 Emissions of NOx (kt): 2,465 Technology type of installations: Boilers

The data in this category are incomplete as the reporting of data is voluntary

20-50 MWth Number of installations: 246 Total capacity of plants (MWth): 8,238 Emissions of PM (kt):3,999 Emissions of SO2 (kt):10,970 Emissions of NOx (kt):5,397 Technology type of installations: Boilers mostly

The competent authority also provided information on the legislation and the applicable ELVS and monitoring requirements38. Finally, information was included concerning the abatement techniques applied for each of the three categories of plants. This information is summarised in the table below.

Abatement Technique Capacity Class Efficiency Pollutant

Battery of cyclones 1-5 MWth 77-95 Dust

5-20 MWth 70-98 Dust

20-50 MWth 72-97.7 Dust

Dry cyclone 1-5 MWth 70-90 Dust

5-20 MWth 60-96 Dust

20-50 MWth 44-92 Dust

Dry ESP 5-20 MWth 90-98.3 Dust

20-50 MWth 92-97 Dust

Fabric filter 1-5 MWth 85-99 Dust

5-20 MWth 75-99.9 Dust

20-50 MWth 90-99.9 Dust

Sedimentation chamber 1-5 MWth 15-32 Dust

38 For ELVs: Regulation of 22 April 2011 on emission standards from installations (Dz. U. Nr 95, poz. 558) and Regulation of 2 July 2010 on cases when release of gases or particulates into the air do not requires the permit (Dz. U. Nr 130, poz. 881). For monitoring: Regulation of 4 November 2008 on requirements for emission measurements and water uptake measurements (Dz. U. Nr 206 poz. 1291).

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Abatement Technique Capacity Class Efficiency Pollutant

Multi-cyclone 1-5 MWth 80-90 Dust

5-20 MWth 50-99.9 Dust

20-50 MWth 50-99 Dust

Semi dry calcium method 20-50 MWth 50-80 SO2






Portugal


Romania

Romania’s competent authority only commented on the terms of reference of the current study. They commented that the regulation of combustion installations below 50 MWth at EU level is not necessary as most Member States have already permitting and monitoring system targeting these installations.

Slovenia

Slovenia provided information for the previous study and during a telephone conversation stated that they were satisfied with the gap filling approach adopted.

Slovakia



The competent authority did not have any comment on the assumptions applied in the previous study but they asked for clarifications on the way the number of installations already affected by the IED as ‘directly associated activities’ had been derived.

D18



The competent authority updated the whole dataset with data from 2011. The data includes:

• Total number of installations;

• Total capacity of installations;

• Total fuel consumptions;

• Updated emissions

The information are summarised in the table below:

Capacity Class Summary of Data provided

1-5 MWth Number of installations: 1,986 Total capacity of plants (MWth): 4,223 Total fuel consumption (TJ): 11,698 Emissions of PM (kt): 0.23 Emissions of SO2 (kt): 0.14 Emissions of NOx (kt) :0.67

5-20 MWth Number of installations: 581 Total capacity of plants (MWth): 5,114 Total fuel consumption (TJ): 15,422 Emissions of PM (kt): 0.13 Emissions of SO2 (kt): 0.24 Emissions of NOx (kt): 1.11

20-50 MWth Number of installations: 91 Total capacity of plants (MWth): 2,695 Total fuel consumption (TJ):13,145 Emissions of PM (kt): 0.13 Emissions of SO2 (kt): 0.21 Emissions of NOx (kt): 1.18

• Sectoral breakdown of installations;

• Technology breakdown of installations

This information is summarised in the table below:

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Capacity Class

% Boiler

% Engine

% Turbine

% Other

Public Electri-

city Public Heat

Food Industry

Indu-stry Hospital Tertiary Other

1-5 MWth 96.2 1.9 0.1 1.8 24 349 75 393 77 892 176

5-20 MWth 98.7 0.8 0.2 0.3 13 296 36 96 38 72 30

20-50 MWth 97.4 0.4 0.4 1.9 3 44 9 19 6 6 4

The competent authority added that no new legislation had been adopted and the ELVs remained unchanged.



The competent authority commented that this information was not available


The competent authority reported that there is no national legislation setting product standard requirements.

Spain

The competent authority was not in measure to send information, however they provided some information on the legislative requirements in one of the autonomous regions (Galicia).

Sweden




The competent authority provided an updated set of data for Sweden. The data have been updated using three existing databases covering specific plants, expert judgement and the national Swedish statistics. The competent authority included details on the estimation of numbers. The updated data includes for each capacity class:

• Updated number of plants;

• Total capacity of plants;

• Updated emissions of dust, SO2, NOx;

• Total fuel consumption; and

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• Information on the technology breakdown

The information provided are summarised below:


1-5 MWth Number of installations: 733 Total capacity of plants (MWth): 2,199 Total fuel consumption (TJ):7,376 Emissions of PM (kt): 0.22 Emissions of SO2 (kt): 0.14 Emissions of NOx (kt) :1.45 Technology type: all boilers

The data do not include stationary engines that are only used for power reserve at hospitals and nuclear plants. It also excludes a dozen of gas turbines that are for power reserve. Finally, it excludes plants in which products of combustion are used for the direct heating, drying, or any other treatment of objects or materials.

5-20 MWth Number of installations: 627 Total capacity of plants (MWth): 7,524 Total fuel consumption (TJ):35,813 Emissions of PM (kt): 0.44 Emissions of SO2 (kt): 1.78 Emissions of NOx (kt) :4.44 Technology type: 99% boilers


20-50 MWth Number of installations: 158 Total capacity of plants (MWth): 5,530 Total fuel consumption (TJ):35,406 Emissions of PM (kt): 0.19 Emissions of SO2 (kt): 0.53 Emissions of NOx (kt) :2.80 Technology type:99 % boilers


The competent authority also reported that there is no general ELV set in Sweden, they are decided on a plant-by-plant basis and set in the permit.



The competent authority has not provided any information


D21


The competent reported that no national legislation specified product standard requirements for combustion unit below 5 MWth.

United Kingdom

The competent authority did not comment or report feedback on the dataset developed in the previous study. Information provided by the industry was forwarded. It includes incomplete numbers of combustion plants for the following industries: vehicle manufacturers, waste water treatment plants and food and drink manufacturers.

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E1


Appendix E Collated Member State Data

Note on Combustion Installations Versus Combustion Plants

Section 1.2 in this report noted that Chapter II of the IED regulates combustion installations of 50 MWth or more, with additional provisions in Chapter III for combustion plants of 50MWth or more. As described in Section 1.2.2 an installation may comprise multiple plants (stacks), and each plant may comprise multiple combustion units (e.g. boilers). For the purposes of data collection for this study, data has been requested on combustion plants (at the stack level), in accordance with the scope of how large combustion plants are presently regulated in Chapter III of the IED. Nonetheless, some of the data returns from Member States have been indicated to be at the boiler level (Finland, Brussels region of Belgium and Sweden). It is unclear whether any of the data returns are at the installation level.

Numbers of Plants

The data reported by Member States on the numbers of combustion plants less than 50 MWth are summarised below in Table E. 1. Any Member States not listed in the table below have not reported numbers of combustion plants. As is noted in the final column of the table, in many cases the data provided by a Member State do not represent a complete picture of combustion plants in that Member State.

Table E. 1 Numbers of Combustion Plants of Rated Thermal Input less than 50MW Reported by Member States, Split by Capacity Class (Note 1)

Member State

Total Number of Combustion Plants Comments on Completeness of the Data by Member States and AMEC (denoted separately)

1-5MW 5-20MW 20-50MW Total

Austria - 190 116 306 MS: These numbers are for steam boilers only. However, we suppose that most of the combustion plants with a rated thermal input > 5 MW are steam boilers. These numbers also exclude any combustion plant < 10 MW that is operated by gaseous fuel or gasoil. The number of 20-50MWth plants should be more or less the correct number. However, the submitted number of plants < 10 MW is very rough information. The number of combustion plants [5-20 MW] is with complete certainty much higher than 190 because of the non-registered plants 5-10 MW using gasoil or natural gas. There is no official view on estimated number of plants, but the correct number could be two or three times higher than 190.

Belgium 2,880 890 144 3,914 MS: The Wallonia figures are indicated to relate to emission trading only (although include plants less than 20MWth) and exclude combustion installations of residential buildings and tertiary sector. The Brussels figures (1-5MWth and 5-20MWth only) are at a boiler level. AMEC: These numbers are the combined totals from three separate regions Wallonia, Brussels and Flanders.

E2


Member State

Total Number of Combustion Plants Comments on Completeness of the Data by Member States and AMEC (denoted separately)


Cyprus 172 36 3 211

Czech Republic

4,068 748 175 4,991

Denmark 899 810 176 1,885 MS: These numbers are at the boiler level. Source of the data is the Danish national database to which 10% has been added (by the MS) for adjustment.

Estonia 537 174 29 740

Finland 196 205 181 582 MS: These numbers are at the boiler level. Source of data is the Finnish national emission register VAHTI. In the VAHTI emissions register, data concerning larger units (20 - 50 MW) is more accurate than data concerning smaller units. AMEC: Estimates of the number of Finnish plants have been derived from the boiler level data using the unique (x,y,z) coordinates of boilers as recommended and supplied by the authorities. These estimates have not been confirmed: 136 1-5MWth plants, 140 5-20MWth plants, 133 20-50MWth plants.

France 13,000 for category 2 to 20MWth

1,600 14,600

MS: The number of plants is based on estimation which has been reviewed since last year consultation. The number of 13 000 plants correspond to the number of plants between 2 and 20MWth, no data available for plants <2MWth

.

Germany 35,500 3,480 658 39,638

Latvia 915 205 40 1,160 MS: These numbers are at the boiler level.

Malta 36 7 0 43 MS: These are estimates number accounting only for registered plants.

Netherlands 6,995 2,250 110 9,355 The figures presented are a rough estimate.

Poland 307 284 246 837 MS: Data concerning plants from 1 to 20 MW are incomplete

Portugal - - 34 34

Romania 790 370 146 1,306

Slovakia 1,986 581 91 2,658

Slovenia 222 119 18 359 MS: The numbers in class 1-5MWth are only boilers using solid fuel. The numbers in class 5-20MWth exclude boilers using natural gas below 10 MW.

Spain - - 1,130 1,130 AMEC: the figures provided appear high and may be an overestimate.

Sweden 733 627 158 1,518 MS: These figures are at a site level. They exclude stationary engines used for power reserve at hospitals and nuclear plants. It also excludes plants in which products of combustion are used for the direct heating, drying, or any other treatment of objects or materials.

United Kingdom

>38 >35 413 413 MS: The numbers in classes 1-5MWth and 5-20MWth are for Northern Ireland only.

Subtotal 80,212 5,468 85,680

Note 1: Boxes marked with “-“ indicate no data provided.

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From the data gathered it appears that robust data on numbers of combustion plants less than 50 MWth (in particular below 20 MWth) are not widely held by Member States. Some Member States appear to have provided seemingly robust figures on these (Cyprus, Czech Republic, Estonia, Germany, Romania and Slovakia), but for many Member States the estimates are either only approximate (Austria, Denmark, Finland, France, Latvia, Malta, Netherlands, Poland and Sweden) or exclude certain categories of plants or even whole regions (Belgium, Slovenia, Spain and United Kingdom). Furthermore, no data have been gathered for several Member States: Bulgaria, Greece, Hungary, Ireland, Italy, Lithuania, Luxembourg and Portugal.

As such, the numbers of plants presented in the table above are considered to be an underestimate for the Member States presented, as well as being an underestimate for the EU.

It is also important to note two points in particular for this table: (a) that the estimated figures reported by France make up 40% of the total reported by the Member States which appears high; and (b) some Member States (Belgium [Brussels region], Denmark, Finland, Latvia and Sweden) are known to have reported at the boiler level, which can lead to a slight overestimate in the number of plants/installations.

The above estimates of numbers of plants rated 1 to 50 MWth are much higher than the numbers of large combustion plants currently regulated in the EU: the number of LCPs of capacity 50-100 MWth is reported to be 987, and the total number of LCPs is reported to be 3,243.39

Capacity of Plants

The data reported by Member States on the capacity of combustion plants 1 to 50 MWth are summarised below in Table E.2. Member States not listed in the table have not reported capacity of combustion plants. The percentage share of total capacity among the three capacity classes has been included for those Member States whose data have been highlighted in green (i.e. whose data appear to be complete).

39 AMEC (2011) Analysis and summary of the Member State’s emission inventories 2007-2009 and related information under the LCP Directive. Final report to the European Commission.

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Table E.2 Capacity of Combustion Plants of Rated Thermal Input less than 50 MWth Reported by Member States, Split by Capacity Class

Member State

Total Capacity of Combustion Plants (GWth) Comments on Completeness of the Data by Member States and AMEC (denoted separately) 1-5MW 5-20MW 20-50MW Total

Austria 1.48 2 3.1 6.6 MS: These numbers are for steam boilers only, i.e. they exclude combustion plants that exclude steam boilers. Numbers for 1-5 MW are for installations using biomass only.

Belgium 6.5 8.5 4.6 19.6 MS: The Wallonia figures are indicated to relate to emission trading only (although include plants less than 20MWth) and exclude combustion installations of residential buildings and tertiary sector. The Brussels figures (1-5MWth and 5-20MWth only) are at a boiler level. AMEC: These numbers are the combined totals from three separate regions Wallonia, Brussels and Flanders. Although the Wallonia figures are indicated to relate to emission trading only they include plants less than 20MWth.

Cyprus 0.4 (50%) 0.3 (35%) 0.1 (15%) 0.8

Czech Republic

8.5 (41%) 7.2 (34%) 5.2 (25%) 20.9

Denmark 2.9 7.7 5.3 15.9 MS: Around 10% of the total is an average

Estonia 1.2 (30%) 1.8 (45%) 1.0 (25%) 4.0

Finland 0.6 (6%) 2.1 (23%) 6.4 (71%) 9.1 MS: Source of data is the Finnish national emission register VAHTI. In this register, data concerning larger units (20 - 50 MW) is more accurate than data concerning smaller units.

France 400 for 2 to 20MWth class

75 475 MS: No data available on plants 1-2MWth. These figures are maximum capacities, assuming that plants in the capacity class ranges are at the upper end of the scale. AMEC: Based on the capacity classes, AMEC calculates that the capacities of the French plants will lie within the range of 70 to 475 GWth and are unlikely to be close to the total maximum capacity (475 GWth) provided by the French authorities. A mid-range estimate of around 270 GWth may be more realistic

Germany 2.3 - 22.5 24.8 MS: No capacity data are available for the solid biomass plants reported in the numbers table. Figures for 20-50MWth plants are derived from ETS data. The figure for 1-5MWth plants covers approximately 6000 biogas engine plants which are mostly less than 3MWth AMEC: The figure for 1-5MWth plants covers approximately 6000 biogas engine plants which are mostly less than 3MWth and much of which must fall below the 1MWth threshold since the average plant capacity of the reported data is <1MWth.

Latvia 1.9 (39%) 1.9 (38%) 1.1 (23%) 4.9

Malta 0.8 0.5 0 1.3 MS: These are estimates number accounting only for registered plants.

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Member State

Total Capacity of Combustion Plants (GWth) Comments on Completeness of the Data by Member States and AMEC (denoted separately) 1-5MW 5-20MW 20-50MW Total

Netherlands 21 (44%) 23 (48%) 3.7 (8%) 47.7 MS: The figures presented are a rough estimate.

Poland 0.7 3 8.1 11.8 MS: Data concerning plants from 1 to 20 MW are incomplete

Portugal - - 1.2 1.2

Romania 1.6 (22%) 2.7 (37%) 3.1 (42%) 7.4

Slovakia 4.2 (35%) 5.1 (43%) 2.7 (22%) 12

Slovenia 0.5 1.3 0.5 2.3 MS: The numbers in class 1-5MWth are only boilers using solid fuel. The numbers in class 5-20MWth exclude boilers using natural gas below 10 MW.

Sweden 2.2 7.5 5.5 15.2 MS: These figures are at a site level. They exclude stationary engines used for power reserve at hospitals and nuclear plants. It also excludes plants in which products of combustion are used for the direct heating, drying, or any other treatment of objects or materials.

United Kingdom

0.1 0.4 13.3 13.8 MS: The capacities in classes 1-5MWth and 5-20MWth are for Northern Ireland only. The capacity for 20-50MWth is estimated to lie in a range from 11.3GWth to 15.4GWth.

Subtotal (19)

532 (combined 1 to 20MWth) 162 694.3

The figures reported by France are estimates based on assuming the average capacity of a plant in a capacity class is the maximum capacity of that class. This assumption is unlikely to be correct, and more realistic figures are calculated by AMEC and noted in the table above.

As such, the total capacity of plants presented in the table above are considered to be on the one hand an underestimate due to those plants excluded in some Member State reports and the Member States that have not reported, and on the other hand to be an overestimate for the Member States presented, due to the French estimates (which, as reported, comprise over 70% of the reported capacity).

For comparison with the above estimates of capacities of plants rated 1 to 50 MWth: the total capacity of large combustion plants 50-100 MWth is reported to be 74 GWth, and the total capacity of all LCPs (> 50 MW) is reported to be 1,354 GWth in 2009.40

40 AMEC (2012) Analysis and summary of the Member State’s emission inventories 2007-2009 and related information under the LCP Directive. Final report to the European Commission.

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Fuel Consumption of Plants

The data reported by Member States on the fuel consumption of combustion plants between 1 and 50MWth are summarised below in Table E. 3. Any Member States not listed in the table below have not reported these data.

Table E. 3 Fuel Consumption Reported by Member States from Combustion Plants < 50MWth, Split into Five Fuel Types (when available)

Member State

Fuel Type Fuel Consumption (PJ) % of MS Total

Notes


Austria Biomass 1.5 1.8 14.2 17.5 35% Representative data for steam boiler only for plants from 5to 50 MW. For plants below 5 MW, the data cover only combustion plants using biomass.

Liquid fuels - 0.4 0.3 0.7 1.5%

Natural gas - 11.3 15.6 26.9 54.5%

Other gaseous fuels

- 3 1.4 4.4 9%

Cyprus Biomass 0.03 0.03 1% Cyprus provided combined data for a 1-20 MW band

Liquid 1.5 1.2 2.7 91% Includes Gas oil & fuel oil, Cyprus provided combined data for a 1-20 MW band

Other gaseous fuels

0.2 0.2 8% Cyprus provided combined data for a 1-20 MW band

Czech republic

Biomass 1.8 1.8 2.9 6.5 2%

Other solid 1.8 1.1 6.0 8.9 3% Mostly brown coal

Liquid 0.7 0.4 2.0 3.2 1% Mostly heating oil

Natural Gas

74.6 214.0 18.7 307 94%

Denmark Biomass 4.1 11 7.5 22.6 33% Assumed fixed load factors based on capacity data, around 10% of the total is an average

Other solid 2.7 7.3 5 15 22% Assumed fixed load factors based on capacity data, around 10% of the total is an average

Liquid 1.5 4 2.8 8.3 12% Assumed fixed load factors based on capacity data, around 10% of the total is an average

Natural Gas

3.8 10.3 7 21.1 30% Assumed fixed load factors based on capacity data, around 10% of the total is an average

Other gaseous fuels

0.4 1 0.7 2.1 3% Assumed fixed load factors based on capacity data, around 10% of the total is an average

Estonia Biomass 2.1 2.5 2.8 7.3 30% firewood & wood waste

Other solid 0.1 0.1 0.3 0.5 2% coal, peat & oil shale

Liquid 1.2 1.4 0.7 3.3 13% light heating oil, shale oil, waste oil & diesel fuel

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Member State


Notes


Natural gas 2.4 4.5 2.1 9.0 37%

Other gaseous fuels

0.2 0.1 4.2 4.5 18% pyrolysis process gases & biogas

Finland Biomass 4 4 9 17 28% Typically wood-based

Other solid 1 1 8 11 17% Includes: Peat, some coal in larger units

Liquid 1 5 10 17 27% Includes: Heavy oil &some light oil

Natural gas 2 4 9 15 24%

Other gaseous fuels

0.5 1 1 2 3% Includes: biogas, waste gas, liquid gas

France Biomass - - - - 15%

Other solid - - - - 2% Other solid fuel is coal

Liquid - - - - 25% Liquid fuel is LPG, HFO and domestic heating fuel oil

Natural gas - - - - 56%

Germany Biomass 10 174 Other solid fuels are coal and lignite. Figures for total 1-50MWth plants are derived from the national emission inventory. Figures for 20-50MWth plants are derived from ETS data. The figure for 1-5MWth plants covers approximately 6000 biogas engine plants which are mostly less than 3MWth and so some of this may be below the 1MWth threshold. The data presented in earlier tables on solid biomass plants are not represented in this table due to lack of fuel consumption data on the solid biomass plants.

Other solid 13 52

Liquid 6 83

Natural gas 117 426

Other gaseous fuels

130 5 135

Netherlands Biomass 1 1 0.3% Biomass is wood. Other solid fuels are waste. All figures presented are a rough estimate. Natural gas 130 160 40 330 99%

Other fuels 1 1 0.3%

Malta Liquid fuels 0.2 0.06 0 0.26 46% Representative data based on registered plants only.

Other gaseous fuels

0.3 0 0 0.3 54% Representative data based on registered plants only.

Poland Biomass 0.3 1.6 1.4 3.3 1% Information from the national emission database. The data are not complete for the 1-5 MW and 5-20MW capacity classes

Other solid 1 13.8 35 49.8 15.5%

Liquid 0.9 0.5 0.06 1.46 0.5%

Natural gas 116 137 10.3 263.3 82%

Other gaseous fuels

0.4 1.2 1.5 3.1 1%

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Member State


Notes


Portugal Biomass - - 4.4 4.4 29%

Liquid - - 4.0 4.0 27% Liquid fuels include diesel, fuel oil, and LPG

Natural gas - - 6.7 6.7 44%

Slovakia Biomass 0.6 1.2 4.1 5.9 15% Includes wood and woodchips & other vegetal matter

Other solid 0.4 1.0 2 3.4 8.1% Includes: anthracite, Polish black coal CZ black coal, Czech brown coal, Slovak brown coal SK, lignite, coke, other solid fuels, waste from agriculture, horticulture, forestry, hunting and fishing, aquaculture production, food production and processing, waste from wood processing and manufacturing of paper, paperboard, pulp, sawn timber and furniture and waste from medical or veterinary care or related research

Liquid 0.04 0.01 0.006 0.056 0.1% Include: heavy fuel oil, medium fuel oil, light fuel oil, other liquid fuels, diesel and propane-butane

Natural gas 10.3 13.2 7 30.5 75.9%

Other gaseous fuels

0.3 0.01 0.04 0.35 0.8% Include: Biogas & propane-butane

Sweden Biomass 4.3 17.3 30.2 51.8 66% MS: Data have been calculated from three database available in Sweden. Stationary engines used for power reserve at hospitals and nuclear plants are excluded from the data. Other solid fuels include coal, peat and waste. Liquid fuel is fuel oil.

Other solid 0 0.2 0.7 0.9 1%

Liquid 2.7 17.3 2.5 22.5 29%

Natural gas 0.3 1.1 2 3.4 4%

United Kingdom

Biomass 2 2 0.1% Data are only applicable to Northern Ireland. No data for England, Scotland or Wales. Liquid fuels include heavy fuel oil and gas oil

Other solid 0.1 0.1 0.01%

Liquid 0.1 1 1 0.1%

Natural gas 3 85 1,695 1,783 91%

Other gaseous fuels

1 174 184 9%

The data in the above table that are highlighted in green are also summarised in Figure E.1. This figure shows that the dominant fuel for reported small combustion plants is natural gas (90% for plants 1-5MWth, 84% for plants 5-20MWth and 55% for plants 20-50MWth). With increasing capacity, usage of solid fuels (biomass and other solid fuels) increases. Biomass reaches 20% for 20-50 MWth capacity class. Liquid fuels make up less than 6% of fuels in all capacity classes. Other gaseous fuels make up less than 3% in all capacity classes.

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In some countries the main fuel used differs from the overall EU average. For example, in Poland, the use of other solid fuels dominates over biomass, in Sweden biomass is the primary fuel type and Cyprus mainly uses liquid fuels.

Figure E.1 Split of Reported Fuel Consumption of Combustion Plants 1 to 50MWth by Fuel Type and Capacity Class

Note: Fuel consumption data presented in red in the table for the UK and Germany have been excluded to avoid distortion

Emissions of Key Pollutants

The data reported by Member States on the emissions of combustion plants between 1 and 50MWth are summarised below in Table E.4 including data provided by Member States on the percentage of total Member State emissions that the emissions from 1 to 50 MWth combustion plants make up. Any Member States not listed in the table below have not reported these data to this study. For those Member States that did not provide an estimate of the proportion of national emissions, national totals have been retrieved from CLRTAP submissions and included in italics. No information has been gathered to identify whether the emissions data submitted by Member States have mainly been calculated or monitored. Whilst no Member States have declared the method by which the emissions data have been derived (e.g. Denmark), some Member States have indicated that emissions have been extracted from national databases, (e.g. Estonia), whilst for others the data are considered a reliable source (e.g. Swedish NOX emissions are from the Swedish NOX tax database).

Table E.4 Dust/PM10, SO2/SOX and NOX Emissions of Combustion Plants of Rated Thermal Input less than 50MW Reported by Member States, split by Capacity Class

Member State

Pollutant Emissions from Combustion Plants (t) Notes

1-5MW 5-20MW 20-50MW 1-50MW % of MS Total Emissions

Austria Dust 50 20 90 160 0.5% Representative data for steam boiler only for plants from 5to 50 MW. For plants below 5 MW, the data cover only combustion plants using

SO2 - 90 110 200 1%

NOX 160 750 2240 3150 1.7%

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

Sum of fuel consumption 20-50 MW

Sum of fuel consumption 5-20 MW

Sum of fuel consumption 1-5MW

Biomass

Other solid fuels

Liquid

Natural Gas

Other gaseous fuels

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Member State



biomass.

Belgium Dust - - - 487 3% The figures presented are for the Wallonia region only. The boilers around 1MWth of the tertiary sector were not taken into account (hospitals, schools). The boilers of residential buildings above 1MWth are not taken into account. Total emissions of heavy metals were also reported.

PM10 - - - 393 5%

SO2 (SOX) - - - 1,726 8%

NOX - - - 5,176 6%

Cyprus Dust 65 44 109 2% The Member State also provided data for emissions of Pb, Cd, Hg As, Cr, Cu, Ni, Se and Zn. Cyprus has provided aggregated figures for the capacity class 1 to 20MWth

SO2 972 494 1,466 8%

NOX 212 1,959 2,171 11%

Czech republic

Dust 321 308 223 852 1%

SO2 1,807 1,248 4,080 7,136 4%

NOX 1,941 1,958 2,236 6,135 3%

Denmark Dust 80 250 80 410 1% The MS stated that emissions were calculated from Danish emissions factors SO2 290 940 770 2000 14%

NOx 1,990 4,180 1,630 7,800 6%

Estonia Dust 1,141 1,015 1,386 3,542 13% Data were also provided for emissions of HCl, Pb, Hg, Ni, As, Cd, Cr, Cu & Zn SO2 4,431 648 3,990 9,069 17%

NOX 552 754 529 1,835 6%

Finland Dust 220 320 320 860 -

SO2 560 1,800 3,680 6,040 -

NOX 1,680 1,940 4,420 8,040 -

France Dust 3,739 2,479 6,218 1% France has provided aggregated figures for the capacity class 1 to 20MWth SO2 18,480 8,034 26,514 9%

NOX 36,242 10,284 46,526 4%

Germany Dust 3,770 1% Data were also provided for emissions of Mercury. Germany provided combined 1-50MW figures for emissions.

SO2 29,800 7%

NOX 62,900 5%

Malta Dust 17 0.8% Malta reported CLRTAP data for sector 1A2fi (Stationary Combustion in Manufacturing Industries and Construction:

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Member State



Other)

SO2 30 0.4%

NOX 60 0.7%

Netherlands NOX 8,600 11,700 1,600 21,900 8% The figures presented are a rough estimate.

Poland Dust 0.257 1,981 3,999 5,979 2% The Member State indicated that data for 1-20 MW were incomplete. AMEC: The year of the provided emissions data is 2011. Latest national totals (2010) were used to calculate the percentage.

SO2 0.514 4,367 10,970 15,338 2%

NOX 0.454 2,465 5,397 7,862 1%

Slovakia Dust 230 130 130 490 2% Emissions data for year 2011.

SO2 140 240 210 590 1%

NOX 670 1,110 1,180 2,960 3%

Slovenia Dust 126 126 24 276 1% The numbers in class 1-5MWth are only boilers using solid fuel. The numbers in class 5-20MWth exclude boilers using natural gas below 10 MW.

SO2 107 193 137 437 4%

NOX 926 794 541 2,261 5%

Sweden Dust 220 440 190 850 2%

SO2 140 1,780 530 2,450 7%

NOX 1,450 4,400 2,800 8,690 5%

Note: The figures of % of MS total emissions for Denmark, Malta, Poland, Slovakia, Slovenia and Sweden have been calculated by AMEC on the basis of supplied emissions data for the combustion plants together with national total emissions reported to CLRTAP

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Appendix F Adjustments made to Data provided by Member States

Note: Member States not listed in this appendix either provided complete data for the MS or provided no data (and were therefore gap-filled in an alternative manner).

Austria

Number and capacity of plants (5-20MWth)

The information provided by the MS covers estimated numbers of plants (=stack) with steam boilers firing solid fuels, biomass and non-standard fuels in capacity classes 5-20MW and 20-50MW. The data originate from a data bank about emission reports from plant operators of steam boilers. For 1-5 MW capacity class data have only been provided for a sample of biomass fired plant.

The reported numbers of plants in the 20-50MW capacity class are suggested to be correct, but that those in the 5-20MW capacity class are likely to be an underestimate, and potentially a significant underestimate.

Adjustments need to be made to the data to take account of the following exclusions:

• The number of plants excludes combustion plants that are not steam boilers. The MS has indicated that “most of the combustion plants with a rated thermal input > 5 MW are steam boilers”.

• The number of plants excludes combustion plants 5-10MW using gas oil or natural gas.

The following adjustments have been made to the 5-20MW numbers and capacities:

iv. Based on a review of indications submitted by other Member States, assumed that approximately 80% are steam boilers, therefore multiply numbers and capacity by a factor of 1.11 to take account of missing data.

v. Assume that one third of the plants are in the capacity range 5-10MWth., i.e. one third of the capacity range 5 to 20MWth.41 The data for Slovakia (a neighbouring MS) suggest that 80% of fuel consumption is natural gas. We assume this ratio is also true for numbers/capacity of plants in AT, i.e. that the data provided for 5-10MWth (which excludes plants using gas oil or natural gas) represents

41 Although it could be argued that a greater number of plants than a third would lie in the capacity bracket 5-10MWth, without robust data to suggest an alternative figure, a simple assumption of one third is adopted. For capacity of plants, the assumption of one third may well be more appropriate than for numbers of plants.

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20% of all plants. Therefore adjust the number of plants in the (sub) 5-10MWth category by a factor of 5. This leads to an overall multiplying factor of 2.33 for the 5-20MW sector.42

Belgium

Data for Belgium comprises data provided separately from each of the three regions of Flanders, Wallonia and Brussels.

Wallonia

The data on numbers, capacity and emissions provided by the Wallonia authorities exclude data on the following plants:

• Boilers in the tertiary sector (hospitals, schools) above 1 MWth

• Boilers in the residential sector above 1 MWth

In order to account for these two exclusions, the following adjustments are made:

• To account for missing tertiary sector, the average contribution this sector comprises of each capacity class from other MS data (Figure 3.4 in the interim report) is utilised for data on numbers and capacity (and as a total of 1-50MWth for emissions): 25% 1-5MWth, 9% 5-20MWth, 9% 20-50MWth, 18% 1-50MWth. I.e. the numbers and capacity data for capacity classes 1-5, 5-20 and 20-50MWth are multiplied by factors 1.33, 1.1 and 1.1 respectively. The emissions data are multiplied by a factor of 1.22.

• To account for the missing residential sector, comparison was made with the detailed sector data provided by SK, in which the residential sector comprised only an appreciate proportion of total number of plants in the 1-5MWth capacity class, and in this instance comprised 4% of the total. Therefore an uplift factor for the 1-5MWth capacity class of 1.04 is used for numbers and capacity data only.

The emissions data were provided as a total for the three capacity classes. In order to apportion these data across the three capacity classes:

• It is proposed to use the ratio of installed capacity among the three capacity classes to split the emissions data. This inherently assumes that plant emission levels across the three capacity classes are the same. A comparison of the ELVs for Flanders and Wallonia suggests that this is a reasonable assumption.

Flanders and Brussels

The data provided by the Brussels region is provided at the boiler level. We are unable to convert these data into the stack level, and so are accepted as a known limitation of the data. Note: we have not attempted to adjust the

42 This is in-line with an approximate factor estimated by the Austrian authorities.

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boiler-level data into a number of stacks as per the approach for Sweden and Finland, as the ratio of boilers to stacks for Brussels is not necessarily the same as for the Scandinavian countries. The implication is that the number of plants for Brussels (and Belgium) and thus estimates based on this (e.g. costs) may be overestimates.

Neither of the regions provided emissions data whilst Wallonia did. Therefore, there is a gap in the emissions data for Belgium.

• It is proposed to utilise the ratio in capacity data of the Flanders and Brussels region to that of the Wallonia region to extrapolate estimated emissions for the whole of Belgium. This inherently assumes that plant emission levels across the three Belgian regions are the same. A comparison of the ELVs for Flanders and Wallonia suggests that this is a reasonable assumption.

Cyprus

Data on fuel consumption and emissions were provided by the MS as an aggregate for the capacity class 1 to 20MWth. Data on numbers and capacity of plants were however provided separately for the two capacity classes 1-5MWth and 5-20MWth.

• The fuel consumption and emissions data for the combined capacity class 1-20MWth are proposed to be split into the two separate capacity classes in accordance with the ratio of the capacity classes.

Finland

The data provided by Finland are provided at the boiler level. It is possible from the data provided to make preliminary estimates of the number of Finnish plants (stack) using the unique (x,y,z) coordinates of boilers supplied by the Finnish authorities. These estimates have not been confirmed by the authorities.

• Propose to use estimated revised numbers at the stack level: 136 1-5MWth plants, 140 5-20MWth plants, 133 20-50MWth plants.

France

The number of 2-20MWth plant has been reported to be 13,000, and that of 20-50MWth is 1,600. The number of plant in the 1-2 MWth category, for which data have not been provided, has been estimated. To do so, the reported number of 2-20 MWth plant has been distributed between 2-5 MWth and 5-20 MWth, using the average ratio in countries for which data has been provided. Then the number of 2-5 MWth plant has been uplifting using the assumption that there is one third as many 1-2 MWth plant as 2-5 MWth. This results in an estimate of 13,399 plant of 1-5 MWth and 2,951 plant of 5-20 MWth (i.e. 16,350 for 1-20 MWth).

The data on numbers (and capacity) provided appear to be high, so the following checks have been performed to validate the figures.

The estimate for the number of 20-50MWth plants has been checked as follows:

• The number of combustion installations >20MWth in the 2009 CITL database is 787

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• The number of combustion facilities >50MWth in the 2009 E-PRTR database is 137

• The number of combustion plants >50MWth in the 2009 LCPD dataset is 241

From the above data points it is implied (assuming one facility is equivalent to one installation) that there are approximately 650 combustion installations 20-50MWth. Looking at the ratio of the number of combustion plants (stack) vs. installation >50MWth suggests a ratio of plant:installation of 241:137. If the same ratio remained true for 20-50MWth installations, the estimated number of combustion plants(stack) 20-50MWth is (241/137)*650 = 1143 plants.

The estimate derived of 1,143 is 29% lower than the estimate provided by the FR authorities. It should be noted that it is the same order of magnitude, and because of this, it is proposed to retain the estimate provided by the French authorities.

The estimate of the number of 1-20MWth plants has been checked as follows:

• The average ratio of number of plants 1-20MWth to 20-50MWth from those MS that provided full data is 45:1. Such a ratio applied to either estimate of FR 20-50MWth plants yields a figure much higher than 16,350.

• Compared against the estimate for Germany (data provided by the DE authorities and BDEW) of 1-20MWth plants of 38,980, and against the estimate for NL by the Dutch authorities of 9,245, the estimate for France appears plausible.

Germany

Data on numbers of plants were provided by BDEW, disaggregated for boilers, engines and turbines, by size category and fuel type.

Data on fuel consumption and emissions were provided by the German authority for a 1-50MWth capacity class. Total fuel consumption of other gases was not available for certain gases, and therefore estimates were made to fill the gaps by multiplying the (complete) reported emissions by emission factors. The emission factors were calculated using data reported for similar categories.

The average load factor implied for the 20-50MWth capacity class (from the capacity and fuel consumption data; of 1864hrs/annum), is used to calculate the capacity of a 1-20MWth capacity class from the derived 1-20MWth fuel consumption. The capacity and fuel consumption estimates for 1-20MWth plants are split into the 1-5MWth and 5-20MWth plants by using the average ratio of capacity for those EU MS that did provide data.

The emissions data have been split across the three capacity sub classes in the ratio of the estimated fuel consumption for each capacity class. This is because the applicable recommended limit values for plants <50MWth in Germany are the same for all plants 1-50MWth.

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Malta

Partial data has been provided for the 1-5MWth and 5-20MWth capacity class. Not all installations are currently included so it has been assumed that there are 2 additional plant in the 5-20MWth capacity class and 50% more plant than reported in the 1-5MWth capacity class. This is on the basis that the Authority indicated:

The data provided in Malta's report is based on registered plants only. With regards to the 50-20MW category we are quite confident that we have no installations that fall within this category. We believe that most combustion plants with a capacity ranging between 5 and 20MW have been registered, but there might be a few others that still need to be registered. A higher degree of uncertainty exists for the smaller combustion plants (5-1MW), since the registering process for such installations is still ongoing. 43

Poland

Data have been provided but has been indicated to be incomplete. Reported data has been used to estimate the ratio of fuel use by each fuel type for the 1-5MWth and 5-20MWth capacity class.

Slovenia

1-5MWth plants

The data (numbers, capacity and emissions) on plants 1-5MWth represent only plants fired with solid fuel. It is therefore necessary to adjust these data to be representative of all plants in Slovenia. It is proposed to use the ratio of fuels used in 20-50MWth SI plants to fill this gap.44

• The data provided (on solid fuel plants) on numbers and capacity should be multiplied by a factor of 9 in order to be representative of all fuels, since it is assumed that a total of 11% of the fuel consumption is of solid fuels (biomass and other solid fuels).

• The data provided (on solid fuel plants) on emissions should not be multiplied by a factor of 9 as the emission level of fuels other than solid fuels (primarily natural gas) are lower than solid fuels. It is proposed to multiply the NOX emissions data (only) by a factor of [9*[emission level of natural gas plant]/[emission level of coal plant]]. Since SO2 and dust emissions from natural gas are ignored, no change is proposed to these emissions.

43 Personal communication: Thomas Paris, MEPA, email dated 25/01/2013

44 The data for Slovakia, a country considered to have similar fuel mix profile was also investigated, i.e. whether the SK data on the fuel mix in the 1-5MWth capacity class could be used instead of the SI data on the fuel mix in 20-50MWth plants. The results of this investigation show that a very similar factor would result (SK proportion of fuel consumption that is solid fuels is 9% in 1-5MWth capacity class compared to the 11% in SI 20-50MWth plants).

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5-20MWth plants

The data (numbers, capacity and emissions) on plants 5-20MWth excludes data for those plants which are <10MWth and which are fired with natural gas. It is therefore necessary to adjust these data to be representative of all plants in Slovenia.

• It is proposed to use the ratio of fuels at 20-50MWth plants in SI45, shown below, coupled with an assumption that natural gas consumption at plants 5-10MWth is one third of natural gas consumption at 5-20MWth plants. These two assumptions leads to an estimate that the data provided on numbers and capacity represent 71% of the actual situation, i.e. that the data on numbers and capacity should be multiplied by a factor of 1.4.

• The data provided on emissions should not be multiplied by a factor of 1.4 as the emission levels of natural gas are lower than for other fuels. It is proposed to multiply the NOX emissions data (only) by a factor of [1.4*[emission level of natural gas plant]/[emission level of coal plant]]. Since SO2 and dust emissions from natural gas are ignored, no change is proposed to these emissions.

Fuel consumption of all plants

• Total fuel consumption data should be estimated from Slovenian capacity data using EU average load factors in line with other Member States.

• The split among fuel types should be adopted (from Table 3-5 of the AEA (2007) study) as:

Biomass Other Solid Liquid Nat Gas Other

6.0% 5.0% 2.4% 86.6% 0.0%

Sweden

The data for the capacity class 1-5MWth appear quite small. The data source from the SE authorities for all the plants is the NOX charge databank; since the NOX charge applies to boilers producing >25GWh per year, this effectively means that it will not cover any plants in the 1-5MWth capacity class. Therefore the small amount of data provided by the MS for this capacity class will be gap-filled.

It is unclear whether the Swedish figures for numbers of plants are at a boiler level. For Finland, an estimate has been made on the number of plants the boiler inventory represents. Although this ratio used in Finland could be utilised for Sweden, the existing data appear robust in terms of the average capacity per plant being 10MWth in the 5-20MWth category and 28MWth in the 20-50MWth category.

Data do not include other technologies, therefore values have been scaled up.

45 As for 1-5MWth plants, data on 5-20MWth plants in Slovakia were also investigated for use instead of utilising the fuel mix of Slovanian 20-50MWth plants. The results of this investigation show that a very similar factor would result (SK proportion of fuel consumption that is natural gas is 85.0% in 5-20MWth capacity class, compared to 86.6% in SI 20-50MWth plants).

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United Kingdom

The data provided for capacity classes 1-5MWth and 5-20MWth are representative for the region of Northern Ireland only. Since this is only a small part of the United Kingdom it is not thought that these data are representative of the UK as a whole. Therefore, the gap-filling process for 1-5MWth and 5-20MWth capacity classes is proposed to be as if no data were provided.

• Overwrite UK provided data on 1-5MWth and 5-20MWth plants and estimate these from other methods as per all MS.

For the capacity class 20-50MWth, we have applied a dataset developed for the UK Government by AMEC instead of the data provided.

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Appendix G Energy Efficiency

11.1 Overview This appendix provides a summary of research undertaken looking at the energy efficiency of 1-50MWth combustion plants. It is based on a rapid review of readily available information sources and relevant legislation as well as some limited consultation with relevant stakeholders. Although the research focused on small combustion installations between 1 and 50MW, smaller and larger combustion units were also considered in the literature review part of this report.

11.2 Literature review

11.2.1 Definition of efficiency

Throughout the literature slightly different terms are used to describe the energy efficiency of combustion units such as boilers, gas turbines etc. Efficiency is defined as the ratio of the useful energy per unit of energy input. Other terms that are used in literature with the same definition are: Boiler efficiency, thermal efficiency or fuel efficiency. They all refer to the ratio of the useful energy per unit of energy input.

11.2.2 LCP BREF46

The LCP BREF covers combustion installations with a rated thermal input exceeding 50 MW. This includes the power generation industry and those industries where ‘conventional’ (commercially available and specified) fuels are used and where the combustion units are not covered within another sector BREF. Coal, lignite, biomass, peat, liquid and gaseous fuels (including hydrogen and biogas) are regarded as conventional fuels. The LCP BREF provides information about the efficiency of combustion units and the efficiencies that can be achieved with the use of Best Available Techniques (BAT).

The efficiency of coal- and lignite-fired combustion plants

According to the LCP BREF, the efficiency of coal–fired combustion plants ranges from 21%, for old plants built during the 60s, to 44% for plants built between 1990 and 2000. Operating conditions strongly influence the mean efficiency recorded during operation. The measured efficiency of the plant is different from the design efficiency, as operation rarely complies with ideal conditions (due to fouling, slagging, de-superheating, non-ideal condenser conditions, blowdown, etc.), and as the characteristics of the solid fuel used never comply exactly with the

46 European Commission, “Reference document on Best Available Techniques for Large Combustion Plants”, 2006

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characteristics of the ‘design solid fuel’ (calorific value, ash content, etc.). Ageing of a normally maintained plant (fouling, slagging, erosion, leaks, etc.) also leads to a deterioration in efficiency over time. Other aspects that influence in the LCP efficiency are the technology used, the level of pollution control and the design of the auxiliaries.

For a clean and new boiler, an efficiency level of around 86 - 95 % (LHV47) is recorded for solid fuels and is reported that it cannot easily be increased. The main losses stem from flue gas waste heat at stack, unburned carbon-in-ash, waste heat and from heat radiation losses. The effect of fuel is also important. Even assuming that the boilers have identical performance, different boiler efficiencies are still obtained and these depend on the fuel, for example:

• international coal: 95 % efficiency

• lignite: 92 % efficiency

• low grade lignite: 86 % efficiency.

Energy efficiency of liquid fuel-fired combustion plants

The boiler efficiency for a clean and new boiler using liquid fuel has been reported to be around 95 % (LHV). The main losses are from flue-gas waste heat at the stack, unburned carbon-in-ash and radiation losses. Oil-fired boiler efficiency is closely linked with the nature of the fuel and the temperature of the ambient air. However, optimisation of some parameters such as unburned carbon ash, excess air and flue-gas temperature is possible.

Efficiency of gaseous fuel-fired combustion plants

The efficiency of gas fired power plants has increased continuously during the last decade by optimisation of the process and by new developments in the field of materials and cooling techniques, which make higher turbine inlet temperatures possible. The table below provides an overview of the efficiencies of gas-fired power plants, designed for electricity production at base load:

Table 11.1 Thermal efficiencies of gas-fired power plants

Thermal efficiencies (%)

Conventional power plant 38 – 49

Simple cycle gas turbine 30 – 42

Simple cycle spark-ignited (SG) or dual fuel engines

40 – 47

Combined cycle with HRSG 46 – 58

47 LHV = Lower heating value

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Thermal efficiencies (%)

Topping cycle with hot wind box 50

Note: The data have been obtained during full load operation. If load operation decreases, thermal efficiencies decrease significantly.

The LCP BREF mentions that the efficiency values reported above apply to new, clean gas turbines at full load and ISO conditions and once-through cooled condensers. For other conditions, the values may be lower, as efficiency strongly depends on ambient conditions and the type of cooling system applied, as well as on the operating mode.

The reason for the highest efficiency of the combined cycle is that the gas turbine gives 65 to 70 % of the total capacity and the energy conversion in the gas turbine is very effective in using relatively hot gases in the turbine. An increased unit efficiency is possible due to the increased firing temperature of the gas turbine and the increased gas turbine exhaust temperature, which results in higher superheated steam temperatures and allows the use of dual or triple pressure heat recovery steam generators.

Efficiency of biomass and peat fired combustion plants

Many peat and biomass fired power plants in Europe are CHP plants. The cogeneration of electricity and heat enables the energy contained in the fuel to be used to its full advantage, and the plant efficiency is thus high (85 – 90%). The energy efficiency (fuel efficiency) level for co-generation plants is difficult to determine on a general basis. The efficiency is highly site-specific with important issues being the heat load and changes in the heat load, price level and the need for electricity in the market, applied technology, etc.

The biomass or peat fired condensing power plants based on fluidised bed combustion are usually smaller in size than the coal-fired plants and the steam pressure and temperature are much lower than with the advanced coal-fired power plants. The heat rate levels for biomass and peat fired FBC power plants are around 3.3 – 3.6 (power plant efficiency 28 – 30 %). But only a few plants operate with these fuels for power generation only. Concerning pulverised peat firing, efficiency levels at 38 – 39 % have been reached in a pulverised peat boiler in Finland.

Thermal efficiency with the application of BAT

According to the LCP BREF (2006), one way to reduce the emission of CO2 per unit of energy generated is the optimisation of the energy utilisation and the energy generating process. Increasing the thermal efficiency has implications on various parameters such as load conditions, cooling system, emissions and use of type of fuel.

Cogeneration (CHP) is considered as the most effective option to reduce the overall amount of CO2 released and is relevant for any new build power plant whenever the local heat demand is high enough to warrant the construction of the more expensive cogeneration plant instead of the simpler heat or electricity only plant. The BAT conclusion to increase efficiency and the BAT associated levels are summarised in the following tables. In this sense, it should be noted that HFO fired plants are considered to have similar efficiencies than coal fired plants.

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For power plants, energy efficiency is considered as the heat rate (fuel input energy/energy output at power plant border) and as the power plant efficiency, in the LCP BRED is considered as the inverse of heat rate, i.e. the percentage of energy produced/fuel input energy. The fuel energy is measured as the lower heating value.

Table 11.2 Levels of thermal efficiency associated with the application of BAT measures for coal and lignite fired combustion plants

Table 11.3 Levels of thermal efficiency associated with the application of BAT measures for peat and biomass fired combustion plants

Fuel Combined technique Unit thermal efficiency (net) (%)

Electric efficiency Fuel utilisation (CHP)

Biomass Grate-firing Around 20 75 – 90 Depending on the specific plant application and the heat and electricity demand

Spreader-stoker >23

FBC (CFBC) >28 – 30

Peat FBC (BFBC and CFBC) >28 – 30

FBC: fluidised bed combustion CFBC: circulating fluidised bed combustion

BFBC: bubbling fluidised bed combustion CHP: cogeneration

Table 11.4 Efficiency of gas-fired combustion plants associated with the application of BAT

Plant type Electrical efficiency (%) Fuel utilisation (%)

New plants Existing plants New and existing plants

Gas turbine 36-40 32-35 -

Gas engine 38-45 -

Gas engine with HRSG in CHP >38 >35 75-85

Fuel Combined technique Unit thermal efficiency (net) (%)

New plants Existing plants

Coal and lignite Cogeneration (CHP) 75-90 75-90

Coal PC (DBB and WBB) 43-47 The achievable improvement of thermal efficiency depends on the specific plant, but as an indication, a level of 36* – 40 % or an incremental improvement of more than 3 % points can be seen as associated with the use of BAT for existing plants

FBC >41

PFBC >42

Lignite PC (DBB) 42-45

FBC >40

PFBC >42

PC: pulverised combustion DBB: dry bottom boiler WBB: wet bottom boiler

FBC: fluidised bed combustion PFBC: pressurised fluidised bed combustion

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Plant type Electrical efficiency (%) Fuel utilisation (%)

New plants Existing plants New and existing plants

Gas-fired boiler 40-42 38-40

Combined cycle with or without supplementary firing (HRSG) for electricity generation only

54-58 50-54 -

Combined cycle without supplementary firing (HRSG) in CHP mode

<38 <35 75-85

Combined cycle with supplementary firing in CHP mode

<40 <35 75-85

HRSG: heat recovery steam generator CHP: cogeneration

No specific thermal efficiency values were concluded when using liquid fuels in boilers and engines. However, some techniques to consider are available in the respective BAT sections.

Relationship between efficiency and environmental issues

The LCP BREF (2006) also provides a relationship between efficiency and environmental issues in the combustion plants. As reported, increases in efficiency have the following effects on fuel consumption, waste heat and emissions:

Savings in fuel: 𝛥𝑒 = 1 − 𝑛1𝑛2

Reduction in waste heat: 𝛥𝑎 = ∆𝑒1−𝑛1

Reductions in CO2 emissions: ∆𝐶 = 1 − 𝑛1𝑛2

Reduction in pollutant gas emissions: ∆𝜀 = 3.6∗𝑉𝑅∗𝑥𝐻𝑢

∗ ( 1𝑛1− 1

𝑛2) (mg/kWh)

Variables:

n1 efficiency before improvement

n2 efficiency after improvement

VR volume air/kg fuel (m3/kg)

x threshold limit value (mg/m3)

Hu lower calorific value (MJ/kg)

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11.2.3 Commission Decision 2011/877/EU

This Commission Decision establishes harmonised efficiency reference values for separate production of electricity and heat for different types of fuels. The reference values shall be used in order to compare the primary energy savings of cogeneration units with the references for separate production of heat and electricity. The decision also includes correction factors relating to the average climatic situation. The harmonised efficiency reference values for separate electricity and heat production are presented in the tables below. In both cases the values are based on net calorific value and standard ISO conditions (15oC ambient temperature, 1013 bar, 60% relative humidity)

Table 11.5 Harmonised efficiency reference values for separate production of electricity according to Commission Implementing Decision 2011/877/EU

Year of construction:

Type of fuel

2001 and before

2002 2003 2004 2005 2006-2011

2012-2015

Sol

ids

Hard coal/coke 42.7 43.1 43.5 43.8 44.0 44.2 42.2

Lignite/lignite briquettes 40.3 40.7 41.1 41.4 41.6 41.8 41.8

Peat/ peat briquettes 38.1 38.4 38.6 38.8 38.9 39.0 39.0

Wood fuels 30.4 31.1 31.7 32.2 32.6 33.0 33.0

Agricultural biomass 23.1 23.5 24.0 24.4 24.7 25.0 25.0

Biodegradable (municipal) waste

23.1 23.5 24.0 24.4 24.7 25.0 25.0

Non-renewable (municipal and industrial waste)

23.1 23.5 24.0 24.4 24.7 25.0 25.0

Oil shale 38.9 38.9 38.9 38.9 38.9 39.0 39.0

Liqu

ids

Oil (gas oil + residual fuel oil), LPG

42.7 43.1 43.5 43.8 44.0 44.2 44.2

Biofuels 42.7 43.1 43.5 43.8 44.0 44.2 44.2

Biodegradable waste 23.1 23.5 24.0 24.4 24.7 25.0 25.0

Non-renewable waste 23.1 23.5 24.0 24.4 24.7 25.0 25.0

Gas

eous

Natural gas 51.7 51.9 52.1 52.3 52.4 52.5 52.5

Refinery gas/hydrogen 42.7 43.1 43.5 43.8 44.0 44.2 44.2

Biogas 40.1 40.6 41.0 41.4 41.7 42.0 42.0

Coke oven gas, blast furnace gas, other waste gases, recovered waste heat

35 35 35 35 35 35 35

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Table 11.6 Harmonised efficiency reference values for separate production of heat (%)

Type of fuel Steam/hot water Direct use of exhaust gases (*)

Sol

ids

Hard coal/coke 88 80

Lignite/lignite briquettes 86 78

Peat/ peat briquettes 86 78

Wood fuels 86 78

Agricultural biomass 80 72

Biodegradable (municipal) waste 80 72

Non-renewable (municipal and industrial waste) 80 72

Oil shale 86 78

Liqu

ids

Oil (gas oil + residual fuel oil), LPG 89 81

Biofuels 89 81

Biodegradable waste 80 72

Non-renewable waste 80 72

Gas

eous

Natural gas 90 82

Refinery gas/hydrogen 89 81

Biogas 70 62

Coke oven gas, blast furnace gas, other waste gases, recovered waste heat

80 72

(*) Values for direct heat should be used if the temperature is 250 oC or higher

Ambient temperature correction that is included in the Decision is based on the difference between the annual average temperature in a Member State and standard ISO conditions (15 °C). The correction factors that are provided relating to the average climatic situation are:

(i) 0,1 %-point efficiency loss for every degree above 15 °C

(ii) 0,1 %-point efficiency gain for every degree under 15 °C

11.2.4 EU ETS

The EU ETS has used an efficiency of 90% with natural gas as fuel for setting the benchmark value for heat production. The heat benchmark does not make any distinction between different origins of heat (e.g. produced

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from different fuels, produced by boilers or CHP, heat as a by-product of a benchmarked production process, etc.)48.

The efficiency value used was based on the Commission Decision 2007/74/EC which was the Decision repealed by Commission Decision 2011/877/EU described in the previous section. The review of the Decision did not produced evidence to indicate that the energy efficiency of boilers has changed in the period considered, and therefore the harmonised efficiency reference values for the separate production of heat remained unchanged (see Table 2.5 above). As reported in Table 2.5, for steam and hot water, reference efficiency values are given ranging from 70% for biogas to 90% for natural gas. For all fossil fuels (excluding waste flows and biomass), the reference efficiency value is between 86 and 90%. Efficiencies of 90% with natural gas as fuel is the best efficiency reported in the Commission Decision. The Decision does not differentiate between hot water and various types of steam.

The impact assessment49 accompanying the Commission Decision on determining the rules for harmonised free allocations reports different efficiencies of the heat production system (e.g. boiler) which were considered during the determination of the heat benchmark value:

Table 11.7 Efficiencies reported in the impact assessment accompanying the Commission Decision on determining the rules for harmonised free allocations

Efficiency Fuel type Comments

93% Natural gas The most energy efficient technology available

90% Natural gas and 3.3% of biomass Lower efficiency due to the use of biomass

90% Natural gas Lower efficiency due to about 9% CHP share in the heat production

90% Natural gas It represents a widely used energy efficient technology. Although it is not considered best available technology, it is consistent with Commission Decision 2007/74/EC establishing harmonised efficiency reference values for separate production of electricity and heat in the application of Directive 2004/8/EC on the promotion of cogeneration

70% Solid fuels Average boiler efficiency

80% Liquid and gas fuels Average boiler efficiency

80% Primary solid biomass and waste gases, i.e. the fuels consumed by these installations

The efficiency reported is above average and it based on the 10% most greenhouse gas efficient heat production

The impact assessment also reports that the 90% efficiency with natural gas as fuel will be reduced by about 10% taking into account an expected increase in the use of biomass/renewable energy and improved efficiency in heat production and heat use until 2020.

48 European Commission, Guidance Document n°2 on the harmonized free allocation methodology for the EU-ETS post 2012, June 2011 49 European Commission, Impact Assessment - Accompanying document to the Commission Decision on determining transitional Union-wide rules for harmonised free allocation pursuant to Article 10a of Directive 2003/87/EC, 2010.

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According to the impact assessment, the extent to which air quality will be affected, will be influenced by the extent to which switching to natural gas or biomass occurs. Any switching to natural gas from oil or coal will result in reductions in emissions of most air pollutants. The impacts of switching to biomass from fossil fuels will be dependent upon the type of biomass used and is likely to lead to a reduction in SOx and possibly NOx. Impacts on emissions of particulate matter may increase.

Furthermore, the study “Developing Benchmarking criteria for CO2 emissions50” which was drafted in support of the ETS revision, reports typical overall fuel efficiency of industrial CHP installations. In the report, the fuel utilisation (fuel efficiency) is defined as a ratio of the useful energy per unit of energy input.

Table 11.8 Typical efficiencies of industrial CHP installations51

Type of installation Capacity (MWe) Overall fuel efficiency

Large combined cycle 250 75%

Small combined cycle 80 84%

Large gas turbine 25 78%

Gas engine 2 90%

Steam turbine52 2-50 90%

11.2.5 Energy Efficiency Directive53

The new Energy Efficiency Directive promotes cogeneration units. According to paragraph 35 of Article 14 of the Energy Efficiency Directive: “New electricity generation installations and existing installations which are substantially refurbished or whose permit or licence is updated should, subject to a cost-benefit analysis showing a cost-benefit surplus, be equipped with high-efficiency cogeneration units to recover waste heat stemming from the production of electricity....”. The impact assessment study of the Directive reported that cogeneration makes it possible to reach 85-90% efficiency of energy production compared to the 35-45% average efficiency of the EU power plant and industrial boiler fleet.

50 Ecofys, The Fraunhofer Institute for Systems and Innovation research by order of the European Commission, Developing Benchmarking criteria for CO2 emissions, February2009. 51 Hers, J.S., Wetzels, W., Seebregts, A.J., and van der Welle, A.J., Onrendabele top berekeningen voor bestaande WKK 2008, May 2008. 52 Data based on Ecofys expert opinion 53 European Commission, Directive 2012/27/EU on energy efficiency, amending Directives 2009/125/EC and 2010/30/EU and repealing Directives 2004/8/EC and 2006/32/EC.

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11.2.6 JRC report - Best available technologies for the heat and cooling market in the European Union54

The report provides an overview of the best available technologies that can be used for district heating including combined heat and power generation, industrial technologies, service and residential technologies and finally agriculture and fishery technologies.

Boilers for industrial applications

Industrial applications might require heat and cooling, both for space conditioning and forprocesses. This area covers the use of heat and cold for a number of different technologies within many different industrial sub- sectors, e.g. chemicals, paper, food, refining and metals. The efficiency reported for the most common fuels used in industrial boilers are:

Table 11.9 Efficiency of industrial boilers by type of fuel

Fuel Actual energy efficiency, full load Actual energy efficiency, low load

Coal 85 % 75 %

Oil 80 % 72 %

Natural gas 75 % 70 %

Biomass 70 % 60 %

It is reported that the installation of economisers can make it possible to extract the surplus heat from the flue gas. Mainly boilers that use natural gas can exploit this technique due to the possibility of condensation of the flue gas. The feed water pre heating using an economizer to extract the heat from a boiler exhaust can increase the efficiency from 1 % to 7 % (typically 5 %). Combustion air pre-heating can improve efficiencies by between 1 % and 2 % (typically 1 %).

54 JRC, “ Best available technologies for the heat and cooling market in the European Union”, 2012, http://publications.jrc.ec.europa.eu/repository/bitstream/111111111/26689/1/eur%2025407%20en%20-%20heat%20and%20cooling%20final%20report-%20online.pdf

http://publications.jrc.ec.europa.eu/repository/bitstream/111111111/26689/1/eur%2025407%20en%20-%20heat%20and%20cooling%20final%20report-%20online.pdf

http://publications.jrc.ec.europa.eu/repository/bitstream/111111111/26689/1/eur%2025407%20en%20-%20heat%20and%20cooling%20final%20report-%20online.pdf

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11.2.7 JRC report – Small combustion installations: Techniques, emissions and measures for emission reduction55

The study deals with small combustion installations with a thermal capacity ≤ 50 MWth; two categories of boilers are examined:

• Small boilers (single household/domestic heating) capacity ≤ 50 kWth

• Boilers with indicative capacity between 50 kWth and 50 MWth

According to the report, boilers of capacity between 50 kWth and 50 MWth are used in multi-residential houses, block of flats and are the most common sources to be found in commercial and institutional sector as well as in agriculture. Efficiency range is only reported for coal/wood boilers. For the other types of boilers e.g. moving bed combustion, fluidised bed combustion etc. a specific efficiency range is not provided

The efficiency reported for coal/wool boilers is 60 – 80%. For condensation boilers it is reported that they partly utilise the latent heat of the water vapour in the flue gases due to its condensation in the heat exchanger and for that reason their efficiency is higher than for other boiler systems. They could efficiently operate at lower inlet water temperatures and besides high efficiency condensation boilers also have lower NOx emissions.

11.2.8 US EPA national emission standards for hazardous air pollutants for major sources: Industrial, commercial and institutional boilers and process heaters

The latest rules that were published by the US EPA in January 2013 do not include specific efficiency targets for industrial, commercial and institutional boilers and process heaters but they include efficiency credits which count towards the compliance with emission limits.

Existing installations can choose to comply with the output-based emission limits instead of the input-based limits. Those installations can take credit for implementing energy saving measures identified in an energy assessment and can demonstrate compliance using efficiency credits according to the procedures described in the rules. Operators using this compliance approach must establish an emissions benchmark, calculate and document the efficiency credits, develop an Implementation Plan, comply with the general reporting requirements, and apply the efficiency credit according to the procedures. Credits are generated by the difference between the benchmark energy that is established for each affected boiler, and the actual energy demand reductions from energy conservation measures implemented after 1 January 2008. Credits are calculated by using a specific formula provided in the rules and can be used to calculate the adjusted emission level with which they must comply.

55 JRC report, Small combustion installations: Techniques, emissions and measures for emission reduction, 2007.

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Also the rules include specific requirements for the energy assessment of the installation depending on the type of installation.

11.2.9 US EPA – Climate leaders greenhouse gas inventory protocol, Offset project methodology for project type: Industrial Boiler Efficiency

This guidance published by the US EPA provides a performance standard (accounting methodology) for greenhouse gas (GHG) offset projects that introduce more efficient boiler technology for industrial process applications. As mentioned in the report, there is no precise regulatory definition for an industrial boiler in the US. An industrial boiler is typically defined by its common function – a boiler that provides heat in the form of hot water or steam for co-located industrial process applications. The industrial boiler category does not include utility boilers or commercial boilers as these do not provide the same service as industrial boilers. The results of the study may be used for industrial boilers of any size, including large boilers (often classified as water-tube and fire-tube boilers that have a capacity greater than 2.93 MW56 and smaller industrial boilers (<2.93 MW). It is mentioned that practically the technologies for boiler efficiency improvement are typically installed on larger water tube boilers >2.93MW since the fuel reductions are greater and better support project economics.

Efficiency ranges are reported along with the incremental improvement with the use of various technical measures:

Table 11.10 Industrial Boiler Efficiency and Emissions with Optional Components

Industrial boilers and optional components

Efficiency range and incremental improvement (%)

Manufacturer specified thermal efficiency value (%)

Resulting overall efficiency

Nominal boiler efficiency 75 – 83 80 80

Non-condensing economiser 1 – 7 5 85

Advanced burner and controls 1 – 2 2 86

Condensing economiser 1 – 2 1 87

Combustion pre-heater 1 – 2 1 88

Blowdown heat recovery 1 1 89

In the guidelines it is mentioned that there is no known data set describing the various efficiencies of industrial boilers in the United States. General engineering practices, however, indicate that industrial boilers are very similar in design efficiency and generate steam within a narrow range of efficiency. Differences in actual operating efficiency occur as a result of desired load, steam pressure, temperature requirements, and local emission thresholds which depend on site-specific parameters. Although there are no “standard” or “high” efficiency industrial boilers, there is a range of technology modifications, which can increase the operational thermal efficiency of the boiler’s

56 The actual capacity is reported in MMBtu/hr

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steam production process, once it is designed or after it is installed. Combinations of these modifications can increase boiler thermal efficiency to approximately 90%.

11.2.10 Environment Agency and DECC - EU emissions trading system: Benchmarking as an allocation methodology for heat from 201357

In this study commissioned by the Environment Agency and DECC, information relating to the fuel consumed in the generation of heat and the quantity of heat generated in boilers has been sought from two sources:

• UK CHP Quality Assurance (CHPQA) scheme information.

• Directly from industry.

The above two sources of information have yielded 49 separate boiler schemes consisting of 139 separate fired boilers with a combined heat capacity of 2,029 MWth6. These boiler schemes have metered fuel inputs and heat outputs.

The study reports that 34 of the 49 schemes analysed have net efficiencies >80% and 13 schemes >90%. The average unweighted efficiency was 82.2%. The average efficiency of the best 10%, is ~ 95%. It is also mentioned that the reported efficiency value of 95% is likely to be higher than the real value due to an underestimate in the enthalpy of the condensate return. It should also be kept in mind that the boilers covered in the above analysis are those with heat metering, which are likely to be towards the newer end of the spectrum and, therefore, towards the higher end of the efficiency spectrum.

11.2.11 IPCC- Climate change 2007: Working Group III: Mitigation of climate change58

According to the report, the efficiency of current steam boilers can be as high as 85%, while research in the USA aims to develop boilers with an efficiency of 94%. It is reported that in practice, average efficiencies are often much lower. Efficiency measures exist for both boilers and distribution systems. Besides general maintenance, these include improved insulation, combustion controls and leak repair in the boiler, improved steam traps and condensate recovery. Boiler systems can also be upgraded to cogeneration systems. Furnaces and process heaters, many of which are tailored for specific applications, can be further optimized to reduce energy use and emissions.

57AEA, “ EU Emissions Trading System: Benchmarking as an allocation methodology for heat from 2013 (Final Report)”, 2010 58IPCC- Climate change 2007, Working Group III: Mitigation of climate change, http://www.ipcc.ch/publications_and_data/ar4/wg3/en/ch7s7-3-2.html

http://www.ipcc.ch/publications_and_data/ar4/wg3/en/ch7s7-3-2.html

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11.2.12 Measures to improve efficiency of combustion units

The report of the US EPA59 summarises information on control techniques and measures to mitigate greenhouse gas (GHG) emissions from industrial, commercial and institutional boilers. Some indicative measures with the relevant improvement in energy efficiency are presented in the table below:

Table 11.11 GHG emission reduction measures with relevant efficiency improvement

GHG Measure Efficiency Improvement (percentage pt) Notes/Issues

Replace/ Upgrade Burners Up to 4-5%. Site specific considerations (retrofit ability) and economic factors may affect the installation of burners

Optimization 0.5% – 3.0% Neural network-based

Instrumentation& Controls 0.5% – 3.0% (in addition to optimization) System integration, calibration, and maintenance

Economizer 40°F decrease in flue gas temperature Larger units; must consider pressure

Air Preheater ∼6% Used in large boiler applications, not widely used in ICIs due to increase in NOX

Create turbulent flow within firetubes 1% efficiency gain for 40°F reduction in flue gas temperature

Widely accepted with older boilers;

Reduce air leakages 1.5 – 3% potential (Effect similar to reducing excess air)

Requires routine maintenance procedures

Capture energy from boiler blowdown Site specific depending on steam conditions Up to ~ 7%

Water quality issue important

Reduce slagging and fouling of heat transfer surfaces

1% to 3% Site specific; fuel quality/operating condition have large impact

Downtime/economic factors, regain lost capacity

11.3 Legislation review A review of existing Member States legislation gathered as part of this study showed that almost no Member States include energy efficiency requirements in their national legislation. It was also found that when presented in national legislation, the requirements are very specific or limited to some specific boilers, activities or thermal ranges.

59 US EPA, Available and emerging technologies for reducing greenhouse gas emissions from industrial, commercial and institutional boilers, 2010, http://www.epa.gov/nsr/ghgdocs/iciboilers.pdf

http://www.epa.gov/nsr/ghgdocs/iciboilers.pdf

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Czech Republic’s decree Coll.V415.2012 provides a specific set of ELVs for waste incinerator boilers that reach 97% or 100% energy efficiency The ELVs are less stringent if the efficiency is higher, for example the ELV for dust for 100% energy efficiency is 30 whereas it is only 10 for efficiency at 97%.

The table below presents another set of Czech Republic’s requirements of minimal thermal efficiency linked to emissions limit values for gaseous and liquid fuels.

Table 11.12 Emissions limit values and thermal efficiency for stationary combustion sources – proposed for revision of Clean Air Act No.309/1991Coll for new plants (in Ng/m3)

O2 (3%) Up to 0.3 MW 0.3 to 1 MW 1 to 5 MW

For gaseous fuels

Min. Thermal efficiency (%) 93 94 94

NOx 70 80 100

CO 50 50 50

For liquid fuels

Min. Thermal efficiency (%) 90 91 91

NOx 130 130 150

CO 80 80 80

From: http://citepaax.alias.domicile.fr/forums/egtei/7-czeck-republic.pdf

The following table, extracted from Czech Republic’s Coll.V349.2010 presents the level of energy efficiency to be reached by new boilers. However it seems to be quite a limited range of application as we understand that these values do not apply for boilers involved in electricity production.

Table 11.13 Minimum efficiency coefficient for fuels

MWth ZP,LTP Coal and lignite

<0.5 0.91 0.77

0.51 - 3 0.92 0.80

3.1 - 6 0.94 0.85

6.1 – 20 0.97 0.88

20.1 – 50 0.99 0.94

> 50 1.00 1.00

Source: from Coll.V349.2010 Note: We understand ZP, LTP to refer to gas and liquid fuels types.

Germany has also adopted minimum efficiency requirements (in BImSchV2010, Annex 3), but these appear to apply to much smaller boilers, stoves etc.

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Table 11.14 Emission limit values and minimum degrees of efficiency for single room firing installations for solid fuels (requirements for the type test) in Germany

Type of appliance Minimum energy efficiency for new installations (22 March 2010)

Room heater with flat-layer firing 73

Room heater with feeder firing 70

Heat storage stoves 75

Fireplace inserts (closed operation) 75

Tiled stove inserts with flat-layer firing 80

Tiled stove inserts with feeder firing 80

Cooking ranges 70

Heating stoves 75

Pellet stoves without hot water heat exchanger 85

Pellet stoves with hot water heat exchanger 90

Source: BImSchV2010, Annex 4

11.4 Consultation A consultation with trade associations, LCP BREF authors, manufacturers and other relevant bodies was undertaken by AMEC. Due to the limited time of the consultation period, only limited information was received mainly from the Association of European Heating Industry (EHI). The following table summarises the consultation.

Table 11.15 Overview of the consultees and information received

Contact details Summary of the contact Information received

Trade association

COGEN Europe None No information received

EPPSA Email conversation EPPSA is currently consulting its members and will try to come back to us as soon as possible

Euromot Email and phone conversation Euromot sent back its answers to our questions concerning engines

EUTurbines Email conversation EUTurbines will present our consultation to its Members during its Member’s meeting early July and will send us any feedback received

Euroheat and power None No information received

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Contact details Summary of the contact Information received

EHI Email and phone conversation, phone conference with expert

EHI has organised a phone discussion with one of its expert on 24th June to understand better the information that we need. They sent their responses to our questions with some additional documents: a study on “energy modernisation of industrial heating systems” of Dena and BDH, a presentation by EHI of this study presented at the Sino/European Congress 2012 in Beijing and German Ordinances 1. BImSchV and 4. BImSchV.

BREFs authors

Michele Canova Telephone conversation No information received due to confidentiality issues

Manufacturers

Ferroli Email Reply with a link to the brochures in their website

Viessmann None No reply received

Hoval None No reply received

Saacke None No reply received

Other

EEB (Kristian Tebert) Email conversation Mr. Tebert contacted Mrs. Lesley James working for EEB on the review of LCP BREF. Unfortunately no information were available. Mr. Tebert provided the name of a contact in University of Stuttgart that works on combustion processes

IFK - University of Stuttgart (Joerg Maier) None No reply received

Information provided by EHI

A summary of the consultation with the EHI and the relevant information received is provided in this section. EHI has provided a complete set of answers to our questions based on the input received from four large heating appliance manufacturers. The process is ongoing and EHI might receive more information from manufacturers.

EHI has highlighted that it is very difficult to give average values as there is such a large variation and differences between the type of installation (boiler, engines, turbines) and the processes these are involved in. However, they estimated the current average net thermal energy efficiency of 1-50 MWth plants at about 91 to 92%. A lot of variation will be found depending on the process, end-use and temperature needed. It was also highlighted that there is a difference between the theoretical energy efficiency of an installation and the actual efficiency. A study forwarded by EHI from Dena and BDH concluded that 80% of the current installations in Germany are not as efficient as they could be ideally, and that there is scope for energy efficient conversion and generation technologies to be applied.

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There is also a lot of variation between Member States as some already have relevant laws and regulations (i.e. Czech Republic Coll.349/2010 sets minimum energy efficiency requirements for new installations) although most don’t.

It was highlighted that for the case of the heating industry, one of the main interest of an operator is to ensure constant conditions of the heating appliance over the lifetime of the appliance. The maintenance is thus essential and in theory it is possible to prevent loss of efficiency over time. However, if the maintenance is not carried out adequately, the heating appliance will be damaged and/or will lose overall efficiency. An estimate of this loss is that around 1% (if a lot of fuel is used) or 15% (when heat demand is low).

More generally, a commercial /industrial boiler lifetime ranges from 20 to 40 years. During this time, the installations will be maintained and modernised a number of times. There is a large range of existing systems for increasing the energy efficiency of a plant, but it depends on the application and plant conditions (EHI highlighted the fact that more than a thousand different types of installations and processes exist).

For more recent steam or hot water boilers, the energy efficiency is estimated to be in the range of 93 to 94%. Technical improvements can also increase the efficiency, for example a burner modulation with speed regulation or additional heat exchanger will increase the efficiency of a boiler by up to 10%; O2 regulation will increase efficiency by 1 to 2%. With improvement of technologies, it is estimated that future plants sold in the EU could reach 95 to 96% energy efficiency in some cases. More can be achieved for specific plant with local technical possibilities (e.g. a condensing economiser after a steam boiler is only possible if an independent heating circuit is available).

Considering settings emissions limit values for air pollutants, the EHI recommended using German’s ELVs included in BmlSchV (2010). As a general rule regarding air quality, EHI have indicated that an increase of 10% of the plant energy efficiency will reduce emissions of air pollutants by 10% although this seems quite simplistic as it would of course depend on the actions taken to improve efficiency.

Information provided by EUROMOT

A summary of the consultation with EUROMOT and the relevant information received is provided in this section. They were not able to provide us with average energy efficiency data as EUROMOT does not collect this type of information. However, they were able to indicate that engine plants in combined heat and power (CHP) can reach efficiencies over 90%. For typical single cycle internal combustion engine plants (without heat recovery), the range of efficiency is significantly lower (41 to 47% depending on the size of the engine).

EUROMOT highlighted that a lot of variation existed between Member States, but also according to factors such as the actual application and the use of heat generated.

It was explained that for engine power plants more than 70% of the operating cost is due to fuel. With the increase of fuel prices, there are strong incentives for improving the general efficiency of engines. EUROMOT reported that engine manufacturers invest heavily into developing more efficient and clean engines. As a result of the significance of fuel costs, energy efficiency in internal combustion engine is already at a high level. The way to reach higher efficiencies is to apply CHP where possible. There are differences in efficiencies which are due to the

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sizes of the engine and the technology used. Larger single cycle internal combustion engines are inherently more efficient than the smaller ones as they run at lower speeds, with lower friction losses and more efficient air handling.

The overall efficiency of an engine can decrease over time, in particular in the absence of proper maintenance. EUROMOT states that an overall1-2% reduction of efficiency can be expected in this case, depending on engine type and the fuel grade. However with proper maintenance it is possible to restore the efficiency to its original level.

The average lifetime of an engine plant is 25 years (providing maintenance), this lifetime is longer for engines used as emergency devices due to the low annual operating hours.

Finally, EUROMOT expects that technological improvement will increase. For example, CHP solutions are expected to become more common. The same is said about the combination of gas engine plants with steam turbines. These plants can currently reach an efficiency of 50% and it is expected that higher efficiencies will be reached in future years.

11.5 Conclusions Combustion units with a total rated thermal input below 50MW are used in a variety of applications including public electricity generation, public heating, food industry, agriculture and also various industrial sectors. This study has estimated that there are more than 142,000 combustion installations ranging from 1 MW to 50MW across the EU. The efficiency of combustion units is affected by several parameters such as the type and design of the combustion unit, the end-use (depending on type of industrial process that uses the combustion unit), type of fuel used, operational parameters, age of the unit, maintenance and even location of the installation. Additionally in many cases the combustion units are tailor-made to fit the requirements of a specific process.

Efficiency of combustion installations have improved significantly compared to the past decades. Newer combustion installations have higher efficiencies compared to older installations. However even older combustion installations can improve their efficiency by taking measures such as optimisation of the operating conditions or reduction of air leakages. The degree of efficiency improvement depends on the end-use of the heat and the complexity of the production process.

The efficiencies of combustion units usually are reported by type of combustion unit and/or type of fuel used. The efficiency data reported in the literature review section are not always directly comparable as there is not enough contextual information (e.g. type of industrial process, end-use requirements of the heat). A conclusion on energy efficiency range for combustion installations <50MW cannot be made as it would not be representative of the current situation (different applications with different end-use characteristics). Another issue might be the difference in efficiencies between electricity, heat and CHP producing installations. Commission’s Decision 2011/877/EU that provides the reference efficiency values for separate production of electricity and heat includes different values for electricity and heat.

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Information was not available at this point in order to assess if the efficiency of combustion installations is affected by the end-use in the various industrial sectors. The data from the literature review refers in all cases to combustion installations that burn specific fuels, without taking into account the industrial sector and the end-use which might affect the efficiency. Both trade associations that were contacted mentioned that the efficiency and the degree of improvement are highly affected by the industrial process that uses the combustion unit.

The review of existing Member States legislation showed that very few Member States (i.e. Czech Republic and Germany) include energy efficiency requirements in their national legislation.

The consultation revealed the lack of readily available information on energy efficiency of combustion installations and also on how energy efficiency affects air emissions such as NOx or SO2 (although the short timescales for this consultation have hindered a number of stakeholders from providing information).

Although this is a work in progress it is evident that a more detailed study, with data collection on plant level, might be necessary in order to assess the energy efficiency of combustion installations <50MW in Europe and to conclude on minimum energy efficiency requirements for new (and potentially existing) combustion installations (<50MW) in the various sectors. There could be scope for the Commission to also collect data on energy efficiency through the implementation reports of the Member States in order to include energy efficiency requirements in future revisions of the proposed legislation.