Long term prospects of CHP - VGBNTUA - Laboratory of Steam Boilers and Thermal Plants Long term...

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ΕΘΝΙΚΟ ΜΕΤΣΟΒΙΟ ΠΟΛΥΤΕΧΝΕΙΟ ΣΧΟΛΗ ΜΗΧΑΝΟΛΟΓΩΝ ΜΗΧΑΝΙΚΩΝ ΤΟΜΕΑΣ ΘΕΡΜΟΤΗΤΑΣ ΕΡΓΑΣΤΗΡΙΟ ΑΤΜΟΚΙΝΗΤΗΡΩΝ ΚΑΙ ΛΕΒΗΤΩΝ Δρ. Εμμανουήλ ΚΑΚΑΡΑΣ, Καθηγητής ΕΜΠ ΗΡΩΩΝ ΠΟΛΥΤΕΧΝΕΙΟΥ 9, 157 80 ΑΘΗΝΑ NATIONAL TECHNICAL UNIVERSITY OF ATHENS MECHANICAL ENGINEERING SCHOOL THERMAL ENGINEERING SECTION LABORATORY OF STEAM BOILERS AND THERMAL PLANTS Prof. Dr.-Ing. Emmanuel KAKARAS 9, HEROON POLYTECHNIOU, 157 80 ATHENS : +30-210-772-3683/3662 Fax : +30-210- 772-3663 e-mail: [email protected] Long term prospects of CHP Prof. Dr.-Ing. Emmanuel Kakaras, National Technical University of Athens, Greece Assoc. Prof. Dr.-Ing. Sotirios Karellas, National Technical University of Athens,Greece Dipl.-Ing. Aris-Dimitrios Leontaritis, National Technical University of Athens, Greece Dipl. Ing. Konstantinos Braimakis, National Technical University of Athens, Greece Dr.-Ing. Vassilios Vrangos, Universität Duisburg-Essen, Germany Dr.-Ing. Aggelos Doukelis, National Technical University of Athens, Greece November 2016

Transcript of Long term prospects of CHP - VGBNTUA - Laboratory of Steam Boilers and Thermal Plants Long term...

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ΕΘΝΙΚΟ ΜΕΤΣΟΒΙΟ ΠΟΛΥΤΕΧΝΕΙΟ ΣΧΟΛΗ ΜΗΧΑΝΟΛΟΓΩΝ ΜΗΧΑΝΙΚΩΝ

ΤΟΜΕΑΣ ΘΕΡΜΟΤΗΤΑΣ ΕΡΓΑΣΤΗΡΙΟ ΑΤΜΟΚΙΝΗΤΗΡΩΝ ΚΑΙ ΛΕΒΗΤΩΝ

Δρ. Εμμανουήλ ΚΑΚΑΡΑΣ, Καθηγητής ΕΜΠ ΗΡΩΩΝ ΠΟΛΥΤΕΧΝΕΙΟΥ 9, 157 80 ΑΘΗΝΑ

NATIONAL TECHNICAL UNIVERSITY OF ATHENS MECHANICAL ENGINEERING SCHOOL

THERMAL ENGINEERING SECTION LABORATORY OF STEAM BOILERS AND THERMAL PLANTS

Prof. Dr.-Ing. Emmanuel KAKARAS

9, HEROON POLYTECHNIOU, 157 80 ATHENS

: +30-210-772-3683/3662

Fax : +30-210- 772-3663

e-mail: [email protected]

Long term prospects of CHP

Prof. Dr.-Ing. Emmanuel Kakaras, National Technical University of Athens, Greece

Assoc. Prof. Dr.-Ing. Sotirios Karellas, National Technical University of Athens,Greece

Dipl.-Ing. Aris-Dimitrios Leontaritis, National Technical University of Athens, Greece

Dipl. Ing. Konstantinos Braimakis, National Technical University of Athens, Greece

Dr.-Ing. Vassilios Vrangos, Universität Duisburg-Essen, Germany

Dr.-Ing. Aggelos Doukelis, National Technical University of Athens, Greece

November 2016

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Contents

Contents ................................................................................................................................................... i

List of Figures ......................................................................................................................................... iii

List of Tables .......................................................................................................................................... iv

Executive Summary ................................................................................................................................. 1

1 Overview of CHP ............................................................................................................................. 2

1.1 Why CHP? ................................................................................................................................ 2

1.1.1 CHP benefits .................................................................................................................... 4

2 CHP technologies ............................................................................................................................ 5

2.1 Status of commercially available CHP technologies ............................................................... 6

2.1.1 Performance indexes and other technical parameters ................................................ 11

2.1.2 Comparison of further operation characteristics of CHP technologies ........................ 13

2.2 Future developments and R&D priorities ............................................................................. 14

2.3 Techno-economic case studies ............................................................................................. 16

2.3.1 Industrial CHP plants ..................................................................................................... 17

2.3.2 Tri-generation plants ..................................................................................................... 19

3 CHP in the EU: Present Status, Potential and Future Projections ................................................. 20

3.1 Capacity and trends .............................................................................................................. 20

3.1.1 CHP fuel mix .................................................................................................................. 26

3.2 Close up: UK and Germany ................................................................................................... 28

3.2.1 Case study: CHP in the UK (2012) ................................................................................ 28

3.2.2 Case study: CHP in Germany (2014)............................................................................. 29

3.3 Potential of CHP .................................................................................................................... 34

3.3.1 CHP projections in Germany ......................................................................................... 35

4 CHP and RES .................................................................................................................................. 37

4.1 RES growth under EU policy .................................................................................................. 37

4.2 Are RES and CHP compatible? .............................................................................................. 39

4.3 Challenges that increasing RES penetration poses to the grid ............................................. 40

4.3.1 Solar and wind power variability .................................................................................. 40

4.3.2 Impacts to fossil-fuelled generators ............................................................................. 41

4.3.3 Need for flexible generation sources ............................................................................ 42

4.4 Correlation between RES and District Heating-CHP generation ........................................... 44

4.5 The role of flexible CHP plants in grid stability under high RES penetration ........................ 45

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4.5.1 Operation strategy of CHP plants ................................................................................. 45

4.5.2 Flexibility of fossil fuelled power plants and the role of power to heat conversion

strategy 48

4.5.3 Performance of power-to-heat conversion electricity only plants and CHP plants ..... 50

4.5.4 Controlling CHP flexibility through the market ............................................................. 53

5 CHP Policies and Barriers .............................................................................................................. 56

5.1 Overview of Policies and Legislation ..................................................................................... 56

5.2 Cogeneration Observatory and Dissemination Europe ........................................................ 57

5.3 Barriers .................................................................................................................................. 58

5.4 The four main barriers to CHP .............................................................................................. 59

5.4.1 Barrier 1: Inconsistent reward of CHP operators by energy markets ........................... 60

5.4.2 Barrier 2: Barriers for small and distributed generators ............................................... 61

5.4.3 Barrier 3: Regulatory and legislative uncertainty ......................................................... 63

5.4.4 Barrier 4: Lack of focus on primary energy savings and heat markets ......................... 64

5.5 Driving Policies ...................................................................................................................... 66

5.6 Impact of policy frameworks across Member States ........................................................... 67

5.6.1 Expected impact of EED on existing barriers ................................................................ 68

5.6.2 First-step policy recommendations for 2030 CHP Roadmap realization ...................... 69

5.6.3 Overview of implemented CHP support mechanisms by region .................................. 69

5.7 Policy case studies................................................................................................................. 74

5.7.1 Germany ........................................................................................................................ 75

5.7.2 Flanders ......................................................................................................................... 77

5.7.3 Italy ................................................................................................................................ 78

5.7.4 Netherlands ................................................................................................................... 80

6 Policy recommendations and key R&D priorities ......................................................................... 81

6.1 EURELECTRIC Recommendations .......................................................................................... 81

6.2 COGEN - 8 Key Recommendations: “Towards an EU Heating and Cooling Strategy” .......... 84

6.3 Recommendations on key R&D priorities ............................................................................. 85

6.3.1 Technology Needs and Gaps ......................................................................................... 86

7 Summary and Conclusions ............................................................................................................ 87

Nomenclature ....................................................................................................................................... 90

Abbreviations Glossary ..................................................................................................................... 90

List of variables and subscripts ......................................................................................................... 91

REFERENCES .......................................................................................................................................... 93

APPENDIX A - CHP definitions according to the Energy Efficiency Directive (EED) .............................. 95

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ANNEXES I and II of the EED ............................................................................................................ 108

APPENDIX B-Calculation example of Primary Energy Savings of a CHP plant according to the EED

methodology ....................................................................................................................................... 113

Application for the Aluminium of Greece S.A. cogeneration plant ............................................ 113

List of Figures

Figure 1. Ideal energy savings potential of CHP (Data Source: Eurostat) ............................................... 2

Figure 2. Example of energetic benefits of CHP...................................................................................... 3

Figure 3. Capacity scale distribution and characterization of CHP systems ........................................... 3

Figure 4. CHP systems by Prime Mover Technology ............................................................................... 5

Figure 5. Overview of key cost and performance characteristics of the commercially available CHP

technologies .......................................................................................................................................... 10

Figure 6. Overview of performance standards of the commercially available CHP technologies ....... 11

Figure 7. Indicative cost breakdown of a 20 MWe gas turbine cogeneration plant ............................. 14

Figure 8. Fuel cell installations by type in the recent years (Source: EPA [2]) ...................................... 16

Figure 9. CHP energy mix and capacity trends in Europe[6] ................................................................. 20

Figure 10. Major industrial combustion CHP installations (>50MWe) in EU27 - 2012 ......................... 20

Figure 11. Participation of CHP in energy mix by country in Europe (Data Source: Eurostat 2015) .... 21

Figure 12. Installed CHP electricity and heat capacity in Europe......................................................... 21

Figure 13. Produced electricity and heat from CHP systems in Europe (Data Source: Eurostat 2015) 22

Figure 14. Installed power to heat ratio and annually produced electric and thermal energy from CHP

systems in Europe (Data Source: Eurostat 2015) ................................................................................. 22

Figure 15. Share of industrial CHP in industrial electricity consumption ............................................. 23

Figure 16. Development of CHP in Europe 2005-2013 ......................................................................... 24

Figure 17. Industrial CHP share growth in 2000 to 2012 (Data source: Enerdata, 2015) ..................... 24

Figure 18. Industrial heat and electricity demands in EU (2009) .......................................................... 25

Figure 19. CHP fuel mix evolution in the EU (2005-2013) .................................................................... 26

Figure 20. Fuel usage in CHP applications in Europe (2013) ................................................................. 27

Figure 21. CHP fuel mix in Europe by country (2013) ........................................................................... 28

Figure 22. Installed capacity and number of CHP units in the UK (2012) ............................................. 29

Figure 23. CHP-Percentage of Electricity Mix in Germany (Source: Öko-Institut [12]) ........................ 29

Figure 24. CHP electricity generation per sector in Germany (Source: Öko-Institut [12]) ................... 30

Figure 25. CHP thermal energy generation per sector in Germany (Source: Öko-Institut [12]) ......... 30

Figure 26. CHP in Germany –Power to Heat Ratio by technology (Source: Öko-Institut [12]) ............. 31

Figure 27. Percentage of CHP electricity generation by fuel input (Source: Öko-Institut [12]) ........... 32

Figure 28. Percentage of CHP heat generation by fuel input (Source: Öko-Institut [12]) .................... 32

Figure 29. CHP capacity (GWe) by technology and by fuel (Source: Öko-Institut [12]) ....................... 33

Figure 30. CO2-emissions of CHP generation in Germany (Source: Öko-Institut [12]) ......................... 34

Figure 31. The CODE 2 roadmap approach .......................................................................................... 34

Figure 32. CHP projections in Europe by 2030...................................................................................... 35

Figure 33. Growth of RES share in electricity consumption ................................................................. 37

Figure 34. Projected share of RES by sector in energy demand, based on BAU and PR by 2020 ......... 38

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Figure 35. Overview of RES integration in the EU ................................................................................. 38

Figure 36. Overview of RES share across EU Member States ............................................................... 39

Figure 37. Projected reduction of CHP due to penetration of renewable sources and potential of CHP

based on CODE2 Roadmap (Source: CODE 2 [16]) ............................................................................... 39

Figure 38. Wind energy requires additional flexibility from the remaining generators ....................... 41

Figure 39. Correlation between CHP and solar power (Source: Prognos AG [23]) ............................... 44

Figure 40. Correlation between CHP and wind power (Source: Prognos AG [23]) ............................... 44

Figure 41. Flexible of operation of a steam turbine plant by load and power-to-heat ratio variability

(Source J. Karl [24]) ............................................................................................................................... 46

Figure 42. Benefits of CHP plant coupled with heat storage ................................................................ 47

Figure 43. Operation of a typical industrial CHP plant.......................................................................... 48

Figure 44. Flexibility status of fossil fuelled power plants .................................................................... 49

Figure 45. Example of performance comparison between a) an older, less flexible lignite power plant

under a power-to-heat conversion scenario, b) an ultra flexible conventional plant, and c) a CHP plant

.............................................................................................................................................................. 51

Figure 46. Example of extreme market situation due to increased wind and solar power generation-

German Grid – 12-19 August 2014 (Source: CODE-2 [16]) ................................................................... 54

Figure 47. Development of Key EU legislation (Source: Eurelectric [32]) ............................................. 56

Figure 48. Geographical distribution of main CHP barriers across Europe (Source: CODE project[5]) 58

Figure 49. Total gross inland consumption(Source: CODE-2 [28]) ........................................................ 65

Figure 50. Geographic distribution of most common success factors across Europe .......................... 67

List of Tables

Table 1. Summary of the advantages and disadvantages of each prime mover technology ................. 8

Table 2. Technical characteristics of CHP technologies ........................................................................ 13

Table 3. Impact of EED articles on CHP barriers (Source: CODE-2[28]) ................................................ 68

Table 4. Policy case studies: Germany –(Source: CODE 2 – European Policy Report) .......................... 75

Table 5. Policy case studies: Flanders – (Source: CODE 2 – European Policy Report) .......................... 78

Table 6. Policy case studies: Italy – (Source: CODE 2 – European Policy Report) ................................. 79

Table 7. Policy case studies: Netherlands – (Source: CODE 2 – European Policy Report) .................... 80

Table 8 Default power to heat ratio for different types of CHP plants according to the EED directive

............................................................................................................................................................ 109

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Executive Summary

The aim of this study is to present an overview of CHP in the EU in terms of current technological

and commercial status, implemented driving policies, development barriers, and finally its future role

and potential. As CHP growth in the EU has stalled in the last few years regardless of its energy savings

potential, it was deemed necessary to create an informative tool for stakeholders and policymakers

in order to evaluate the prospects of its further development. The main considerations for such a work

include the review of the current legislative framework at an EU and at a national level, the

investigation of potential conflicts with conventional power plants and renewable energy sources and

its role in the modern power generation European landscape. The latter refers to the increased needs

for energy efficiency, emissions mitigation, as well as the rising grid stability issues due to the ever

growing penetration of RES.

In this context, a brief summary of the technical aspects of different CHP technologies is first

presented together with a number of case studies showcasing real examples of CHP applications and

investments. The current status of CHP development in the countries of EU is subsequently discussed

by providing the currently best available statistical data. Notably, a major issue regards the estimation

of the CHP actual potential at an EU level. As it is discussed in this study, due to the strongly localized

character of heat production, the reasonable share of CHP-generated electricity potential is heavily

dependent on the heat market, which determines its limits. However, this field is characterised by

severe scarcity of data in most countries. It is thus very important to investigate the actual, realistic

CHP potential in each Member State.

Moreover, the deployment of CHP under an energy policy landscape characterized by increasing

RES penetration has been examined in terms of technical (e.g. grid stability) and strategic (capacity

compatibility) perspectives. Next, an extensive review of the findings of available studies on the main

policies implemented across the EU to promote the integration of CHP is provided under the prism of

the continuously changing legal and policy CHP framework. Finally, an overview of the policy

recommendations of two major CHP stakeholders (EURELECTRIC, COGEN) has been included

accompanied by a short summary of crucial R&D priorities towards an increased CHP market

penetration.

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1 Overview of CHP

Although cogeneration is a mature technology, these days we are still encountering the very rapid

evolution of the technology and related applications. The main advantage of cogeneration – the high

overall efficiency for the conversion of fuel to heat and electricity – is the reason why it has attracted

interest from the EU industry, which is currently faced with increased challenges to contribute to

global energy and environment goals.

Figure 1. Ideal energy savings potential of CHP (Data Source: Eurostat)

1.1 Why CHP?

Combined heat and power (CHP) is an efficient and clean approach to generating electric power

and useful thermal energy from a single fuel source (Figure 2). CHP places power production at or near

the end-user’s site so that the heat released from power production can be used to meet the user’s

thermal requirements while the power generated meets all or a portion of the site electricity needs.

Applications with considerable demand for electricity and thermal energy are potentially good

economic targets for CHP deployment.

Figure 2 shows the efficiency advantage of CHP compared with conventional central station power

generation and onsite boilers. When considering both thermal and electrical processes together, CHP

typically requires only 80% of the primary energy that separate heat and power systems require. CHP

systems utilize less fuel than separate heat and power (SHP) generation, resulting for the same level

of output, resulting in fewer emissions.

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Figure 2. Example of energetic benefits of CHP

CHP systems can be categorized according to their electrical capacity and grade of produced heat

according to the example shown in Figure 3. Industrial applications particularly in industries with

continuous processing and high steam requirements are very economic and represent a large share

of existing CHP capacity today. Usual fields of application are agrofood (e.g. sugar), brewing, brick -

clay and ceramics, cement, chemicals, paper and textiles.

Figure 3. Capacity scale distribution and characterization of CHP systems

Commercial applications such as hospitals, nursing homes, laundries, and hotels with large hot

water needs as well as institutional applications such as colleges and schools, prisons, and large scale

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residential and recreational facilities are attractive for small scale CHP (<1MW). Micro-CHP on the

other hand is best suited for smaller applications such as households, small residential blocks and

offices.

1.1.1 CHP benefits

The direct benefits of combined heat and power for facility operators are [1], [2], [3]:

Low energy related costs – providing direct cost savings

Contribution to grid reliability

High economic competitiveness due to lower cost of operations

In addition to these direct benefits, the electric industry, electricity customers, and society, in general,

derive benefits from CHP deployment, including:

High energy efficiency – providing useful energy services to facilities with less primary energy

input

Economic development value – allowing businesses to be economically competitive on a

global market thereby maintaining local employment and economic health

Reduction in GHG emissions- high efficiency of energy use allows facilities to achieve the

same levels of output or business activity with lower levels of fossil fuel combustion and

reduced emissions of carbon dioxide.

Contribution to mitigation of emissions of criteria air pollutants (NOx, SO2, CO, PM) -CHP

systems can reduce air emissions of carbon monoxide (CO), nitrogen oxides (NOX), and Sulfur

dioxide (SO2) especially when state-of-the-art CHP equipment replaces outdated and

inefficient boilers at the site.

High reliability and grid support for the utility system and customers as a whole

Fuel security supply

Resource adequacy – reduced need for regional power plant and transmission and

distribution infrastructure construction

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2 CHP technologies

CHP systems consist of a number of individual components – prime mover (heat engine),

generator, heat recovery, and electrical interconnection – configured into an integrated whole. The

type of equipment that drives the overall system (i.e., the prime mover) typically identifies the CHP

system. The purpose of this chapter is to provide a description of the cost and performance of

complete systems powered by prime-mover technologies (Figure 4) consisting of:

(I) Reciprocating internal combustion engines (Recip. ICEs)

(II) Gas turbines and combined cycle plants (GT & CC)

(III) Steam turbines (ST)

(IV) Micro-turbines (μΤ)

(V) ORC and Stirling engines (μ-CHP)

(VI) Fuel cells (FC)

The final selection of the most appropriate technology for a specific application is based on case-

specific parameters such as:

• Scale (based on heat and power demand)

• Fuel availability

• Flexibility requirements (start-up time, part load behaviour)

• Power to heat ratio

• Heat grade

• Maintenance requirements

• Investment costs

• Social, market and policy based issues (electricity/fuel prices, heat market status,

technical/social barriers)

Figure 4. CHP systems by Prime Mover Technology

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2.1 Status of commercially available CHP technologies

All of the technologies described convert the chemical energy content of a fuel into electric power.

The energy in the fuel that is not converted to electricity is released as heat. All of the technologies,

except fuel cells, are a class of technologies known as heat engines. Heat engines combust the fuel to

produce heat, and a portion of that heat is utilized to produce electricity while the remaining heat is

exhausted from the process. Fuel cells convert the energy in the fuel to electricity electrochemically;

however, there are still inefficiencies in the conversion process that produce heat that can be utilized

for CHP. A short introduction of each technology is provided next [2]:

(I)Reciprocating engines make up over half of the CHP systems in place, though, because of the

generally smaller system sizes, less than 5 percent of total capacity. The technology is common place

– used in automobiles, trucks, trains, emergency power systems, portable power systems, farm and

garden equipment. Reciprocating engines can range in size from small hand-held equipment to giant

marine engines standing over 5-stories tall and producing the equivalent power to serve 18,000

homes. The technology has been around for more than 100 years. The maturity and high production

levels make reciprocating engines a low-cost reliable option. Technology improvements over the last

30 years have allowed this technology to keep pace with the higher efficiency and lower emissions

needs of today’s CHP applications. The exhaust heat characteristics of reciprocating engines make

them ideal for producing hot water.

(II)Steam turbine systems represent about one third of installed CHP capacity; however, the

median age of these installations is around 45 years old. Today, steam turbines are mainly used for

systems matched to solid fuel boilers, industrial waste heat, or the waste heat from a gas turbine

(making it a combined cycle.) Steam turbines offer a wide array of designs and complexity to match

the desired application and/or performance specifications ranging from single stage backpressure or

condensing turbines for low power ranges to complex multi-stage turbines for higher power ranges.

Steam turbines for utility service may have several pressure casings and elaborate design features, all

designed to maximize the efficiency of the system. For industrial applications, steam turbines are

generally of simpler single casing design and less complicated for reliability and cost reasons. CHP can

be adapted to both utility and industrial steam turbine designs.

(III)Gas turbines make up half of CHP system capacity. It is the same technology that is used in jet

aircraft and many aero-derivative gas turbines used in stationary applications are versions of the same

engines. Gas turbines can be made in a wide range of sizes from micro-turbines (to be described

separately) to very large frame turbines used for central station power generation. For CHP

applications, their most economic application range is in sizes greater than 5 MW with sizes ranging

into the hundreds of megawatts. The high temperature heat from the turbine exhaust can be used to

produce high pressure steam, making gas turbine CHP systems very attractive for process industries.

(IV) Micro-turbines, as already indicated, are very small gas turbines. They were developed as

stationary and transportation power sources the last 30 years. They were originally based on the truck

turbocharger technology that captures the energy in engine exhaust heat to compress the engine’s

inlet air. Micro-turbines are clean-burning, mechanically simple, and very compact. There were a large

number of competing systems under development throughout the 1990s. Today, following a period

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of market consolidation, commercial systems for CHP use have capacities ranging from 30-250 kW for

single turbine systems to 1,000 kW for multiple turbine packages.

(V) ORC &Stirling Engines. Among the modern technologies used for decentralized heat and

power generation, ORC (Organic Rankine Cycle) plants are commercially available systems that

ensure good conversion efficiencies especially in the electric power range of ≤ 1 MWe. In fact, at small

scales, the classic water Rankine Cycle becomes very inefficient and expensive owing to the high

temperatures and pressures required. It is possible to replace water as the working medium with an

organic compound with a lower boiling point, such as a silicone oil or organic solvent. This allows the

system to work more efficiently at much lower temperatures, pressures and at smaller scale. Small

biomass ORC-CHP plants are now commercially available from a number of manufacturers. Electrical

outputs are typically in the range of 100-160 kWe with thermal to electrical output ratio typically

around 5:1.The Stirling Engine (SE) is an external combustion engine, where the working gas is

alternately compressed in a cold cylinder volume and expanded in a hot cylinder volume. The SE works

with heat from an external heat source (furnaces): hot flue gas from direct combustion of fuel enters

the heater of the Stirling engine at high temperature and heat is transferred into the engine. The

working temperature of the engine heat exchanger is typically between 700 and 800 °C. In the engine,

the heat is converted into work and lower temperature-level heat is rejected in the cooler. This last

can be used as the heater for cogeneration with low temperatures (40-60 °C). Stirling engines are

available commercially with a net electrical output from 35 to about 140 kWe.

(VI) Fuel cells use an electrochemical or battery-like process to convert the chemical energy of

hydrogen into water and electricity. In CHP applications, heat is generally recovered in the form of hot

water or low-pressure steam (<30 psig) and the quality of heat is dependent on the type of fuel cell

and its operating temperature. Fuel cells use hydrogen, which can be obtained from natural gas, coal

gas, methanol, and other hydrocarbon fuels. Fuel cells are characterized by the type of

electrochemical process utilized, and there are several competing types, phosphoric acid (PAFC),

proton exchange membrane (PEMFC), molten carbonate (MCFC), solid oxide (SOFC), and alkaline

(AFC). PAFC systems are commercially available in two sizes, 200 kW and 400 kW, and two MCFC

systems are commercially available, 300 kW and 1200 kW. Fuel cell capital costs remain high due to

low-volume custom production methods, but they remain in demand for CHP applications because of

their low air emissions, low-noise, and generous market subsidies.

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Table 1. Summary of the advantages and disadvantages of each prime mover technology

CHP system

(Capacity range) + - Reciprocating engines (Recip.)

Spark ignition (SI) 1 kW to 5 MW

- High power efficiency with part-load operational flexibility

- Fast start-up.

- Relatively low investment cost

- High maintenance costs

- Lower temperature heat cogeneration - Relatively high emissions

Compression ignition (CI) - dual

fuel 4 – 20 MW

- Has good load following capability - Operation on low-pressure gas

- Cooling required

- Low frequency noise

Gas Turbines (GT) &

Combined Cycle (CC) 500 kW – 400 MW

- High reliability

- Low emissions

- High grade heat available

- No cooling required

- Require high pressure gas or in-house gas compressor

- Poor efficiency at low loading.

- Electrical uutput falls as ambient temperature rises

- Requires a boiler or other steam source

Steam turbine (ST) 150 kW – several

hundred MWs

- Fuel flexibility

- Heat extraction at multiple

temperatures

- Long working life and high reliability

- Variable power to heat ratio

- Slow start up

- Requires a boiler or other steam source

Micro-turbine (μT) 30 kW - 300 kW

up to 1MW with multiple units

- Few moving parts

- Compact size

- Low emissions

- No cooling required

- High costs

- Relatively low mechanical efficiency

- Limited to lower temperature cogeneration applications

- Very low power to heat ratio

Fuel Cells (FC) 5 kW to 2 MW

- Low emissions and noise

- High efficiency over load range

- Modular design

- High costs

- Fuels require processing

- Sensitive to fuel impurities

- Low power density

ORC 1 kW - 3 MW

- Low temperature operation

- Fuel flexibility

- Low maintenance costs

- Modular design

- High investment costs

- Low power to heat ratio - Poor efficiency at low loading

- Dependence on ambient temperature

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Stirling Engine (SE)

1 kW – 1,5 MW

- Few moving parts

- Compact size

- Low emissions

- No cooling required

- High costs

- High temperature operation

- Relatively low mechanical efficiency

- Limited to lower temperature cogeneration applications

Table 1 summarizes the advantages and disadvantages of each prime mover technology while

Figure 5 and Figure 6 provide an overview of the key cost and performance characteristics of CHP

systems which are discussed next:

Electric efficiency varies by technology and by size with larger systems of a given technology

generally more efficient than smaller systems. There is overlap in efficiency ranges among the five

technology classes, but, in general, the highest electric efficiencies are achieved by combined cycle

plants, followed by fuel cells, steam turbines, simple cycle gas turbines, large reciprocating engines,

and then microturbines.

• Overall CHP efficiency is more uniform across technology types. One of the key features of

CHP is that inefficiencies in electricity generation increase the amount of heat that can be utilized

for thermal processes. Therefore, the combined electric and thermal energy efficiency remains in

a range of 80-90%. The overall efficiency is dependent on the quality of the heat delivered. Gas

turbines that deliver high pressure steam for process use have lower overall efficiencies than

microturbines, reciprocating engines, and fuel cells that are assumed, in this comparison, to deliver

hot water.

• Installed capital costs include the equipment (prime mover, heat recovery and cooling

systems, fuel system, controls, electrical, and interconnect) installation, project management,

engineering, and interest during construction for a simple installation with minimal need for site

preparation or additional utilities. The costs are for an average location; high cost areas would cost

more. The lowest unit capital costs are for the established mature technologies (reciprocating

engines, gas turbines, steam turbines) and the highest costs are for the two small capacity, newer

technologies (microturbines and fuel cells.) Also, larger capacity CHP systems within a given

technology class have lower installed costs than smaller capacity systems.

• Non-fuel O&M costs include routine inspections, scheduled overhauls, preventive

maintenance, and operating labour. As with capital costs, there is a strong trend for unit O&M costs

to decline as systems get larger. Among technology classes gas turbines and microturbines have

lower O&M costs than comparably sized reciprocating engines. Fuel cells have shown high O&M

costs in practice, due in large part to the need for periodic replacement of the expensive stack

assembly.

• Start-up times for the five CHP technologies described in this study can vary significantly.

Reciprocating engines have the fastest start-up capability, which allows for timely resumption of

the system following a maintenance procedure. In peaking or emergency power applications,

reciprocating engines can most quickly supply electricity on demand. Microturbines and gas

turbines have a somewhat longer start-up time to “spool-up” the turbine to operating speed. Heat

recovery considerations may constrain start-up times for these systems. Steam turbines, on the

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other hand, require long warm-up periods in order to obtain reliable service and prevent excessive

thermal expansion, stress and wear. Fuel cells also have relatively long start-up times (especially

for those systems using a high temperature electrolyte.). The longer start-up times for steam

turbines and fuel cells make them less attractive for start-stop or load following operation.

• Availability indicates the amount of time a unit can be used for electricity and/or steam

production. Availability generally depends on the operational conditions of the unit.

Measurements of systems in the field have shown that availabilities for gas turbines, steam

turbines, and reciprocating engines are typically 95% and higher. Early fuel cell and microturbine

installations experienced availability problems; however, commercial units put in service today

should also show availabilities over 95%.

As it can be observed from Figure 5, gas turbines, reciprocating engines and also steam turbines

are on the lower end of the CHP installed cost spectrum, with specific costs down to less than 1000

€/kWe. Among these three technologies, steam turbines and reciprocating engines have consistently

higher overall CHP efficiency. Nevertheless, GT systems have a higher potential for maximum

efficiency, which can surpass 90%. Fuel cells and μ-CHP applications are currently comparatively

expensive, with specific investment cost that can exceed 4000-5000 €/kWe, even almost reaching 6000

€/kWe in the case of fuel cells. Currently μ-CHP systems exhibit in principle higher overall efficiencies,

similar to those attained by GT systems. On the other hand, fuel cell technology has yet to accomplish

efficiencies over 90%. In the middle range of the cost and efficiency spectrum, micro turbines are

encountered, with average costs of around 3000 €/kWe but generally low yet consistent efficiency

values in the range from 75% to 80%.

In Figure 6, it can be observed that despite the fact that most CHP technologies have typically

similar performance standards regarding their overall CHP efficiency (around 80 to 90%), the expected

Figure 5. Overview of key cost and performance characteristics of the commercially available CHP technologies

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electric efficiency can differ substantially for each application. Combined cycle plants exhibit the

highest efficiencies (55 %).

They are followed by fuel cells, which are associated with electric efficiencies of around 50%,

steam turbine machines (40%), simple gas turbine units (35%) and reciprocating engines (30%). Micro

turbine and micro-CHP systems, on the other hand, are characterized by lower efficiencies, ranging

from 20 to 30%.

Based on the above remarks, it can be observed that regarding the efficiency of CHP systems the

following statements generally apply:

Large capacity systems have generally higher electrical efficiencies. Thus μ-CHP and micro

turbine applications have the lowest electrical efficiencies.

As a result, the CHP efficiency is quite uniform since it depends mainly on the overall energy

conversion efficiency.

It is therefore to consider additional performance indexes and technical parameters for each

technology such as start-up time, power-to-heat ratio and grade of produced heat to assess its

suitability for a certain application.

2.1.1 Performance indexes and other technical parameters

(a) Power-to-heat ratio

An important concept related to CHP operation is the power-to-heat ratio. The power-to-heat

ratio indicates the proportion of the generated energy (electrical or mechanical energy) to the

generated heat (steam or hot water) produced in the CHP system.

More specifically, according to the Energy Efficiency Directive (EED) [4] (see Appendix A), the

power-to-heat ratio is defined as follows:

Figure 6. Overview of performance standards of the commercially available CHP technologies

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E CHP =H CHP *C

where:

E CHP is the amount of electricity from cogeneration;

C is the power-to-heat ratio;

H CHP is the amount of useful heat from cogeneration (calculated for this purpose as total heat

production minus any heat produced in separate boilers or by live steam extraction from the

steam generator before the turbine).

Because the efficiencies of power generation and steam generation are likely to be considerably

different, the power-to-heat ratio has an important bearing on how the total CHP system efficiency

might compare to that of a separate power-and-heat system.

The power-to-heat ratio is key index for calculating the efficiency of CHP plants.

(b) High-efficiency cogeneration (HECHP)

According to the EED (see Appendix A), HECHP is defined as:

For the purpose of this Directive high-efficiency cogeneration shall fulfil the following criteria:

— cogeneration production from cogeneration units shall provide primary energy savings calculated according to point (c) of at least 10% compared with the references for separate production of heat and electricity,

— production from small-scale and micro-cogeneration units providing primary energy savings may qualify as high- efficiency cogeneration.

(c) Calculation of primary energy savings (PES)

Accordingly, the primary energy savings (PES) are defined by the EED as (see Appendix A):

The amount of primary energy savings provided by cogeneration production defined in accordance

with Annex I shall be calculated on the basis of the following formula:

1PES 1 100%

CHP Hη CHP Εη+

Ref Ηη Ref Εη

(1)

Where:

PES is primary energy savings.

CHP Hη is the heat efficiency of the cogeneration production defined as annual useful heat output

divided by the fuel input used to produce the sum of useful heat output and electricity from

cogeneration.

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Ref Hη is the efficiency reference value for separate heat production.

CHP Eη is the electrical efficiency of the cogeneration production defined as annual electricity from

cogeneration divided by the fuel input used to produce the sum of useful heat output and electricity

from cogeneration. Where a cogeneration unit generates mechanical energy, the annual electricity

from cogeneration may be increased by an additional element representing the amount of

electricity which is equivalent to that of mechanical energy. This additional element does not

create a right to issue guarantees of origin in accordance with Article 14(10).

Ref Eη is the efficiency reference value for separate electricity production

A calculation example of PES according to the EED is given in APPENDIX B

2.1.2 Comparison of further operation characteristics of CHP technologies

Having defined the performance indexes and technical parameters used for CHP plants, an overview

of a further comparison of different CHP technologies is presented in Table 2.

Table 2. Technical characteristics of CHP technologies

CHP

system Recip. GT& CC ST μT

μ-CHP

ORC-Stirl. FC

Power to

Heat ratio 0,5 - 2 0,6 – 1,1 0,07 – 0,57 0,2 – 0,5 0,1 – 0,4 1 - 2

Start-up

time 10 sec

10 min - 1

hr (GT) –

up to 1day

for CC

1 hr - 1 day 60 sec 20 min –

1 hr 3 hrs - 2 days

Uses of

produced

heat

- space

heating

- LP steam

- Hot water

- LP-HP

steam

- HP process steam

- district

heating

- hot water

- space

heating

- hot water

- space

heating

- hot water

- LP-HP steam

As expected, the power to heat ratio (also known as σ), greatly varies from one technology to

another, due to the variation of the electric efficiencies. The power to heat ratio can thus range from

0.07-0.57 (in the case steam turbines) to up to 1.6 (fuel cells). Another considerable operational

difference between CHP technologies involves their start-up time, which, as can be seen, varies from

seconds to some minutes for reciprocating engines as well as micro and gas turbines, to many hours

for steam turbines and fuel cells. This difference is essential when deciding on the applicability of a

CHP technology for a given application, especially in respect to the heat load and electricity demand

time variation. A decisive factor for determining the suitability of CHP systems is the grade of the

produced heat and thus its potential uses. For example, certain CHP technologies produce low

temperature heat and are thus oriented for domestic heating (space heating and hot water

production) purposes. In industrial applications, on the other hand, high pressure and temperature

steam is required.

Regarding the power to heat ratio, the following remarks can be made:

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Separate heat and power (SHP) efficiency strongly affected by power to heat ratio (σ)

Higher electric efficiency ηel (and thus σ) systems exhibit considerable CHP to SHP efficiency

relative improvement.

Naturally, the cost of each technology plays an additionally significant role on its applicability. This

is composed of several components such as:

Prime mover engine/module

Heat recovery and cooling systems

Fuel systems

Controls, electrical costs

Installation

Project management and engineering

Interest during construction

An example to showcase the relative distribution of these cost components is provided for the

case of a 20 MWe gas turbine cogeneration plant in Figure 7.

Figure 7. Indicative cost breakdown of a 20 MWe gas turbine cogeneration plant

2.2 Future developments and R&D priorities

In this section, the most important future developments for each CHP technology are discussed.

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Reciprocating engines

Reciprocating engines are currently viable and competitive with newer immature technologies

(fuel cells and micro-turbines) for distributed generation applications. Furthermore, the installation of

multiple large engines has been proven to be competitive in power generation applications of more

than 200 MW.

Future R&D goals:

efficiency goals of 20 ppm NOx emissions,

50% BTE efficiency,

80+% CHP efficiency,

maintenance costs of 0.009 €/kWh

Gas turbines

Currently, gas turbines are used for the implementation of high efficiency units (>60%). One major

goal is to further reduce their NOX emissions to low levels (<10 ppm), while attaining a reduction of

the levelized cost of electricity (LCOE) by 10%. A notable novel implementation of gas turbines is for

the development of 5 MW solar-driven recuperating units of high efficiency (37.5%).

Current research trends:

Large scale GTs: efficiency increase to 65%, application of low emission technologies and CCU

schemes with IGCC integration

Small scale GTs: improvement in fuel flexibility, emissions, life cycle costs and combination

with efficient thermal utilization technologies

Research advances imminent due to continued development of aero-derivative GTs

Long term goal: hybrid gas-fuel cell turbines capable of 70% electric efficiency

Micro turbines

The first commercial micro turbines entered the market in the 30-75 kW size. Future

developments are oriented towards the construction of units with higher capacities (250-400 kW) with

target electric efficiencies between 35 and 42 (gross output, LHV) and CHP efficiencies of 85%.

Steam turbines

Although steam turbines are considered a more mature technology, a significant amount of

research aims to develop improved ultra-supercritical (USC) steam turbines capable of efficiencies of

55-60% based on boiler tube materials that can withstand pressures of up to 350 bar and

temperatures of 760 oC. Meanwhile, waste heat recovery, biomass, and CHP applications are

stimulating the demand for small and medium steam turbines. Most of the future improvements aim

towards the further increase of turbine efficiency, longevity and the reduction of scaling costs for small

capacity units (<500 kW).

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Fuel cells

Research on fuel cells is carried out to achieve further decrease in capital costs and commercial

diffusion, with the addition of waste heat recuperators for the implementation of high temperature

fuel cell systems. Additional targets include the development of a favourable outlook in regard to the

socio-economic environment, with low domestic natural gas prices, the adoption of new business

models, research advances in distributed energy systems to increase their reliability and resiliency

profiles.

It is also worth noting that large scale stationary FCs have been already developed in Korea and

Japan, with residential, micro-CHP fuel cells, largely popular in Japan, currently migrating to Europe.

This trend is depicted in Figure 8.

Figure 8. Fuel cell installations by type in the recent years (Source: EPA [2])

2.3 Techno-economic case studies

In this section, a series of techno-economic case studies for different CHP systems across Europe

are presented [5]. The aim is to provide examples of actual CHP applications with technical operation

data, such as application type, fuel used, power and heat capacities, properties and uses of generated

heat and costs.

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2.3.1 Industrial CHP plants

Data MVR

Rugenberger

Damm, Germany

Aluminium of

Greece

UPM Kymi

Recovery Island,

Finland

UIPSA

Cogeneration

Plant, Spain

Electrical capacity 29 MWe 334 MWe 110 MWe 33 MWe

Heat capacity 70 MWth 145 MWth 630 t/h 52.6 t/h

Technology Steam turbine Combined Cycle Recovery island

with a steam

turbine

Combined cycle

No. of units 1 2 GTs, 2 HRSGs, 1

ST

1 1

Manufacturer AE&E METKA SA Metso GE

Type of fuel Municipal solid

waste

Natural Gas, Fuel

Oil

Black liquor Natural gas

Electricity 75 GWh 1200 GWh - 250 GWh

Heat 48 GWh dist.

480 GWh proc.

steam

820 GWh proc.

steam

- 265 GWh

Construction 1999 2008 2006-2008 2008

Investment cost EUR 254 million EUR 200 million EUR 360 million EUR 25 million

SIC (EUR/kWe) 8,760 3,270 760

Financing Own funds, KfW-

Loans

Own Funds,

Investment

subsidy

Own funds, loans Loans

State support KfW-Loans Feed-in tariff None Feed-in tariff

Location Hamburg Aspra Spitia,

Voiotia, Greece

Kuusankoski Barcelona

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Data Psyttalia, sewage

sludge treatment

plant, Greece

BelgomilkLan

gemark,

Belgium

Bailieboro CHP

Plant, Lakeland

Dairies, Ireland

CHP Plant

Siekierki,

Warsaw, Poland

Electrical capacity 12.9 MWe 7.35 MWe 5 MWe 622 MWe

Heat capacity 17.3 MWth 13.8 MWth 18.5 MWth 1.193 MWth

Technology Gas turbine with Dry

Low Emissions

technology WHRG

Gas turbine Gas turbine &

Waste heat

recovery boiler

Steam turbine

No. of units 1 1 1 9

Manufacturer Siemens Ind.

Turbomachinery Ltd.

Turbomach Centrax – Gas

turbine

Wulff – WHRB

Rafako/Siemens/

Alstom/ Zamech

Type of fuel Natural gas Naturalgas,

biogas

Natural gas Coal, biomass

Electricity - 57.3 GWh 30 GWh 2,000 GWh

Heat - 430 TJ 115 GWh 5.82 PJ

Construction 2009 2009 2009 1961,

improvements

between 2001-

2009

Investment cost EUR 9 million EUR 7 million EUR 6.3 million Unknown

SIC (EUR/kWe) 700 950 1,260

Financing European funding Own funds,

loans

Contracting Own funds, loans

State support Investment subsidy Investment

subsidy,

certificates

None Green certificates

Location Psyttalia island, off the

coast of Athens

Langemark, Bailieborough Warsaw

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2.3.2 Tri-generation plants

Data “Hypo Alpe Adria”

Trigeneration Plant, Italy

Museum of Liverpool, UK

Ospedale Policlinico di Milano, Italy

CCHP Unit in a hi-tec

greenhouse, Greece

Electrical capacity 1.06 MWe 2.3 MWe 3 MWe 4800 kW

Heat capacity 1.27 MWth 2.4 MWth 2.8 MWth 6000 kW

Technology Motor engine Motor engine Motor engine Internal combustion engine

No. of units 1 4 2 3

Manufacturer Jenbacher 2 x Scania, 2 x MTU

Jenbacher Caterpillar

Type of fuel Natural gas 2 x natural gas, 2 x biodiesel

Natural gas Natural gas

Electricity 2.37 GWh 2.39 GWh 16 GWh 25000 MWh

Heat 2.57 GWh – 13 GWh 32000 MWh

Construction 2006 2010 2010 2007

Investment cost EUR 2.8 million EUR 4.4 million EUR 2 million 20.5 million

Financing Own funds Third party financing, contracting

Contracting EU Community Supporting Funds

State support Certificates, tax reduction

Certificates, tax reduction

Project financing 9 years by ESCO Siram Spa

Feed-in tarrif

Location Tavagnacco Liverpool Milan AGRITEX s.a. Alexandria, Imathia W. Macedonia

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3 CHP in the EU: Present Status, Potential and Future Projections

3.1 Capacity and trends

The participation of CHP in the energy mix of each European country and its development trend

between the years 2000-2014 is depicted in Figure 9.Figure 10 depicts the geographic distribution of

the existing industrial CHP plants in the EU.

Figure 9. CHP energy mix and capacity trends in Europe[6]

Figure 10. Major industrial combustion CHP installations (>50MWe) in EU27 - 2012

(Source: Heat ROADMAP Europe 2050[7])

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A more detailed presentation of the participation of CHP in the energy mix for each country is

presented in Figure 11. It can be observed that CHP exhibits the highest penetration in Denmark

(>50%), Latvia, Lithuania, in the Netherlands and Finland.

Figure 11. Participation of CHP in energy mix by country in Europe (Data Source: Eurostat 2015)

The electricity and heat capacity of installed CHP systems in European countries in absolute values

is illustrated in Figure 12.

Figure 12. Installed CHP electricity and heat capacity in Europe (Source: COGEN Europe [8])

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The installed capacity values are useful for evaluating the integration and market diffusion of CHP

technologies, but they can sometimes be misleading, since they do not provide any information on

the actual energy production of these systems, which greatly depends on their capacity factor.

Additional parameters that need to be taken into account to properly and realistically assess the

integration of CHP include the district heating use in the different countries as well as the potential for

using waste heat. The produced CHP electricity and heat in 2013 is presented in Figure 13.

Figure 13. Produced electricity and heat from CHP systems in Europe (Data Source: Eurostat 2015)

Figure 14. Installed power to heat ratio and annually produced electric and thermal energy from

CHP systems in Europe (Data Source: Eurostat 2015)

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Based on the above diagrams, it is possible to estimate the installed power to heat ratio of CHP

systems, as well as the annually produced electrical to thermal energy ratio in each country. The

results are depicted in Figure 14. It can be observed that the actual power to heat ratio of CHP systems

based on the produced electricity and heat is often lower than the installed, nominal power to heat

ratio. This means that the units prioritize the generation of heat, at the expense of electricity

production.

Figure 15 presents the diffusion of CHP in the industry across European countries.

Figure 15. Share of industrial CHP in industrial electricity consumption

The trend of CHP development in Europe can be seen in Figure 16. Overall, between 2012 and

2013, the cogeneration market stagnated at EU level in terms of both the cumulative capacity and

electrical output. It can be observed that the installed capacity of CHP has been undergoing a very

slow increase, while the amount of cogenerated electricity decreased marginally. The same holds

roughly for the CHP share in electricity production, which is fixed at around 12%. With regard to the

heat part of the CHP market, there was a drop in heat capacity and more substantially in heat output.

The same can be observed for the industrial CHP growth in the countries of Europe during the last

years, which is plotted in Figure 17. It is evident that from 2006 to 2012 the increase of CHP share in

the industrial electricity consumption has risen only from 30 to around 34% and is thus stagnating.

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Figure 16. Development of CHP in Europe 2005-2013 (Source: COGEN Europe [8]

Figure 17. Industrial CHP share growth in 2000 to 2012 (Data source: Enerdata, 2015)

10

15

20

25

30

35

40

45

50

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

% C

HP

sh

are

Share of industrial CHP in industrial electricity consumption EU - 2012

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A more detailed outline of the industrial annual energy demand in Europe is given in Figure 18.

Figure 18. Industrial heat and electricity demands in EU (2009) (Source: Ecoheatcool [9])

The heat and electricity needs of the EU industrial sector are analyzed next [10], [11]:

Iron and steel industry: the energy consumption of the iron and steel sector amounts to 16% of

total energy consumption (around 690 TWh of final energy). Almost 95% of heat demand is in the

high-temperature range, i.e. > 400°C.

Non-ferrous metal industry: the electricity demand of this sector totally accounts 6.5% of

electricity consumption in industry and represents more than 50% of total energy needed in this

sector. Almost 90% of heat demand is in the high-temperature range, i.e. > 400°C.

Non-metallic mineral products industry: the energy consumption of the non- metallic mineral

products in the EU was around 485 TWh of final energy, with the cement sector as the major consumer

(320 TWh) [75]. This amount represents 11% of total industrial energy consumption. High-grade heat

(> 400°C) represents 88% of the total heat demand.

Pulp and paper industry: total primary energy consumption for the paper and pulp industry was

370 TWh in 2013 in the EU. (Ecoheatcool and Euroheat & Power 2005-2006, 2005). The

electricity/steam consumption ratio at paper mills enables an efficient use of cogeneration of heat

and power (CHP) and therefore, modern paper mills have their own CHP unit. On the overall European

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paper market, 96.4% of total electricity required was produced through CHP in 2013, with biomass as

prevalent fuel with a share exceeding 50%.

3.1.1 CHP fuel mix

The evolution of the use of various fuel types in CHP in EU is depicted in Figure 19, accounting for

the period between 2005 and 2013. It can be observed that there has been a considerable decrease

in the utilization of solid fuels as well as of natural gas, mainly in favour of renewable sources and at

a lesser extent of other fuels. In 2013, although the majority of CHP plants are based on natural gas,

the solid fuels have been almost matched by renewables. This is also apparent from the diagrams

included in Figure 20.

Figure 19. CHP fuel mix evolution in the EU (2005-2013) (Source: COGEN Europe [8])

When looking at the electricity production split by fuels as well as CHP vs. non-CHP (Figure 20), 60%

and 53% of the overall electricity generated from bioenergy and natural gas respectively were

produced in cogeneration plants. The most dynamic year-on-year trend was represented by

renewable CHP growth, as renewable fuels continued to gain ground in the CHP fleet, reaching 18%

of the fuel input in 2013 – up from 16% in 2012

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Figure 20. Fuel usage in CHP applications in Europe (2013) (Source: COGEN Europe [8])

.

Finally, Figure 21 presents the CHP fuel mix by country. It is important to note that the following

countries show a strong dependence on natural gas:

Netherlands

Italy

Spain

UK

Belgium

Germany

Other important remarks on this diagram include the high percentage of renewables in Finland, the

huge share of coal in Poland and the considerable share of coal in Germany.

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Figure 21. CHP fuel mix in Europe by country (2013) (Source: COGEN Europe [8])

3.2 Close up: UK and Germany

A close up on the status of CHP in UK and Germany is presented in this section.

3.2.1 Case study: CHP in the UK (2012)

Regarding the UK, some interesting conclusions can be drawn from Figure 22. From this figure, it

can be observed that:

• There are relatively few high capacity (>10 MWe) in industrial applications (refining, chemicals)

or in large district heating schemes, which account for the largest share of the total installed

capacity, corresponding to 5000 MWe.

• Most CHP installations of low capacity (<10 MWe) are encountered in food or paper sectors

or embedded in still smaller heat demands such as hospitals, university campuses or

greenhouses.

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Figure 22. Installed capacity and number of CHP units in the UK (2012)

(Source: CODE-2 [3])

3.2.2 Case study: CHP in Germany (2014)

Germany is a leader in terms of CHP production, which accounts for 21% of the total cogenerated

electricity in the EU. However, CHP growth has been low in the recent years as shown in Figure 23,

Figure 24 and Figure 25. Specifically, Figure 24shows the electricity generated by CHP plants from 2003

to 2014. Within this period the amount of electricity continuously increased from 77.5 TWh in 2003

to 97.1TWh in 2010, which corresponds to 13.8% and 16.2% respectively of the electricity mix in

Germany in the same year. Since then it has practically remained at the same levels and in 2014, the

generated net electricity amounts to 97.6TWh which corresponds 16.8% respectively of the electricity

mix in Germany in the same year. Similar tendency is recorded for the generated thermal energy

(Figure 25).

Figure 23. CHP-Percentage of Electricity Mix in Germany (Source: Öko-Institut [12])

10

11

12

13

14

15

16

17

18

2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014

CHP-Percentage of Electricity Mix in Germany%

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Figure 24. CHP electricity generation per sector in Germany (Source: Öko-Institut [12])

Figure 25. CHP thermal energy generation per sector in Germany (Source: Öko-Institut [12]) In Figure 24 and Figure 25, both the total amount of electricity and the thermal energy have

divided into 3 main categories [12]:

District Heating (DH) supply: Plants operated by district heating suppliers

50,3 52,4 52,3 54 51,9 53,850,5 53,4 51,1 51,1 49,7

44,9

23,5 22,9 25,6 25,8 25,8 25,7 26,629,8 28,4 28,3 28,9 29,7

3,7 4,6 5,3 7,1 8,8 9,7 12,1 13,9 14,7 15,721 23

77,5 79,983,2

86,9 86,5 89,2 89,2

97,1 94,2 95,199,6 97,6

0

20

40

60

80

100

120

2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014

CHP-Generated Net Electricity in TWh

DH supply industrial other total

94 100 101 103 97 99 95 10193 96 97

8882 77 80 78 80 80 7987 84 84 85 84

7 9 10 12 14 16 18 23 24 25 30 33

183 186 191 193 191 195 192

211201 205

212205

0

50

100

150

200

250

2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014

CHP-Generated Net Thermal Energy in TWh

DH supply industrial other total

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Industrial: Plants for industrial applications

Other: not officially registered Mini- and Micro-CHP on gas motor basis < 1MW and not officially registered Mini-CHP on biogenic fuel basis

It is clearly shown, that within the period from 2010 to 2014 the recorded decrease of CHP

generation in the energy sector, i.e. district heating and electricity supply, has been compensated by

the growth of the Mini- and Micro-CHP on gas and biogenic fuel basis (other). Furthermore the CHP

generation from industry remains more or less unchanged.

Analyzing the Power to Heat Ratio over the above mentioned categorization which is presented in

Figure 26 some interesting conclusions can be drawn. The high values of the power to heat ration of

the category “other indicates that Mini- and Micro-CHP units on gas and biogenic fuel basis work

mainly as electricity priority units and use the heat as a by-product. On the other hand, the industrial

plants work under low power to heat ratio since they are usually designed to cover the heat demand

of various processes and electricity is actually produced as a high grade by-product. Finally, DH supply

is usually delivered by electricity priority thermal plants such as municipal waste incinerators and coal

plants. The relatively lower power to heat ratio can be attributed to the lower thermal efficiency of

this kind of plants.

Figure 26. CHP in Germany –Power to Heat Ratio by technology (Source: Öko-Institut [12])

Furthermore, an insight into the fuels used in CHP applications in Germany is of great interest.

Figure 27 and Figure 28 demonstrate the trend of the percentage of the fuel input for the CHP plants

within the period from 2003 to 2014. Throughout this period more than half of the CHP generated

electricity has been constantly delivered from natural gas (52-54% of electricity production) followed

by coal which has been significantly decreased from over 30% in 2003 to about 18% in 2014. Biomass

plants on the other hand have shown a remarkable growth accounting for about 25% of the CHP

generated electricity when the respective value in 2003 was less than 7%.

0,2

0,3

0,4

0,5

0,6

0,7

0,8

2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014

CHP Power to Heat Ratio

DH supply industrial other total

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Figure 27. Percentage of CHP electricity generation by fuel input (Source: Öko-Institut [12])

Figure 28. Percentage of CHP heat generation by fuel input (Source: Öko-Institut [12])

The distribution of the CHP installed capacity in Germany by technology and fuel is presented in

Figure 29.The CHP Capacity in Germany (2014) amounts approximately 33.4 GW [12].

0

1

2

3

4

5

6

1 2 3 4

Diagrammtitel

other

biomass

gas

oil

coal

0

1

2

3

4

5

6

1 2 3 4

Diagrammtitel

other

biomass

gas

oil

coal

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Figure 29. CHP capacity (GWe) by technology and by fuel (Source: Öko-Institut [12])

Especially regarding the industrial CHP, existing CHP capacity is mainly based on steam and gas

turbines plants. All of them are supplying district heating and electricity in many regions in Germany.

Two new combined cycle power plants have started running in the last 2 years. These are Lausward

Block Fortuna in Düsseldorf and the Thermal Power Station Niehl 3 in Cologne. Generally the base

technology is very well known. Significant innovations were done concerning the flexibility in running

the engines at partial load and in start-ups.

A significant novelty regards the new power plant in Kiel, consisting of 20 Gas Engines each

9.5MWe and 9.5 MWth corresponding to a total of 190 MWe and 190 MWth [13].

The main advantage of a gas fired CHP plants is their high flexibility and their modular

construction, especially when considering residual load as well as the fluctuating demand of district

heating.

3.2.2.1 CO2 emissions

As a technology for the efficient use of energy resources, combined heat and power (CHP) can play

an important role in Germany’s future energy system alongside renewable energies, which are used

in the first instance to ensure achievement of the fixed medium and long-term climate mitigation

targets. The CO2 savings of CHP plants mainly result from gas-fired CHP plants when they replace non-

CHP electricity production that is CO2-intensive. As expected, the more CO2 intensive the non-CHP

electricity production is, the higher the respective CO2 savings are.

The total CO2-emissions of CHP in Germany decreased from 2003 to 2014 by approximately 10%,

while the cogenerated electricity and thermal energy increased by approximately 12% and 26%

respectively, due to the better efficiency of CHP plants and the increasing use of biomass (as seen in

Figure 30). That means that within the period from 2003 to 2014 a reduction of the total CO2-emissions

per kWh of cogenerated electricity and thermal energy together of approximately 22% [12]

15,4

12,4

5,3

CHP-Capacity by Technology

Steam Turbines Gas Turbines Gas Motors + Other

7,4

0,9

19

4,8

1,3

CHP-Capacity by Fuel

Coal Oil Gas Biomass Other

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.

Figure 30. CO2-emissions of CHP generation in Germany (Source: Öko-Institut [12])

3.3 Potential of CHP

Figure 31. The CODE 2 roadmap approach (Data Source: CODE-2[3])

83,8 83,8

82,5

81,6

77,8

79,6

78,5

83,8

79,2

80,1

81

75,9

70

72

74

76

78

80

82

84

86

2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014

CO2-Emissions from CHP equipments [Mt CO2]

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The CODE-2 project roadmaps estimate that in 2030 CHP could generate 20% of the EU’s electricity

highly efficiently on a range of increasingly renewable fuels. 15% of the EU’s heat today comes from

CHP (850 TWh). The CODE 2 project estimates that this heat volume will increase by around 50% to

1,264 TWh in 2030. The CHP Roadmap projections estimate that new and upgraded CHP capacity

beyond 2016 would further reduce total inland energy consumption by 870 TWh and additionally

reduce CO2 emissions by 350 Mt in 2030[3].

Figure 32. CHP projections in Europe by 2030 (Data Source: CODE-2 [3])

3.3.1 CHP projections in Germany

The following statements are based on:

- Öko-Institut Dec. 2015, Aktueller Stand der KWK-Erzeugung [12]

- New CHP law (KWKG 2016)[14]

- PROGNOS Oct. 2014 , Endbericht zum Projekt I C4-42/13[15]

- Own research into energy market development

In order to achieve the goals set by the new CHP-law (KWKG 2016), regarding capacities of 110

TWhe until 2020 and 120 TWhe until 2025, an additional CHP-capacity of 3-4 GWe and 6-7 GWe

respectively should be installed. Crucial factors for increasing the capacity include CO2-saving aspects

and the flexibility (operating reserve) of CHP plants.

Moreover, based on the new CHP-law (KWKG 2016), it is expected that small facilities and plants

with electricity capacities lower than 100 kW will be preferably installed. This is because it is expected

that for normal operating conditions, an acceptable ROI (Return of Investment) of 5-7 years can be

achieved especially in the case of instances of internal power supply (auto-producers). Consequently

a growth of mini and micro-CHP equipments is anticipated.

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The CHP-generation for district heating supply is expected to be more or less constant or to slightly

decrease during the next years. Therefore no more big plants (150-400 MWe) are expected to be built.

On the other hand, the CHP generation potential in the industry is expected to increase for fields of

industries with high demand on process-heat and electricity until 2040. However the rate of growth

within 2030 and 2040 is expected to be lower than within 2020 and 2030.After 2040, no further

growth in CHP is expected. The generation of coal-based electricity and heat is going to be reduced.

Meanwhile, natural gas will become increasingly used (gas engines) and the number of CHP plants

operating with bio-fuels will grow until 2020-2025. Although this technology constitutes a positive

contribution concerning the reduction of CO2-emissions, no further growth of such CHP plants is

expected after 2025-2030 due to difficulties in security of biomass supply.

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4 CHP and RES

As already shown, heat demand takes up a significant share of the EU’s primary energy

consumption. At the same time, CHP is by far the most efficient way of power and heat generation. If

we consider the production of heat as the primary product of CHP plants, then the produced electricity

is a high grade by-product. Usually, the added energetic and environmental benefit of CHP power

generation is generally acknowledged by supportive subsidizing schemes. A counter argument is that

the heat demand could be in theory entirely covered by electricity-to-heat technologies based

exclusively on RES. However, as it will be shown next, such a high penetration of RES has a number of

practical obstacles, related to grid stability issues and the feasibility of ancillary services. Meanwhile,

CHP is inherently flexible, allowing the stabilization and effective control of the grid supply/demand

power balance. For this reason, fossil fuelled CHP is expected to play an increasingly significant role in

the future energy mix of the EU.

4.1 RES growth under EU policy

Increasing the RES penetration in the electricity generation is an already established EU strategy

priority. As it can be seen in Figure 33, the share of renewable energy sources into the consumption

of electricity in Germany has increased from less than 10% in 2000 to more than 25% as of 2013, with

prospects of reaching 50% in 2030.

Figure 33. Growth of RES share in electricity consumption (Source: CODE 2[16])

In Figure 34, the projected share of RES by origin on the energy demand in EU is depicted based

on business as usual (BAU) and on policy recommendations (PR) scenarios by 2020. It can be seen that

even considering the standard BAU scenario, the share of renewables in electricity generation is

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expected to exceed 30% by 2020, with prospects of reaching a penetration of 37.2%, if the PR scenario

is taken into account.

Figure 34. Projected share of RES by sector in energy demand, based on BAU and PR by 2020

(Source: TU Wien [17])

These projections are valid despite the fact that, as can be seen in Figure 35, most of the member

states are not well on track to achieve the EU set targets, assuming the BAU scenario.

Figure 35. Overview of RES integration in the EU

(Source: TU Wien [17])

A quantitative overview of the status of RES share in energy demand across EU member states is

given in Figure 36.

The result of the EU focus on RES integration is a growing share of fluctuating wind and solar

power in the electricity system, which is changing the generation requirements. The need of ancillary

services is proportionally increasing, putting pressure on the operation of existing conventional power

plants. Moreover, it is evident that the target of 100% RES penetration in electricity production is

incompatible with CHP powered by fossil fuels. Thus, it is important to highlight in which ways the

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development of CHP can fit into the rapidly transforming electricity, heating and cooling generation

and energy distribution landscape in the EU.

Figure 36. Overview of RES share across EU Member States

(Source: TU Wien [17])

4.2 Are RES and CHP compatible?

In Figure 37, the projected reduction of CHP compatible power generation considering the

increasing penetration of RES from present day to 2050 is plotted.

Figure 37. Projected reduction of CHP due to penetration of renewable sources and potential of

CHP based on CODE2 Roadmap (Source: CODE 2 [16])

It is evident that the penetration of renewables (mainly wind) is expected to lead to a significant decrease of CHP compatible power generation by 2050. As a result, it can be seen that the current CHP potential, by market and socio-economic standards, is roughly equal to the CHP compatible

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generation of 2050. However, at the time being, RES and CHP are compatible, since the technologies are not, within this time range antagonistic, but can be complementary.

4.3 Challenges that increasing RES penetration poses to the grid

While power systems have been designed to handle the variable nature of grid demand, the

additional supply-side variability and uncertainty can pose new challenges for utilities and system

operators.

4.3.1 Solar and wind power variability

Much of the variation in solar energy output during the course of the day and the year is highly

predictable, because the movement of the sun is very well understood. An additional, less-predictable

source of variability, however, is due to the presence of clouds that can pass over solar power plants

and limit generation for short periods of time. Cloud cover can result in very rapid changes in the

output of individual PV systems, but the cumulative impact on the electric grid is minimized when

solar projects are spread out geographically, so that they are not affected by clouds at the same time.

In this way, the variability from a large number of systems is smoothed out. For large photovoltaic

(PV) plants, cloud cover typically affects only a portion of the project at a given time while the clouds

travel through the system [18].

Furthermore, in contrast to wind, solar generation is often more coincident with load. However,

in regions with evening load peaks, loss of solar generation at sunset can exacerbate ramping needs

to meet the evening demand. Extreme event analysis in the US [19], which examined renewable

energy penetration of up to 33%, showed that sunrise and sunset events dominate ramping needs.

These events can be anticipated, however, because we know when the sun will rise and set each day.

As it is possible to plan for this aspect of solar power variability, increased operating reserve levels

need to focus only on the unpredictable cloud variability, which is reduced by aggregation of

geographically diverse solar power plants (as well as aggregation with wind and load variability). As a

result, operating reserves were lower for the high solar scenario (25% solar) than the high wind

scenario (25% wind) [19].

Solar power that is connected to the distribution system has similar impacts as that connected to

the bulk power system; however, there are differences. Transmission-level solar power plants provide

real-time generation data to power system operators; whereas distributed solar power plants do not.

That makes it difficult for a system operator to know whether an increase in net load is because of

increasing demand or decreasing solar generation. Another difference is the way the solar generation

reacts to faults or voltage excursions. Transmission-level solar power can be designed to maintain

synchronization during faults of limited duration. However, current standards require distribution-

level solar to quickly disconnect during these events. The result is that it may be more difficult to avoid

or recover from some system disturbances.

Compared to solar, wind energy is less predictable, but still subject to daily and seasonal weather

patterns. Often wind energy is more available in the winter or at night time, when the wind blows

stronger. This can pose challenges in some instances, if the output corresponds to lower load levels.

A key difference in the variability of wind and solar power is that changes in wind generation typically

occur more slowly, with large changes occurring during the course of hours as storm fronts move

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across a wind power plant. This is in contrast to the fast, second-to-second changes in solar power

output that result from cloud cover.

An example of the high variability of wind power and the instability it can introduce to power

generation is given through Figure 38.The uncertainty and variability of wind and solar generation can

pose challenges for grid operators. Variability in generation sources can require additional actions to

balance the system. Greater flexibility in the system may be needed to accommodate supply-side

variability and the relationship to generation levels and loads. Sometimes wind generation will

increase as load increases, but in cases in which renewable generation increases when load levels fall

(or vice versa), additional actions to balance the system are needed. System operators need to ensure

that they have sufficient resources to accommodate significant up or down ramps in wind

generation to maintain system balance. Another challenge occurs when wind or solar generation is

available during low load levels; in some cases, conventional generators may need to turn down to

their minimum generation levels. Utilizing all of the wind energy would require conventional

generators to meet the net load, which is defined as the demand minus the wind energy. The graph

shows the load and net load for a sample week. There are periods when the net load changes, or

ramps, more quickly than the load alone. Also, the remaining generators must be operated at a low

output level (sometimes called “turndown”) at night when there is a lot of wind power [18].

Figure 38. Wind energy requires additional flexibility from the remaining generators (Source: NREL [18])

4.3.2 Impacts to fossil-fuelled generators

The presence of additional wind and solar power on electric grids can cause coal or natural gas–

fired plants to turn on and off more often or to modify their output levels more frequently to

accommodate changes in variable generation. This type of cycling of fossil-fuelled generators can

result in an increase in wear-and-tear on the units and a decrease in efficiency, particularly from

thermal stresses on equipment because of changes in power output. Costs of cycling vary by type of

generator. Generally, coal-fired thermal units have the highest cycling costs, although combined-cycle

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units and many combustion turbines, unless specifically designed to provide flexibility, can have

significant costs as well. Hydropower turbines, internal combustion engines, and specially designed

combustion turbines have the lowest cycling costs.

For coal plants in particular, the impacts can include increased damage to a boiler as a result of

thermal stresses, decreased efficiency from running a plant at part load, increased fuel use from more

starts, and difficulties in maintaining steam chemistry and NOX control equipment [20]. Start-up costs

are also influenced by how cold a unit is when it is being started. For example, hot starts (i.e., restarting

a unit within 12 hours while a boiler and turbine are still relatively hot) have fewer impacts than cold

starts (i.e., when a unit has been idle for three days and has cooled).. Costs are specific to individual

units, however, and can vary by vintage, design, operating history, maintenance history, and operating

practice.

A study by Xcel Energy for the US system found that for a 30-year-old 500-MW coal plant, costs

ranged from $153,000 to $201,000 per cold start, whereas hot starts costs ranged from $82,000 to

$110,000 [20],[21]. The impacts on fossil-fuelled generation from high penetrations of wind and solar

power (33% of generation) in the Western Interconnection of the United States were examined in

detail by the WWSIS-2 study [19]. It utilized cost data from hundreds of coal and natural gas plants

regarding hot, warm, and cold starts, running at minimum generation levels, and ramping. These costs

were used in a production cost model to optimize commitment and dispatch decisions. The study

found that high penetrations of wind and solar power lead to cycling costs of $0.47/MWh to

$1.28/MWh per fossil-fuelled generator, on average. High penetrations of wind- and solar-induced

cycling costs $35 million/year to $157 million/year across the West, while displacing fuel costs saved

approximately $7 billion [19].

Cycling can also impact emissions from fossil-fuelled generators because plants are run at part

loads, ramped, and started more frequently. Although wind and solar power displace substantial

emissions by reducing fossil-fuel use for electricity generation, how much the avoided emissions are

eroded as a result of cycling of fossil-fuelled plant operations has been questioned. Cycling of plants

can lead to increases or decreases in emissions of CO2, NOX, and SO2from fossil-fuelled generators,

depending on the plant type and wind/solar power mix. The WWSIS-2 study found that cycling had a

negligible impact on expected CO2emission reductions, improved NOX emission reductions by

approximately 1% to 2%, and worsened SO2 emissions by approximately 2% to 5%. In the high wind

and solar penetration scenarios SO2 emissions were reduced by 14% to 24% when cycling was

accounted [19].

4.3.3 Need for flexible generation sources

Flexibility to accommodate wind and solar power can also be achieved through the use of flexible

generating sources. The flexibility of generation sources can be gauged by their ramp rates, output

control range, response accuracy as well as minimum run times and off times, start-up time, cycling

cost, and minimum generation level. Some forms of flexibility are inherent to particular types of

generators, whereas others can be affected by the plant design or the way in which it is operated.

Increasing the flexibility of existing plants can require capital outlays as well as impacts to plant

efficiency and maintenance costs.

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Generally, natural gas combustion turbines, hydropower plants, and internal combustion engines

are among the most flexible generators if not subject to other constraints, whereas unretrofitted older

coal and nuclear base-load units are among the least flexible.

Regarding older conventional steam turbine plants, they have a substantial amount of thermal

inertia in the boiler that limits their ability to ramp up or down quickly. Older coal-fired plants were

designed to operate at relatively constant, high output levels to provide base-load generation. These

older plants have generally been designed to have minimum operating load levels of about 45% to

50% of their rated capacity.

On the other hand, modern coal and gas fired power plants are designed as highly flexible power

generation units and are very well prepared to balance the fluctuating power of RES. For example,

modern lignite-fired power plants are able to ramp up and down their output by average rates of 30

MW/min, which is in the same range as a combined cycle gas turbine plant. What is more, a great

number of older plants have been retrofitted to improve their flexibility, reaching the above

mentioned standards. This is one of the main reasons that despite the greatly increasing penetration

of fluctuating RES into the grid, it has been possible to ensure grid stability.

Combined-cycle natural gas plants are generally able to ramp faster than coal plants, but are not

as nimble as combustion turbines. Many older combined-cycle units were often designed to optimize

efficiency, not for flexibility, but newer units generally have increased flexibility and minimum

operating load levels of about 35% of their rated capacity. In general, the flexibility of natural gas–

fired thermal units is constrained by time needed to warm up and for the heat-recovery steam

generator to meet required conditions, as well as limits on pressure and temperature [20],[22]. Utility

scale internal combustion engine driven generators are now often designed for very quick start (one

minute to synchronization and five minutes to full load) with zero cycling cost.

Flexibility in the generation fleet can be achieved through modifications to existing units or

through the addition of new flexible units. Some existing generators can be modified to increase

flexibility by increasing ramp rates, lowering minimum generation levels, speeding up start-up, or

lowering wear-and-tear costs to enable them to better perform load following. Wear-and-tear costs

can be reduced through preventative or corrective maintenance, changing operating procedures, and

upgrading equipment [20].

Relatively new types of generators have been developed that have relatively flat efficiency curves,

can start and stop quickly and at very low cost, and can ramp quickly. Some of these units are aero-

derivative gas turbines, which utilize jet aircraft engine technology. Other types of flexible generators

are reciprocating engines, which consist of multiple small generators connected in parallel. Although

each engine, which often runs on natural gas, can cycle relatively efficiency, the existence of multiple

engines provides a scalable ramping capability—e.g., if one unit can ramp from 0% to 100% of output

in 5 minutes, then the entire plant can match this performance because the plant is made up of

multiple generators [18].

Obtaining a generation fleet with the needed flexibility attributes is a necessary, but not sufficient,

condition for efficient integration. Markets and operational process must allow the system operator

to access this flexibility. For example, under a paradigm of hourly dispatch and interchange scheduling,

an operator may not have the ability to access the fast ramping capability that may physically exist.

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Recognition of this possibility, and proactive revision of markets or other procedures, will improve

system performance and improve integration in the bulk power system [18].

4.4 Correlation between RES and District Heating-CHP generation

Before investigating the role of flexible CHP plants in a grid highly penetrated by intermittent RES,

it is imperative to study the correlation between RES and District Heating cogeneration (DH-CHP) at

different weather conditions. Interestingly, a cold-warm weather distribution analysis unveils a not so

obvious correlation between them. Industrial CHP plants on the other hand are not affected by

weather conditions and are therefore not included in the following analysis.

In Figure 39 and Figure 40, the correlation between CHP and solar PV as well as between CHP and

wind power is depicted, based on the variation of district heating load.

Figure 39. Correlation between CHP and solar power (Source: Prognos AG [23])

Figure 40. Correlation between CHP and wind power (Source: Prognos AG [23])

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It is important to notice that during cold and very cold time periods, the produced electricity both

from PV and wind turbines is generally low, while naturally the heat demand from district heating

networks is high (>60% of the maximum value). Thus, no conflict between RES and CHP occurs within

these periods, during which CHP plants fully deliver their energy efficiency benefits, operating close

to their full load.

Meanwhile, during warm periods, the heat demand is very low. The power output of PV is almost

normally distributed, and wind power is generally limited to lower than 60% of the maximum value.

Therefore, CHP plants connected to district heating networks operate either at low loads (when RES

generation is high) or at high power-to-heat ratios, when required to contribute to the grid at times

of low RES generation. In other words it is a case of “normal grid operation” where conventional and

CHP plants have to follow load and RES fluctuations to ensure grid stability. However, as already

discussed, if we consider electricity as a by-product of heat generation, the operation of CHP plants is

not affected by RES. Flexibility of CHP plants is in this case is only related to grid ancillary services.

Finally, transition periods, corresponding to medium heat loads, cover almost half of the year and

a similar pattern can be observed. During these periods the power output of PV is generally low (<40%

of the maximum value). Wind power production can be either low/average, but it can also be

substantially high at times (>60%). Accordingly, CHP plants require to operate either at medium loads

(medium RES power generation – CHP plants operation being fully determined by heat demand) or at

low power to heat ratios (high RES power generation – partial CHP and RES conflict), in order to

sufficiently cover the heat demand. In the first case there is no conflict between CHP and RES, while

the latter case can be characterised as “normal grid operation”, and CHP plants need to be ultra-

flexible to continue their operation and offer the necessary grid ancillary services.

Based on the above discussion, it can be concluded that no essential conflict occurs between RES

and CHP.

4.5 The role of flexible CHP plants in grid stability under high RES

penetration

A variety of options are available to address integration challenges. Key considerations in selecting

methods to address the variability and uncertainty of the renewable generation are the cost-

effectiveness of the method and the characteristics of the existing grid system. Grid infrastructure,

operational practices, the generation fleet, and regulatory structure all impact the types of solutions

that are most economic and viable. As already discussed, systems generally need additional flexibility

to be able to accommodate the additional variability of renewables. Flexibility can be achieved

through institutional changes, operational practices, storage, demand-side flexibility, flexible

generators, and other mechanisms. In this section the importance of the role of flexible CHP plants in

grid stability under high RES penetration is discussed and compared with the increasingly promoted

power to heat strategy.

4.5.1 Operation strategy of CHP plants

The combination of district heating (DH CHP) and industrial CHP plants can cover an important

share of the residual electricity demand (demand load minus RES generation) and thus security of

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supply can be ensured without power-only-plants (i.e. without any compromise regarding energy

efficiency) even at increased RES penetration scenarios.

Next, typical operation scenarios of DH CHP and industrial CHP plants are presented, in order to

showcase their capability of variable power generation.

4.5.1.1 District Heating CHP plants

A typical example to present the flexibility of a DH CHP plant is given in Figure 41. Flexible

operation is achieved by varying the power-to-heat ratio of a steam turbine DH CHP. In this plant,

there are no strict limitations on the heating output. This is typical of DH CHP plants, which, contrary

to industrial plants, operate to cover highly variable heating demands. Auxiliary heating equipment is

assumed in this scenario to ensure the reliable covering of heat demand. Alternatively heat storage

equipment is necessary.

The plant includes a high pressure as well as a low pressure detachable turbine. This configuration

enables the operation at very low power-to-hear ratios, down to 0.05, by shutting down the low

pressure part. When the electricity demand is low (for example due to high RES availability), only the

first turbine operates, leading to a reduced power output. In this case, the entire steam mass flow rate

expands at a higher pressure and temperature, thus increasing the heating production available for

heat consumers. In a CHP plant equipped with heat storage, the excess heat could be stored (for

example in a storage tank) and be used at periods of increased heating demand.

Figure 41. Flexible of operation of a steam turbine plant by load and power-to-heat ratio variability

(Source J. Karl [24])

On the other hand, when there is high electricity demand OR low heat demand, both turbines

operate and only a fraction of steam is extracted from the high pressure turbine to cover the heat

demand. Consequently, in this case the power to heat ratio is greatly increased.

The power and heat output of this plant can be additionally controlled by varying the load of the

plant, which can either operate at full or at part load. By the combined adjustment of the plant load

and the power-to-heat ratio, a wide area of operating points, corresponding to different power and

heat outputs, is available, as it is graphically presented on the right section of Figure 41 (green area).

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Figure 42. Benefits of CHP plant coupled with heat storage

(Source: CODE-2 [16])

The DH-CHP electricity can be produced in times with low wind and solar power production and

high electricity prices, regardless of the heat demand, if suitable heat storage systems are coupled to

the CHP plant. This way, the heat produced in cogeneration with electricity can be used later, as heat

demand patterns are generally different from the residual electricity demand pattern. This strategy

has the disadvantage of increased costs for the heat storage systems but has certain economical and

energetic benefits.

Two instances of CHP operation, with and without heat storage are presented in the left and right

sections respectively, of Figure 42. Considering a constant power to heat ratio and full load operation,

in the first case the plant operates at a lower heating output, as the heating demand puts certain

constraints.

4.5.1.2 Industrial CHP plants

Industrial plants on the other hand, are typically way less flexible regarding the heat load and most

of the served industrial processes require quite constant heat flows. Flexible operation, expressed by

the ability of the plant to vary fast the operational power to heat ratio, provides the ability to produce

electricity both at peak loads or low RES generation periods (high market prices) and offer fast ramp-

up/ ramp-down reserve services to the grid (ancillary services). In Figure 43, the operation of a typical

industrial CHP plant under variable electrical load is presented under the following assumptions:

• Constant heat demand (e.g. aluminium or pulp industry)

• 100% reliable cover of heat demand

• High Overall efficiency

• Very flexible operation

• Variable power to heat ratio

• Minimization of fuel consumption for heat-only operation

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Figure 43. Operation of a typical industrial CHP plant

4.5.2 Flexibility of fossil fuelled power plants and the role of power to heat

conversion strategy

High RES penetration poses certain challenges to the EU energy system. With growing shares of

fluctuating power production from wind turbines and solar PV arrays, increasingly flexible production

technologies are needed to cover the residual loads. In Figure 44, an overview of the flexibility

capability of the fossil fuelled generation fleet is presented.

CHP plants are inherently more flexible, due to their combined ability of varying both their load

and the respective power to heat ratio. Nevertheless, this of course involves specific design

requirements, especially regarding their control. Large CHP plants can be categorized into district

heating plants and industrial plants. Industrial CHP plants constitute the bulk of CHP installations in

terms of capacity. On the other hand, district heating is a common practice in large power plants and

most of its potential has mostly already been exploited. In both cases, due to the strongly localized

character of heat production, opportunities for further CHP development are strongly determined by

the existence of industrial heat consumers with reasonable and continuous demand of heat supply,

which can lead to economically attractive investments. In other words, the reasonable share of CHP-

generated electricity is heavily dependent on the heat market, which determines its limits.

However, even though flexible CHP plants are overall more energy efficient than conventional

power plants, they prerequisite quite a large heat demand adjacent to the power plant site which

is not always the case. In this context they rather play a supplementary role and therefore do not

compete with conventional power plants. Consequently, a decisive share of the electricity demand,

which depends on the already installed generation fleet and the status of the heat market in each

European country, has to be covered by electricity-only power plants.

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Figure 44. Flexibility status of fossil fuelled power plants

In order to deal with flexibility issues there are two main operation strategies for electricity only

power plants as shown in Figure 44. The first one is the ultra-flexible design of modern conventional

power plants and the retrofitting of older plants. As already discussed, modern coal and gas fired

power plants are already being designed as highly flexible power generation units and are very well

prepared to balance the fluctuating power of RES. However, flexibility issues remain for old,

unretrofitted electricity-only plants, which are poorly suited to balancing the intermittent power

output of wind farms and large solar photovoltaic arrays. Their upgrade involves the advanced design

of their equipment, in order to operate at variable conditions without significant efficiency penalties.

This should be accompanied by sophisticated control systems, to ensure their stability of operation.

Overall, the above involves high investment costs, while certain performance penalties are inevitable.

However, the current technological status already allows for highly-flexible operation (which is even

more increased for the modern power plants), providing advanced grid stability while the investment

costs have been restrained to viable levels. This strategy has shown remarkable results and has up to

now enabled the successful penetration of quite a large share of fluctuating RES, while ensuring grid

stability at the same time.

The second strategy is the so called power to heat conversion which has been proposed as an

alternative solution to increasing grid stability issues. In this concept, when the electricity generation

is excessive, electric power is converted to heat (e.g. with the installation of electrical boilers at a grid

level) and is absorbed by the respective heat demand or stored for future use in suitable storage

systems. This concept enables highly flexible operation with minor modifications and control

requirements, but has certain efficiency disadvantages. The power-to-heat conversion concept is

thoroughly analysed in the following Section.

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4.5.3 Performance of power-to-heat conversion electricity only plants and CHP

plants

In this section, an example of the operation of a) an older lignite power plant under power-to-

heat conversion scenario, b) an ultra-flexible lignite power plant and c) a CHP power plant is presented

(Figure 45). The aim of this analysis is to compare the performance of these plants, in a low-electricity

residual load scenario, as a result of high RES power generation.

As already discussed, the design and construction of CHP plants is totally dependent on the

existence and grade of on-spot heat demand. As CHP offers great primary energy savings potential,

the goal at an energy efficient European electrical grid is to cover CHP compatible heat demand with

CHP plants.

Naturally, at the current technological status, RES and CHP are not sufficient to cover the whole

load and therefore electricity-only plants are an indispensable part of the generation fleet. Moreover,

their ultra-flexible operation is imperative due to the increased ancillary services demand. In this

context, older conventional power plants are retrofitted to enhance their performance and flexibility

and are finally converted to highly-flexible electricity only plants. This practice has proved successful

so far and has enabled the integration of quite a big share of RES in the EU grid.

As mentioned previously, power-to-heat conversion at grid level can be applied as a strategy in

order to improve the efficiency of the usage of renewable surplus energy. This means that instead of

implementing power-to-fuel technologies (e.g. production of synthetic natural gas via electrolysis and

methanation), which are characterized by low overall efficiencies, the surplus renewable power is

used directly to produce heat, resulting in savings of the corresponding amount of natural gas. At the

same time, the need for ancillary services and hence the requirement for load variation from relatively

inflexible conventional power plants is decreased.

However, under the current legislative framework, RES systems are always prioritized to supply

all the electricity that they produce to the grid (no curtailment of RES power is ensured) at usually

higher prices compared to the rates achieved by conventional electric power producers in the

electricity market. Meanwhile, by implementing the power to heat strategy, what actually changes

compared to the current situation, is that the residual load is managed in a way that does not

require from conventional plants to lower their load beyond their technical minimum limits.

As a result, when power to heat conversion is applied at a grid level, it can be assumed that for

the grid operator this is equivalent with the direct conversion of the electric power of conventional

power plants to heat (Figure 45a). For this reason, in this section, the power-to-heat strategy has

been equivalently considered for an older lignite power plant.

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Figure 45. Example of performance comparison between a) an older, less flexible lignite power

plant under a power-to-heat conversion scenario, b) an ultra flexible conventional plant, and c) a CHP plant

Non flexible conventional power plant with power-to-heat conversion

100 MWPrimary energy

30 MWElectricity

70 MW Rejected heat

10 MW Electricity

Operation at technical minimum (40 % load)

Low electricity operation

25 MW Heat

Electrical efficiency 30 %Overall efficiency 35 %

250 MWPrimary energy

95 MWElectricity

155 MW Rejectedheat

Operation at 100 % load

Electrical efficiency 38 %

400 MWPrimary energy

180 MWElectricity

220 MW Rejectedheat

Operation at 100 %load

Operation at technical minimum (25 % load or lower)

67 MW Rejected heat

Ultra flexible lignite power plant

100 MWPrimary energy

33 MW Electricity

Electrical efficiency 33 %Electrical efficiency 45 %

CHP plant with power-to-heat ratio variation

100 MWPrimary energy

45 MWElectricity

40 MW Heat

15 MW Rejected heat

10 MW Electricity

75 MW Heat

Standard operation Low electricity operation

Overall efficiency 85 %

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The comparison of the performance of a) an older, less flexible lignite power plant under a power-

to-heat conversion scenario, b) an ultra flexible conventional plant, and c) a CHP plant is depicted by

the example given in Figure 45.

All cases refer to a high RES penetration scenario under which the residual electricity demand

drops and, as a result, the power plants have to decrease their power output. The older lignite power

plant has a technical minimum of 40% of its rated power (Figure 45a), while the ultra-flexible power

plant has a technical minimum of 25% of its rated power (Figure 45b). The first plant follows a power-

to-heat conversion strategy in order to cope with the reduced demand for power output. Thus, when

the electricity requirement is below the technical minimum of the plant, a part of the high grade

electricity produced from the primary energy source at an efficiency of 35% is converted to useful

heat, assuming 100% efficiency. This corresponds to an overall conversion efficiency that remains at

35%, which is extremely low for the part corresponding to the fuel to heat conversion. It is noted that

a relatively low electrical efficiency has been assumed due to the efficiency penalties of the plant

operation at its technical minimum.

The ultra-flexible plant, on the other hand, is able to operate at even lower capacities, with an

overall efficiency of 30%, which is relatively high if it is considered that it refers to exclusive electrical

power generation while offering highly rated ancillary services to the grid.

Finally, the CHP plant with variable power-to-heat ratio (as in most cases) can respond to reduced

electricity loads efficiently, even if it is load-inflexible, maintaining high overall conversion efficiencies

at a level of 85%. In addition, modern CHP plants are also load flexible making them an attractive

option (when a respective heat load is present) towards a flexible high-RES-penetrated electrical

grid.

Based on this discussion, it can be concluded that on one hand, ultra flexible electricity-only plants

are an indispensable part of the power generation fleet, with very high efficiency (45%) and ability to

operate under very extensive load variations (down to 25% of the nominal value) with relatively small

efficiency penalties. Meanwhile, since CHP applications are very strongly tied to mostly industrial

applications with high and consistent heat demand, the potential of CHP compatible electricity is

fundamentally restrained. Consequently, electricity-only plants are expected to continue playing a

major role in covering the electricity load within the next years.

CHP is the most efficient way to generate heat, since it is characterized by very high overall

efficiency (around 85%) at ranging capacities, due to the capability of power-to-heat ratio variation.

Therefore, CHP plants (industrial and district heating) are the best option for covering heat demands,

given the existence of an economically rewarding environment. Consequently, when a sufficient heat

demand is present, a CHP solution should always be considered over the application of power-to-heat

technology at a local level.

Currently, due to the current priority given to RES-generated electricity, power-to-heat conversion

essentially concerns fossil fuelled power plants. While practical from a perspective of grid stability,

power-to-heat is substantially inefficient in terms of primary energy consumption, due to the greatly

reduced heat conversion efficiency. Consequently, retrofitting older plants to become ultra flexible is

a more viable option than power-to-heat conversion integration.

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It should be lastly noted that power-to-heat from renewable power as a grid balancing strategy

could only be applied under a different regulatory landscape concerning the promotion of RES

electricity penetration. However, even under this scenario, extensive techno-economic and life cycle

assessment studies need to be carried out in order to specify the limits and the optimal integration

strategies of power-to-heat into RES in order to ensure grid balancing, security of supply,

environmental sustainability and economic viability.

4.5.4 Controlling CHP flexibility through the market

Within the EU there are many distributed CHP plants, but few are used as flexibly and intelligently

as they could be. Most of the European and national CHP initiatives aim to increase electricity

generation from CHP, but lack plans to include CHP into system ancillary services and grid balancing.

As already discussed, balancing power demand and generation is an increasing challenge in countries

with limited potential for (flexible) hydropower and a rising share of fluctuating wind and solar power.

The increasing RES shares will, in the current legislative framework and power plant fleet, increase the

probability of extreme market situations (like negative electricity prices analyzed in the following

section ) as well as threats to stable grid operation.

This urgent need to include CHP into system ancillary services and grid balancing is clearly

reflected in the following articles of the EED [4]:

Article 15.1: Member states shall “ensure that national regulatory authorities provide incentives

for grid operators to make available system services”. Encourage the use of high efficiency sources

such as CHP in the electricity balancing and Ancillary Services markets. This provides a market-

based route to making the economic proposal for CHP more attractive to CHP operators which

would sell both electricity and electricity network services.

Article 18: Member states shall promote the energy services market and access for SMEs to this

market. Energy services companies have an important potential role in enabling the greater

uptake of CHP by including CHP in their offering.

In conclusion, both grid and market instabilities push for modern flexible CHP plants, which can

serve as a very useful tool to both regulate system operational stability as well as to prevent anomalies

(e.g. negative electricity prices) in the electricity market at instances of extremely disproportionate

electricity supply and residual demand. These instances are to be expected more often as long as

intermittent RES share increase.

4.5.4.1 Negative wholesale electricity prices

In certain cases, negative prices occur in wholesale electricity markets. A negative price indicates

that power generators are willing to pay grid operators to buy the generated energy. This is generally

due to a combination of high production from renewable energy sources (RES), which are generally

characterized by very low or zero marginal generation costs (the most notable exception being

biomass), and low demand [26]. At the same time certain types of generators, such as nuclear,

hydroelectric, and wind, cannot or prefer not to reduce output for short periods of time when demand

is insufficient to absorb their output. Sometimes buyers can be induced to take the power when they

are paid to do so.

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Technical and economic factors may drive power plant operators to run generators even when

power supply outstrips demand. For example [27]:

For technical and cost recovery reasons, nuclear plant operators try to continuously operate

at full power.

The operation of hydroelectric units reflects factors outside of power demand, for example,

compliance with environmental regulations such as controlling water flow to maintain fish

populations.

There are maintenance and fuel-cost penalties when operators shut down and start up large

steam turbine (usually fossil-fuelled) plants as demand varies over a day or a week. These

costs may be avoided if the generator sells at a loss to attract a buyer when demand is low.

Moreover, negative prices are more likely to emerge where the power system as a whole is not

flexible enough, and hence it is hard (i.e., costly) for it to adapt to changing conditions, either on the

demand or on the supply side – or both. In these situations, generators may seek to maintain a rather

constant power output by offering to pay wholesale buyers to take their electricity. These situations

are most likely to occur in markets with large amounts of inflexible generation.

Additionally, while the economic crisis and the subsequent reduction in actual and expected

electricity demand is the contingent cause of negative prices, their deep rationale is to be found in the

penetration of RES. On the day-ahead markets, as well as on intra-day markets, most RES bid at very

low or zero prices, reflecting their marginal costs. This means that as the marginal generator is one

with a less costly technology of generation, the market clearing price decreases [26]. Such an example

is given in Figure 46.

Figure 46. Example of extreme market situation due to increased wind and solar power generation- German Grid – 12-19 August 2014 (Source: CODE-2 [16])

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To date, in the European Union negative power prices have been allowed in the countries covered

by the European Power Exchange (EPEX), i.e. France, Germany, Austria, Switzerland, as well as in

Belgium and The Netherlands. Other power exchanges, however, do not allow prices to fall below

zero. This is probably because, when market rules were designed, there was no particular reason to

do otherwise.

According to EPEX, negative electricity prices were introduced for the first time in 2007 on the

German Intraday market, followed by the German/Austrian Day-Ahead Market in 2008. Two years

after, in 2010, the French Day-Ahead and Intraday markets allowed for negative prices as well, while

in Austria and Switzerland the possibility of negative prices on Intraday markets was allowed in 2012

and 2013 respectively [26].

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5 CHP Policies and Barriers

Europe is a centre of excellence for CHP; designing, selling and innovating in CHP and its

applications. As already shown, the CHP development in the EU has stagnated in the last years,

regardless of the great potential for energetic and economic savings. Member states which choose to

encourage the development of CHP will benefit from economic stimulus through this knowledge-

based industry which currently employs more than 100,000 people across Europe [28]. However, for

any Member State wishing to encourage the development of additional CHP, verifying that CHP is

economic in the most attractive applications and then introducing suitably structured supportive

measures and policies, is imperative to success.

The industry itself is adapting to the demands of an electricity grid with high penetration of

intermittent RES, and in this perspective new designs consider participation in ancillary services and

electricity markets and are frequently sized for on-site demand. Moreover, SMEs are encouraged to

consider CHP where their heat demand is appropriate and where the electricity market conditions are

favourable for a good economic return. For industry and district heating, there are more to be done

regarding the policy framework and access to the necessary capital in order to deliver the high energy

savings potential of these sectors.

5.1 Overview of Policies and Legislation

A general overview of the EU policies and legislation, directly or indirectly affecting the evolution

of CHP, is graphically presented in Figure 47. European legislation has had a specific role in

encouraging the wider use of high-efficiency CHP in the European Union since 2004, when the CHP

Directive 2004/08/EC[29]was introduced as a measure for improving security of supply and energy

efficiency. The Directive standardised the methodology for calculating the efficiency of CHP plants,

allowing plants which could demonstrate a 10% minimum primary energy saving, defined as high

efficiency, to be promoted and supported by Member States in applications where barriers to market

or market failures still persist. Subsequently, the 2020 package - a set of binding legislation to ensure

the EU meets its climate and energy targets for the year 2020 – was adopted by EU leaders in 2007

and enacted in legislation in 2009. AT the same time they were also headline targets of the Europe

2020 strategy for smart, sustainable and inclusive growth.

Figure 47. Development of Key EU legislation (Source: Eurelectric [32])

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Additionally, the Renewable Energy Sources Directive 2009/28/EC [30], the Energy Performance

of Buildings Directive (EPBD) – via the “high efficiency alternative systems” concept – and the energy-

related Products Directive (ErPD) 2009/125/EC[31] encourage and clarify the legislative framework for

CHP, while several additional Directives touch upon CHP as a topic

However, in 2012, the Energy Efficiency Directive 2012/27/EC[4] came to supersede the CHP

directive of 2004, introducing more specific measures, particularly via its Articles 14 and 15.The new

policy developments deriving from the European Energy Efficiency Directive (EED -2012/27/EC) are

recognised to have significantly altered the landscape of CHP development in the EU. In order to

achieve the energy savings and CO2 emissions mitigation targets projected for 2030, it is imperative

to strictly implement the EED [32]. The EED aims to promote CHP by requiring member states to assess

every five years the potential of high-efficiency CHP (as defined in the EED – see Appendix A), district

heating, and cooling in their territory. This includes detailed cost-benefit analyses and adoption/

implementation of driving policies that promote investments in high-efficiency CHP systems. The

targets set by the EED include:

EU target on 20% energy savings target by 2020 when compared to the projected

energy use.

EU target on a new energy efficiency target of at least 27% by 2030.

Status-2014: The EU is expected to achieve energy savings of 18%-19% by 2020

Furthermore, the EU’s 2030 Climate and Energy Policy Framework, which builds on the 2020

climate and energy package, was adopted by EU leaders in October 2014. Support for the CHP

principle is a significant part of the broader European energy efficiency agenda and has been explicitly

re-emphasised.

5.2 Cogeneration Observatory and Dissemination Europe

An important share of this chapter is based on the findings of the Cogeneration Observatory and

Dissemination Europe and specifically on CODE and CODE-2 projects.

CODE [33] was an Intelligent Energy Europe (IEE) sponsored project which looked at the

implementation of the CHP Directive in all 27 member states. The project’s first phase assessed how

well the CHP Directive had been implemented in member states and analysed studies of its potential

reported across Europe. The CODE project was the first to show that European member states believe

there is the economic potential to double CHP in Europe by 2020. This means that 22% of Europe’s

delivered electricity would be generated in the CHP mode by 2020. A following phase examined the

economic incentives for CHP available in Europe. The study looked at standard projects and their

financial return in each member state, highlighting the diversity of funding approaches and the

difficulty in designing a support scheme to stimulate the full capacity range of projects.

The CODE 2 project [34] was co-funded by the European Commission through Intelligent Energy

Europe (IEE) and the project partners, building on the experience of the previous CODE project. The

project aimed to provide a better understanding of the key markets and policy interactions around

cogeneration, and to accelerate cogeneration’s penetration into industry (including SMEs) and at the

domestic level. It specifically considered the implementation of the Energy Efficiency Directive

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2012/27/EU (EED) as an opportunity to promote CHP in EU Member States. Between 2012 and 2014

CODE 2 partners carried out an important market consultation with cogeneration experts in 27

European Union Member States to generate proposals to promote CHP. The European Roadmap [3]

and the partnering Policy paper [28] summarise the findings of 27 National CHP roadmaps.

5.3 Barriers

According to the CODE 2 project, four major policy-related barriers to extending CHP in Europe

have been identified [28]:

1. The electricity and heat markets do not consistently reward CHP for its energy savings at the energy system level. There is thus often market failure for the CHP operator.

2. Issues related to grid connection, network charges, permitting and bureaucracy continue for CHP despite legislation to the contrary since 2004. Special barriers to entry persist for distributed generators.

3. Regulatory and legislative uncertainty arising from the significant changes in recent years in both the electricity market and the energy market make CHP investment high-risk.

4. The absence of appropriate consideration of heat in general energy and climate policy hampers CHP, as does the weakening focus on primary energy savings compared to energy end-use consumption in EU energy efficiency policy.

These four main barriers are presented in detail in the next section according to the analysis carried

out within the CODE 2 project [28].

Additional minor barriers that reflect regional obstacles include long bureaucratic procedures,

unmet technological requirements, space limitations, environmental rules and high natural gas prices.

Figure 48. Geographical distribution of main CHP barriers across Europe (Source: CODE project[5])

Some of these region-specific, non-economic barriers are listed below [5] while the distribution of

these barriers along Europe is represented in Figure 48:

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Difficulty to obtain agreement for a connection to the electrical grid (Slovenia, Belgium, Spain,

Italy, Ireland);

High or volatile natural gas prices (Slovenia, Greece, Belgium);

Strict environmental rules have to be followed (Finland, UK, Ireland);

Space limitations (UK, Belgium, Greece);

The high capital cost of district heating infrastructure (UK);

Specific technological requirements demand specific, usually more expensive solutions

(Germany, Belgium);

Finally, additional regulatory barriers often further inhibit the development of CHP and mainly

include [5]:

Lack of recognition of environmental (non-energy) benefits

Exclusion from energy efficiency standards

Utility business model – lack of common incentives between customers and utilities

Environmental permitting barriers

Lack of possibility for CHP participating in capacity and ancillary services markets

Inadequate interconnection requirements that do not favour inclusion of CHP

Long bureaucratic procedures (Greece)

5.4 The four main barriers to CHP

Despite the fact that the EED contains several elements that could assist growth in CHP, a

substantial take-up of CHP across Europe is unlikely to happen without a continued focus from the

EU on improving legislation and particularly on ensuring that CHP is empowered to play a strong

role in the ancillary services and electricity markets.

Gas-fired CHP, which constitutes the majority of Europe’s installed capacity, is currently facing

particular difficulties due to a combination of high gas prices and low electricity wholesale prices.

This comes at a time when reinvestment in installed plants is under consideration and the opportunity

can be taken to reinvest on CHP while modernising plants to meet the new demands of the electricity

market.

While different member states can claim to have largely overcome one or more of these barriers,

all four need to be in the mind of any EU or national-level policymaker interested in an effective

policy structure for CHP. These barriers therefore need to be considered in developing and reviewing

EU-level policy if CHP is to deliver on energy efficiency objectives and strategic goals. A more detailed

discussion on the implemented support mechanisms and each one of the four barriers follows as

presented in the final reports of the CODE 2 project [28].

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5.4.1 Barrier 1: Inconsistent reward of CHP operators by energy markets

The most important factor in the adoption of CHP by a new customer, and hence in triggering its

wider uptake in the economy, is that the CHP must be an attractive economic proposition in the first

place. This means an adequate return on the investment over the lifetime of the plant and a

sufficiently well-defined investment risk. While there are some organisations which for corporate

social responsibility reasons – or sometimes for reasons of energy autonomy – may prioritise a CHP

solution, they will not take on the technology without a sensible business case to do so.

5.4.1.1 Market and awareness actions concerning Barrier 1

The market for CHP is still under-developed. While there are several reasons for this there is no

doubt that awareness must be improved among target groups, through energy agencies and energy

and climate actions in cities and with industry and SMEs. Policy should initiate or encourage and

support appropriate measures. The European Commission which seeks energy system efficiency

benefits through CHP should give more weight to this issue.

In addition to this, the electricity market has changed; especially regarding the penetration of

intermittent renewable electricity sources, which is rapidly increasing. Manufacturers and packagers

of CHP plants are already responding and considering the new design requirements to better fit the

new market demands, and especially regarding the system ancillary services that could be provided

by modern flexible CHP plants. CHP designs will adapt to the new electricity market more confidently

and faster when the shape of that market is clarified. There is thus a significant interaction between

the firmness of policy direction and the design investment decision.

In order to overcome these barriers, several proposals have been discussed. One problem is that

there is no market value for the primary energy savings of CHP at the system level. In existing energy

market structures, savings at the system level remain a “public good” and are not rewarded. Any policy

that aims to stimulate further investments in CHP as part of an energy and climate policy strategy

must develop a policy framework that addresses this issue. The aim must be to make CHP an economic

proposition in a number of its possible applications in order to achieve the desired energy savings and

CO₂ reduction aims both at a member state and at an EU level.

Investment studies [28] based on the internal rate of return (IRR) have also shown that suitable

support mechanisms and an attractive IRR alone are not sufficient to trigger market growth.

Substantial non-financial barriers in terms of market access, permitting, authorisation delay and

barriers to entry exist for new entrants wishing to invest in the cogeneration sector. The best case

practice also highlights the need for consistent long-term policy strategy on CHP and clear

communication and outreach concerning its benefits.

5.4.1.2 Policy suggestions for Barrier 1

Approaches to CHP market support in member states [28] fall into four broad categories: feed-in

tariffs, tax support, market-based certificate schemes, or premium and capital support. Of these,

approaches which lower the operating risk of the CHP, rather than support the capital, are the most

effective for larger plants. For smaller units and certainly in the SME or district heating sectors, access

to capital is an important consideration and should be taken into account.

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The two European Union Member States which have most consistently supported CHP in the last

ten years and which have succeeded in its promotion are Belgium and Germany. The Flemish region

of Belgium (2/3 of the Belgian population), for example, uses a market-based certificate approach

while Germany uses a premium approach on all cogenerated electricity. These systems implicitly

recognise that the energy efficiency of CHP is not rewarded through normal trading on today’s energy

markets. The schemes introduce either market-based or government support-based additional

funding for energy efficiency. These two cases are analyzed in more detail in section 4.6 – Policy Case

Studies.

In addition to this, some more specific policy interventions for improving the existing EED

structure the economic framework around CHP are highlighted:

Article 7: include CHP measures as complying with the energy efficiency obligation (France, Italy and Slovenia are among the member states that currently do so). This represents a market-based solution for CHP support.

Article 14: Comprehensive assessment which fully and proportionately quantifies the system-level benefits of CHP and then introduces measures to address the economic shortfall at the project level. This represents a government regulation or support opportunity within the existing EED structure.

Article 15.1: Member states shall “ensure that national regulatory authorities provide incentives for grid operators to make available system services”. Encourage the use of high efficiency sources such as CHP in the electricity balancing and Ancillary Services markets. This provides a market-based route to making the economic proposal for CHP more attractive to CHP operators which would sell both electricity and electricity network services.

Article 18: Member states shall promote the energy services market and access for SMEs to this market. Energy services companies have an important potential role in enabling the greater uptake of CHP by including CHP in their offering.

5.4.2 Barrier 2: Barriers for small and distributed generators

Non-Economic Barriers to CHP usually relate to the inherently distributed nature of

cogeneration compared to the traditionally large centralized generation providing power to the

electricity network at the Transmission System Operator (TSO) level. Cogeneration by comparison is

embedded with the heat demand which it serves as part of society and the economy and although

the very large plants are connected at the TSO level, the large majority of CHP installations are

connected at the Distribution System Operator (DSO) level (> 80% of the CHP fleet is under 10MWe in

electricity generating capacity).

Initial connection to the electricity grid is subject to local DSO requirements, which have their own

specificities. There are over 300 DSOs in Germany and over 30 in the UK. The information is not

standardized and network tariffs and connection charges vary. Physical connection possibilities and

costs also vary. The network information largely resides with the DSO (a selling and contracting

partner) so the speed and effectiveness of the interaction with a distributed generator has a high

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dependency on the DSO concerned. For larger CHPs connecting at the TSO level, the difficulties follow

a similar pattern.

5.4.2.1 Market and awareness actions concerning Barrier 2

The CHP industry should step up its role in the development and maintenance of new network

codes under the EU’s third energy market liberalization package: providing information and

expertise, and ensuring that the important and changing role of distributed generation is taken into

account in this cross border-focused legislation and that the requirements placed on CHP generators

are proportionate to their size. More challenging is that the CHP industry must also ensure that the

new codes reflect the benefits of distributed CHP as a high efficiency and “dispatchable” generator in

the emerging new low-carbon network.

Industry should take an active role insisting through industry associations and other bodies at the

member-state level on an interpretation of the new EED in Member States which is supportive of both

the letter and the spirit of the Directive regarding connection and operating procedures for HE CHP

on the DSO and TSO networks.

There are several examples of Member States in which the process of network connection has

been systematised with a specified time limit for completing defined stages. In Flanders, the grid

user can demand the completion of the grid connection within a certain period after the payment of

this connection. There are strict response periods to confirm the correct application for a grid

connection and to respond with an offer for the grid connection. However, in many member states

the level of transparency and reliability of these charges and associated processes remains

challenging for CHP operators and the bureaucracy appears disproportionate, particularly for smaller

generators.

5.4.2.2 Policy suggestions for Barrier 2

In order to overcome the network-related challenges of CHP at member-state level through the

implementation of the EED, the following options have been proposed:

Article 15: This article focuses on the energy efficiency of the electricity transmission and distribution networks. It increases the responsibilities of regulators for improving energy efficiency on the networks and lays down specific requirements regarding CHP in general and also micro-CHP.

ANNEX XI: Energy Efficiency criteria for energy network regulation and for electricity network

tariffs.

Wherever possible, standardization of procedures regarding the connection of new

distributed generation to the electricity network.

ANNEX XII: Energy Efficiency Requirements for Transmission System Operators and Distribution System Operators.

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Additional policies for addressing network-related challenges of CHP at a European level are the

following:

The European Regulator should be asked to articulate their approach to improving efficiency on the networks at the European level considering the requirements of the EED.

In finalizing the new European Network Codes, the European Regulator should report how

the compliance of the Codes with the EED has been ensured at the European level.

5.4.3 Barrier 3: Regulatory and legislative uncertainty

Ongoing instability in the electricity sector triggered by large growth of highly intermittent RES

interacting with global energy markets, as well as by the ongoing economic crisis, has introduced high

regulatory and legislative risks, posing a significant barrier for investment in CHP. Moreover in 2014,

the European Commission adopted new rules on public support for projects in the field of

environmental protection and energy (Energy and Environmental State Aid Guidelines).These

changing guidelines added further uncertainties for project developers and investors in several

Member States. These major challenges are occurring within a policy background of sudden changes

of policy at member-state level, and an apparent shifting away from a primary energy focus of EU

energy efficiency policy towards energy savings at the end-user level. Losses in generation,

transformation and distribution are not addressed when focusing on end-user energy savings. This

uncertainty significantly impacts investment costs in a sector where the role of policy support has

already been highlighted.

CHP is impacted by a wide range of policies concerning energy and electricity. Care needs to be

taken that legislative changes designed to bring about specific action in the electricity sector and not

necessarily designed to change the policy conditions for CHP do not in fact impact CHP with

unintended consequences.

5.4.3.1 Market and awareness actions concerning Barrier 3

Industry should be active in providing information to policymakers regarding regulatory and

legislative matters. The more present and active the customer group and the CHP industry sector

remains in policy at all levels, the more likely it is that a stable policy environment can be created for

the sector. In the Czech Republic, for example, the Energy Regulatory Office (ERU) has established a

CHP project team: a team of experts and stakeholders to design a system of support for cogeneration

in the Czech Republic. This is an important example of cooperation of different CHP market actors

with the common goal of developing and maintaining a financially reasonable, sustainable and

predictable CHP support environment.

5.4.3.2 Policy suggestions for Barrier 3

CHP producers are affected alongside all other type of electricity generators as regards the impact

of global fuel prices and other significant changes in the European electricity sector.

Experience shows that when policies clearly define the period of operation and the review

process, they are more successful in moving markets with long investment times. On the other hand,

unclear policies which are continually changing or are short-term, can lead to confusion, insecurity

and inhibit investments.

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Moreover, CHP policy measures at Member State level need to be linked with long term national

targets in the energy sector, in order to create a reassuring investment environment.

However, it should be noted that the success of the German CHP incentive schemes, which are

well structured in extent and duration still could not resist the upsets in the European electricity

market as a whole. Nevertheless, the impact of these negative changes has been to slow rather than

completely halt progress, as investors seem to be taking a longer term view of the current problems,

still keeping the long term national goals and the continued support of government in mind.

For addressing the regulatory and legislative challenges of CHP at Member State level, the

following points are suggested:

Article 3 EED: Increase the transparency of the existing links between CHP and the 2020 and

2030 energy and climate policy frameworks. Member States should link the achievements

under Article 14 and Article 15 directly to the PES target set in Article 3. In monitoring

member-state reporting, the European Commission should reinforce the need for a Primary

Energy Savings (PES) measurement and tracking through National Energy Efficiency Action

Plans (NEEAPs).

EED implementation and NEEAPS: Member states should comply with, and the European

Commission should enforce, the timeframes and deliverables of the EED and other CHP-

related legislation. In framing legislation, member states should consider that it contains clear

timeframes for operation and review, and review processes that allow stakeholders and

investors to adequately make provisions for any agreed changes.

5.4.4 Barrier 4: Lack of focus on primary energy savings and heat markets

The CHP principle delivers Primary Energy savings, i.e. fuel use savings, within the energy

conversion processes of producing heat and electricity. However, only the delivered electrical and

thermal energy is recorded as part of the Gross Inland Consumption (GIC) in European statistics under

Eurostat. The GIC metric (Figure 49) indicates the quantity of energy necessary to cover Europe’s

(inland) consumption. Final energy statistics which record the energy consumption at end-user level

do not show the substantial conversion losses (32%) across the energy system.

Despite the importance of losses in energy conversion and transmission in the EU energy sector,

there is a risk of decreased focus on primary energy savings in EU policy, due to the structure of the

EED, which currently gives more focus on the reduction of end-user energy consumption. This in turn

reflects a risk for investors in CHP, who are uncertain of EU legislators’ ongoing commitment to the

sector. As a result, the lack of focus on electricity network and generation efficiency poses a

significant barrier to the growth of CHP and for the continuation of existing CHP systems.

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Figure 49. Total gross inland consumption(Source: CODE-2 [28])

Another missing element of the policy mix for CHP growth concerns the historic absence of a

real analysis of the heat market in the EU’s energy policy discussions. In 2014, heat entered the

discussions under the banner of security of energy supply. If this was followed through with the

integration of heat into the EU’s energy policy framework, it would be a positive step for the

promoting the efficiency increase of the energy conversion sector and for CHP. 55% of the EU's

primary gross inland energy consumption is used for space and water heating. A significant amount of

this energy corresponds to high temperature industrial processes. However, understanding the

characteristics of this demand, (geographical distribution, heat grade, load curves, capacity) as well as

the potential options for delivering it within the EU’s energy and climate objectives, are still at an early

stage.

Lastly, for both EU policymakers and the industry itself, inconsistent reporting of CHP, heat and

electricity by member states through Eurostat remains a serious concern. In the case of Greece, for

example, the CHP-delivered electricity reported by Eurostat was 2,467,856 MWh (2010), while LAGIE

(the market operator) reported that high efficiency cogenerated electricity was 125.07 MWh (2010).

The origin of this discrepancy is that the LAGIE number only includes High Efficiency CHP (as defined

in Chapter 1), and not cogenerated electricity from non-HECHP units or auto-producers. Consequently,

neither number accurately clarifies the status of high efficiency CHP in Greece. Another important

conclusion can be drawn from this analysis regarding the insufficient recognition of CHP benefits.

LAGIE recognizes only high efficiency CHP units, providing attractive economic incentives (feed-in

tariffs), while the rest of CHP producers are not rewarded for their contribution in reaching the

national energy targets.

5.4.4.1 Market and awareness actions concerning Barrier 4

There is a poor level of awareness among key market groups, including policymakers, of the role

of CHP in the European economy and the variety of its applications. This hinders appropriate policy

development and the omission of CHP from appropriate consideration at the regional and national

level.

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The absence of thinking and planning for heat leaves CHP providers approaching the market case-

by-case and severely challenged in developing proposals that link several heat demands to make one

connected demand or identifying new customers for excess heat capacity. Industry itself should do

more to work with policymakers on understanding the market implications and potentials for heat.

5.4.4.2 Policy suggestions for Barrier 4

Article 3: PES linking to actions directly to actions in Articles 14 and 15

Using Article 14 of the EED, the EU determines characteristics of heat demand across Europe

for all sectors in sufficient detail to allow modelling of supply and demand with attention to

temperature and temporal characteristics.

Study integrated supply options to reveal system integration opportunities, network

integration opportunities and energy efficiency opportunities.

Move towards a more integrated approach to energy planning so that demand rather than

supply is the focus of planning.

Article 24 (6) of the Energy Efficiency Directive states that starting from April 2015 Member

States will have to report data for production, capacity and fuels used for cogeneration and

district heating and cooling. Implementation of this article is fundamental to good member-

state policy around CHP.

The CODE 2 roadmaps [3] stress the need for an ambitious and rigorous implementation of the

EED in order to realize the identified potential. However the reality of member-state implementation

of EU policy is that it is seldom either of these, leaving EU legislators facing the challenge of what to

do next.

5.5 Driving Policies

The main factors (Figure 50) which enabled the successful implementation of different CHP

projects can be divided into policy-related success factors and specific success factors related to

particular issues of certain systems.

The most often mentioned general policy-related success factors are [5]:

investment subsidies and subsidies for demonstration projects (Belgium, Greece, Spain);

a feed-in tariff scheme (Slovenia, UK, Cyprus, Greece);

a green certificates scheme (Belgium, Poland);

third party financing (UK, Greece);

policy favouring the use of RES (Cyprus)

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Figure 50. Geographic distribution of most common success factors across Europe (Source: CODE project [5])

Additional specific success factors are largely case-dependent [5]:

environmentally-friendly-orientated customer organization (Belgium, UK)

good access to the energy infrastructure(Germany)

obligatory feasibility studies (UK)

local availability of follow-up, service and maintenance of the system (Belgium)

5.6 Impact of policy frameworks across Member States

The long-term view of CHP is currently clouded by the ongoing changes in the electricity market

which are affecting all players and creating large market uncertainty. At the point of the introduction

of the EED, the effects of the original CHP Directive 2004 were still young in many member states. The

sector has been under constant change for more than 10 years which has inevitably made investors

cautious.

However in the cases where a member-state government has had clear objectives for the sector,

there has been progress. In Germany, for example, several driving policies foster CHP growth. Among

others, these include the dedicated CHP law and binding target focus on improving energy efficiency

in buildings the strong GHG emission reduction objectives and the commitment to phase out nuclear

energy by 2022. The main CHP support scheme consists of a feed-in premium and EU ETS bonus for

fossil-fuel CHP as well as a feed-in tariff schemed offered to renewable-based CHP. In addition,

micro-CHP units up to 20 kWe benefit from a capital grant ranging between €1425-3325. In 2014, the

German CHP law entered a review process to assess whether additional support is necessary to

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achieve the 25% CHP target [28]. A more detailed discussion of the support schemes is provided in

Section 4.6.

5.6.1 Expected impact of EED on existing barriers

Initial experience after the adaption of the EED shows a potential positive impact of the EED in

addressing and reducing elements of the major barriers. The EED provides a structure to make

progress in terms of heat planning, assessment of CHP potential and the removal of non-economic

barriers which are nonetheless barriers to market growth for CHP. The EED requires Member States

to introduce “adequate measures” to promote CHP where their analysis reveals a socio-economic

benefit at the member-state level.

Table 3. Impact of EED articles on CHP barriers (Source: CODE-2[28])

However the EED has by necessity been written in a way that grants member states considerable

flexibility in the application of Articles 14 and 15 which are most relevant to CHP. Apparently, there is

a considerable gap in awareness and market ‘maturity’ amongst the different Member States, which

represents a considerable awareness, market and policy barrier to the growth CHP. The level of

flexibility in the EED may lead Member States, exactly because of these barriers, to judge CHP growth

has an excessively complicated strategic objective compared to other energy efficiency choices where

the barriers to market delivery are lower with the current legislation (e.g. RES, Energy related Products

- ErP or Energy Performance of Buildings). This is a significant challenge for the CHP industry and EU

legislators alike.

In any case, Member-state policymakers wishing to move CHP forward will find the EED a useful

tool in their hands, but in EU countries that are yet to be persuaded of the potential benefit, this

legislation will definitely not suffice.

The detailed expected impact of specific EED articles on the four main CHP barriers is summarized

in Table 3.

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5.6.2 First-step policy recommendations for 2030 CHP Roadmap realization

The CODE 2 roadmaps [3] show the opportunity that lies within the EED to mobilize member-state

effort towards the removal of the four main CHP barriers. At the same time, it is also suggested that

certain policy links which are present in the EED need to be reinforced by the Directorate General for

Energy (DG Energy) in the monitoring of the EED implementation. If this proves to be insufficient, then

additional efforts regarding the policy framework around CHP will be required if the projected primary

energy savings are to be achieved.

The main actions at a national level are [28]:

Create clear links within the EED reporting to the wider deployment of CHP and the associated primary energy savings (Article 14, 15 results linked to Article 3 target) in NEEAP reporting.

Full enforcement of the national EE indicative target reported in PES, according to Article 3

Encouragement for the inclusion of CHP in the set of measures stemming from Article 7

The monitoring of the NEEAPs by the European Commission should ensure that the Member

States clearly identify that they have met the following EED provisions [28]:

Article 14: Member State CBA (Cost Benefit Analysis) includes a full consideration of the societal benefits of CHP

Article 14: Inclusion of a dedicated micro-CHP analysis in the NEEAP report.

Article 15: That the electricity market, network efficiency and network tariff and access requirements in the Article and the requirements of the Associated Annexes have been fully met

5.6.3 Overview of implemented CHP support mechanisms by region

The following regional analysis for the implemented CHP support mechanisms was conducted

within the CODE-2 project [3] and provides a very useful overview of CHP policies in the EU.

5.6.3.1 Overview of current situation in member states in North-Western Europe CODE 2 Region:

Belgium (pilot), Ireland (pilot), Luxemburg, Netherlands and United Kingdom

Overview

The Netherlands has the largest share of electricity produced by CHP, with 33%. Belgium and

Luxembourg each have a share of 12% and the United Kingdom and Ireland only 6%. In all member

states, the share of CHP is flat or decreasing despite the shortage of electrical capacity in the United

Kingdom and Belgium.

Belgium, the Netherlands and the United Kingdom have a large share of industry where steam is

an important energy carrier, such as oil refineries, chemicals, pulp and paper, and food and beverages.

Within those sectors, where steam is dominant, there is a large potential for CHP. This is less the case

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for Ireland. Luxembourg has a relatively large iron and steel industry, with electric arc furnaces, which

decrease the potential of CHP. District heating is not widespread.

Three of the five member states (Belgium, the Netherlands and Luxembourg) are located within

the CWE electricity market, where the electricity price is mainly determined by the marginal cost of

coal power plants. This results in a low spark spread for CHP. This is also true for the United Kingdom.

On the other hand, in Ireland, more than half of the electricity is produced by gas, which results in a

more interesting spark spread.

The way forward

The major barrier in all member states within this region is the weak business case for CHP. This

is due to a combination of reasons:

High gas prices and low electricity prices (low spark spread)

Low economic value of primary energy savings and/or carbon emissions savings

Investors demand high returns for investments such as CHP which are non-core activities:

Uncertainty in investment climate due to low economic growth.

Uncertainty in the energy markets (as a result of energy market liberalisation).

Most member states (except Belgium) are reducing financial support for fossil CHP due to the negative impact of CHP on emission targets.

Overcapacity in case of the Netherlands.

Opportunities are located in:

Smaller CHP installations (50 kWe – 1 MWe) in applications with a high amount of hot water and electricity like hospitals, homes, leisure centres, etc. These kinds of application typically have higher electricity prices than the energy intensive industry.

Bio-CHP: most member states still provide financial support for renewable energy, including bio-CHP.

5.6.3.2 Regional Summary for the CODE 2 Project Northern Europe Region: Germany (pilot),

Austria, Denmark, Finland, Sweden

Overview

All the countries in the group differ in their approaches to CHP and their energy history.

Germany’s energy history is mainly determined by huge own hard coal and lignite reserves which

have dominated electricity production for a long time and are partly still doing so. Nuclear power has

also been developed, but will be terminated up to 2023. On the other hand electricity from RES has

strongly developed in the last decade. District heating has been developed mainly in major cities and

has a medium share in total heat supply, whilst industrial CHP is relatively well developed.

Austria and Sweden have huge hydropower resources. Sweden has also developed nuclear power

but has recently decided to get out. Finland still relies on nuclear power, but huge wood energy

resources have also been developed. Austria and Denmark have renounced nuclear power. All

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Scandinavian countries have extensive district heating networks but only Denmark and Finland’s have

high CHP shares, whilst Sweden’s CHP share is relatively low.

Austria has a medium CHP share in electricity production. With the exemption of Germany, which

aims to develop its CHP share in total electricity production from 16% currently to 25% up to 2020,

none of the countries in the Northern Region have CHP development plans or even targets.

The way forward

Keeping CHP’s benefits visible in the energy policy agenda at both the EU and MS level is important

if policy action is to result; MS implementation of the CHP measures in the EED is an immediate

opportunity therefore to encourage investments in highly efficient and flexible CHP plants. The EED

provides a policy framework for member states to support CHP systems; strengthen information on

CHP and its opportunities; support know-how building for professionals (planners, consultants,

installers); and encourage CHP implementation by ESCOs.

To achieve the EU’s Third Energy Package and long-term energy and climate policy objectives, the

current lack of price signals for long-term investment in high-efficiency, low-carbon dispatchable

power must be addressed at the EU level through improved electricity market design/operation. The

European Commission consistently supports CHP; however, it has failed with the 2004 Directive to

achieve the targeted efficiency gains through CHP. Should there be similarly poor progress with the

EED, the EU should consider a special communication on CHP to reinforce and improve the EED

provisions. Try and strengthen the ETS, e.g. via minimum CO2 prices, or alternatively CO2 taxation.

5.6.3.3 Regional Summary for the CODE 2 Project Eastern Region: Slovenia (pilot), Poland (pilot),

Czech Republic, Estonia, Hungary, Latvia, Lithuania, Slovakia

Overview

The key regional challenges to the growth of CHP in the Member States of this region include

issues regarding:

How to finance support schemes in the current unfavourable energy market: CHP needs a rather high level of support and as a consequence there is huge pressure on final electricity sales prices from the plants, bringing resistance especially from industrial consumers.

State aid compliance – several ongoing notification procedures within DG Competition are currently increasing uncertainty for CHP support in the future.

Security of natural gas supply – huge dependence on imported natural gas from Russia linked to high prices and uncertain supply require solutions to reduce energy dependence, including completion of plans for electricity and gas network connections.

Future competitiveness and economic operation of district heating systems is a key precondition for the future of the majority of current CHP capacity in the region.

Small-scale CHP is not yet in the policy focus of several Member States in the region.

Lack of investment capital resources especially in industry and SMEs.

Cogeneration is a traditional approach among Eastern Region EU member states, resulting in an

above EU-28 average share of CHP in electricity generation (except Estonia and Slovenia with lower

shares). Except Hungary, all MS have a positive or stable cogeneration development trend as a result

of operational government incentive support schemes. Almost all support schemes are in a

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transitional period, modified in accordance with state aid regulation or due to a lack of financial

resources.

District heating is the major cogeneration sector in all Eastern Region member states. Coal is the

dominant fuel in Poland, Czech Republic, Slovenia and Estonia (oil shale) whereas in other MS natural

gas is used. Presence and future plans on nuclear energy play an important role in the energy

strategies in the Czech Republic, Hungary, Lithuania, Slovakia, and Slovenia. High import dependency

(Lithuania and Latvia) of natural gas from Russia tends towards a future strategic reduction of

natural gas consumption and the development of renewable-based cogeneration. The goals to

increase energy independence and security of energy supply required by national security do not

include further development of natural gas-fuelled CHP in the Baltic region. Small-scale CHP is well-

developed in the Czech Republic, Slovakia and Slovenia, whereas in other MS development is very

limited as support schemes are mainly focused or restricted to district heating CHP plants.

The way forward

Current unfavourable energy market conditions are a key barrier for future CHP development

without there being additional policy support in place. Preserving or establishing stable, predictable

incentive support in accordance with state aid guidelines and member-state energy and climate

objectives is the key challenge in almost all MS in the region.

The lack of member-state financial resources for support schemes is a key barrier and most often

the reason for the reduction even of successful support instruments. A gradual introduction of

additional market incentives for CHP to provide ancillary services to the electricity network and

demand response could improve the current disadvantageous market position of CHP plants,

especially of medium and small-scale CHP units, which are not yet supported in several MS. There is a

clear positive turn toward renewable cogeneration, although at least limited support should be

maintained for efficient recent fossil-fuelled CHP plants, where the integral implementation of new

EU transmission infrastructure for diversification of the natural gas supply is crucial to reducing the

current huge dependency and risks for the supply of natural gas from Russia.

Investment subsidies from EU structural funds for the energy retrofit of existing district heating

systems are potentially a very important instrument used in several MS in the region to increase the

efficiency and competitiveness of district heating compared to other heating alternatives. Similarly,

investment subsidies for switching from fossil fuels (mainly coal; in Baltic countries natural gas too) to

renewables enable faster environmental retrofit of existing old CHP units and sustainable growth of

cogeneration. The future economic operation of district heating systems is crucial for the majority of

the existing CHP capacity in the region.

Lack of investment resources and difficulty accessing affordable funds are serious barriers for

industry and SMEs in the current unstable economic situation. Faster development of ESCO service

offerings and specific financial products for cogeneration could significantly ease this problem in those

MS where the ESCO market is still at an early stage and suitable finance is lacking.

Fast and rigorous implementation of the EED could significantly contribute to:

more consistent local heating planning and the setting of accurate priorities in heat supply based on a comprehensive assessment and cost benefit analysis;

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standardisation and simplification of network connection procedures and standards, especially for small-scale and micro-CHP units, where simplification and reduction of costs is an important factor to increase their competitiveness, and;

faster access for CHP plants to the ancillary services market and demand response and the design of these markets to allow the full participation of non-utility (electricity-only generators) such as CHP.

5.6.3.4 Regional Summary for CODE 2 Project South-West Europe Region: Italy (pilot), France,

Malta, Portugal, Spain

Overview

These member states share broadly similar climate and space heat demands. However, the MS

are diverse in terms of industrial development, energy history, resources and CHP adoption.

Italy and Spain – and to a lesser extent Portugal – have historically strong development of

cogeneration in industrial applications. Italy has maintained the position of CHP in several sectors and

the future of cogeneration is tied to good implementation of the Energy Efficiency Directive and to

ongoing economic demand. CHP in Spain and Portugal has suffered a critical decline since 2008 due

to a combination of economic recession and major adjustments to support measures in the electricity

sector.

France in the last 30 years has chosen to follow nuclear energy. Currently biomass CHP is the single

CHP growth sector.

As an island with a mild climate and specific energy challenges Malta has not yet developed

cogeneration stock for either space heating or industry. However, applications in tourist/ tertiary

segments may exist.

The way forward

The common theme through practically all the member states is that the economic crisis has

increased uncertainty of investments, due to a fall in industrial heat demand. Inadequate policy

responses regarding tariffs, taxation and incentives have rapidly produced a non-profitable position

for operating CHPs on gas. At the same time there is a general overcapacity in the electrical system (in

Italy it exceeds 50%) caused by a reduction in energy demand and by the powerful entry of some

renewable energy sources.

While new regulation of the legal framework, led by the implementation of the EED, is generally

felt by the CHP sector to be a premise to pump new life into the industrial cogeneration sector, other

sectors like micro-/small-scale cogeneration, domestic and tertiary, district heating, and gas or

biomass-fuelled CHP may be able to offer quicker paths to create a shift under the current financial

and electricity market conditions compared to traditional cogeneration applications.

5.6.3.5 Regional Summary for the CODE 2 Project South-East Europe Region: Greece (pilot),

Bulgaria, Cyprus, and Romania.

Overview

In Bulgaria and Romania – two member states with a history of planned economies until 1990 –

CHP developed in connection with district heating systems and for heavy industrial purposes. These

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fell into decline for a period but the CHP sector has been gradually growing, especially in industry. In

Greece, CHP is still in slight decline and the most notable applications can be found in the agricultural

and industrial sectors. In Cyprus, the development of CHP projects started after the transposition of

the CHP Directive (2004/8/EC) with biogas as fuel.

The only partial liberalisation of gas and electricity markets creates further obstacles to further

integration in these countries.

Regarding their respective energy mix, consumption patterns, level of liberalisation and resource

potentials, the region faces three major common energy challenges:

Over-dependence on using oil and coal for electricity generation;

almost total dependence on hydrocarbon fuel imports that are necessary to meet domestic demand, except for Romania, which has a relatively low dependence, and;

sharp increase in RES penetration, especially PV, in the energy and electricity mix of the region, over the past five years, particularly in Greece and Bulgaria, with legal and financial implications for investors.

The way forward

The transposition of the 2004/8/EC Directive for HE CHP gave a boost to the promotion of CHP in

all MS, especially in Cyprus, where it gave an impulse for the first CHP units with biofuel/biogas in the

agricultural sector.

The Energy Efficiency Directive represents an opportunity for MS in the CODE 2 SEE region to

review CHP policies. MS in the SEE region should pay particular attention to thoroughly implementing

the EED requirements of Article 15, and of Article 14 where a “comprehensive assessment of the

potential for the application of high-efficiency cogeneration and efficient district heating and cooling”

and a territory level cost-benefit analysis based on socio-economic and ecologic criteria are required.

The further development of industrial CHP in Romania and to some extent Bulgaria requires more

pronounced economic activity in general plus active policy action to remove key barriers to CHP

growth. Investment in the renovation and upgrade of District Heating is a significant concern. In

Greece and Cyprus, industrial cogeneration can be an asset, but the promotion of CHP should primarily

target the tertiary and agricultural sector, as tourism is a major economic sector. The promotion of

CHP in these sectors should thus aim to increase penetration of tri-generation, allowing CHP units to

operate for more than 7,000 hours annually.

5.7 Policy case studies

In the following section, detailed member-state case studies illustrating successful policy approaches

around CHP are presented according to the CODE-2 project findings [28]. An analysis of the new

German CHP law has also been added.

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5.7.1 Germany

The older KWKG CHP law

The German support mechanism for CHP had already created significant interest from new

potential users and stimulated investment in the sector. Two specific barriers had then been

effectively confronted:

Barrier 1 - Finance: the support mechanism, which is varied across sectors to provide adequate but

appropriate support, promoted CHP to an economic proposition across a wide range of applications.

Barrier 3 - Regulatory risk: While there have been several adjustments to the support scheme, the

German commitment to a CHP target – with suitable terms for support, has served to minimize the

perceived legislative and regulatory risk.

Table 4. Policy case studies: Germany –(Source: CODE 2 – European Policy Report)

Policy/ Measure:

Kraft-Wärme-Kopplungsgesetz (CHP law) 2002-2013

Description: - Bonus payments on CHP net electricity produced in new and modernised plants, amount depending on plant size:

o for up to the first 50 kWe:5.41Cent/kWh o for the exceeding amount up to 250 kWe: 4 Cent/kWh o for the exceeding amount up to 2 MWe: 2.41 /kWh o for the exceeding amount: 1.8 Cent/kWh (if ETS obligation 2.1

Cent/kWh)

- Electricity fed into the public grid is paid by the grid operator according to market prices or directly sold on the market.

- Additionally a fee for “avoided grid cost” according to the general grid cost rules is paid by the grid operator: this is not special support for CHP.

- Support for investments in heating and cooling networks if 60% of the heat or cooling comes from CHP or waste heat.

- Support for heat (and cooling) networks €100/m and max. 40% of investment (<= 100 mm diameter) or 30% (> 100 mm diameter).

- Industrial waste heat is treated as CHP heat.

- Support of heat storage infrastructure €250/m3 up to 30% of investment costs and capped to €5 million (incentive for flexible CHP operation with regards to growing supply of fluctuating wind and solar electricity).

- Overall budget allocated €750 million/year.

- The payments are allocated to final electricity consumers over the electricity bills.

- Runtime of the law up to 2020.

Results - Increase of CHP share in total electricity production 2003 to 2013 from 13.5% to 16.2% (2013: 96 TWh/a). But note that the increase is mainly due to additional bio-CHP which has been supported by the Renewable Energy Law (EEG).

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- This increase has been judged as insufficient to reach the 25% target up to 2020 in the monitoring study from October 2014. The main reasons for this were the extremely low electricity market prices which had been discouraging investments in new CHP since 2011 and even threaten the existence of CHP plants already in operation.

- The consequences of the update of the CHP law in 2015 were thoroughly discussed and considered. The CHP law evaluation study concluded that the target of 25% CHP electricity in 2020 would not be achievable without a significant increase in support payments. To fill the lack of about 50 TWh per year 2 to 3 x 109 € support per year was considered to be necessary, which means 4 to 6 cents per kWh. Periodical adaptations to electricity market prices were advised amongst others. Incentives to shift the CHP electricity production in times with high electricity prices were also discussed. Finally special support for bio-energy CHP via higher bonus payments compared to fossil-fuel CHP was claimed by bio-energy associations.

Transferability of measure

- The general structure and mechanisms were broadly accepted in Germany. The law was relatively simply designed and is estimated to be easily transferable to other countries.

The new KWKG (2016) CHP regulation

The new Regulation KWKG (2016)[14] has brought some modifications in comparison to the old

Regulation (KWKG 2012).

The amended German Combined Heat and Power Act (KWKG – Gesetz zur Neuregelung des

Kraft-Wärme-Kopplungsgesetzes), for the development of CHP generation, entered into force

on 1.1.2016.

For the first time there are specific targets for electric power generation with CHP plants for

2020 (110 TWh) and 2025 (120 TWh). Starting with about 98 TWhe for 2014 this targets

represent an increase of 12 and 22TWh for the next 4 and 9 years respectively .However, this

is significantly below the target of the old regulation, i.e. to reach 25% of the net electrical

energy production (approximately 600-620 TWh) meaning 150 TWh.

Annual support for CHP plants increased from €750m to €1.5bn.

Raised surcharge threshold from 100.000 kWh/a of electricity consumption to 1.000.000

kWh/a .

Scope is to increase the power produced from combined heat and power generation while

CHP operators receive a subsidy (feed-in tariff) allocated per kWh of power consumed. New,

modernized and retrofitted CHP Plants based on waste, waste heat, biomass, gas or liquid

fuels as well as existing ones based on gas, are promoted

Own power consumption (electricity) will be paid only for small installations of <100 kWe. The

remuneration concerns systems of <50 kWe (4 Ct / kWh) and between 50 and 100 kWe (3

cents / kWh). When feeding into the grid, however, the compensation raises in comparison to

the regulation and is 8 cents / kWh for CHP plants of <50 kWe and 6 cents / kWh for plants

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between 50 and 100 kWe. Plants up to 250 kWe get an allowance of 5 cents / kWh, plants up

to 2 MWe get an allowance of 4.40 cents / kWh and plants beyond 2 MWe an allowance of

3.1 cents / kWh. Plants fired with coal of > 2 MW are no longer supported while operators of

installations with an electrical output of> 100 kWe must either consume their electricity

themselves or directly sell it.

Additional policies include:

In case of replacement of coal fired CHP plants, an additional subsidy of 0,6Ct/kWh is provided

Coal fired CHP plants do not receive any subsidies.

CHP operators with capacities higher than 100 kWe can either use the generated electricity

for internal power supply or sell the electricity participating in the electricity stock exchange.

Networks for heating and cooling are also supported by funding.

In addition to the above mentioned tariffs, the renewable energy act (EEG 2014) applies to

CHP installations with biofuels.

Policies such as the Micro CHP Incentive Programme (Mini-KWK-Anlagen-Impulsprogramm),

the Renewable Heat in Buildings Act (EE Wärme-G) and other diverse Taxes Regulations have

an influence on subsidy support.

Impact of KWKG (2016) on market development

Based on the new CHP-law in Germany (KWKG 2016) it is expected that facilities and equipments

with an electricity capacity < 100 kW will be preferably installed. It seems to be clear, that for normal

operation conditions an acceptable ROI (return of investment) could be expected especially in case of

internal power supply. Moreover, the goal to produce 110 TWh of electricity with CHP by 2020,

translates into an increase of the installed capacity of CHP Plants of approximately 3-4 GW.

5.7.2 Flanders

The Flanders support mechanism for CHP has created significant interest from new potential users

and stimulated investment in the sector. It is a market based certificate scheme.

Barrier 1 -Finance: the Flanders scheme has succeeded in attracting new capacity into the market.

Flanders, Wallonia and Brussels all use a form of certificate scheme to successfully promote CHP.

Barrier 3 - Regulatory risk: the use of a floor price for certificates and a clear market approach has

operated as a reduction on regulatory/legislative risk on the market. This even when there have been

several adjustments to the scheme itself.

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Table 5. Policy case studies: Flanders – (Source: CODE 2 – European Policy Report)

Policy/ Measure:

Energy Decree (Vlaanderen, 2009)

Description: Principle of the certificate systems in Belgium: A CHP certificate is a tradable product that proves that an installation makes an amount of primary energy or CO2 savings by using CHP, compared to a reference installation. The owner of a qualitative CHP installation receives every month a number of certificates from the local energy regulator. He can then sell them to the electricity suppliers for a price determined by the free market. In order to maintain the market, electricity suppliers have to buy a number of certificates, regulated by quota. The owner also has the option to sell his certificates to the grid regulators for a minimum price.

The Energy Decree regulates several CHP-related topics:

- It defines high efficiency CHP in Flanders;

- it regulates the general principles of CHP and green electricity certificates as well as guarantees of origin;

- it regulates the responsibilities of the electricity suppliers and grid operators regarding priority access to the grid, the costs of grid connection and responsibility to stimulate rational energy use, and defines the reporting obligations of the Flemish Government, including an energy balance with the production of electricity and heat by CHP per sub-sector and energy source.

- The Energy Resolution (Vlaanderen, 2010) arranges the implementation of the Decree which was revised in July 2012. The implementation of the certificate system was also changed in 2012.

5.7.3 Italy

The Italian support mechanism for CHP has triggered significant interest among new potential users

and stimulated investment in the sector. It is also a market-based certificate scheme.

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Barrier 1 - Finance: The support mechanism of white certificates, which is part of a wider use of

certificates to stimulate low-carbon investment, has promoted CHP to an economic proposition across

a wide range of applications.

Table 6. Policy case studies: Italy – (Source: CODE 2 – European Policy Report)

Policy/ Measure:

M.D. 20/7/2004, 2/1/2013, 5/9/2011 (2004-2013)

Description: - An eligible party (DSO or volunteer) may apply for a White Certificate (WhC) by presenting an energy efficiency project and, if the project is accepted, the party receives a number of WhCs corresponding to the recognised saving (one WhC correspond to one toe of saving). Every party with WhCs on their account can then trade the certificates on the market. WhC trading allows the obligated parties to obtain sufficient WhCs to reach their targets, expressed as primary energy savings assessed using tons of oil equivalent (toe)

- With the entry into force of DM 5/9/ 2011, WhCs are also attributable to simple producers of electric power through CHP plants.

- Every year that High Efficiency (HE) CHP requirements are met, the CHP installation is entitled to release of "HE CHP WhC" based on primary energy saved calculated according to a (rather complicated) formula provided by the Decree.

- HE CHP WhCs are recognised for a maximum period of 10 years or 15 in the case of plants combined with district heating.

- The price of WhCs is fixed by the reference market and continually increased in the scheme’s first six months, reaching 144 €/toe, attributing a greater value to energy efficiency projects which can find a significant support for investments.

Results - The mechanism of WhCs is generally accepted by the industrial sector and by industrial CHP installations in particular. Enea (the body assessing the conformity of projects for WhC release) judges that WhC is the system that contributed most to generating energy savings (approximately 35,000 GWh/year between 2008 and 2012).

- The last trend indicates a clear shift towards projects in industrial and large service sectors. This is evidently a good indication for industrial competitiveness, but it could also be a sign that the complexity required by the procedure and the continuous monitoring effort is rarely compatible with those small and medium-sized operations that are typical for SMEs, constituting the backbone of Italian economy.

Transferability of measure

- The diversity of the mechanisms, tools and actors put to use by each European country to monitor and measure energy savings from different sectors and applications implies that caution is necessary to conclude whether schemes like the Italian WhCs are practically transferable from one country to another. It would be advisable to first carry out an initial phase of stating minimum common rules for measuring parameters and

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obligations where possible in order to build towards a potential common scheme.

5.7.4 Netherlands

Barrier 2: Connections and tariffs: CHP is well established in the Netherlands and clear parameters exist

for new connections and tariffs. This transparency helps investors to estimate and plan projects,

lowering overall transaction costs.

Table 7. Policy case studies: Netherlands – (Source: CODE 2 – European Policy Report)

Policy/ Measure:

Activiteitenbesluit (Regulations for small and medium-sized heat generators under the activities legislation) and procedures for grid connection.

Description: - For systems up to 50 MWth running standard fuels (i.e. natural gas, propane, pellets):

o No permits needed, just a mention o Emission requirements exist

- For systems larger than 50 MWth running standard fuels (i.e. natural gas, propane, pellets):

o Permits are needed o (Strict) emission requirements exist

- The following obligations of grid operators are important:

o Obligation of grid operator to provide a connection to the grid (Article 23 electricity law)

o Obligation of grid operator to transport the required amount of electricity from and to the connection (Article 3.1.1 Network code electricity)

Transferability of measure

- The process of connecting CHP to the grid is relatively simple in the Netherlands. If the system meets the conditions outlined above it has to be formally mentioned to the authorities and to the grid operator. The underlying legislation is unfortunately not simple. It involves environmental legislation, energy legislation and the network code.

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6 Policy recommendations and key R&D priorities

As already discussed, CHP development in the EU has stagnated in the last few years regardless of

its huge potential for energetic and economic savings. This fact has been attributed to a number of

barriers mainly related to policy issues, underlining the need for decisive initiatives in policies and

legislation at both EU and at member-state level. Therefore, research is needed to develop an industry

roadmap to define appropriate target levels for the EU’s CHP market penetration and to develop

specific technology and policy actions to reach those levels. The Roadmap should consider a

combination of both policy and R&D activities to achieve market goals.

A number of CHP stakeholders such as COGEN Europe (European Association for the Promotion

of Cogeneration), and EURELECTRIC(Union of the Electricity Industry), have publicly released a number

of policy recommendations to enhance the development of CHP in EuropeIn the first section of this

Chapter, these recommendations are presented.Finally, crucial R&D priorities towards an increased

CHP market penetration are recommended.

6.1 EURELECTRIC Recommendations

The Union of the Electricity Industry - EURELECTRIC is the sector association which represents the

common interests of the electricity industry at pan-European level. Currently, EURELECTRIC's three

major objectives are [35]:

• Delivering carbon-neutral electricity in Europe by 2050

• Ensuring a cost-efficient, reliable supply through an integrated market

• Developing energy efficiency and the electrification of the demand-side to mitigate climate

change

In this context, the following policy recommendations regarding CHP development have been

presented [32].

1. Strengthen the EU ETS rewarding the energy efficiency of large CHP plants. Further clarity

required in the revision for phase 4 (2021-2030) regarding allocation to CHP plants.

CO2 reductions should primarily be driven through the EU Emissions Trading System, since carbon

markets are the cost-effective way to drive investment choice in CO2 reduction.

• Moreover the EU ETS is fully compatible with the Internal Energy Market. A reformed ETS

should therefore be the main driver for the low carbon transition. EURELECTRIC supports

measures to strengthen the ETS soon and effectively.

• Due to its distortive impacts, support for mature technologies should be progressively

phased out. Improved subsidy schemes are needed to reduce the distortive impacts of

support.

• Support should focus on fostering R&D. R&D support should be available for technologies

throughout the entire innovation cycle as well as for improvement of mature technologies

such as CHP.

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Given that the CO2 emissions from CHP are relatively low due to its high efficiency, CHP benefits

from emission reduction measures, like the EU ETS and R&D support that do not risk the functioning

of the power market (assuming that costs for CO2 are internalised both for electricity and heat).

Contrastingly, measures focusing on energy sources, such as RES support, priority access to RES

electricity or prioritised access to heat network distort the market and do not take into account

emission reductions gained through efficient use of primary energy. For this reason they are not

beneficial for CHP. During periods with low heat demand, heat from the CHP plant can be stored and

used later during peak hours. The electric boilers can be used during periods with low electricity prices

to produce heat and store it.

CHP competes with heating technologies that are not within the scope of the EU emissions trading.

For example natural gas used by households is provided at lower tax levels in some countries. This

provides perverse incentives and does not encourage efficient emission reductions. CHP is at a

disadvantage if economic instruments are not used to reduce CO2 emissions from other heat sources

and if mature technologies receive support.

2. The policy framework should drive CO2 reductions in all sectors, including heat

• The policy framework should drive emission reductions in all sectors, including heat:

because CHP is in the scope of EU ETS it is at a disadvantage if the costs of carbon emissions

are not internalised for competing heating technologies.

• Renewable and low carbon heating solutions such as renewable district heat and CHP, heat

pumps, pellet heating and solar heating can be advanced by applying economic instruments

on heating rather than providing support for renewable heating technologies.

• Policy instruments such as subsidies and carbon taxes disturb the functioning of the carbon

market and lead to inefficiencies. Consequently, there should be no national carbon taxes or

other overlapping instruments in the emissions trading sector, including CHP.

3. Avoid taxes on fuels used for power generation: electricity-tax at the point of consumption

instead

• Electricity should be taxed at the point of consumption, allowing power generators in

different European countries to operate on a level playing field.

• Limitation of the application of technology specific taxes on power generation as they also

distort competition.

CHP benefits from a well-functioning internal electricity market and a reduced tax burden on

power generation.

4.Member States should develop power markets that allow operators to explore opportunities to

develop flexible operation of CHP

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• Member states should strive to develop integrated day ahead, intraday and balancing

markets in order to reveal the price for flexibility and thus meet the demands in changing

power systems.

• In order to allow aggregated flexibility to participate in spot and intra-day markets, system

balancing and constraints management, the following issues need to be addressed

Capacity remuneration mechanisms (CRMs), which are now becoming de facto reality in many EU

Member States, influence the attractiveness of investments in CHP plants that can provide firm

capacity. In EURELECTRIC’s view CRMs should only be introduced as a means of ensuring security of

supply, not to achieve other policy objectives. CRMs should remunerate generation adequacy service

that is not properly valued in the energy-only market. They should be technology neutral and non-

discriminatory i.e. give equal treatment to existing and new units for generation, storage, demand and

cross-border participation, and should be coordinated at regional level to ensure consistency and

minimum distortion to the internal energy market.

Remuneration of reliable capacity and flexibility in the power market influences the profitability

of investments to facilitate more flexible operation of CHP plants. This will help CHP to adapt to the

changes to the power system brought by increased variable generation.

5. Ensure a competitively priced, flexible and secure fuel supply

• Alongside well-functioning electricity markets, flexible and competitive gas markets can

strongly contribute to a cost-efficient transition towards a low-carbon economy. Taking into

account that more than half of CHP electricity is produced with natural gas, it is important

for the future of Europe’s CHP fleet to continue improving security of gas supply.

• Strengthening the diversity of pipeline connections within and towards the EU ensures that

gas can flow where it is needed. Implementing physical reverse flows – as envisaged by the

Security of Supply Regulation – should be done systematically and especially at key

interconnection points. Diversification of both sources (LNG, unconventional gas) and routes

of supply is needed.

• In order to realise the potential of biomass, biogas and waste Europe needs a stable and

reliable EU and national regulatory framework that supports the use of these fuels, and

contributes to ensuring sustainability of biomass

Take or pay contracts for gas hinder flexible operation of CHP plants. High gas prices reduce the

competitiveness of CHP. Uncertainty about regulatory requirements can be a barrier to increasing

utilisation of biomass and waste in CHP plants.

6. Implement a stable and proportionate framework for emissions from CHP

• It is essential that the BREF (Best Available Technique Reference Documents) are being

developed under the Industrial Emissions Directive take full account of inputs from industry

stakeholders.

• Emission limit values for CHP and other thermal plants should be realistic and proportionate

and should take account of factors such as differing plant load factors and ages. Future

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regulation of small and medium combustion plants should also be cost-effective and

proportionate.

• Requirements on environmental performance should be stable enough to allow companies

to plan their investments well in advance.

6.2 COGEN - 8 Key Recommendations: “Towards an EU Heating and Cooling

Strategy”

COGEN Europe is the European association for the promotion of cogeneration. Its principal goal is

to work towards the wider use of cogeneration in Europe for a sustainable energy future. COGEN

Europe promotes the widespread development of cogeneration in Europe and worldwide. To achieve

this goal, COGEN Europe works at the EU level and with member states to develop sustainable energy

policies and remove unnecessary barriers to implementation [36].

COGEN Europe and its members believe the following eight points must be included in the scope

of an EU Heating and Cooling Strategy [37]:

1) Take all strategic objectives of the EU's existing energy and climate policy framework into account

(the 'Energy Trilemma')

Adopting an 'Energy Efficiency First' approach to the Strategy offers the advantage of addressing

the trilemma of the EU's energy goals: security of supply, competitiveness and environmental

protection. Security of supply in particular requires that energy efficiency along the supply chain and

not only in end use should be included in the Strategy.

2) Take a System not a Silo approach

Heat storage and transactions between energy networks (heat, gas and electricity) can all help to

increase efficiency. Heat and electricity production are closely linked. Heat cannot be addressed in

isolation from the rest of energy demand, nor can it be supplied in isolation from the rest of energy

supply. Heat networks should receive similar planning consideration as electricity and gas networks in

that they give EU energy users advantages in terms of services and efficiency. All energy users must

benefit.

3) Encompass all significant heat and chilling demands

A central element of the Strategy must be the development of a practical and sufficient framework

for understanding heat use in Europe, as well as the collection of supporting data. The strategy should

include heat needs for industry, a sector which uses around 40% of Europe's heat.

4) Establish consistency with EU electricity market design

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The links between supply and demand for heat and electricity are strong and are the source of

major energy efficiency gains. There must be consistency between electricity market design and the

Strategy.

5) Measure success in Primary Energy Savings (PES) in the EU energy system

In 2012 the EU imported 53% of its primary energy at an estimated cost of €405bn, out of which

about €170bn was used non-transport sectors. The EU must have dependable domestic energy

sources and it must use the energy it imports more efficiently. A focus on primary energy savings

delivers success in terms of both end-use savings and network and transformation improvements,

which end-use measures do not.

6) Take a Multi-Technology approach

Decarbonising the heat sector requires the large-scale mobilisation of capital and innovation.

Demand for heat is very local in nature and the Strategy should recognise the need for flexibility from

the outset. A multi-technology approach should be adopted to stimulate innovation and ensure that

good technologies based on local and most-efficient solutions come forward.

7) Include Cities and Regions in its scope from the outset

The Strategy's need to lead with energy efficiency, consider a system approach and tackle

challenges where the best solutions may be very local in nature points to success in linking with cities

and regions. Using networks like the Covenant of Mayors and regional platforms as partners in moving

ideas and actions forward should be part of the Strategy from the outset.

8) Establish the adequacy of data to support its recommendations

As the first-ever detailed inclusion of heat in the EU's energy thinking, the Strategy should highlight

data gaps and seek to address these first. Only where sufficient data exists at this stage can framework

recommendations be made.

6.3 Recommendations on key R&D priorities

The aim of this section is to provide recommendations for the research and development activities

which could lead to increases in CHP market penetration.

Based on the analysis of CHP barriers and driving policies presented in Chapter 5, there are certain

specific R&D activities which could improve the market penetration of CHP, with significant economic

and social benefits. In fact, despite the large technical market potential of CHP, only a small part of it

is currently cost effective, primarily due to economic considerations and restrictive environmental

emissions criteria. This suggests the need for continued R&D towards technologies and systems that

could boost the CHP market sector [38].

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6.3.1 Technology Needs and Gaps

A critical factor for CHP market penetration is the ability to be both cost competitive and to have

acceptable environmental emission levels. In the context of the European environmental policies that

aim to increase the RES share and reduce CO2 footprint and emissions of pollutants, near-term R&D

actions should address the following areas:

• Ensure market availability of low emission gas turbines and internal combustion engines.

Develop and demonstrate low NOX emission control systems for these technologies and

demonstrate solutions are viable in the field through end-use demonstrations.

• Longer term R&D activities should focus on achieving more significant capital cost

reductions of CHP options – particularly smaller systems for the commercial sector and light

industrial markets.

• Improve the cost of current non-competitive micro turbines and high temperature fuel cells.

Market research points that payback times are too long for many commercial sector market

applications, suggesting that current retail rates may be competitive.

Therefore, R&D efforts should specifically focus on:

• Improving durability and reducing O&M costs of emerging CHP technologies

• Increasing electrical efficiency

• Increasing operational flexibility

• Reducing the capital and installation costs of fully integrated packaged systems

• Defining and standardizing packaged systems for specific end-use markets of Member States

• Accelerating the development, demonstration and adoption of very low emission high

temperature fuel cells such as solid oxide fuel cell technology

• Integrating electrical energy storage systems and thermal energy storage with CHP systems

to provide an increased value proposition to end-users.

• Assessing the potential for standardized CHP systems/ appliances for EU’s mass market

sector

• R&D is needed to address the perceived risks of emerging CHP systems. These risks could be

reduced through:

- Definition of standard CHP packaged systems for target markets

- Pre-qualification, testing and certification of these systems

- Development and validation of seamless interconnection solutions with the ability to export power.

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7 Summary and Conclusions

In this report, a thorough review of CHP technologies and their characteristics has been carried

out. Moreover, the current status of CHP and its potential for future development across the EU has

been extensively presented, based on the currently best available data. Of course, to accurately and

realistically assess the potential and future development of CHP it is necessary to take into account

the use of municipal DH use in the EU countries and the potential use of waste heat. A number of

case studies have been included to showcase real examples of CHP applications and investments. The

deployment of CHP under an energy policy landscape characterized by increasing RES penetration has

been examined in terms of technical (e.g. grid stability) and strategic (capacity compatibility)

perspectives. Subsequently, a summary of the findings of available studies on the current EU policies

as well as the most important barriers to CHP development has been carried out. Despite the

numerous successful driving policies focused on providing economic incentives (capital support, feed-

in tariffs, market support and tax reduction schemes etc.), investment uncertainties are caused by the

continuously changing legal and policy CHP framework. Another important issue, recognized in many

cases, is the insufficient recognition of the CHP contribution to energy efficiency, emissions mitigation

and grid stability services. Therefore it has been concluded that certain policies need to be

implemented in order to provide the necessary initiatives for CHP development. In this direction, an

overview of the policy recommendations of two major CHP stakeholders (EURELECTRIC, COGEN) has

been presented. Finally, crucial R&D priorities towards an increased CHP market penetration are

recommended.

The main findings of this study are summarized and discussed next:

The potential benefits of a CHP focused electricity market at an EU level are very high, with

industrial and district heating CHP playing a leading role. These benefits regard energetic efficiency

(i.e. Primary Energy Savings), CO2 footprint as well as system stability and operation. In this

perspective, certain policy measures have been taken both at an EU level (e.g. the Energy Efficiency

Directive –EED) and at a member-state level in order to promote the deployment of CHP. However, in

the last years CHP development has stagnated in terms of both cumulative electrical/heat capacity

and also electrical/heat output. In particular, the installed electrical capacity of CHP has been

undergoing a very slow increase, while the amount of cogenerated electricity has been marginally

decreasing. The same holds roughly for the CHP share in electricity production.

With regard to the heat part of the CHP market, in the last few years there was a drop in heat

capacity and more substantially in heat output. Meanwhile, heat demand takes up a significant share

of the EU’s primary energy consumption. At the same time, CHP is an efficient way of power and heat

generation. If we consider the production of heat as the primary product of CHP plants, then the

produced electricity is a high grade by-product. However, certain concerns need to be addressed for

promoting the fruitful development of CHP.

As already discussed, CHP plants can be categorized into district heating plants and industrial

plants. Industrial CHP plants constitute the bulk of CHP installations in terms of capacity, but district

heating plays certainly an important role especially in northern EU countries. In both cases, due to the

strongly localized character of heat production, opportunities for further CHP development are

strongly determined by the existence of industrial heat consumers with reasonable and continuous

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demand of heat supply, which can lead to economically attractive investments. In other words, the

reasonable share of CHP-generated electricity is heavily dependent on the heat market, which

determines its limits.

Consequently, a decisive share of the electricity demand, which depends on the already installed

generation fleet and the status of the heat market in each European country, has to be covered by

electricity-only power plants. It is thus very important to investigate the actual, realistic CHP potential

in each Member State. Furthermore, in the same context, it is useful to define the co-existence and

interaction of electricity-only power plants and CHP plants in order to enhance the security of energy

supply and promote grid stability.

The development of CHP is also strongly influenced by the gradually increasing participation of

RES in the energy mix, which is an already established EU energy strategy priority. It has been shown

that very high RES penetration has a number of practical obstacles, related to grid stability issues and

the feasibility of ancillary services. Another issue that raises certain concerns on CHP deployment is

its compatibility with the projected RES installed capacities in the future, as well as with the inherent

characteristics of RES and CHP power generation seasonal patterns. It was shown that at the present

status, no significant conflicts arise between RES and CHP development. High RES penetration,

however, poses certain challenges to the EU energy system. With growing shares of fluctuating power

production from wind and solar, increasingly flexible production technologies are needed to cover the

residual loads. Moreover, the need for a flexible generation fleet is highlighted by the occurrence of

anomalies (e.g. negative wholesale electricity prices) in the electricity market at instances of extremely

disproportionate electricity supply and residual demand. An important question is the extent at which

CHP can offer load variation management. To respond to this matter, it is necessary to investigate the

possibilities and limitations of different CHP technologies, as well as the local DH supply mix, the

industrial heat demand and the more general system context (surrounding electricity generation

system and demand).

Up to this point, older conventional fossil fuelled power plants are retrofitted to enhance their

flexibility and technologically advanced new ones, capable of ultra flexible operation, are being

constructed. These plants have the ability to effectively and efficiently adapt to intense load variations

and have so far significantly helped to ensure grid balancing and thus allowing for the increase of RES

penetration. In fact, ultra flexible electricity-only plants are an indispensable part of the power

generation fleet, with very high efficiency (up to 45%) and ability to operate under very extensive load

variations (25% of the nominal value or even lower in some cases) with relatively small efficiency

penalties.

A commonly discussed option to further enhance the integration of RES sources is the so called

power to heat conversion strategy at a grid level, which has been proposed as an alternative solution

to deal with increased excess electricity during high RES power generation and thus with grid stability

issues. This means that instead of implementing power-to-fuel technologies (e.g. production of

synthetic natural gas via electrolysis and methanation), which are characterized by low overall

efficiencies, the surplus renewable power is used directly to produce heat, resulting in savings of the

corresponding amount of natural gas. At the same time, the need for ancillary services and hence the

requirement for load variation from relatively inflexible conventional power plants is decreased.

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However, under the current legislative framework, RES systems are always prioritized to supply

all the electricity that they produce to the grid (no curtailment of RES power is ensured) at usually

higher prices compared to the rates achieved by conventional electric power producers in the

electricity market. Meanwhile, by implementing the power to heat strategy, what actually changes

compared to the current situation, is that the residual load is managed in a way that does not require

from conventional plants to lower their load beyond their technical minimum limits.

As a result, when power to heat conversion is applied at an electrical-grid level, it can be assumed

that for the grid operator this is equivalent with the direct conversion of the electric power of

conventional power plants to heat, which, as it has been shown, is characterized by low overall

conversion efficiencies.

Consequently, while practical from a perspective of grid stability, the power-to-heat strategy is

substantially inefficient in terms of primary energy consumption, due to the greatly reduced heat

conversion efficiency.

Meanwhile, it should be noted that power-to-heat from renewable power as a grid balancing

strategy could only be applied under a different regulatory landscape concerning the promotion of

RES electricity penetration. However, even under this scenario, extensive techno-economic and life

cycle assessment studies need to be carried out in order to specify the limits and the optimal

integration strategies of power-to-heat into RES in order to ensure grid balancing, security of supply,

environmental sustainability and economic viability.

CHP plants, on the other hand, which constitute a significant part of the energy generation fleet,

are inherently flexible, allowing for the stabilization and effective control of the grid supply/demand

power balance, while maintaining a very high overall energetic efficiency. A growing CHP share means

an intelligent and cost effective interaction between covering electricity supply and heat supply,

considering all objectives: security of supply, economy, decarbonisation, using limited energy

resources as efficiently as possible. Therefore, CHP plants (industrial and district heating) are the best

option for covering heat demands, given the existence of an economically rewarding environment.

Consequently, when a sufficient heat demand is present, a CHP solution should always be considered

over the application of power-to-heat technology at a local level.

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Nomenclature

Abbreviations Glossary

BAU: Business as usual

BREF: Best Available Technique Reference Notes

CBA: Cost Benefit Analysis

CHP: Cogeneration of Heat and Power

DH: District Heating

DSO: Distribution System Operator

EC: European Commission

EED: Energy Efficiency Directive

ETS: Emission Trading Scheme

EU: European Union

FC: Fuel Cells

GIC: Gross Inland Consumption

GT & CC: Gas Turbine and Combined Cycle plants

HECHP: High Efficiency Cogeneration

HP: High Pressure

ICE: Internal Combustion Engine

IRR: Internal Rate of Return

LCOE: Levelized Cost of Electricity

LHV: Lower Heating Value

MP: Medium Pressure

NEEAPs: National Energy Efficiency Action Plans

ORC: Organic Rankine Cycle

PES: Primary Energy Savings

PR: Policy Recommendations

PV: Photovoltaic

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RES: Renewable Energy Sources

SE: Stirling Engine

SHP: Separate heat and power

ST: Steam Turbines

TSO: Transmission System Operator

UK: United Kingdom

μ-CHP: micro CHP

μT: micro Turbines

List of variables and subscripts

Variables

C power-to-heat ratio (production)

CHP Εη electrical efficiency of CHP (annual production basis)

CHPΗη heat efficiency of CHP (annual production basis)

E energy, electricity produced from CHP

F fuel

H CHP useful heat produced from CHP

H useful cogeneration heat

PES primary energy savings

PESR primary energy savings ratio

Q heat

Ref Ηη efficiency reference value for SHP

SIC specific investment cost

η efficiency

ηe electric efficiency

σ power-to-heat ratio (operational)

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Subscripts

C fuel

CHP combined heat and power plant

CON condensate

e electrical

er reference efficiency for separate electricity generation

HP high pressure

hr reference efficiency for separate heat generation

M.U. make up water

max maximum

MP medium pressure

th thermal

TOT total

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REFERENCES

[1] COGEN EUROPE website, http://www.cogeneurope.eu/

[2] U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy, Office of

Industrial Technologies, Review of Combined Heat and Power Technologies, 2012

[3] CODE 2 project, Cogeneration Observatory and Dissemination Europe, European Cogeneration

Roadmap, 2015

[4] European Commission, Energy Efficiency Directive (EED). Directive 2012/27/EU of the European

Parliament and of the Council of 25 October 2012 on energy efficiency, amending Directives

2009/125/EC and 2010/30/EU and repealing Directives 2004/8/EC and 2006/32/EC Text with

EEA relevance

[5] CODE project, Cogeneration Observatory and Dissemination Europe, Cogeneration Case Studies

Handbook, 2011

[6] Enerdata,Global Energy Statistical Yearbook 2016, https://yearbook.enerdata.net/

[7] Heat Roadmap Europe 2050. Aalborg University and Halmstad University for Euroheat & Power,

Brussels, 2012

[8] A brief analysis of the latest Eurostat data (reference year: 2013),COGEN EUROPE, 2015

[9] Ecoheatcool and Euroheat & Power 2005-2006, The European Heat Market, 2005.

[10] G. Pardo , K. Vatopoulos, . A. Krook-Riekkola, . J. A. Moya Rivera and A. Perez Lopez, “Heat and

cooling demand and market perspective,” JRC Scientific and Policy reports, 2012.

[11] CEPI, “European pulp and Paper Industry Key Statistics 2014,” 2015.

[12] Öko-Institut e.V. Aktueller Stand der KWK-Erzeugung (Dezember 2015), Im Auftrag des

Bundesministerium für Wirtschaft und Energie, Berlin, 17/12/2015

[13] https://www.bhkw-infozentrum.de/bhkw-news/22445_Hocheffizientes-

Gasmotorenheizkraftwerk-in-der-Kieler-Foerde.html

[14] Bundesrat, Drucksache 594/15 04.12.15., Gesetzesbeschluss des Deutschen Bundestages,

Gesetz zur Neuregelung des Kraft-Wärme-Kopplungsgesetzes

[15] Prognos AG, Potenzial- und Kosten-Nutzen-Analyse zu den Einsatzmöglichkeiten von Kraft-

Wärme-Kopplung (Umsetzung der EU-Energieeffizienzrichtlinie) sowie Evaluierung des KWKG

im Jahr 2014, Auftraggeber Bundesministerium für Wirtschaft und Energie, Projektleitung

[16] CODE 2 project, Cogeneration Observatory and Dissemination Europe, Flexibility options of

CHP: bringing together renewable energies and efficiency (German example), Adi Golbach

[17] Technische Universität Wien, Energy Economics Group, Gustav Resch et al., 2020 RES scenarios

for Europe, 2014

[18] NREL, Integrating Variable Renewable Energy: Challenges and Solutions, 2013

[19] Lew, D.; Brinkman, G.; Ibanez, E.; Hodge, B.-M.; Hummon, M.; Florita, A.; Heaney, M.; Stark, G.;

King, J.; Kumar, N.; Lefton, S.; Agan, D.; Jordan, G.; Venkataraman, S. (2013). Western Wind and

Solar Integration Study Phase 2 (WWSIS-2). NREL/TP-5500-55588. Golden, CO: National

Renewable Energy Laboratory.

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[20] Western Governors’ Association (WGA). (2012). Meeting Renewable Energy Targets in the West

at Least Cost: The Integration Challenge. Denver, CO: Western Governors’ Association..

[21] Agan, D.; Besuner, P.; Grimsrud, G.P.; Lefton, S. (2008). Cost of Cycling Analysis for Pawnee

Station Unit 1 Phase 1: Top-Down Analysis. AES 08116940-2-1pr. Work performed by Aptech

Engineering Services, Sunnyvale, CA. Minneapolis, MN: Xcel Energy, November..

[22] Puga, N. (2010). “The Importance of Combined Cycle Generating Plants in Integrating Large

Levels of Wind Power Generation.” The Electricity Journal (23:7) August/September.

[23] Prognos AG, Potenzial undEinsatzmöglichkeiten von Kraft-Wärme-Kopplung, May 2015

[24] J. Karl, Dezentrale Energiesysteme: Neue Technologien im liberalisierten Energiemarkt,

Oldenbourg-Verlag , 2006

[25] A. Andersen, P. Sorknæs,Next generation CHP to balance intermittent production from

renewables, 2011

[26] S. Benedettini and C. Stagnaro, The case for allowing negative electricity prices, Energypost,

2014

[27] U.S. Energy Information Administration, Negative prices in wholesale electricity markets

indicate supply inflexibilities, 2012

[28] CODE 2 project, Cogeneration Observatory and Dissemination Europe, European Policy Report,

January 2015

[29] European Commission, DIRECTIVE 2004/8/EC OF THE EUROPEAN PARLIAMENT AND OF THE

COUNCIL of 11 February 2004 on the promotion of cogeneration based on a useful heat

demand in the internal energy market and amending Directive 92/42/EEC

[30] Directive 2009/28/EC of the European Parliament and of the Council of 23 April 2009 on the

promotion of the use of energy from renewable sources and amending and subsequently

repealing Directives 2001/77/EC and 2003/30/EC

[31] European Commission, Energy Related Products Directive(ERPD – 2009/125/EC)

[32] EURELECTRIC, CHP as part of the energy transition: The way forward, 2014

[33] CODE project, http://www.code-project.eu/

[34] CODE 2 project,http://www.code2-project.eu/

[35] EURELECTRIC website, http://www.eurelectric.org/

[36] COGEN EUROPE website, http://www.cogeneurope.eu/

[37] COGEN EUROPE, Towards an EU Heating and Cooling Strategy, Brussels, 3 July 2015, position

paper

[38] EPRI (Electric Power Research Institute), Assessment of California Combined Heat and Power

(CHP) Markets andPolicy Options for Increased Penetration, Technical Report, 2006

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APPENDIX A - CHP definitions according to the Energy Efficiency

Directive (EED)

APPENDIX A is divided in three sections. In the first section, the Articles of the EED that are referenced

in this report are included in their entirety. In the second section, the ANNEXES I and II of the EED,

which contain the main definitions related to CHP are included. Lastly, in the third section, some

remarks on the definition of high-efficiency CHP are provided, based on the EED.

Selected Articles of the EED mentioned in this Report

Article 3

Energy efficiency targets

1. Each Member State shall set an indicative national energy efficiency target, based on either primary

or final energy consumption, primary or final energy savings, or energy intensity. Member States shall

notify those targets to the Commission in accordance with Article 24(1) and Annex XIV Part 1. When

doing so, they shall also express those targets in terms of an absolute level of primary energy

consumption and final energy consumption in 2020 and shall explain how, and on the basis of which

data, this has been calculated.

When setting those targets, Member States shall take into account:

(a) that the Union’s 2020 energy consumption has to be no more than 1 474 Mtoe of

primary energy or no more than 1 078 Mtoe of final energy;

(b) the measures provided for in this Directive;

(c) the measures adopted to reach the national energy saving targets adopted pursuant to

Article 4(1) of Directive 2006/32/EC; and

(d) other measures to promote energy efficiency within Member States and at Union level. L

315/12 Official Journal of the European Union 14.11.2012 EN

When setting those targets, Member States may also take into account national circumstances

affecting primary energy consumption, such as:

(a) remaining cost-effective energy-saving potential;

(b) GDP evolution and forecast;

(c) changes of energy imports and exports;

(d) development of all sources of renewable energies, nuclear energy, carbon capture and

storage; and

(e) early action.

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2. By 30 June 2014, the Commission shall assess progress achieved and whether the Union is likely to

achieve energy consumption of no more than 1 474 Mtoe of primary energy and/or no more than 1

078 Mtoe of final energy in 2020.

3. In carrying out the review referred to in paragraph 2, the Commission shall:

(a) sum the national indicative energy efficiency targets reported by Member States;

(b) assess whether the sum of those targets can be considered a reliable guide to whether

the Union as a whole is on track, taking into account the evaluation of the first annual report

in accordance with Article 24(1), and the evaluation of the National Energy Efficiency Action

Plans in accordance with Article 24(2);

(c) take into account complementary analysis arising from:

(i) an assessment of progress in energy consumption, and in energy consumption in

relation to economic activity, at Union level, including progress in the efficiency of

energy supply in Member States that have based their national indicative targets on

final energy consumption or final energy savings, including progress due to these

Member States’ compliance with Chapter III of this Directive;

(ii) results from modelling exercises in relation to future trends in energy

consumption at Union level;

(d) compare the results under points (a) to (c) with the quantity of energy consumption that

would be needed to achieve energy consumption of no more than 1 474 Mtoe of primary

energy and/or no more than 1 078 Mtoe of final energy in 2020.

Article 7

Energy efficiency obligation schemes

1. Each Member State shall set up an energy efficiency obligation scheme. That scheme shall ensure

that energy distributors and/or retail energy sales companies that are designated as obligated parties

under paragraph 4 operating in each Member State’s territory achieve a cumulative end-use energy

savings target by 31 December 2020, without prejudice to paragraph 2.

That target shall be at least equivalent to achieving new savings each year from 1 January 2014 to 31

December 2020 of 1,5% of the annual energy sales to final customers of all energy distributors or all

retail energy sales companies by volume, averaged over the most recent three-year period prior to 1

January 2013. The sales of energy, by volume, used in transport may be partially or fully excluded from

this calculation.

Member States shall decide how the calculated quantity of new savings referred to in the second

subparagraph is to be phased over the period.

2. Subject to paragraph 3, each Member State may:

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(a) carry out the calculation required by the second subparagraph of paragraph 1 using values

of 1% in 2014 and 2015; 1,25% in 2016 and 2017; and 1,5% in 2018, 2019 and 2020;

(b) exclude from the calculation all or part of the sales, by volume, of energy used in industrial

activities listed in Annex I to Directive 2003/87/EC;

(c) allow energy savings achieved in the energy transformation, distribution and transmission

sectors, including efficient district heating and cooling infrastructure, as a result of the

implementation of the requirements set out in Article 14(4), point (b) of Article 14(5) and

Article 15(1) to (6) and (9) to be counted towards the amount of energy savings required under

paragraph 1; and

(d) count energy savings resulting from individual actions newly implemented since 31

December 2008 that continue to have an impact in 2020 and that can be measured and

verified, towards the amount of energy savings referred to in paragraph 1.

3. The application of paragraph 2 shall not lead to a reduction of more than 25% of the amount of

energy savings referred to in paragraph 1. Member States making use of paragraph 2 shall notify that

fact to the Commission by 5 June 2014, including the elements listed under paragraph 2 to be applied

and a calculation showing their impact on the amount of energy savings referred to in paragraph 1.

4. Without prejudice to the calculation of energy savings for the target in accordance with the second

subparagraph of paragraph 1, each Member State shall, for the purposes of the first subparagraph of

paragraph 1, designate, on the basis of objective and non-discriminatory criteria, obligated parties

amongst energy distributors and/or retail energy sales companies operating in its territory and may

include transport fuel distributors or transport fuel retailers operating in its territory. The amount of

energy savings to fulfil the obligation shall be achieved by the obligated parties among final customers,

designated, as appropriate, by the Member State, independently of the calculation made pursuant to

paragraph 1, or, if Member States so decide, through certified savings stemming from other parties as

described in point (b) of paragraph 7.

5. Member States shall express the amount of energy savings required of each obligated party in terms

of either final or primary energy consumption. The method chosen for expressing the required amount

of energy savings shall also be used for calculating the savings claimed by obligated parties. The

conversion factors set out in Annex IV shall apply. 14.11.2012 Official Journal of the European Union L

315/15 EN ( 1) OJ L 216, 20.8.2009, p. 76.

6. Member States shall ensure that the savings stemming from paragraphs 1, 2 and 9 of this Article

and Article 20(6) are calculated in accordance with points (1) and (2) of Annex V. They shall put in place

measurement, control and verification systems under which at least a statistically significant

proportion and representative sample of the energy efficiency improvement measures put in place by

the obligated parties is verified. That measurement, control and verification shall be conducted

independently of the obligated parties.

7. Within the energy efficiency obligation scheme, Member States may:

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(a) include requirements with a social aim in the saving obligations they impose, including by

requiring a share of energy efficiency measures to be implemented as a priority in households

affected by energy poverty or in social housing;

(b) permit obligated parties to count towards their obligation certified energy savings achieved

by energy service providers or other third parties, including when obligated parties promote

measures through other State-approved bodies or through public authorities that may or may

not involve formal partnerships and may be in combination with other sources of finance.

Where Member States so permit, they shall ensure that an approval process is in place which

is clear, transparent and open to all market actors, and which aims at minimising the costs of

certification;

(c) allow obligated parties to count savings obtained in a given year as if they had instead

been obtained in any of the four previous or three following years.

8. Once a year, Member States shall publish the energy savings achieved by each obligated party, or

each sub-category of obligated party, and in total under the scheme.

Member States shall ensure that obligated parties provide on request:

(a) aggregated statistical information on their final customers (identifying significant changes

to previously submitted information); and

(b) current information on final customers’ consumption, including, where applicable, load

profiles, customer segmentation and geographical location of customers, while preserving

the integrity and confidentiality of private or commercially sensitive information in

compliance with applicable Union law. Such a request shall be made not more than once a

year.

9. As an alternative to setting up an energy efficiency obligation scheme under paragraph 1, Member

States may opt to take other policy measures to achieve energy savings among final customers,

provided those policy measures meet the criteria set out in paragraphs 10 and 11. The annual amount

of new energy savings achieved through this approach shall be equivalent to the amount of new energy

savings required by paragraphs 1, 2 and 3. Provided that equivalence is maintained, Member States

may combine obligation schemes with alternative policy measures, including national energy efficiency

programmes.

The policy measures referred to in the first subparagraph may include, but are not restricted to, the

following policy measures or combinations thereof:

(a) energy or CO2 taxes that have the effect of reducing end-use energy consumption;

(b) financing schemes and instruments or fiscal incentives that lead to the application of

energy-efficient technology or techniques and have the effect of reducing end-use energy

consumption;

(c) regulations or voluntary agreements that lead to the application of energy-efficient

technology or techniques and have the effect of reducing end-use energy consumption;

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(d) standards and norms that aim at improving the energy efficiency of products and services,

including buildings and vehicles, except where these are mandatory and applicable in

Member States under Union law;

(e) energy labelling schemes, with the exception of those that are mandatory and applicable

in the Member States under Union law;

(f) training and education, including energy advisory programmes, which lead to the

application of energy efficient technology or techniques and have the effect of reducing end-

use energy consumption.

Member States shall notify to the Commission, by 5 December 2013, the policy measures that they

plan to adopt for the purposes of the first subparagraph and Article 20(6), following the framework

provided in point 4 of Annex V, and showing how they would achieve the required amount of savings.

In the case of the policy measures referred to in the second subparagraph and in Article 20(6), this

notification shall demonstrate how the criteria in paragraph 10 are met. In the case of policy measures

other than those referred to in the second subparagraph or in Article 20(6), Member States shall

explain how an equivalent level of savings, monitoring and verification is achieved. The Commission

may make suggestions for modifications in the three months following notification.

10. Without prejudice to paragraph 11, the criteria for the policy measures taken pursuant to the

second subparagraph of paragraph 9 and Article 20(6) shall be as follows: L 315/16 Official Journal of

the European Union 14.11.2012 EN

(a) the policy measures provide for at least two intermediate periods by 31 December 2020

and lead to the achievement of the level of ambition set out in paragraph 1;

(b) the responsibility of each entrusted party, participating party or implementing public

authority, whichever is relevant, is defined;

(c) the energy savings that are to be achieved are determined in a transparent manner;

(d) the amount of energy savings required or to be achieved by the policy measure are

expressed in either final or primary energy consumption, using the conversion factors set out

in Annex IV;

(e) energy savings are calculated using the methods and principles provided in points (1) and

(2) of Annex V;

(f) energy savings are calculated using the methods and principles provided in point 3 of

Annex V;

(g) an annual report of the energy savings achieved is provided by participating parties

unless not feasible and made publicly available;

(h) monitoring of the results is ensured and appropriate measures are envisaged if the

progress is not satisfactory;

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(i) a control system is put in place that also includes independent verification of a statistically

significant proportion of the energy efficiency improvement measures; and

(j) data on the annual trend of energy savings are published annually.

11. Member States shall ensure that the taxes referred to in point (a) of the second subparagraph of

paragraph 9 comply with the criteria listed in points (a), (b), (c), (d), (f), (h) and (j) of paragraph 10.

Member States shall ensure that the regulations and voluntary agreements referred to in point (c) of

the second subparagraph of paragraph 9 comply with the criteria listed in points (a), (b), (c), (d), (e),

(g), (h), (i) and (j) of paragraph 10. Member States shall ensure that the other policy measures referred

to in the second subparagraph of paragraph 9 and the Energy Efficiency National Funds referred to in

Article 20(6) comply with the criteria listed in points (a), (b), (c), (d), (e), (h), (i) and (j) of paragraph 10.

12. Member States shall ensure that when the impact of policy measures or individual actions overlaps,

no double counting of energy savings is made

Article 14

Promotion of efficiency in heating and cooling

1. By 31 December 2015, Member States shall carry out and notify to the Commission a comprehensive

assessment of the potential for the application of high-efficiency cogeneration and efficient district

heating and cooling, containing the information set out in Annex VIII. If they have already carried out

an equivalent assessment, they shall notify it to the Commission.

The comprehensive assessment shall take full account of the analysis of the national potentials for

high-efficiency cogeneration carried out under Directive 2004/8/EC.

At the request of the Commission, the assessment shall be updated and notified to the Commission

every five years. The Commission shall make any such request at least one year before the due date.

2. Member States shall adopt policies which encourage the due taking into account at local and

regional levels of the potential of using efficient heating and cooling systems, in particular those using

high-efficiency cogeneration. Account shall be taken of the potential for developing local and regional

heat markets.

3. For the purpose of the assessment referred to in paragraph 1, Member States shall carry out a cost-

benefit analysis covering their territory based on climate conditions, economic feasibility and technical

suitability in accordance with Part 1 of Annex IX. The cost-benefit analysis shall be capable of

facilitating the identification of the most resource-and cost-efficient solutions to meeting heating and

cooling needs. That cost-benefit analysis may be part of an environmental assessment under Directive

2001/42/EC of the European Parliament and of the Council of 27 June 2001 on the assessment of the

effects of certain plans and programmes on the environment (1).

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4. Where the assessment referred to in paragraph 1 and the analysis referred to in paragraph 3 identify

a potential for the application of high-efficiency cogeneration and/or efficient district heating and

cooling whose benefits exceed the costs, Member States shall take adequate measures for efficient

district heating and cooling infrastructure to be developed and/or to accommodate the development

of high-efficiency cogeneration and the use of heating and cooling from waste heat and renewable

energy sources in accordance with paragraphs 1, 5, and 7. Where the assessment referred to in

paragraph 1 and the analysis referred to in paragraph 3 do not identify a potential whose benefits

exceed the costs, including the administrative costs of carrying out the cost-benefit analysis referred

to in paragraph 5, the Member State concerned may exempt installations from the requirements laid

down in that paragraph.

5. Member States shall ensure that a cost-benefit analysis in accordance with Part 2 of Annex IX is

carried out when, after 5 June 2014:

(a) a new thermal electricity generation installation with a total thermal input exceeding 20

MW is planned, in order to assess the cost and benefits of providing for the operation of the

installation as a high-efficiency cogeneration installation;

(b) an existing thermal electricity generation installation with a total thermal input exceeding

20 MW is substantially refurbished, in order to assess the cost and benefits of converting it to

high-efficiency cogeneration;

(c) an industrial installation with a total thermal input exceeding 20 MW generating waste

heat at a useful temperature level is planned or substantially refurbished, in order to assess

the cost and benefits of utilising the waste heat to satisfy economically justified demand,

including through cogeneration, and of the connection of that installation to a district heating

and cooling network;

(d) a new district heating and cooling network is planned or in an existing district heating or

cooling network a new energy production installation with a total thermal input exceeding 20

MW is planned or an existing such installation is to be substantially refurbished, in order to

assess the cost and benefits of utilising the waste heat from nearby industrial installations.

The fitting of equipment to capture carbon dioxide produced by a combustion installation with a view

to its being geologically stored as provided for in Directive 2009/31/EC shall not be considered as

refurbishment for the purpose of points (b), (c) and (d) of this paragraph.

Member States may require the cost-benefit analysis referred to in points (c) and (d) to be carried out

in cooperation with the companies responsible for the operation of the district heating and cooling

networks.

6. Member States may exempt from paragraph 5:

(a) those peak load and back-up electricity generating installations which are planned to

operate under 1 500 operating hours per year as a rolling average over a period of five years,

based on a verification procedure established by the Member States ensuring that this

exemption criterion is met;

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(b) nuclear power installations;

(c) installations that need to be located close to a geological storage site approved under

Directive 2009/31/EC. Member States may also lay down thresholds, expressed in terms of

the amount of available useful waste heat, the demand for heat or the distances between

industrial installations and district heating networks, for exempting individual installations

from the provisions of points (c) and (d) of paragraph 5.

Member States shall notify exemptions adopted under this paragraph to the Commission by 31

December 2013 and any subsequent changes to them thereafter.

7. Member States shall adopt authorisation criteria as referred to in Article 7 of Directive 2009/72/EC,

or equivalent permit criteria, to:

(a) take into account the outcome of the comprehensive assessment referred to in

paragraph 1;

(b) ensure that the requirements of paragraph 5 are fulfilled; and

(c) take into account the outcome of cost-benefit analysis referred to in paragraph 5.

8. Member States may exempt individual installations from being required, by the authorisation and

permit criteria referred to in paragraph 7, to implement options whose benefits exceed their costs, if

there are imperative reasons of law, ownership or finance for so doing. In these cases the Member

State concerned shall submit a reasoned notification of its decision to the Commission within three

months of the date of taking it.

9. Paragraphs 5, 6, 7 and 8 of this Article shall apply to installations covered by Directive 2010/75/EU

without prejudice to the requirements of that Directive.

10. On the basis of the harmonised efficiency reference values referred to in point (f) of Annex II,

Member States shall ensure that the origin of electricity produced from high efficiency cogeneration

can be guaranteed according to objective, transparent and non-discriminatory criteria laid down by

each Member State. They shall ensure that this guarantee of origin complies with the requirements

and contains at least the information specified in Annex X. Member States shall mutually recognise

their guarantees of origin, exclusively as proof of the information referred to in this paragraph. Any

refusal to recognise a guarantee of origin as such proof, in particular for reasons relating to the

prevention of fraud, must be based on objective, transparent and non-discriminatory criteria. Member

States shall notify the Commission of such refusal and its justification. In the event of refusal to

recognise a guarantee of origin, the Commission may adopt a decision to compel the refusing party to

recognise it, in particular with regard to objective, transparent and non-discriminatory criteria on

which such recognition is based.

The Commission shall be empowered to review, by means of delegated acts in accordance with Article

23 of this Directive, the harmonised efficiency reference values laid down in Commission Implementing

Decision 2011/877/EU (1) on the basis of Directive 2004/8/EC by 31 December 2014

11. Member States shall ensure that any available support for cogeneration is subject to the electricity

produced originating from high-efficiency cogeneration and the waste heat being effectively used to

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achieve primary energy savings. Public support to cogeneration and district heating generation and

networks shall be subject to State aid rules, where applicable.

Article 15

Energy transformation, transmission and distribution

1. Member States shall ensure that national energy regulatory authorities pay due regard to energy

efficiency in carrying out the regulatory tasks specified in Directives 2009/72/EC and 2009/73/EC

regarding their decisions on the operation of the gas and electricity infrastructure.

Member States shall in particular ensure that national energy regulatory authorities, through the

development of network tariffs and regulations, within the framework of Directive 2009/72/EC and

taking into account the costs and benefits of each measure, provide incentives for grid operators to

make available system services to network users permitting them to implement energy efficiency

improvement measures in the context of the continuing deployment of smart grids.

Such systems services may be determined by the system operator and shall not adversely impact the

security of the system.

For electricity, Member States shall ensure that network regulation and network tariffs fulfil the

criteria in Annex XI, taking into account guidelines and codes developed pursuant to Regulation (EC)

No 714/2009.

2. Member States shall ensure, by 30 June 2015, that:

(a) an assessment is undertaken of the energy efficiency potentials of their gas and electricity

infrastructure, in particular regarding transmission, distribution, load management and

interoperability, and connection to energy generating installations, including access possibilities for

micro energy generators;

(b) concrete measures and investments are identified for the introduction of cost-effective energy

efficiency improvements in the network infrastructure, with a timetable for their introduction.

3. Member States may permit components of schemes and tariff structures with a social aim for net-

bound energy transmission and distribution, provided that any disruptive effects on the transmission

and distribution system are kept to the minimum necessary and are not disproportionate to the social

aim.

4. Member States shall ensure the removal of those incentives in transmission and distribution tariffs

that are detrimental to the overall efficiency (including energy efficiency) of the generation,

transmission, distribution and supply of electricity or those that might hamper participation of demand

response, in balancing markets and ancillary services procurement. Member States shall ensure that

network operators are incentivised to improve efficiency in infrastructure design and operation, and,

within the framework of Directive 2009/72/EC, that tariffs allow suppliers to improve consumer

participation in system efficiency, including demand response, depending on national circumstances.

5. Without prejudice to Article 16(2) of Directive 2009/28/EC and taking into account Article 15 of

Directive 2009/72/EC and the need to ensure continuity in heat supply, Member States shall ensure

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that, subject to requirements relating to the maintenance of the reliability and safety of the grid, based

on transparent and non-discriminatory criteria set by the competent national authorities, transmission

system operators and distribution system operators when they are in charge of dispatching the

generating installations in their territory:

(a) guarantee the transmission and distribution of electricity from high-efficiency

cogeneration;

(b) provide priority or guaranteed access to the grid of electricity from high-efficiency

cogeneration;

(c) when dispatching electricity generating installations, provide priority dispatch of electricity

from high-efficiency cogeneration in so far as the secure operation of the national electricity

system permits.

Member States shall ensure that rules relating to the ranking of the different access and dispatch

priorities granted in their electricity systems are clearly explained in detail and published. When

providing priority access or dispatch for high-efficiency cogeneration, Member States may set rankings

as between, and within different types of, renewable energy and high-efficiency cogeneration and shall

in any case ensure that priority access or dispatch for energy from variable renewable energy sources

is not hampered.

In addition to the obligations laid down by the first subparagraph, transmission system operators and

distribution system operators shall comply with the requirements set out in Annex XII.

Member States may particularly facilitate the connection to the grid system of electricity produced

from high-efficiency cogeneration from small-scale and micro-cogeneration units. Member States

shall, where appropriate, take steps to encourage network operators to adopt a simple notification

‘install and inform’ process for the installation of micro-cogeneration units to simplify and shorten

authorisation procedures for individual citizens and installers.

6. Subject to the requirements relating to the maintenance of the reliability and safety of the grid,

Member States shall take the appropriate steps to ensure that, where this is technically and

economically feasible with the mode of operation of the high-efficiency cogeneration installation, high-

efficiency cogeneration operators can offer balancing services and other operational services at the

level of transmission system operators or distribution system operators. Transmission system

operators and distribution system operators shall ensure that such services are part of a services

bidding process which is transparent, non-discriminatory and open to scrutiny. Where appropriate,

Member States may require transmission system operators and distribution system operators to

encourage high-efficiency cogeneration to be sited close to areas of demand by reducing the

connection and use-of system charges.

7. Member States may allow producers of electricity from high-efficiency cogeneration wishing to be

connected to the grid to issue a call for tender for the connection work.

8. Member States shall ensure that national energy regulatory authorities encourage demand side

resources, such as demand response, to participate alongside supply in wholesale and retail markets.

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Subject to technical constraints inherent in managing networks, Member States shall ensure that

transmission system operators and distribution system operators, in meeting requirements for

balancing and ancillary services, treat demand response providers, including aggregators, in a non-

discriminatory manner, on the basis of their technical capabilities.

Subject to technical constraints inherent in managing networks, Member States shall promote access

to and participation of demand response in balancing, reserve and other system services markets, inter

alia by requiring national energy regulatory authorities or, where their national regulatory systems so

require, transmission system operators and distribution system operators in close cooperation with

demand service providers and consumers, to define technical modalities for participation in these

markets on the basis of the technical requirements of these markets and the capabilities of demand

response. Such specifications shall include the participation of aggregators.

9. When reporting under Directive 2010/75/EU, and without prejudice to Article 9(2) of that Directive,

Member States shall consider including information on energy efficiency levels of installations

undertaking the combustion of fuels with total rated thermal input of 50 MW or more in the light of

the relevant best available techniques developed in accordance with Directive 2010/75/EU and

Directive 2008/1/EC of the European Parliament and of the Council of 15 January 2008 concerning

integrated pollution prevention and control (1).

Member States may encourage operators of installations referred to in the first subparagraph to

improve their annual average net operational rates.

( 1) OJ L 24, 29.1.2008, p. 8

Article 18

Energy services

1. Member States shall promote the energy services market and access for SMEs to this market by:

(a) disseminating clear and easily accessible information on:

(i) available energy service contracts and clauses that should be included in such

contracts to guarantee energy savings and final customers’ rights;

(ii) financial instruments, incentives, grants and loans to support energy efficiency

service projects;

(b) encouraging the development of quality labels, inter alia, by trade associations;

(c) making publicly available and regularly updating a list of available energy service providers

who are qualified and/or certified and their qualifications and/or certifications in accordance

with Article 16, or providing an interface where energy service providers can provide

information;

(d) supporting the public sector in taking up energy service offers, in particular for building

refurbishment, by:

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(i) providing model contracts for energy performance contracting which include at

least the items listed in Annex XIII;

(ii) providing information on best practices for energy performance contracting,

including, if available, cost benefit analysis using a life-cycle approach;

(e) providing a qualitative review in the framework of the National Energy Efficiency Action

Plan regarding the current and future development of the energy services market.

2. Member States shall support the proper functioning of the energy services market, where

appropriate, by:

(a) identifying and publicising point(s) of contact where final customers can obtain the

information referred to in paragraph 1;

(b) taking, if necessary, measures to remove the regulatory and non-regulatory barriers that

impede the uptake of energy performance contracting and other energy efficiency service

models for the identification and/or implementation of energy saving measures;

(c) considering putting in place or assigning the role of an independent mechanism, such as

an ombudsman, to ensure the efficient handling of complaints and out-of court settlement of

disputes arising from energy service contracts;

(d) enabling independent market intermediaries to play a role in stimulating market

development on the demand and supply sides.

3. Member States shall ensure that energy distributors, distribution system operators and retail energy

sales companies refrain from any activities that may impede the demand for and delivery of energy

services or other energy efficiency improvement measures, or hinder the development of markets for

such services or measures, including foreclosing the market for competitors or abusing dominant

positions.

Article 24

Review and monitoring of implementation

1. By 30 April each year as from 2013, Member States shall report on the progress achieved towards

national energy efficiency targets, in accordance with Part 1 of Annex XIV. The report may form part

of the National Reform Programmes referred to in Council Recommendation 2010/410/EU of 13 July

2010 on broad guidelines for the economic policies of the Member States and of the Union (1).

2. By 30 April 2014, and every three years thereafter, Member States shall submit National Energy

Efficiency Action Plans. The National Energy Efficiency Action Plans shall cover significant energy

efficiency improvement measures and expected and/ or achieved energy savings, including those in

the supply, transmission and distribution of energy as well as energy end-use, in view of achieving the

national energy efficiency targets referred to in Article 3(1). The National Energy Efficiency Action Plans

shall be complemented with updated estimates of expected overall primary energy consumption in

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2020, as well as estimated levels of primary energy consumption in the sectors indicated in Part 1 of

Annex XIV.

The Commission shall, by 31 December 2012, provide a template as guidance for the National Energy

Efficiency Action Plans. That template shall be adopted in accordance with the advisory procedure

referred to in Article 26(2). The National Energy Efficiency Action Plans shall in any case include the

information specified in Annex XIV.

3. The Commission shall evaluate the annual reports and the National Energy Efficiency Action Plans

and assess the extent to which Member States have made progress towards the achievement of the

national energy efficiency targets required by Article 3(1) and towards the implementation of this

Directive. The Commission shall send its assessment to the European Parliament and the Council. Based

on its assessment of the reports and the National Energy Efficiency Action Plans, the Commission may

issue recommendations to Member States.

4. The Commission shall monitor the impact of implementing this Directive on Directives 2003/87/EC,

2009/28/EC and 2010/31/EU and Decision No 406/2009/EC, and on industry sectors, in particular

those that are exposed to a significant risk of carbon leakage as determined in Decision 2010/2/EU.

5. The Commission shall review the continued need for the possibility of exemptions set out in Article

14(6) for the first time in the assessment of the first National Energy Efficiency Action Plan and every

three years thereafter. Where the review shows that any of the criteria for these exemptions can no

longer be justified taking into account the availability of heat load and the real operating conditions of

the exempted installations, the Commission shall propose appropriate measures.

6. Member States shall submit to the Commission before 30 April each year statistics on national

electricity and heat production from high and low efficiency cogeneration, in accordance with the

methodology shown in Annex I, in relation to total heat and electricity production. They shall also

submit annual statistics on cogeneration heat and electricity capacities and fuels for cogeneration, and

on district heating and cooling production and capacities, in relation to total heat and electricity

production and capacities. Member States shall submit statistics on primary energy savings achieved

by application of cogeneration in accordance with the methodology shown in Annex II.

7. By 30 June 2014 the Commission shall submit the assessment referred to in Article 3(2) to the

European Parliament and to the Council, accompanied, if necessary, by proposals for further measures.

8. The Commission shall review the effectiveness of the implementation of Article 6 by 5 December

2015, taking into account the requirements laid down in Directive 2004/18/EC and shall submit a

report to the European Parliament and the Council. That report shall be accompanied, if appropriate,

by proposals for further measures.

9. By 30 June 2016, the Commission shall submit a report to the European Parliament and the Council

on the implementation of Article 7. That report shall be accompanied, if appropriate, by a legislative

proposal for one or more of the following purposes:

(a) to change the final date laid down in Article 7(1);

(b) to review the requirements laid down in Article 7(1), (2) and (3);

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(c) to establish additional common requirements, in particular as regards the matters referred

to in Article 7(7).

10. By 30 June 2018, the Commission shall assess the progress made by Member States in removing

the regulatory and non-regulatory barriers referred to in Article 19(1). This assessment shall be

followed, if appropriate, by proposals for further measures.

11. The Commission shall make the reports referred to in paragraphs 1 and 2 publicly available.

ANNEXES I and II of the EED

ΑΝΝΕΧΙ

GENERAL PRINCIPLES FOR THE CALCULATION OF ELECTRICITY FROM COGENERATION

Part I

General Principles

Values used for calculation of electricity from cogeneration shall be determined on the basis of the

expected or actual operation of the unit under normal conditions of use. For micro- cogeneration units

the calculation may be based on certified values.

(a) Electricity production from cogeneration shall be considered equal to total annual

electricity production of the unit measured at the outlet of the main generators;

(i) in cogeneration units of types (b), (d), (e), (f), (g) and (h) referred to in Part II with an annual overall efficiency set by Member States at a level of at least 75%, and

(ii) in cogeneration units of types (a) and (c) referred to in Part II with an annual overall efficiency set by Member States at a level of at least 80%.

(b) In cogeneration units with an annual overall efficiency below the value referred to in point

(i) of point (a) (cogeneration units of types (b), (d), (e), (f), (g), and (h) referred to in Part II) or

with an annual overall efficiency below the value referred to in point (ii) of point (a)

(cogeneration units of types (a) and (c) referred to in Part II) cogeneration is calculated

according to the following formula:

E CHP =H CHP *C

where:

E CHP is the amount of electricity from cogeneration;

C is the power-to-heat ratio;

H CHP is the amount of useful heat from cogeneration (calculated for this purpose as total heat

production minus any heat produced in separate boilers or by live steam extraction from the

steam generator before the turbine).

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The calculation of electricity from cogeneration must be based on the actual power-to-heat ratio. If

the actual power- to-heat ratio of a cogeneration unit is not known, the following default values may

be used, in particular for statistical purposes, for units of types (a), (b), (c), (d) and (e) referred to in

Part II provided that the calculated cogeneration electricity is less or equal to total electricity

production of the unit:

Table 8 Default power to heat ratio for different types of CHP plants according to the EED directive

Type of the unit Default power to heat ratio

Combined cycle gas turbine with heat recovery 0.95 Steam back pressure turbine 0.45 Steam condensing extraction turbine 0.45 Gas turbine with heat recovery 0.55 Internal combustion engine 0.75

If Member States introduce default values for power-to-heat ratios for units of types (f), (g), (h), (i), (j)

and (k) referred to in Part II, such default values shall be published and shall be notified to the

Commission.

(c) If a share of the energy content of the fuel input to the cogeneration process is recovered

in chemicals and recycled this share can be subtracted from the fuel input before calculating

the overall efficiency used in points (a) and (b).

(d) Member States may determine the power-to-heat ratio as the ratio of electricity to useful

heat when operating in cogeneration mode at a lower capacity using operational data of the

specific unit.

(e) Member States may use other reporting periods than one year for the purpose of the

calculations according to points (a) and (b).

Part IΙ

Cogeneration technologies covered by this Directive

(a) Combined cycle gas turbine with heat recovery

(b) Steam back pressure turbine

(c) Steam condensing extraction turbine

(d) Gas turbine with heat recovery

(e) Internal combustion engine

(f) Microturbines

(g) Stirling engines

(h) Fuel cells

(i) Steam engines

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(j) Organic Rankine cycles

(k) Any other type of technology or combination thereof falling under the definition laid down in Article 2(30).

When implementing and applying the general principles for the calculation of electricity from

cogeneration, Member States shall use the detailed Guidelines established by Commission Decision

2008/952/EC of 19 November 2008 establishing detailed guidelines for the implementation and

application of Annex II to Directive 2004/8/EC of the European Parliament and of the Council ( 1 ).

1) OJ L 338, 17.12.2008, p. 55.

ΑΝΝΕΧΙI

METHODOLOGY FOR DETERMINING THE EFFICIENCY OF THE COGENERATION PROCESS

Values used for calculation of efficiency of cogeneration and primary energy savings shall be

determined on the basis of the expected or actual operation of the unit under normal conditions of use.

(a) High-efficiency cogeneration

For the purpose of this Directive high-efficiency cogeneration shall fulfil the following criteria:

— cogeneration production from cogeneration units shall provide primary energy savings calculated according to point (b) of at least 10% compared with the references for separate production of heat and electricity,

— production from small-scale and micro-cogeneration units providing primary energy savings may qualify as high- efficiency cogeneration.

(b) Calculation of primary energy savings

The amount of primary energy savings provided by cogeneration production defined in accordance

with Annex I shall be calculated on the basis of the following formula:

1PES 1 100%

CHP Hη CHP Εη+

Ref Ηη Ref Εη

(1)

Where:

PES is primary energy savings.

CHP Hη is the heat efficiency of the cogeneration production defined as annual useful heat output

divided by the fuel input used to produce the sum of useful heat output and electricity from

cogeneration.

Ref Hη is the efficiency reference value for separate heat production.

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CHP Eη is the electrical efficiency of the cogeneration production defined as annual electricity from

cogeneration divided by the fuel input used to produce the sum of useful heat output and electricity

from cogeneration. Where a cogeneration unit generates mechanical energy, the annual electricity

from cogeneration may be increased by an additional element representing the amount of electricity

which is equivalent to that of mechanical energy. This additional element does not create a right to

issue guarantees of origin in accordance with Article 14(10).

Ref Eη is the efficiency reference value for separate electricity production.

(c) Calculations of energy savings using alternative calculation

Member States may calculate primary energy savings from a production of heat and electricity and

mechanical energy as indicated below without applying Annex I to exclude the non-cogenerated heat

and electricity parts of the same process. Such a production can be regarded as high-efficiency

cogeneration provided it fulfils the efficiency criteria in point (a) of this Annex and, for cogeneration

units with an electrical capacity larger than 25 MW, the overall efficiency is above 70%. However,

specification of the quantity of electricity from cogeneration produced in such a production, for issuing

a guarantee of origin and for statistical purposes, shall be determined in accordance with Annex I.EN

14.11.2012 Official Journal of the European Union L 315/31

If primary energy savings for a process are calculated using alternative calculation as indicated above

the primary energy savings shall be calculated using the formula in point (b) of this Annex replacing:

‘CHP Hη’ with ‘Hη’ and ‘CHP Eη’ with ‘Eη’, where:

Hη shall mean the heat efficiency of the process, defined as the annual heat output divided by the fuel

input used to produce the sum of heat output and electricity output.

Eη shall mean the electricity efficiency of the process, defined as the annual electricity output divided

by the fuel input used to produce the sum of heat output and electricity output. Where a cogeneration

unit generates mechanical energy, the annual electricity from cogeneration may be increased by an

additional element representing the amount of electricity which is equivalent to that of mechanical

energy. This additional element will not create a right to issue guarantees of origin in accordance with

Article 14(10).

(d) Member States may use other reporting periods than one year for the purpose of the calculations

according to points (b) and (c) of this Annex.

(e) For micro-cogeneration units the calculation of primary energy savings may be based on certified

data.

(f) Efficiency reference values for separate production of heat and electricity

The harmonised efficiency reference values shall consist of a matrix of values differentiated by relevant

factors, including year of construction and types of fuel, and must be based on a well-documented

analysis taking, inter alia, into account data from operational use under realistic conditions, fuel mix

and climate conditions as well as applied cogeneration technologies.

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The efficiency reference values for separate production of heat and electricity in accordance with the

formula set out in point (b) shall establish the operating efficiency of the separate heat and electricity

production that cogeneration is intended to substitute.

The efficiency reference values shall be calculated according to the following principles:

1. For cogeneration units the comparison with separate electricity production shall be based on the

principle that the same fuel categories are compared.

2. Each cogeneration unit shall be compared with the best available and economically justifiable

technology for separate production of heat and electricity on the market in the year of construction of

the cogeneration unit.

3. The efficiency reference values for cogeneration units older than 10 years of age shall be fixed on

the reference values of units of 10 years of age.

4. The efficiency reference values for separate electricity production and heat production shall reflect

the climatic differences between Member States.

As far as the definition of high-efficiency cogeneration, according to Article 38 and 39 of the directive,

Remarks of high-efficiency cogeneration, according to Paragraphs 38 and 39 of Article 1 of the EED

(38) High-efficiency cogeneration should be defined by the energy savings obtained by combined

production instead of separate production of heat and electricity. The definitions of cogeneration and

high-efficiency cogeneration used in Union legislation should be without prejudice to the use of

different definitions in national legislation for purposes other than those of the Union legislation in

question. To maximise energy savings and avoid energy saving opportunities being missed, the

greatest attention should be paid to the operating conditions of cogeneration units.

(39) To increase transparency for the final customer to be able to choose between electricity from

cogeneration and electricity produced by other techniques, the origin of high-efficiency cogeneration

should be guaranteed on the basis of harmonised efficiency reference values. Guarantee of origin

schemes do not by themselves imply a right to benefit from national support mechanisms. It is

important that all forms of electricity produced from high-efficiency cogeneration can be covered by

guarantees of origin. Guarantees of origin should be distinguished from exchangeable certificates

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APPENDIX B-Calculation example of Primary Energy Savings of a CHP

plant according to the EED methodology

Application for the Aluminium of Greece S.A. cogeneration plant

Case 1: condensate return excluded from useful heat

The cogeneration plant consists of 2 GT’s, two Heat Recovery Steam Generators and one ST and

produces electricity and high pressure (HP) and medium pressure(MP) steam for covering the heat

demand of the alumina/aluminium production. In the typical plant operation, the total gross electricity

generation in one hour is:

6.134EC MWh

The HP and MP steam sent to the alumina/aluminium factory, the returned condensate from the heat

consumer and the make-up water have a heat content of:

8.146QHP MWh, 8.38QMP MWh, 5.41QCON MWh, 6.0Q .U.M MWh

Thus, the useful cogeneration heat HCHP is calculated from the equation:

6.1446.05.418.388.146QQQQH .U.MCONMPHPCHP MWh

The fuel heat input to the gas turbines, FC, is:

6.390Fc MWh

The electrical, thermal and total efficiency of the cogeneration plant are calculated by the following

equations:

45.346.390

6.134

C

Cel

F

E %, 01.37

6.390

6.144

C

CHPth

F

H %

46.71 thelTOT %

According to the Greek legal status and calculation methodology, which is according to the European

directives, in order for a cogeneration plant to be high-efficiency CHP, it should have a Primary Energy

Savings Ratio (PESR) higher than 10%, with respect to the separate electricity and heat generation.

Furthermore, not all the produced electricity is regarded as CHP electricity, unless the total efficiency

is higher than a threshold value, otherwise the electricity is split into two parts, the cogeneration

electricity ECHP and the non-cogeneration electricity Enon-CHP. The calculation of ECHP is based on the

calculation of the coefficient C, which is calculated from Emax, which is the maximum electricity that

could be produced from the cogeneration plant if steam extractions were eliminated. For the case

under consideration, Emax is 187.6 MWh, while the cogeneration efficiency, nCHP, is taken as the

threshold value in the calculations, since the total efficiency is below 75%:

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114

03.486.390

6.187maxmax,

Ce

F

E %

367.06.144

6.1346.187

H

E

CHP

Cmax

761.003.4875

75367.003.48

max,

max,

eCHP

CHPeC

For the particular power plant, the reference efficiencies for the separate electricity and heat

generation are defined as:

%51.51er , 85hr %

The cogeneration and non-cogeneration electricity generation are calculated by the following

equations:

0.1106.144761.0HCE CHPCHP MWh

6.240.1106.134EEE CHPCCHPnon MWh

While the fuel input for the cogeneration and non-cogeneration part is provided by the equations:

4.33975.0

6.1440.110

n

HEF

CHP

CHPCHPCHP

MWh

2.514.3396.390FFF CHPCCHPnon MWh

And the electrical and thermal efficiency of the cogeneration part are:

40.324.339

0.110,

CHP

CHPCHPe

F

E % and 60.42

4.339

6.144,

CHP

CHPCHPh

F

H %

The corresponding primary energy saving ratio (PESR) is calculated by the formula:

4.9

85

01.37

51.51

45.34

11

11

hr

th

er

elPESR

<10%

While

5.11

85

60.42

51.51

40.32

11

11

,,

hr

CHPh

er

CHPeCHPPESR

>10%

Therefore, the plant produces 110 MWh of high-efficiency cogeneration electricity (PESRCHP>10%),

that are paid with a feed-in tariff, and 24.6 MWh of non-CHP electricity, that are paid with the system

marginal price.

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40.324.339

0.110,

CHP

CHPCHPe

F

E % and 60.42

4.339

6.144,

CHP

CHPCHPh

F

H %

The corresponding primary energy saving ratio (PESR) is calculated as follows:

4.9

85

01.37

51.51

45.34

11

11

hr

th

er

elPESR

%

%105.11

85

60.42

51.51

40.32

11

11

,,

hr

CHPh

er

CHPeCHPPESR

Case 2: condensate return included in useful heat

In this case, the useful cogeneration heat HCHP is calculated from the equation:

6.1858.388.146QQH MPHPCHP MWh

The electrical, thermal and total efficiency of the cogeneration plant are calculated by the following

equations:

45.346.390

6.134

F

E

C

Cel %, 52.47

6.390

6.185

F

H

C

CHPth %

97.81thelTOT %

Since the total efficiency is higher than the threshold value (75%), the cogeneration efficiency, nCHP, is

equal to the calculated total efficiency:

03.486.390

6.187

F

E

C

maxmax,e %

286.06.185

6.1346.187

H

E

CHP

Cmax

725.003.4897.81

97.81286.003.48C

max,eCHP

CHPmax,e

For the particular power plant, the reference efficiencies for the separate electricity and heat

generation are defined as:

%51.51er , 90hr %

The cogeneration and non-cogeneration electricity generation are calculated by the following

equations:

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6.1346.185725.0HCE CHPCHP MWh

06.1346.134EEE CHPCCHPnon MWh

While the fuel input for the cogeneration and non-cogeneration part is provided by the equations:

6.3908197.0

6.1856.134HEF

CHP

CHPCHPCHP

MWh

06.3906.390FFF CHPCCHPnon MWh

And the electrical and thermal efficiency of the cogeneration part are:

45.346.390

6.134

F

E

CHP

CHPCHP,e % and 52.47

6.390

6.185

F

H

CHP

CHPCHP,h %

The corresponding primary energy saving ratio (PESR) is calculated by the formula:

4.16

90

52.47

51.51

45.34

11

11PESR

hr

th

er

el

>10%

While

4.16

90

52.47

51.51

45.34

11

11PESR

hr

CHP,h

er

CHP,eCHP

>10%

Therefore, the plant produces 134.6MWh of high-efficiency cogeneration electricity (PESRCHP>10%),

that are paid with a feed-in tariff.