The EU Clean Energy Package.
Date: 2020-11-13
Institutions: Robert Schuman Centre for Advanced Studies
Subjects: EU energy policy, clean technology, energy efficiency, energy law, energy production, energy storage, price regulations, renewable energy

AUTHORS

ATHIR NOUICER
LEONARDO MEEUS 

TECHNICAL
REPORT

OCTOBER
2019

THE EU CLEAN 
ENERGY PACKAGE

(2019 ed.)

 
© European University Institute, 2019 
This text may be downloaded only for personal research purposes. Any additional reproduction for other 
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and not those of the European University Institute. 

QM-02-19-812-EN-N 

ISBN:978-92-9084-794-6 

doi:10.2870/33236 

© Athir Nouicer, Leonardo Meeus, 2019 
European University Institute 
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I – 50014 San Domenico di Fiesole (FI) Italy 
fsr.eui.eu 
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cadmus.eui.eu 

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Robert Schuman Centre for Advanced Studies 
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Brigid Laffan, aims to develop inter-disciplinary and comparative research on the major issues facing the 
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has developed a strong core of general regulatory topics and concepts as well as inter-sectoral discussion 
of regulatory practices and policies. 

For more information: fsr.eui.eu 

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ABSTRACT  

The EU Clean Energy Package, proposed by the European Commission in November 2016, includes eight 
legislative  texts  on  the  electricity  market  and  consumers,  Energy  Efficiency  and  Energy  Efficiency  of 
buildings, Renewables & bioenergy sustainability as well as governance of the Energy Union. They were 
all published in the Official Journal of the European Union by June 2019. In this report, we will focus on 
two of the eight legislative texts; the Directive on common rules for the internal market in electricity (e-
Directive)  and the  Regulation on the  internal market for electricity (e-Regulation).  We will assess their 
impact on the European internal electricity market rules compared to the framework established by the 
Third Energy Package, including the first generation of network codes. In the different topics, we present 
the final versions of the CEP provisions and highlight the main differences compared to initial proposals of 
the Commission. 

The  structure  of  this  report  follows  the  structure of the  Clean  Energy Package  online  course.  The  first 
section on Electricity Markets is ‘Ensuring the internal market level playing field.’ The second section on 
Electricity Grids is ‘Adapting to the decentralization of the power system.’ The third, on the New Deal, is 
‘Empowering customers and citizens.’ 

Keywords:  European  regulation,  public  interventions  in  electricity  prices,  network  tariffs,  capacity 
mechanisms,  network  codes,  bidding  zones,  interconnectors  capacity,  EV  charging  infrastructure, 
electricity storage, DSO planning, DSO active network management, procurement of flexibility services, 
TSO-DSO coordination, EU DSO entity, active customers, smart metering, dynamic pricing, aggregators, 
citizens energy communities 

Note: This report is an updated version of ‘Meeus and Nouicer, 2018’. The EU Clean Energy Package. FSR 
Technical report. July 2018. ’’  

This  version  of  the  report  includes  the  provisions  from  the  final  text  of  the  electricity  Directive  and 
Regulation of the Clean Energy Package. It updates the previous version that was based on the Commission 
and Council positions. 

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Content 

List of Figures and Tables .............................................................................................................................. 8 

Abbreviations ................................................................................................................................................ 9 

Acknowledgments ....................................................................................................................................... 12 

Introduction ................................................................................................................................................. 13 

1. Ensuring the internal market level playing field...................................................................................... 14 

1.1. 

1.2. 

Setting the scene: the different components of the electricity bill ............................................ 14 

Limiting public interventions in electricity market prices ........................................................... 15 

1.2.1 

Current practices ................................................................................................................. 16 

1.2.2.  Measures for limiting public intervention in electricity market prices ............................... 17 

1.2.3. 

Transitional measures for limiting public intervention in electricity market prices ........... 17 

1.3.  Methodologies for network tariffs .............................................................................................. 21 

1.3.1. 

Current practices ................................................................................................................. 21 

1.3.2. 

Principles for network tariffs design in the CEP .................................................................. 22 

1.4. 

Limiting the use of capacity mechanisms .................................................................................... 24 

1.4.1. 

Fundamentals of Capacity Mechanisms .............................................................................. 24 

1.4.2. 

Current implementation practices in capacity mechanisms ............................................... 25 

1.4.3. 

Current practices in adequacy assessments ....................................................................... 27 

1.4.4. 

Limiting the introduction of capacity mechanisms ............................................................. 28 

1.4.5. 

Limiting discrimination between existing versus alternative resources ............................. 33 

1.4.6. 

Limiting the impacts on climate goals ................................................................................. 34 

1.5. 

Interlinkage with Network codes ................................................................................................ 35 

1.5.1. 

Balancing responsibilities .................................................................................................... 36 

1.5.2. 

System operation regional governance .............................................................................. 37 

1.5.3. 

Bidding zones and capacity calculation between zones ..................................................... 39 

2. Adapting to the decentralisation of the power system .......................................................................... 46 

2.1. 

2.2. 

Setting the scene: The DSO landscape ........................................................................................ 46 

Current practices ......................................................................................................................... 47 

2.2.1. 

Traditional Roles .................................................................................................................. 47 

2.2.2. 

Emerging Roles .................................................................................................................... 50 

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2.3. 

Increased expectations for DSOs in their traditional roles ......................................................... 52 

2.3.1.  Measures for DSOs network planning ................................................................................. 52 

2.3.2.  Measure to incentivize DSOs to procure flexibility services ............................................... 54 

2.4. 

Limiting the role of DSOs in emerging businesses ...................................................................... 55 

2.4.1. 

Limiting DSOs’ ownership of EV charging facilities ............................................................. 56 

2.4.2. 

Limiting DSOs ownership of storage facilities ..................................................................... 57 

2.4.3. 

Neutral DSOs role in data management.............................................................................. 58 

2.5. 

The EU DSO entity ....................................................................................................................... 59 

2.5.1. 

Establishment of the EU DSO entity .................................................................................... 59 

2.5.2. 

Tasks of the EU DSO Entity .................................................................................................. 60 

2.6. 

Interlinkage with Network Codes ................................................................................................ 62 

2.6.1. 

The second generation of network codes and guidelines ................................................... 62 

2.6.2. 

Stakeholders’ roles in network codes development process .............................................. 65 

2.6.3. 

The new adoption process for network codes and guidelines............................................ 66 

3. Empowering customers and citizens ....................................................................................................... 68 

3.1. 

Setting the scene: From Demand Response to energy communities ......................................... 68 

3.2.  New rights for active customers ................................................................................................. 70 

3.2.1. 

Self-consumption ................................................................................................................ 70 

3.2.2. 

Smart metering systems ...................................................................................................... 72 

3.2.3. 

Data access and management ............................................................................................. 76 

3.2.4. 

Dynamic pricing ................................................................................................................... 78 

3.3.  Market entry for new customer intermediaries ......................................................................... 80 

3.3.1. 

Aggregators ......................................................................................................................... 81 

3.3.2. 

Citizens Energy Communities .............................................................................................. 83 

Bibliography ................................................................................................................................................. 88 

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List of Figures and Tables 

Figure 1: End-user electricity prices breakdown of incumbents’ standard offers for households in EU 
capital cities ................................................................................................................................................. 14 
Figure 2: Weighted average breakdown of end-user electricity price components in EU capital cities .... 15 
Figure 3: Application of regulated prices for households as of June 2019 ................................................. 16 
Figure 4: Status quo on energy and capacity transmission tariffs components among MSs ..................... 21 
Figure 5: Status quo on energy and capacity distribution tariffs components among MSs ....................... 22 
Figure 6: Taxonomy of capacity mechanisms ............................................................................................. 24 
Figure 7: CMs implementation in Europe ................................................................................................... 26 
Figure 8: New framework for Capacity Mechanisms implementation ....................................................... 33 
Figure 9: Emission limit (550 g CO2/ kWh) in CMs (Article 22) ................................................................... 34 
Figure 10: Services provided by RSCs to TSOs ............................................................................................. 37 
Figure 11: Left – The Capacity Calculation Regions (CCRs), status as on the 1st of January 2019 Right – 
Map of the Regional Security Coordinators in Europe as established by the end of 2016......................... 38 
Figure 12: Sequence of ROCs functions ...................................................................................................... 39 
Figure 13: New bidding zones configuration in Europe as of May 2019 ..................................................... 41 
Figure 14: Breakdown of the transmission capacity ................................................................................... 44 
Figure 15: Number of electricity DSOs per Member State ......................................................................... 46 
Figure 16: Logical Framework for DSO Activities ........................................................................................ 47 
Figure 17: Published distribution network development plans (DNDP) ..................................................... 48 
Figure 18: The saving network expansion by the curtailment of RES energy ............................................. 48 
Figure 19: Flexibility pilot projects in EU ..................................................................................................... 50 
Figure 20: Responsible parties for access to metering data ....................................................................... 52 
Figure 21: A one-system approach for flexibility procurement .................................................................. 55 
Figure 22: Main stages of the EU DSO establishment ................................................................................. 60 
Figure 23: Adoption as implementing acts.................................................................................................. 64 
Figure 24: Adoption as delegated acts ........................................................................................................ 65 
Figure 25: Theoretical demand response potential 2030 (in MW) ............................................................. 68 
Figure 26: Demand-Side Engagement ......................................................................................................... 69 
Figure 27: Electricity smart meter roll-out rates in EU MSs (and Norway) – 2017 (%) ............................... 73 
Figure 28: Target year by when the 80 % rate of electricity smart meters will be reached in EU MSs– as of 
end 2017 ...................................................................................................................................................... 74 
Figure 29: Methods of dynamic pricing for electricity ................................................................................ 78 
Figure 30: Share of standard household consumers supplied under dynamic pricing (DP) ....................... 79 
Figure 31: Independent aggregators’ access to markets ............................................................................ 81 
Figure 32: EU groups or cooperatives of citizens on renewable energy, energy efficiency, and e-mobility
 ..................................................................................................................................................................... 84 

Table 1: Probabilistic Vs Deterministic approaches to adequacy assessments .......................................... 27 
Table 2: MSs practice in setting a reliability standard ................................................................................ 28 

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Abbreviations 

ACER: Agency for Cooperation of Energy Regulators, also called the agency 

Art: Article 

BEUC: The European Consumer Organisation 

BRP: Balance responsible party 

BSP: Balance service provider 

BZ : Bidding zone 

CA: Capacity auction  

CACM: Regulation establishing a guideline on capacity allocation and congestion management 

CBA: cost-benefit analysis  

CCP: Critical peak pricing  

CEC: Citizens Energy Community 

CEDEC: The European Federation of Local Energy Companies 

CEP: Clean Energy Package 

CEER: Council of European Energy Regulators 

CHP: Combined Heat and Power 

CM: Capacity mechanism 

CO: Capacity obligation  

CO2: Carbon dioxide 

CRM: Capacity remuneration mechanism 

CP: Capacity Payments  

DCC: Regulation establishing a network code on demand connection  

DEP: Data Exchange Platform 

DER: Distributed Energy Resources 

DNDP: Distribution network development plan  

DP: Dynamic pricing 

DR: Demand Response 

DSO: Distribution System Operator 

EB GL: Regulation establishing a guideline on electricity balancing 

EC: European Commission 

EDSO for Smart Grids: Distribution System Operators' Association for Smart Grids 

FBCC: Flow-based capacity calculation  

EIF: Entry into force 

ENTSO-E: European Network of Transmission System Operators for Electricity 

EENS: Expected energy not served  

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EFET: European Federation of Energy Traders 

EP: European Parliament 

EPOV : European Energy Poverty Observatory  

EPS : Emission Performance Standard  

E-Directive: The Directive on common rules for the internal market in electricity (final text) 

E-Regulation: The electricity Regulation on the internal market for electricity (final text) 

EU: European Union 

EURELECTRIC: The Union of the Electricity Industry  

Europex: Association of European Energy Exchanges 

EV: Electric vehicle  

FCA: Regulation establishing a guideline on forward capacity allocation  

FSR: Florence School of Regulation 

GB: Great Britain 

Gr: Gram 

HVDC NC: Regulation establishing a network code on requirements for grid connection of high voltage 
direct current systems and direct current-connected power park modules  

IEM: Internal Energy Market 

kW: Kilowatt 

kWh: Kilowatt hour 

LEC: Local energy community 

LOLE: Loss of load expectation  

LOLP: Loss of load probability 

MMR: Market Monitoring Report 

MS: Member State 

MW: Megawatt 

MWh: Megawatt-hour 

NC: Network code 

NC ER: Regulation establishing a network code on electricity emergency and restoration 

NIS Directive: The Directive on security of network and information systems (NIS Directive) 

NRA: National Regulatory Authority 

NTC: Net transfer capacity  

Ofgem: Office of Gas and Electricity Markets (UK) 

OJ: Official Journal of the European Union 

RE: Renewable energy 

REScoop: European federation of renewable energy cooperatives 

RES-E: Electricity from Renewable Energy Sources  

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RfG NC: Regulation establishing a network code on requirements for grid connection of generators  

RO: Reliability options  

ROC: Regional Operation Centre  

RSC: Regional Security Coordinators 

RSCI: Regional Security Coordination Initiatives 

SEDC: Smart Energy Demand Coalition 

SO: System operation 

SO GL: Regulation establishing a guideline on electricity transmission system operation 

SoS: Security of supply 

SR: Strategic reserve  

T&L: taxes and levies 

TFEU: Treaty on the Functioning of the European Union 

ToU: Time of Use  

TSO: transmission system operator 

UK: United Kingdom 

VAT: Value-Added Tax 

VOLL: Value of Lost Load  

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Acknowledgments 

This report was developed for the online course on the EU Clean Energy Package at the Florence School of 
Regulation, directed by Prof Leonardo Meeus. Participants from the course were invited to contribute to 
the text, and many of them did so very actively. The second edition of this course welcomed more than 90 
participants from 26 countries, most of them senior professionals from the private and public sector. The 
course had an 80% completion rate with 24 participants reaching the master level of excellence.   

We are very grateful for the insights and remarks of Erik Ahlström, Alia Al-hathloul, Joanna Bolesta, Marco 
Campagna,  Žilvinas  Dragūnas,  Lars  Olav  Fosse,  Bastian  Henze,  Patrícia  Lages,  Lenka  Jancova,  Louise 
Nørring and Ellen Valkenborgs. 

Disclaimer: The authors are responsible for any errors or omissions. The underlined text in this report, 
reflects the authors’ selected important points. 

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Introduction 

The  adoption  process  of  the  Clean  Energy  Package  (CEP),  composed  of  four  Directives  and  four 
Regulations, was completed in June 2019 after the publication of the last legislative texts in the Official 
Journal (OJ)1. The CEP was proposed by the European Commission (EC) in November 2016. The European 
Council published its agreed negotiating position on these proposals in December 20172 for the ‘trialogue’ 
negotiations that continued until the end of 2018. The CEP Regulations entry into force (EIF) was on the 
twentieth  day  following  their  publication  in the OJ,  corresponding  to  the  4th  of  July  2019.  The  date  of 
application  for the Regulation  on the  internal market for electricity (e-Regulation)  is the 1st  of  January 
2020.  The  provisions  of  Directive  on  common  rules  for  the  internal  market  in  electricity  (e-Directive), 
representing substantive amendments with regard to Directive 2009/72/EC, will have to be transposed 
into national law within 18 months from the Directive’s publication. 

The Commission shall review the e-Directive implementation and the e-Regulation by 31 December 2025 
and 31 December 2030, respectively. It shall submit a report, regarding the e-Directive and e-Regulation 
to the European Parliament and the Council, accompanied by a legislative proposal where appropriate. 
The  Commission's  review  of  the  e-Directive  shall  assess,  in  particular,  whether  customers,  especially 
energy poor or vulnerable ones, are adequately protected. 

This  report  focuses  on  two of  the  eight  legislative  texts;  the  e-Directive  and  the  e-Regulation.  We  will 
assess  their  impact  on  the  European  internal  electricity  market  rules  compared  to  the  framework 
established by the Third Energy Package, including the first generation of network codes. In the different 
topics, we present the final versions of the CEP provisions and highlight the main differences compared to 
initial proposals of the Commission. 

The structure of this text follows the structure of the online course. The first section on Electricity Markets 
is ‘Ensuring the internal market level playing field.’ The second section on Electricity Grids is ‘Adapting to 
the decentralization of the power system.’ The third, on the New Deal, is ‘Empowering customers and 
citizens.’  

1 The Directive text can be found at: https://eur-lex.europa.eu/legal-
content/EN/TXT/?uri=uriserv:OJ.L_.2019.158.01.0125.01.ENG&toc=OJ:L:2019:158:TOC 
The Regulation text can be found at: https://eur-lex.europa.eu/legal-
content/EN/TXT/?uri=uriserv:OJ.L_.2019.158.01.0054.01.ENG&toc=OJ:L:2019:158:TOC 
2The document can be found at: http://www.consilium.europa.eu/en/documents-publications/public-register/ 

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1. Ensuring the internal market level playing field 

In this section, we first set the scene by introducing the different components of the typical electricity bill. 
We then focus on three key measures in the CEP to ensure the level playing field in the internal electricity 
market,  i.e.,  the  phasing  out  of  public  intervention  in  setting  electricity  prices,  the  methodologies  for 
network  tariffs,  and  the  limitation  of  the  use  of  capacity  mechanisms.  We  conclude  the  section  by 
highlighting  the  interlinkage  of  the  CEP  with  the  network  codes  (NC)  on  topics  related  to  the  internal 
electricity market such as balancing responsibilities and system operation regional governance, as well as 
bidding zones and the calculation of interconnectors’ capacity. We also refer to the second generation of 
network codes that are included in the CEP. 

1.1.  Setting the scene: the different components of the electricity bill 
End-user electricity prices consist of the sum of three main components: the energy component, network 
charges, and taxes and levies3 (T&L). The European average in 2017 of the energy component (contestable 
charges), is about 35% of the total bill for households. Non-contestable charges (i.e., network charges, 
T&L,  and  possible  other  charges)  constitute  the  remaining  65%  of  the  consumers’  bill.  Note  that  for 
countries with a high share of renewable energy sources (RES) like Germany or Denmark4, the T&L, which 
also include RES contributions, constitute the main part of the electricity bill. Figure 1 gives an overview 
of the composition of end-user electricity prices across EU capital cities. 

Figure 1: End-user electricity prices breakdown of incumbents’ standard offers for households in EU capital cities – 
November–December 2017 (%), source: (ACER and CEER, 2018a)  

Electricity  prices  differ  significantly  across  MSs  for  several  non-market  reasons.  For  households,  they 
increased by 25.9% compared to 2008 (ACER and CEER, 2018a). This increase is due to significant rises in 
non-contestable charges (network charges and T&L) in absolute terms (EC, 2016a). However, the shares 
of network charges (%) in the electricity bill, as shown in Figure 2, have remained almost unchanged (ACER 
and  CEER,  2018a).  Germany,  with 30.5 €  cents/kWh,  has  the  highest  household  electricity  prices.  This 
represents more than three times the household prices in Bulgaria (9.7 € cents/kWh). For the industrial 

3 Please take into account that RES subsidies are considered in this text as T&L. Indeed, RES are not a necessary cost for grids, 
however, they bring significant positive externalities for the environment and promote energy transition. 
4 In the case of Denmark, even though the share of renewable energies is expected to increase, this part of the bill will decline in 
the coming years, because costs for renewable energies are going to be gradually moved from the electricity bill to the national 
budget (Blomgren-Hansen and Rye-Andersen, 2017). 

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sector, this difference is even more important with 24.0 € cents/ kWh) in Denmark and 4.3 € cents/kWh 
in Luxembourg (ACER and CEER, 2018a).  

The energy component is determined by two main factors: wholesale prices and costs associated with the 
retail activity. There are three main drivers for wholesale electricity prices: fuel shares in the electricity 
generation  mix,  commodity  prices,  and  market  features  (i.e.,  the  degree  of  competition,  access  to 
resources, and regional market integration). Retail costs include supply operating costs (i.e., billing and 
marketing) and a profit margin for providing retail services5. The energy component share declined from 
41% to 35% in EU capital cities between 2012 and 2017. This decline over the past years reflects a better 
functioning of the internal electricity market as well as the decrease in wholesale electricity prices. 

The network component, including subcomponents of transmission and distribution, represented 27% of 
the EU electricity bill for households in EU capital cities in 2017 (weighted average). Distribution charges 
represent the largest part of network charges in a consumer bill. They ranged from 13% to 47% in 2017 
households’  electricity  bill  in  EU  capital  cities,  while  for  the  transmission  network  charges,  these 
percentages were between approximately 0% and 10%. 

Figure 2: Weighted average breakdown of end-user electricity price components in EU capital cities – 2012–2017 (%), source: 
(ACER and CEER, 2018a) 

The T&L component share of the electricity bill has increased6 for electricity since 2012. This is mainly due 
to the cost of support mechanisms for electricity from renewable energy sources (RES-E) and cogeneration 
or combined heat and power (CHP) across Europe7. The applied value-added taxes (VAT) on household 
electricity prices are percentages of these prices. Therefore, its nominal effect increased with the increase 
of total prices. Some MSs additionally raised the VAT rate. Tax rates vary in general for consumers across 
MSs depending on factors such as consumption and grid connection. 

1.2.  Limiting public interventions in electricity market prices 
In this part, we begin by providing an overview of the current practices for electricity price regulation in 
Europe. Then we present measures included in the CEP to limit public interventions in the electricity price 
setting, as well as the transitional measures aiming at ensuring customer protection during the transition 
to market-based retail prices.  

5 Note that in some reports the energy component does not include the retail costs. This would mean that the electricity bill 
would contain four components (CRU, 2017).  
6Also its absolute value increased as the end-users’ electricity prices have risen since then. 
7 In some countries (Italy, for example) RES levy is paid through a specific fee added to the electricity bill. Levies to remunerate 
RES are usually not included in the network component but rather in the T&L one to allow a comparison between different MSs. 

15 

 
 
 
                                                           
1.2.1  Current practices 
In  Europe,  the  majority  of  MSs  have  opted  for  retail  liberalization  with  the  phasing  out  of  regulated 
electricity  market  prices.  Art  21  of  the  European  Directive  2003/54/EC  already  required  that  non-
household electricity consumers should be able to freely choose their supplier from 1 July 2004 and for 
household electricity consumers starting from 1 July 20078. Today, around 40% of Member states still have 
regulated end-user electricity prices, as presented in Figure 39. Countries in Eastern Europe, as well as 
France, Spain, and Portugal still have public interventions in setting electricity prices, either for the entire 
retail segment or only for the household segment.  

Figure 3: Application of regulated prices for households as of June 2019, source: based on (CEER, 2017a) 

MSs  have  adopted  varying  approaches  for  retail  competition  following  the  European  Directive 
2009/72/EC. Art 3(3) of European Directive 2009/72/EC states that ‘Member States shall ensure that all 
household customers, and (…) small enterprises, (…), enjoy universal service, that is, the right to be supplied 
with electricity of a specified quality within their territory at reasonable, easily and clearly comparable and 
transparent prices’. The Directive adds in art 3(14) that ‘the interests of the Community include, inter alia, 
competition with regard to eligible customers’. Besides, the Directive foresees the possibility to introduce 
a  ‘supplier  of  last  resort’10  to  ensure  the  provision  of  a  universal  service  of  electricity  connection  and 
supply. This Directive was interpreted differently by MSs, and thus varying approaches have been adopted 
by  MSs  for 
in  the  degree  of 
market liberalisation between them.  

leading  to  significant  variation 

introducing  retail  competition 

The European Commission framework strategy encourages MSs to establish a roadmap for the phasing 
out of public interventions in electricity prices where such intervention still exists (EC, 2015a). The phasing-
out of regulated prices should be pursued with a mechanism to protect vulnerable consumers. According 
to the Commission framework strategy, this may be provided through the general welfare system. It adds 

8 These provisions were kept by the electricity Directive 2009/72/EC of the Third Energy Package. 
9 Please note that this figure indicates the countries that still offer regulated electricity prices regardless of their shares compared 
to competitive retail offers. For instance, in Portugal, 80% of electricity customers were under a liberalised tariff regime in January 
2018 (Baratti, 2018). Italy will phase electricity price regulation (called "maggior tutela") by July 1st, 2020 (Stagnaro et al., 2018). 
10 Art 3 of the Directive 2009/72/EC states that ‘to ensure the provision of universal service, Member States may appoint a supplier 
of last resort’. 

16 

 
 
                                                           
that if it is provided through the energy market, then it could be implemented through schemes such as a 
solidarity tariff or as a discount on energy bills, moving away from the tradition of regulated prices. 

1.2.2.  Measures for limiting public intervention in electricity market prices  
The CEP and more specifically the e-Directive ‘aims to ensure affordable, transparent energy prices and 
costs for consumers, a high degree of security of supply and a smooth transition towards a sustainable 
low-carbon  energy system.’  The  e-Directive  allows  MSs,  by  way of  derogation,  to  temporarily  regulate 
prices to protect energy-poor or vulnerable households. It sets specific conditions for interventions in the 
electricity price setting, to be only applied as public service obligations and subject to specific conditions. 
These public interventions should not sidestep open market principles.  

Recital  22  of  the  e-Directive,  on  public  authorities’  price  regulation,  highlights  the  distorting  effect  of 
public interventions on price regulation. It states that ‘Member States should maintain wide discretion to 
impose public service obligations on electricity undertakings11 in pursuing objectives of general economic 
interest. (…) Nevertheless, public service obligations in the form of price setting for the supply of electricity 
constitute a fundamentally distortive measure that often leads to the accumulation of tariff deficits, the 
limitation of consumer choice, (…).’ MSs are invited to apply other policy tools, such as targeted social 
policy measures, to guarantee citizens affordability of electricity supply. It adds that ‘a fully liberalised, 
well-functioning retail electricity market would stimulate price and non-price competition among existing 
suppliers  and  provide  incentives  to  new  market  entrants,  thereby  improving  consumer  choice  and 
satisfaction.’ 

MSs  shall  adopt  appropriate  measures  to  promote  effective  competition  among  electricity  suppliers, 
which shall be able to set the electricity supply prices freely, according to Art 5(1) of the e-Directive. Art 
5(2) adds that MSs shall ensure the protection of energy-poor or vulnerable household customers, defined 
in art 28 and art 29, through social policy or other means than public interventions in price setting. These 
principles were included in the first draft of the e-Directive and approved in the final version. Transitional 
measures for applying market-based supply prices and derogations to apply public intervention in price 
setting are possible for MSs. These measures changed from the first Commission proposal to different 
extents. We present them in the following subsection. 

Art 9 of the e-Directive introduces public service obligations. In price setting, they can occur in situations; 
first, when the electricity prices rise higher than normal due to constrained supply. Second, in case of a 
market failure where NRAs and competition authorities’ interventions were ineffective.  

1.2.3.  Transitional measures for limiting public intervention in electricity market prices  
The measures for limiting public intervention include two main derogations. The first one concerns the 
application  of  these  interventions  for  vulnerable  consumers  and  households  in  a  situation  of  energy 
poverty. The second one is to ensure the transition towards retail market competition where MSs applying 
public interventions in price-setting shall report on the necessity of these interventions and the progress 
made towards market-based prices. 

By 1 January 2022 and 1 January 2025, MSs shall submit reports to the Commission on the implementation 
of market-based prices and the necessity of public interventions. Following this, by the end of 2025, the 
Commission shall submit a report to the European Parliament and the Council on the implementation of 
market-based  retail  pricing.  This  can  be  together  with  or  followed  by  a  legislative  proposal  that  may 

11 Art 2(57)  of the e-Directive defines an ‘electricity undertaking’ as ‘a natural or legal person who carries out at least one of the 
following functions: generation, transmission, distribution, aggregation, demand response, energy storage, supply or purchase 
of electricity, and who is responsible for the commercial, technical or maintenance tasks related to those functions, but does not 
include final customers.’ 

17 

 
                                                           
include  a  roadmap  for  removing  regulated  prices  with  an  end-date  to  them.  In  the  remainder  of  this 
section, we discuss the two derogations  under which MSs may apply public interventions in electricity 
prices. 
Derogation 1: Protective measures for energy-poor and vulnerable customers:  

Regarding energy poverty, the e-Directive indicates, in recital 58, that ‘Member States should take the 
necessary measures to protect vulnerable and energy poor customers in the context of the internal market 
in  electricity.’  Indeed,  confirming  the  need  for  a  common  EU-wide  effort  to  face  energy  poverty,  the 
Commission launched, in December 2016, the European Energy Poverty Observatory (EPOV) to provide 
support for MSs. It is a 40-month research project aiming to improve the state of the art on energy poverty 
detection and the measures to tackle it. For more information, see Bouzarovski (2018). 

The recital (4) of the e-Directive emphasizes the protection of vulnerable consumers and states that the 
Energy Union Framework Strategy ‘sets out the vision of an Energy Union with citizens at its core, where 
citizens take ownership of the energy transition, (…) and where vulnerable consumers are protected’. MSs 
should  identify  through  accurate  measures,  according  to  recital  (59),  vulnerable  consumers  and  put 
measures in place that give them adequate attention. Art 5 (2) of the e-Directive adds that ‘Member States 
shall ensure the protection of energy poor or vulnerable household customers pursuant to Articles 28 and 
29  by  social  policy12  or  by  other  means  than  public  interventions  in  the  price  setting  for  the  supply  of 
electricity.’ 

The conditions for MSs’ derogation to apply public intervention in electricity price to protect energy poor 
or vulnerable household customers are stated in art 5(4) and art5(5). These conditions changed from the 
first Commission proposal to the final e-Directive text. In the first draft, the Commission proposed that 
public interventions in price setting for energy-poor or vulnerable household customers may continue to 
be  applied by MSs up to five years from the entry into force of the  e-Directive.  This  option allows for 
transitional  price  regulation  for  vulnerable  consumers.  After  the  five  years,  MSs  may  still  apply  these 
interventions for vulnerable household customers for reasons of extreme urgency. 

The  final  text  removed  the  five-year  period.  Art  5(4),  sets  the  conditions  for  MSs  applying  these 
interventions in the electricity price setting. Public interventions shall: 

‘(a)  pursue  a  general  economic  interest  and  not  go  beyond  what  is  necessary  to  achieve  that  general 
economic interest;  
(b) be clearly defined, transparent, non-discriminatory and verifiable;  
(c) guarantee equal access for Union electricity undertakings to customers;  
(d) be limited in time and proportionate as regards their beneficiaries; 
(e) not result in additional costs for market participants in a discriminatory way.’ 

The  application  of  these  public  interventions  by  a  MS  shall  comply  with  art  3(3)d  of  the  Governance 
Regulation  for  the  assessment  the  number  of  households  in  energy  poverty  and  art  24  of  the  same 
Regulation on the integrated reporting on energy poverty. This should be done ‘regardless of whether the 
Member State  concerned has  a significant  number of households  in energy poverty’  (art 5(5)  of the  e-
Directive). 
In addition to that, MSs are obliged to monitor the number of households in energy poverty to provide 
targeted support. According to art 29, ‘Member States shall establish and publish a set of criteria, which 
may include low income, high expenditure of disposable income on energy and poor energy efficiency.’ In 
addition, guidance  on the definition of  ‘significant  number of households  in energy poverty’  should be 
provided  by  the  Commission  in  the  context  of  this  art  29  on  energy  poverty  and  art  5(5)  on  public 

12 Social policy was added in the final text of the e-Directive 

18 

 
                                                           
interventions  in  price  setting.  This  should  be  done  ‘starting  from  the  premise  that  any  proportion  of 
households in energy poverty can be considered to be significant.’ 
Derogation  2:  Public  intervention  and  market  monitoring  for  a  transition  period  to  establish  retail 
competition  
The second derogation stated in art 5(6), aims to make it possible for MSs to apply public interventions in 
electricity  price  setting  for  a  transitional  period  in  order  to  establish  effective  retail  competition.  In 
addition  to  the  compliance  criteria  set  out  in  art  5(4)  and  presented  under  the  previous  derogation,  
further criteria for the application of the second derogation are set out in art 5(7). Indeed, for the purpose 
of a transition period, public interventions shall: 

‘(a) be accompanied by a set of measures to achieve effective competition and a methodology for assessing 
progress with regard to those measures;  
(b) be set using a methodology that ensures non-discriminatory treatment of suppliers;  
(c) be set at a price that is above cost, at a level where effective price competition can occur;  
(d) be designed to minimise any negative impact on the wholesale electricity market; 
(e)  ensure  that  all  beneficiaries  of  such  public  interventions  have  the  possibility  to  choose  competitive 
market offers and are directly informed at least every quarter of the availability of offers and savings in 
the competitive market, in particular of dynamic electricity price contracts, and shall ensure that they are 
provided with assistance to switch to a market-based offer; 
(f) ensure that, pursuant to Articles 19 and 21, all beneficiaries of such public interventions are entitled to, 
and  are  offered  to,  have  smart  meters  installed  at  no  extra  upfront  cost  to  the  customer,  are  directly 
informed of the possibility of installing smart meters and are provided with necessary assistance;  
(g)  not  lead  to  direct  cross-subsidisation  between  customers  supplied  at  free  market  prices  and  those 
supplied at regulated supply prices.’  

At the same time, MSs have also monitoring obligations on retail market competition.  Art 12 of the e-
Directive, promoting retail competition, states that MSs shall ensure that ‘switching supplier or market 
participant engaged in aggregation shall be carried out within the shortest possible time.’ Also, MSs shall 
provide that the switching should happen within a maximum of three weeks from the date of the request. 
Additionally, MSs shall ensure that ‘at least household customers, microenterprises and small enterprises13 
are not charged any switching-related fees.’ The final version of the e-Directive added that ‘by  no later 
than  2026,  the  technical  process  of  switching  supplier  shall  take  no  longer  than  24 hours  and  shall  be 
possible on any working day.’ 

Nevertheless,  contract  termination  fees,  charged  to  customers  willingly  terminating  fixed-term  supply 
contracts  before  their  maturity,  can  be  allowed  by  way  of  derogation.  These  fees  have  to  be  clearly 
communicated to the customer before they sign the contract, as emphasized in the art 12(3) of the e-
Directive.  They  shall  be  proportional  to  the  direct  economic  loss  of  the  contract  termination  for  the 
supplier or the aggregator and shall not exceed it. NRAs, or any other competent authority, shall monitor 
the permissibility of these fees. 

On retail offer comparison tools, art 14 of the e-Directive states that ‘Member States shall ensure that at 
least household customers, and microenterprises14 with an expected yearly consumption of below 100,000 
kWh have access, free of charge, to at least one tool comparing the offers of suppliers. The article also 
mentions the different criteria that have to be met by these tools such as their independence from market 

13 A microenterprise, according to art 2(6) of the e-Directive, means ‘an enterprise which employs fewer than 10 persons and 
whose annual turnover and/or annual balance sheet total does not exceed EUR 2 million.’ 
14 Same replacement here as in the previous footnote 

19 

 
                                                           
participants, the disclosure of the tool owner as well as setting out, and disclosing, comparison criteria. 
Comparison  tools  should  also  use  plain  and  unambiguous  language,  be  accessible  for  persons  with 
disabilities, and be accurate. MSs shall ensure that there is at least one tool that covers the whole of the 
market  as  they  predominantly  benefit  consumers  and  especially  the  active  ones  who  compare  offers 
and/or switch regularly between suppliers. Finally, these tools should provide ‘an effective procedure to 
report  incorrect  information  on  published  offers’  and  perform  offers’  comparisons  while  limiting  the 
requested personal data to the strictly necessary for the comparison. 

Customers should be informed about the availability of such tools. These tools may be operated by any 
entity,  including  private  companies  and  public  authorities  or  bodies.  A  competent  authority  shall  be 
appointed by MSs to be responsible for issuing a trust mark to comparison tools that meet the criteria 
stated above.15 CEER (2016) public consultation paper presents, for instance, guidelines of good practice 
on comparison tools. 

Moreover, art 59 of the e-Directive on ‘Duties and powers of the regulatory authority’ adds in paragraph 
(1)(o)  that  NRAs  have  to  monitor  ‘the  level  and  effectiveness  of  market  opening  and  competition  at 
wholesale and retail levels, including on electricity exchanges, prices for household customers including 
prepayment systems, the impact of dynamic electricity price contracts and of the use of smart metering 
systems, switching rates, disconnection rates, (…).’ They should also monitor the interrelation between 
household and wholesale electricity prices as well as the evolution of grid tariffs and levies. Any complaints  
by household customers and any distortion or restriction of competition shall be brought to the relevant 
competition authorities. 

Highlights  

Main measures 

- Public interventions in end-user electricity prices shall be gradually removed. 
- NRAs are required to enhance retail markets competition, to ensure efficient competition and to 
guarantee consumer protection. 
- MSs are required to define and publish a set of criteria for measuring energy poverty and to ensure 
that the customers who are vulnerable or in energy poverty are protected. 
- By 1 January 2022 and 1 January 2025, MSs shall submit reports to the Commission on the 
implementation of market-based prices and the necessity of public interventions. 
- By 31 December 2025, the Commission shall submit a report on the implementation of market-
based retail pricing. This can be together with or followed by a legislative proposal which may 
include an end date for regulated prices. 

Transitional measures 

- A derogation for using public intervention to protect vulnerable household customers. 
- A derogation for using public intervention as a transitional measure towards establishing retail 
competition together with parallel provisions for retail market monitoring. 

15 The trust mark replaces the certificate introduced in the Commission proposal. The final text of the Directive includes a 
derogation for MSs not to issue a trust mark for comparison tools fulfilling the mentioned criteria in art 14(6). 

20 

 
 
                                                           
 
1.3.  Methodologies for network tariffs  
In this part, we first present the current practices for network tariffs across Europe. Then, we describe the 
CEP measures regarding the network tariffs design and methodologies.  
1.3.1.  Current practices  
Transmission tariffs design across Europe 

In Europe, there are different systems of electricity transmission pricing and associated tariff structures. 
Transmission  access  is  generally  charged  via  capacity  component  (€/kW)  and/or  energy  volumetric 
component (€/kWh). Transmission tariffs can be applied to electricity generators and consumers, or in 
some cases only to the consumers. Figure 4 shows the differences across Europe based on ENTSO-E data.  

Figure 4: Status quo on energy and capacity transmission tariffs components among MSs, based on (ENTSO-E, 2017a) 

The  current  situation  is  the  result  of  nationally  established  transmission  tariff  policies  and  different 
national contexts. Some MSs (i.e., Germany, the UK, and Sweden) have implemented a capacity-based 
tariff whereas some other MSs (i.e., France, Spain and Italy) have implemented an energy-based tariff. In 
some  tariff  designs,  system  ancillary  service  costs  and  network  losses  costs  can  be  charged  through 
transmission tariffs (partially or totally) (such as Austria and France (ENTSO-E, 2017a)), rather than through 
market mechanisms (such as Spain and Portugal). Another difference between TSO charges in the EU is 
the share between generation (G-charge) and load (L-Charge) network charges as well as the seasonal and 
locational differentiation. This implies a certain complexity at the EU level. The Regulation EC 838/2010 
(EC, 2010), is the last published legislative document relevant to the regulation of the network tariffs.   

Part B of this Regulation sets guidelines for a common regulatory approach to transmission charging, such 
as  annual  average  transmission  charges  paid  by  producers  (G-charges)  and  their  ranges.  These  ranges 
differ by category of MSs. Four categories of MSs are distinguished. The first includes producers from all 
MSs, except for Denmark, Sweden, Finland, Romania, Ireland, Great Britain and Northern Ireland, which 
pay a G-charge in the range of 0 to 0,5 EUR/MWh. The second category is for producers from Denmark, 
Sweden and Finland, where the G-charges shall be within a range of 0 to 1,2 EUR/MWh. The third category 
is for producers from  Ireland, Great Britain and Northern Ireland where the G-charges shall be within a 
range of 0 to 2,5 EUR/MWh and the fourth category is for producers from Romania where the G-charges 
shall be within 0 and 2,0 EUR/MWh. 

These ranges aim to ensure that the benefits of harmonisation are realized and to prevent the variations 
in  G-charges  from  undermining  the  internal  market,  according  to  recital  (10)  of  the  Regulation  EC 

21 

 
 
838/2010. The different ranges by MSs can be explained by the different tariffs methodologies and policies 
within the EU (ENTSO-E, 2017a). 

Distribution tariffs design across Europe 

The  methodologies  and  structures  for  distribution  tariffs  are  also  different  across  Europe.  As  with 
transmission tariffs, the shares of energy/capacity components for distribution tariffs, shown in Figure 5, 
vary  significantly  across  EU  countries.  Most  European  DSOs’  revenue  is  currently  based  on  volumetric 
tariffs,  i.e.,  69%  of  the  revenue  for  households,  54%  for  small  industrial  consumers  and 58%  for  large 
industrial consumers. For more details, please refer to (EC, 2015b). 

Figure 5: Status quo on energy and capacity distribution tariffs components among MSs for households, based on (EC, 2016b) 

Interesting cases are the Netherlands and Great Britain (GB). In the Netherlands, the distribution tariff has 
been  based  on  the  physical  capacity  of  the  household  connection  since  2009,  and  there  is  no  energy 
component in the tariff. In GB, part of the network charges paid  is intended to reflect the consumers’ 
contribution  to  the  system  peak.  For  more  information  per  country,  please  consult  CEER  (2017b) 
guidelines of good practice for electricity distribution network tariffs. 
1.3.2.  Principles for network tariffs design in the CEP 
The CEP brings new measures for network tariffs methodologies. Art 18 of the e-Regulation states that 
network tariffs shall be cost-reflective16 and send appropriate signals on the short and long term. This shall 
support  overall  system  efficiency  and  guide  efficient  investments.  Also,  network  tariffs  shall  not 
discriminate  against distributed energy resources and aggregation either  positively or negatively. Non-
distortive and cost-reflective tariffs design facilitate innovation and ease unlocking flexibility potential in 
electricity  systems.  Art  18(1)  adds  that  network  charges  shall  not  include  unrelated  costs  supporting 
unrelated policy objectives, such as T&L, as this would distort production, consumption, and investment 
decisions. 

Distribution tariffs, in particular, shall be cost-reflective regarding the use of the distribution network by 
grid-connected  users,  including  active  customers  art  18(7).  The  article  adds  that  they  ‘may  contain 
network connection capacity elements and may be differentiated based on system users' consumption or 
generation profiles.’ In case a MS has undertaken smart metering system roll-out, the NRA shall consider 

16 A cost reflective tariff, according to SCHITTEKATTE et al. (2019),  implies that the cost a consumer creates on the electricity 
network should be reflected by the network tariff. It aims to lead to an overall lowest final cost for serving electricity to 
different system customers. Ideally, the tariff level for different user groups should reflect over time how their usages affect the 
costs of the network. 

22 

 
 
                                                           
time differentiated network tariffs ‘when fixing or approving transmission and distribution tariffs or their 
methodologies.’  This  should  be  in  line  with  art  59  of  the  e-Directive.  Then,  where  appropriate,  time 
differentiated network tariffs may be introduced. 

Regarding  system  operation,  distribution  tariff methodologies  shall  provide  incentives  to  DSOs  for  the 
most cost-efficient operation and development of their networks, including through the procurement of 
services. NRAs shall, therefore, according to art 16(8) recognize the relevant costs that result from the 
procurement  of  innovative  services  and  include  them  in  distribution  tariffs.  NRAs  may  also  introduce 
‘performance targets in order to provide incentives to distribution system operators to increase efficiencies 
in their networks, including through energy efficiency, flexibility and the development of smart grids and 
intelligent metering systems.’ 

In order to mitigate the risk of internal electricity market fragmentation, ACER shall provide a best practice 
report17 on transmission and distribution tariff methodologies within three months after the entry into 
force of the Regulation as stated in art 16(9). ‘That best practice report shall address at least: 
‘(a) the ratio of tariffs applied to producers and tariffs applied to final customers; 
(b) the costs to be recovered by tariffs;  
(c) time-differentiated network tariffs;  
(d) locational signals; (e) the relationship between transmission tariffs and distribution tariffs;  
(f) methods to ensure transparency in the setting and structure of tariffs;  
(g) groups of network users subject to tariffs including, where applicable, the characteristics of those 
groups, forms of consumption, and any tariff exemptions;  
(h) losses in high, medium and low-voltage grids.’ 
ACER shall update its report at least once every two years and should leave sufficient room for MSs to take 
into account  national specificities. NRAs shall duly take into consideration this report when approving, 
determining network tariffs, or their methodologies, or both.  

Regarding the harmonization of network tariffs, it should be noted that the Commission proposed in the 
e-Regulation proposal version that this area should be handled through network codes as indicated in art 
55(1)(k) of the Commission proposal. It added the harmonization of distribution tariffs in the areas to be 
covered by network codes  in addition to  transmission tariffs. Following the ‘trilogue’  negotiations,  the 
final text of the e-Regulation has removed the addition of the harmonization of distribution tariffs from 
the network codes focus areas. It has also removed the harmonization of transmission tariffs, which has 
been first introduced in art 8 of the Regulation (EC) No 714/2009 of the Third Energy Package, among the 
focus areas of network codes. However, it has not been developed into a tariff network code18. 

Highlights 

- Network tariffs shall give appropriate incentives to TSOs and DSOs to foster market integration and 
security of supply (SoS) as well as to increase efficiencies and support investment and R&D. 
- ACER shall provide a best practice report transmission and distribution tariff methodologies.  
- NRAs shall take into consideration ACER’s best practice report when approving or determining 
transmission and distribution tariffs or their methodologies. 

17The best practice report replaced the recommendation on the progressive convergence of transmission and distribution tariff 
methodologies, to be addressed by ACER to NRAs, included in the Commission proposal. 
18There are tariff network codes only for the gas sector. For the electricity, the developed network codes are on market, grid 
and connection. 

23 

 
 
                                                           
 
1.4.  Limiting the use of capacity mechanisms  
Security  of  supply,  resource  adequacy,  and  capacity  mechanism  are  three  related  topics  in  electricity 
systems. Security of supply is a key pillar of the European Electricity Policy as stated in art 194(1) of the 
Treaty on the Functioning of the European Union (‘TFEU’). It is indispensable in modern societies that are 
increasingly relying on electricity both for households and industries segments. Resource adequacy needs, 
therefore, to be suitably assessed to ensure that there are sufficient generation and flexibility for a reliable 
electricity  supply  at  all  times. In  case  of  adequacy  concerns,  MSs  may  anticipate  this  inadequacy  in 
generation  capacity  and  introduce  capacity  mechanisms  at  the  national  level,  supporting  generation 
capacity  investment  and  ensuring  system  adequacy.  However,  when  capacity  mechanisms  are 
uncoordinated and  imperfectly  designed,  they  may  risk  affecting  cross-border  trade  and  distort 
investment  signals,  creating  market  entry-barriers  for  alternative  providers.  The  CEP  prioritizes  the 
adoption of market reforms to address resource adequacy. MSs may apply capacity mechanism, as a last 
resort, to eliminate residual adequacy concerns. 

In this section, we discuss the current implementation practices on capacity mechanisms (CMs), also called 
capacity remuneration mechanisms (CRMs) in Europe. The CEP includes measures to limit their use, the 
discrimination  against  emerging  business,  their  impact  on  climate  goals,  and  the  related  cross-border 
concerns. 

1.4.1.  Fundamentals of Capacity Mechanisms 
Capacity mechanisms are defined in art2(22) of the e-Regulation as ‘temporary measure to ensure the 
achievement of the necessary level of resource adequacy by remunerating resources for their availability, 
excluding measures relating to ancillary services or congestion management.’ 

Capacity mechanisms can be classified as ‘volume-based mechanisms’ and ‘price based mechanisms’. In 
Figure 6, below, we illustrate the classification of CMs according to their characteristics. 

Figure 6: Taxonomy of capacity mechanisms, source: based on (EP, 2017) 

24 

 
 
 
In  the  volume-based  mechanisms,  the  total  amount  of  capacity  required  is  determined  in  advance  by 
policymakers  or  by  a  designated  entity,  i.e.,  a  TSO  or  a  NRA.  A  market-based  process  is  then  used  to 
establish the price to be paid. Volume-based mechanisms may also be divided into two subcategories. The 
first is ‘Market-wide mechanisms’ which provide support to all market participants that are required to 
meet the reliability standard, and they, in principle, reward all capacity providers. The second subcategory 
is ‘targeted mechanisms’ which reward only specific plants or technologies, i.e., they provide support only 
to the extra capacity required in addition to that provided by the market without the subsidies (Hancher 
et al., 2015). 

In  the  price-based mechanisms, a  price  is  administratively  set  by  policymakers at  a  level  calculated  to 
achieve investment in the amount of capacity required. The investors decide how much volume of capacity 
they are willing to invest for the given price. The box below describes the different capacity mechanisms19 
used in Europe (EP, 2017). 

Box: Description of the different capacity mechanisms 
Capacity  obligation  (CO):  Also  called  capacity  requirement,  is  an  obligation  on  suppliers  or  large 
consumers to contract with generators for a certain level of capacity. This capacity is determined by 
TSO/regulator and related to their self-assessed future consumption or supply (e.g. three years ahead), 
plus a reserve margin. If not enough capacity is contracted, the supplier or the consumer will pay a 
buy-out price/fine. The price for capacity is determined in a decentralised way, through the contracts; 
this model could also include a market of exchangeable obligations (secondary market).  
Capacity  auction  (CA):  The  capacity  volume  to  be  auctioned  is  decided  centrally  (by  the  TSO  or 
regulator)  a  few  years  in  advance.  The  price  is  determined  by  auction  and  is  paid  to  all  resources 
(existing and new) clearing the auction. Capacity providers bid to receive a payment that reflects the 
cost of building new capacity. The new capacity participates in the energy-only market. 
Reliability options (RO): RO is based on a forward auction (e.g. three years ahead). A capacity provider 
enters into an option contract with a counterparty (a TSO or a large consumer or supplier). The contract 
offers the counterparty the option to procure electricity at a predetermined strike price. The capacity 
provider must be available to the system operator for dispatch above the strike price. 
Strategic reserve (SR): A central agency (transmission system operator or government agency) decides 
upon the amount of capacity needed to make up any shortfall in the market few years in advance. The 
level of payment of the contracted capacity (strategic reserve) is set through a competitive tendering 
process.  The  contracted  power  plants  cannot  participate  in  the  electricity  market  and  are  only 
activated in case of extreme conditions.  
Capacity Payments (CP): CP is a price-based mechanism. It pays a fixed amount (set by the regulator) 
for available capacity to all generators. The plants receiving capacity payments continue to participate 
in the energy-only market. The payment could be given also when the plant does not run, but certain 
availability criteria have to be met. 

1.4.2.  Current implementation practices in capacity mechanisms 
In  recent  years,  different  EU  Member  States  have  implemented  varying  CM  designs  (see  Figure  7). 
The most  common  CMs  are  strategic  reserves  (EC,  2016c).  They  are  used,  for  example,  in  Belgium, 
Germany, Poland, Sweden, and Finland. In Germany, the strategic reserve mechanism requires network 
operators to  procure  and hold  2GW  of  capacity  outside  the market,  starting  in  winter  2018/2019  and 

19 For more details on the different uses of capacity mechanisms, please see (ACER, 2013), (Hancher et al., 2015)  and (EC, 
2016d) 

25 

 
 
                                                           
lasting  initially  for  two  years  (BMWi,  2018).  In  Italy,  a  reliability  option  scheme  is  planned  with  a  first 
delivery in 2020. Capacity procurment will be through competitive tenders for reliability option contract.  

Recent Developments:  
In  February  2018,  capacity  mechanisms  in  six  member  states,  namely  Belgium,  France,  Germany, 
Greece, Italy, and Poland, received EU State aid approval (EC, 2018).The Commission found that these 
measures will contribute towards ensuring security of supply while preserving competition in the single 
market. The approved mechanisms are the following: strategic reserves, in Belgium and Germany, two 
market-wide  capacity  mechanisms  in Italy and Poland,  as  well  as  a  demand  response20  (DR)  tender 
in France and an interruptibility scheme in Greece21. 

Figure 7: CMs implementation in Europe, source: (ACER and CEER, 2018b) 

20 DR operators can choose either between a certification of DR as capacity or a reduction of consumption as supplier 
obligation. 
21 ‘Interruptibility schemes’ are mechanisms ‘in which industrial customers are asked by the network operator to reduce their 
demand in scarcity situations, are also considered a form of "reserve", as they provide capacity that is only activated when a 
supply shortfall occurs’, (EC, 2016c). 

26 

 
 
 
 
 
                                                           
1.4.3.  Current practices in adequacy assessments 

According  to  the  sector  inquiry  report  (EC,  2016d),  many  MSs  have  not  applied  sufficiently  rigorous 
assessment methodologies to establish appropriate levels of SoS before applying a CM. As can be observed 
in Table 1, the methods of assessing resource adequacy vary widely among MSs22 and there is no common 
approach  between MSs.  This  makes  a  comparison  between  the  assessment  results  quite  difficult.  The 
sector inquiry report adds that ‘many resource adequacy assessments take a purely national perspective 
and  may  substantially  differ  depending  on  the  underlying  assumptions  made  and  the  extent  to  which 
foreign capacities as well as demand side flexibility are taken into account.’  

Adequacy assessments can follow two approaches: a deterministic approach and a probabilistic one. The 
deterministic approach compares the sum of all generation capacities with the peak demand for a single 
one-off moment. It assesses the generation adequacy level via the capacity margin, which is the relation 
between peak demand and the reliably available supply, as a percentage23. This approach, however, does 
not give a reliable picture of the adequacy situation due to the increase in renewable energies in electricity 
systems. The Probabilistic approach, in turn, considers variations in demand over the years. Generation 
adequacy can be measured through the calculation of the loss of load probability (LOLP), ‘which quantifies 
the probability of a given level of unmet  demand over a certain period of time.’ In many cases LOLP is 
expressed as a loss of load expectation (LOLE) representing the number of hours per annum in which, over 
the long-term, the supply is statistically expected not to meet demand (EC, 2016d). Both LOLP and LOLE, 
however,  do  not  measure  the  shortfall  in  the  capacity  that  arises  when  there  are  disconnections  and 
neither  LOLP/LOLE  nor  capacity  margins  can  measure  the  unmet  demand. This  would  require  a 
measurement of expected energy not served (EENS), which represents the amount of electricity demand 
(in MWh) that is expected not to be met by generation for a given year. Note that to obtain the economic 
value of adequacy, it is necessary to quantify the Value of Lost Load (VOLL). As the name suggests, VOLL 
measures the damage suffered by consumers when the supply is curtailed24. It is crucial to implement a 
cost-effective adequacy level. 

Compared to the deterministic approach, the Probabilistic approach considers a wide range of variables 
and assesses their behavior under different scenarios. The probabilistic approach is gradually replacing 
the deterministic one in some MSs as electricity systems are becoming more complex. 

Table 1: Probabilistic Vs Deterministic approaches to adequacy assessments, source: (EC, 2016d) 

22 There were eleven markets under this assessment: Belgium, Croatia, Denmark, France, Germany, Ireland, Italy, Poland, 
Portugal, Spain and Sweden (EC, 2016d).  
23 For instance, a system with 11 GW of installed capacity and 10 GW of peak demand has a 10% capacity margin. In two of the 
eleven Member States, only this relatively simple capacity margin is calculated. 
24 VOLL calculation is quite complex. It is normally based on surveys and includes several factors such as types of customers, 
duration of interruption, frequency and occurrence time. 

27 

 
 
                                                           
Reliability Standards 
The level of capacity needed to ensure SoS, is expressed by the reliability standards. There are different 
metrics  used  across  MSs  to  set  reliability  standards  depending  on  the  adopted  adequacy  assessment 
approach. Each one of them represents a way of measuring SoS based on consumers' willingness to pay.  

Table 2, based on replies to the sector inquiry, shows the MSs practices in setting a reliability standard. It 
can be observed that currently there are some MSs that do not measure this level, and others that have 
not even defined a reliability standard when introducing capacity mechanism.  

Table 2: MSs practice in setting a reliability standard, source: (EC, 2016d) 

1.4.4.  Limiting the introduction of capacity mechanisms 
The e-Regulation includes measures to limit the implementation of capacity mechanisms, considering the 
views of the sector inquiry report (EC, 2016d). Adequacy concerns need to be identified, against reliability 
standards, by the European and/or the national resource adequacy assessment25 as a binding measure. 
Then, MSs, with adequacy concerns, shall publish, first, an implementation plan for adopting measures 
eliminating the identified regulatory distortions and/or market failures. CMs may be implemented as a 
last  resort  to  eliminate  residual  adequacy  concerns.  They  should  be  temporary  and  should  not  create 
undue market distortions art 22(1).  In this subsection, we will present the different provisions of the e-
Regulation  for  resource  adequacy  assessment,  reliability  standards,  implementation  plans  and  the 
principles for applying capacity mechanisms. The new rules for capacity mechanisms, as stated in art 22(5), 
will not prejudice to commitments or contracts concluded before 31 December 2019. 

European resource adequacy assessment 

The European resource adequacy assessment is the first step in a significantly important procedure that 
may  potentially  lead  to  the  implementation of  a CM.  According  to  art 23  of the  e-Regulation,  it  ‘shall 
identify resource adequacy concerns by assessing the overall adequacy of the electricity system to supply 
current and projected demands for electricity at Union level, at the level of the Member States, and at the 
level of individual bidding zones, where relevant.’ It shall cover each year within a ten-year period, starting 
from the date of the assessment. The assessment shall be conducted every year by ENTSO-E based on 

25 The complementing national resource adequacy assessment were added in the final e-Regulation text and did not exist in the 
first Commission proposal. 

28 

 
 
 
                                                           
data provided by national TSOs. Generators and other market participants, in their turn, shall provide TSOs 
with data about the expected utilization of the generation resources. By 5 January 2020, ENTSO-E shall 
submit to the Electricity Coordination Group and ACER a draft methodology for the European resource 
adequacy assessment. The methodology shall be transparent and ensure that the assessment is carried 
out  on  each  respective  bidding  zone  level  and  based  on  appropriate  central  reference  scenarios  of 
projected demand and supply. In addition to applying a single modelling tool, the assessment shall contain 
separate scenarios reflecting generation adequacy concerns that the capacity mechanisms are designed 
to  address.  Also,  according  to  art  23(5),  the  assessment  shall  apply  at  least  the  "expected  energy  not 
served"  (EENS) and  the  "loss  of  load  expectation"  (LOLE)  indicators.  By  5  January  2020,  ENTSO-E  shall 
submit to ACER a draft methodology for calculating the VOLL, the cost of new entry for generation, or 
demand response, and the reliability standard referred to in art 25, integrating, therefore, existing work 
on VOLL and other indicators. 

A complementing national resource adequacy assessment  

MSs  may  complement  the  European  resource  adequacy  assessment  with  national  resource  adequacy 
assessments. This additional assessment was not included in the Commission proposal for e-Regulation 
and was brought by the Council negotiating position. National adequacy assessments shall have a regional 
scope,  and  their  methodology  shall  be  similar  to  the  European  one  described  in  art  23(4).  They  shall 
contain  the  reference  central  scenarios  of  projected  demand  and  supply  similarly  to  the  European 
assessment. In addition, they may  provide additional sensitivities through considering particularities of 
national power demand and supply and use complementary tools as well as more consistent and recent 
data than the European one. 
When there is a divergence26 between the national and the European resource adequacy assessment with 
regard to the same bidding zone, the national assessment shall include the reasons for the divergence, 
‘including  details  of  the  sensitivities  used  and  the  underlying  assumptions’. MSs  shall  publish  that 
assessment and submit it to ACER. Within two months from report  submission, ACER  shall provide  an 
opinion on whether the discrepancies are justified. Then ACER opinion shall be taken duly into account by 
the body governing the national assessment and where necessary it shall amend the final assessment. 
However, they if the governing body decides not to consider ACER opinion fully, it shall publish its detailed 
reasoning in a report. 

Reliability standards 

The  e-Regulation  also  proposes  the  development  of  EU-wide  methodologies  for  calculating  coherent 
reliability standards, representing the basis for capacity mechanism implementation decisions. Art 25 of 
the e-Regulation states that ‘a reliability standard shall indicate the necessary level of security of supply of 
the Member State in a transparent manner.’  For cross-border bidding zones, the relevant authorities shall 
jointly establish reliability standards. Reliability standards shall be set by a MS or a competent authority 
designated by the MS based on the methodology referred to in  art 23(6). This  article states that  ‘by 5 
January 2020, the ENTSO for Electricity shall submit to ACER a draft methodology for calculating:  
(a) the value of lost load;  
(b) the cost of new entry for generation, or demand response; and  
(c) the reliability standard referred to in Article 25.’ 
Art 25(3) adds that reliability standard, expressed as EENS and LOLE, ‘shall be calculated using at least the 
value  of  lost  load  and  the  cost  of  new  entry  over  a  given  timeframe.’  Also,  ‘when  applying  capacity 
mechanisms,  the  parameters  determining  the  amount  of  capacity  procured  in the  capacity mechanism 

26 A divergence means that the national resource adequacy assessment identifies a concern with regard to a bidding zone and 
the European resource adequacy assessment has not identified a concern. 

29 

 
                                                           
shall be approved by the Member State or by a competent authority designated by the Member State, on 
the basis of a proposal of the regulatory authority,’ (art 25(4)). 

An implementation plan for market reforms before capacity mechanisms 

The  EC  (2016d)  sector  inquiry  states  that  MSs  are  required  to  put  in  place  measures  to  address  the 
regulatory distortions causing the identified resource adequacy concerns, such as market reforms. The 
sector inquiry report highlighted four market reforms that can address the security of supply concern and 
may  even  remove  the  need  for  capacity mechanisms.  MSs  that  have  introduced  capacity mechanisms 
should  also  make  appropriate  efforts  to  integrate  market  reforms,  as  they  are  not  substitutable  by 
capacity mechanisms. The market reforms are with regard to the removal of prices caps and regulated 
electricity  prices,  the  participation  of  demand  response,  the  de-lineation  of  bidding  zones,  and  the 
balancing market reform. 

To address the identified regulatory distortions at the level of MS, art 20(3) of the e-Regulation requires 
in turn from MSs to ‘publish an implementation plan with a timeline for adopting measures to eliminate 
any identified regulatory distortions or market failures as a part of the State aid process.’ In addition, when 
addressing these  regulatory distortions and market  failures, MSs shall take  into account  the  principles 
regarding the operation of electricity markets stated in art 3 of the e-Regulation. The art 20(3) adds that 
MSs shall also consider: 

‘(a) removing regulatory distortions;  

(b) removing price caps in accordance with Article 10;  

(c) introducing a shortage pricing function for balancing energy as referred to in Article 44(3) of Regulation 
(EU) 2017/2195;  

(d)  increasing  interconnection  and  internal  grid  capacity  with  a  view  to  reaching  at  least  their 
interconnection targets as referred in point (d)(1) of Article 4 of Regulation (EU) 2018/1999;  

(e)  enabling self-generation,  energy  storage,  demand  side measures  and  energy  efficiency  by  adopting 
measures to eliminate any identified regulatory distortions;  

(f) ensuring cost-efficient and market-based procurement of balancing and ancillary services;  

(g) removing regulated prices where required by Article 5 of Directive (EU) 2019/944.’ 

MSs shall submit the developed implementation plans to the Commission for review and opinion. They 
shall monitor their application and publish an annual report on the results to be also submitted to the 
Commission.  Figure  8,  at  the  end of this  subsection,  explains the  CEP  e-Regulation  process  to address 
adequacy concerns in MSs. A more detailed explanation of the impact of these market reforms can be 
found in EC (2016b) and EC (2016d). 

General principles for capacity mechanisms   

When  a  MS  decides  to  implement  a  CM  following  the  resource  adequacy  assessment  and  the 
implementation plan for market reforms. The MS should study its cross-border effects, assess strategic 
reserves first then the other types of CMs. 
When a MS is already applying a CM, the mechanism shall be reviewed. The MS shall not also conclude 
new contracts if both the European and the national resource adequacy assessment have not provided so 
pursuant  to  art  21(6),  ‘or  in  the  absence  of  a  national  resource  adequacy  assessment,  the  European 
resource adequacy assessment have not identified a resource adequacy concern or the implementation 
plan  as  referred  to  in  Article 20(3)  has  not  received  an  opinion  by  the  Commission  as  referred  to  in 
Article 20(5).’ Capacity mechanisms shall be temporary, and MSs shall include a provision allowing for an 

30 

 
efficient administrative phase-out of the CMs in case no new contracts are concluded for a CM following 
art 21(6) during three consecutive years. 

In  addition,  according  to  art  21(8),  capacity  mechanisms  ‘shall  be  approved  by  the  Commission  for  no 
longer than 10 years.’ Then, they shall be phased out, or the amount of the committed capacities shall be 
reduced  based  on  the  implementation  plan  pursuant  to  art  20(3)  aiming  to  eliminate  any  identified 
regulatory  distortions.  Also,  MSs  shall  continue  the  application  of  the  implementation  plan  after  the 
introduction of the capacity mechanism. 

Limiting cross-border concerns 

Cross-border participation in capacity mechanisms is not very common between MSs. Some of them do 
not  even  take  into  account  the  contribution  of  imports  when  assessing  their  resource  adequacy,  thus 
leading to a collection of national overcapacities (EC, 2016d). Nevertheless, this situation is changing. For 
instance,  France  and  Ireland  are  developing  plans  to  allow  cross-border  participation  in  their  capacity 
mechanisms, (RTE, (2019); EC, (2016d)). 

The  EC  (2016b)  impact  assessment  highlights  the  necessity  of  taking  into  account  cross-border 
participation in CMs to ensure efficient signals and avoid internal market failure such as distorting cross-
border trade, leading to suboptimal investments and creating shifts of generation capacity towards the 
country with a capacity mechanism.  

The e-Regulation sets cross-border participation rules in capacity mechanisms. Art 26 of the e-Regulation 
states that ‘mechanisms other than strategic reserves and where technically feasible, strategic reserves, 
shall be open to direct cross-border participation of capacity providers located in another Member State 
(…).’ Indeed, CMs must be open to explicit cross-border participation to limit distortions to cross-border 
trade and competition as well as providing incentives for interconnection investment to ensure the EU 
security of electricity supply at least costs. 

When implementing a capacity mechanism, a study on cross-border effect shall be undertaken by the MS 
implementing  it  through  consulting  at  least  its  electrically  connected  neighbouring  MSs  and  the 
stakeholders of those MSs (art 21(2)). In addition, ‘national regulatory authorities shall ensure that cross-
border participation in capacity mechanisms is organised in an effective and non-discriminatory manner. 
(…)’ (art 26 (13)). 
Regional coordination centres (RCCs)27, national TSOs, the ENTSO-E, NRAs and ACER are involved in the 
development of technical parameters for the participation of foreign capacities as well as the operational 
rules for their participation. For instance, according to art 21(6) of the e-Regulation, the maximum entry 
capacity available for the participation of foreign capacity shall be calculated annually by TSOs, based on 
the recommendation of the RCC. The calculation, required for each bidding zone border, should take into 
account ‘the expected availability of interconnection and the likely concurrence of system stress between 
the system where the mechanism is applied and the system in which the foreign capacity is located.’  

The  methodology  for  calculating  the  maximum  entry  capacity  for  cross-border  participation shall  be 
developed by ENTSO-E and submitted to ACER by 5 July 2020. Also, ENTSO-E shall submit a methodology 
for sharing the revenues arising through the allocation of eligible capacity providers in case of cross border 
participation pursuant to art 26(11)(b) and art 26(9).  ENTSO-E shall also develop and submit to ACER the 
common rules for the carrying out of availability checks by TSOs, where the foreign capacity is located, as 
well as the common rules for determining when a non-availability payment is due. Also, the terms of the 
operation  of  the  registry  of eligible  capacity  providers  for  a  CM  and  the  common  rules  for  identifying 

27 The creation of new Regional Coordination Centres (RCCs) builds on the framework established by the Regional Security 
Coordinators in the CEP. This aims to ensure a more coordinated regional approach to transmission system operations. For 
more information, please see 1.5.2. 

31 

 
                                                           
capacity eligible to participate in the capacity mechanism shall be developed by ENTSO-E and submitted 
to ACER by the same time, as stated in art 26(11). 

Specific design principles for strategic reserves 

Strategic reserves, described in 1.4.1, are widely used across MSs such as in Belgium, Germany, Poland, 
and Sweden. They are, according to EC (2016d), the most appropriate response to temporary adequacy 
concerns since they operate only outside the market and only in rare cases when markets can no longer 
clear. When they are designed not to promote new generation and when the reserve is kept as small as 
possible, distortions can be kept at a minimum. 
The final text of the e-Regulation includes specific design principles for strategic reserves. They shall be 
assessed first by MSs when introducing capacity mechanisms. A specific paragraph was added regarding 
strategic reserves compared to the Commission proposal for the e-Regulation. Strategic reserves shall only 
be dispatched in case TSOs are likely to exhaust their balancing resources. The strategic reserve’s output 
after the dispatch shall be attributed to BRPs through the imbalance settlement mechanism. Art 22(2) 
states the following requirement that the design of strategic reserves shall meet: 
(a) where a capacity mechanism has been designed as a strategic reserve, the resources thereof are to be 
dispatched only if the transmission system operators are likely to exhaust their balancing resources to 
establish an equilibrium between demand and supply;  
(b) during imbalance settlement periods where resources in the strategic reserve are dispatched, 
imbalances in the market are to be settled at least at the value of lost load or at a higher value than the 
intraday technical price limit as referred in Article 10(1), whichever is higher; 
(c) the output of the strategic reserve following dispatch is to be attributed to balance responsible parties 
through the imbalance settlement mechanism;  
(d) the resources taking part in the strategic reserve are not to receive remuneration from the wholesale 
electricity markets or from the balancing markets;  
(e) the resources in the strategic reserve are to be held outside the market for at least the duration of the 
contractual period. 
Further design principles for other capacity mechanisms 

For CMs other than strategic reserves, the e-Regulation adds further specifications on the design principles 
with regard to the availability payment and capacity obligation. Art 22(3) of the e-Regulation states that 
CMs, other than strategic reserves, shall: 

(a) be constructed so as to ensure that the price paid for availability automatically tends to zero when the 
level of capacity supplied is expected to be adequate to meet the level of capacity demanded;  
(b) remunerate  the  participating  resources  only  for  their  availability  and  ensure  that  the  remuneration 
does not affect decisions of the capacity provider on whether or not to generate;  
(c) ensure that capacity obligations are transferable between eligible capacity providers.  

Figure  8,  in  the  next  page,  summarizes  the  different  steps  prior  to  the  introduction  of  a  capacity 
mechanism by a MS following the CEP provisions. 

32 

 
European/National 
Adequacy 
assessment

ENTSO-E/MSs (for 
national assessments) 

No adequacy 
concerns

Identified 
adequacy concerns

1 

No CM 

Implementation plan 
for market reforms

MSs with Commission 
approval 

No adequacy 
concerns

Residual adequacy 
concerns

1- Study on cross-border effects 
2- Assess strategic reserves 
alternative 
3- Implement other types of CMs not 
distorting market functioning 

Figure 8: New framework for Capacity Mechanisms implementation, source: own illustration 
1.4.5.  Limiting discrimination between existing versus alternative resources  
Demand response providers still face important barriers for participating in capacity mechanisms across 
Europe. The report of the sector inquiry on capacity mechanisms concluded that capacity mechanisms 
should be open to all types of potential capacity providers, except for the mechanisms specific for demand 
response given their particular ability to address market failures, and strategic reserves since they are not 
designed to promote new generation capacity28(EC, 2016d). 
In the first place, the European resource adequacy assessment should appropriately take account of ‘the 
contribution  of  all  resources  including  existing  and  future  possibilities  for  generation,  energy  storage, 
sectoral integration, demand response, and import and export and their contribution to flexible system 
operation.’  It  shall  also  ensure  that  ‘the  national  characteristics  of  generation,  demand  flexibility  and 
energy storage, the availability of primary resources and the level of interconnection are properly taken 
into consideration,’ (art 23(5)(m) of the e-Regulation).  

28According to the same report, ‘market distortions can be kept at a minimum if the reserve is kept as small as possible’.  
Strategic reserve is designed not to promote new generation capacity. 

33 

 
  
 
 
 
 
 
 
                                                           
 
 
 
 
Regarding  the  participation  of  alternative  resources  in  capacity  mechanisms,  the  first  Commission 
proposal  for  e-Regulation  did  not  specify  precise  rules  for  this.  However,  the  final  text  brings  more 
provisions  for  alternative  resources  participation,  inter  alia,  for  the  participation  of  storage,  energy 
efficiency,  and  demand  response.  They  are  stated,  first,  among  the  measures  to  be  considered  for 
eliminating  regulatory  distortions  creating  adequacy  concerns.  Then,  for  the  design  principles,  in  art 
22(1)(h), indicating that any capacity mechanism shall ‘be open to participation of all resources that are 
capable  of  providing  the  required  technical  performance,  including  energy  storage  and  demand  side 
management’.  
1.4.6.  Limiting the impacts on climate goals 
The  e-Regulation  sets  emission  limits  for  MSs  willing  to  subsidize  polluting  generation  units.  Indeed  a 
capacity mechanism shall prevent the most polluting coal power plants in Europe from receiving state aid 
and shall aim to help the EU to reach its climate targets. A grandfathering clause was introduced in art 
22(5),  for  capacity  mechanisms  contracts  that  were  concluded  before  31  December  2019.  This 
grandfathering clause aims to protect investment security, according to Council (2018). 
Art  22(4)  of  the  e-Regulation  introduces  the  Emission  Performance  Standard  (EPS)  to  which  capacity 
mechanisms shall comply: 

- 

- 

‘(a) from 4 July 2019 at the latest, generation capacity that started commercial production on or 
after that date and that emits more than 550 g of CO2 of fossil fuel origin per kWh of electricity 
shall  not  be  committed  or  to  receive  payments  or  commitments  for  future  payments  under  a 
capacity mechanism; 
(b) from 1 July 2025 at the latest, generation capacity that started commercial production before 
4 July 2019 and that emits more than 550 g of CO2 of fossil fuel origin per kWh of electricity and 
more  than  350  kg  CO2  of  fossil  fuel  origin  on  average  per  year  per  installed  kWe  shall  not  be 
committed  or  receive  payments  or  commitments  for  future  payments  under  a  capacity 
mechanism.’ 

These  emissions  limits  ‘shall  be  calculated  on  the  basis  of  the  design  efficiency  of  the  generation  unit 
meaning  the  net  efficiency  at  nominal  capacity  under  the  relevant  standards  provided  for  by  the 
International Organization for Standardization.’ Regarding the calculation of the EPS values, ACER shall 
publish an opinion providing technical guidance related to their calculation by 5 January 2020. Figure 9 
gives an overview about the new emission requirements to participate in capacity mechanism.  

Figure 9: Emission limit (550 g CO2/ kWh) in CMs (Article 22), source : (EC, 2019a) 

34 

 
 
Emissions threshold throughout the ‘trialogue’ negotiations  

These  emissions’ thresholds  have  changed  compared  to  the  first  draft  of  the commission  for  the  e-
Regulation. The Commission introduced in the draft only a 550gr CO2/kWh without differentiation for 
new  and  existing  generation  units.  In  addition,  it  did  not  include  the  clause  excluding  contracts 
approved before 31 December 2019. 

The Council negotiating position included a 550 gr CO2/kWh of energy or a 700 kg CO2 on average per 
year per installed kW threshold for new and existing generation. Existing generation should not receive 
payments  as  of  31  December  2030.  This  could  be  seen  as  a  stricter  provision  as  it  provides  two 
independent metrics. European countries that are heavily dependent on fossil fuels were concerned 
about the EPS provisions (EURACTIV, 2018).  

The Parliament proposed a different limit for strategic reserves, a system widely used in Europe. It has 
also privileged this mechanism over other mechanisms when a country decides to introduce one. The 
final text is a compromise between the different positions. 

This emission limitation will impact the participation of coal-fired and lignite power plants as well as oil-
based plants and gas peaking plants in CMs as they emit, in most cases, more than the stated threshold of 
550 gr CO2/KWh (IEA, 2013). The second metric, expressed in kg CO2 on average per year per installed 
KWe, based on yearly emissions, targets highly emitting plants that are dispatched occasionally (a few 
hours per year).  

Highlights 
-  A European resource adequacy assessment is introduced. It may be complemented by national 
resource adequacy assessments performed by the MS. 
- Common methodologies for reliability standards shall be developed. 
- In case of adequacy concerns, an implementation plan to eliminate identified regulatory distortions 
before implementing CMs shall be developed.  
- MSs shall assess first the potential of strategic reserves to address adequacy concerns before the 
other types of CMs. Specific design principles for strategic reserves are introduced. 
- CMs can be introduced, as a last resort, for possible residual concerns. 
- The participating of the most polluting units is limited by introducing an emission threshold of 
550gr CO2/kWh for new generating units as of 4 July 2019.  
- For existing generation units, they are not eligible to participate in CM if they emit more than 550gr 
CO2/kWh and more than 350 kg CO2 on average per year per installed KWe as of 1 July 2025.  
- CMs shall be open to direct cross-border participation of capacity providers.  
- TSOs shall annually calculate this maximum entry capacity available for cross-border participation, 
based on RCCs recommendation. 
- MSs applying CMs on 4 July 2019 shall adapt their mechanisms to comply with the described 
provisions, without prejudice to commitments or contracts concluded by 31 December 2019. 

Interlinkage with Network codes  

1.5. 
In what follows, we discuss the interlinkages between topics that are covered in the first generation of 
network  codes  and  that  are  also  addressed  in  the  CEP,  i.e.  balancing  responsibilities,  the  regional 
governance of system operation, bidding zones, and the calculation of interconnection capacities.  

35 

 
 
 
 
The first generation of network codes includes:  

●  The market codes: 

o  Commission  Regulation  (EU)  2015/1222  of  24  July  2015  establishing  a  guideline  on 

capacity allocation and congestion management (CACM) 

o  Commission Regulation (EU) 2016/1719 26 September 2016 establishing a guideline on 

forward capacity allocation (FCA) 

o  Commission Regulation (EU) 2017/2195 of 23 November 2017 establishing a guideline on 

electricity balancing (EB GL)  

●  The connection codes: 

o  Commission Regulation (EU) 2016/631 of 14 April 2016 establishing a network code on 

requirements for grid connection of generators (RfG NC)  

o  Commission Regulation (EU) 2016/1388 of 17 August 2016 establishing a network code 

on demand connection (DCC)  

o  Commission Regulation (EU) 2016/1447 of 26 August 2016 establishing a network code 
on requirements for grid connection of high voltage direct current systems and direct 
current-connected power park modules (HVDC NC)  

●  The operation codes: 

o  Commission  Regulation  (EU)  2017/1485  of  2  August  2017  establishing  a  guideline  on 

electricity transmission system operation (SO GL)  

o  Commission  Regulation  (EU)  2017/2196  of  24  November  2017  establishing  a  network 

code on electricity emergency and restoration (ER)  

For a more complete introduction to the first generation of network codes, see Schittekatte et al., (2019). 

1.5.1.  Balancing responsibilities  
Balancing in network codes 

The Balancing Guideline (EB GL) has been adopted as a Commission Regulation and entered into force in 
18  December  2017.    Balancing  responsibilities  are  not  explicitly  mentioned  in  the  electricity  network 
codes. However, the EB GL art 18(1) states that no later than six months after its entry into force and for 
all scheduling areas of a MS, a national proposal regarding the terms and conditions for BSPs and BRPs 
should be submitted by the TSOs of this MS. This proposal, which is currently under development in the 
different MSs, shall contain the definition of balance responsibility for each (Schittekatte et al., 2019). Art 
18(4d) of the EB GL adds that terms and conditions for BRPs shall ‘require that each balancing energy bid 
from a balancing service provider is assigned to one or more balance responsible parties to enable the 
calculation of an imbalance adjustment pursuant to Article 49.’ 
The different terms & conditions as well as methodologies of the EB GL are currently in the development 
or  approval  process  (ACER,  2019a).  ACER’s  first  monitoring  report  on  the  implementation  of  EB  GL  is 
expected to be issued in 2020 (ACER, 2019b). 

CEP measures on balancing responsibilities 

Art 2 of the e-Regulation defines a BRP as ‘a market participant or its chosen representative responsible 
for its imbalances in the electricity market.’ The balance responsibility is passed on to the BRP before the 
actual delivery. A BRP can represent one or more electricity generators, suppliers and/or large consumers. 

On  balancing  responsibility,  art  4  of  the  e-Regulation  indicates  in  the  first  paragraph  that  ‘all  market 
participants shall be responsible for the imbalances they cause in the system.’ Thus, market participants 
shall either be BRPs or delegate contractually their responsibility to a BRP. The article adds that each BRP 
shall be financially responsible for its imbalance, strive to be balanced, and aim to keep the power system 
balanced. 

36 

 
Derogations from balance responsibilities 

MSs may provide derogations from balance responsibility only for projects the following characteristics, 
art 4(2) of the regulation: 

‘(a) demonstration projects for innovative technologies, subject to approval by the regulatory authority, 
provided that those derogations are limited to the time and extent necessary for achieving the 
demonstration purposes;  

(b) power-generating facilities using renewable energy sources with an installed electricity capacity of 
less than 400 kW;  

(c) installations benefitting from support approved by the Commission under Union State aid rules 
pursuant to Articles 107, 108 and 109 TFEU, and commissioned before 4 July 2019.’ 

When  such  derogations  are  given,  MSs  ‘shall  ensure  that  the  financial  responsibility  for  imbalances  is 
fulfilled  by  another market  participant.’  From  1  January  2026,  point  (b) of  art 4(2)  shall  apply  only  ‘to 
generating installations using renewable energy sources with an installed electricity capacity of less than 
200 kW’ (art 4(3)). 

1.5.2.  System operation regional governance 
RSCs in network codes 

The system operation guideline (SO GL) introduced the establishment of Regional Security Coordinators 
(RSCs). RSCs are owned or controlled by TSOs and perform tasks related to TSO regional coordination. The 
SO GL states that each control area shall be covered by at least one RSC. A control area is defined as a 
coherent part of the interconnected system, operated by a single system operator. RSCs combine the tasks 
outlined in the SO GL and the capacity calculation stated in the CACM. Regional cooperation in SO allows 
TSOs to have a regional vision on threats to SO coming from regional power flows. The TSOs remain in 
charge of security of supply and consequently of the final operational decision-making. RSCs are intended 
to provide five core services. They are presented in Figure 10. 

Figure 10: Services provided by RSCs to TSOs, source: (ENTSO-E, 2016) 

The implementation of Regional Coordination Centres (RCCs) 

Originally introduced as Regional Operational Centres (ROC) in the Commission proposal, these bodies will 
finally be called Regional Coordination Centres (RCCs), which is the version chosen by the Parliament. Two 
proposals, introduced by the e-Regulation, shall be made regarding the implementation of RCCs. The first 
by ENTSO-E to ACER for their geographical scope, called System Operation Region (SOR), and the second 
by TSOs to their NRAs for RCCs’ establishment which includes an implementation plan. The RCCs will have 
to be set up by 1 July 2022 replacing the regional security coordinators (RSCs). This date is sooner than 
what the Council proposed29.  

29 The Council proposed a RCCs start date of January 2025. 

37 

 
 
 
                                                           
In  the  first  proposal, ENTSO-E  shall  submit  to  ACER, by  six months  from  the  entry  into  force  of  the  e-
Regulation, a proposal on SORs, the geographical scope of RCCs, ‘specifying which transmission system 
operators,  bidding  zones,  bidding  zone  borders,  capacity  calculation  regions  and  outage  coordination 
regions are covered by each of the system operation regions.’ It shall consider the grid topology, inter alia, 
the degree of interconnection and the interdependency of the power system in terms of flows. The size 
of the SOR shall cover at least one capacity calculation region (art 36(1)). This aims to set effective RCCs 
contribution  to  the  coordination  of  the  operations  of  TSOs  over  regions,  as  well  as  increasing  system 
security and market efficiency. TSOs of a SOR shall participate in the RCC of that region. In cases where 
the control area of a TSO is part of different synchronous areas, the TSO may be exceptionally coordinated 
by two RCCs. To better understand the new geographical scope of RCCs, Figure 11 shows a map of the 
CCRs as of the 1st of January 2019 on the left and of RSCs on the right. 

ACER  shall  either  approve  ENTSO-E  proposal  defining  the  SORs  or  propose  amendments  within  three 
months of its reception. In the case of amendments, ACER shall consult ENTSO-E before adopting them. 
ACER shall, afterward, publish the proposal on its website.  

Figure 11: Left – The Capacity Calculation Regions (CCRs), status as on the 1st of January 2019  (ACER, 2019c) Right – Map of 
the Regional Security Coordinators in Europe as established by the end of 2016 (ENTSO-E, 2019) 

In the second proposal, according to art 35(1), all TSOs of a SOR, which is the region to be covered by a 
RCC,  shall  submit,  within  twelve  months  after  entry  into  force  of  the  Regulation,  a  proposal  for  the 
establishment of RCCs to their respective  NRAs. NRAs of the  system operation region shall review  the 
proposal and approve it. The different elements that shall be at least included in the proposal are set out 
in  art  35(1).  Among  them,  we  find  the  location  of  the  RCC  (the  MS  of  the  RCC  prospective  seat),  the 
participating TSOs, arrangements regarding the RCC organization, finance, operations, and liability as well 
as the RCC implementation plan for the entry into operation. RCCs shall replace RSCs established pursuant 
to the SO GL after the NRAs’ approval of the TSOs’ proposal according to art 35(2) of the e-Regulation. 

38 

 
 
 
 
 
Tasks of Regional Coordination Centres (RCCs) 
RCCs tasks complement the RSCIs30 voluntary TSOs’ approach and the RSCs established in the SO GL of the 
Network  Codes  as  shown  in  Figure  12. They  were  set  to  perform  regionalisation  tasks where  it  brings 
benefit for the system and market operation, compared to actions performed at national level. ENTSO-E 
role regarding RCCs is to ensure that their activities are coordinated across the regions' boundaries. RCCs’ 
tasks do not include the real-time operation of the electricity system, which remains a task of national 
TSOs.  In  contrast  to  the  e-Regulation  proposal  of  the  Commission,  ROCs’  ‘’binding  decisions”  were 
replaced by RCCs’ “coordinated actions”. 

The full list of tasks that shall be carried out by RCCs is available in art 34 and with more details ANNEX I 
of the e-Regulation. Some tasks shall be performed and others may be performed subject to the request 
of TSOs or the delegation from ENTSO-E. They shall also perform coordinated security analysis and create 
common grid models, in accordance with the methodologies developed following the SO GL. 

Note  also  that  the  Emergency  and  Restoration  Network  Code  (ER  NC)  states  that  RSCs,  which  will  be 
replaced by RCCs, shall be consulted to assess the consistency of a TSO system defence and restoration 
plan measures within its synchronous area and in the plans of neighbouring TSOs belonging to another 
synchronous area (ER NC, Art. 6(1)). In the e-Regulation, more clear roles for RCCs regarding the support 
for TSOs' defence and restoration plans with regard to the consistency assessment and the coordination 
and optimisation of regional restoration. 

Figure 12: Sequence of ROCs functions, adapted from: EC (2017b) 

To fulfill these tasks, RCCs shall be entrusted with the necessary powers to coordinate the actions of the 
TSOs  in the system operation region  for certain functions,  and with an enhanced advisory role for the 
remaining tasks. The e-Regulation adds that their resources should not go beyond what is necessary to 
perform their tasks. 
1.5.3.  Bidding zones and capacity calculation between zones 
Bidding zones in Europe  
Europe is divided into different bidding zones, as shown in Figure 13. Currently, their configurations are 
mainly defined by national borders (e.g., France or Spain). Other bidding zones can be within the same 

30 The Regional Security Coordination Initiatives (RSCIs) were launched voluntarily by TSOs since 2009. They aim to improve TSOs 
cooperation by covering a greater part of the European interconnected networks. CORESO and TSC are the pioneers in this respect 
in continental Europe (ENTSO-E, 2015). 

39 

 
 
                                                           
 
countries (Italy or Sweden) or grouping more than one country (Germany and Luxembourg). Austria was 
part of this bidding zone together with Germany and Luxembourg until its split in October 2018. 
Within a bidding zone, wholesale electricity prices are the same per market time unit. Market participants 
who  wish  to  trade  electricity  in  another  bidding  zone  have  to  consider  bidding  zone  interconnection 
constraints. As long as electricity can flow freely through the interconnector (no congestion), there will be 
a single price across the markets. However, when the cross-zonal interconnector is congested between 
bidding zones, prices can diverge between those zones. The markets of the two bidding zones are in this 
case split. The price differential between the two interconnected bidding zones, in case of congestion, 
multiplied  by the  capacity of  the  line  is  called  the  congestion  rent,  and  this  is a  revenue  for  the TSOs 
owning the interconnection31.  
Regarding congestion income, art 19(2) states that ‘the following objectives shall have priority with the 
respect to the allocation of any revenues resulting from the allocation of cross-zonal capacity:  

‘(a) guaranteeing the actual availability of the allocated capacity including firmness compensation; or  

(b)  maintaining  or  increasing  cross-zonal  capacities  through  optimisation  of  the  usage  of  existing 
interconnectors by means of coordinated remedial actions, where applicable, or covering costs resulting 
from network investments that are relevant to reduce interconnector congestion.’ 

When these objectives are fulfilled, the revenues may be used as income to be taken into account by NRAs 
when  approving  network  tariffs  calculation  methodology  or  fixing  network  tariffs,  or  both.  Then  the 
residual revenues shall be placed on a separate internal account line until such a time as it can be spent 
for the same objectives. 

Regarding the use of revenues with respect to these objectives, a methodology shall be proposed by the 
TSOs after consulting NRAs and relevant stakeholders and after approval by ACER. The TSOs shall submit 
the proposed methodology to ACER by 5 July 2020. ACER shall decide then on the proposed methodology 
within six months of receiving it. It may request  from  TSOs  to amend or update the methodology and 
decide on it within six months from the submission. 

In addition, art 19(5) states that TSOs shall clearly establish beforehand how any congestion income will 
be used. They shall also report on the actual use of that income. In addition, ‘by 1 March each year, the 
regulatory authorities shall inform ACER and shall publish a report setting out:  

(a) the amount of revenue collected for the 12-month period ending on 31 December of the previous year;  

(b) how that revenue was used pursuant to paragraph 2, including the specific projects the income has 
been used for, and the amount placed on a separate account line; 

(c) the amount that was used when calculating network tariffs; and  

(d) verification that the amount referred to in point (c) complies with this Regulation and the methodology 
developed pursuant to paragraphs 3 and 4.’ 

Art 19(5) adds that in the case of some of the congestion revenues being used when calculating network 
tariffs, the  NRAs report  shall set out how  the  TSOs  fulfilled the stated  objectives  regarding congestion 
income set out in art 19(2). 

31 For example, imagine that during a certain hour the interconnectors between two bidding zones are congested. The price in 
one bidding zone equals 30 €/MWh and 40 €/MWh in the other. The interconnection capacity between the two bidding zones is 
500 MW. This means that the congestion rent for this hour is 5,000 €.  

40 

 
                                                           
Figure 13: New bidding zones configuration in Europe as of May 2019, source: own illustration 

A review process, to be taken by TSOs, has been formalized in legislation as part of the CACM Guideline 
on  the  existing  and  possible  alternative  configurations.  It  aims  to  ensure  the  alignment  between  the 
market and the physical characteristics of the electricity grid, thereby increasing trades. It also reduces 
the need for costly remedial actions32 and enhances the security of supply (SoS) by ensuring that electricity 
flows where it is most needed. The review can be launched by ACER, NRA(s), TSO(s) or MSs. It consists of 
two  steps  stated  in  art  32  of  the  CACM;  first  participating  TSOs  ‘shall  develop  the  methodology  and 
assumptions that will be used in the review process and propose alternative bidding zone configurations 
for  the  assessment’  and  submit  it  to  NRAs.  Second,  participating  TSOs  shall  ‘assess  and  compare  the 
current bidding zone configuration and each alternative bidding zone configuration’, hold a consultation 
and  a  workshop  regarding  the  alternative  bidding  zone  configuration  and  submit  a  joint  proposal  to 
maintain or amend the bidding zone configuration to participating MSs within 15 months of the decision 
to start the review. MSs shall reach an agreement within six months. 
In November 2017, ENTSO-E developed the first edition of the bidding zone review (ENTSO-E, 2017b). The 
review was  based on three  categories of criteria: network  security, market efficiency and stability and 
robustness of bidding zones, as prescribed in the CACM. The participating TSOs recommended maintaining 
the current bidding zone delimitation. This was quite a lengthy process. Early studies began in 2012, where 
ACER  invited ENTSO-E to initiate  a pilot project on bidding zone  configuration assessment and review. 
ENTSO-E published a technical report in January 2014, followed by the ACER Market Report in March 2014. 
Based on those early findings, in the spring of 2015 ENTSO-E began its investigation on the technical and 

32 Remedial action according to art 2(13) of CACM Regulation as “any measure applied by a TSO or several TSOs, manually or 
automatically,  in  order  to  maintain  operational  security.”  They  may  include re-dispatching, countertrading,  Demand  Side 
Response, increase/decrease energy storage, topology changes in the network. 

41 

 
 
                                                           
 
economic  efficiency  of  the  current  European  bidding  zones,  including  the  possibility  of  splitting  the 
German-Austrian bidding zone (Rossetto, 2017). 
CEP measures on bidding zones 
A  bidding  zone  review  aims  to  address  long-term  structural  congestion.  The  process  of  bidding  zone 
configuration  has  experienced  several  proposals  and  positions  from  the  different  EU  institutions.  The 
Commission  proposed  in  its  draft  e-Regulation  that  more  powers  would  be  given  to  EU  institutions to 
decide on bidding zone configuration following the bidding zone review. The Commission was given the 
task of adopting a decision whether to amend or maintain the bidding zone configuration. The Council 
position for the e-Regulation had foreseen more national decision-making powers for the bidding zones 
review. In the Council position, ACER was also tasked to decide on the methodology of the review if the 
relevant  NRAs  do  not  come  to  a  unanimous  decision  within  three  months,  (art  13(3)  of  the  Council 
position). The bidding zone review shall be submitted in a joint proposal by the participating TSOs to the 
relevant Member States or designated NRAs. The final text of the e-Regulation highlights the importance 
of addressing structural congestion, defined in art 2(2)e as a ‘congestion in the transmission system that 
is  capable  of  being  unambiguously  defined,  is  predictable,  is  geographically  stable  over  time,  and 
frequently reoccurs under normal electricity system conditions.’  
Bidding zone configuration shall reflect long-term structural congestions in the transmission grid. MSs can 
choose  between  a  bidding  zone  reconfiguration  or  measures  such  as  grid  reinforcement  and  grid 
optimization. According to art 14(1), ‘bidding zones shall not contain such structural congestions unless 
they  have  no  impact  on  neighbouring  bidding  zones,  or,  as  a  temporary  exemption,  their  impact  on 
neighbouring  bidding  zones  is  mitigated  through  the  use  of  remedial  actions  and  those  structural 
congestions do not lead to reductions of cross-zonal trading capacity in accordance with the requirements 
of Article 1633.’  

Two main measures are stated in art 14 of the e-Regulation related to bidding zones. The first one is on 
the identification of structural congestions and the second one on bidding zone review. 
The identification of long term structural congestions can be done via three means; ENTSO-E’s report on 
structural congestion (art 14(2)), TSOs assessments or the bidding zone review itself (art 14(7)).  When 
structural congestion is identified, the MS in cooperation with its TSOs shall decide, within six months of 
receipt of the report, ‘either to establish national or multinational action plans pursuant to Article 15, or 
to review and amend its bidding zone configuration’ (art 14(7)). These Action Plans shall contain network 
investments to be achieved by the end of 2025. They shall also include a concrete timetable for adopting 
measures  reducing  the  identified  structural  congestions  within  four  years  of  the  adoption  of  the  MS 
decision of art 14(7). The Commission and ACER shall be notified immediately by those decisions. In the 
case of a structural congestion having been identified but no action plan having been defined within 6 
months, the relevant TSOs shall, ‘within 12 months of identification of such structural congestion, assess 
whether the available cross-border capacity has reached the minimum capacities provided for in Article 
16(8) during the previous 12 months  and shall submit an assessment report  to the relevant regulatory 
authorities and to ACER.’ If the minimum level of interconnector capacity is not reached, the decision-
making process of art 15(5), regarding MSs unanimous decision and the Commission last resort decision 
after consulting ACER and the relevant stakeholders, applies. 
Regarding  the  bidding  zones  review,  art  14(3)  states  that  the  review  ‘shall  identify  all  structural 
congestions  and  shall  include  an  analysis  of  different  configurations  of  bidding  zones  in  a  coordinated 
manner with the involvement of affected stakeholders  from all relevant Member States (…).’  This shall 
follow the CACM Regulation that provides a framework for bidding zones reconfiguration (art 32-34). Art 
14(5) adds that ‘by 5 October 2019 all relevant transmission system operators shall submit a proposal for 

33 Art 16 on General principles of capacity allocation and congestion management 

42 

 
                                                           
the  methodology  and  assumptions  that  are  to  be  used  in  the  bidding  zone  review  process  and  for  the 
alternative  bidding  zone  configurations  to  be  considered  to  the  relevant  regulatory  authorities  for 
approval.’  This  time  limit  was  not  included  in  the  CACM  process.  Then,  NRAs  ‘shall  take  a  unanimous 
decision on the proposal within 3 months of submission of the proposal.’ If NRAs fail to reach a unanimous 
decision on the proposal within the 3 months, then ACER shall decide, within an additional 3 months, on 
the methodology and assumptions of the bidding zone review process, as well as the alternative bidding 
zone configurations to be considered. 
CEP measures for interconnector capacity calculation 
The rules on capacity allocation, as stated in the e-Regulation, require the allocation of maximum capacity 
to market participants on the bidding zone border. According to art 16(4), ‘the maximum level of capacity 
of the interconnections and the transmission networks affected by cross-border capacity shall be made 
available to market participants complying with the safety standards of secure network operation.’ It adds 
that  ‘counter-trading  and  redispatch,  including  cross-border  redispatch,  shall  be  used  to  maximise 
available capacities to reach the minimum capacity provided for in paragraph 8. A coordinated and non-
discriminatory  process  for cross-border  remedial  actions  shall  be  applied  to  enable  such  maximisation, 
following the implementation of a redispatching and counter-trading cost-sharing methodology.’ 

Art 16(8) of the e-Regulation introduces the minimum levels of available capacity for cross-zonal trade to 
be reached. These minimum levels were not included in the Commission proposal of the e-Regulation but 
were introduced in the Council position. 

TSOs, according to art 16(8), shall not limit the volume of interconnection capacity to be made available 
to market participants in order to solve congestion inside their bidding zone or as a means of managing 
flows from transaction internal to bidding zones34. The minimum levels of available capacity for cross-
zonal trade, also called minRAM, to be complied with are:  

‘(a) for borders using a coordinated net transmission capacity approach, the minimum capacity shall be 70 
% of the transmission capacity respecting operational security limits after deduction of contingencies, as 
determined in accordance with the capacity allocation and congestion management guideline adopted on 
the basis of Article 18(5) of Regulation (EC) No 714/2009;  

(b) for borders using a flow-based approach, the minimum capacity shall be a margin set in the capacity 
calculation process as available for flows induced by cross-zonal exchange. The margin shall be 70 % of the 
capacity respecting operational security limits of internal and cross-zonal critical network elements, taking 
into  account  contingencies,  as  determined  in  accordance  with  the  capacity  allocation  and  congestion 
management guideline adopted on the basis of Article 18(5) of Regulation (EC) No 714/2009.’  

The  article  adds that  ‘the total  amount  of 30 %  can be  used  for  the reliability margins,  loop  flows  and 
internal flows on each critical network element.’ Moreover, note that ACER (2019c) decision on the CORE35 
Capacity  Calculation  Methodology,  which  already  considers  the  recast  e-Regulation,  states  that 
‘independently  from  the  minRAM  trajectory  and  from  transit  flows,  at  least  20%  Fmax  shall  remain 
available for trade within Core.’ 
Note that the 70% minimum capacity available for trade applies in general from January 2020. However, 
for the purpose of implementing art 14(7), on action plans adoption decisions, and art 15(2), on the linear 
trajectory achievement, the minimum applies from EIF which is July 2019. Figure 14 explains the changes 
in cross-zonal and also internal capacity for Critical Network Elements and Contingencies (CNECs).  

34  Flows over a bidding zone caused by having the origin and destination within one zone. 
35 Core is a Capacity Calculation Region (CCR), which comprises Austria, Belgium, Croatia, the Czech Republic, France, Germany, 
Hungary, Luxembourg, the Netherlands, Poland, Romania, Slovakia and Slovenia. See Figure 11 for its representation. 

43 

 
                                                           
The ‘starting point’ shall be calculated pursuant to art 15(2) for each Critical Network Element (CNE), or 
border and see how does it compare to 70%. A CNE, according to ENTSO-E (2017c) is ‘a network element 
either within a bidding zone or between bidding zones monitored during the CCC36 process’. It can be an 
overhead line, underground cable or transformer that is significantly impacted by cross-border exchange. 
The CNEC (Critical Network Element and Contingencies) is a ‘CNE limiting the amount of power that can 
be exchanged, potentially associated to a contingency.’ Internal CNECs can be included based on efficiency 
considerations and may impact cross-border CNEC. Note that, according to ACER (2019c), ‘internal CNECs 
are allowed only for a transition period (2 years). After the transition period, internal CNECs are allowed 
only if other alternatives are less efficient.’ 

Figure 14: Breakdown of the transmission capacity, source: (ACER, 2019d) 

-The way the flow reliability margin (FRM) is described in detail in the Capacity Calculation Methodology 
(ENTSO-E, 2018a). The FRM shall cover the following uncertainties:  
- ‘Core external transactions (out of Core CCR control: both between Core CCR and other CCRs as well as 
among TSOs outside the Core CCR);  
- Generation pattern including specific wind and solar generation forecast;  
- Generation shift key;  
- Load forecast;  
- Topology forecast;  
- Unintentional flow deviation due to the operation of frequency containment reserves;  
-  Flow-based  capacity  calculation  assumptions  including  linearity  and  modelling  of  external  (non-Core) 
TSOs’ areas.’ 

The unscheduled allocated flows (UAF) or transit flows are flows due of exchanges outside of Core CCR. 
They are calculated,  according  to  ACER  (2018)  as  the  difference  between ‘scheduled  flows’  (known  as 
schedules,  SCHs),  representing  administrative  (calculated)  flows  resulting  from  capacity  allocation  and 
‘actual flows’ coming from capacity allocation (allocated flows, AFs). 

Two derogations from the 70% threshold are possible; 

A.  Derogation related to RCCs conclusion on available remedial actions 

The first  derogation, stated in  art 16(9), is related to the calculation of the threshold and  where  RCCs 
conclude that all available remedial actions in the CCR or between CCRs are not sufficient to reach the 

36 Coordinated Capacity Calculation 

44 

 
 
 
                                                           
70% threshold while respecting operational security limits. Then, RCCs may as a measure of last resort, 
‘set  out  coordinated  actions  reducing  the  cross-zonal  capacities  accordingly.’  TSOs  ‘may  deviate  from 
coordinated actions in respect of coordinated capacity calculation and coordinated security analysis only 
in accordance with Article 42(2)’ 

By 3 months after the entry into operation of the RCCs and every three months thereafter, the RCCs shall 
report to the relevant NRAs and ACER on reductions of the capacity or any deviations from the coordinated 
actions. They ‘shall assess the incidences and make recommendations, if necessary, on how to avoid such 
deviations in the future.’ If ACER concludes that the prerequisites for a deviation were not fulfilled or are 
of a structural nature, it shall ‘shall submit an opinion to the relevant regulatory authorities and to the 
Commission.  The  competent  regulatory  authorities  shall  take  appropriate  action  against  transmission 
system operators or regional coordination centres pursuant to Article 59 or 62 of Directive (EU) 2019/944 
if the prerequisites for a deviation pursuant to this paragraph were not fulfilled.’ 

B.  Derogation upon TSOs request for maintaining the system operational security 

The second derogation may be granted by relevant NRAs upon request by TSOs of a CCR according to art 
16(9).  It  shall  have  foreseeable  reasons  where  it  is  necessary  for  maintaining  the  system  operational 
security.  It  shall  be  limited  to  one  year  at  a  time,  or  up  to  a  maximum  two  years  with  a  significantly 
decreasing level of the derogation after the first year. Art 16(9) adds that ‘the extent of such derogations 
shall  be  strictly  limited  to  what  is  necessary  to  maintain  operational  security  and  they  shall  avoid 
discrimination between internal and cross-zonal exchanges.’  

The NRA has to consult the relevant other NRAs of an affected CCR before granting this derogation. If one 
of them disagrees, ACER shall decide on the derogation according to art 6(10)(b) of the ACER Regulation 
(EU) 2019/942 giving ACER the right and competency to adopt individual decisions on regulatory issues 
having effects on cross-border trade. Note that ‘where a derogation is granted, the relevant transmission 
system  operators shall develop and publish a methodology and projects that  shall provide a long-term 
solution to the issue that the derogation seeks to address. The derogation shall expire when the time limit 
for the derogation is reached or when the solution is applied, whichever is earlier.’ 

Highlights 
- All market participants shall aim for system balance and shall be financially responsible for imbalances 
they cause in the system. Derogations are possible for projects with certain characteristics. 

- RCCs will have to enter into operation by July 2022. They gradually build on RSCs and aim to strength 
regional cooperation between TSOs through providing coordinated actions and recommendations.  
-RCCs  complement  TSOs  roles  to  ensure  secure  and  reliable  operation  of  the  interconnected 
transmission system. 
-  MSs  can  choose  between  an  Action  Plan  with  network  investments  until  2025,  or  a  bidding  zone 
reconfiguration  to  address  structural  congestion.  The  Commission  may  intervene  in  the  decision 
making process, as a measure of last resort, if no agreement between MSs. 

- Maximisation of trade across borders. A threshold of 70% for minimum available capacity for cross-
zonal trade that TSOs have to comply with. Derogations are possible, at the request of the TSOs in a 
CCR. 

- The e-Regulation applies in general from Jan 2020. However, for the purpose of implementing art 
14(7)  on  action  plans  establishment  and  art  15(2)  on  cross-zonal  trade  capacity  increase,  art  16, 
including the 70% minimum cross-border transmission capacity threshold, applies from the EIF (4 July 
2019). 

45 

 
 
 
 
2. Adapting to the decentralisation of the power system 

In  this  section,  we  set  the  scene  by  introducing  the  DSO  landscape  in  Europe.  We  then  focus  on  key 
measures included in the CEP to adapt the DSOs’ roles and responsibilities to the ongoing decentralisation 
of the power system. This includes increased expectations in their traditional roles of network planning 
and network management. It also covers the limitations that have been introduced for DSO ownership of 
EV charging infrastructures, storage facilities, and for data management by DSOs. To conclude, we discuss 
the establishment of an EU DSO entity, and the interlinkages between DSO topics and network codes.  

2.1.  Setting the scene: The DSO landscape  
There are around 2,600 DSOs (Figure 15) that own and operate around 10 million km of power lines in 
Europe.  They  employ  around  240,000  people  and  service  260  million  customers.  About  90  %  of  these 
customers are residential and small businesses  (Meeus and Glachant, 2018). 

Figure 15: Number of electricity DSOs per Member State, source: (EC, 2016b) 

Despite the large number of DSOs in Europe, the distribution industry is rather concentrated. In countries 
such as Ireland and Slovenia there is only one DSO. In France (148 DSOs) and Italy (151 DSOs), there is one 
dominant DSO and many small players sharing small market shares. In other MSs we find a significantly 
lower  concentration.  For  instance,  in  Austria  (128 DSOs),  Belgium  (26  DSOs),  Sweden  (170 DSOs),  and 
Germany (883 DSOs) where the three largest DSOs represent less than half of the industry (Meeus and 
Glachant, 2018). Today, according to data from EC (2016b), only 13% of the European DSOs have more 
than 100,000 connected customers. 

DSOs  are  represented  in  five  different  industry  associations  based  in  Brussels:  EURELECTRIC,  GEODE, 
CEDEC, EDSO for Smart Grids and REScoop. The larger DSOs in Europe work together within the association 
EDSO  for  smart  grids.  This  association  has  about  30  members  that  represent  more  than  70  %  of  the 
industry. EURELECTRIC gathers electricity industry companies (generators and retailers, most of them are 
not ownership-unbundled). CEDEC and GEODE represent smaller ‘local’ and ‘regional’ energy distributors. 
REScoop is the federation of energy cooperatives that undertake distribution activities in some cases.  

46 

 
 
 
2.2.  Current practices  
According  to  CEER  (2015),  DSOs  activities  can  be  separated  into  three  categories.  This  categorization 
regards the nature and the different businesses at the distribution network:  

●  Core activities, such as planning, developing, operating and maintaining the network, connecting 

users to the grid, managing technical data and managing network losses; 

●  Prohibited activities such as electricity generation; 
●  Non-core  activities  or  grey  areas  where  there  are  concerns  about  DSOs  activities,  such  as 
infrastructure  for  EVs,  flexibility  services  such  as  the  ownership  of  flexibility  assets,  managing 
metering data for customers. 

Their logical framework for categorizing DSOs activities is described in Figure 16. 

Figure 16: Logical Framework for DSO Activities, source: (CEER, 2014) 

For the grey areas, there is no single model defining how they should be regulated. The DSO involvement 
in areas such as the ownership of storage and EV charging infrastructure is allowed in some MSs under 
certain  conditions.  In  such  cases,  the  aim  is  to  help  the  development  of  this  sector  on  a  provisional 
mandate until the market evolves into actual competition. 
2.2.1.  Traditional Roles  
In what follows, we discuss the traditional DSO roles in network planning and network management. 

Network planning 

The  EC  (2015b)  study on tariff design for distribution systems presents the main features of the DSOs 
network  development  process.  It  considers  whether  the  distribution  network  development  plan  is 
published  in  different  MSs  and  whether  the  investments  are  subject  to  approval  by  the  NRAs  or  the 
government. 

Across  Europe,  only  DSOs  in  Italy,  Portugal,  Hungary,  the  Netherlands,  Poland,  UK,  and  Germany  (for 
network assets at high voltage distribution level) publish distribution network development plans. In six 
MSs (Spain, Greece, Poland Portugal, Romania, and Slovenia) distribution network development plans are 
approved  by  regulators.  In  France,  Germany,  and  Lithuania,  the  regulator  approves  only  selected 
investments. Figure 17 gives an overview of the situation in various MSs. 

47 

 
Figure 17: Published distribution network development plans (DNDP), based on: (EC, 2015b) 

The  Commission  report  adds  that  the  decision‐making  process  of  distribution  network  development 
appears  less  structured  and  transparent  than  for  transmission  network  development  in  most  MSs. 
However, the importance of the process has increased with the recent trends in the sector. Distribution 
and transmission system operators may need to take a coordinated approach to network planning and 
development with transparent data exchange processes for an increased overall efficiency and quality of 
the electricity network. For instance, planned reinforcements on the transmission network may offset the 
need for reinforcements of the distribution system.  

Some countries allow planning flexibility options for DSOs in order to optimize their network planning. 
Indeed, in Germany, the amendment of the Energy Act in 2016 allows DSOs to consider curtailment in the 
planning of distribution grid expansion. The government allows TSOs and DSO to curtail a maximum of 3% 
of onshore wind and PV in their network development plans. This aims to avoid high grid investments. In 
Figure 18 from the BMWi (2014) study, we can see that a 3% curtailment, in the EEG scenario, can bring 
up to 40% of saving in investment expansion. This rule is, however, optional and DSOs can choose not to 
consider it in their planning (Furusawa et al., 2019).   

Figure 18: The saving network expansion by the curtailment of RES energy, source: (BMWi, 2014) 

48 

 
 
 
Network management 

Today, some DSOs have already started to consider procuring flexibility services to re-dispatch the system 
at the level of distribution grids. However, in most countries, there are no rules in place that allow DSOs 
to do that. According to the EvolvDSO37 project survey, in countries like France, Ireland, Italy, or Portugal, 
DSOs are not able to contract flexibility for congestion management, except possibly for pilot projects. 
Discussions on the topic are ongoing in these countries. In others, like Belgium and Germany38, DSOs can 
obtain system flexibility services via connection and distribution access contracts. These contracts provide 
a reduced network fee in exchange of the unit control by the DSO. CEDEC et al. (2019) TSO–DSO report 
focusing on TSO–DSO coordination in congestion management and balancing presents different market 
models for flexibility procurement. It aims to provide, based on discussion with the main stakeholders, 
sharing TSOs and DSOs needs, a framework that could be used for assessment at the EU level, leaving 
freedom  for  MSs  to  choose  the  model  to  implement.  Three  main  options  for  models  were  derived 
depending on the links between congestion management and balancing. The first one is where TSO and 
DSO  have  separated  congestion  management  markets.  This  requires  coordination  between  market 
processes. The second is with combined TSO and DSO congestion management, with separated balancing. 
This model gathers TSOs and DSOs needs, which may overlap. The third model is with combined balancing 
and  congestion  management  for  all  system  operators  together.  The  different  market  models  need 
appropriate governance with clear processes to manage interactions.  

The implementation of these different market models can take place through different platforms options. 
The CEDEC et al. (2019) report also presents different platforms options that can be used according to the 
market model chosen as both issues are linked. A digital platform is defined, in CEDEC et al., (2019), as a 
‘(distributed) software functionality, needed by actors to perform their tasks, corresponding to their roles 
and  responsibilities,  which  as  part  of  an  ecosystem  interacts  with  other  relevant  actors  in  the  energy 
system.’ Four platforms options are presented. In the first option DSOs and TSOs interact with flexibility 
service providers via their own separately developed platforms. In the second option, DSOs interact with 
flexibility providers directly in the market or via congestion management market platforms, and the TSO 
uses the balancing platform also for congestion management. In the third option, DSOs and TSOs use a 
combined platform for congestion management, where TSO–DSO coordination might take place through 
algorithms to avoid conflicts and double-activation of flexibility). TSOs continue to operate their separate 
platform for balancing. In the fourth option, DSOs and TSOs interact with flexibility providers through a 
joint  platform  market  trading  platforms  for  DSOs  and  TSOs  congestion  management  as  well  as  TSOs 
balancing. 

In Europe, there are currently DSOs, TSOs, and other market actors that have started to develop platforms 
for procuring and trading flexibility services. Figure 19, in the next page, presents a mapping of the main 
flexibility  pilot  projects  in  Europe.  Among  these  pilot  projects,  there  are  pilot  demonstrators  (e.g., 
SmartNet  and  INTERRFACE)  that  are  elaborated  in  the  framework  of  R&D  projects  to  test  new 
functionalities.  Others  are  pilots  for  commercial  projects  aiming  for  a  wider  scale  implementation. 
Schittekatte  and  Meeus  (2019)  have  studied  four  pioneering  projects;  Piclo  Flex,  Enera,  GOPACS,  and 
NODES, implementing flexibility markets and analysed the projects over a six-question framework that 
covers,  for  instance,  their  integration  in  electricity  market  sequence  and  the  existence  of  TSO-DSO 
cooperation for the organisation of the flexibility market. 

37 EvolvDSO (‘Development of methodologies and tools for new and evolving DSO roles for efficient DERs integration in 
distribution networks’) is an FP7 collaborative project funded by the European Commission.  
38 This is particularly relevant for DSOs in Germany where the distribution grid can be up to 110 kV and therefore hosts large 
amounts of DG. 

49 

 
                                                           
Figure 19: Flexibility pilot projects in EU, source: (ENTSO-E, 2018b) 

2.2.2.  Emerging Roles 
Storage facilities 

Electricity storage is one way of providing flexibility to the system. It can be defined as any device that can 
store electrical energy and make it available when required. Several types of storage technologies have 
been  proposed,  tested,  and  are  currently  being  implemented.  Storage  systems  can  be  chemical, 
electrochemical,  electrical,  mechanical,  and  thermal.  Currently,  pumped  hydro,  which  is  classified  as 
mechanical storage, accounts  for most of the storage  capacity. This can be considered as a traditional 
storage technology as it has been around for a long time.  

However,  due  to  rapid  innovation,  large-scale  batteries  (also  referred  to  as  electrochemical  storage 
devices)  are  recently  becoming  economically  viable  (Obi  et  al.,  2017).  Batteries  have  some  unique 
characteristics that set them apart from traditional storage resources. These devices are modular and can 
be installed quickly, and they are not constrained by location. Not only can batteries be installed at any 
location, but they can also be cost-effectively moved to other locations when required. This makes them 
an invaluable resource for providing location-specific services such as voltage control for distribution grids. 

Before  the  adoption  of  the  e-Directive  of  the  EU  Clean  Energy  Package,  there  was  no  common  EU 
regulatory framework incorporating storage in distribution grids. In the UK, DSOs that have invested in 
batteries have been exempted from acquiring generation license for capacities below 50 MW and possibly 
up to 100 MW in individual cases. In Spain, the DSO and the TSO could own batteries and have also been 
exempted  from  acquiring  authorization  if  the  generation  output  is  less  than  50MW.39  Several  other 
regulators across the EU have approved battery pilots in motivated cases, such as in Germany and Italy 
(Meeus and Bhagwat, 2018).  

39 Ley 24/2013, de 26 de diciembre, del Sector Eléctrico. 

50 

 
                                                           
EV charging infrastructure  

According to Meeus and Schittekatte (2018), 70,000 public charging points were in place in Europe by the 
end of 2016, representing one public charging point for every nine EVs. 27% of them are installed in the 
Netherlands. 90% of the public charging points in the EU are normal charging points (AC, <22 kW), meaning 
that full charging times is a matter of hours. The remaining 10% are considered fast (AC, >22 kW or DC, 
>25 kW) where the charging time is lower than an hour.40 Also, there were 390,000 private charging points 
in Europe in 2016, bringing the total charging points to 460,000. During the year (2015-2016), the amount 
of public charging stations installed had a higher increase than the number of EVs sold (71% versus 53%). 

Several actors may play a role in the provision of EV charging infrastructures, such as DSOs, suppliers, or 
third  parties  who  can  use  the  charging  points  to  sell  electricity.  DSOs’  involvement  in  EV  charging  is 
different across MS as there was no common EU regulatory framework before the adoption of the EU 
Clean Energy Package. In the Spanish model, most DSOs deployed the charging infrastructure while the 
commercial operation is open to retailers. In Ireland, the DSO is involved, but the assets have not yet been 
included in the regulated asset base. Costs have been recovered via the distribution tariffs but are kept in 
a separate company and account. In the Czech Republic EV public charging infrastructure is built, owned 
and managed through competitive tenders mostly pushed by the three biggest energy utilities while DSOs 
are only in charge of the connection (EDSO, 2018).  

Data management  

Data management comprises ‘the processes by which data is sourced, validated, stored, protected and 
processed  and  by  which  it  can  be  accessed  by  suppliers  or  customers’,  according  to  the  EC  impact 
assessment (EC, 2016b). 

Data access and management is a key enabler for the operation of electricity markets. There are currently 
different data management models across EU MS, as presented in CEER (2016b); decentralised, partially 
centralized or fully centralised. The categories of data management models are described as follows: 

●  A fully centralized model comprises a centralization of all key aspects related to data management. 
A typical centralized model is a data hub, where all data is retrieved, validated, stored, protected, 
processed, distributed and accessed. In this model DSOs, market actors and all consumers relate 
to the data hub. The party responsible for a Data Exchange Platform (DEP) should be full neutral 
in order to avoid any discrimination in data access and delivery. 

●  A partially centralized model involves centralization of one or a few of the key aspects of data 
management,  typically  distribution  and  access  to  data.  It  is  rather  a  communication  hub  that 
provides a common access point to data stored in several databases, at DSOs or metering points. 
●  A  decentralized  model,  or  DSO  model,  typically  means  that  all  the  key  aspects  of  data 
management  are  decentralized,  meaning  that  they are  the  responsibility of the  DSO.  A typical 
decentralized model would be a standardized message exchange system or another cruder way 
of connecting market actors with DSOs. 

40 As a reference, it would take approximately 30 minutes for an 80 % charge or 120 km of extra range with a 60 kW DC charger 
on a Nissan Leaf. 

51 

 
                                                           
Figure 20: Responsible parties for access to metering data, source: (THEMA, 2017) 

Figure 20 gives an overview of the state of play of data management models in Europe. Italy and Ireland 
currently  operate  each  a  DEP.  The  Netherlands  has  a  partially  centralized  model,  with  centralized 
communications with multiple databases and is considered as a DEP. Denmark, Estonia and the UK have 
just  recently  implemented  a  central  DEP.  Other  MSs,  such  as  Sweden  and  Finland,  are  either  in  the 
discussion  or  the  implementation  process  of  DEPs.  Germany,  which  has  a  combination  of  models,  is 
considered as a decentralized data exchange (DSO) model in the figure. In fact, a metering point operator, 
which  can  be  a  DSO,  is  responsible  for  third-party  access  to  metering  data  in  Germany.  Portugal  and 
Austria are also using decentralised data exchange, also called the DSO model. 
2.3. 
In this subsection, we will present two new responsibilities that the CEP assigns to the DSOs. First, we 
present the measures for DSOs in network planning and then the incentives for flexibility procurement. 

Increased expectations for DSOs in their traditional roles 

2.3.1.   Measures for DSOs network planning  
On the introduction of distribution network planning, the newly added recital (62) of the e-Directive states 
that ‘(..) Member States should also introduce network development plans for distribution systems in order 
to support the integration of installations generating electricity from renewable energy sources, facilitate 
the development of energy storage facilities and the electrification of the transport sector, and provide to 
system users adequate information regarding the anticipated expansions or upgrades of the network, as 
currently such procedures do not exist in the majority of Member States.’ 

The  e-Directive  requires  that  DSOs  prepare  and  implement  multi-annual  development  plans  and 
coordinate with TSOs on such multi-annual development plans. It adds in art 32(3) that ‘the  development 
of a distribution system shall be based on a transparent network development plan that the distribution 
system  operator  shall  publish  at  least  every  two years  and  shall  submit  to  the  regulatory  authority.’ 
Moreover  ‘the  network  development  plan  shall  provide  transparency  on  the  medium  and  long-term 

52 

 
 
flexibility services needed, and shall set out the planned investments for the next five-to-ten years, with 
particular  emphasis  on  the  main  distribution  infrastructure  which  is  required  in  order  to  connect  new 
generation capacity  and new  loads,  including recharging points  for  electric vehicles.’  The development 
plan ‘shall also include the use of demand response, energy efficiency, energy storage facilities or other 
resources that the distribution system operator is to use as an alternative to system expansion.’  

During the network development plan elaboration, DSOs shall consult all relevant system users and the 
relevant  TSOs.  They  shall  publish  the  results  of  the  consultation  process  together  with  the  network 
development plan and submit both to the relevant NRA.41 The NRA may request amendments to the plan.   

Regarding renewable energy sources  or high-efficiency cogeneration  integration,  art 13(5)(a) of the e-
Regulation states that a limited redispatching can be taken into account by DSOs and TSOs in their network 
planning where proven in a transparent way to be economically efficient. It ‘shall not exceed 5 % of the 
annual generated electricity in installations which use renewable energy sources and which are directly 
connected to their respective grid (…).’ MSs, where electricity from RES or high-efficiency cogeneration 
represents more than 50 % of the annual gross final electricity consumption, can exceed this threshold 
according the same article.    

Art 57(1) of the e-Regulation adds that in order to ensure a cost-efficient, secure and reliable development 
and operation of the network, DSOs and TSOs ‘shall cooperate with each other in planning and operating 
their  networks.’  They  shall,  in  particular,  ‘exchange  all  necessary  information  and  data  regarding,  the 
performance of generation assets and demand side response, the daily operation of their networks and 
the  long-term  planning  of  network  investments,  with  the  view  to  ensure  the  cost-efficient,  secure  and 
reliable development and operation of their networks.’ 

A  derogation from the development  and publication of distribution  network plans may be  granted for 
DSOs serving less than 100,000 connected consumers, or serving small isolated systems, according to art 
32(5) of the e-Directive. 

Highlights 
- DSOs are required to prepare and implement multi-annual development plans and coordinate with 
TSOs and other relevant stakeholders on their development. 
- DSOs shall publish the network development plan and submit it to the NRA at least every two years. 
. 
- DSOs should undertake a public consultation on the proposed investment in the network plans. 
NRAs may require amendments. 
- The network development plan shall provide transparency on the medium and long-term flexibility 
services needed and contain the planned investments for the next five to ten years. 
- DSOs (and TSOs) can integrate up to 5% of curtailment in their distribution planning, with 
derogation for MSs with high share or RES and cogeneration integration in their annual gross final 
electricity consumption (50%). 
- For DSOs serving less than 100,000 connected consumers, or serving small isolated systems, MSs may 
decide not to apply these obligations. 

41 In the Commission draft of the e-Directive, it was the NRAs that were in charge of the consultation process and the 
publication of the network development plans.  

53 

 
 
                                                           
2.3.2.  Measure to incentivize DSOs to procure flexibility services  
The  CEP  aims  to  define  the  conditions  under  which  DSOs  may  acquire  flexibility  services42  without 
distorting the markets for such services. It includes clear provisions that will enable DSOs to manage local 
grid issues and enhance the security of supply (SoS) through flexibility procurement.  

DSOs flexibility services procurement process 

Regarding the regulatory framework for the procurement of flexibility by distribution system operators, 
art 32(1) of the e-Directive requires MSs to define the exact regulatory framework, including incentives 
for DSOs and adequate remuneration. It states that ‘Member States shall provide the necessary regulatory 
framework to allow and provide incentives to distribution system operators to procure flexibility services, 
including  congestion  management  in  their  areas,  in  order  to  improve  efficiencies  in  the  operation  and 
development of the distribution system.’  

This procurement shall be transparent, non-discriminatory,  and market-based.  In this context, market-
based  flexibility  procurement  refers  to  a  process  whereby  flexibility  is  obtained  and  priced  through  a 
(separate) market mechanism from all stakeholders that are a source of flexibility, benefit from it, or have 
a controlling role, i.e., consumers, producers, BRP, system operators and regulators. In addition, the non-
discriminatory aspect refers to the ‘participation of all market participants, including market participants 
offering energy from renewable sources, market participants engaged in demand response, operators of 
energy storage facilities and market participants engaged in aggregation,’ as stated in art 32(2).  

In  addition,  DSOs,  subject  to  NRA  approval  or  the  NRA  itself,  shall  define  ‘the  specifications  for  the 
flexibility  services  procured  and,  where  appropriate,  standardised  market  products  for  such  services  at 
least at national level.’  This shall be done in a transparent and participatory process, including all relevant 
system users and the TSO.  

DSOs  shall  receive  an  adequate  remuneration  for  the  procurement  of  flexibility  service  so  that  they 
recover  ‘at  least  their  reasonable  corresponding  costs,  including  the  necessary  information  and 
communication technology expenses and infrastructure costs.’ 

A derogation could be given by NRAs if they establish that this kind of procurement is not economically 
efficient or if it may cause severe market distortions or higher congestions. Note that on the application 
of flexibility service procurement to smaller DSOs, no clear derogation was introduced. However, there is 
a nuance. Art 32(5) gives the possibility to MSs to not apply the obligation of developing and publishing 
network  plans only  for  small  DSOs.  So,  in  theory,  this  is  not  directly  related  to  flexibility  procurement 
incentives  introduced  in  art  32(2),  even  though  that  DSO  plans  shall  include  the  use  of  DERs  as  an 
alternative to system expansion. 

Coordination with TSOs in the procurement of flexibility services 

Using system flexibility services will require extensive cooperation and clear boundaries between TSOs 
and DSOs. This aims to ensure an efficient data exchange on the activated flexibility resources and to avoid 
a double activation from a DSO and a TSO of the same flexibility source. According to art 32(2) of the e-
Directive,  ‘distribution  system  operators  shall  exchange  all  necessary  information  and  shall  coordinate 
with transmission system operators in order to ensure the optimal utilisation of resources, to ensure the 
secure and efficient operation of the system and to facilitate market development.’ 

42 Regarding the DSO role in balancing the system, the CEP has not foreseen the procurement of frequency ancillary services 
(Frequency Containment Reserves (FCR), Frequency Restoration Reserves (FRR) and Replacement Reserves (RR)) by DSOs. The 
flexibility services, that DSOs may procure, have been limited to non-frequency ones and congestion management services. 

54 

 
                                                           
In addition, for the access to flexibility resources,  art 57(2) of the e-Regulation states that ‘distribution 
system operators and transmission system operators shall cooperate with each other in order to achieve 
coordinated access to resources such as distributed generation, energy storage or demand response that 
may  support  particular  needs  of  both  the  distribution  system  operators  and  the  transmission  system 
operators.’ Figure 21 shows the new one-system approach for flexibility provision. 

Figure 21: A one-system approach for flexibility procurement, source: (EC, 2017a) 

Highlights 
- DSOs shall include flexibility services in network planning, as an alternative to traditional grid 
investment. 
- MSs shall provide the necessary regulatory framework to allow and to incentivise DSOs to procure 
flexibility services. 
- DSOs subject to NRA approval, or the NRA itself, shall define the specifications for the flexibility 
services and where appropriate standardized products. 
- The procurement of flexibility services shall be transparent, non-discriminatory and market-based, 
unless the NRA grants a derogation. At the same time, it shall ensure TSO/DSO coordination. 
- DSOs shall receive an adequate remuneration for the procurement of flexibility services so that 
they recover at least the corresponding reasonable costs. 
- A derogation could be given by NRAs, from market-based flexibility services procurement, if they 
establish that it is not economically efficient or if it may cause severe market distortions or higher 
congestions.  

2.4.  Limiting the role of DSOs in emerging businesses  
EV  charging  and  storage  facilities  are  emerging  businesses  in  the  electricity  sector.  The  CEP  aims  to 
establish a regulatory framework for limiting the DSOs’ roles in these businesses when their involvement 
is not necessary. 

55 

 
 
 
 
 
 
2.4.1.  Limiting DSOs’ ownership of EV charging facilities  
DSOs, according to recital 40 of the e-Directive, have to integrate electric vehicles into their system in a 
cost-efficient  manner,  and  to  create  favourable  conditions  for  electric  vehicles  through  the  different 
market  rules  set  out  in  the  e-Directive.  For  instance,  the  distribution  network  development  plans, 
submitted at least every two years to NRAs, shall include the planned investments for the next five to ten 
years covering, inter alia, re-charging points for electric vehicles.  

MSs are in charge of providing the necessary regulatory framework facilitating the connection of public 
and private EV charging facilities to the distribution networks. According to art 33(1) of the e-Directive, 
each MS shall ensure that DSOs ‘cooperate on a non-discriminatory basis with any undertaking that owns, 
develops, operates or manages recharging points for electric vehicles, including with regard to connection 
to the grid.’ In addition, DSOs ‘shall not own, develop, manage or operate recharging points for electric 
vehicles, except where distribution system operators own private recharging points solely for their own 
use’(art 33(2)). 

Derogation for EV charging facilities’ ownership by DSOs 

The e-Directive promotes a market-based solution for the ownership of EV charging infrastructure. It also 
provides a derogation for DSOs’ ownership as a last resort and under certain conditions. Art 33(3) of the 
e-Directive states that: 

‘Member States may allow distribution system operators to own, develop, manage or operate recharging 
points for electric vehicles, provided that all of the following conditions are fulfilled:  

(a) other parties, following an open, transparent and non-discriminatory tendering procedure that is 
subject to review and approval by the regulatory authority, have not been awarded a right to own, 
develop, manage or operate recharging points for electric vehicles, or could not deliver those services at 
a reasonable cost and in a timely manner; 

(b) the regulatory authority has carried out an ex ante review of the conditions of the tendering 
procedure under point (a) and has granted its approval; 

 (c) the distribution system operator operates the recharging points on the basis of third-party access in 
accordance with Article 6 and does not discriminate between system users or classes of system users, and 
in particular in favour of its related undertakings.’ 

In case of a MS applying this derogation, a public consultation, to re-assess the condition of the derogation, 
shall  be  made  at  regular  intervals  or  at  least  every  five  years  by  MSs  or  their  designated  competent 
authorities. In case a third-party becomes able to own, develop, operate, or manage EV charging points, 
MSs shall ensure the DSOs’ ownership phase-out. NRAs may allow DSOs to recover the residual amount 
of investment that has been already made. 

Highlights 

- MSs shall promote market-based schemes Member States or their designated competent authorities 
shall  perform  for  the  ownership  of  EV  charging  infrastructure  through  providing  the  necessary 
regulatory framework to facilitate the connection of publicly accessible and private recharging points 
to the distribution networks. 
- MSs may allow DSOs ownership of EV charging infrastructure under certain conditions, followed by 
a continuous monitoring and public consultation for emerging interested third-parties. 

56 

 
 
 
 
2.4.2.  Limiting DSOs ownership of storage facilities 
Storage  units  represent  an  attractive  source  of  flexibility  for  the  electricity  system,  especially with the 
increasing diffusion of RES-E and the challenges they create for system operation. Art 36 of the e-Directive 
sets the measures with regard to DSOs ownership of storage facilities. It states that DSOs shall not be 
allowed  to  own,  develop,  manage,  or  operate  energy  storage  facilities.  However,  derogations  may  be 
granted. 

Derogation for storage facilities ownership by DSOs 

The e-Directive differentiates two separate derogations for storage facilities ownership. This depends on 
whether the storage facilities are ‘fully integrated network components’ or not. Fully integrated network 
components means according to art 2(51) of the e-Directive ‘network components that are integrated in 
the transmission or distribution system, including storage facilities, and that are used for the sole purpose 
of ensuring a secure and reliable operation of the transmission or distribution system, and not for balancing 
or congestion management.’ The derogation for fully integrated network components was not included in 
the Commission proposal for the e-Directive but was introduced by the Council in its negotiating position. 
Fully integrated network components can include energy storage facilities such as capacitors or fly wheels, 
which help to ensure network security and reliability and to maintain synchronisation between different 
parts of the system. They must not be used to buy or sell electricity in the electricity markets. In general, 
the idea of limiting storage ownership is to prevent DSOs and TSOs from owning storage assets that they 
use in congestion management and balancing (for TSOs) as they should procure these services in a market 
based process and owning some of these assets by DSOs and TSOs would distort this process. 

According to recital 63, ‘where energy storage facilities are fully integrated network components that are 
not  used  for  balancing  or  for  congestion  management,  they  should  not,  subject  to  approval  by  the 
regulatory authority, be required to comply with the same strict limitations for system operators to own, 
develop,  manage  or  operate  those  facilities.  In  case  they  are  not  fully  integrated  components,  the 
derogation requires, according to art 36(2), all of the following conditions to be fulfilled: 

‘(a)  other  parties,  following  an  open,  transparent  and  non-discriminatory  tendering  procedure  that  is 
subject to review and approval by the regulatory authority, have not been awarded a right to own, develop, 
manage or operate such facilities, or could not deliver those services at a reasonable cost and in a timely 
manner;  
(b) such facilities are necessary for the distribution system operators to fulfil their obligations under this 
Directive for the efficient, reliable and secure operation of the distribution system and the facilities are not 
used to buy or sell electricity in the electricity markets; and  
(c)  the  regulatory  authority  has  assessed  the  necessity  of  such  a  derogation  and  has  carried  out  an 
assessment  of  the  tendering  procedure,  including  the  conditions  of  the  tendering  procedure,  and  has 
granted its approval. 
The  regulatory  authority  may  draw  up  guidelines  or  procurement  clauses  to  help  distribution  system 
operators ensure a fair tendering procedure.’ 
In case of the application of this derogation and similarly to the case of EV charging station ownership, a 
public consultation, to re-assess the condition of the derogation, shall be made at regular intervals or at 
least every five years by NRAs. 

In case the public consultation indicates that third parties are able to own, develop, operate or manage 
such the storage facilities in a cost-effective manner, NRAs shall ensure that DSOs’ activities in this regard 
are  phased-out  within  18  months.’43  NRAs  may  allow  DSOs,  in  this  case,  to  receive  reasonable 

43 This requirement was not included in the Commission proposal. The Council proposed a 24 months period. 

57 

 
 
                                                           
compensation allowing them to recover the residual amount of investment that has been already made 
in storage facilities. 

Highlights 
- DSOs shall not be allowed to own, develop, manage or operate energy storage facilities.  
- Two types of derogations are possible depending whether the storage facilities are fully integrated 
network components or not.  
- For storage facilities, which are fully integrated network components, the NRA’s approval is enough 
for DSO ownership. 
- For storage facilities, which are not fully integrated network components, three conditions need to 
be fulfilled, including that no third party was awarded this right in the tender process. 
- A public consultation shall be done by NRAs regarding third parties’ capabilities and interest for the 
ownership of storage facilities, at regular intervals or at least every five years. 

2.4.3.  Neutral DSOs role in data management 
Being in charge of the smart metering systems roll-outs in most of the EU MSs, DSOs  have the role of 
pooling or collecting of data from consumers. This ‘advantageous’ position induces the need to ensure a 
neutral role for DSO in data management.   

Art 34 of the e-Directive on ‘tasks of distribution system operators in data management’ states that MSs 
shall  ensure  that  data  eligible  parties44  have  non-discriminatory,  clear  and  equal access  to  data.45  This 
should be under clear terms that respect the relevant data protection legislation, such as EU General Data 
Protection Regulation (GDPR). Indeed, in MSs where smart meters are implemented according to art 19 
of the e-Directive and DSOs are involved in data management, compliance programmes, ensuring that 
discriminatory conduct  is excluded, shall include  specific measures to exclude discriminatory  access to 
data from eligible parties as provided in art 23 on data management.  

The same article adds that where DSOs are not subject to art 35(1), (2) and (3), on unbundling of DSOs, 
‘Member States shall take all necessary measures to ensure that vertically integrated undertakings do not 
have privileged access to data for the conduct of their supply activities.’ 

Highlights 
- Eligible parties shall have a non-discriminatory access to data under clear and equal terms, in 
compliance with the GDPR. 
- Where smart meters are implemented and DSOs are involved in data management, compliance 
programmes shall be set to ensure that discriminatory conduct is excluded. 
- Vertically integrated undertakings shall not have privileged access to data for the conduct of their 
supply activity. 

44 A minimum list of eligible parties was included in the art 23  of the Commission proposal of e-Directive Directive, being the 
customers, suppliers, transmission and distribution system operators, aggregators, energy service companies, and other parties 
which provide energy or other services to customers. This minimum list was removed in the final version of the e-Directive. 
45 There is no clear provision on DSO profit from data. In the Commission draft Directive, regulated entity were not allowed to 
profit from data, a provision that does not exist anymore in the final version. Further data access provisions are presented in 
section 3.2.3.  

58 

 
 
 
                                                           
 
 
2.5.  The EU DSO entity  
Being at the center of the European energy transition, the diverse DSOs’ landscape demands closer inter-
DSO cooperation. In this subsection, we will present the CEP measures for the establishment of the EU 
DSO entity  and  its  tasks.  The  creation of  this  entity  represents  recognition  for  the  role of  DSOs  in  the 
energy  transition  and  aims  to  foster  cooperation  between  DSOs  which  are  currently  represented  by 
different organisations as introduced at the beginning of this chapter in 2.1.  

2.5.1.  Establishment of the EU DSO entity 
The  CEP  e-Regulation  defines  the  EU  DSO  entity  establishment  procedure.  The  EU  DSO  Entity  will  be 
composed  by  European  DSOs  aiming  to  join  this  entity,  without  the  unbundling  condition  that  was 
introduced in the Commission proposal for the e-Regulation. Art 52 of the e-Regulation states that DSOs46 
‘shall  cooperate  at  Union  level  through  the  EU  DSO  entity,  in  order  to  promote  the  completion  and 
functioning of the internal market for electricity, and to promote optimal management and a coordinated 
operation of distribution and transmission systems.’ Moreover, DSOs wishing to participate in the EU DSO 
entity  shall  have  the  right to  become  registered members  of  the  entity.  The  registered  members may 
participate  in  the  DSO  entity  directly  or  indirectly,  being  represented  by  their  national  association 
designated by the MS or by a Union level association. A fair and proportionate membership fee shall be 
paid by the members of the EU DSO entity which shall be proportionate to the number of their connected 
customers. 

The EU DSO entity should be an expert entity working for the general European interest. It, therefore, 
should  not  defend  any  particular  interest.  Art  52(2)  adds  that  ‘EU  DSO  entity  shall  neither  represent 
particular interests nor seek to influence the decision-making process to promote specific interests.’ 

Art 53 of the e-Regulation on the establishment of the EU DSO entity for electricity indicates that it ‘shall 
consist of, at least, a general assembly, a board of directors, a strategic advisor group, expert groups and 
a secretary-general.’ It further sets the different establishment steps, that are explained in Figure 22: 

‘2. By 5 July 2020, the distribution system operators shall submit to the Commission and to ACER, the draft 
statutes, in accordance with Article 54, including a code of conduct, a list of registered members, the draft 
rules of procedure, including the rules of procedures on the consultation with the ENTSO for Electricity and 
other  stakeholders  and  the  financing  rules,  of  the  EU  DSO  entity  to  be  established.  The  draft  rules  of 
procedure of the EU DSO entity shall ensure balanced representation of all participating distribution system 
operators.  

3. Within two months of receipt of the draft statutes, the list of members and the draft rules of procedure, 
ACER  shall provide the Commission with its  opinion, after consulting the organisations  representing all 
stakeholders, in particular distribution system users.  

4. Within three months of receipt of ACER's opinion, the Commission shall deliver an opinion on the draft 
statutes,  the  list  of  members  and  the  draft  rules  of  procedure,  taking  into  account  ACER's  opinion  as 
provided for in paragraph 3.  

5. Within three months of receipt of the Commission's positive opinion, the distribution system operators 
shall establish the EU DSO entity and shall adopt and publish its statutes and rules of procedure. 

 6. The documents referred to in paragraph 2 shall be submitted to the Commission and to ACER where 
there are changes thereto or upon the reasoned request of either of them. The Commission and ACER shall 
deliver an opinion in line with the process set out in paragraphs 2, 3 and 4.  

46 The Commission proposal for e-Regulation stressed that the DSOs that are to form part of the DSO entity should 
be ‘unbundled’, a requirement that has been removed in the final text. 

59 

 
                                                           
7. The costs related to the activities of the EU DSO entity shall be borne by the distribution system operators 
that  are  registered  members  and  shall  be  taken  into  account  in  the  calculation  of  tariffs.  Regulatory 
authorities shall only approve costs that are reasonable and proportionate.’ 

DSOs shall submit to EC and 
ACER:

- the draft statutes

- a list of registered members 

- the draft rules of procedure

ACER shall provide an 
opinion to EC, after 
consulting relevant 
stakeholders.

EC shall deliver an opinion 
taking into account ACER's 
opinion.

DSOs shall establish the 
EU DSO entity, and adopt 
and publish its statutes 
and rules of procedure.

•By 5 July 2020

•Within 2 months of 

receipt

•Within 3 months of 

ACER opinion's 
receipt

•Within 3 months of 
the receipt of EC's 
positive opinion

Figure 22: Main stages of the EU DSO establishment, source: own illustration 

Art 54, on ‘Principal rules and procedures for the EU DSO entity’, sets more detailed rules and procedures 
for the EU DSO entity. It includes the conditions for the participation in the works of the entity, the rules 
for strategic decision and conditions for the general assembly decision-making process as well as the Board 
of Directors election and roles such as the lead of DSO-TSO cooperation. These specific rules were not 
included in the Commission proposal. 

The Board of Directors is elected by the General Assembly for a maximum period of 4 years and has the 
tasks to nominate the President and the three Vice-Presidents from among the members of the board, 
propose Expert Groups, appointed by the General Assembly (art 54(1)). The board of directors shall also 
establish  the  Strategic  Advisory  Group,  which  consists  of  representatives  of  the  European  DSOs’ 
associations  and  representatives  of  MSs  that  are  not  represented  in  the  Board  of  Directors.  The  e-
Regulation introduces, in art 54(2), the composition of the 27 members of the Board of Directors. A 9/9/9 
composition of which:  

 - 9 are representatives of members with more than 1 million grid users; 
 - 9 are representatives of members with more than 100,000 and less than 1 million grid users; 
 - 9 are representatives of members with less than 100,000 grid users. 

This  composition  allocates  the  same  number  of  representatives  to  the  three  categories  of  DSOs  with 
regard to their number of customers.  This aims, according to art 54(2) of the e-Regulation, to ‘safeguard 
the  fair  and  proportionate  treatment  of  its  members  and  shall  reflect  the  diverse  geographical  and 
economic structure of its membership.’  

2.5.2.  Tasks of the EU DSO Entity 
We divide the EU DSO Entity tasks into three categories. In this subsection, we will present the proposed 
aggregated tasks for the DSO entity, its cooperation with ENTSO-E and its role in drafting network codes. 

Aggregated tasks 

Art 55(1) of the e-Regulation lists the tasks of the new EU DSO entity; 
‘(a) promoting operation and planning of distribution networks in coordination with the operation and 
planning of transmission networks;  

60 

 
(b) facilitating the integration of renewable energy resources, distributed generation and other resources 
embedded in the distribution network such as energy storage;  

(c) facilitating demand side flexibility and response and distribution grid users' access to markets; (d) 
contributing to the digitalisation of distribution systems including deployment of smart grids and 
intelligent metering systems;  

(e) supporting the development of data management, cyber security and data protection in cooperation 
with relevant authorities and regulated entities;  

(f) participating in the development of network codes which are relevant to the operation and planning 
of distribution grids and the coordinated operation of the transmission networks and distribution 
networks pursuant to Article 59.’ 

Cooperation with ENTSO-E and other tasks 

At the European level, TSOs and DSOs shall cooperate for the planning and operation of the network. The 
DSO entity should cooperate closely with ENTSO-E on the preparation and implementation of the network 
codes  where  applicable,  i.e.,  areas  related  to  distribution  networks.  Art 55(2)  of the e-Regulation  also 
brings the following additional tasks for the DSO entity related to cooperation with ENTSO-E putting them 
on the same footing. These additional tasks include: 
‘(a) cooperate with the ENTSO for Electricity on the monitoring of implementation of the network codes 
and guidelines adopted pursuant to this Regulation which are relevant to the operation and planning of 
distribution grids and the coordinated operation of the transmission networks and distribution networks;  
(b) cooperate with the ENTSO for Electricity and adopt best practices on the coordinated operation and 
planning of transmission and distribution systems including issues such as exchange of data between 
operators and coordination of distributed energy resources;  
(c) work on identifying best practices on the areas identified in paragraph 1 and for the introduction of 
energy efficiency improvements in the distribution network;  
(d) adopt an annual work programme and an annual report;  
(e) operate in accordance with competition law and ensure neutrality.’ 

Network codes drafting 

When the matter of network codes is directly related to the operation of the distribution system and not 
primarily relevant for the transmission system, the Commission may require from the EU DSO entity, in 
cooperation with ENTSO-E, to convene a drafting committee and submit a proposal for a network code to 
ACER (art 59(3)). In the first Commission proposal, the EU DSO entity was originally tasked to convene a 
drafting committee instead of ENTSO-E and not in cooperation with it.   

In  addition,  the  DSO  entity  shall  conduct  an  extensive  consultation  process  while  participating  in  the 
elaboration  of  new  network  codes.  This  consultation  process  should  be  done  at  an  early  stage  of  the 
development  and  in  a  transparent  and  open  manner  for  the  relevant  stakeholders.47  This  process,  as 
stated  in  art  56(1),  ‘shall  aim  at  identifying  the  views  and  proposals  of  all  relevant  parties  during  the 
decision-making  process.’  In  addition  to  that,  ‘the  EU  DSO  entity  shall  indicate  how  it  has  taken  the 
observations received during the consultation into consideration. It shall provide reasons where it has not 
taken such observations into account.’ (art 56(3)). 

47 ‘That consultation shall also involve regulatory authorities and other national authorities, supply and generation undertakings, 
system users including customers, technical bodies and stakeholder platforms. It shall aim at identifying the views and proposals 
of all relevant parties during the decision-making process,’ according to art 56(1). 

61 

 
 
 
                                                           
Highlights 
- The DSO entity will reinforce the DSOs representation at the European level. 
- The DSO entity will be involved in the development of EU rules such as network codes in 
cooperation with ENTSO-E. 
- The DSO entity will cooperate with ENTSO-E on issues of mutual concern, such as data 
management, balancing, planning, congestion, etc. 
 - The DSO entity will work on areas such as DSO/TSO cooperation, integration of RES, deployment of 
smart grids, demand response, digitalization and cybersecurity. 
- A 9/9/9 composition of the board of the DSO entity, according to the DSO’s number of customers, is 
introduced. 
- The e-Regulation sets clear rules and procedures for the decision making process. 

Interlinkage with Network Codes 

2.6. 
The CEP introduces a more  participative  process for network codes development. In this part, we first 
present the second generation of network codes that has been foreseen in the CEP. Then we introduce 
the stakeholders’ roles in network codes development and the newly proposed adoption process. 

2.6.1.  The second generation of network codes and guidelines 
The  e-Regulation  brings  two  main  new  measures  for  the  second  generation  of  network  codes  and 
guidelines. In this subsection, we first present the scope of the second generation of network codes and 
guidelines. Second, we present the adoption process for network codes characterized by the introduction 
of the delegated acts adoption process for some focus areas of network codes.  

Scope of the second generation of network codes and guidelines 

Network  codes  and  guidelines  are  Commission  Regulations.  They  apply  directly  to  all  the  EU  Member 
States without being transposed into national laws or regulatory frameworks (Schittekatte et al., 2019). 
The electricity Regulation 714/2009 identified twelve focus areas for network codes. From these twelve 
areas, only seven are covered by the first generation of network codes that has been developed since the 
introduction of the third package. For the following six areas, network codes have not yet been developed; 

-Third-party access rules;  
-Data exchange and settlement rule; 
-Interoperability rules; 
-Transparency rules; 
-Rules regarding harmonised transmission tariff structures incl. locational signals and inter-transmission 
system operator compensation rules;  
-Energy efficiency regarding electricity networks; 

In November 2016, the Commission draft for e-Regulation added four additional focus areas to be covered 
by NC:  
-Rules for non-discriminatory, transparent provision of non-frequency ancillary services, including steady 
state voltage control, inertia, fast reactive current injection, black-start capability; 
-Demand response, including aggregation48, energy storage, and demand curtailment rules; 
-Cyber security rules; and 
-Rules concerning regional operational centres.  

48 An aggregator, according to art 2(14) of the e-Directive is ‘a market participant that combines multiple customer loads or 
generated electricity for sale, for purchase or auction in any organised energy market.’ 

62 

 
 
                                                           
 
 
The  e-Regulation  Commission  proposal  adds  the  harmonisation  of  distribution  tariffs  next  to  the 
transmission ones. They were both removed in the final text, as stated in 1.3.2. Also, the rules concerning 
regional operational centres were removed as the ROCs do not exist anymore in the final text while no 
specific area for network codes regarding RCCs has been included. 

The final text of the e-Regulation has brought changes to this list. Indeed art 59(1) & (2) include an updated 
version of the focus areas compared to the first proposal. They also categorize the focus areas into the 
ones  for  which  the  Commission  is  empowered  to  adopt  them  as  implementing  acts  and  the  other  as 
delegated acts. We present the classification below. More details regarding the adoption process will be 
given in 2.6.3. 

The areas where the Commission is empowered to adopt network codes as implementing acts (see Figure 
23 for the process) are: 

-  Network security and reliability rules (existing, covered by SO GL guideline); 
-  Capacity-allocation and congestion-management rules (existing, covered by the  CACM and FCA 

GL guidelines); 

-  Rules for trading related to technical and operational provision of network access services and 

system balancing (existing guideline EB GL); 

-  Rules for non-discriminatory, transparent provision of non-frequency ancillary services (new); 
-  Rules on demand response, including aggregation, energy storage, and demand curtailment rules 

(new); This area was highlighted as a priority area in Florence forum. 

The areas where the Commission is empowered to adopt network codes as delegated acts (see Figure 24 
for the process) are: 

-  Network connection rules (existing, covered by RfG, DCC HVDC network codes); 
-  Operational emergency and restoration procedures in an emergency (existing network code NC 

ER); 

-  Data  exchange,  settlement  and  transparency  rules  (partly  by  the  SO  GL  and  the  transparency 

- 
- 

regulation No 543/201349); This area was highlighted as a priority area in Florence forum. 
Third-party access rules (new); 
Sector-specific  rules  for  cyber  security  aspects  of  cross-border  electricity  flows  (new); 
Cybersecurity50 was highlighted as a priority area in Florence forum. 

The Commission is empowered to adopt Guidelines in the same stated areas of the network codes. The 
areas also condition the Commission adoption empowerment as either implementing or delegated acts 
for the guidelines.  
In addition, art 61(3) states that the Commission is empowered to adopt, as delegated acts, guidelines 
relating to the inter-TSOs compensation mechanism. These different areas touch upon the areas covered 
by  the  Regulation  No  838/2010  on  laying  down  guidelines  relating  to  the  inter-transmission  system 
operator compensation mechanism  and  a  common regulatory  approach  to transmission  charging.  The 
guidelines shall specify: 

TSOs liability to pay compensation for cross-border flows; 

- 
-  Details of the payment procedure; 
-  Details of methodologies for determining the cross-border flows hosted; 

49 The Regulation (EU) No. 543/2013 is called a ‘transparency regulation’. It aims to make the pan-European 
electricity market information more transparent. It requires from TSOs to share data regarding generation, load, 
transmission and electricity balancing.  it sets also transparency measures regarding market rules. It establishes 
also the ENTSO-E Transparency platform that publishes those TSOs data. 
50 Note that the reference was made to cybersecurity in general and not only the aspect related to cross-border 
flows. 

63 

 
                                                           
-  Details of the methodology for determining the costs and benefits incurred as a result of hosting 

cross-border flows; 

-  Details  of  the  treatment  of  the  inter-TSOs  compensation  mechanism  when  electricity  flows 

- 

originate or end in countries outside the European Economic Area; 
Participation of national systems which are interconnected through direct current (DC) lines (also 
partly covered by the HVDC network code); 

Moreover, guidelines may specify, where appropriate, ‘details of rules for the trading of electricity’ and 
‘details of investment incentive rules for interconnector capacity including locational signals’ according to 
art 64(4) aiming to provide the minimum degree of harmonisation required. The Commission, according 
to art 64(5), may also adopt guidelines on the implementation of operational coordination between TSOs 
at Union level. They shall be consistent with and build upon the network codes described at the beginning 
of this section and art 59.  
Note that the matching between the network codes and guidelines focus areas of the e-Regulation and 
the existing network codes and guidelines is non-exhaustive. One focus area can be only partly covered 
by a network code or a guideline. It can also be covered by two or more. 
Implementing acts versus delegated acts 
Network codes, which are Commission Regulations, were only subject to Comitology adoption procedure 
through implementing acts under  the Third Energy Package. With the CEP, the  e-Regulation, as stated 
above,  introduces  the  delegated  acts  adoption  process  for  some  focus  areas  of  network  codes  while 
keeping  the  implementing  acts  adoption  for  others.  In  what  follows,  we  will  present  the  differences 
between these two adoption processes. 
Network codes adoption as implementing acts, shown in Figure 23, can be divided into two phases. The 
pre-comitology process where the Commission undertakes legal and impact assessment of the network 
code as well as inter-service consultation within the Commission. Then the Comitology phase where the 
Commission submits draft implementing acts to a committee composed of representatives of each MS. 
The committee votes the Commission’s draft with three possible outcomes. In the first case, a qualified 
majority of MSs in favour of the act and where the Commission must adopt it. In the second case, where 
a qualified majority against where the Commission cannot adopt the act. In the third case, there is no 
qualified  majority  for  or  against  and  where  the  Commission  may  adopt  the  draft.  More  information 
regarding the process can be found in EC (2017).  

Figure 23: Adoption as implementing acts, source: (EC, 2016b) 

64 

 
 
Network  codes  adoption  as  delegated  acts  can  be  seen  as  a  fast  track  adoption  process  as  the  major 
change  compared  to  the  implementing  acts  one  is  the  abolition  of  the  comitology  committees.  The 
Commission  prepares  and adopts  delegated  acts  after  consulting national  expert  groups,  composed of 
representatives  from  each  MS  or  can  also  take  the  form  of  studies  (Christiansen  and  Dobbels,  2013). 
Citizens and other stakeholders can provide feedback on the delegated act draft within a 4-week period 
(EC, 2017b). Then, as shown in Figure 24, the Commission presents its draft delegated act simultaneously 
to  both  the  European  Parliament  and  the  Council  without  asking  the  opinion  of  a  committee.  The 
European Parliament and Council generally have two months to formulate any objections. If they do not, 
the delegated act enters into force, as indicated in art 290 of the TFEU. 

Figure 24: Adoption as delegated acts, source: (Stratulat and Molino, 2011) 

2.6.2.   Stakeholders’ roles in network codes development process 
The Commission starts with the establishment of a priority list every three years, identifying the focus 
areas to be developed in network codes from the list stated in art 59 and the previous subsection. This 
shall be done, according to art 59(3), after consulting ACER, ENTSO-E, the EU DSO Entity, and the other 
relevant  stakeholders.  ACER,  following  a  request  from  the  Commission,  shall  develop  a  non-binding 
framework guideline that sets out ‘clear and objective principles for the development of network codes 
relating  to  the  areas  identified  in  the  priority  list  (framework  guideline).’  This  shall  be  done  after 
consultation with ENTSO-E, the EU DSO entity, and the other relevant stakeholders. If the Commission 
considers  that  the  framework  guideline  does  not  contribute  to  market  integration,  competition,  or 
efficient functioning, it may require ACER to review and re-submit it. If ACER ‘fails to submit or resubmit a 
framework guideline within the period set  by the Commission under paragraph 4 or 7, the Commission 
shall develop the framework guideline in question’ art 59(8). 

Based on the framework guideline, ENTSO-E or where appropriate the EU DSO entity in cooperation with 
ENTSO-E, shall convene a drafting committee to provide support for the development of the network code 
and submit it to ACER within twelve months. ACER shall then revise the network code and ensure that it 
is in line with the relevant framework guideline and submit it to the Commission within six months of the 
reception. 

If ENTSO-E or the EU DSO entity fails to develop a network code within the set period of time set, the 
Commission may request ACER to prepare a draft network code based on the framework guideline. ACER 
may also launch further consultation on the development.  

The Commission may adopt one or more network codes per focus area, on its own initiative, where ENTSO-
E or the DSO entity have failed to develop it, or ACER has failed to develop it, or upon proposal of ACER 
after revising the submitted draft from ENTSO-E or the DSO entity. When the Commission decides so, it 
shall  consult  ACER,  ENTSO-E  and  all  relevant  stakeholders  regarding  ‘the  draft  network  code  during  a 
period of no less than two months’ (art 59(13)). 

65 

 
 
 
2.6.3.  The new adoption process for network codes and guidelines 
The exercise of delegation in network codes and guidelines  

The CEP provides the adoption of network codes by the Commission as implementing or delegated acts 
instead of the only implementing acts adoption empowerment of the 3rd Energy Package. The conditions 
for the Commission exercise of delegation are stated in art 6851 of the e-Regulation for the establishment 
of network codes. The e-Regulation refers to the power to adopt delegated acts for network codes and 
guidelines in art 59(2) for the establishment of network codes and in art 60 for the amendment of network 
codes. The area of empowerment for amending codes and guidelines follows the same areas as for their 
establishment in the art 59. 
According to EC, (2017b), the Commission's power to adopt delegated acts is subject to strict limits: 

● 
● 

‘the delegated act cannot change the essential elements of the law 
the legislative act52 must define the objectives, content, scope, and duration of the delegation of 
power 

●  Parliament and Council may revoke the delegation or express objections to the delegated act’ 
The Commission prepares and adopts delegated acts after consulting expert groups53, designated by each 
MS, which meet on a regular or occasional basis. Citizens and other stakeholders can provide feedback on 
the draft text of a delegated act during a four-week period. Once the Commission has adopted the act, 
the Parliament and the Council have two months to formulate any objections. If they do not, the delegated 
act enters into force. According to EC (2009) communication on the implementation of Article 290 of the 
TFEU, the Commission carries out the necessary preparatory steps from a political and institutional point 
of view to ensure that no objections will be made by Parliament or the Council. In case of an objection 
raised by one of these European institutions, the delegated act is revoked and cannot enter into force. 
Then the Commission can either adopt a new delegated act or amend where necessary while taking into 
account  the  expressed  objections,  if  these  objections  are  based  on  the  fact  that  the  Commission  has 
overstepped the powers delegated to it. Another possibility, in case of objection, is that the Commission 
will decide not to do anything at all. 

The  adoption  process  of  guidelines  is  described  in  art  61.  It  gives  the  Commission  wider  discretion 
especially in the development process under which there is no development role for ACER or ENTSO-E. 
According to art 61(6), it shall consult ACER, ENTSO-E, the EU DSO entity and other stakeholders where 
relevant.  There  is  no  specific  role  assigned  for  the  different  stakeholders  and  not  many  steps  as  for 
network codes. Therefore, it could be seen as a way for the Commission to by-pass the different steps in 
a network code adoption process and adopt it as a guideline. 

Regarding the existing network codes and guidelines, by 1 July 2025, the Commission shall review them in 
order to assess which of their provisions could be appropriately incorporated into legislative acts of the 
Union concerning the internal electricity market, according to art 69(1). The Commission shall also assess 
how the empowerments for network codes and guidelines adoption pursuant to art 59 and art 61 of the 
e-Regulation could be revised. The Commission should submit a detailed report of the assessment to the 
European Parliament and to the Council by the same date. Then by 31 December 2026, ‘the Commission 
shall, where appropriate, submit legislative proposals on the basis of its assessment’ art 69(2). 

51  In  addition  to  the  network  codes  and  guidelines  areas  in  art  59(2)  and  art  61(2),  the  e-Regulation  refers  also  to  the 
empowerment of the Commission to adopt delegated acts in other areas; art 34(4) concerning the geographical area covered by 
each  RCC,  art  49(4)  on  Inter-transmission  system  operator  compensation  mechanism,  art  63(11)  on  new  direct  current 
interconnectors condition. 
52 Regulation, directive or decision. 
53 The Commission requests specialist advice from outside experts as a basis for sound policymaking. This may be provided by 
groups of experts or external consultants, or it can take the form of studies. For more information, see EC (2019b). 

66 

 
                                                           
Regarding  the  exercise  of  delegation,  art  68(2)  of  the  e-Regulation  states  that  the  power  to  adopt 
delegated acts shall be conferred to the Commission until 31 December 2028 starting from the entry into 
force of the e-Regulation and not for an undetermined period of time which was stated in the Commission 
e-Regulation  proposal.  No  later  than  nine  months  before  the  end  of  the  empowerment  period54,  the 
Commission  shall  draw  up  a  report  in  respect  of  the  delegation  of  power.  The  article  adds  that  ‘the 
delegation of power shall be tacitly extended for periods of eight years, unless the European Parliament or 
the Council opposes such extension not later than three months before the end of each period.’ 

Amendments of network codes and guidelines 

The art 60(1) on ‘the Commission is empowered to amend the network codes within the areas listed in 
Article  59(1)  and  (2)  in  accordance  with  the  relevant  procedure  set  out  in  that  Article.  ACER  may  also 
propose amendments to the networks codes in accordance with paragraphs 2 and 3 of this Article.’ 

Persons who have an interest in any network code may propose draft amendments to network codes to 
ACER. Art 60(2) defines them as an entity or persons including ‘the ENTSO for Electricity, the EU DSO entity, 
regulatory  authorities,  transmission  system  operators,  distribution  system  operators,  system  users  and 
consumers. Moreover ‘ACER may also propose amendments on its own initiative’, as is stated in the same 
article  of  the  e-Regulation.  Indeed,  ACER  may  make  proposals  for  amendments  to  the  Commission, 
explaining  how  such  proposals  are  in  line  with  the  network  codes  objectives  and  shall  consult  all  the 
stakeholders in accordance with art 14 of ACER Regulation (EU) 2019/942. 

Regarding the amendment of guidelines, the Commission shall consult ACER, the ENTSO-E, the DSO Entity 
and other stakeholders where relevant as stated in art 61(6). 

Highlights 
- The Commission is empowered to adopt network codes as implementing acts or delegated acts 
depending on their focus area. 
-  The  addition  of  the  harmonisation  of  distribution  tariffs,  in  the  network  focus  areas,  has  been 
removed as well as the harmonisation of transmission tariffs (compared to the Commission proposal). 
- ACER has Increased responsibilities the stakeholders’ consultation of network codes. 
- The Commission shall review the existing network codes and guidelines by 1 July 2025 and assess 
which of their provisions could be appropriately incorporated into legislative acts of the Union. 
- The Commission empowerment to adopt delegated acts is conferred until 31 December 2028. This 
empowerment can be extended for periods of 8 years if there is no objection from the Parliament or 
the Council.  

54 and, if applicable, before the end of subsequent periods. 

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3. Empowering customers and citizens 
In this section, we set the scene by describing customer and citizen empowerment from demand response 
to energy communities. We then focus on key measures of the CEP to enable these kinds of initiatives. 
This includes new rights for active customers regarding self-consumption, smart metering, data access and 
management, and dynamic pricing. We also present the new rules to facilitate the market entry of new 
customer intermediaries, aggregators and citizens energy communities. 

3.1.  Setting the scene: From Demand Response to energy communities 
According to EC (2016e), the theoretical European potential of DR in 2016 adds up to about 100 GW and 
is  expected  to  reach  160  GW  in  2030.  In  almost  all  MSs,  the  highest  share  of  DR  potential  is  in  the 
residential sector. The potential increase will depend on the roll-out of flexible technologies integration 
such as electric vehicles and heat pumps. Figure 25 shows its potential per Member State and share per 
sector. 

Figure 25: Theoretical demand response potential 2030 (in MW), source: (EC, 2016b) 

The viable potential of demand response is limited, however, to approximately 30-40% of the theoretical 
one. This is due to the fact that not all facilities and devices can be technically controlled by the existing 
ICT  and  infrastructure  (technical  barrier) and  due  to  the  fact  that  only  a  proportion  of  the  technically 
feasible potential can be used in a cost-efficient way (economical barrier). Also, there can be timing issues 
as the associated loads are unlikely to be available all at the same time. In 2016, around 21 GW (out of the 
100 GW potential) of DR participated in the market; 15 GW come from large industrial customers through 
direct  market  participation,  while  approximately  6  GW  come  from  residential  customers  who  are  on 
dynamic pricing contracts. 

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Demand  response  is  actually  a  broad  concept,  ACER  and  CEER  (2016)  provides  guidance  on  how  to 
categorise DR. They divide DR into implicit or explicit: 

● Implicit  DR  is  to  be  understood  as end-consumers  adapting  their  electricity  consumption  patterns  to 
price without explicitly buying or selling in a market. An example is a dynamic electricity contract, which 
reflects the real or expected cost of electricity provision to the consumer (energy and/or network) in 
different time periods. Consumers are rewarded for their flexibility services by reducing their electricity 
bill. Implicit DR potential should be measured through an estimation of the capacity (MW) and volumes 
(MWh) available through it. This requires: 

 - Monitoring the percentage of customers equipped with smart meters 
 - The percentage of them with dynamic pricing contracts (hourly or shorter-term); and  
 - Assessing customers’ reaction to price signals  
● Explicit  DR means  that  demand  response  is explicitly  sold  by  consumers,  directly (for  large  industrial 
ones)  or  through  demand  response  service  providers/aggregators  (supplier  or  a  third  party)  to  the 
market  or  to  grid  operators.  They  are  rewarded  for  their  willingness  to  change  their  demand  for 
electricity at a given point in time, usually in response to a specific system operator’s request. Explicit 
DR  should  be  monitored,  through  the  capacity  (MW)  contracted  and  volumes  (MWh)  sold  into  the 
different markets, in order to assess the flexibility share in each segment of the electricity market.  

Enabling  both  types  of  DR  is  necessary  to  address  different  consumer  preferences.  Some  consumers, 
especially large ones, may engage in both types of DR for different applications and time-scales (SEDC, 
2017). Figure 26 gives an overview of the sequence of Demand-Side engagement. 

Figure 26: Demand-Side Engagement, source: (ACER, 2017) 

Next  to  DR,  another  important  concept  introduced  in  this  section  is  energy  communities.  Energy 
communities are not a new concept. Through energy communities or cooperatives, citizens may engage 
in generation, distribution, aggregation, supply, or storage services. REScoop (2015) stated that after the 
economic crisis of 1929, private investors were very cautious about undertaking new investments, and 
this applied to the electricity sector as well. In the first decades of the last century, local governments and 
cooperatives  of  citizens  filled  in  the  electricity  supply  gaps  throughout  Europe,  as  private  and  public 
undertakings were slow in delivering electrification, especially for rural and isolated areas. Germany, for 
instance,  was  hit  by  a  tidal  wave  of  ‘electricity  cooperatives.’  Between  1895  and  1932,  about  6,000 
electricity cooperatives were created in Germany. For many reasons, explained in the  REScoop (2015), 
only  about  50  are  still  in  existence.  After  the  1973  oil  crisis,  the  anti-nuclear  and  pro-environmental 

69 

 
 
 
movements  emerged.  Enthusiastic  ‘do  it  yourself’  builders  constructed  their  first  wind  turbines  in 
Germany, Denmark, Belgium, the Netherlands and kept on collectively financing and operating them. As 
for their new regulatory framework in the CEP, several questions are worthy of discussion such as the local 
dimension  of  energy  communities,  being  profit  or  value  driven,  and  the  provisions  regarding  grid 
management. 

3.2.  New rights for active customers 

3.2.1.  Self-consumption 
Current practices 
A very simple definition of active customers55, who are often referred to as prosumers, is that they are 
electricity customers that are engaged in the consumption and production of electricity. Other roles can 
be added to this definition, such as storage, demand response, and energy efficiency. Active consumers 
can  be  both  household  customers  and  non-household  customers.  However,  with  reference  to  the  3rd 
Energy Package, only a final customer can be an active customer, and wholesale customers do not qualify 
as active customers (Butenko, 2017). Active customers emerged in Europe more than two decades ago, 
and their number has been slowly increasing. More recently, with the ongoing technological innovation 
(DER, batteries, smart metering...), their roles have been expanding and increasing more rapidly. In 2050 
the European electricity system is expected to have millions of prosumers, electric vehicles and storage 
systems willing to provide energy and flexibility. 

Legislators  wanted  to  set  guarantees  for  final  customers  to  encourage  them  to  engage  in  electricity 
generation  and  Demand  Response.  In  Europe,  national  regulatory  frameworks  vary  widely  across  MSs 
regarding  this  question.  The  EC  (2017c)  study on  residential  prosumers  in  the  European  Energy  Union 
states three main indicators against which national regulation for residential prosumers can be assessed: 
the legal basis or definition in the national regulation, generation/consumption elements, and the power 
capacity cap reference56. 

First, most countries covered in the EC (2017c) study define and regulate prosumers under different types 
of legislation. Few of them, however, do not have any legally binding definition. For instance, Belgium 
Flemish Region, Ireland, and Romania only have definitions developed by the DSO in private codes, which 
do not have any legally binding character. 

Second, there is the concept definition of prosumers or active customers with reference to consumption 
or  production.  Some  MSs  (Portugal,  The  Netherlands,  France,  Austria,  Bulgaria,  Denmark,  Spain,  and 
Lithuania) refer to self-consumption or auto-consumption. In Greece, prosumers are characterised as self-
producers,  instead of self-consumers. In Portugal, self-consumers are  defined in relation to renewable 
energy  as  the  persons  who  produce  energy  through  renewable  sources  for  self-consumption.  In  the 
Netherlands, the self-consumer definition is also related to renewable energy. In France, the production 
does not necessarily need to be from renewable energy sources. In Spain57, self-consumption was defined 
as the ‘consumption of electric energy from generation installations that belong to the consumer or from 
installations that are connected to the consumer through a direct line of electric energy connected to the 

55 Note that three terms are used in the European Commission official documents with the same meaning, which are active 
customers, active consumers and prosumers. 20 to 30 years ago, the term prosumer was mainly used to refer to large industrial 
units with DG. 
56 Refers to the capacity of power generation and to the installation size. 
57 Spain has recently introduced a new regulation, Real Decreto 244/2019, setting new administrative, technical and economic 
requirements for promoting self-consumption transposing the e-Directive and the renewable energy Directive into the Spanish 
regulation  (Energy Democracy, 2019). 

70 

 
                                                           
grid,’ which form an interesting definition combining consumption, production, and connection to the grid 
(EC, 2017c). This assessment indicator, however, does not have any consequences for the quality of the 
support system to the corresponding prosumers. 
Third, MSs may also define residential prosumers in relation to the capacity of the installation by stating 
that it has to be below a certain threshold. For example, Ireland defines micro-generation as a source of 
electrical energy that operates in parallel to the energy distributor and is rated up to 6kW at low voltage 
with a single phase connection (230 Volt) and 11kW at low voltage with the three-phase connection. Some 
other MSs  use  the  10kW  capacity  as  a threshold,  such  as  Lithuania,  Slovakia, Czech  Republic,  and  the 
Flemish system operator. A third group (e.g., Spain, Romania, and also Norway58) uses a capacity cap of 
100kW for defining residential prosumers. 

The CEP measures for active customers 

The  CEP  sets  a  regulatory  framework  that  copes  with  the  new  technological  developments  and  puts 
consumers at the heart of the energy market. This does not create a new category of customers, but it will 
enable active  consumer  participation while  ensuring their rights  and  setting their duties. Indeed, even 
though consumers can generate and store electricity and easily manage their energy consumption, there 
are  still  some  barriers  in  the  current  design  of  the  retail  market,  preventing  consumers  from  fully 
benefiting from such opportunities. The CEP measures aim to extend the level playing field in generation 
to the prosumers.  
The  e-Directive  defines  an  ‘active  customer’  as  a  ‘final  customer,  or  a  group  of  jointly  acting  final 
customers,  who  consumes  or  stores  electricity  generated  within  its  premises  located  within  confined 
boundaries or, where permitted by a Member State, within other premises, or who sells self-generated 
electricity or participates in flexibility or energy efficiency schemes, provided that those activities do not 
constitute its primary commercial or professional activity.’ 
The  active  customer  participation  in  the  wholesale  market  is  restricted  to  the  sale  of  self-generated 
electricity  and  purchasing  electricity  for  their  own  use  while  not  constituting  a  primary  commercial 
activity. The situation is similar for DR provision by active customers. They can place bid, alone or through 
aggregation, to sell demand reduction or increase at a price in an organised market. The contract of a final 
customer with an aggregator, according to art 13 of the e-Directive, should be done directly, and without 
the prior consent of the final customer's electricity undertakings, referring to electricity suppliers.  
Art  13(4)  of  the  e-Directive  requires  MSs  to  ensure  the  rights  of  final  customers  to  contract  with 
aggregators shall not be subject ‘to discriminatory technical and administrative requirements, procedures 
or charges by their supplier on the basis of whether they have a contract with a market participant engaged 
in aggregation.’ 
Compared to the version of the Commission proposal of e-Directive, art 15 in the final text brings more 
clarification on the framework to be established for active consumers. Indeed MSs shall ensure that active 
customers are; 
‘(a) entitled to operate either directly or through aggregation;  

(b) entitled to sell self-generated electricity, including through power purchase agreements;  

(c) entitled to participate in flexibility schemes and energy efficiency schemes;  

(d) entitled to delegate to a third party the management of the installations required for their activities, 
including installation, operation, data handling and maintenance, without that third party being 
considered to be an active customer;  

58 Norway is not a EU MS. 

71 

 
                                                           
(e) subject to cost-reflective, transparent and non-discriminatory network charges that account 
separately for the electricity fed into the grid and the electricity consumed from the grid, in accordance 
with Article 59(9) of this Directive and Article 18 of Regulation (EU) 2019/943, ensuring that they 
contribute in an adequate and balanced way to the overall cost sharing of the system;  

(f) financially responsible for the imbalances they cause in the electricity system; to that extent they shall 
be balance responsible parties or shall delegate their balancing responsibility in accordance with Article 5 
of Regulation (EU) 2019/943.’ 

MSs may apply different national governing provisions for individual and jointly acting final customers as 
long as all the mentioned rights and obligations are applied. In case of different treatment towards jointly 
acting active customers, it shall be proportionate and duly justified (art 15(3)). 
In addition, regarding mostly feed-in tariffs schemes, art 15(4) adds that MSs ‘have existing schemes that 
do not account separately for the electricity fed into the grid and the electricity consumed from the grid, 
shall not grant new rights under such schemes after 31 December 2023.’ Customers under these schemes 
shall have the possibility to opt for a new scheme accounting separately for the electricity fed into the grid 
and the electricity consumed as the basis for calculating network charges, at any time. 
For residential storage, the final version of the e-Directive adds more clarification on the rights of active 
customers owning storage facilities. Art 15(5) states that MSs shall ensure that these customers: 

-  Have the right to a grid connection within a reasonable time, provided fulfilling all the conditions59. 
-  Are not subject to any double charges when providing flexibility services60 to system operators. 
-  Are not subject to disproportionate licensing requirements or fees. 
-  Are allowed to provide different services at the same time, if technically feasible. 

Highlights 
- Active customers can be both household and non-household final customers. 
- Active customers activities regarding selling self-generated electricity or participating in flexibility or 
energy efficiency schemes, shall not constitute their primary commercial or professional activities. 
- Network tariffs shall reflect the cost and value of the system infrastructure, including for active 
customers.  
- Customers are entitled to direct contracts with aggregators, without prior consent of the supplier. 
-No new rights shall be given to existing national schemes, not accounting separately for the electricity 
fed into the grid and the electricity consumed from the grid, after 31 December 2023. 

3.2.2.  Smart metering systems 
Current levels of smart meter deployment  
The electricity Directive 2009/72/EC of the 3rd Energy Package set, in ANNEX I(2), a target of 80% of total 
consumers being equipped with a smart metering system by 2020. Smart metering systems aim to support 
retail markets to fully deliver benefits to consumers and the electricity system through enabling demand 
response, dynamic pricing competition, and other energy services to evolve. 

The decision to roll-out smart metering systems at MS levels was subject to national cost-benefit analyses, 
resulting in different coverage choices, technical characteristics, and implementation roadmaps. Figure 27 

59 Conditions such as balancing responsibility and adequate metering. 
60 This refers mainly to double charging when storing electricity for flexibility purposes.  

72 

 
 
                                                           
 
shows the status of smart metering systems roll-out status in EU MSs at the end of 2017. Eight MSs and 
Norway have a roll-out that already reached more than 50% of household consumers. Italy (95%), Finland 
(97%)  and  Sweden  (100%)  are  the  EU  frontrunners  in  smart  meter  coverage.  In  seven  other  MSs,  the 
implementation has just started (ACER and CEER, 2018c). These significant variations among the Member 
States are due to the uncertain cost/benefit of the deployment, as well as concerns about security and 
data  protection.  EC  (2016f)  evaluation  of  the  EU  Framework  for  metering  and  billing  of  energy 
consumption,  a  report  accompanying  the  CEP,  points  out  the  relatively  low  penetration  rate  of  smart 
meters across most MSs. It adds that this indicates the limited effectiveness of the provisions in the 3rd 
Energy Package. Note that in the majority of MSs, the DSOs are in charge of the procurement of smart 
meters except in the UK where the suppliers are in charge of the implementation.  

Figure 27: Electricity smart meter roll-out rates in EU MSs (and Norway) – 2017 (%), source: (ACER and CEER, 2018c) 

By 2020 it is projected that 72% of European consumers will be equipped with smart meters for electricity 
(EC, 2016b). Figure 28 shows when the electricity smart meter roll-out 80% target has been or is planned 
to be reached.  

-14 Member States: Sweden, Italy, Finland, Malta, Spain, Austria, the UK, Estonia, Romania, France, the 
Netherlands, Denmark, Luxembourg,  and lately Latvia are targeting a nation-wide roll-out to at least 80% 
of customers by 2020 (with some of them already going much beyond the target of the e-Directive). 

-2  Member  States,  Germany,  and  Slovakia,  are  moving  to  a  deployment  in  a  selected  segment  of 
consumers (to max. 23% by 2020). 

-The remaining ones; Belgium, Bulgaria, Czech Republic, Greece, Ireland, Lithuania, Poland, and Portugal, 
have either decided against, at least under current conditions or have not made a firm commitment yet 
for a mass-scale or even a selective roll-out. For some MSs, like Hungary or Cyprus, no data were available. 

73 

 
 
 
 
 
Figure 28: Target year by when the 80 % rate of electricity smart meters will be reached in EU MSs– as of end 2017, source: 
(ACER and CEER, 2018c) 

The CEP measures for smart meter integration 

A ‘smart metering system’ according to the e-Directive is ‘an electronic system that is capable of measuring 
electricity  fed  into  the  grid  or  electricity  consumed  from  the  grid,  providing  more  information  than  a 
conventional meter, and that is capable of transmitting and receiving data for information, monitoring 
and control purposes, using a form of electronic communication.’ They have a key role promoting energy 
efficiency and empowering final customers, in particular with regard to their interaction with consumer 
energy management systems and smart grids. 

Incentives for smart metering systems 
Smart metering is a key technology that allows consumers to engage in the electricity markets (recital 52 
of the e-Directive). It adds that ‘smart metering systems empower consumers because they allow them to 
receive accurate and near real-time feedback on their energy consumption or generation, and to manage 
their  consumption  better,  to  participate  in  and  reap  benefits  from  demand  response  programmes  and 
other services, and to lower their electricity bills.’ For DSOs, smart metering enables them to have better 
visibility of their networks. It reduces operation and maintenance costs. It could be considered as a sensor, 
which can ‘open the door’ to new services.  
The roll-out of smart metering systems in a MS may be subject to cost-benefit analysis (CBA), as indicated 
in art 19(2) and following the principles laid down in Annex III of the e-Directive. The ANNEX II states that 
‘subject to that assessment, Member States or, where a Member State has so provided, the designated 
competent authority, shall prepare a timetable with a target of up to ten years for the deployment of smart 
metering systems.’   
Where smart metering is positively assessed or systematically rolled out, the MS shall implement smart 
metering systems in accordance with European standards and in line with the provisions of Annex II on 
‘Smart  meters’  as  well  as  art  20  of  the  e-Directive.  If  it  is  negatively  assessed  (negative  CBA)  and  not 

74 

 
 
systematically  rolled  out,  the  MS  shall  ensure  that,  on  request,  every  final  customer  is  entitled  ‘while 
bearing  the  associated  costs,  to  have  installed  or,  where  applicable,  to  have  upgraded,  under  fair, 
reasonable and cost-effective conditions, a smart meter that’, according to art 21(1). 
Positive CBA - Minimum smart meters functionalities  
In case of a positive CBA, at least 80 % of final customers in the MSs shall be equipped with smart metering 
systems. This shall be done within seven years from the date of their positive CBA or by 2024 for MSs that 
have started the systematic deployment before 4 July 2019. 
‘Member States that proceed with the deployment of smart metering systems shall adopt and publish the 
minimum functional and technical requirements for the smart metering systems to be deployed in their 
territories,  in  accordance with  Article  20  and  Annex  II,’  as  stated  in  art 19(3)  of  the  e-Directive.  These 
minimum functionalities should correspond, inter alia, to the ones listed in EC (2012) recommendations 
2012/148/EU, based on best practices from CBAs for smart metering carried out in 11 MSs, ‘as well as the 
best  available  techniques  for  ensuring  the  highest  level  of  cybersecurity  and  data  protection.’  These 
minimum functionalities cover:  

●  Accurate, direct and near-real-time reading for the customer and third parties designated by the 

consumer, at no additional cost; 

●  System  security  provision,  privacy  and  data  communications  protection,  in  compliance  with 

relevant Union security legislation ensuring the highest level of cybersecurity protection; 
●  Accounting for electricity injected into the grid and remote reading of meters by the operator; 
●  Appropriate advice and information shall be given to final customers; 
●  Enabling final customers to be metered and settled at the same time resolution as the imbalance 

period in the national market; 

●  Two-way  communication  between  the  smart  metering  system  and  external  networks  for 

maintenance and control of the metering system; 

●  Support of advanced tariff systems. 

Note  that  art  8(4)  of  the  e-Regulation  states  that  imbalance  settlement  shall  be  15  minutes61  in  all 
scheduling areas at wholesale and retail level by 1 January 2021, unless NRAs have granted a derogation 
or  an exemption.  Derogations  may  be  granted only  until  31  December  2024.  Therefore,  smart meters 
should allow the provision of data at least with this granularity level. 
Also,  flexibility  and  interoperability62  play  a  large  role  for  promoting  smart  meter  implementation. 
Art 19(3) adds that ‘(…) Member States shall ensure the interoperability of those smart metering systems, 
as well as their ability to provide output for consumer energy management systems.’ MSs shall use relevant 
available standards enabling interoperability, refer to best practices and be aware of the importance of 
the development of data exchange, future and innovative energy services, smart grids and the internal 
market in electricity.   
Note that the different smart metering systems provisions shall apply to future installations as well as to 
installations replacing older smart meters. The already-installed systems, or for which the ‘start of works’ 
began, before 4 July 2019, may remain in operation over their lifetime. However, if they do not meet the 
requirements stated in this section and the e-Directive, they  shall not remain in operation after 5 July 
2031. 

61 It is currently 60 minutes in most Member States.  
62  ‘Interoperability’,  is  defined  in  the  e-Directive  in  the  context  of  smart  metering  as  ‘the  ability  of  two  or  more  energy  or 
communication networks, systems, devices, applications or components to interwork to exchange and use information in order to 
perform required functions.’ 

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Customer contributions to smart metering systems costs 
The  e-Directive  provisions  state  that  final  customers  contribute  to  the  costs  of  smart  meters  in  a 
transparent and non-discriminatory manner. Art 19(4) states that ‘Member States that proceed with the 
deployment of smart metering systems shall ensure that final customers contribute to the associated costs 
of the deployment in a transparent and non-discriminatory manner, while taking into account the long-
term benefits to the whole value chain.’ MSs, or were provided the NRA, shall monitor smart metering 
systems’ deployment in their territories regularly to assess the benefits provided for consumers. 
Negative CBA - Consumers’ right to a smart meter  
When the smart metering systems’ deployment is negatively assessed through the CBA, a MS shall ensure 
that a periodical revision, at least every four years, of this assessment is carried-out, or more frequently 
with regard to the changes in the underlying assumptions and market and technology developments. The 
updated economic assessment should be notified to the Commission, according to art 19(5). 
Final consumers are still entitled to have a smart meter installed in the case of a negative national CBA, 
although they have to pay for the associated costs themselves as stated in art 21(1). It should have the 
functionalities referred to in art 20, or be equipped with a set of minimum functionalities to be defined 
and published by MSs at the national level in line with the provisions in Annex II. The offer to the final 
customers requesting the smart meter should clearly state the functions and interoperability of the system 
as well as associated costs to be borne. In this framework, the MS or the designated competent authority 
shall ensure that smart metering systems are installed ‘within a reasonable time, no later than four months 
after  the  customer's  request63after  the  customer's  request.’  They  shall  also,  according  to  art  21(2), 
‘regularly, and at least every two years, review and make publicly available the associated costs, and trace 
the  evolution  of  those  costs  as  a  result  of  technology  developments  and  potential  metering  system 
upgrades.’ 

Highlights 
- Smart meter roll-out may be subject to a CBA analysis. 
-  Consumers  will  have  the  right  to  get  smart  meters  to  control  their  consumption,  unless  the  CBA 
analysis in a given member state shows that the costs outweigh the benefits. 
- In case of a positive CBA: a roll-out to at least 80% of final customers within 7 years from the date of 
the positive CBA or by 2024 for MSs that have started the systematic deployment before 4 July 2019. 
- In case of a negative CBA: customers’ entitlement to the installation or the upgrade of a smart meter 
with  a  set  of  defined  minimum  functionalities  on  request  and  under  fair  and  reasonable  conditions 
within 4 months, while bearing associated costs. 
- More concrete and clear minimum set of functionalities for smart meters are set. 
- The imbalance settlement period to be harmonised at 15 min across Europe by 2021, with possible 
derogation/exemptions. 

3.2.3.  Data access and management 
Current practices 
With the increased roll-out of smart meters across Europe, the experience from leading MSs in this process 
shows that robust and clear rules are necessary to ensure that the full benefits of smart metering data are 
realised, and that data privacy is respected (EC, 2016b). Such rules are not fully developed in the existing 
EU legislation, and national regulations may differ from one MS to another. This may harm the interests 
of market actors involved in data handling, meaning that they are unlikely to emerge without regulatory 

63 This was three months in the Commission proposal. 

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intervention. For example, studies from NRAs, according to EC (2016b) indicate that discriminatory access 
to  information  on  potential  customers  represents  a  key  barrier  for  new  entrants  to  retail  electricity 
markets in Europe. Indeed, as most DSOs are also electricity retailers, safeguards, and market monitoring 
are  necessary  to  prevent  them  from  adopting  rules  on  discriminatory  access  and  management  of 
consumer  data  (i.e.,  smart  metering  data)  and  gaining  a  competitive  advantage  through  information 
asymmetry between them (the incumbents) and the potential new entrants. 

The CEP measures for data access and management  
According to the EC (2016b) impact assessment, consumer data management rules should be put in place 
in  Europe,  and  standardised  national  data  formats  –  to  facilitate  data  access  –  should  also  be 
implemented. The CEP defines responsibilities in data handling as well as criteria and principles to ensure 
the  impartiality  and  non-discriminatory  behaviour  of  entities  involved  in  data  handling.  Each  MS  is 
required to apply these principles independent from the data management model. These measures aim 
to increase transparency, provide non-discriminatory access and enhance competition, while at the same 
time ensuring data protection. The final text of the e-Directive sets also interoperability requirements and 
procedures  for  access  to  data,  instead  of  a  common  EU  data  format  that  builds  upon  national  ones 
proposed initially by the Commission. 
‘When laying down the rules regarding the management and exchange of data, Member States or, where 
a Member State has so provided, the designated competent authorities shall specify the rules on the access 
to data of the final customer by eligible parties in accordance with this Article and the applicable Union 
legal framework.’ according to art 23(1) of the e-Directive. ‘Data shall be understood to include metering 
and  consumption  data  as  well  as  data  required  for  customer  switching,  demand  response  and  other 
services,’  for  the  purpose  of  the  e-Directive.  Art  23(2)  adds  that  ‘Member  States  shall  organise  the 
management of data in order to ensure efficient and secure data access and exchange, as well as data 
protection and data security.’  
MSs  or  the  designated  competent  authorities  shall  also  authorise  and  certify  or,  where  applicable, 
supervise the parties that are managing data in order to ensure that they comply with the requirements 
of the e-Directive, according to art 23(4). Art 23(5) states, regarding data access, that ‘no additional costs 
shall  be  charged  to  final  customers  for  access  to  their  data  or  for  a  request  to  make  their  data 
available.’ The  article  adds  that  costs  charged  by  regulated  entities  providing  data  services  shall  be 
reasonable and duly justified. This replaces the non-profit criteria of the provision of these services by 
regulated entities, stated in the Commission proposal for e-Directive. 
Regarding customers’ right to access their data, art 13(3) of the e-Regulation adds that, MSs shall ensure 
that when final customers are engaged in aggregation, they are entitled ‘to receive all relevant demand 
response data or data on supplied and sold electricity free of charge at least once every billing period if 
requested  by  the  customer.’  In  addition  to  non-discriminatory  data  access,  the  e-Directive  sets 
interoperability requirements and procedures for access to data. They replace the common data formats 
originally proposed by the Commission. According to art 24 of the e-Directive, MSs shall facilitate the full 
interoperability of energy services within the EU in order to promote competition in the retail market and 
avoid excessive administrative costs for the eligible parties. Indeed the Commission ‘shall adopt, by means 
of implementing acts, interoperability requirements and non-discriminatory and transparent procedures 
for access to data referred to in Article 23(1).’  
Art 24(3) adds that MSs ‘shall ensure that electricity undertakings apply the interoperability requirements 
and procedures for access to data referred to in paragraph 2. Those requirements and procedures shall be 
based on existing national practices.’ 

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Highlights 
-  MSs  are  required  to  set  principles  ensuring  the  impartiality  and  non-discriminatory  behaviour  of 
entities involved in data handling and data access. 
- MSs, or their designated competent authorities, shall specify the rules for access to final customers’ 
data by eligible parties. 
- Costs charged by regulated entities providing data services shall be reasonable and duly justified. 
- Final customers engaged in aggregation shall have the right to receive, least once every billing period 
if requested, all their demand response data or data on supplied and sold electricity. 
- MSs shall facilitate the full interoperability of energy services within the EU and apply requirements 
building on existing national practices. 

3.2.4.  Dynamic pricing 
Dynamic pricing methods in Europe  
Several dynamic pricing (DP) methods with different penetration levels among customers exist in 
Europe. The different methods depend on two main factors (ACER and CEER, 2016): 

- 
- 

The granularity of the period during which consumption is metered separately, and 
The dynamics/statics of ToU prices.  

The impact on consumers depends on the combination of these two factors. They can be rewarded for 
positively reacting to price signals or penalized for not reacting. There are three main methods applied in 
the EU. Their implementation depends on the provided enabling framework. 

- 

Static Time of Use (ToU): the end-user electricity price is set in advance for each fixed time band. 
It reflects the average wholesale price in the time band (low granularity-low dynamics). It can 
vary by time of day, the day of the week and/or the season of the year. Another form of ‘static 
ToU’, less common, that has high granularity-low dynamics, is where hourly consumption is 
priced at monthly average prices. This form is called ‘spot market-based pricing’.  

-  Critical peak pricing (CCP): a higher end-user electricity price is charged in designated and limited 
periods corresponding to consumption peaks at the system level (low granularity-high dynamics)  

-  Real-time pricing: the end-user electricity price is posted in real time (typically at least hourly) 

and communicated automatically to the consumer as it changes (high granularity-high 
dynamics). 

Figure 29 gives a classification of the DP methods in function of the two factors. 

Figure 29: Methods of dynamic pricing for electricity, source: own illustration 

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Dynamic pricing in electricity supply 
Figure  30  shows  the  different  DP  methods  across  MSs;  countries  are  coloured  according  to  the  main 
dynamic pricing method used, as stated in the questionnaire presented in (ACER and CEER, 2016).  

Figure 30: Share of standard household consumers supplied under dynamic pricing (DP), adapted from (ACER and CEER, 2016) 

ToU pricing is applied in 17 out of 22 countries whose NRAs participated in the questionnaire. The most 
commonly applied type of ToU is a day/night differentiation. However, in some countries the number of 
time  periods  of  ToU  tariffs  can  be  higher  (e.g.,  in  Italy,  three-time  bands  are  set  based  on  the 
weekdays/weekends  and  peak/off-peak  differentiation).  Spot  market-based  pricing  applies  to  a  large 
share  of  electricity  household  customers  in  three  countries  (Denmark,  Norway,  and  Sweden)  through 
monthly  spot-exchange  prices.  The  hourly  real-time  pricing  method  is  only  used  in  five  European 
countries:  Sweden,  the  UK,  Romania,  Estonia  and  Spain  with  different  penetration  levels  among 
households. For the latter two, between 25% and 50% of all households have access to supply tariffs based 
on  hourly  pricing.  Critical  peak  pricing  (CCP)  applies  to  a  smaller  proportion  of  households  in  France, 
Romania, Lithuania, Portugal and the UK. 
In  some  MSs,  there  are  multiple  DP  methods  in  use.  The  additional  dynamic  pricing  methods  are 
represented by the coloured dots in Figure 30. As for Spain, between 25% and 50% of households incur 
hourly real-time pricing and ToU also applies to less than 25% of the households.  

The CEP measures for dynamic contracting 
The  CEP  sets  measures  for  the  expansion  of  dynamic  price  contracts  in  Europe  to  enhance  consumer 
empowerment and participation in competitive retail markets. We will present here the new measures of 
the  CEP  in  two  parts,  first,  the  entitlement  to  dynamic  supply  contracts  and  second  the  provision  for 
dynamic network charges. 

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Customer’s entitlement and implementation monitoring 
The e-Directive defines a dynamic electricity contract as ‘an electricity supply contract between a supplier 
and a final customer that reflects the price variation in the spot markets, including in the day-ahead and 
intraday markets, at intervals at least equal to the market settlement frequency.’ Note that this definition 
focuses on real-tme pricing rather thanstatic Time-of-Use Tariff (ToU) and the critical peak pricing (CCP). 

Art  11  of  the  e-Directive on  ‘Entitlement  to  a  dynamic  electricity  price  contract’  states  that  MSs  shall 
ensure that every final customer, with a smart meter installed, should be entitled to a dynamic electricity 
price  contract  on  request.  The  final  customer  should  benefit  from  this  right  and  conclude  a  dynamic 
electricity supply contract ‘with at least one supplier and with every supplier that has more than 200 000 
final customers.’ Final customers shall also be ‘fully informed by the suppliers of the opportunities, costs 
and risks of such dynamic electricity price contracts, (…)’ according to art 11(2). This includes the provisions 
of information regarding the type of meter needed for customers. In addition, dynamic contracts market 
developments shall be monitored by NRAs that also assess the risks that these new products and services 
may entail as well as the possible abusive practices. Art 11(3) states that the final customer’s consent is 
required to be obtained by suppliers before that the customer is switched to a dynamic electricity price 
contract.’ 
Moreover, MSs or their NRAs shall monitor and publish a report annually for at least a ten-year period 
after  the  introduction  of  such  contracts.  The  report  shall  contain  the  main  developments  of  dynamic 
contracts and the impact on consumers' bills, specifically the level of price volatility. 

Dynamic pricing for network charges in the CEP 
Art 18 of the e-Regulation on ‘Charges for access to networks, use of networks and reinforcement,’ focuses 
in paragraph 7 on distribution tariffs. They shall reflect the cost of use of the distribution grid by system 
users and may contain network connection capacity elements. They can be differentiated based on system 
user characteristics and generation/consumption profiles. It adds that in MSs that have rolled-out smart 
metering systems, NRAs shall consider and may introduce time differentiated network tariffs when fixing 
or approving their network tariffs or their methodologies. This aims to reflect ‘the use of the network, in 
a transparent, cost efficient and foreseeable way for the final customer.’ 

Highlights 
- The new definition of DP excludes the less granular pricing methods. 
- Every final customer shall be entitled to a dynamic electricity contract upon request. 
- MSs shall ensure that final customers with a smart meter can request to conclude a DP contract with 
at least one supplier and with every supplier with more than 200 000 final customers. 
- MSs, or their NRAs, shall publish an annual report on the main developments of DP contracts for at 
least ten years. 
- Incentives are provided for the introduction of dynamic time differentiated network tariffs. 

3.3.  Market entry for new customer intermediaries 
The CEP defines two new customer market intermediaries: aggregators and citizens energy communities. 
Furthermore,  The  CEP  contains  provisions  on  their  regulatory  framework,  roles,  and  duties  aiming  to 
group the energy generation or consumption of several consumers. In this section, we discuss these two 
customer market intermediaries in detail.  

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3.3.1.  Aggregators 
The landscape of electricity aggregators  
Aggregation, according to art 2 (17) of the e-Directive means ‘a function performed by a natural or legal 
person who combines multiple customer loads or generated electricity for sale, purchase or auction in any 
electricity market.’ An aggregator is, therefore, an energy service provider that can change the electricity 
consumption of  a  group of  electricity  consumers  and  provide  demand-side  flexibility  to  the  grid.  They 
represent important actors helping to enhance demand participation and to activate the DR potential (EC, 
2016b). 
Different aggregator models exist that are discussed both in stakeholders reports (NordREG, 2016) and 
academic  literature  (Poplavskaya  and  De  Vries,  2018).  First,  aggregation  can  be  carried  out  by  the 
traditional energy service provider, i.e., the electricity supplier and the aggregator are one entity. Second, 
aggregation services can be provided by new entrants that are not the electricity supplier. They are called 
then independent aggregators. Figure 31 illustrates the access of independent aggregators to markets in 
Europe. 

Figure 31: Independent aggregators’ access to markets, source: (SEDC, 2017) 

According  to  SEDC  (2017),  the  MSs  that  currently  provide  the  most  supportive  framework  for  the 
development  of  demand  response  and  aggregation  are  France,  Belgium,  Finland,  the  UK  and  Ireland. 
Nevertheless, there are still regulatory issues that exist in these MSs.  
France64 has put in place detailed frameworks for independent aggregation, including the standardised 
roles  and  duties  of  market  participants.  In  Belgium,  upcoming  legislation  addressing  the  role  of  the 
aggregator and independent aggregation will soon be put in place. Spain, Portugal, and Estonia are in red 
in Figure 31, because aggregated demand-side flexibility is either not accepted as a resource in any of the 
electricity markets or not economically viable. Note that for Italy, which is also in red, a partial opening of 
balancing markets to aggregators occurred in 2018 (Bertoldi et al., 2017). For instance, in Italy, different 

64 In France, large industrial customers have been participating in balancing mechanisms since 2003. The provision of FCR by 
industrial customers started in 2014. Furthermore, demand was allowed to participate in automatic FRR since July 2014, and in 
the day ahead and intraday markets from January 2017 (SEDC, 2017). 

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types of aggregation model are being tested under the supervision of the Italian TSO Terna and the Italian 
regulatory authority ARERA (Terna, 2019).  

Independent aggregators and electricity suppliers can have opposing interests due to their type of activity; 
the former sell flexibility while the latter sell electricity. In most MSs, except France, the UK, and Ireland, 
an  aggregator  needs  permission  from  the  supplier  to  access  the  supplier’s  customers,  and  this  may 
constitute a market entry barrier for the aggregator to contract with these customers, though this may be 
changing. 

The CEP measures for aggregators  

The CEP establishes a regulatory framework that clarifies the roles and responsibilities of aggregators 
and thus removes barriers impeding independent aggregators from entering the market. 
Consumers’ right for aggregator contracting 
Art 13 of the e-Directive on ‘Aggregation contract’ sets a requirement from MSs to ensure that customers 
have  the  freedom  to  purchase  or  sell  electricity  service,  including  by  means  of  aggregation.  This  is 
independent of customers’ supplier contracts and could be agreed with an electricity undertaking they 
choose.  In  addition,  MSs  shall  ensure  that  final  customers’  engagement  with  an  aggregator  shall  not 
require the consent of the final customer's electricity undertaking as stated in art 13(2) and 3.2.1. 
MSs shall ensure in turn that aggregators inform customers about all the terms and conditions of their 
offers and contracts. They shall also provide their customers with demand response data or data on the 
electricity supplied and sold at least once every billing period if requested by the customer, and this shall 
be free of charge. 

These rights to customers shall be  granted in a non-discriminatory way. Indeed, MSs, according  to  art 
13(4),  shall  safeguard customers  and  ensure  that  they  ‘are  not subject  to  discriminatory  technical  and 
administrative requirements, procedures or charges by their supplier on the basis of whether they have a 
contract with a market participant engaged in aggregation.’ 

Regarding contract termination with an aggregator, the rules were included in art 12 and are similar to 
contract termination with supplier. Accordingly, the process of switching from market participant engaged 
in aggregation shall be concluded within a maximum of three weeks. By no later than 2026, the switching 
process shall take no longer than 24 hours and be possible on any working day. 

Also similarly, ‘Member States shall ensure that at least household customers, microenterprises and small 
enterprises are not charged any switching-related fees65’ when switching between aggregators according 
to  art  12(2).  By  way  of  derogation,  MSs  can  allow  aggregators  to  charge  their  customers  contract 
termination fees, as long as they were included in the signed contract and were clearly communicated to 
the customer ex-ante. The fees shall be proportionate and not more than the aggregator’s direct economic 
loss. Art 12(3) adds that ‘the burden of proving the direct economic loss shall be on the supplier or market 
participant engaged in aggregation, and the permissibility of contract termination fees shall be monitored 
by the regulatory authority, or by an other competent national authority.’ 

Rules for aggregators’ market participation  
Art  17  of  the  e-Directive,  on  ‘Demand  response  through  aggregation,’  requires  MSs  to  foster  DR 
participation of active customers directly, or through aggregation, in all electricity markets. MSs shall also 
ensure that TSOs and DSOs have a non-discriminatory behaviour towards market participants engaging in 
DR aggregation when procuring ancillary services. 

65 'Contract termination fee‘, according to art 2(16) of the e-Directive, means ‘a charge or penalty imposed on customers by 
suppliers or market participants engaged in aggregation, for terminating an electricity supply or service contract’. 

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To promote aggregators’ participation, art 17(3) states that MSs’ regulatory frameworks should ensure 
that each market participant engaged in aggregation, including independent aggregators, has the right to 
enter the market without consent from other market participants. Clear and non-discriminatory rules shall 
be established to assign roles and responsibilities, including the data exchange between aggregators and 
other market participants. 

For  balancing  responsibilities,  the  article  adds  that  ‘market  participants  engaged  in  aggregation  to  be 
financially responsible for the imbalances that they cause in the electricity system; to that extent they shall 
be balance responsible parties or shall delegate their balancing responsibility in accordance with Article 5 
of Regulation (EU) 2019/943.’ Market participants engaged in aggregation may, however, be required to 
pay a compensation66 to other market participants or market participants BRPs which are directly affected 
by DR activation. The financial compensation payments ‘shall be strictly limited to covering the resulting 
costs  incurred  by  the  suppliers  of  participating  customers  or  the  suppliers'  balance  responsible  parties 
during the activation of demand response.’ The calculation method for compensation shall be approved 
by NRAs or other competent authorities. It may take into account the benefits created by aggregators to 
other market participants. In this case, the aggregator may only contribute to the compensation if the 
benefit  they  create  for  all  customers,  their  BRPs  and  suppliers  are  less  than  the  incurred  costs.    The 
national regulatory framework shall contain ‘a conflict resolution mechanism between market participants 
engaged in aggregation and other market participants, including responsibility for imbalance.’ 
Also, regarding the technical requirements for DR participation, TSOs and DSOs in close cooperation with 
other market participants and final customers shall, according to art 17(5), establish them in all electricity 
markets  ‘on  the  basis  of  the  technical  characteristics  of  those  markets  and  the  capabilities  of  demand 
response. Such requirements shall cover participation involving aggregated loads.’  

Highlights 
- Reducing entry barriers: Aggregators can participate in the market without consent from other 
market participants, i.e., the customer’s supplier. 
- Enabling consumer switching: Final customers’ contract termination with aggregators to be done 
within three weeks and within 24 hours by 2026. 
- Aggregators shall be balance responsible and liable to pay a compensation in certain situations. 
- A conflict resolution mechanism between market parties engaged in aggregation and other market 
participants, including responsibility for imbalance shall be included in MSs regulatory frameworks. 

3.3.2.  Citizens Energy Communities 
The landscape of energy communities  

The past decade or so has seen the emergence of increasing numbers of energy cooperatives through 
citizen initiatives, which produce and supply themselves with clean, renewable energy, and this trend is 
likely  to continue  in  the  future  (see  Figure  32). Energy  communities  may  be  a  gathering  of  household 
consumers on a small scale or be a more structured larger group of citizens and stakeholders. Figure 32 
gives an overview of the energy communities in Europe. 

66  This  financial  responsibility  was  not  included  in  the  Commission  proposal  for  the  e-Directive  and  it  was  only  possible  in 
exceptional cases subject to the approval of NRAs and monitored by ACER. 

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Figure 32: EU groups or cooperatives of citizens on renewable energy, energy efficiency, and e-mobility, (REScoop, 2019) 

Recently citizen cooperatives have started looking at taking back the electricity grids as well. One of the 
most known examples is the one of Hamburg, where citizens voted to buy back the distribution grid from 
Vattenfall in early 2014. A similar campaign was attempted in Berlin but failed. However, the question of 
buying back the grid there has not yet been completely resolved (EC, 2015c).  

The  drivers  for  energy  communities  are  not  just  the  benefits  from  competitive  energy  prices  and 
investment returns. Indeed by cooperating with their neighbours, energy communities aim to realize a fair 
energy transition and effectively fight climate (REScoop and Energie Cities, 2018). 

EU citizens have started investing in energy communities and especially renewable energy cooperatives 
in countries like Spain, Croatia, France, and Greece. However, complexities of varying legal frameworks 
and lack of effective support mechanisms have prevented those countries from keeping up with the more 
developed  energy  community  countries  of  the  North,  such  as  the  Netherlands,  Sweden,  Denmark, 
Germany and Belgium (EC, 2015c). 

The CEP measures for Citizens Energy Communities (CECs) 
The e-Directive defines a ‘citizens energy community67, that replaced the term ‘local energy community’ 
in the Commission e-Directive, based on three dimensions; membership, primary purpose, and activities. 
Art 2(11) states that a CEC means ‘a legal entity that:  

67 A differentiation should be made between citizen energy communities and renewable energy communities introduced by art 
22 of the Renewable Energy Directive.  

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(a) is based on voluntary and open participation and is effectively controlled by members or shareholders 
that are natural persons, local authorities, including municipalities, or small enterprises;  
(b) has  for  its  primary purpose  to provide environmental, economic or  social community benefits  to its 
members or shareholders or to the local areas where it operates rather than to generate financial profits; 
and  
(c)  may  engage  in  generation,  including  from  renewable  sources,  distribution,  supply,  consumption, 
aggregation, energy storage, energy efficiency services or charging services for electric vehicles or provide 
other energy services to its members or shareholders.’  
Furthermore, CECs, according to recitals 43 to 47 of the e-Directive,  must be considered as a category of 
cooperation between citizens or local actors’ and should be ‘subject to recognition and protection under 
the Union law.’ Besides, CECs ‘should not face regulatory restrictions if they apply existing or future ICT 
technologies to share electricity.’ Also, the electricity sharing process ‘should not affect the collection of 
network charges, tariffs and levies related to electricity flows.’ 
The  CEP  recognises  CECs  as  a critical  enabler  for  encouraging  the  involvement of the  individual  in  the 
development  of  the  electricity  sector  and  requires  MSs  to  ensure  implementation  of  enabling  legal 
frameworks and to guarantee the right to energy sharing. The provisions on CECs in the e-Directive ‘do 
not preclude the existence of other citizen initiatives such as those stemming from private law agreements.’ 
Thus,  MSs  can  provide  that  CECs  can  take  any  form  of  entity,  ‘for  example  that  of  an  association,  a 
cooperative, a partnership, a non-profit organisation or a small or medium-sized enterprise, provided that 
the entity is entitled to exercise rights and be subject to obligations in its own name.’  
CECs  membership  shall  be  open  to  all  categories  of  entities  with  a  restriction  in  the  members  and 
stakeholders with decision making powers to the ones ‘that are not engaged in large-scale commercial 
activity and for which the energy sector does not constitute a primary area of economic activity.’ 
MSs shall adopt a legal framework for the establishment of CECs. Art 16 of the e-Directive introduces a 
catalogue of applicable rights and obligations for CECs. Due to their type and status as new entrants in the 
electricity markets, they should cooperate in the market on a level-playing field without creating market 
distortions. It sets mandatory provisions for MSs regarding CECs membership as well as CECs participation 
in  electricity  markets.  It  also  sets  optional  provisions  that  MSs  can  adopt  regarding  CECs  cross-border 
participation as well as CECs ownership, establishment, purchase or lease of distribution networks. 
Mandatory provisions for CECs enabling regulatory framework 
For the mandatory  provisions,  art 16(1)  states that shall provide  that  the enabling framework ensures 
that: 
‘(a) participation in a citizen energy community is open and voluntary;  
(b) members or shareholders of a citizen energy community are entitled to leave the community, in which 
case Article 12 applies;  
(c)  members  or  shareholders  of  a  citizen  energy  community  do  not  lose  their  rights  and  obligations  as 
household customers or active customers;  
(d)  subject  to  fair  compensation  as  assessed  by  the  regulatory  authority,  relevant  distribution  system 
operators cooperate with citizen energy communities to facilitate electricity transfers within citizen energy 
communities;  
(e)  citizen  energy  communities  are  subject  to  non-discriminatory,  fair,  proportionate  and  transparent 
procedures  and  charges,  including  with  respect  to  registration  and  licensing,  and  to  transparent,  non-
discriminatory  and  cost-reflective  network  charges  in  accordance  with  Article  18  of  Regulation  (EU) 
2019/943, ensuring that they contribute in an adequate and balanced way to the overall cost sharing of 
the system.’ 

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In addition, regarding electricity market access, balance responsibilities, self-consumption, art 16(3) brings 
further mandatory provisions for CECs aiming to ensure that they contribute in an adequate and balanced 
way to the overall cost sharing of the system and to be on equal footing with other market participants; 

‘(a) are able to access all electricity markets, either directly or through aggregation, in a non-discriminatory 
manner;  
(b) are treated in a non-discriminatory and proportionate manner with regard to their activities, rights and 
obligations as final customers, producers, suppliers, distribution system operators or market participants 
engaged in aggregation;  
(c) are financially responsible for the imbalances they cause in the electricity system; to that extent they 
shall  be  balance  responsible  parties  or  shall  delegate  their  balancing  responsibility  in  accordance  with 
Article 5 of Regulation (EU) 2019/943;  
(d) with regard to consumption of self-generated electricity, citizen energy communities are treated like 
active customers in accordance with point (e) of Article 15(2);  
(e) are entitled to arrange within the citizen energy community the sharing of electricity that is produced 
by the production units owned by the community, subject to other requirements laid down in this Article 
and subject to the community members retaining their rights and obligations as final customers. 
For the purposes of point (e) of the first subparagraph, where electricity is shared, this shall be without 
prejudice to applicable network charges, tariffs and levies, in accordance with a transparent cost-benefit 
analysis of distributed energy resources developed by the competent national authority.’ 

Optional provisions for CECs enabling regulatory framework 
Apart from the mandatory elements to be included in the CECs’ regulatory framework, MSs may decide 
to  provide  CECs  with  three  additional  rights  in  their  national  regulations.  Indeed  art  16(2)  states  that 
‘Member States may provide in the enabling regulatory framework that citizen energy communities:  

(a) are open to cross-border participation; 

(b) are entitled to own, establish, purchase or lease distribution networks and to autonomously manage 
them subject to conditions set out in paragraph 4 of this Article; 

 (c) are subject to the exemptions provided for in Article 38(2).’ 

For MSs that allow CECs to network ownership and management, following art 16(2)(b),  art 16(4) sets out 
specific conditions for CECs on aspects of distribution system operation without prejudice to the other 
provisions and rules applying to distribution system operation68. Indeed, art 16(4) states that where MSs 
provide the network ownership and management rights, they shall ensure that CECs: 

‘(a) are entitled to conclude an agreement on the operation of their network with the relevant distribution 
system operator or transmission system operator to which their network is connected;  
(b) are subject to appropriate network charges at the connection points between their network and the 
distribution  network  outside  the  citizen  energy  community  and  that  such  network  charges  account 
separately  for  the  electricity  fed  into  the  distribution  network  and  the  electricity  consumed  from  the 
distribution network outside the citizen energy community in accordance with Article 59(7);  
(c) do not discriminate or harm customers who remain connected to the distribution system.’ 

68 This refers to the articles of Chapter IV of the e-Directive on designation, tasks and rules for DSOs as well as other rules and 
regulations applying to them. 

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Also, where MSs decide to allow CECs to become closed distribution system operators69 in accordance 
with art 38, it may provide  for  NRAs to exempt the operator of a closed distribution system from  (art 
38(2)): 
‘(a) the requirement under Article 31(5) and (7) to procure the energy it uses to cover energy losses and 
the non-frequency ancillary services in its system in accordance with transparent, non-discriminatory and 
market-based procedures;  
(b) the requirement under Article 6(1) that tariffs, or the methodologies underlying their calculation, are 
approved in accordance with Article 59(1) prior to their entry into force; 
 (c) the requirements under Article 32(1) to procure flexibility services and under Article 32(3) to develop 
the operator's system on the basis of network development plans;  
(d)  the  requirement  under  Article  33(2)  not  to  own, develop,  manage  or  operate  recharging  points  for 
electric  vehicles;  and  (e)  the  requirement  under  Article  36(1)  not  to  own,  develop,  manage  or  operate 
energy storage facilities.’ 
Art 38(3) adds that in case of an exemption grant, ‘the applicable tariffs, or the methodologies underlying 
their calculation, shall be reviewed and approved in accordance with Article 59(1) upon request by a user 
of the closed distribution system.’ 

Highlights 
-  Citizens  energy  communities  (CECs)  constitute  a  new  type  of  entity  having  access  to  electricity 
markets. 
- A catalogue of applicable rights and obligations for CEC is introduced by art 16. 
- CEC membership is open to all categories of entities.  The decision-making powers within a CEC should 
be limited to those members or shareholders that are not engaged in large scale commercial activity 
and for which the energy sector does not constitute a primary area of economic activity. 
- CECs should be subject to appropriate network charges for the electricity consumed from an external 
network. 
-  DSOs,  subject  to  a  fair  compensation,  shall  cooperate  with  CECs  to  facilitate  electricity  transfers 
between them. 
- MSs are free to decide upon cross-border participation as well as for the right of CEC to own, manage, 
establish, purchase or lease the distribution network in their area of operation. 
- MSs may choose whether to establish a framework allowing CECs to have the role of a DSO either 
under the general regime or as ‘Closed Distribution System Operator’.  

69 A ‘closed distribution system’ according to art 2(5) of the Demand Connection Code (DCC) means ‘a distribution system 
classified pursuant to Article 28 of Directive 2009/72/EC as a closed distribution system by national regulatory authorities or by 
other competent authorities, where so provided by the Member State, which distributes electricity within a geographically 
confined industrial, commercial or shared services site and does not supply household customers, without prejudice to incidental 
use by a small number of households located within the area served by the system and with employment or similar associations 
with the owner of the system’ 

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doi:10.2870/33236
ISBN:978-92-9084-794-6