COMPREHENSIVE ASSESSMENT OF THE POTENTIAL FOR IMPLEMENTATION OF HIGH-EFFICIENCY CO ... · 2016-06-13 · IMPLEMENTATION OF HIGH-EFFICIENCY CO-GENERATION AND EFFICIENT DISTRICT HEATING

HELLENIC REPUBLIC

MINISTRY OF ENVIRONMENT AND ENERGY

SECRETARIAT GENERAL FOR ENERGY AND MINERAL RAW MATERIALS DIRECTORATE-GENERAL FOR ENERGY DIRECTORATE FOR RES AND ELECTRICITY

COMPREHENSIVE ASSESSMENT OF THE POTENTIAL FOR IMPLEMENTATION OF HIGH-EFFICIENCY CO-GENERATION

AND EFFICIENT DISTRICT HEATING AND COOLING

Athens, March 2016

Pursuant to Article 15(1) of Law 4342/2015 [Article 14(1) of Directive 2012/27/EU]

Comprehensive Assessment of the Potential for Implementation of High-Efficiency Co-generation and Efficient District Heating and Cooling - 2016 1

Table of Contents

Table of Contents .......................................................................................................................................... 1

Graphs............................................................................................................................................................ 2

Tables 3

Maps 3

General .......................................................................................................................................................... 5 List of abbreviations ...................................................................................................................................... 6

1. Introduction ............................................................................................................................................... 8

2. Determination of demand for heating and cooling ................................................................................. 11

2.1 Residential sector ..................................................................................................................................... 11

2.1.1. Assessment of demand for heating for residential sector buildings at the level of settlements and administrative units ....................................................................................................................................... 11

2.1.2 Assessment of demand for cooling for residential sector buildings at the level of settlements and administrative units ....................................................................................................................................... 13

2.2 Tertiary sector .......................................................................................................................................... 14

2.2.1 Assessment of demand for heating for tertiary sector buildings at the level of settlements and administrative units ....................................................................................................................................... 14

2.2.2 Assessment of demand for cooling for tertiary sector buildings at the level of settlements and administrative units ....................................................................................................................................... 15

3. Forecast of the evolution of demand for heating and cooling in the next decade ................................. 17

4. Geographical map of generation and demand for heating and cooling in Greek territory ................... 26

5. Determination of technical potential for efficient heating and cooling .................................................. 30

5.1 The technical potential of biomass .......................................................................................................... 30

5.2 Technical potential for heat production from natural gas ....................................................................... 34

6. Cost-benefit analysis at a nationwide level .............................................................................................. 35

6.1 Cost-benefit analysis under Scenario 1: District heating and cooling by use of waste heat from

existing facilities ............................................................................................................................................. 36

6.1.1 Economic analysis of Scenario 1 ............................................................................................................ 41

6.1.2 Cost-benefit analysis ............................................................................................................................. 43

6.2 Cost-benefit analysis under Scenario 2 .................................................................................................... 46

6.2.1. Biomass and lignite co-firing in a boiler ............................................................................................... 46

6.2.1.1. Economic analysis ............................................................................................................................. 46


6.2.2. Heat generation from a combination of biomass and natural gas-fired boiler technologies .............. 48

6.2.2.1 Economic analysis .............................................................................................................................. 48

6.2.2.2 Cost-benefit analysis .......................................................................................................................... 49

6.3 Scenario 3: Heat supply from new HECHP plants via district heating networks ...................................... 52

6.3.1 Heat supply from new HECHP plants .................................................................................................... 52

6.3.1.1 Summary of the status of co-generation from 1970 to 2005 ............................................................. 52

6.3.1.2 Summary of the status of co-generation from 2006 to 2015 ............................................................ 53

6.3.1.3 The developments in the legal framework governing CHP/HECHP .................................................... 57

6.3.1.4 Support mechanisms for CHP/HECHP ................................................................................................ 58

6.3.1.6 The finance of CHP ............................................................................................................................. 60

6.3.1.6 HECHP support mechanisms .............................................................................................................. 61

6.3.1.7 cost-benefit analysis of HECHP for the generation of energy-efficient heating via district heating networks fuelled with natural gas ................................................................................................................. 70

6.4 Scenario 4: Penetration of co-generation and heat pumps for individual installations in the

residential, tertiary and industrial sectors ..................................................................................................... 74

6.4.1 Penetration of co-generation for individual installations in the residential, tertiary and industrial sectors ............................................................................................................................................................ 74

6.4.2. Air-cooled heat pumps ......................................................................................................................... 77

7. Setting out strategies, policies and measures for 2020 and 2030 ........................................................ 80

Graphs

Graph 1: Energy demand in the residential sector in the period 2010-2030 ................................................ 18

Graph 2: Energy demand in the agricultural sector for heating for livestock units

in total and per Region in the period 2010-2030 ........................................................................................... 19

Graph 3: Energy demand in the agricultural sector for heating for greenhouses in total and

per Region in the period 2010-2030 .............................................................................................................. 20

Graph 4: Energy demand for space heating per type of buildings in the tertiary sector in the period

2010-2030 ..................................................................................................................................................... 21

Graph 5: Energy demand for domestic hot water per type of buildings in the tertiary sector in the

period 2010-2030 ........................................................................................................................................... 22

Graph 6: Energy demand for space cooling per type of buildings in the tertiary sector in the

period 2010-2030 23

Graph 7: Total demand for heat in industry and per Region in the period 2010-2030 ................................. 24


Graph 8: Economic viability of district heating networks in relation to the population of the settlement and the distance from the waste heat source ............................................................................................................ 42

Graph 9: Installed capacity of HECHP plants per year (2006-2015) .............................................................. 55

Graph 10: Capacity of HECHP plants holding generation licences per year .................................................. 56

Graph 11: Number of generation licences issued to HECHP plants per year (2010-2015) ............................ 57

Graph 12: ‘Spark ratio’ variation for households and industries ................................................................... 61

Graph 13: HECHP Climate Zone A .................................................................................................................. 71

Graph 14: HECHP Climate Zone B .................................................................................................................. 71

Graph 15: HECHP Climate Zone C .................................................................................................................. 72 Graph 16: HECHP Climate Zone D .................................................................................................................. 72

Tables

Table 1: Cost of pumping equipment ............................................................................................................ 39

Table 2: Indicators of economic viability of the investment.......................................................................... 41

Table 3: Economic viability under Scenario 1 ................................................................................................ 44

Table 4: Economic viability under sub-scenario 6.2.1 .................................................................................... 48

Table 5: Economic viability under sub-scenario 6.2.2 ................................................................................... 50

Table 6: Co-generation data for Greece in the period 2004-2005 ................................................................ 53

Table 7: Data on co-generated electricity from the main autoproducers in the period 2006-2015 ............. 54

Table 8: Generation licences issued to HECHP plants (2010-2015) ............................................................... 56

Table 9: Prices of natural gas and electricity in Greece ................................................................................. 60

Table 10: ‘Spark ratio’ for the period 2012-2015 .......................................................................................... 61

Table 11: ‘F-i-T’ for various categories of operating HECHP plants, with or without subsidy

and efficiency levels ....................................................................................................................................... 64

Table 12: Aggregate data on HECHP in Greece following application of Law 4254/2014 65

Table 13: Classification of new HECHP installations after April 2014 ............................................................ 67

Table 14: Cost-benefit analysis of Scenario 4 - Residential Sector ................................................................ 75

Table 15: Cost-benefit analysis of Scenario 4 - Tertiary Sector ..................................................................... 76

Table 16: Economic potential of CHP in the tertiary sector ......................................................................... 77 Table 17: Cost-benefit analysis of the substitution of existing systems with heat pumps ............................. 79


Maps

Map 1: Waste heat supply sites ..................................................................................................................... 27

Map 2: Demand for thermal energy .............................................................................................................. 28 Map 3: Energy demand for cooling................................................................................................................ 29

Map 4: Allocation of estimated sites of facilities for heat production from biomass - North Greece ............ 32

Map 5: Allocation of estimated sites of facilities for heat production from biomass - South Greece ................................................................................................................................. 33 Map 6: Natural gas networks in Greece (source: DEPA) ................................................................................ 34


General

Energy efficiency is at the core of the EU’s energy strategy for 2020 and is an important tool for attaining the objectives set in the Roadmap for moving to a competitive low carbon economy in 2050. In 2012, the Energy Efficiency Directive (2012/27/EU) was adopted, after it was recognised at a European level that the European Union’s energy efficiency target was not on the right track and determined action was needed for utilising the significant potential for higher energy savings in buildings, transport, products and processes.

The Energy Efficiency Directive (2012/27/EU) lays down a common framework of measures for promoting energy efficiency in the EU, with a view to attaining the European Union’s target to improve energy efficiency by 20%. The Energy Efficiency Directive was transposed into national legislation by Law 4342 of 9 November 2015 on energy efficiency, and the amendment of Directives 2009/125/EC and 2010/30/EU and repeal of Directives 2004/8/EC and 2006/32/EC.

Among other measures for improving energy efficiency, Article 15 of Law 4342 lays down that the potential for high-efficiency co-generation, efficient heating and cooling and recovery of waste heat from industrial facilities must be determined and that an analysis of the cost and benefit resulting from the application of these technologies for the production of heating and cooling must be made. Compliance with this requirement is ensured through the comprehensive study assessing the possibilities of applying the above technologies on the basis of a cost-benefit analysis at a nationwide level.

The purpose of the comprehensive assessment study is to draw clear conclusions on energy-efficient heating and cooling. These conclusions are related not only to the technical potential but also to the greater economic potential for improving energy efficiency in the generation of heating and cooling. Therefore, a holistic approach is adopted to identify the sectors where the use of technologies of co-generation, efficient district heating and cooling, as well as recovery of waste heat from industrial facilities, may add value to the heating and cooling generation system.


List of abbreviations

RES Renewable energy sources

IA Industrial area

DEPA Public Gas Corporation

IMF International Monetary Fund

IRR Internal rate of return

EC European Commission

ESCO Energy service company

EPE European Power Exchange

ECB European Central Bank

ELSTAT Hellenic Statistical Authority

NTUA National Technical University of Athens

HACHP Hellenic Association for the Cogeneration of Heat and Power

ETMEAR Special duty for reduction of gas emissions

DHW Domestic hot water

SH Space heating

CRES Centre for Renewable Energy Sources

REPB Regulation on the Energy Performance of Buildings

NPV Net present value

CSF Community Support Framework

LAGIE Greek Electricity Market Operator

RAE Regulatory Authority for Energy

CHP Cogeneration of heat and power

HECHP High efficiency cogeneration of heat and power

CC Clause coefficient

MECC Ministry of the Environment and Climate Change

NG Natural gas

F-i-T Feed-in-Tariff

NUTS Nomenclature of territorial units for statistics


ATH Region of Attica

CMC Region of Central Macedonia

CRT Region of Crete

CYC Region of Cyclades

DOD Region of Dodecanese

EMC Region of Eastern Macedonia-Thrace

EPI Region of Epirus

ION Region of Ionian Islands

NAG Region of North Aegean

PEL Region of Peloponnese

STR Region of Central Greece

THE Region of Thessaly

WGR Region of Western Greece

WMC Region of Western Macedonia


1. Introduction

The comprehensive assessment addresses, on an integrated basis, the possibility of meeting the heating and cooling needs at a nationwide level in an energy-efficient manner. The study assesses the demand for heating and cooling in all sectors of economic activity, the potential for high-efficiency cogeneration, efficient district heating and cooling, as well as recovery of waste heat from industrial facilities, to cover that demand in a cost-effective manner.

In order to explore and determine the most cost-effective manner of meeting the demand for heating and cooling, a cost-benefit analysis is carried out. This covers the entire Greek territory geographically and takes into account the climate conditions, the economic feasibility and the technical capabilities for implementation of the technologies examined, in accordance with Part 1 of Annex IX to Law 4342/2015.

In particular, the demand for thermal energy for space heating and cooling and domestic hot water (DHW) at the level of municipalities throughout the Greek territory is determined. The climatic data of the municipalities, the population, all tertiary sector buildings inside the municipality borders and primary energy consumption data, as recorded in the context of implementation of the Regulation on the Energy Performance of Buildings, are taken into account to determine such demand. A methodology for calculating thermal demand has been developed for each case, as presented in detail in Chapter 2 hereof.

The TIMES model is used to determine the evolution of the energy system in Greece and the evolution of the demand for heating and cooling in the next decade. The geographical breakdown of the model for energy demand and generation is at the level of Region (NUTS 2) and all energy-consuming and generating sectors are analysed. In particular, the evolution of energy demand for space heating and cooling and for heat for industrial processes is calculated according to the general methodology described in Chapter 3.

Moreover, Chapter 4 presents the geographical maps of heating and cooling generation and demand in the Greek territory. These maps show potential locations where waste heat is available and apply to existing power plants with capacity above 20 GWh/yr, existing HECHP facilities, existing and planned district heating installations and networks, as well as industrial areas (IA) with potential useful waste heat.


The geographical maps of energy demand for heating and cooling show, at the level of municipalities, the demand for energy resulting from the analysis made in Chapter 2.

Chapter 5 lays down the technical potential for efficient heating and cooling. It explores the implementation of energy-efficient systems for generation and transmission of thermal energy by substituting the existing conventional systems that generate heat for space heating and DHW. The fuels mainly examined are biomass and natural gas, as well as the potentially available waste heat from existing facilities. The technical potential of the systems, as examined, exists in areas where fuel is available for heat generation and these areas are mapped.

Chapter 6 presents an economic analysis and a cost-benefit analysis, at a community level, of the technically exploitable potential for efficient heating and cooling. The analysis takes into account the variation in the demand for heating and cooling per climate zone, as well as the variation in economic potential in relation to the source of the available energy for covering heating and cooling needs.

Three (3) scenarios are defined for analysis purposes. Each scenario is assessed comparatively to the baseline scenario, which relates to the current situation of heating and cooling generation by use of conventional technologies. The scenarios are as follows:

Scenario 1: The demand for heating per settlement type is covered by district heating systems using available waste heat from existing facilities.

Scenario 2: The demand for heating per settlement type is covered by district heating systems using heat generated from new heat generation facilities by use of natural gas, biomass and co-combustion of biomass and lignite.

Scenario 3: The demand for heating per settlement type is covered by district heating systems using heat generated from high-efficiency cogeneration systems fuelled with natural gas.

Scenario 4: Penetration of co-generation and heat pumps for individual installations in the residential, tertiary and industrial sectors.

The results of the cost-benefit analysis point out the measures and policies that may be implemented by 2030 with a view to best exploiting the potential for efficient heating and cooling.


According to the outcomes of the analysis of the scenarios examined, great emphasis should be placed on identifying points where waste heat is available and utilising it for providing heat to settlements via district heating networks, since the cost-benefit analysis demonstrates that major economic, social and environmental benefits may arise from selecting this specific method of generating energy-efficient heating.

In addition, the cases of implementing biomass and lignite co-combustion technology and generating heat from a combination of natural gas and biomass boiler technologies are examined. The cost-benefit analysis performed demonstrated major benefits for society in both cases. For these technologies to be economically viable, State aid must be granted, of an amount depending on the climate zone, the demand for heat and the distance from the thermal source and provided that there is technical potential for the implementation of those technologies, as extensively presented in Chapter 6 hereof.

With regard to scenario 3, namely the penetration of HECHP systems for the production of energy-efficient district heating, the analysis made demonstrated that the technologies of differential pressure steam turbine, steam extracting-condensing turbine with heat recovery and steam turbine with heat recovery differ marginally as regards both the economic analysis and the cost-benefit analysis. The most common method, where technical capability is available, is the combined cycle gas turbine with heat recovery, followed by internal combustion engines and other HECHP technologies.

With regard to scenario 4, the analysis performed showed that the investment is not financially viable in all cases examined in each climate zone. Nevertheless, the cost-benefit analysis at the level of society demonstrates a major benefit from investing in heat generation by use of co-generation systems. For that purpose, the amount of the existing funding gap that has to be covered for the investment to be economically viable is determined, where the benefit/cost ratio is over 1.

Moreover, the penetration of air-heated heat pumps in residential sector buildings is not recommended, since the benefit-cost ratio is in all cases below 1.

Lastly, according to the results of the cost-benefit analysis, energy-efficient district cooling is not proven to be socially efficient and the envisaged policies should not include the district cooling infrastructures as a first stage.


2. Determination of demand for heating and cooling The energy demand for heating and cooling is determined for each final consumption sector at the level of municipalities for the entirety of Greece (administrative division level: 5).

The methodology used takes into account data from the overall energy balance of Greece for 2013, the last census of population and buildings performed in 2011 by the Hellenic Statistical Authority (ELSTAT), the geographical and climate location, the processing of available results relating to the energy performance of buildings in the residential and tertiary sectors, as well as the results of the project entitled ‘Collection and processing of final energy consumption data’.

A separate methodology is applied for each final consumption sector, depending on the availability of data and their correctness. The following sections present in detail how these methodologies were applied.

The geographical presentation of the total demand for heating and cooling is shown in Chapter 4 hereof.

2.1 Residential Sector

This section presents the overall thermal demand for space heating and domestic hot water, as well as

the total demand for cooling. The demand for heating and cooling determines the overall heat market for the specific sector and is calculated at the level of municipalities at a nationwide level.

2.1.1 Assessment of demand for heating for residential sector buildings at the level of settlements and administrative units

The demand for heating examined in the next chapter includes space heating (SH) and domestic hot water (DHW) in the residential sector.

The demand for heating in the residential sector is calculated by using the results of the census of the number of permanent residences carried out in 2011 by ELSTAT. The same source is used for obtaining the average surface area of permanent residences at a nationwide level.

In addition, the average primary energy consumption for space heating and domestic hot water (kWh/m2) per climate zone (zones A, B, C, D, as laid down in the Joint Ministerial Decision approving the Regulation on the Energy Performance of Buildings) is determined by processing the energy certificates.


Primary energy consumption is converted into final energy consumption by use of the conversion factors laid down in the Joint Ministerial Decision approving the Regulation on the Energy Performance of Buildings, taking into account that the fuels used for space heating are heating oil and natural gas, while domestic hot water is generated by use of electricity. The primary energy consumption, as resulting from the processing of available results about the energy performance of residential sector buildings, and the assumptions on the use of these fuels for meeting the thermal needs for space heating and domestic hot water, involve a certain degree of uncertainty. A correction factor is applied in determining the thermal demand in order to eliminate such uncertainty. This factor is set by taking into account the total energy consumption in the residential sector for 2013 (energy balance of Greece), as well as the allocation of energy consumption per end use in the sector (project entitled ‘Collection and processing of final energy consumption data’).

The equations applied for determining the total thermal demand at the level of municipalities are as follows:

TDMi =TDSHi + TDDHWi

In particular:

TDSHi= Αi*AA*PESHi*CFSH*CF

TDDHWi = Αi*PEDHWi*AA*CFDHW*CF

Where:

i: the municipality

TDMi : the total thermal demand in the municipality

TDSHi: the thermal demand for space heating

TDDHWi: the thermal demand for domestic hot water

Αi: the number of permanent residences

AA: the average surface area of a permanent residence

PESHi: the primary energy consumption for space heating

PEDHWi: the primary energy consumption for domestic hot water

CFSH: the primary-to-final fuel energy conversion factor for space heating

CFDHW: the primary-to-final fuel energy conversion factor for domestic hot water

CF : the correction factor


2.1.2 Assessment of demand for cooling for residential sector buildings at the level of settlements and administrative units.

The demand for cooling in the residential sector is calculated in line with the calculation of the demand for heating detailed in section 3.1.1, by using the results of the census of the number of permanent residences and the average surface area of the permanent residences at a nationwide level, which was carried out in 2011 by ELSTAT.

The average primary energy consumption for space cooling (kWh/m2) per climate zone (zones A, B, C, D, as laid down in the Joint Ministerial Decision approving the Regulation on the Energy Performance of Buildings) is determined by processing the energy certificates. Primary energy consumption is converted into final energy consumption by use of the conversion factors laid down in the Joint Ministerial Decision approving the Regulation on the Energy Performance of Buildings, taking into account that electricity is used to cool spaces.

The equation applied for determining the demand for cooling at the level of municipalities is as follows:

DCi= Αi*AA*PESCi*FCFSC*CF

Where:

i: the municipality

DCi : the demand for cooling in the municipality

Αi: the number of permanent residences

AA: the average surface area of a permanent

residence

PESCi: the primary energy consumption for space cooling

FCFSC: the primary-to-final fuel energy conversion factor for space cooling



2.2 Tertiary Sector

To assess demand for heating and cooling in the tertiary sector, the total energy consumption in the tertiary sector is used, as resulting from the energy balance of Greece every year.

Heat demand for space heating and cooling and domestic hot water is determined for the following sub-sectors of final consumption:

• School buildings

• Office buildings - trade establishments

• Hospitals

• Hotels - tourist accommodation establishments

2.2.1 Assessment of demand for heating for tertiary sector buildings at the level of settlements and administrative units

The demand for space heating and domestic hot water is allocated per local community on the basis of the allocation of the energy for heating calculated by use of the TIMES model developed by the CRES. That allocation takes into account:

• the total number of installations/buildings,

• the population of each community examined,

• tourism statistics relating to the number of overnight stays in tourist accommodation establishments,

as resulting from the census of buildings and population for 2011 carried out by ELSTAT and the heating degree-days for each area, as obtained from Degree Days (www.degreedays.net)

http://www.degreedays.net/


2.2.2 Assessment of demand for cooling for tertiary sector buildings at the level of settlements and administrative units

The demand for cooling in the tertiary sector is determined in line with the determination of the demand for space cooling in the residential sector, as detailed in section 3.1.2.

The data for calculating the demand for cooling per final consumption sub-sector are obtained from the overall energy balance of Greece for 2013, the last census of buildings performed in 2011 by the Hellenic Statistical Authority (ELSTAT), the geographical and climatic location and the processing of available results relating to the energy performance of buildings in the tertiary sector.

The results of the project entitled ‘Collection and processing of final energy consumption data’ are used to determine the average surface area of cooled spaces of the buildings per final energy sub-sector of the tertiary sector.

The average primary energy consumption for space cooling (kWh/m2) per climate zone (zones A, B, C, D, as laid down in the Joint Ministerial Decision approving the Regulation on the Energy Performance of Buildings) is determined by processing the energy certificates. Primary energy consumption is converted into final energy consumption by use of the conversion factors laid down in the Joint Ministerial Decision approving the Regulation on the Energy Performance of Buildings, taking into account that electricity is used to cool spaces.

The equation applied for determining the demand for cooling at the level of municipalities is as follows:

DCij= Αij*AAij*PESCij*FCFSC*CF

Where:

i: the municipality

j: the final consumption sub-sector of the tertiary sector

DCij: the demand for cooling in the municipality

Αij: the number of buildings in the final consumption sub-sector

AAij: the average surface area of the cooled spaces of the building

PESCij: the primary energy consumption for space cooling in the sub-sector

FCFSC: the primary-to-final fuel energy conversion factor for space cooling



2.3 Industry

Energy demand in the industrial sector was determined by analysing the data recorded in the industrial activity sheets for 2013 kept by the Ministry of Economic Affairs, Development and Tourism in the Department of Design, Analysis, Evaluation and Documentation in the Directorate-General for Industrial and Business Policy and in the Secretariat-General for Industry.

The industrial activity sheets for 2013 provided data relating to the annual energy demand per fuel type for all industrial undertakings which declared their energy consumption figures. Out of the numerous industrial activity sheets, only 197 facilities declared their annual fuel consumption.

Of the 197 facilities in total, 127 facilities recorded a fuel demand above 20 GWh/year. Most of these facilities relate to emissions trading and are, thus, excluded from this study. The other facilities with an annual fuel demand above 20 GWh/year are recorded and presented in the map of demand for heat in Chapter 5.

The examination of energy demand in the industrial sector performed for purposes of drawing up the comprehensive assessment, demonstrated that this sector should be further examined, since the data available for the industrial sector are limited. For that reason, it was not possible to accurately determine the demand for heating and cooling.

The identified absence of energy data was the trigger for defining and coordinating wide research into the industrial sector, with a view to recording the heating and cooling needs of the industrial sector. The results of the research will contribute to determining these needs and will be presented in the review of the comprehensive assessment to take place in 4 years, in accordance with the requirements of domestic law.


3. Forecast of the evolution of demand for heating and cooling in the next decade

The TIMES1 model (The Integrated MARKAL-EFOM System) is used for forecasting the evolution of the energy system in Greece. The geographical breakdown of the model for energy demand and generation is at the level of Region (NUTS 2)2 and all energy-consuming and generating sectors are analysed. The evolution of demand for useful energy drives developments in all energy generation and consumption sectors and is found through correlations with the evolution of economic fundamentals. In particular, the evolution of energy demand for space heating and cooling and for heat in industrial processes is calculated by applying the general methodology described below for the residential, tertiary and industrial sector.

1) Residential sector

The evolution of energy demand for heating, hot water and cooling in the residential sector in each Region is related to the GDP change rate and is calculated by the equation:

Where:

Dt+1 is the demand for useful energy for space heating or cooling in the year t+1

Dt is the demand for useful energy for space heating or cooling in the year t

Gt+1 is the GDP change rate from year t to year t+1

ε is the elasticity of demand for useful energy for space heating or cooling in relation to the GDP change. This elasticity has been calculated using historical data.

The forecast of the GDP change rate at a nationwide level is derived from forecasts of the Ministry of Finance, in agreement with the Ministry of Environment and Energy. The forecast is then broken down at regional level (NUTS 2), using historical data relating to the contribution of each Region to the national GDP, assuming that the relevant weight of each Region will not change during the time scale of the analysis.

1 http://www.iea-etsap.org/web/Times.asp 2 http://ec.europa.eu/eurostat/web/nuts/overview

http://www.iea-etsap.org/web/Times.asp

http://ec.europa.eu/eurostat/web/nuts/overview


Graph 1: Energy demand in the residential sector in the period 2010-2030

The evolution of energy demand in the residential sector (Graph 1) for space cooling is almost stable in the 2010-2016 period at approximately 282 ktoe. In the subsequent years, the change does not vary substantially and it stands at approximately 308 ktoe in 2020. The trends until 2030 are slightly increasing, rising to 329 ktoe in 2030.

The small variations in energy demand are mainly due to the fact that the new cooling technologies to be adopted, as well as the replaced cooling devices, will be more efficient and, therefore, even though the demand for cooling will be increasing, the final energy consumption will show a slight increase.

The evolution of demand for domestic hot water in the residential sector has similar characteristics to the energy demand for cooling. Therefore, it stood at 360 ktoe in 2010, it will be 389 ktoe in 2020 and the expected demand will rise to 405 ktoe for 2030. On the contrary, space heating in the residential sector presents a totally different picture. The fuel used, mainly in urban centres, is heating oil.

A large variation has been recorded in the period from 2010 (2106 ktoe) to 2015 (1550 ktoe) mainly due to the economic recession and increasing energy poverty, the sharp increase in 2011 being due to the announcement of significant increases in the excise duty on heating oil in the next winter period (2012), which urged consumers to procure oil earlier and, therefore, the oil supplies for 2012 were recorded in 2011. In addition, consumers searched for other fuels and space heating technologies and many of them have turned to biomass and heat pumps. The evolution of demand for the years to come presents upward trends, standing at 1790 ktoe in 2020 and 1910 ktoe in late 2030.


Graph 2: Energy demand in the agricultural sector for heating livestock units in total and per Region in the period 2010-2030

The demand for thermal energy in the agricultural sector followed the general trends of reduction as a result of the recession in the 2010-2015 period examined. More specifically in livestock farming, energy demand for heating livestock facilities was reduced from approximately 101 ktoe in 2010 to 95 ktoe in 2015 (Graph 2), while the forecast for the next years shows upward trends, rising to approximately 106 ktoe for 2020 and 117 ktoe for 2030.


Graph 3: Energy demand in the agricultural sector for heating greenhouses in total and per Region in the period 2010-2030

The energy demand for heating greenhouses was reduced from approximately 139 ktoe in 2010 to 129 ktoe in 2015 (Graph 3), while the provision for the next years shows upward trends, rising to approximately 145 ktoe for 2020 and 185 ktoe for 2030. The Regions with the highest demand are those of Western Macedonia, followed by Western Greece, Thessaly, Central Greece and, then, Peloponnese and Epirus; average demand in the others is below 50 ktoe.

2) Tertiary sector

The tertiary sector is broken down into the following sub-sectors with different characteristics in the analysis of the demand for energy:

• Hotels • Hospitals • Educational buildings • Office buildings • Trade establishments


The evolution of demand for useful energy for heating and cooling in each sub-sector is related to the evolution of the added value of the sub-sector, as resulting from equation (1). Forecasts of the added value of each sub-sector were obtained from the Ministry of Finance in agreement with the Ministry of Environment and Energy.

Educational buildings

Hotels

Hospitals

Offices (public and private)

Trade establishments

Total

Graph 4: Energy demand for space heating per type of buildings in the tertiary sector in the period 2010-2030

The highest energy demand for space heating in the tertiary sector is recorded in office buildings, in general, of the public and private sectors, followed by trade establishments, hotels, hospitals and, lastly, educational buildings. A downward trend is recorded in the period from 2010 to 2015 due to the current economic crisis. More specifically, the total demand for thermal energy was 860 ktoe in 2010, reduced to 788 ktoe in 2015. It seems to increase in the future, rising to 895 ktoe in 2020, while the upward trend of demand for heating continues in the decade to come, reaching 1065 ktoe at the end of 2030 (Graph 4). The highest demand for thermal energy is recorded in office buildings, followed by trade establishments and, then, in decreasing order hotels, hospitals and, lastly, educational buildings.



Hotels

Hospitals

Offices (public and private)

Trade establishments

Total

Graph 5: Energy demand for domestic hot water per type of buildings in the tertiary sector in the period 2010-2030

The demand for domestic hot water in the tertiary sector is clearly lower than space heating but is still important. Offices (public and private) and trade establishments record the highest demand, mainly due to the great number of buildings as compared to hotels and hospitals where specific consumption of domestic hot water is much higher.

In detail, the demand for domestic hot water was 191.5 ktoe in 2010 (Graph 5). Then, it gradually decreased, falling to 177 ktoe in 2015. The trend for the years to come is estimated to be upward, since economic recovery, which will contribute to an increase in the demand, is forecasted. Therefore, demand is estimated to stand at 206 ktoe in 2020 and to increase to 255 ktoe in 2030.

The demand for domestic hot water per type of buildings for 2030 will be 81.5 ktoe for offices, approximately 51 ktoe for trade establishments and hotels and 31 ktoe for hospitals.



Hotels

Hospitals Offices (public and private) Trade establishments Total

Graph 6: Energy demand for space cooling per type of buildings in the tertiary sector in the period 2010-2030

Demand for cooling in the tertiary sector is clearly lower than demand for space heating and higher than demand for domestic hot water. Offices (public and private) and trade establishments record the highest demand mainly due to the great number of buildings as compared to hotels and hospitals, in which specific consumption of energy for space cooling is comparatively much higher.

In detail, the demand for space cooling was 532 ktoe in 2010 (Graph 6) and gradually decreased to 493 ktoe in 2015. The figures in the years to come are expected to follow an upward trend, since economic recovery, which will contribute to an increase in the demand, is anticipated; therefore, the demand has been estimated to stand at 568 ktoe in 2020 and to increase to 693 ktoe in 2030.

The demand for space cooling per type of buildings for 2030 is calculated at 263 ktoe for offices, 182 ktoe for trade establishments, approximately 77 ktoe for hotels and educational buildings and, lastly, approximately 31 ktoe for hospitals.


3) Industry

The estimates of demand for heating in the industrial sector are based on different approaches for energy-intensive sectors and for non-energy-intensive sectors. Therefore, a forecast of the demand for natural product (e.g. tonnes of cement) is made in the sectors of iron/steel, cement, glass, aluminium, ammonia. The demand for energy (and, therefore, heating) needed for the manufacture of a product, is calculated on the basis of existing technologies and the potential future technologies to be implemented within the time scale of the analysis.

For the other industrial sectors, the evolution of useful demand is related to the evolution of the added value of the sector, on the basis of a relation of the same form as equation (1). Forecasts of the added value of each sector were obtained from the Ministry of Finance in agreement with the Ministry of Environment and Energy.

Graph 7: Total demand for heat in industry and per Region in the period 2010-2030

The industrial sector presented, on an overall basis, a sharp decrease from 2010 to 2013 due to economic recession. Then, a stabilisation trend was recorded in the demand for heating until 2015 (Graph 7). According to the forecast, the trends after 2016 are constantly upwards, since the demand rises to 1550 ktoe in 2020 and reaches 1850 ktoe in 2030.


Central Greece is the region with the highest demand for thermal energy, throughout the period examined, with a thermal demand of 522 ktoe in 2020 and 601 ktoe in 2030. It is followed by the Region of Attica, with a demand for heat of approximately 321 ktoe in 2020 and 385 ktoe in 2030. The Regions of Central Macedonia and Thessaly also record high demand figures, with 281 ktoe and 163 ktoe, respectively, for 2020 and 338 ktoe and 208 ktoe, respectively, for 2030. The Regions of Western Greece and Eastern Macedonia and Thrace are next in ranking order, with an approximately equal demand of 82 ktoe for 2020 and 106 ktoe for 2030. Smaller figures of demand for heat are recorded in the other Regions, as shown in Graph 7 above.


4. Geographical map of generation and demand for heating and cooling in Greek territory Facilities generating waste heat (Supply):

Potential sites where waste heat is available are shown in Map 1 for the following facilities. These sites relate to:

• Power plants with a capacity over 20 GWh/yr

• Existing HECHP plants

• Existing and planned district heating installations and networks

• Industrial facilities with potential useful waste heat (IA)

Sites of demand for heating and cooling (Demand): Maps 2 and 3 present the energy demand for heating and cooling, respectively, per Municipality, as

determined in Chapter 3 hereof.


REGIONAL UNITS MUNICIPAL/LOCAL DISTRICTS ESTIMATED SITES OF PLANTS FOR CO-GENERATION OF ELECTRICITY & HEAT FROM BIOMASS [TEXT MISSING] EXISTING PROCESSING FACILITIES ESTIMATED SITES OF PLANTS FOR CO-GENERATION OF ELECTRICITY & HEAT FROM BIOMASS [TEXT MISSING] FROM EXISTING PROCESSING FACILITIES INDUSTRIAL AREAS POWER GENERATION PLANTS DISTRICT HEATING PLANTS COMBINED HEAT AND POWER PLANTS

Map 1: Waste heat supply sites


INDUSTRIES Map 2: Demand for thermal energy


Map 3: Energy demand for cooling


5. Determination of technical potential for efficient heating and cooling This study explores the generation of energy-efficient heating and cooling by substitution of the existing conventional systems that generate heat for space heating and domestic hot water with energy-efficient thermal energy generation and transmission systems. The fuels examined in each case are biomass and natural gas, as well as the potentially available waste heat from existing facilities. Therefore, the technical potential of the systems that is examined exists in areas where fuel is available for heat generation.

5.1 The technical potential of biomass

In this phase, the quantities of biomass that can be utilised by potential facilities and fall in the category of agricultural residue, as well as forest biomass, were calculated. These are close to potential facilities (maximum distance of 50 km) and are either exclusive fuel, in cases where there are no industrial residues, or additional fuel, in cases where there are.

Given the spatial allocation of the potential, the geographical database of biomass potential, organised by the CRES, has been used. The biomass potential database of the CRES includes statistical data at a municipal district level, as well as estimates of:

• the quantities of biomass left on the field on the basis of the annual agricultural statistical survey;

• the available quantities of biomass, taking into account relevant availability factors;

• the physical characteristics of the residues of each category (calorific value, relative moisture), as well as their disposal and transport costs;

• the wood fuels available based on the applicable management studies.

On the basis of the geographical information system where the information about the potential has been entered, it is possible to calculate the relevant distance between extraction sites and combustion sites for each category of potential, in order to assess the relevant transport costs.


The exploitable biomass potential may be defined as the maximum quantity of biomass that can be utilised for energy production in each area, so that a positive balance of income and expenses results from its sale. The maps below present the areas with exploitable biomass potential.


Map 4: Allocation of estimated sites of facilities for heat production from biomass - North Greece


Map 5: Allocation of estimated sites of facilities for heat production from biomass - South Greece


5.2 Technical potential for heat production from natural gas The technical potential for heat production from natural gas is located in areas in Greece where a natural gas transmission network is available. The map below presents the natural gas transmission network.

HIGH-PRESSURE NATURAL GAS TRANSMISSION NETWORK

OPERATIONAL UNDER DESIGN

UNDER CONSTRUCTION GREECE-ITALY INTERCONNECTOR

FUTURE NETWORKING Map 6: Natural gas networks in Greece (source: DEPA)


6. Cost-benefit analysis at a nationwide level

This section presents an economic analysis and a cost-benefit analysis, at a community level, of the technically exploitable potential for efficient heating and cooling. The analysis takes into account the variation in the demand for heating and cooling per climate zone, as well as the variation of the economic potential in relation to the source of the available energy for covering heating and cooling needs.

A cost-benefit analysis at a community level is carried out in any case, taking into account the external costs and benefits resulting from the penetration of the technologies provided for by the scenarios considered. In addition, in cases where there is no financial potential but the benefit-to-cost ratio for the community is higher than one, the amount of the funding gap that needs to be covered for the investments in those technologies to be economically viable is examined.

Four (4) scenarios are defined for analysis purposes. The existence of financial potential is in any case dependent on the availability of a source of heat considered in each scenario, as well as the financial viability of the investment, as resulting from the financial analysis, taking into account the cash flows of the investments. In any case, the financial benefit to result from the sale of the energy generated must be high enough to render the investment financially viable.

Each scenario is assessed comparatively to the baseline scenario, which relates to the current situation of heating and cooling generation by use of conventional technologies.

The basic assumption of the baseline scenario is that:

• the total energy demand for space heating is covered by conventional oil-fired boilers

• the total energy demand for domestic hot water is covered by electric water heaters.

The scenarios considered are as follows:

Scenario 1: The demand for heating per settlement type is covered by district heating systems using available waste heat from existing facilities.


Scenario 2: The demand for heating per settlement type is covered by district heating systems using heat generated from new heat generation facilities by use of natural gas, biomass and co-combustion of biomass and lignite.

Scenario 3: The demand for heating per settlement type is covered by district heating systems using heat generated from high-efficiency cogeneration systems fuelled with natural gas.

Scenario 4: Penetration of co-generation and heat pumps for individual installations in the residential, tertiary and industrial sectors.

The scenarios are analysed in the subsequent sections, while the technical potential for efficient heating and cooling is also identified.

6.1 Cost-benefit analysis under Scenario 1: District heating and cooling by use of waste heat from existing facilities

Substituting conventional heat-generating systems in settlements for each climate zone separately by use of waste heat in district heating networks with a view to covering the thermal needs of a settlement is examined in this section. The analysis performed takes into account the potential distance of the settlement from the thermal source, as well as the population of the settlement.

The financial viability of the investments is examined, while a cost-benefit analysis is carried out in order to identify cases where the installation of district heating networks is beneficial to the community.

The results of the financial analysis and the cost-benefit analysis are presented in the following sub-sections.

The thermal demand that may be covered by district heating and cooling networks is determined for each climate zone on the basis of the available certificates of energy performance and the allocation of demand for energy per end use in the building sector in Greece. The necessary rated heating and cooling output is determined by analysing the heating and cooling degree-days per climate zone for the last three years.

The heating and cooling degree-days are obtained for each climate zone from main weather stations located in the areas inside each climate zone (www.degreedays.net). The following assumptions are taken into account for allocating heating and cooling loads on a monthly basis and for determining the heating and cooling output provided:

http://www.degreedays.net/


• the monthly allocation of loads is consistent with the relevant allocation of heating and cooling degree-days in each area.

• The demand for domestic hot water is considered (for purposes of method simplification, to the extent that the estimates are macroscopic) as equally allocated to all months of the year.

An analysis is made for the following types of settlements:

• Small mountain settlements with no more than 500 residents

• Settlements with 500 to 2 000 residents

• Towns with 2 000 to 10 000 residents

• Urban areas with more than 10 000 residents

Determination of the rated thermal demand of the settlement

The rated heat output (qov) of the facility that covers the typical demand for heating and domestic hot water of a settlement may be calculated in relation to the actual population of the settlement according to the following equation:

Where:

π is the actual population of the settlement.

The above empirical equation refers to settlements of Western Macedonia; therefore, for the other areas

in Greece, the equation is adjusted on the basis of the specific consumption per climate zone and end use

in accordance with the REPB.


Determination of thermal output of thermal energy transmission

The thermal output of transmission is determined by the rated output according to the following equation:

Qμετ = ν * qον

Where: ν is the percentage rate of the thermal output transmitted

The percentage rate of the rated output ν of the settlement in our calculations is equal to 70% of the rated output, since that is the prevailing coverage rate according to existing implementation studies in Greece. More specifically, when thermal energy is transmitted over a distance via a transmission network, usually from a low-cost thermal source, the best practice is not to design the transmission network for 100% of the demands of the settlement but for a part of the rated output.

Calculation of district heating/district cooling network costs:

Data from studies on the district heating networks that are operating in Greece or that have been already tendered and are under construction, have been used to determine the cost of the district heating distribution network (main distribution network, building interconnection costs and district heating substation costs). The above-mentioned district heating distribution networks are, specifically, those of Kozani, Ptolemaida, Amyndeo, Florina and Megalopoli. Using data from these studies, it was possible to roughly determine the cost of the distribution networks.

The following basic assumptions have been made for the described cost estimate:

• The thermal energy transmission medium is hot/superheated water, with a maximum temperature of 130oC and ΔΤ=50oC.

• The thermal energy transmission and distribution networks are underground and consist of pre-insulated steel pipes with insulation made of polyurethane and a protective enclosure of polyethylene, which are placed directly under the ground.

• The thermal energy transmission - distribution system is a closed two-pipe system.

For district cooling, even though there are no data from actual projects available, we can extrapolate based on both the ΔΤ and the cooling potential: More specifically, the cost of the district cooling network Cτψ can be approximately calculated in this case on the basis of the cost of the district heating network of ΔΤτψ and the ratio of the cooling potential to the heating potential of the settlement; the approximate reduction formula is as follows:


Δ Ττψ for district cooling is approximately 10oC.

In any case, the cost of the district cooling pipes is lower than the cost of the district heating pipes and, for that reason, the installation in the analysis performed is based on the district heating pipe costs.

Cost of thermal power plants and pumping equipment

• District heating plant generating thermal energy from natural gas-fired boilers: 0.05-0.15 M€/MWth

• District heating plant generating thermal energy from biomass-fired boilers: 0.4-0.6 M€/MWth • Small-scale district heating plant generating thermal energy through HECHP and biomass fuel:

1.5-1.9 Μ€/MWth • Medium-scale district heating plant generating thermal energy through HECHP and biomass fuel:

1.2-1.4 Μ€/MWth • District heating plant with thermal energy recovery from the industry (e.g. PPC steam-driven

power plants): 0.05-0.12

The cost of the pumping equipment, as well as of the thermal energy storage infrastructure, is approximately determined by the following table:

Type of settlements Cost as a percentage of the network (transmission and distribution) costs

Towns with 2 000 to 10 000 residents

10%

Urban areas with more than 10 000 residents

5%

Table 1: Cost of pumping equipment


Cost of thermal energy transmission network

The transmission cost of thermal energy Κ is calculated in conjunction with the transmission distance L (Km) as follows:

Κ = κ * L * Ομετ

Where:

κ is the specific cost of thermal energy transmission as calculated by the following equation:

κ = 155764 * αμετ(-0,5199), €/MW/Km

Ομετ: the thermal output of transmission, as calculated above in MWth.

Cost of thermal energy distribution network

The cost of the distribution network Κ is related to the size of the settlement and is determined by the following equation:

Κ = κ * π (€)

Where:

κ = 7000 * π^(-0.1889) €/resident: the specific cost and

π: the actual population of the settlement. The climate data for Western Macedonia are taken into account for calculation purposes; therefore, the result must be accordingly reduced for the other regions in Greece.

Energy selling price to consumer

The selling price of the energy generated must not exceed 80% of the energy cost already incurred by consumers for covering their energy needs with conventional technologies, so that an economic incentive is given to the consumer to choose the energy supply from the district heating and cooling network.

Thus, the selling price of the energy available from district heating networks is determined taking into account the energy demand per end use, the efficiency of the conventional technologies, as well as the selling price of conventional fuels.


The specific method of calculating the selling price of the available energy disconnects the analysis made from the potential impact of the selling price of conventional fuels to the final consumer, under the baseline scenario, on the cash flows of the investment. A potential change to the fuel price of conventional systems is directly reflected in the selling price of the energy made available from the district heating systems.

6.1.1 Economic analysis of Scenario 1

For an investment to be designated as economically viable and for economic potential to be deemed as existing, the economic indicators must record the following values:

Indicator Abbreviation Unit Value

Net present value NPV EUR >0

Internal rate of return IRR % ≥10%

Table 2: Indicators of economic viability of the investment

Indicators of economic viability of the investment

The results of the economic analysis relating to the use of waste heat for covering heating and DHW needs is presented in the following graph per climate zone.

The curves on the graph represent the points where the economic indicators of the investments record the values cited in Table 2 for the given population and distance between the waste heat source and the point of demand for energy. The points under the curves represent points where the internal rate of return (IRR) of the investments is less than 10% and, therefore, there is no economic potential for the development of district heating networks. Accordingly, investments are economically viable at the points over the curves. The dotted curves on the graph represent the population ceilings of the categories of settlements examined.


Economic viability of district heating networks

Distance from the waste heat source (km)

Climate Zone D Climate Zone C ---------------- Climate Zone B Climate Zone A — — Small settlement — — Medium-sized settlement — Town

Graph 8: Economic viability of district heating networks in relation to the population of the settlement and the distance from the waste heat source

As shown in the above graph, there is economic potential within a short distance from the thermal source, even in towns in climate zones A and B (low thermal demand).

In settlements with high thermal demand (climate zone C and D), economic potential exists in towns at greater distances of up to 10 km from the thermal source.

In addition, the economic potential for district heating increases in all cases where the population and the distance from the thermal source increase.


6.1.2 Cost-benefit analysis

This section presents a cost-benefit analysis at a community level, with a view to exploring whether a benefit for society arises from the installation of district heating networks in smaller populations and at shorter distances from the thermal source.

The cost and benefit components that are taken into account in the cost-benefit analysis, are as follows:

(+) Income: Includes revenues from the sale of the electricity and thermal energy generated from the co-generation plant.

(-) Operating costs: Include the district heating network maintenance costs.

(+) Operating benefit from the substitution of oil and electricity used for heating: Includes the cost of heating oil and electricity that is avoided.

(+) External benefit from the substitution of oil and electricity used for heating: Includes the external benefit from the heating oil avoided and the electricity avoided and relates to the impact on climate change, health, ecosystems, national economy due to reduction in the consumption of imported conventional fuels, etc.

According to the analysis made and as shown in the tables below, the indicators used for assessing the penetration of the district heating networks improve when moving from the climate zone with the minimum thermal demands (climate zone A) to the climate zone with the maximum thermal demands (climate zone D).

In most cases, other than in climate zones A and B for very small settlements and long distances from the thermal source, the benefit-to-cost (B/C) ratio is, according to the analysis, higher than one. For that reason, the amount of financial aid that may be granted for the investments to become economically viable has been examined.

The tables below present the results of the cost-benefit analysis per climate zone, as well as the minimum rate of financial aid that may be granted either in the form of grants or under subsidised loans, so that the investments are economically viable.


Climate Zone A Population 500 1 000 2 000 5 000 10 000 20 000 50 000 100 000

Dis

tanc

e (k

m)

1 36% 21% 10%

5 67% 55% 43% 18%

10 80% 70% 61% 40% 15%

15 B/C<1 78% 71% 53% 31% 6%

20 B/C<1 B/C<1 76% 61% 42% 19%

30 B/C<1 B/C<1 B/C<1 71% 56% 37%

40 B/C<1 B/C<1 B/C<1 77% 64% 48% 17%

50 B/C<1 B/C<1 B/C<1 81% 70% 56% 28%

Climate Zone B Population 500 1 000 2 000 5 000 10 000 20 000 50 000 100 000

Dis

tanc

e (k

m)

1 34% 18% 8%

5 64% 51% 39% 14%

10 77% 67% 58% 35% 10%

15 B/C<1 75% 67% 48% 25%

20 B/C<1 80% 73% 57% 36% 13%

30 B/C<1 B/C<1 81% 68% 51% 30%

40 B/C<1 B/C<1 B/C<1 74% 60% 42% 9%

50 B/C<1 B/C<1 B/C<1 78% 66% 51% 21%

Climate Zone C Population 500 1 000 2 000 5 000 10 000 20 000 50 000 100 000

Dis

tanc

e (k

m)

1 31% 15% 5%

5 60% 46% 34% 8%

10 74% 63% 53% 29%

15 81% 72% 63% 42% 18%

20 B/C<1 77% 69% 51% 29% 4%

30 B/C<1 B/C<1 77% 63% 44% 22%

40 B/C<1 B/C<1 82% 70% 54% 34%

50 B/C<1 B/C<1 B/C<1 75% 61% 44% 11%

Climate Zone D Population 500 1 000 2 000 5 000 10 000 20 000 50 000 100 000

Dis

tanc

e (k

m)

1 30% 14%

5 58% 44% 32% 5%

10 72% 61% 50% 26%

15 79% 70% 60% 39% 14%

20 B/C<1 75% 67% 48% 25%

30 B/C<1 82% 76% 60% 40% 17%

40 B/C<1 B/C<1 81% 67% 51% 30%

50 B/C<1 B/C<1 B/C<1 73% 58% 39% 5%

Table 3: Economic viability under Scenario 1


As shown in the above tables, the benefit-to-cost ratio falls below one as the thermal demands of the region decrease, either due to climate zone or due to the small number of the residents of the settlements, and as the distance of the thermal source from the settlement increases.

In any case, where the benefit-to-cost ratio is higher than one, the maximum rate of financial aid needed for the implementation of investments in district heating networks is 80%.

In addition, financial aid for the same settlement varies between climate zones. For the same type of settlement and distance from the thermal source, the rate of necessary financing increases when moving from climate zone D (maximum thermal demands) to climate zone A (minimum thermal demands).


6.2 Cost-benefit analysis under Scenario 2

Scenario 2 examines how thermal demand per settlement type is covered by district heating systems using heat generated from new heat generation facilities fuelled with natural gas, biomass and co-combustion of biomass and lignite.

6.2.1. Biomass and lignite co-firing in a boiler

6.2.1.1. Economic analysis

The analysis of the economic potential under scenario 2 which relates to the generation of thermal energy from biomass and lignite co-firing in a boiler and its sale to the final consumer via district heating networks demonstrated that economic potential for the specific method of producing energy-efficient heat exists only in large urban centres (more than 100 000 residents) and where the plant is at a very short distance from the urban centre.

6.2.1.2. Cost-benefit analysis

This section presents a cost-benefit analysis at a community level, with a view to exploring whether a benefit for the society arises from the installation of district heating networks in smaller populations and at shorter distances from the thermal source.


(+) Income: Includes revenues from the sale of the electricity and thermal energy generated from the co-generation plant.

(-) Operating costs: Include the district heating network maintenance costs.

(-) Operating costs of the co-fired boiler: Include the biomass and lignite purchase costs.

(+) Operating benefit from the substitution of heating oil:

Includes the cost of heating oil that is avoided.

(+) Operating benefit from the substitution of electricity for the generation of DHW:

Includes the electricity cost avoided for DHW.


(-) External cost of biomass-fired boiler: Includes the external cost of the co-fired boiler and relates to the impact on climate change, health, ecosystems, etc.

(+) External benefit from the substitution of heating oil: Includes the external benefit from the heating oil avoided and relates to the impact on climate change, health, ecosystems, etc.

The tables below present the results of the cost-benefit analysis per climate zone, as well as the minimum rate of financial aid that may be granted either in the form of grants or under subsidised loans, so that the investments are economically viable.

Climate Zone A Population Α 500 1 000 2 000 5 000 10 000 20 000 50 000 100 000

Distance (km)

1 89% 82% 76% 64% 52% 40% 19%

5 B/C<1 88% 82% 71% 59% 47% 26% 8% B/C<1

10 B/C<1 B/C<1 86% 76% 66% 53% 33% 15% B/C<1 B/C<1

15 B/C<1 B/C<1 Β/C<1 80% 70% 59% 39% 21% B/C<1 B/C<1

20 B/C<1 B/C<1 B/C<1 83% 74% 63% 44% 26% B/C<1 B/C<1

30 B/C<1 B/C<1 Β/C<1 Β/C<1 79% 69% 52% 34% B/C<1 B/C<1

40 B/C<1 B/C<1 Β/C<1 Β/C<1 82% 74% 57% 41% B/C<1 B/C<1

50 B/C<1 B/C<1 Β/C<1 B/C<1 B/C<1 77% 62% 47%

Climate Zone A Population B 500 1 000 2 000 5 000 10 000 20 000 50 000 100 000

Distance (km)

1 88% 82% 75% 63% 52% 39% 19%

5 B/C<1 87% 81% 70% 58% 45% 25% 6%

B/C<1

10 B/C<1 B/C<1 85% 75% 64% 51% 31% 12% B/C<1

15 B/C<1 Β/C<1 88% 79% 68% 56% 36% 18% B/C<1

20 B/C<1 Β/C<1 Β/C<1 82% 72% 61% 41% 23% B/C<1

30 B/C<1 Β/C<1 B/C<1 85% 77% 67% 48% 31% B/C<1

40 B/C<1 Β/C<1 Β/C<1 Β/C<1 81% 71% 54% 37% B/C<1

50 B/C<1 Β/C<1 Β/C<1 Β/C<1 83% 75% 59% 43%

Climate Zone A Population C 500 1 000 2 000 5 000 10 000 20 000 50 000 100 000

Distance (km)

1 88% 81% 75% 63% 51% 38% 18%

5 B/C<1 86% 80% 68% 56% 44% 23% 4%

10 B/C<1 89% 84% 73% 62% 49% 28% 10%

15 Β/C<1 B/C<1 86% 77% 66% 53% 33% 15%

20 Β/C<1 Β/C<1 Β/C<1 80% 69% 58% 37% 19%

30 Β/C<1 Β/C<1 Β/C<1 83% 75% 64% 45% 26%

40 Β/C<1 Β/C<1 B/C<1 86% 78% 68% 50% 32%

50 Β/C<1 Β/C<1 Β/C<1 B/C<1 81% 72% 55% 38%


Climate Zone D Population 500 1 000 2 000 5 000 10 000 20 000 50 000 100 000

Distance (km)

1 88% 81% 74% 62% 51% 38% 17%

5 91% 85% 79% 68% 56% 43% 22% 4%

10 B/C<1 88% 83% 72% 61% 48% 27% 9%

B/C<1

15 B/C<1 B/C<1 86% 76% 65% 52% 32% 13% B/C<1 B/C<1

20 B/C<1 B/C<1 88% 79% 68% 56% 36% 17% B/C<1 B/C<1

30 B/C<1 B/C<1 B/C<1 82% 73% 62% 43% 24% B/C<1 B/C<1 B/C<1

40 B/C<1 B/C<1 B/C<1 85% 77% 66% 48% 30% B/C<1 B/C<1 B/C<1

50 B/C<1 B/C<1 B/C<1 B/C<1 80% 70% 53% 35%

Table 4: Economic viability under sub-scenario 6.2.1

As shown in the above tables, the benefit-to-cost ratio falls below one as the thermal demands of the region decrease, either due to climate zone or due to the small number of residents of the settlements, and as the distance of the thermal source from the settlement increases.



6.2.2. Heat generation from a combination of biomass and natural gas-fired boiler technologies

6.2.2.1. Economic analysis This section examines the case where the thermal demands of a settlement are covered by a district heating network and heat generation from a biomass-fired boiler by 50% and from a natural gas-fired boiler by 50%.

The analysis of the economic potential under scenario 2 relating to the generation of thermal energy from the 2 boilers (fired with biomass and natural gas) and its sale to the final consumer via district heating networks demonstrated that there is no economic potential for the specific method of generating energy-efficient heat.


6.2.2.2. Cost-benefit analysis This section presents a cost-benefit analysis at a community level, with a view to exploring whether a benefit for the society arises from the installation of district heating networks in smaller populations and at shorter distances from the thermal source. The cost and benefit components that are taken into account in the cost-benefit analysis, are as follows: (+) Income: Includes revenues from the sale of the electricity and thermal energy generated from the co-generation plant. (-) Operating costs: Include the district heating network maintenance costs. (-) Operating costs of the co-fired boiler: Include the biomass and lignite purchase costs.

(+) Operating benefit from the substitution of heating oil:

Includes the cost of heating oil that is avoided.

(+) Operating benefit from the substitution of electricity for the generation of DHW:

Includes the electricity cost avoided for DHW.

(-) External cost of biomass-fired boiler: Includes the external cost of the co-fired boiler and relates to

the impact on climate change, health, ecosystems, etc.

(-) External cost of NG-fired boiler: Includes the external cost of the co-fired boiler and relates to the impact on climate change, health, ecosystems, etc. (+) External benefit from the substitution of heating oil: Includes the external benefit from the heating oil avoided and relates to the impact on climate change, health, ecosystems, etc. The tables below present the results of the cost-benefit analysis per climate zone, as well as the minimum rate of financial aid that may be granted either in the form of grants or under subsidised loans, so that the investments are economically viable.

Climate Zone A

Population

500 1 000 2 000 5 000 10 000 20 000 50 000 100 000

Distance (km)

1 86% 80% 74% 63% 52% 41% 22% 6%

5 B/C<1 87% 82% 72% 61% 49% 30% 13%

10 B/C<1 Β/C<1 87% 78% 68% 57% 38% 21%

15 B/C<1 B/C<1 B/C<1 82% 73% 62% 44% 28%

20 B/C<1 B/C<1 B/C<1 85% 77% 67% 49% 33%

30 B/C<1 B/C<1 B/C<1 B/C<1 82% 73% 57% 42%

40 B/C<1 B/C<1 B/C<1 B/C<1 85% 77% 63% 49%

50 B/C<1 B/C<1 B/C<1 B/C<1 B/C<1 80% 67% 54%


Climate Zone B

Population

500 1 000 2 000 5 000 10 000 20 000 50 000 100 000

Dis

tanc

e (k

m)

1 86% 80% 74% 63% 52% 40% 21% 5%

5 B/C<1 86% 81% 70% 59% 47% 29% 12%

10 B/C<1 B/C<1 86% 76% 66% 55% 36% 19%

15 B/C<1 B/C<1 89% 80% 71% 60% 42% 25%

20 B/C<1 B/C<1 B/C<1 83% 75% 64% 46% 30%

30 B/C<1 B/C<1 B/C<1 B/C<1 80% 71% 54% 38%

40 B/C<1 B/C<1 B/C<1 B/C<1 83% 75% 60% 45%

50 B/C<1 B/C<1 B/C<1 B/C<1 85% 78% 64% 50%

Climate Zone C

500 1 000 2 000 5 000 10 000 20 000 50 000 100 000

Dis

tanc

e (k

m)

1 85% 79% 73% 62% 51% 39% 20% 4%

5 B/C<1 85% 79% 69% 57% 45% 26% 9%

10 B/C<1 Β/C<1 84% 74% 64% 52% 33% 16%

15 B/C<1 Β/C<1 87% 78% 68% 57% 38% 21%

20 B/C<1 Β/C<1 B/C<1 81% 72% 60% 43% 26%

30 B/C<1 Β/C<1 Β/C<1 85% 77% 67% 50% 34%

40 B/C<1 Β/C<1 Β/C<1 B/C<1 81% 71% 56% 40%

50 B/C<1 Β/C<1 Β/C<1 Β/C<1 83% 75% 60% 45%

Climate Zone D

Population

500 1 000 2 000 5 000 10 000 20 000 50 000 100 000

Dis

tanc

e (k

m)

1 85% 81% 73% 62% 50% 38% 20% 3%

5 90% 79% 79% 68% 57% 44% 25% 9%

10 B/C<1 84% 83% 73% 63% 51% 31% 14%

15 B/C<1 88% 86% 77% 67% 55% 36% 19%

20 B/C<1 B/C<1 B/C<1 80% 71% 59% 41% 24%

30 B/C<1 Β/C<1 Β/C<1 84% 76% 66% 48% 31%

40 B/C<1 Β/C<1 Β/C<1 B/C<1 79% 70% 54% 37%

50 Β/C<1 Β/C<1 Β/C<1 Β/C<1 82% 74% 58% 43%

Table 5: Economic viability under sub-scenario 6.2.2

As shown in the above tables, the benefit-to-cost ratio falls below one as the thermal demands of the region decrease, either due to climate zone or due to the small number of the residents of the settlements, and as the distance of the thermal source from the settlement increases.




With regard to the comparison of sub-scenarios 6.2.1 and 6.2.2, co-firing is preferable to combined heat generation from biomass and natural gas-fired boilers, since the benefit-to-cost ratio is higher than one for longer distances and lower thermal demand (smaller settlements) per climate zone.

In addition, for a given population, climate zone and distance from the heat-generating source, the amount of the funding gap that needs to be covered for the investments to be economically viable is lower in case of co-firing than in the relevant case of combined heat generation from natural gas and biomass-fired boilers.


6.3. Scenario 3: Heat supply from new HECHP plants via district heating networks

6.3.1 Heat supply from new HECHP plants

For an investment to be designated as economically viable and for economic potential to be deemed to exist, the economic indicators must record the values cited in Table 2 of section 6.1.1.

6.3.1.1 Summary of the status of co-generation from 1970 to 2005

In Greece, the latest co-generation plants were created in the early 1970s in the industrial sector, that is in food processing (sugar), textile, paper and paper pulp, steel, oil refineries, chemicals, etc., without State aid. The co-producers were autoproducers and the main fuels used for the CHP plants were oil or petroleum products, since natural gas was not at the time available in Greece. In addition, two small CHP plants were installed in the tertiary sector, as pilot projects, co-funded by the European Programme VALOREN.

In 1985, the installed capacity of CHP plants in the various industrial sectors was 346.3 ΜWe, of which 93.5 MWe (27%) in oil refineries, 80 MWe (23%) in steel industries, 56 MWe (16%) in food industries, 48 MWe (14%) in chemical industries, 43 MWe (12%) in paper industries, 14,5 MWe (4%) in the textile industry and, lastly, 11.3 MWe (3%) in aluminium.

De-industrialisation in Greece had started in 1995 and many industries that operated based on co-generation became inoperative for many reasons, since the political and economic changes on the European continent after 1989 seriously afflicted Greece as well. As a result, the Greek textile industry, for example, shrank drastically due to intense competition from Asian companies or Eastern European companies, in conjunction with the relocation of companies to neighbouring countries for purposes of decreasing their payroll and taxation costs.

Therefore, the installed CHP was significantly reduced in 1995 and the installed capacity of CHP plants in the various industrial sectors was 116,4 ΜWe, of which 93.5 MWe (81%) were installed in oil refineries, 11.3 MWe (10%) in the aluminium industry and 11.6 MWe (9%) in the chemical industry.

At the beginning of the 21st century, the situation of the CHP was improved, in terms of establishment of a legal framework and of fuel supply security. This was due to the adoption of Law 2773/1999 implementing the European Directive liberalising the electricity market and the developments in the planned infrastructure for natural gas use. Now, Greece is supplied with natural gas from three different points of entry, the State applies a strong legal framework to co-generation and the monopolistic position of PPC has started being subject to a framework of structural changes.


The installed capacity for CHP was 168.16 MWe in 2005, of which 93.5 MWe (56%) were installed in oil refineries, 11.3 MWe (7%) in the aluminium industry, 11 MWe (7%) in the chemical industry, 4.5 MWe (3%) in food industries and 3 MWe (2%) in metal industries. A reference is also made to CHP facilities in the tertiary sector (hospitals, universities, etc.) and to CHP plants in six different municipal water supply companies throughout Greece, where there are HCP plants fired with gas from urban waste. Many of these facilities have been financed by the EC under CSFs during that period.

According to the Electricity Market Operator (LAGIE), during the 2004-2005 period, the technical data of ‘producers mainly engaging in CHP’ who feed the electricity they co-generate into the grid and are remunerated with ‘Feed-in-Tariffs’ are as follows (Table 6):

Year Energy in MWh

Installed Capacity in MW

2004 10 317 50.98

2005 14 395 163.4

Table 6: Co-generation data for Greece in the period 2004-2005

6.3.1.2 Summary of the status of co-generation from 2006 to 2015 According to the Electricity Market Operator (LAGIE), during the 2006-2015 period, the technical data of ‘producers mainly engaging in CHP’ who feed the electricity they co-generate into the grid3 and are remunerated with ‘Feed-in-Tariffs’4, are presented in Table 7.

3 Monthly Bulletin on ‘Feed-in-1Tariffs’ for RES and CHP; www.lagie.gr 4 Law 3468/2006, Article 9

http://www.lagie.gr/


Year Installed CHP potential in

MW

Co-generated electricity in MWh

Contracted HECHP in MW

2006 107.8 9 114 46.36

2007 109.65 34 028 51.28

2008 98.65 34 792 62.64

2009 140.74 144 122 104.74

2010 125.07 114 560 89.07

2011 89.07 141 638 -

2012 90.07 148 858 -

2013 90.07 118 790 -

2014 (99.07+134.60) 233.67 1 275 136 -

2015 (100.07+134.60) 234.67 1 309 344 -

Table 7: Data on co-generated electricity from the main autoproducers in the period 2006-2015

The installed capacity of HECHP plants per year, for the period 2006-2015, is shown in Chart 1. Please

note that the dispatched HECHP plant operating in Aluminium of Greece, with a capacity of 134.60 MWe,

has been added as from 2014. Moreover, all HECHP plants operate on the Greek mainland.


INSTALLED CAPACITY, MW YEAR Graph 9: Installed capacity of HECHP plants per year (2006-2015)

As a result of the economic recession that started in 2010, many co-producers, mostly with HECHP plants, closed their plants due to financial difficulties, especially in paying the natural gas bills to DEPA, and due to a delay of more than six months in the payment by the Electricity Market Operator (LAGIE) of the ‘Feed-in-Tariff’ for the co-generated electricity fed into the grid. This situation got worse in the following years, the relevant delay being extended to eight months, causing significant cash flow problems for co-producers. An attempt to solve this problem was made by Law 4254/2014.


With regard to the applications for the licensing of HECHP plants by the RAE5, according to data it has published, the situation is shown in Table 8 and in Graphs 10 and 11 below.

Year MW Number of licences

2010 15.23 4

2011 68.93 6

2012 7.5 2

2013 6.77 3

2014 36 3

2015 4 1

Table 8: Generation licences issued to HECHP plants (2010-2015)

Capacity of HECHP plants holding generation licences (2010-15)

Installed Capacity (MW) Year

Graph 10: Capacity of HECHP plants holding generation licences per year

5 Data provided by the RAE, www.rae.gr


Number of generation licences issued to HECHP plants

Graph 11: Number of generation licences issued to HECHP plants per year (2010-2015)

With regard to the applications of micro CHP, which are mainly installed in the residential sector, there was a remarkable increase in the years before the economic crisis, but the trend is currently downward, mainly due to the high initial expenditure needed for these systems. Development is expected, though, in the tertiary sector in applications of micro and small CHP, with particular emphasis on public and private hospitals and clinics and public buildings. Moreover, many hotels, mainly in Athens and Thessaloniki, submit applications for the requisite licences for trigeneration plants, which is a time-consuming procedure, especially if an environmental authorisation is required.

6.3.1.3 The developments in the legal framework governing CHP/HECHP

Legal Policy on CHP/HECHP Law 2244/1994 lays down the legal framework governing co-generation in Greece. This Law on ‘Arrangement of issues of electricity generation from RES and conventional fuels’ entered into force in October 1994 and introduced the distinction between ‘autoproducer’ and ‘independent producer’ in the Greek energy market, while also permitting the establishment of co-generation plants by autoproducers (either independently or in connection to the PPC grid).

Directive 2004/8/EC lays down the framework for promoting co-generation of energy and, in particular, high efficiency co-generation, a key factor for attaining the energy efficiency targets in the EU. Greece transposed Directive 2004/8/EC into national law by Laws 3468/2006 and 3734/2009.


Law 3851/2010 (Article 10) lays down that all new buildings must cover their needs for primary energy with energy systems operating on the basis of RES, CHP, district heating/cooling, as well as heat pumps, by 31 December 2019 at the latest. This obligation shall apply to all new buildings housing government and public services from no later than 31 December 2014.

Law 4001/2011 transposed into national law the third Directive on the internal electricity market. It provides, inter alia, for the separation of the system operators and reinforces the role of independent regulatory authorities in terms of security of supply, licensing, market and consumer protection monitoring. The Law abolishes the maximum limit of installed capacity of 35 MWe per high-efficiency combined heat and power (HECHP) plant for the electricity generated by that plant to have a priority access in load dispatching. In 2012, the Minister for Environment and Climate Change adopted a decision on the creation of a Register for Certification, Verification and Inspection Bodies for HECHP Plants, so that only those which have been certified and designated as Registered HECHP Plants are supported with ‘F-i-T’. The Register is maintained at LAGIE.

At the beginning of 2013, the Ministry of Environment and Climate Change adopted a Ministerial Decision on a requisite licensing procedure both for HECHP and for CHP plants, thus making the investment environment easier.

On 7 April 2014, certain Articles of Law 4254/2014 on ‘Measures for supporting and developing the Greek economy in implementing Law 4946/2012’ revised relevant Articles of Law 3851/2010 which refer to the pricing policy applicable to RES and HECHP (feed-in-tariffs). The Law introduced a new classification for HECHP plants.

6.3.1.4 Support mechanisms for CHP/HECHP

HECHP promotion has been based on various support mechanisms including either investment subsidies granted under ‘Operational Programmes for Competitiveness and Entrepreneurship’ financed by the EC and the national investment law or tax remissions. The same actions that are aimed to providing economic assistance are still in effect with the help of Energy Service Companies (ESCO).


Law 3908/2011 on ‘Private investment aid for economic development, entrepreneurship and regional cohesion’ includes support for investment plans, including the construction of HECHP plants, by offering:

(a) tax exemption,

(b) a subsidy, which consists of payment by the State of an amount, free of charge, for covering a part of the subsidised expenses,

(c) a financial leasing subsidy, which consists in the coverage by the State of a part of the instalments paid for acquisition of mechanical and other equipment.

The programmes financed by the EU under ‘Competitiveness and Entrepreneurship’, which are part of the National Strategic Reference Framework (NSRF) 2007-2013 and finance various investments relating to co-generation systems as eligible expenditure, are as follows:

• ‘High-Efficiency Combined Heat and Power in Hospitals’ aimed at the installation of HECHP plants in combination with cooling systems, using natural gas, in hospitals, with a budget of EUR 15 million;

• ‘Green Tourism’ aimed at supporting tourist facilities with a view to improving their operating infrastructure and their operational procedures to take a “greener” approach and with actions that include the installation of co-generation systems.

• The budget is approximately EUR 30 million; • ‘Alternative Tourism’ aimed at supporting investment plans, including the development of one or

more special and/or alternative forms of tourism, as well as actions that include the installation of energy-saving, co-generation and RES systems (with a total capacity of up to 20 kWe only for covering own needs) in the context of an ‘autoproduction’ scheme. The estimated budget is approximately EUR 20 million;

• Moreover, proposals for actions that finance district heating either via new projects or by extension of existing networks are acceptable under the Operational Programme ‘Environment and Sustainability’, with a total budget of EUR 50 million.


Many of these programmes for promoting CHP have not been activated.

The Greek co-generation market is still at an early phase of development, demonstrating a limited level of information and awareness of the significant advantages of that technology. In addition, the challenges of the Greek energy market are added to the difficulty in developing appropriate market awareness: the electricity market is still partly liberalised, with many distortions still existing in the electricity and the fuel markets, and many legal and administrative obstacles that need to be overcome.

6.3.1.5. The finance of CHP

The basic parameters affecting the economic viability of CHP are the energy prices on the market, namely the prices of purchase/sale of electricity and natural gas, both for the industrial CHP and for CHP plants in the primary and tertiary sector. Therefore, the prices of electricity and natural gas and the calculated ratio of ‘electricity selling price to NG selling price’ or, as widely known, ’spark ratio’, are presented in Tables 9 and 10 for four consecutive years (2012-15).

Natural gas (€/MWh) Electricity (€/MWh)

Years Industrial Residential Industrial Residential

Sector6 Sector7 Sector8 Sector9

2012 65 147 118 126

2013 58 112 121 154

2014 54 100 122 173

2015 47 80 113 180

Table 9: Prices of natural gas and electricity in Greece

6 Eurostat - Industrial sector with consumption ranging from 10 000 GJ to 100 000 GJ 7 Eurostat - Residential sector with consumption less than 20 GJ 8 Eurostat - Industrial sector with consumption ranging from 2 000 MWh to 20 000 MWh 9 Eurostat - Residential sector with consumption ranging from 1 000 kWh to 2 500 kWh


Years Spark ratio

Industrial sector Residential sector

2012 1.80 0.86

2013 2.07 1.37

2014 2.27 1.72

2015 2.43 2.26

Table 10: ‘Spark ratio’ for the period 2012-2015

Graph 12 presents the variation of the ‘Spark ratio’ for households and industries in the period from 2012 to 2015.

Industrial Residential

Graph 12: ‘Spark ratio’ variation for households and industries

6.3.1.6. HECHP support mechanisms

In Greece, CHP support policy applies, under law, to co-producers ‘irrespective of whether they operate as self-producers or as independent producers via guaranteed feed-in-tariffs, and only for high-efficiency co-generated electricity that is fed into the system or the grid, including the network of non-interconnected islands, on a basis of a defined price expressed in EUR per MWh of electricity and for a specific time period.


Law 3851/2010 and, in particular Article 5, set the F-i-T rates for co-generated power fed into the system or the grid at 87.85 EUR/MWh for the interconnected grid and at 99.45 EUR/MWh for the network of non-interconnected islands, produced from all fuels except for natural gas. For natural gas-fired CHP plants, the NG-fuel clause factor (CF) had been introduced for regulating the price of electricity co-generated by a HECHP plant, according to international natural gas prices of the previous month. Thus, the F-i-T calculation formula for electricity co-generated from HECHP plants fired with natural gas was set as follows: 87.85 * CF for the interconnected system (in EUR/MWh) and 99.45 * CF for non-interconnected islands (in EUR/MWh)

The fuel clause factor (CF) is calculated by the following equation:

CF = 1 + (NGUP - 26) / (100 x nel) (1)

where: NGUP = the monthly average price, in EUR/MWh, for the sale of higher calorific value natural gas used for co-generation purposes to users in Greece, exclusive of power generating customers. The price is set by DEPA SA and communicated to HTSO.

nel = the power efficiency level of a HECHP system using higher calorific value natural gas, set at 0.33 for HECHP plants of <1 MWe and 0.35 for HECHP plants of >1 MWe.

The clause factor (CF) rate may not be lower than one.

By Decision 435/2011, the RAE stipulated that the clause factor (CF) that is used to determine the price of electricity co-generated by HECHP producers who have invested in HECHP plants that include exhaust gas scrubbing and their utilisation for CO2 enrichment in high-technology greenhouse facilities is modified according to the following equation:

CF = 1.18 + (NGUP - 26) / (100 x ne) (2)

Law 4254/2014 revised Article 5 of Law 3851/2010 which refers to the ‘F-i-T’ calculation methodology and introduced a new methodology for calculating them for all RES and for HECHP, with a view to eliminating within a short period, as stated in its introductory report to the Hellenic Parliament, the debts of the Electricity Market Operator (LAGIE).


Now, the F-i-T for co-generated electricity that is fed into the grid is set at 85 EUR/MWh for the interconnected networks and at 95 EUR/MWh for the non-interconnected network (islands), by use of all fuels, except for natural gas.

The Law introduces new classifications for HECHP plants, which are divided into two distinct categories, as follows:

a. existing and operating HECHP plants; and

b. new HECHP plants that enter in operation upon the entry into force of Law 4254/2014.

More specifically:

a. For existing and operating HECHP plants

The new classification applicable to existing HECHP plants, the new pricing policy for high-efficiency co-generated electricity (in EUR/MWh) that is based on two basic types: (a) HECHP investments implemented without subsidy; and (b) HECHP investments implemented with subsidy either with European or with national funds, as well as the efficiency levels, are presented in Table 12.

Without subsidy

EUR/MWh

With subsidy EUR/MWh

HECHP Categories Efficiency Rates

NG-fired HECHP plants, ≤ 1MWe with:

- Combined gas turbine cycle with heat recovery - Steam extraction condensing turbine

95+VA 80+VA η = 72%, ηe = 33%, ηhr = 81%

NG-fired HECHP plants, ≤ 1MWe for all other categories, in accordance with Directive 2004/8/EC

100+VA 85+VA η = 67%, ηe = 33%, ηhr = 81%

NG-fired HECHP plants, from > 1 MWe to ≤ 35 MWe with: - Combined gas turbine cycle with heat recovery - Steam extraction condensing turbine

85+VA 75+VA η = 72%, ηe = 35%, ηhr = 81%

NG-fired HECHP plants, from > 1 MWe to ≤ 35 MWe for all other categories, in accordance with Directive 2004/8/EC

90+VA 80+VA η = 67%, ηe = 35%, ηhr = 81%

NG-fired HECHP plants, > 35 MWe with: 62+VA 57+VA η = 72%, ηe = 33%, ηhr = 81%


- Combined gas turbine cycle with heat recovery

- Steam extraction condensing turbine

NG-fired HECHP plants, > 35 MWe for all other categories, in accordance with Directive 2004/8/EC

68+VA 63+VA η = 67%, ηe = 35%, ηhr = 81%

Table 11: ‘F-i-T’ for various categories of operating HECHP plants, with or without subsidy and efficiency levels

The term ‘VA’ in Table 11 refers to the adjustment of natural gas, a parameter covering the variation of the natural gas costs, and is calculated by the following formula:

where: η=ηe + ηh total efficiency of a HECHP plant

ηε = power efficiency level of a HECHP plant ηh = thermal efficiency level of a HECHP plant

ηhr = the efficiency reference value for the separate generation of thermal energy, where efficiency is expressed as Higher Calorific Value (HCV), as presented in Table 12.

NGUPt = the monthly average natural gas unit price, in EUR/MWh, of higher calorific value, which includes the selling price with the transmission cost and the excise duty NGUPμ or NGUPη, to which the average CO2 cost that corresponds to power generation is added.

NGUPμ = the monthly average natural gas unit price for cogeneration in EUR/MWh of higher calorific value for selling natural gas to NG users in Greece, exclusive of power generation customers.

NGUPη = the monthly average natural gas unit price in EUR/MWh of higher calorific value for selling natural gas to NG users in Greece who are power generation customers.

The NGUPμ and NGUPη rates are set as the responsibility of the Oil Policy Directorate of the Ministry of Energy and are communicated on a monthly basis to LAGIE.

According to LAGIE data, aggregate data on HECHP in Greece as from the entry into force of the provisions of Law 4254/2014 are presented in Table 12.


Year HECHP & dispatched

HECHP plant MW

Annually

generated energy

GWh

Average HECHP

energy price EUR/MWh

Average energy price of a dispatched HECHP plant

EUR/MWh

NGUPμ

EUR/MWh

NGUPη

EUR/MWh

2013 220 1062 179.5 53.7 - -

2014 229 1156 161.3 33.9 44.0436 39.0225

2015 230 1192 154.7 29.8 37.4435 33.1311

Table 12: Aggregate data on HECHP in Greece following application of Law 4254/2014.

The average CO2 cost is calculated by the following equation:

Ave CO2 (EUR/MWh) = 0.37 x aver CO2 allowances (EUR/tn) x ηο (4)

The average prices of CO2 emission allowances are provided by the European Power Exchange (EPX) on a monthly basis.

The average price of CO2 allowances was 5.94 EUR/tn for 2014 and 7.58 EUR/tn for 2015 (LAGIE data).

With regard to HECHP plants installed in the primary sector (agriculture) or heat generation from district heating installations, Law 4254 of 4 July 2014 provides for the addition to the fixed part of ‘X + VA’ (price, except for VA) of an extra rate of 20%, which was further increased by 45% by virtue of an amendment to another energy law, Law 4273/2014.


b. For new HECHP plants, which enter in operation following the entry into force of Law 4254/2014

A new classification of HECHP plants that will enter in operation following the entry into force of Law 4254/2014 is applicable, as presented in Table 13.

HECHP Categories Without subsidy

EUR/MWh

With subsidy EUR/MWh

• Efficiency Levels

NG-fired HECHP plants, < 1 MWe for:

-Combined gas turbine cycle with heat recovery -Steam extraction condensing turbine

88+VA 76+VA η = 72%, ηe = 33%, ηhr = 81%

NG-fired HECHP plants, < 1MWe for all other categories, in accordance with Directive 2004/8/EC

92+VA 80+VA η = 67%, ηe = 33%, ηhr = 81%

NG-fired HECHP plants, from > 1 MWe to ≤ 5 MWe for: -Combined gas turbine cycle with heat recovery -Steam extraction condensing turbine

80+VA 70+VA η = 72%, ηe = 33%, ηhr = 81%


84+VA 74+VA η = 67%, ηe = 35%, ηhr = 81%


74+VA 65+VA η = 72%, ηe = 35%, ηhr = 81%


78+VA 70+VA η = 67%, ηe = 35%, ηhr = 81%


68+VA 62+VA η = 72%, ηe = 35%, ηhr = 81%


72+VA 66+VA η = 67%, ηe = 35%, ηhr = 81%

NG-fired HECHP plants, > 35 MWe


for:

-Combined gas turbine cycle with heat recovery -Steam extraction condensing turbine

61+VA 57+VA η = 72%, ηe = 35%, ηhr = 81%

NG-fired HECHP plants, > 35MWe for all other categories, in accordance with Directive 2004/8/EC

65+VA 60+VA η = 67%, ηe = 35%, ηhr = 81%

Other HECHP plants connected to the interconnected system

85 80 -

Other HECHP plants connected to the network of non-interconnected islands

95 90 -

Table 13: Classification of new HECHP installations after April 2014

The new pricing policy applicable to high-efficiency electricity (in EUR/MWh) co-generated from new HECHP plants is based on two types:

• HECHP investments without subsidy; and • HECHP investments with subsidy, either with European or with national resources, as

presented in Table 12.

The NG value adjustment ‘VA’ in Table 16 covers NG cost variations and is calculated by the following equation:

where: η= ηe + ηh : total efficiency of a HECHP plant

ηe : power efficiency level of a HECHP plant

ηh : thermal efficiency level of a HECHP plant ηhr : the efficiency reference value for the separate generation of thermal energy, where efficiency is expressed as Higher Calorific Value (HCV), as presented in Table 12.

NGUPt : the monthly average natural gas unit price, in EUR/MWh, of higher calorific value, which includes the selling price with the transmission cost and the excise duty NGUPμ or NGUPη, to which the average CO2 cost that corresponds to power generation is added.

NGUPμ : the monthly average natural gas unit price for cogeneration in EUR/MWh of higher calorific value for selling natural gas to NG users in Greece, exclusive of power generation customers.

NGUPη : the monthly average natural gas unit price in EUR/MWh of higher calorific value for selling natural gas to NG users in Greece who are power generation customers.

The NGUPμ and NGUPη rates are set under the responsibility of the Oil Policy Directorate of the Ministry of Environment and Climate Change and are communicated on a monthly basis to LAGIE.


The average CO2 cost is calculated by the following equation:

Ave CO2 (EUR/MWh) = 0.37 x aver CO2 allowances (EUR/tn) x ηe (6)

The average prices of CO2 emission allowances are provided by the European Power Exchange (EPX) on a monthly basis.

In two cases, namely for existing and for new HECHP plants, the Law lays down that each co-producer must be registered in Certification Bodies for co-generated electricity that is fed into the grid/system (e.g. NTUA, TUV, etc.) which inspect the installation and then verify, at any time, the operation of the plant and the co-generated electricity that is fed into the system/grid and is recorded online at LAGIE. Only co-producers having complied with the recommendations of the Certification Bodies and with the procedures issued by LAGIE with the help of the HACHP shall be eligible for any subsidies granted.

With regard to new HECHP installations in the agricultural sector or heat generation from district heating, Law 4254/2014 provides for an increase by 20% and 15%, respectively, of the fixed part of ‘X + VA’ (price except for VA).

Moreover, taxation and levies have been imposed on co-producers in accordance with the provisions of Law 4254/2014, such as:

• A tax on all fuels, including natural gas, was imposed for 2010, according to the requirements under the First Memorandum signed between the Greek Government and the lenders (European Commission, ECB, IMF).

• A 10% ‘extraordinary levy’ was imposed on gross profit from the monthly ‘F-i-T’ under the Second Memorandum, for 2 + 1 years, starting from June 2012 and ending on June 2015.

With regard to co-generation plants that are fuelled with biomass or biogas, the ‘F-i-T’ applicable to the co-generated electricity are set in Law 4254/2014 as follows: 85 EUR/MWh for the interconnected network and 95 EUR/MWh for the non-interconnected network (islands). Therefore, investors who use ‘biomass-biogas’ as fuel submit an application for ‘F-i-T’ in the subcategory ‘biomass/biogas’ of the category ‘RES’, for higher ‘F-i-T’ than those applicable to HECHP.

New support scheme, the feed-in tariffs for electricity from HECHP in accordance with

Currently, the new RES support scheme is under development and relates to the feed-in-premium system.


The new scheme supporting power generation from RES and HECHP plants, within the context of attaining the European and national energy targets, aims to radically reform the support scheme for these plants in the best possible manner in terms of the cost-benefit ratio for the community, with a view to achieving their gradual integration and participation in the electricity market with the minimum possible burden on the final consumer as a result of the ETMEAR charge.


6.3.1.7 Analysis of HECHP cost-benefit for the generation of energy-efficient heating via district heating networks fuelled with natural gas

This section addresses the substitution of conventional heat-generating systems in settlements for each climate zone separately by use of heat produced by 75% from high-efficiency co-generation (HECHP) systems and by 25% from natural gas-fired boilers and transmission of the energy generated via district heating networks to settlements, with a view to covering their thermal needs.

The analysis performed takes into account the co-generation technology that may be used, the potential distance of the settlement from the thermal source, the population of the settlement, as well as the climate zone where the settlement is located.

More specifically, the following HECHP technologies are examined:

• Combined cycle gas turbine with heat recovery

• Differential pressure steam turbine

• Steam extracting-condensing turbine with heat recovery

• Gas turbine with heat recovery

• Internal combustion engine

The results of the economic analysis are presented in the graphs below per climate zone and HECHP technology examined. Please note that the results of the analysis performed for the technologies of differential pressure steam turbine, steam extracting-condensing turbine with heat recovery and gas turbine with heat recovery differ marginally as regards both the economic analysis and the cost-benefit analysis.

For that reason, the results for the differential pressure steam turbine technology in the graphs below also apply, at the same time, to the other two technologies that are not presented in the graphs.


HECHP Climate Zone A Population Distance (km) - Combined cycle gas turbine with heat recovery - Internal combustion engine - Medium-sized settlement - Differential pressure steam turbine - Small-sized settlement - Town Graph 13: HECHP Climate Zone A


HECHP Climate Zone B Population Distance (km) - Combined cycle gas turbine with heat recovery - Internal combustion engine - Medium-sized settlement - Differential pressure steam turbine - Small-sized settlement - Town Graph 14: HECHP Climate Zone B


HECHP Climate Zone C Population Distance (km)

- Combined cycle gas turbine with heat recovery - Internal combustion engine - Medium-sized settlement - Differential pressure steam turbine - Small-sized settlement - Town Graph 15: HECHP Climate Zone C


HECHP Climate Zone D Population Distance (km)

- Combined cycle gas turbine with heat recovery - Internal combustion engine - Medium-sized settlement - Differential pressure steam turbine - Small-sized settlement - Town Graph 16: HECHP Climate Zone D


The curves on the graph represent the points where the economic indicators of the investments record the values cited in Table 2 (section 6.1.1) for the given population and distance between the waste heat source and the point of demand for energy.

The points under the curves represent points where the internal rate of return (IRR) of the investments is less than 10% and, therefore, there is no economic potential for the penetration of HECHP technologies via district heating networks. Accordingly, investments are economically viable at the points over the curves. The dotted curves on the graph represent the population ceilings of the categories of settlements examined.

As shown in the graph above, for each climate zone, where an installed capacity of HECHP system higher than 4 MWe is needed for covering the thermal demands for the settlements (technical potential), the combined cycle gas turbine with heat recovery (the installed capacity of combined cycle gas turbine with heat recovery system ranging from 4 to 300 MWe) is the prevailing technology, since, for a given distance from the settlement, investments in that technology are economically viable for settlements with a smaller population.

In all other cases, internal combustion engines prevail over the other HECHP technologies.

In any event, efficient heating is economically viable in towns at a distance from the heat generation point ranging from 15 km (climate zone A) to 30 km (climate zone D).

In addition, economic potential for heat generation from HECHP plants exists also for very small settlements (with no less than 230 residents in climate zone D) at a short distance from the heat-generating plant (1 km).

Lastly, the economic potential increases in all cases where the population and the thermal demand per climate zone increase while the distance from the thermal source decreases.


6.4. Scenario 4: Penetration of co-generation and heat pumps for individual installations in the residential, tertiary and industrial sectors

6.4.1 Penetration of co-generation for individual installations in the residential, tertiary and industrial sectors This section examines the viability of replacing existing conventional systems for heating and domestic hot water at the level of installation with usage of energy generated from co-generation systems. In that case, the operating benefit from the installation of a CHP system also includes the cost avoided through the termination of the existing conventional systems. The economic viability of investments was examined by taking into account the analysis performed under Scenario 1. Therefore, the technical potential of natural gas-fired co-generation systems is analysed per climate zone. The analysis performed showed that the investment is not economically viable in all cases examined in each climate zone. Nevertheless, the cost-benefit analysis at the level of society demonstrates a major benefit from investing in heat generation by use of co-generation systems. The Tables below summarise the results of the economic analysis and the cost-benefit analysis for the implementation of small and medium-scale co-generation systems in the residential and tertiary sectors. In addition, the funding gap that needs to be covered for the investments to become economically viable is pointed out. The cost and benefit components that are taken into account in the cost-benefit analysis, are as follows: (+) Income: It includes revenues from the sale of the electricity generated from the co-generation plant. (-) Operating costs: It includes the fuel purchase costs and the co-generation plant maintenance costs. (+) Operating benefit from the substitution of heating oil and electricity for the generation of DHW: Includes the cost of heating oil and electricity that is avoided. (-) External cost of co-generation plant: It includes the external cost of the co-generation plant and relates to the impact on climate change, health, ecosystems, etc.


(+) External benefit from the substitution of oil and electricity used for heating: Includes the external benefit from the heating oil avoided and the electricity avoided and relates to the impact on climate change, health, ecosystems, national economy due to reduction in the consumption of imported conventional fuels, etc.

The Tables below present the results of the analysis.

Residential Sector: Detached house

Climate Zone A Indicator Α Β C D

Economic analysis NPV (EUR) -9 663.67 -10 731.05 -12 238.83 -13 085.49 IRR (%) -3% -5% -10% -14%

NPV (EUR) -1 856 -4 451 -8 120 -10 176 Cost-benefit analysis IRR (%) 3% 1% -3% -7%

B/C 1.39 1.09 0.67 0.44 Economic aid rate for investment

viability purposes

% 48% 60% - -

Residential building of 10 flats

Climate Zone A Indicator D C Β Α NPV (EUR) -60 831.31 -51 081.51 -37 404.53 -29 596.76

Economic analysis IRR (%) 1% 1% 0% 0%

NPV (EUR) 23 164 17 638 9 705 5 419 Cost-benefit analysis IRR (%) 7% 7% 7% 6%


viability purposes

% 20% 21% 25% 30%


Climate Zone A Indicator D C Β Α

Economic analysis NPV (EUR) -77 868.95 -65 272.99 -47 638.82 -37 524.41 IRR (%) 4% 3% 3% 3%



viability purposes

% 12% 13% 16% 18%

Table 14: Cost-benefit analysis of Scenario 4 - Residential Sector


Tertiary Sector

Internal combustion engine fuelled with natural gas Indicator Climate Zone A D C Β Α

Economic analysis NPV (EUR) -19 819.51 -16 745.24 -12 566.88 -10 001.11 IRR (%) 8% 8% 8% 8%


B/C 3.03 3.02 2.98 2.95 Economic aid rate for investment viability purposes

% 15% 15% 15% 15%

Table 15: Cost-benefit analysis of Scenario 4 - Tertiary Sector

Industry

The study on the viability of replacing existing conventional systems for heating and domestic hot water with co-generation systems was carried out at the level of individual installation and complex. In that case, the operating benefit from the installation of a CHP system also includes the cost avoided through the termination of the existing conventional systems. The study examined the economic viability of investments, taking into account the annual operating hours of the system, as well as the fuel used by the conventional systems and the co-generation systems. Economic potential of CHP at the level of individual installation is identified in the replacement of an existing heat-generation system fired with heating oil with a co-generation system fired with natural gas. Table 16 below presents the results relating to the economic potential of CHP in the industrial sector.


Operating

hours Economic indicator

Internal combustion engine

Micro-turbines Fuel cells Other types of technology

NPV Χ Χ Χ √ IRR Χ Χ Χ Χ

6 500 BCR Χ Χ Χ √ DPB Χ Χ Χ Χ NPV √ Χ Χ √ IRR Χ Χ Χ √

7 000 BCR Χ Χ Χ √ DPB Χ Χ Χ √ NPV √ Χ Χ √ IRR √ Χ Χ √

7 500 BCR √ Χ Χ √ DPB √ Χ Χ √ NPV √ Χ Χ √ IRR √ Χ Χ √

8 000 BCR √ Χ Χ √ DPB √ Χ Χ √

Table 16: Economic potential of CHP in the tertiary sector

6.4.2. Air-cooled heat pumps

The specific scenario relates to the substitution of thermal energy for space heating, generated from a heating oil-fired boiler, with thermal energy generated from air-heated heat pumps in residential and tertiary sector buildings. The analysis below examines the substitution of conventional heat generation systems in typical buildings for each climate zone separately.

An economic analysis of investments and a cost-benefit analysis at community level are carried out.


(-) Operating costs of air-heated heat pumps: It includes the cost of electricity consumed and the maintenance costs for air-heated heat pumps.

(+) Operating benefit from the substitution of heating oil: It includes the heating oil costs and the maintenance costs for the heating oil that are avoided.


(-) External cost of air-heated heat pumps: It includes the external cost of the electricity consumed and relates to the impact on climate change, health, ecosystems, etc.

(+) External benefit from the substitution of heating oil: It includes the external benefit from the substitution of heating oil and relates to the impact on climate change, health, ecosystems, etc.

The results of the economic analysis and the cost-benefit analysis are presented in the following tables.

The assumptions and cash flows of the specific analysis are cited in the Annex.

According to the analysis performed and as shown in the tables below, the indicators used for assessing the penetration of the air-heated heat pump technology in the residential sector improve when moving from the climate zone with the minimum thermal demands (climate zone A) to the climate zone with the maximum thermal demands (climate zone D).

Nevertheless, the penetration of air-heated heat pumps in residential sector buildings is not recommended, since the benefit-cost ratio is in all cases lower than one.

Detached house Climate Zone A

Indicator Α Β C D

Economic analysis NPV -11 586 -11 078 -10 181 -9 544

IRR -17% -13% -8% -6% NPV -9 467 -8 115 -5 727 -4 031

Cost-benefit analysis IRR -9% -6% -2% 1% B/C 0.54 0.63 0.77 0.85


Indicator Climate Zone A

Α Β C D


IRR - -22% -12% -9% NPV -105 884 -92 369 -68 490 -51 529

Cost-benefit analysis IRR -12% -8% -3% -1%

B/C 0.48 0.58 0.73 0.81


Residential building of 20 flats Indicator Climate Zone A

Α Β C D


IRR - - -12% -9% NPV -213 015 -185 985 -138 225 -104 304

Cost-benefit analysis IRR -13% -8% -3% -1% B/C 0.48 0.58 0.73 0.81

Tertiary sector

Indicator Climate Zone A

Α Β C D


IRR - -14% -8% -5% NPV -187 839 -152 871 -90 705 -46 023

Cost-benefit analysis IRR -8% -5% 0% 3% B/C 0.57 0.69 0.84 0.93

Table 17: Cost-benefit analysis of the substitution of existing systems with heat pumps


7. Setting out strategies, policies and measures for 2020 and 2030

The policies and measures that can be implemented by 2030 with a view to best utilising the potential for efficient heating and cooling will initially focus on the development of district heating networks in areas where waste heat is available.

The analysis of Scenario 1 demonstrated a very high economic potential with major benefits for the community. In settlements with high thermal demand (climate zone C and D), economic potential exists in towns at greater distances of up to 10 km from the thermal source.

The economic potential for district heating increases in all cases where the population increases and the distance from the thermal source decreases. In any case, where the benefit-to-cost ratio is higher than one, the maximum rate of financial aid needed for the implementation of investments in district heating networks is 80%.


Therefore, it is highly necessary to accurately identify the points where waste heat is available, in order to ensure that this is utilised more effectively.

As a result, the extension of existing district heating networks at first, and the construction, subsequently, of new networks first in areas with high thermal demand are a priority.

The analysis of Scenario 2 demonstrated that economic potential exists only for thermal energy generation from biomass-lignite co-firing and sale thereof to final consumers via district heating networks in large urban centres (>100 000 residents) and at a very short distance of installation from the urban centre.


The cost-benefit analysis demonstrated that the benefits from the generation and sale of heat by use of these technologies are high at a community level. Areas with low thermal demand either due to climate zone or due to the small number of residents in the settlement and long distance from the heat-generating source are excepted from the above conclusion.



With regard to the comparison of sub-scenarios 6.2.1 and 6.2.2, co-firing is preferable to combined heat generation from biomass and natural gas-fired boilers, since the benefit-to-cost ratio is higher than one for longer distances and lower thermal demand (smaller settlements) per climate zone.

In addition, for a given population, climate zone and distance from the heat-generating source, the amount of the funding gap that needs to be covered for the investments to be economically viable is lower in case of co-firing than in the relevant case of combined heat generation from oil and biomass-fired boilers.

With regard to the penetration of HECHP technologies, the analysis of Scenario 3 demonstrated high economic potential for co-generation in cases where technical potential is available.

For small settlements and cooler climate zones where there is no technical potential for the combined cycle gas turbine with heat recovery (the installed capacity of combined cycle gas turbine with heat recovery systems ranging from 4 to 300 MWe), internal combustion engines are the prevailing technology, since there is economic potential for heat generation even for very small settlements (with no less than 230 residents in climate zone D), at short distances from the heat-generating plant (1 km).


In any case, efficient heating is economically viable in towns at distances from the heat-generating point ranging from 15 km (climate zone A) to 30 km (climate zone D).

In addition, support will be provided for installation of micro co-generation and medium-scale co-generation plants, especially in urban areas where interconnection with the natural gas network is possible, so that applications for the simultaneous generation of heat and electricity from individual buildings, small enterprises and communities are developed for covering their needs.

In addition, the penetration of NG-fired HECHP technologies must be promoted at the level of individual installation, since the comprehensive assessment reveals very important benefits for the community.

Extending the natural gas network and utilising the available biomass are basic conditions for the higher penetration of efficient technologies.

The promotion of HECHP plants will be achieved via the new RES support scheme and relates to the feed-in-premium system. Currently, the new RES support scheme is under development and relates to the feed-in-premium system. The new scheme is aimed at radically reforming the support system for RES and HECHP plants with a view to achieving their gradual integration and participation in the electricity market. The system is reformed with a view to placing the minimum possible burden on the final consumer as a result of the ETMEAR charge, and aiming to achieve the best outcome for the community in terms of cost and benefit.

Please note that the extension of existing and the construction of new efficient district heating infrastructure may be combined with the further penetration of biomass, since the benefits arising for the community render this fuel highly attractive.

The analysis of Scenario 4 demonstrated that heat pumps are not a competitive technology for the generation of energy-efficient heat on the basis of the applicable electricity tariffs and investment costs.


Lastly, according to the results of the cost-benefit analysis, energy-efficient district cooling is not proven to be socially efficient and the envisaged policies should not include the district cooling infrastructures as a first stage. Nevertheless, their contribution in terms of cost and benefit will be reassessed at a subsequent phase.

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COMPREHENSIVE ASSESSMENT OF THE POTENTIAL FOR IMPLEMENTATION OF HIGH-EFFICIENCY CO ... · 2016-06-13 · IMPLEMENTATION OF HIGH-EFFICIENCY CO-GENERATION AND EFFICIENT DISTRICT HEATING