ISSN 1831-9424

Local Electricity Flexibility Markets in

Europe
Chondrogiannis, S., Vasiljevska, J., Marinopoulos, A., Papaioannou, I., Flego, G.

2022

EUR 31194 EN
This publication is a Technical report by the Joint Research Centre (JRC), the European Commission’s science and knowledge service. It aims
to provide evidence-based scientific support to the European policymaking process. The contents of this publication do not necessarily
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on the part of the European Union concerning the legal status of any country, territory, city or area or of its authorities, or concerning the
delimitation of its frontiers or boundaries.

Contact information
Name: Stamatios Chondrogiannis
Address: JRC – Via E. Fermi 2749 – I – 21027 ISPRA (VA) – Italy
Email: stamatios.chondrogiannis@ec.europa.eu
Tel. +39 0332 785324

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JRC130070

EUR 31194 EN

PDF ISBN 978-92-76-56156-9 ISSN 1831-9424 doi:10.2760/9977 KJ-NA-31-194-EN-N

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How to cite this report: Chondrogiannis, S., Vasiljevska, J., Marinopoulos, A., Papaioannou, I. and Flego, G., Local Electricity Flexibility Markets
in Europe, Publications Office of the European Union, Luxembourg, 2022, doi:10.2760/9977, JRC130070.
Contents
Acknowledgements...........................................................................................................................................................................................................................................1
Abstract........................................................................................................................................................................................................................................................................2
1. Introduction .....................................................................................................................................................................................................................................................3
1.1. Scope of this report ...................................................................................................................................................................................................................5
2. Methodology ..................................................................................................................................................................................................................................................7
2.1. Pre-qualification procedures.............................................................................................................................................................................................7
2.2. Design of flexibility products............................................................................................................................................................................................7
2.3. Market architecture ...................................................................................................................................................................................................................8
2.4. Activation and settlement procedures ....................................................................................................................................................................8
2.5. Results and lessons learnt ..................................................................................................................................................................................................9
3. Review of the regulatory framework on flexibility ............................................................................................................................................... 10
3.1. Distribution system operator revenue models ............................................................................................................................................ 10
3.1.1. France ............................................................................................................................................................................................................................... 12
3.1.2. Germany......................................................................................................................................................................................................................... 12
3.1.3. Netherlands................................................................................................................................................................................................................. 13
3.1.4. Norway ............................................................................................................................................................................................................................ 13
3.1.5. Sweden ............................................................................................................................................................................................................................ 14
3.1.6. United Kingdom....................................................................................................................................................................................................... 14
3.2. Solutions to flexibility procurement ....................................................................................................................................................................... 15
3.2.1. Network tariffs and connection agreements .............................................................................................................................. 16
3.2.2. Rule-based approach to access distributed flexibility ....................................................................................................... 17
3.2.3. Market-based procurement of distributed flexibility .......................................................................................................... 18
3.3. Participation of independent aggregators ....................................................................................................................................................... 20
3.3.1. Regulatory framework for demand-side participation ...................................................................................................... 20
3.3.2. Aggregator models adopted in the selected European countries ........................................................................... 21
3.3.2.1. Independent aggregator implementation models.................................................................................................... 22
3.3.2.2. Non-independent aggregator implementation models ....................................................................................... 23
3.3.2.3. Implementation of aggregator models in the European countries examined .............................. 23
3.3.3. Balance responsibility ....................................................................................................................................................................................... 25
3.3.4. Compensation mechanisms ........................................................................................................................................................................ 26
4. Presentation of flexibility markets in Europe ............................................................................................................................................................. 29
4.1. NODES market platform ................................................................................................................................................................................................... 29
4.1.1. General information............................................................................................................................................................................................ 29
4.1.2. Pre-qualification procedures ...................................................................................................................................................................... 29
4.1.3. Flexibility products ............................................................................................................................................................................................... 29
4.1.4. Market architecture ............................................................................................................................................................................................. 30
4.1.5. Activation and settlement procedures .............................................................................................................................................. 30
4.1.6. Lessons learnt and future developments ...................................................................................................................................... 31

i
4.2. sthlmflex project ...................................................................................................................................................................................................................... 32
4.2.1. General information............................................................................................................................................................................................ 32
4.2.2. Pre-qualification procedures ...................................................................................................................................................................... 32
4.2.3. Flexibility products ............................................................................................................................................................................................... 33
4.2.4. Market architecture ............................................................................................................................................................................................. 33
4.2.5. Activation and settlement procedures .............................................................................................................................................. 34
4.2.6. Results, lessons learnt and future developments .................................................................................................................. 35
4.3. IntraFlex project ........................................................................................................................................................................................................................ 37
4.3.1. General Information ........................................................................................................................................................................................... 37
4.3.2. Pre-qualification procedures ...................................................................................................................................................................... 37
4.3.3. Flexibility products ............................................................................................................................................................................................... 38
4.3.4. Market architecture ............................................................................................................................................................................................. 38
4.3.5. Activation and settlement procedures .............................................................................................................................................. 38
4.3.6. Results and lessons learnt............................................................................................................................................................................ 39
4.4. NorFlex project ........................................................................................................................................................................................................................... 39
4.4.1. General Information ........................................................................................................................................................................................... 39
4.4.2. Pre-qualification procedures ...................................................................................................................................................................... 40
4.4.3. Flexibility products ............................................................................................................................................................................................... 40
4.4.4. Market architecture ............................................................................................................................................................................................. 40
4.4.5. Activation and settlement procedures .............................................................................................................................................. 41
4.4.6. Results, lessons learnt and future developments .................................................................................................................. 41
4.5. GOPACS ............................................................................................................................................................................................................................................. 43
4.5.1. General information............................................................................................................................................................................................ 43
4.5.2. Pre-qualification procedures ...................................................................................................................................................................... 44
4.5.3. Flexibility products ............................................................................................................................................................................................... 44
4.5.4. Market architecture ............................................................................................................................................................................................. 44
4.5.5. Activation and settlement procedures .............................................................................................................................................. 46
4.5.6. Results and lessons learnt............................................................................................................................................................................ 46
4.6. enera Flexmarkt ........................................................................................................................................................................................................................ 47
4.6.1. General information............................................................................................................................................................................................ 47
4.6.2. Pre-qualification procedures ...................................................................................................................................................................... 48
4.6.3. Flexibility products ............................................................................................................................................................................................... 48
4.6.4. Market architecture ............................................................................................................................................................................................. 48
4.6.5. Activation and settlement procedures .............................................................................................................................................. 49
4.6.6. Results and future developments ......................................................................................................................................................... 49
4.7. UK flexibility tenders ............................................................................................................................................................................................................ 51
4.7.1. General information............................................................................................................................................................................................ 51
4.7.2. Pre-qualification procedures ...................................................................................................................................................................... 51
4.7.3. Flexibility products ............................................................................................................................................................................................... 52

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 4.7.4. Flexibility procurement process ............................................................................................................................................................... 54
4.7.4.1. Coordination between network operators ........................................................................................................................ 55
4.7.5. Activation and settlement procedures .............................................................................................................................................. 55
4.7.6. Results, lessons learnt and future developments .................................................................................................................. 56
4.8. ENEDIS flexibility tenders ................................................................................................................................................................................................ 57
4.8.1. General information............................................................................................................................................................................................ 57
4.8.2. Pre-qualification procedures ...................................................................................................................................................................... 57
4.8.3. Flexibility products ............................................................................................................................................................................................... 58
4.8.4. Procurement of flexibility .............................................................................................................................................................................. 58
4.8.5. Activation and settlement procedures .............................................................................................................................................. 59
4.8.6. Results, lessons learnt and future developments .................................................................................................................. 59
5. Synthesis of reviewed local flexibility markets ........................................................................................................................................................ 61
5.1. Pre-qualification procedures......................................................................................................................................................................................... 61
5.2. Flexibility product design.................................................................................................................................................................................................. 64
5.3. Market design.............................................................................................................................................................................................................................. 67
5.4. Activation and settlement procedures ................................................................................................................................................................ 70
6. Critical notes on the evolution of local flexibility markets in Europe ................................................................................................. 73
6.1. State of evolution of local flexibility markets in Europe ................................................................................................................... 73
6.1.1. Shift towards short-term local flexibility markets ................................................................................................................ 74
6.2. Level of integration of local flexibility markets with wholesale markets ......................................................................... 74
6.2.1. State of integrated security analyses among different network operators ................................................. 74
6.2.2. Emergence of transmission/distribution system operator competition for flexibility services .. 75
6.2.3. Barriers to flexibility service provider value stacking ......................................................................................................... 75
6.3. Role of the regulatory framework in the development of local flexibility markets ................................................ 76
7. Conclusions ................................................................................................................................................................................................................................................. 77
7.1. Future work ................................................................................................................................................................................................................................... 78
References ............................................................................................................................................................................................................................................................ 80
List of abbreviations ................................................................................................................................................................................................................................... 84
List of figures..................................................................................................................................................................................................................................................... 86
List of tables ....................................................................................................................................................................................................................................................... 87
Annexes.................................................................................................................................................................................................................................................................... 88
Annex 1. Survey on Flexibility Marketplaces in Europe .............................................................................................................................................. 88

iii
Acknowledgements
The authors would like to thank Ms Eng and Mr Stølsbotn from NODES, Ms Ersson and Ms Schumacher from
Svenska kraftnät, Mr Johansson from Ellevio, Ms Ruwaida from Vatenfall, Mr Fowler from Western Power
Distribution, Mr Pedersen from Agder Energi, Mr D. Stufkens currently working at BritNed (in his capacity as an
expert on the Grid Operators Platform for Congestion Solutions (GOPACS); he previously worked at TenneT), Mr
Gertje from EWE NETZ GmbH, Mr Dupin and Mr Kuhn from ENEDIS, Mr Anagnostopoulos from Piclo Flex, and
Mr Aithal from the Energy Networks Association (ENA) for their time during the structured interviews that took
place in the context of this work.

Authors
Stamatios Chondrogiannis
Julija Vasiljevska
Antonios Marinopoulos
Ioulia Papaioannou
Gianluca Flego

1
Abstract
This report reviews some of the main projects on developing flexibility markets in Europe. The analysis focuses
on cases aiming primarily to improve the provision of local flexibility services to Distribution System Operators
(DSOs) through market-based instruments, and it considers the role of regulation in promoting the use of
flexibility. Specifically, the following projects/markets are reviewed (the countries in which they have been
developed are in parentheses):
— sthlmflex (Sweden),
— IntraFlex (United Kingdom),
— NorFlex (Norway),
— the Grid Operators Platform for Congestion Solutions (GOPACS) (the Netherlands),
— enera Flexmarkt (Germany),
— GB flexibility tenders by DSOs (United Kingdom),
— ENEDIS flexibility tenders (France).
The following aspects are examined in more detail: pre-qualification procedures, the specification of flexibility
products, the trading mechanism, and activation and settlement. Whenever possible, information on traded
volumes and prices has been gathered. Common characteristics of and differences between the local flexibility
markets reviewed are discussed, while current trends and challenges for the future are identified.
The main finding of this analysis is that flexibility procurement for distribution network operation and planning
is under development at various degrees of maturity among European countries, with a variety of methods
employed. The regulatory framework for DSOs’ revenues and the specific national situation of the distribution
network both play significant roles in the level of flexibility procurement and in the preferred method(s). Market-
based procurement of flexibility services by DSOs is still a niche practice in most countries. From the cases
reviewed in this report, three countries (France, the Netherlands and the United Kingdom) take a business-as-
usual approach to market-based procurement, two (Norway and Sweden) have developed pilot projects and, in
Germany, a rule-based approach was, in the end, chosen as the main option. Nevertheless, even among those
countries where market-based procurement can be considered to have reached a business-as-usual stage,
there are significant discrepancies in terms of volumes procured and level of market maturity. Distribution
network operators in the United Kingdom systematically procure local flexibility services and in increasing
volumes each year, backed by a supportive regulatory mandate. In the Netherlands, GOPACS is a well-
established mechanism, and the recent collaboration with EPEX SPOT is expected to further increase the
liquidity in the market for flexibility services provided by assets in the distribution system. On the other hand,
the flexibility tenders in France have produced rather disappointing results so far, owing to, among other things,
more attractive business alternatives for flexibility service providers (e.g. participation in the capacity
remuneration mechanism), the design of the tenders (specific, non-divisible products) and the price caps
imposed by the major DSO in France (ENEDIS).

2
1. Introduction
The decarbonisation of the energy system will bring a significant, perhaps even pervasive, electrification of
end-uses in all consumer categories and in a number of sectors, such as in heating and cooling and in transport.
In conjunction, the proliferation of variable renewable energy sources (RESs) – the main technological option
for decarbonising the energy system – is already exerting stress on transmission and distribution networks.
Considerable investments in network infrastructure are expected to be required in the next decades to
accommodate these trends (see, for example, (Deloitte, et al., 2021; ENTSO-E, 2021).
On the other hand, the diffusion of distributed energy resources (DERs), digitalisation, and policy and regulatory
impetus set active customers ( 1) at the centre of the energy transition, which offers significant opportunities
for ‘smarter’ planning and operation of power systems.
The role and value of demand-side flexibility in enabling cost-efficient grid utilisation while enabling large-
scale integration of renewable energy into the system has been recognised and included in a set of policy
documents as part of the third energy package ( 2) adopted in 2009. More specifically, the electricity directive
(Directive 2009/72/EC) ( 3) uses the term ‘demand-side management’, mainly in the context of security of
supply. In 2015, the role and value of demand-side flexibility was further strengthened within the energy union
package ( 4) and in the Commission communication on a new deal for energy consumers (European Commission,
2015), which places citizens at the core of the EU energy strategy and empowers them to actively participate
in the energy market. The clean energy for all Europeans package ( 5), which was proposed in 2016 and entered
into force in 2019, consists of a set of legal acts among which is the renewable energy directive (Directive (EU)
2018/2001) ( 6), in which paragraph 24 calls for ‘additional investments in various sources of flexibility (e.g.
demand response and flexible generation) to allow for cost-effective integration of additional renewable
energy capacity’. Furthermore, the energy efficiency directive (Directive (EU) 2018/2002) ( 7), paragraph 2,
endorses the view that ‘energy efficiency and demand-side response can compete on equal terms with
generation capacity’.
Article 3 of the electricity regulation (Regulation (EU) 2019/943) ( 8) demands adoption of market rules that will
‘facilitate the development of more flexible generation, sustainable low carbon generation, and more flexible
demand’ and calls for incentives for distribution system operators (DSOs), ‘for the most cost-efficient operation
and development of their networks including through the procurement of flexibility services’. Article 53 of the
regulation goes even further by establishing a new entity, the EU DSO, with one of its tasks (defined in
Article 55) to ‘facilitate demand-side flexibility and response and distribution grid users’ access to markets’. In
parallel, the electricity market directive (Directive (EU) 2019/944) ( 9) promotes active participation of
consumers – individually or collectively via energy community schemes – in all energy markets. More
specifically, and as regards the context of this study, Article 32 of the electricity market directive highlights the
importance of the development of an adequate 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’.
In the meantime, and even before some of these policy documents came into force, the Council of European
Energy Regulators (CEER) alluded to the value of deploying and using flexibility at both transmission and
distribution grid levels (CEER 2016, 2018). The most recent publication in this regard focuses on the DSO
procedures for the procurement of flexibility (CEER, 2020a). On a similar note, in 2019, five European

(1) According to the electricity directive (Directive 2009/72/EC), ‘“active customer” means 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.’
(2) https://energy.ec.europa.eu/topics/markets-and-consumers/market-legislation/third-energy-package_en
(3) Directive 2009/72/EC of the European Parliament and of the Council of 13 July 2009 concerning common rules for the internal
market in electricity and repealing Directive 2003/54/EC.
(4) https://energy.ec.europa.eu/topics/energy-strategy/energy-union_en
(5) https://energy.ec.europa.eu/topics/energy-strategy/clean-energy-all-europeans-package_en
(6) Directive (EU) 2018/ 2001 of the European Parliament and of the Council of 11 December 2018 on the promotion of the use of
energy from renewable sources.
(7) Directive (EU) 2018/2002 of the European Parliament and of the Council of 11 December 2018 amending Directive 2012/27/EU on
energy efficiency.
(8) Regulation (EU) 2019/943 of the European Parliament and of the Council of 5 June 2019 on the internal market for electricity
(recast).
(9) Directive (EU) 2019/944 of the European Parliament and of the Council of 5 June 2019 on common rules for the internal market
for electricity and amending Directive 2012/27/EU (recast).

3
organisations (European Distribution System Operators (E.DSO), the European Federation of Local and Regional
Energy Companies (CEDEC), the European Association for the Cooperation of Transmission System Operators
for Electricity (ENTSO-E), Eurelectric and GEODE) joined forces and published their views in a transmission
system operator (TSO) / DSO data management report focusing on TSO/DSO coordination in congestion
management and balancing using flexibility (CEDEC et al., 2019).
In December 2019, the European Commission adopted the European Green Deal ( 10) – an ambitious plan in
which decarbonisation of the energy sector plays a key role and citizens are at its heart. As part of this plan,
the EU strategy for energy system integration ( 11) was adopted in 2020, which promotes better integration
across multiple energy carriers to ‘unlock additional flexibility for the overall management of the energy system
and thus help to integrate increased shares of variable renewable energy production’.
Large-scale deployment of demand-side flexibility necessitates digital infrastructure to allow secure and
reliable data access and exchange between different market players. In 2020, the EU adopted a policy
document on shaping Europe’s digital future ( 12) as part of the EU digital strategy, which highlights the
importance of the twin challenge of the green and digital transitions to support the implementation of the EU
Green Deal. The most recent Fit for 55 package ( 13) embraces the revision of Europe’s climate, energy and
transport-related legislation that was undertaken to align current laws with the 2030 and 2050 ambitions. As
part of this package, and for Europe to be able to deliver the EU Green Deal, revisions have been proposed for
both the renewable energy directive and the energy efficiency directive to align them with the EU’s increased
climate ambition. The proposal for a revised renewable energy directive (European Commission, 2021a) ( 14)
reiterates the importance of having national regulatory frameworks that:
do not discriminate against participation in the electricity markets, including congestion management
and the provision of flexibility and balancing services, of small or mobile systems such as domestic
batteries and electric vehicles, both directly and through aggregation.
Similarly, the proposal for a revised energy efficiency directive (European Commission, 2021b) strengthens the
value of demand-side flexibility in view of the energy efficiency first principle ( 15) and calls on Member States
to:
take into account potential benefits from demand-side flexibility in applying the energy efficiency first
principle and where relevant consider demand response, energy storage and smart solutions as part of
their efforts to increase efficiency of the integrated energy system.
The European Commission’s recent plan REPowerEU ( 16) takes a stance on the recent geopolitical and energy
market developments and calls on EU Member States to accelerate the clean energy transition and increase
Europe’s energy independence. Supported by a set of financial and legal measures, REPowerEU commits to
massively scaling up the deployment of RES and to accelerating the electrification of the end-use sector – both
of which will produce significant opportunities for distributed flexibility in the future.
Figure 1 summarises the EU energy policy documents relevant to flexibility. It is noted that, while all of these
policy documents envisage and contribute to the development of flexibility in the power (and, in more general
terms, the energy) system, they do not provide specific provisions for the architecture of local flexibility
markets.

(10) https://ec.europa.eu/clima/eu-action/european-green-deal_en
(11) Error! Hyperlink reference not valid.https://energy.ec.europa.eu/topics/energy-systems-integration/eu-strategy-energy-system-
integration_en
(12) Error! Hyperlink reference not valid.https://ec.europa.eu/info/strategy/priorities-2019-2024/europe-fit-digital-age/shaping-
europe-digital-future_en
(13) https://www.consilium.europa.eu/en/policies/green-deal/fit-for-55-the-eu-plan-for-a-green-transition/
(14) EUR-Lex – 52021PC0557 – EN – EUR-Lex (europa.eu)
(15) The “energy efficiency first principle” means taking utmost account of cost-efficient energy efficiency measures in shaping energy
policy and making relevant investment decisions.
(16) https://ec.europa.eu/info/strategy/priorities-2019-2024/european-green-deal/repowereu-affordable-secure-and-sustainable-
energy-europe_en

4
 Figure 1: Energy policy documents with reference and relevance to flexibility

Source: JRC analysis.

1.1. Scope of this report

This report examines the emerging market-based flexibility procurement initiatives by DSOs, given that
Article 32 of the EU electricity market directive defines market-based procedures as the default option for
procurement of such services by DSOs, except in cases in which national regulatory authorities establish that
this procurement method would not be effective or efficient or would be severely market distortive ( 17).
In this report, the term ‘local flexibility markets’ refers to all types of market-based procurement of flexibility
services by DSOs, irrespective of their architecture (e.g. spot markets close to real time as opposed to long-
term tenders) and operational status (e.g. business as usual as opposed to pilot projects). In all of the markets
reviewed, the DSO(s) is (are among) the buyer(s) of flexibility services, but other players (e.g. the TSO or balance
responsible parties (BRPs)) may or may not, depending on the case, also procure flexibility services. The types
of possible flexibility services and buyers are summarised in Table 1.

Table 1: Possible flexibility services procured by different actors in the local flexibility markets reviewed

Type of flexibility Buyer of flexibility

services

DSO TSO BRPs

Congestion management (distribution system) X

Voltage control (distribution system) X

Reliability enhancement (distribution system) X

Network deferral (distribution system) X

Frequency control (balancing) X

Congestion management (transmission system) X

Portfolio optimisation X
Source: JRC analysis.
First, the report investigates the role of regulation in promoting the use of flexibility, particularly at distribution
network level, in six European countries where local flexibility markets have been developed. This investigation

(17) Section 3.2 provides a detailed overview of the different possible procurement methods of flexibility services by DSOs (rules-based
procurement, flexible connection agreements, tariff structures and market-based procurement).

5
includes the DSO revenue model to better understand the incentives provided to the DSO for more cost-efficient
operation and planning of the distribution grid, the role of independent aggregators and the financial
responsibility associated with independent aggregators on balancing and on tranfer of energy (ToE).
Given that very few local flexibility markets currently have a business-as-usual status, pilot projects are also
examined. More specifically, the following initiatives are reviewed in detail:
— the NODES market platform and its applications in the local flexibility market projects of NorFlex (Norway),
sthlmflex (Sweden) and IntraFlex (the United Kingdom);
— the Grid Operators Platform for Congestion Solutions (GOPACS) (the Netherlands);
— the enera Flexmarkt (Germany);
— the UK flexibility tenders;
— the ENEDIS flexibility tenders (France).
The cases analysed were chosen based on a combination of the level of maturity, the public information
available, size, results and the insights provided. Further work is required to look into new initiatives from all
over Europe, and particularly initiatives developed in the context of some ongoing major Horizon projects on
the topic (we are referring here to CoordiNet ( 18), Platone ( 19), OneNet ( 20) and Interrface ( 21)). When future
trends are discussed in this report, insights from these projects have also been considered, subject to their level
of progress.
For the analysis of the aforementioned initiatives, extensive desktop research was undertaken, complemented
by a survey and structured interviews with relevant stakeholders (i.e. market platform and network operators).
Following this, the aforementioned projects were summarised focusing on pre-qualification procedures, the
design of flexibility products, the trading of flexibility (the architecture of market-based procurement), and
activation and settlement procedures. Based on this assessment, common themes and major differences were
identified and are discussed in this report. In addition, key issues for the shaping of local flexibility markets in
the future are discussed.
The structure of the report is as follows. In Chapter 2, more details on the methodology are provided. Chapter 3
presents deployment provisions that are relevant to flexibility in the national regulatory frameworks of the
countries examined. Chapter 4 presents in detail the local flexibility markets examined. Chapter 5 provides a
synthesis analysis of the local flexibility markets examined. Chapter 6 discusses critical issues in the
development of local flexibility markets in Europe. Finally, Chapter 7 sets out the conclusions of the overall
analysis.

(18) https://coordinet-project.eu/
(19) https://www.platone-h2020.eu/
(20) https://onenet-project.eu/
(21) http://www.interrface.eu/

6
2. Methodology
We first investigated the role of regulation in promoting the use of flexibility by performing extensive desktop
research to better understand the DSO revenue models in the countries selected for our analysis, as well as
the role of independent aggregators, including their balance and financial responsibility.
Furthermore, we examined real-life examples of local flexibility markets/projects in Europe in the same six
European countries by complementing the in-depth desktop research with a survey and structured interviews
with relevant stakeholders.
Overall, feedback from the following entities was received (the relevant local flexibility markets are indicated
in parentheses):
— NODES (NODES market platform)
— Svenska kraftnät (sthlmflex)
— Ellevio (sthlmflex)
— Vattenfall Eldistribution (sthlmflex)
— Western Power Distribution (IntraFlex)
— Agder Energi (NorFlex)
— EWE NETZ GmbH (enera Flexmarkt)
— EPEX SPOT (enera Flexmarkt)
— ENEDIS (ENEDIS flexibility tenders)
— Piclo Flex (UK flexibility tenders)
— Energy Networks Association (ENA) power networks (UK flexibility tenders).
In addition, feedback on GOPACS was received from an expert previously working at TenneT.
The main survey targeted all flexibility markets in general, with certain, more specialised, markets specific to
each project also targeted. The questions of the former can be found in Annex 1.
The analysis of the local flexibility markets was undertaken according to the following dimensions:
— pre-qualification procedures;
— the design of flexibility products;
— the trading of flexibility (procurement architecture);
— activation and settlement procedures;
— results and lessons learnt.
It is noted that a similar approach was also followed in other work on the subject (see Frontier Economics and
ENTSO-E, 2021). The remainder of this chapter sets out a more detailed presentation of the key questions
investigated for each of the aforementioned dimensions.

2.1. Pre-qualification procedures

The pre-qualification procedures imposed on flexibility assets and service providers were investigated with the
purpose of assessing the level of complexity and any potential barriers to their participation in the local
flexibility market. The investigation was divided into technical aspects (e.g. pre-qualification tests and other
processes) and compliance with the necessary regulatory, legal and/or financial requirements.

2.2. Design of flexibility products

The technical specifications of the traded flexibility products were investigated with the final aim of assessing
the level of convergence among the different markets. Particular aspects that were examined included:
— the flexibility service that the products targeted – flexibility services include network deferral, congestion
management, enhancement of network resilience and reactive power/voltage control;

7
— whether the flexibility products had only an activation component or also had an availability component;
— the direction of the traded flexibility (upwards, downwards or both ( 22));
— the procurement horizon and the activation period of each flexibility product;
— the minimum bid size and whether or not bids were divisible;
— other technical specifications associated with the design of each flexibility product, such as notice period,
time to full activation, ramping limits and/or recovery rules;
— whether price is freely formed or predefined by the buyer network operator, and whether or not price caps
exist.

2.3. Market architecture

The subject of this particular dimension is how, and between which parties, flexibility is traded. Particular
aspects that were examined included:
— the involved parties – although the focus is on local flexibility markets for the provision of services to
DSOs, the market platform can be used for the provision of services also to TSOs; in this case, of particular
interest was the relevant priority rules between the different network operators;
— the operational security coordination mechanisms (if any) between different network operators for
avoiding the activation of flexibility causing security violations to parts of the network outside the
responsibility of the buying network operator;
— coordination (if any) with the wholesale energy market – flexibility service providers (FSPs) may also trade
their flexibility to market parties (i.e. to BRPs) and so we consider the coordination of flexibility provided to
network operators, with a particular interest in the mechanisms and responsibilities for avoiding double
counting of the same flexibility activation;
— the temporal form of trading and, in particular, differentiation between long-term and short-term trading;
— the time span between the point when the buyer network operator declares the requested volumes of
flexibility and the time of flexibility activation, as well as the gate closure time (GCT) for FSPs declaring
their offers;
— the market time unit (MTU) ( 23);
— the spatial organisation of trading, as well as differentiation between portfolio bidding and separate
flexibility asset bidding (unit bidding);
— whether spot trading takes place (auctions) or different forms of continuous trading are followed;
— the clearing mechanism and, in particular, whether only price or also other criteria are employed for the
evaluation of flexibility offers;
— the price formation mechanism (pay-as-clear, pay-as-bid or predetermined price set by the buyer network
operator);
— access to information by FSPs regarding the existence of price caps.

2.4. Activation and settlement procedures

On this subject, we first reviewed the communication means for the activation of flexibility services. The
assessment of the settlement procedures included the following topics:
— the measurement period and the settlement period;
— the type of measurements employed for the settlement (i.e. whether measurements from the connection
meter only were allowed or measurements from the flexibility assets’ sub-meters were also permitted for
the settlement);

(22) Upwards flexibility is the reduction of consumption or an increase in generation against a baseline, while downwards flexibility is
the opposite (i.e. an increase in consumption or a decrease in generation against a baseline).
(23) The MTU is the period for which the flexibility product price is established.

8
— the employed baseline against which the settlement took place, with the main differentiation being
between self-declared baselines by the FSPs and a centrally defined baseline by the market operator or
the buying network operators;
— remuneration rules under partial delivery of flexibility, including whether penalties were imposed or not;
— the contractual relationships between FSPs and respective BRPs when the two entities were different (i.e.
in the case of independent aggregators ( 24)) – two issues were investigated here in more detail: first, which
market party undertakes balance responsibility and, second, whether the FSP compensates the supplier for
the energy pre-bought by the latter in the wholesale market ( 25).

2.5. Results and lessons learnt

The results gained thus far from the flexibility markets studied have been collated, including the flexibility
volumes activated and prices. The major lessons learnt were analysed and, during the structured interviews,
the projects’ stakeholders were asked about their general views regarding the evolution of flexibility markets
in Europe, along with their future plans.

(24) According to the electricity market directive, an ‘independent aggregator’ is a market participant engaged in aggregation who is not
affiliated to the customer’s supplier.
(25) A comprehensive presentation of the issues pertaining to the contractual relationships between independent aggregators and BRPs
can be found in Schittekatte et al. (2021).

9
3. Review of the regulatory framework on flexibility
This chapter looks into the role of regulation in promoting the use of flexibility, particularly at distribution
network level, in the six European countries in which the local flexibility markets examined were found: France,
Germany, the Netherlands, Norway, Sweden and the United Kingdom. More specifically, we provide a closer
look into the DSO revenue model to better understand the incentives provided to DSOs for more cost-efficient
operation and planning of the distribution grid. Additionally, we investigate the extent to which the countries
analysed have already deployed or are in the process of deploying distributed flexibility at a larger scale,
including by identifying major barriers to the development of local flexibility markets. In this context, we analyse
and discuss a set of relevant issues, including existing solutions to flexibility procurement, the role of
independent aggregators, and balancing responsibility and compensation mechanisms associated with
independent aggregators.

3.1. Distribution system operator revenue models

This section provides a general overview of the regulatory frameworks for DSOs in the selected EU countries
and, more specifically, discusses the types of regulations adopted, including incentives for more efficient
operation and planning of the distribution grids. The types of regulations that DSOs are subject to may influence
their choice between the use of traditional solutions, such as network reinforcement or flexible solutions
(flexible connections, market-based procurement of flexibility, etc.), or a combination of different types of
solutions. In this context, we want to examine whether or not the adopted regulatory mechanism in each country
incorporates the value of flexibility in the DSO revenue model, or at least does not present a barrier to flexibility
deployment.
Furthermore, this section sheds light on the types of incentives used in each country to promote and facilitate
innovation in the operation and planning of the distribution grids.
The following topics are discussed for each of the countries selected for our analysis:
— the type of regulatory mechanisms in place (rate of return, incentive regulation (revenue/price cap), etc.);
— the main elements for the determination of the DSO’s revenue – the treatment of capital expenditure
(CAPEX) and operational expenditure (OPEX), the duration of the regulatory period, quality (performance-
or output -based) regulation, efficiency benchmarking, etc.;
— innovation incentives – the treatment of research and development (R & D) costs, regulatory sandboxes,
the regulatory impetus for market-based procurement of flexibility, etc.
Table 2 presents an overview of the DSO regulatory mechanisms in the selected countries, including the main
elements used for the calculation of the DSO’s revenues and the type of innovation incentives used for
promoting more cost-efficient operation and planning of the distribution system.
First, we look at the type of regulation each of the countries analysed has implemented as a way of granting
DSOs with an adequate return for maintaining and expanding their infrastructure, while protecting electricity
consumers from high network tariffs. As we can see from Table 2, all of the EU countries analysed have opted
for incentive regulation with revenue/price cap schemes and efficiency benchmarking ( 26). Under such a scheme,
the regulator sets the overall revenue that the DSO can earn (revenue cap) or the price it can charge (price cap)
for the price control (regulatory) period, considering the expected efficient cost during the regulatory period,
based on the network operator’s own costs but also on the performance of other comparable DSOs (yardstick
competition). In this sense, the DSO can either benefit from cost savings or receive reduced revenue allowance
for not reaching the target values. Additionally, only a few outputs, such as quality and reliability of supply,
may account for an increase or decrease of the revenue or price cap, thus incentivising the DSOs to improve
quality of service.
Under revenue (or price) capping schemes, as costs are estimated for each regulatory period (typically a few
years ahead), DSOs may be incentivised to reduce costs as early as possible rather than considering the long-
term effect of the investment. This can limit investments in infrastructure, which normally have a payback time
longer than the regulatory period (Armstrong and Sappington, 2006). To address this, regulators could treat
OPEX and CAPEX differently (Müller, 2012). Allowed revenue for the DSO is calculated as the sum of estimated
OPEX, depreciation and return on capital. Return on capital represents the opportunity cost of investing in the
network rather than in other activities. Thus, while forecast OPEX is added directly, CAPEX is capitalised in the

(26) Efficiency benchmarking involves assessing the operators’ individual costs against the services they provide and determining each
operator’s cost efficiency compared to other operators.

10
regulatory asset base (RAB) and a rate of return is applied to the RAB. Although this can be effective in
incentivising infrastructure investment, it can result in a bias towards CAPEX. An alternative to this approach is
total expenditure (TOTEX), which allows the DSO to choose between OPEX and CAPEX, or an efficient mix of
both, to meet network demands (Ofgem, 2009).

Table 2: DSO revenue models

Elements for France Germany Netherlands Norway Sweden United

calculation of Kingdom
model

Regulatory Incentive Incentive Incentive Incentive Incentive Incentive

mechanism regulation regulation regulation regulation regulation regulation
(revenue cap) (revenue cap) (price cap) (revenue (revenue cap) (revenue
cap) cap)

Cost
TOTEX (*) TOTEX TOTEX TOTEX TOTEX TOTEX
examination

Regulatory 4 years 5 years 3–5 years 3–5 years 4 years 8 years

period (2021–2025) (2019–2023) (2022–2026) (2018– (2020–2023) (2015–
2022) 2023)

Efficiency Yes Yes Yes Yes Yes

No
benchmarking (yardstick) (yardstick) (yardstick) (yardstick) (yardstick)

Quality Yes Yes Yes Yes Yes Yes

incentive

Innovation — Through — Efficiency Indirect (**) Pass- — Indirect (**) — Innovation

incentives tariffs (R & D bonus passed through stimulus and
— Pilot
OPEX not through costs (***) price control
regulation on
subject to tariffs package
different
efficiency (RIIO (****)
— Regulatory tariff
requirements) model)
sandboxes structures
— Regulatory — Flexibility
sandboxes innovation
programme
(*) For non-network expenditures.
(**) Innovation as a means to reach other goals.
(***) Under certain conditions.
(****) Revenues = innovation + incentives + outputs.
Source: JRC analysis.
Another relevant aspect is the duration of the regulatory period, which is critical in determining the strength of
the incentive (Armstrong and Sappington, 2006). While longer regulatory periods provide more stability and
certainty for network operators and customers, as well as stronger efficiency incentives, they can create high
uncertainty owing to the level of assumptions and forecast required during the price control period. This was
recognised by the UK regulator and, as a result, the regulatory period for the new price control (RIIO-2) has
been shortened. On the other hand, excessively short regulatory periods may lead to under-investments and
may undermine the strength of the efficiency incentive (Balázs, 2009).
Finally, rather than using the firm’s expected costs to set the revenue (or price) cap, the regulator can use the
costs of similar firms as a benchmark, an approach called yardstick competition. By comparing similar firms,
the regulator can deduce the DSO’s achievable costs, thus reducing the degree of information asymmetry
between the firm and the regulator, which can provide additional efficiency incentives for the revenue (or price)
capping (Shleifer, 1985; Hellwig et al., 2019).

11
All of the European countries analysed in this study have adopted a TOTEX approach, which allows the DSO to
choose OPEX or CAPEX or a mix of both to meet network demands, which is the opposite of non-TOTEX
approaches, which may direct network expenditure towards CAPEX- or OPEX-based solutions. In this way, DSOs
are incentivised to choose the most efficient combination of resources to achieve several regulatory aims using,
for example, less capital-intensive innovative expenses and higher OPEX in the short term (e.g. flexibility
procurement), instead of traditional network investments (CEER, 2022). The following subsections provide a
more detailed view on the DSO revenue model in each of the countries examined.

3.1.1. France
The French regulatory authority Commission de Régulation de l’Énergie (CRE) sets a revenue cap that is annually
adjusted during each 4-year regulatory period (currently 2021–2025). Each year’s revenues are set ex ante
and mainly consist of an estimation of OPEX and a return on the RAB. While OPEX is subject to incentive
regulation, CAPEX is subject to rate of return regulation, which can create incentive bias. As a result, the
regulator has decided to differentiate between the way network and non-network expenses are treated – while
network expenditures are treated as before, for non-network expenditures, OPEX and CAPEX are subject to the
same incentives. In addition, the French regulator has strengthened the incentive for quality of service,
particularly regarding connection times, and it has set a goal for the largest French DSO (ENEDIS) to shorten
its connection times by an average of 30 % by 2024 (CRE, 2021a).
As for R & D incentives, each network operator proposes an annual R & D budget at the beginning of each
regulatory period, which is then subject to approval by the regulator. Deviations from planned R & D
expenditures are recovered entirely through adjustments to the revenue allowance in the following years,
subject to evidence sent by the DSO to the regulator to justify and account for the difference from the planned
budget. It is interesting to note here is that, owing to the different schemes applied to OPEX and CAPEX, the
regulator has observed that investments that produce a reduction in CAPEX (e.g. demand-side management
and storage) with a less than proportional increase in OPEX may be penalised – a case particularly relevant for
smart grid investments, and also applicable to flexibility projects. As a result, R & D OPEX is not subject to
efficiency benchmarking. In addition, smart grid projects with OPEX higher than EUR 3 million can recover
justified cost overruns following adjustments in the revenue cap (CRE, 2021a).
In 2020, the French regulator (CRE) published its decision for implementation of a regulatory sandbox, followed
by two application periods, in 2020 and 2021, respectively (CRE, 2021b). During the first application period, 20
projects (out of 42) were granted a regulatory sandbox and the main topics included the integration of electric
vehicles (EVs) into the power system, the participation of storage and the provision of flexibility services in the
market, innovative network tariffs and power-to-gas applications (An et al., 2021). The second application
period was September 2021–January 2022. In addition, the Ministry for Ecological Transition may also grant
regulatory exemptions from the conditions for network access and use in its areas of competence. As of July
2021, the ministry had granted exemption to four projects, one being the ReFlex project, led by the largest
French DSO (ENEDIS). Further details about this project can be found in Section 3.2.3.

3.1.2. Germany
The German regulatory authority (Bundesnetzagentur - BNetzA) sets caps on firms’ revenues during each
regulatory period (currently 5 years: 2019–2023). The revenues allowed are set ex ante for the whole
regulatory period and are adjusted yearly based on outputs that account for network reliability and quality of
supply (Matschoss, et al. 2019). Furthermore, the regulatory authority applies efficiency benchmarking by
increasing or reducing the revenue cap when the reliability of supply deviates from the average of all
comparable DSOs ( 27) each year (weighted averages of key figures, e.g. duration and frequency of interruptions
of supply are calculated for all comparable DSOs for the last 3 years). To further incentivise innovation, in
2016, the regulator introduced a super efficiency bonus scheme, which provides those DSOs with a 100 %
efficiency rating with a mark-up on the revenue cap (Federal Ministry for Economic Affairs and Climate Action,
2016). The mark-up amounts to a maximum of 5 % and is evenly distributed over the regulatory period
(Matschoss et al., 2019).
Incentives for R & D in new technologies are mainly provided by large funding programmes under the Federal
Government, leaving the regulator with a limited role in this regard. However, an incentive mechanism exists in
the form of an adjustment to the revenue allowance, meaning that, every year, network operators can partially

(27) The standard procedure applies to DSOs with a customer base larger than 30 000 and a simplified procedure applies to small DSOs
of up to 30 000 customers (182 out the 879 German DSOs are subject to the standard procedure).

12
recover R & D project expenses undertaken in that year by increasing the revenue allowance by 50 % of the
total costs not covered by public funding (Federal Ministry for Economic Affairs and Climate Action, 2016)].
R & D costs already included in the initial revenue caps are not eligible for adjustment. For a project to be
eligible, it must be included in a research funding programme approved by a regulatory authority or
governmental body (e.g., the Federal Ministry for Economic Affairs and Climate Action).
To further facilitate the transfer of technology and innovation for the integration of large-scale renewable
energy, the Federal Ministry for Economic Affairs and Climate Action launched the implementation of regulatory
sandboxes for energy transition (technology readiness levels 3–9), as part of the seventh edition of the energy
research programme (Federal Ministry for Economic Affairs and Energy, 2020). Regulatory sandboxes for the
energy transition were set to last from 2019 to 2022 with allocated funding of up to EUR 100 million per year.
Topics range from sector coupling and hydrogen technologies to energy storage in the electricity sector and
energy-optimised urban districts. Projects granted a regulatory sandbox can have a duration of up to 5 years.

3.1.3. Netherlands
The Dutch regulator adopted an incentive regulation using a price cap based on TOTEX with network operational
efficiency (reduced network losses) and a quality incentive, and using yardstick competition for cost-efficiency
benchmarking. This approach provides DSOs with an opportunity to select the most efficient mix of expenses:
OPEX (e.g. procuring flexibility) and CAPEX (i.e. conventional grid reinforcement). However, DSOs that spend
more on CAPEX (i.e. timely investment in network reinforcement) may perform better than the benchmark,
whereas DSOs that procure flexibility to manage congestion with relatively high OPEX may perform worse
(Anaya and Pollitt, 2021). Therefore, it is critical that the regulation is fit for purpose and that the DSOs properly
factor in the value of flexibility in their network investment decisions.
With respect to R & D spending, the Ministry of Economic Affairs together with other institutions is responsible
for guiding the choice of the necessary projects and the implementation of funding programmes, such as the
Topsector program ( 28). The regulatory sandboxes in the Netherlands between 2015 and 2018 were explicitly
reserved for small emerging players in the energy arena, such as energy communities and homeowner
associations, and focused mainly on decentralised energy production and peer-to-peer energy trading and
supply. Following the advice of the Council of State, the Ministry of Economic Affairs and Climate decided to
no longer run the scheme, partly because the new energy act should come into force in 2022 and because the
decision on whether regulatory experiments should be part of it is still pending.

3.1.4. Norway
In Norway, the revenue cap is set annually based on a formula of 40 % cost recovery and 60 % cost norm
resulting from benchmarking models based on the costs of other comparable DSOs in the country (yardstick
competition). This ratio will change starting from 2023 to 30 % cost recovery and 70 % cost norm, which is
expected to increase incentives for cost-efficiency.
Expenditures for R & D and pilot projects are added to the revenues allowed (with a maximum of 0.3 % RAB).
The current R & D scheme for Norwegian DSOs was implemented on 1 January 2013, which allows specific
and pre-qualified R & D project costs to be recovered directly through the grid tariff (i.e. outside the revenue
cap regulation scheme); therefore, they are not included in the benchmarking. Three conditions must be fulfilled
before the costs are accepted in this mechanism ( 29):
1. the R & D project should prove useful for grid operation / investments / planning;
2. it represents a maximum of 0.3 % of the DSO’s RAB;
3. it needs to be approved by an external body (e.g. the Norwegian Research Council).
As of 2021, the Norwegian Energy Regulatory Authority (NVE-RME) has approved 215 projects as part of this
scheme ( 30).
In addition, in 2019, the regulator developed a regulatory sandbox framework for pilot and demonstration
projects (typically with technology readiness levels 5–8) ( 31). The main purpose of this framework is to facilitate

(28) https://www.topsectorenergie.nl/en
(29) https://www.nve.no/norwegian-energy-regulatory-authority/economic-regulation/incentive-scheme-for-r-d/
(30) https://www.nve.no/reguleringsmyndigheten/bransje/bransjeoppgaver/finansieringsordning-for-fou/godkjente-prosjekter-i-rmes-
finansieringsordning-for-fou/
(31) https://www.nve.no/reguleringsmyndigheten/bransje/bransjeoppgaver/pilot-og-demonstrasjonsprosjekter/

13
the implementation of these projects in a controlled regulatory environment based on two basic principles: to
provide information about current rules and regulations and to have a transparent derogation process. Since
the adoption of the framework, there have been nine projects granted a derogation. Most of those projects aim
to trial innovative solutions linked to flexibility, aggregation and network tariffs. The regulator has also granted
a derogation to several TSOs that are willing to trial solutions related to the procurement of flexibility services
but that are not able to commercially do so due to current requirements regarding bid size and composition.

3.1.5. Sweden
In Sweden, output-based incentives for reliability and quality of supply and efficient grid utilisation (assessed
through network losses and average load factor) are integrated in the revenue cap, which is annually adjusted.
In addition, an efficiency benchmarking model is used to estimate DSOs’ specific potential for efficiency
improvements. The benchmarking involves assessing DSOs’ individual costs against the services they provide
and determining each DSO’s cost-efficiency compared with other DSOs. In the benchmarking process, the
regulator compares the inputs (controllable OPEX) with the outputs (number of customers, high and low voltage
electricity delivered, number of network stations, etc.) for each DSO (CEER, 2022). Furthermore, the regulator
proposed a legislative amendment for the next regulatory period to include TOTEX in the efficiency benchmark
instead of controllable OPEX only, which shows a movement towards higher cost-efficiency. In addition, the
Swedish regulator has implemented a pilot regulation that allows all DSOs to test different tariff structures for
specific customer categories to stimulate demand-side flexibility. In March 2022, the Swedish regulator
launched a project to examine the conditions for setting up a regulatory sandbox scheme in the energy sector.
A proposal for a model on regulatory sandboxes in the Swedish energy market will be presented at the end of
the project in February 2023.

3.1.6. United Kingdom

The UK regulator Ofgem adopted, in 2013, an incentive (performance-based) regulation using a revenue cap,
where revenues = innovation + incentives + outputs (RIIO). Under RIIO, firms are held accountable for delivering
a high quality of service and cost-efficiency using output targets and TOTEX allowances, which means that a
fixed proportion of a firm’s total expenditure is added to the RAB, irrespective of whether it comprises CAPEX
or OPEX. The revenue cap is adjusted yearly through performance and innovation incentives (Ofgem, 2010).
Innovation is stimulated through a long regulatory period, an equal treatment of OPEX and CAPEX, and a focus
on the delivery of outputs. There are three measures focusing on innovation – the network innovation allowance
(NIA), network innovation competition (NIC) and the innovation roll-out mechanism (IRM) – which were
introduced in 2015 for electricity distribution. The NIA is a yearly adjustment to the revenue allowance of
network firms, which is used to finance small R & D and demonstration projects. This allowance is capped at
0.5–1 % of base revenues for each company, depending on the quality of its innovation strategy (Ofgem, 2011).
NIC is a competition through which a few large development and demonstration projects run by the TSO and
DSOs are selected for funding. Unlike the NIA, NIC focuses on projects aimed at granting environmental
benefits. For a project to be funded (up to 90 %), the licensee must show how the innovation creates new
knowledge and how it can be shared among network operators ( 32), while providing long-term value to network
customers and environmental benefits (Ofgem, 2017). The IRM is an incentive that works by adjusting allowed
revenues to fund the roll-out of trialled innovations if they have environmental benefits and provide value for
money for consumers. However, the operator cannot get commercial benefits from this roll-out within the price
control period to avoid financing investments that should be made under a business-as-usual status by the
company (Ofgem, 2015).
The new RIIO price control framework will start in April 2023 and includes several modifications, including
(Ofgem, 2018):
— a shortening of the price control length from 8 to 5 years, as, in the current regulatory period, the high
uncertainty in the energy sector generated unreliable assumptions and forecasts, which led to allowances
being set too high and performance targets being set too low;
— an increase in innovation delivered under a business-as-usual status while keeping the innovation stimulus
package;

(32) Data about projects supported by NIC and NIA mechanisms can be found on the ENA Smarter Networks Portal
(https://smarter.energynetworks.org/).

14
— an overall simplification of the price control, especially regarding how outputs and costs are set.
In addition, the UK government (i.e. the Department for Business, Energy and Industrial Strategy) has recently
launched the flexibility innovation programme ( 33), which is part of the department’s net zero innovation
portfolio and it seeks to enable large-scale widespread electricity system flexibility through smart, flexible,
secure and accessible technologies and markets. Markets for flexibility and unlocking the value of flexibility is
one of the central themes of the programme.
Large-scale deployment of flexibility services is also one of the focus areas of the open networks
programme ( 34) which was set up in 2017 and is run by the ENA ( 35). As part of this programme, the United
Kingdom’s six distribution network operators (DNOs) ( 36) have made a strong commitment to increasing the
use of competitive third-party flexibility services. More information on the open networks programme can be
found in Section 4.7.
In 2017, a regulatory sandbox framework had already been developed by Ofgem, with the aim of supporting
innovators who already (or intend to) operate in a regulated energy market in delivering trials or entering the
market with a new product or service for energy consumers. Some of the topics of the projects granted
derogation under this framework include trials linked to the development of new price methodologies for
facilitating investment in on-street EV charge point infrastructure, for which reinforcement costs may be a
barrier to deployment; trading of domestic flexibility in the balancing mechanism; peer-to-peer trading; etc ( 37).

3.2. Solutions to flexibility procurement

The electricity market directive granted DSOs an extended role by introducing access rights for end-users to
sell flexibility (both upwards and downwards), directly or through aggregators or citizen energy communities.
In this context, DSOs are empowered to take a more active role both as buyers of distributed flexibility and to
facilitate others’ use of flexibility resources in their own networks to enable system-wide benefits. Article 32
of the electricity market directive states that DSOs:
shall procure flexibility services in accordance with transparent, non-discriminatory and market-based
procedures unless the regulatory authorities have established that the procurement of such services is
not economically efficient or that such procurement would lead to severe market distortions or to higher
congestion.
Furthermore, this directive states that ‘DSOs shall cooperate with transmission system operators for the
effective participation of market participants connected to their grid in retail, wholesale and balancing markets’.
According to CEER, DSOs can access flexibility through (1) rules-based approaches, (2) flexible connection
agreements, (3) tariff structures or (4) market-based procurement, or through a combination of these options
(CEER, 2020a). In all cases, flexibility should be seen not as an end but rather as a tool to operate grids more
efficiently while at the same time contributing to managing the ongoing challenges due to growing integration
of renewable generation. The choice of measures as alternatives to traditional network reinforcement is driven
by a plethora of factors, among them the national regulatory framework in place. More specifically, the choice
is affected by the incentives for DSOs to more cost-efficiently operate and plan their networks, how CAPEX
versus OPEX are treated in the regulatory model, if there are any efficiency requirements and how R & D-
related costs are incorporated into the DSO revenue model (see Section 3.1). In addition, several approaches
to accessing flexibility often co-exist and are linked, for example a flexible connection agreement coupled with
a (rebated) interruptible tariff, which makes it more difficult to assess different solutions when facing a network
constraint (e.g. congestion management). In this context, one issue that may arise is the co-existence of
different solutions (namely market- versus non-market-based solutions) and whether (or not) one type of
solution may hinder the deployment of another. For example, the advent and wider adoption of smart home
technology and smart metering systems will further the possibilities regarding demand response; this in turn
will help consumers to be more price-responsive and will increase the value of implicit flexibility in view of
growing levels of variable renewables and the electrification of other end-user sectors (e.g. transport and

(33) https://www.gov.uk/government/publications/flexibility-innovation
(34) https://www.energynetworks.org/creating-tomorrows-networks/open-networks/
(35) The ENA is an industry body representing the companies that operate the electricity wires, gas pipes and energy system in the United
Kingdom and Ireland.
(36) The United Kingdom’s six DNOs are Electricity North West, Northern Powergrid, SP Energy Networks, Scottish and Southern Electricity
Networks, UK Power Networks and Western Power Distribution.
(37) A full list of projects, including descriptions and additional information, can be found on Ofgem’s website
(https://www.ofgem.gov.uk/publications/regulatory-sandbox-repository).

15
heating). On the other hand, depending on the tariff structure, implicit demand response may increase, rather
than reduce, the need for explicit (market-based) flexibility at a certain location in the network (e.g. wholesale
spot prices dropping to zero or negative levels could trigger a surge in EV fast charging, which in turn could
cause a local congestion problem) (Nordic Energy Research, 2021).
In the following subsections, we discuss in more detail three out of the four options mentioned by CEER, namely
the tariff structure, including network connection charges (flexible connection agreements); the market-based
procurement of flexibility; and, briefly, the rule-based approach to flexibility procurement, which has been
adopted in Germany.

3.2.1. Network tariffs and connection agreements

Article 32, paragraph 1, of the electricity market directive calls for Member States to enable and incentivise
DSOs to procure flexibility services. One way of doing this is through a more cost-reflective tariff structure,
such as use-of-network tariffs and connection charges, both contributing to what is called implicit flexibility.
More specifically, flexibility can be procured through static or dynamic network tariffs. If flexibility is contracted
for a sufficient period through static network tariffs, necessary network reinforcements may be
deferred/avoided, which may lead to an overall reduction of the DSO’s costs in the long run and therefore to
lower network tariffs for network users. However, if static time signals do not trigger the desired demand-side
flexibility, the procurement of explicit flexibility – when the DSO explicitly procures flexibility from the customer
or through an intermediary – may be a cost-effective alternative to network reinforcements. To this end, explicit
flexibility procurement can have an impact on DSOs’ cost structures and, as a result, on network tariffs. In this
context, the cost of procuring flexibility could be included in the DSOs’ regulated revenue and passed on to all
network users.
Dynamic network tariffs are another instrument for responding to network constraints. In this sense, demand-
side flexibility can be used to respond to dynamic network tariffs and to offer flexibility services requested by
a network operator. As such, the interaction between these instruments needs to be carefully considered.
Incentives for end-users to adopt dynamic network tariffs might be weakened by other factors, for example
dynamic retail prices, particularly if the retail price and network tariffs are integrated into a single component
in the electricity bill. Another aspect is the technological requirements linked to the adoption of dynamic network
tariffs, such as smart meters and certain levels of automation, to allow flexibility provision. In this context,
dynamic tariffs might be more applicable to larger customers and to those smaller customers with sufficient
means for flexibility provision and automation. Evidence from the adoption of dynamic tariffs in Europe is
rather limited; combining dynamic tariffs with explicit flexibility may further increase complexity and not deliver
increased efficiency (CEER, 2020b; Eurelectric, 2021). In addition, from consumers’ perspective, dynamic tariffs
may raise concerns over transparency and price volatility.
In this context, this section provides a closer look at the network tariffs and connection charges in the countries
selected for our analysis as a method of encouraging both DSOs to acquire and customers to provide flexibility
services.
In Norway, a proposal to modify the current network tariff structure to low-voltage (LV) customers, including a
new capacity-based tariff design, has been made (Eriksen and Mook, 2020). The proposal suggests that the
energy charge can no longer include a proportion of the fixed network costs. Instead, it should reflect the cost
of marginal losses in the network. Furthermore, in periods of network constraints, the energy charge should be
set higher than the short-term marginal cost of utilising the network, to incentivise reduction in peak demand
(e.g. via time-of-use (ToU) dynamic or static tariffs). Alternatively, short-term flexibility can be procured via a
local flexibility market. Nevertheless, the introduction of such a price signal may add more complexity to the
tariff design, which necessitates the alignment of the tariff design with the development of flexibility markets.
In addition, the proposal includes changes to the current design of the fixed charge, based on a reasonable
distribution of fixed network costs, and a differentiation according to the customer’s demand for capacity. First
changes in network tariff design into this direction were implemented in July 2022. In addition, DSOs in Norway
also currently rely on interruptible tariffs, which grant a network customer a reduced tariff in return for allowing
the DSO to interrupt or reduce the power consumption.
In Sweden, the regulator considers network tariffs as critical to the promotion of efficient use of the grid.
However, in 2020, only 17 (out of 170) DSOs indicated offers for network tariffs with a power-based
component to customers with a fuse size below or equal to 63 A. Nevertheless, power-based tariffs with time
differentiation, by season and/or by time of day, are expected to become more common in view of the growing
capacity of renewable energy in the grid and the electrification of the transport and industry sectors. As in the
case of Norway, in Sweden some DSOs also use interruptible tariffs to respond to grid constraints in addition

16
to other alternatives, such as the procurement of local production (e.g. Ellevio’s agreement for 320 MW
production availability by Stockholm Exergi) and temporary subscription rights (see also Section 4.2).
In the Netherlands, the regulatory framework on network tariffs offers limited opportunities in terms of
flexibility provision. One of the main reasons is the lack of locational signals, given the use of a uniform
capacity-based tariff for residential consumers introduced in 2009. In addition, change towards a more
dynamic network tariff structure is not expected to take place in the coming years. According to a recent study
(D-Cision and Ecorys, 2019), the implementation of dynamic network tariffs could add additional complexity
to the current static tariff structure, increase administrative burden and require more complex regulation.
In Germany, the current regulatory framework (Section 14a of the Energy Industry Act) grants reduced network
tariffs to LV network users (controllable loads) for adjusting their consumption, as a way of responding to
network constraints. Nevertheless, the value of the discount is not regulated and varies considerably across
DSOs (with an average reduction in network charges of 55 %, equivalent to 3.44 ct/kWh) (Bundesnetzagentur,
2019). Current revisions of Section 14a of the Energy Industry Act include the possibility of reduced network
charges for producers and the introduction of flexible contractual arrangements. In addition, the current model
adopted for procuring flexibility at transmission and distribution network level (Redispatch 2.0) follows a rule-
based approach, where all energy sources, including renewables and combined heat and power above 100 kW,
are obliged to provide their flexibility in return for a cost-based compensation.
In France, procurement of explicit flexibility and network tariffs are considered as two different and
complementary ways of addressing network investment needs, while optimising grid operation and planning.
ToU network tariffs are offered to medium-voltage (MV) customers with a capacity above 36 kW; they can
choose between a static ToU and a dynamic ToU with different off-peak and peak time windows defined for
each MV circuit. In addition, critical peak pricing for network tariffs is available to LV customers (with predefined
peak and off-peak time windows communicated a day ahead). Most retailers follow the same ToU windows
offered by the DSO for the energy tariffs. The largest DSO in France (ENEDIS) also includes flexible (conditional)
connection agreements for MV producers and MV consumers, with the aim being to increase and accelerate
the integration of RES and to optimise planning and the operation of its distribution grid.
In the United Kingdom, there is an ongoing reform of network access and charges (Ofgem, 2022)– launched at
the end of 2018 – in view of wider policy developments, including the broader flexibility strategy, as well as
transport and heat decarbonisation. This reform touches on various aspects related to network access and
charges, including distribution use-of-system charges, and demand and generation distribution network
connections.
In a nutshell, most EU countries are proceeding cautiously with the adoption of more dynamic network tariffs –
mainly owing to associated increased complexity, lack of predictability, technological requirements and the risk
of unfairness (i.e. customers unable to react to them may end up paying more unless the tariff is applied on a
voluntary basis) (Eurelectric, 2021).

3.2.2. Rule-based approach to access distributed flexibility

A market-based approach for the procurement of flexibility at distribution level, as opposed to a rule-based
approach, is still a niche practice in many European countries, where a cautious approach is seen. Germany is
a prime example: driven by high costs for congestion management, mainly at transmission network level (the
annual cost is above EUR 1 billion (AFRY, 2021), the German regulatory authority (Bundesnetzagentur) has
revised the NABEG 2.0 regulation and introduced Redispatch 2.0 (effective since 1 October 2021).
Redispatch 2.0 is a cost-based mandatory approach to solving network congestion problems by involving
storage facilities, RES generators, and combined heat and power plants, as well as conventional units, all with
installed capacity above 100 kW, at both transmission and distribution level. To be able to fulfil the obligations
under Redispatch 2.0 while reducing the overall costs for TSOs and DSOs and, ultimately, for consumers, a high
degree of automatisation in the data exchange processes, sufficient digital databases of the networks and
intensive cooperation between network operators is required. A basic argument for the adoption of a cost-
based approach is to avoid the possibility of strategic behaviour among market players (‘inc-dec gaming’ ( 38)).
However, there is an ongoing discussion on introducing a hybrid model using the Redispatch 2.0 infrastructure,
which will enlarge the pool of flexibility by allowing a voluntary market-based approach for load participation,
in addition to the current mandatory cost-based approach for generation. Moreover, on the demand side, there

(38) Inc-dec gaming refers to the possibility of some market players artificially creating a congestion problem in order to trigger the
activation of flexibility.

17
are several ongoing pilot projects aiming at coordinating charging plans between battery EVs and DSOs using
the Redispatch 2.0 infrastructure to avoid local congestions (AFRY, 2021).

3.2.3. Market-based procurement of distributed flexibility

The rest of the countries reviewed in this report adopt a market-based approach, either through a business-
as-usual approach or at a trial stage. In France, the main value of flexibility lies in the integration of growing
penetration levels of renewable energy in the most cost-efficient way. The largest DSO in France (ENEDIS)
published its vision of embedding local flexibility to accelerate the energy transition and enhance the
performance of the distribution network in 2019 (ENEDIS, 2019), followed by a roadmap for integration of
flexibility in the network operation and planning, which was published in February 2020 (ENEDIS, 2020a). As
part of this roadmap, ENEDIS identifies two main opportunities (use cases) in which the integration of local
flexibility could prove beneficial.
1. Facilitate the connection of customers and accelerate and increase the integration of renewable
energy into the grid by (1) offering smart (conditional) connection arrangements to both MV consumers
and producers and (2) promoting the development of renewable energy by optimising grid planning
under the regional renewable energies connection master plans (S3REnR). In the context of the latter
point, the ReFlex project ( 39) aims to increase the hosting capacity of a set of selected HV / MV primary
substations by 2.5 GW owing to market-based flexibility procurement as an alternative to generation
curtailment. The project is part of a regulatory sandbox with a target year for feedback provision of
2022, which will be followed by potential changes to the regulatory framework. In the context of the
ReFlex project, ENEDIS procures downwards flexibility (generation reduction) in two geographical areas
and the first call for tenders was launched in 2021.
2. Optimise planning and operation of the distribution grid by deploying flexibility to (1) repower
customers before or after an incident, (2) enhance work planning (by preventing outages linked to
planned works on the distribution grid) and (3) defer grid investments. ENEDIS publishes flexibility
opportunities (location, time, type of flexibility product, minimum bid, etc.) based on the identified
network constraints that the distribution grid faces (see also Section 4.8).
In the Netherlands, flexibility for congestion management in the distribution grids is procured using the
TSO/DSO coordination platform GOPACS, which has been in operation since 2019. An extensive overview of
GOPACS is provided in Section 4.5. Furthermore, the Dutch TSO, together with the Italian and Swiss TSOs, takes
part in the Equigy initiative to facilitate flexibility at LV level so that residential customers, through an
aggregator, can participate in balancing services ( 40). The Netherlands is one of the European countries where
flexibility markets are developed and operational – largely owing to there being a regulatory framework in
place that incentivises flexibility procurement as a cost-effective solution to network capacity constraints (e.g.
through yardstick competition based on TOTEX, granting DSOs the possibility of selecting the most efficient
mix of expenses (CAPEX and OPEX), and TSO–DSO cooperation).
In Norway and Sweden, the adoption of a market-based approach to flexibility procurement is limited to pilot
projects, the most relevant being NorFlex (Norway) and sthlmflex (Sweden), which use NODES as the market
platform (see Sections 4.4 and 4.2, respectively). Such a limited approach to this type of flexibility procurement
in the Nordic countries could partly be attributed to regulatory challenges, in particular the way that CAPEX and
OPEX are treated, and network reinvestments that are already taking place as the networks are reaching the
end of their lifetime (e.g. in Norway) (Nordic Energy Research, 2021).
However, future flexibility needs are expected to increase, with smart charging of EVs and electric heating
having the largest growth potential in the near future. Another relevant factor, in this context, could be the co-
existence of market-based procurement with non-market-based procurement, such as interruptible tariffs
and/or conditional (flexible) connections and the way those forms of flexibility interact. The results of the survey
and interviews conducted as part of the study performed by Nordic Energy Research (Nordic Energy Research,
2021) indicate that DSOs in the Nordic countries may have access to a rather inexpensive form – from their
standpoint – of flexibility procurement today, in the form of interruptible tariffs, particularly if these tariff
reductions can be recovered from other customers, who may not necessarily send the right cost signal to the
DSO. In addition, according to the same study, the preference of some DSOs in the Nordic countries for non-
market-based solutions may reflect their concern for long-term reliability and predictability, particularly in view
of the current setup of local flexibility markets in the Nordic countries, as they are in the early stages of

(39) https://flexibilites-enedis.fr/
(40) https://equigy.com/the-platform

18
commercial development. On the other hand, the results of the interviews conducted as part of this study
showed a clear preference for market-based approaches in the future in Norway, whereas interruptible tariffs
were reported to be seen as a security back-up (Pedersen, 2021a).
In the United Kingdom, flexibility is considered one of the key enabling factors for accelerating a clean, but also
more cost-effective and reliable, energy transition, while ensuring that regulation is fit for purpose. In this
context, the regulator (Ofgem) with the government published a second joint plan for smart systems and
flexibility in July 2021, which sets out a vision, an analysis and a set of clear policy actions to drive a net-zero
energy system (Department for Business, Energy & Industrial Strategy and Ofgem, 2021). From 2030, the
United Kingdom is expected to have unlocked ‘full chain’ flexibility – with all flexible supply and demand energy
resources contributing to their full potential – to be able to respond efficiently to available energy and network
resources. This plan also includes a monitoring framework for flexibility to understand how flexibility markets
perform and the barriers to participation in flexible technologies, among other things, so that government and
the regulator can identify actions to determine the right trajectory.
In a questionnaire sent to regulators (Anaya and Pollitt, 2021), energy associations and DSOs in the few
countries with a supportive regulatory framework for flexibility procurement, many of the respondents from
the United Kingdom agreed that the TOTEX regulatory model implemented since 2015 (as part of RIIO-ED1)
has had a positive impact in terms of unlocking the value of flexibility. Some critical changes are to be included
in the next regulatory period (RIIO-ED2), starting in April 2023. One of the key lessons learnt from RIIO-ED2 is
that the overall high cost for consumers is largely attributed to the underspend allowances and rewards from
quality incentives, particularly the interruptions incentive scheme (Ofgem, 2020a). Moreover, some of the
respondents pointed out that procuring flexibility can save TOTEX, but this also means lower RAB; therefore,
more incentives to manage uncertainty (e.g. load growth) through flexibility are needed, which should also be
part of TOTEX. In addition, flexibility should be considered and valued in terms of outputs and the benefits that
it can bring to the whole system. To capture efficiency across the whole system, the next price control period
will have a greater focus on a whole-system approach (Ofgem, 2020b), including a coordinated adjustment
mechanism re-opener, which will allow realignment of revenues and responsibilities of projects within and
across sectors to deliver net benefits to electricity consumers.
Table 3 provides an overview of the different solutions to flexibility procurement in the countries selected for
our analysis.

Table 3: Solutions to flexibility procurement

France Germany Nether- Norway Sweden United

lands Kingdom

Network ToU and Reduced Uniform — Capacity- — Capacity- Distribution

tariffs critical peak network capacity- based based use of
pricing charges for based residential residential system
the provision tariffs for network tariffs network tariffs charges
of a load residential (a few DSOs) under RIIO-
— Interruptible
control (LV consumers ED2 (e.g.
tariffs — Interruptible
consumers) more
tariffs
granular
zones for
charging
and time
bands for
ToU
charges)

19
 Connection Flexible Flexible — — — Flexible
agreements connections connections (non-firm)
for MV connections
network (enhanced
users access
(producers rights under
and RIIO-ED2)
consumers)

Market- Yes No (*) Yes Yes (trial Yes (trial Yes

based phase) phase)
procurement
of flexibility
(*) Hybrid model under discussion (cost-based for generation + voluntary market-based for load).
Source: JRC analysis.

3.3. Participation of independent aggregators

Article 17 of the electricity market directive lays out requirements about the integration of market participants
engaged in aggregation and independent aggregation into the electricity market. More specifically, paragraph 1
of Article 17 calls for Member States to ‘allow final customers, including those offering demand response
through aggregation, to participate alongside producers in a non-discriminatory manner in all electricity
markets’. Furthermore, paragraph 2 of the same article states that:
Member States shall ensure that transmission system operators and distribution system operators, when
procuring ancillary services, treat market participants engaged in the aggregation of demand response
in a non-discriminatory manner alongside producers on the basis of their technical capabilities.
Moreover, Article 2(19) of the electricity market directive defines an ‘independent aggregator’ as a market
participant engaged in aggregation who is not affiliated to the customer’s supplier.
In addition, the electricity balancing guideline ( 41) led to the initiation of discussions in some countries, such as
the Netherlands and the United Kingdom, on independent aggregators through the implementation of a balance
service provider (BSP) independent of a BRP, which to some extent mirrors the separation between the role of
the supplier and the role of aggregators.
In the following subsections, we first provide a brief overview of existing regulatory frameworks for demand-
side participation in the European countries selected for our analysis, to understand how such frameworks
support the development of independent aggregators and the market access of these actors in all electricity
markets. We then provide an overview of the aggregation frameworks adopted in the selected countries, and
particularly with respect to the type of contractual models between aggregators and BRPs/suppliers, the
balancing and financial responsibilities of the former, and the compensation mechanisms in markets in which
independent aggregators participate.

3.3.1. Regulatory framework for demand-side participation

Technological progress in the management of both grid operation and the integration of renewable generation
has unlocked different opportunities for consumers. The clean energy package adopted in 2019 clearly
acknowledges the critical role of consumers in providing the required flexibility for the future energy system
by referring to a ‘consumer centric electricity market design’. Some of the provisions of the electricity market
directive for the development of demand-side flexibility include non-discriminatory access to all electricity
markets and the recognition of (independent) aggregators as market participants.
In this context, Article 32 of the electricity market directive encourages Member States to develop the necessary
regulatory frameworks to allow system operators to procure and deploy flexibility in their networks to
effectively respond to network congestions. Furthermore, Article 17 of the same directive addresses the need
of such regulatory frameworks to facilitate participation of (independent) aggregators in the market.

(41) See Commission Regulation (EU) 2017/2195 of 23 November 2017 establishing a guideline on electricity balancing.

20
A recent monitoring report from smartEn reveals that, despite some progress made in some Member States,
substantial effort is still needed to unlock the full potential of demand-side flexibility and to develop and
implement the right regulatory framework (smartEn, 2022).
In France, the regulatory framework for demand-side participation has been in place since 2014 and, since
then, it has been under constant development, which makes it one of the most advanced in Europe. Demand-
side flexibility can participate in the day-ahead and intraday market, balancing market and capacity market, as
well as in TSO and DSO congestion management services.
In Germany, access to demand-side flexibility is limited to participation in the balancing and the wholesale
markets – in the latter only within the BRP’s portfolio.
In the United Kingdom, demand-side flexibility can participate in balancing, capacity and wholesale (only within
the BRP’s portfolio) markets and in the provision of TSO and DSO constraint management services.
In the Netherlands, demand-side flexibility can participate in the balancing market (the frequency containment
reserve (FCR), automatic frequency restoration reserve (aFRR) and manual frequency restoration reserve direct
activated (mFRRda)) implicitly in passive balancing within the BRP portfolio and in the provision of TSO and
DSO congestion management services (through GOPACS). The recent energy law proposal ( 42) includes
provisions for DSOs to perform market-based congestion management and it also specifies the role of
aggregator and independent aggregator. In addition, a very recent decision of the regulator ( 43) encourages
network operators to utilise their grids more efficiently by procuring flexibility when dealing with congestion
management. The decision revises and updates the rules on transmission scarcity and congestion management
with the aim of making them more applicable to congestion management in the distribution networks.
In Norway, demand-side flexibility has access to the balancing, capacity and wholesale markets and to TSO
congestion management services. Similarly, in Sweden, demand-side flexibility can participate in balancing,
TSO congestion management and the wholesale market. The participation of demand-side flexibility in the
provision of DSO congestion services is still in the trial phase in both Norway and Sweden.

3.3.2. Aggregator models adopted in the selected European countries

The electricity market directive recognises independent aggregators as market actors, and therefore ensures
that customers are free to purchase electricity services independently of their supplier. Article 13 of this
directive eliminates the requirement of prior consent by suppliers, for final customers (through independent
aggregators) to be able to provide services at different markets. This means that independent aggregators are
market parties not affiliated with the customer’s supplier and therefore are free to access different markets
without needing the prior consent of the customer’s supplier.
In this context, the universal smart energy framework (USEF) defines aggregator implementation models as
market models for the aggregator role, describing the aggregator’s contractual relationship to the supplier and
its BRP. Furthermore, each model describes how balance responsibility, sourcing position and associated
transfer of energy (ToE) between the aggregator and the supplier, as well as information exchange, are
organised (Figure 2). The following subsections provide a closer look at the different aggregator
implementation models.

(42) https://www.internetconsultatie.nl/energiewet
(43) https://www.acm.nl/nl/publicaties/codebesluit-congestiemanagement

21
 Figure 2: USEF aggregator implementation models

Source: Armenteros et al. (2021).

3.3.2.1. Independent aggregator implementation models

In a nutshell, the three most widespread types of independent aggregator models in Europe are uncorrected,
corrected and central settlement models (de Heer, van der Laan and Armenteros, 2021). None of these models
requires a contractual relationship between the aggregator and the supplier, and a brief overview of each of
these models follows (see
Table 5 for a summary of the models across the different markets and products).
Uncorrected model
In this model, the aggregator does not hold balancing or financial responsibility for the imbalances caused in
the system following the activation of flexibility. There is also no energy transfer between the aggregator and
the supplier. Therefore, the aggregator can create an imbalance in the portfolio of the supplier’s BRP.
Nevertheless, if the flexibility contributes to the system balance, the supplier’s BRP is remunerated through the
imbalance settlement mechanism for passive contribution to balance restoration. This model is deemed
suitable for products with few and short activations and thus low amounts of activated energy (e.g. frequency
containment reserve for disturbances (FCR-D) in the Nordic countries) (ENERGINET, FINGRID et al.).
Central settlement model
In this model, the aggregator holds balancing (and financial) responsibility for the imbalances caused because
of flexibility activation. A central entity (a TSO or an imbalance settlement responsible party) corrects the
balancing perimeter of the supplier’s BRP and settles the compensation for the ToE based on a predefined
formula set by the regulator. In such cases, the aggregator pays for the sourced energy, at the ToE price, to
the central entity and then the central entity transfers the payment to the supplier. In the case of generation
reduction or load increase, both the energy and the payment will follow the opposite direction. An alternative
to this model is the net benefit model, in which the sourced energy is compensated by the consumers (through
tariffs), who benefit from the flexibility activation, as opposed to the aggregator.
Corrected model
Similarly to the central settlement model, in this model the aggregator is balance (and financially) responsible
for the imbalances caused as a result of flexibility activation. This model requires modification of the
customer’s meter readings, based on the amount of flexibility activated by the aggregator. The aggregator
must assign a BRP that holds responsibility for the difference between the actual consumption and the baseline
(corrected measurements). The supplier bills the same energy volume to the customer as if no activation has
taken place. As the energy is transferred through the customer, the aggregator pays the customer for the
energy that has been billed, but not consumed (or vice versa in the case of load increase), depending on the

22
contract conditions between the customer and the aggregator (the flexibility service contract). In addition,
variations of this model may impose responsibility on the aggregator for possible rebound effects because of
the flexibility activation, typically outside the activation window, resulting in two different versions of this model
(Nordic Energy Research, 2022).
Split-responsibility model
Another alternative to the USEF aggregation models is the split-responsibility model (also called the split-
supply model – see de Heer, van der Laan and Armenteros (2021)). This model is already being piloted in the
Nordic countries (ENERGINET et al..; Färegård and Miletic, 2021) and it separates the energy supply and balance
responsibility by dividing the part of the energy and associated asset(s) controlled by the aggregator, and the
remaining load (non-controlled assets). In this case, the aggregator operates the controllable part of the
connection and is responsible for contracting supply for that part, whereas the retailer supplies the remaining
load (non-controllable). The aggregator can fulfil its sourcing and balance responsibilities either by entering
into a contract with a single supplier (and a BRP) for all its customers or by performing this role itself. This
model typically requires installation of submetering for the controllable part of the load. This model focuses
on the split of the energy supply and, as such, it can be seen as complementary to the USEF aggregator
implementation models, thus allowing for any combination of the two concepts (Armenteros, de Heer and van
der Laan, 2021).

3.3.2.2. Non-independent aggregator implementation models

Alternatives to the independent aggregation models are three types of non-independent aggregation models
that are present in the European energy landscape: contractual, integrated and broker models.
In the integrated model, the supplier and the aggregator roles are combined within a single market party.
In the broker model, the aggregator transfers the balance responsibility to the BRP of the supplier, and
compensation for the imbalances caused and the pre-bought energy by the supplier is settled bilaterally
between the aggregator and the supplier based on contractual arrangements. The aggregator also has a
flexibility service contract with a BSP offering its flexibility to the TSO.
In the contractual model, the aggregator is balance responsible for the imbalances caused by the activation of
flexibility and only during the periods of activation and, thus, it assigns its own BRP to cover the imbalance. In
addition, the aggregator compensates the supplier for the ToE based on a contract that includes a formula for
the calculation of the ToE agreed between the two parties and preferably using a standardised method.
Furthermore, the BRPs of the supplier and of the aggregator enter into a contract on the correction of the
balance perimeter. Finally, the aggregator or its BRP has a flexibility service contract with a BSP, which offers
flexibility to the TSO.

3.3.2.3. Implementation of aggregator models in the European countries examined

Table 4 provides an overview of the types of aggregation models implemented in the countries selected for
our analysis; they mainly concern flexibility traded on the balancing, wholesale and capacity markets.
In France, the uncorrected model is applied for the FCR and aFRR products; however, for the provision of the
aFRR, demand-side flexibility can participate only through a secondary market. As for the other products –
mFRR, replacement reserve (RR), the capacity market, and day-ahead and intraday trading – the corrected and
the central settlement models are applicable, and the choice is based on the connection characteristics. As for
the balancing responsibility, an aggregator active in the wholesale and capacity markets is accountable for the
imbalances caused by the flexibility activation. In the case of the balancing market, the aggregator acts as a
‘floating BSP’ and thus is only financially responsible for deviations from the procured amount of flexibility
(Nordic Energy Research, 2022). Another relevant aspect to mention in the context of flexibility procured in
these markets is that the French regulation only considers load reduction and generation increase as demand
response, while load increase or generation reduction is not (yet) considered.
The German regulation considers two aggregation models – uncorrected and corrected. The former applies to
the FCR product and the latter, implemented in 2021, concerns the mFRR and aFRR products (Nordic Energy
Research, 2022). Under this model, the aggregator must hold a BRP certificate and, following flexibility
activation, it exchanges schedules with the supplier’s BRP for the correction of the balance perimeter. Next,
following the correction of the imbalance, the supplier corrects the energy bill of the customer as if no flexibility
activation has taken place.

23
In the United Kingdom, there are two models applicable, depending on the type of product – the uncorrected
model and another, that is, either the central settlement model or the corrected model, depending on the
circumstances (Nordic Energy Research, 2022). The uncorrected model is applied for balancing products, such
as FCR and the capacity market. As for aFRR, mFRR and RR, the central settlement model applies. To be able
to participate in these markets, the aggregator needs to register as a virtual lead party (VLP), which is basically
equivalent to a BSP role. The compensation for the ToE depends on customers’ consent to share their flexibility
activation data with the retailer. If the customer allows these data to be shared, the imbalance settlement
responsible party then shares the activation volumes with the supplier; therefore, the supplier could charge the
customer for the ToE as a separate specification, which basically mirrors the corrected model. On the other
hand, if the customer does not allow data to be shared, the compensation would be zero and the model in this
case could be mapped as a central settlement model with no compensation (ToE = 0).
Table 4: The aggregation models followed in the European countries analysed
Member FCR aFRR mFRR Wholesale Capacity
State (and RR) market market
France Uncorrected Uncorrected — Corrected — Corrected — Corrected
— Central — Central — Central
settlement settlement settlement
Germany Uncorrected Corrected Corrected Integrated N/A
Netherlands Uncorrected Integrated/ Integrated/ Integrated/ N/A
broker/ broker contractual
contractual (plan for
(plan for central
central settlement)
settlement)
Norway Integrated/ Integrated/ Integrated/ Integrated/ N/A
broker/ broker/ broker/ broker/
contractual contractual contractual contractual
Sweden Integrated/ Integrated/ Integrated/ Integrated/ N/A
broker/ broker/ broker/ broker/
contractual contractual contractual contractual
United Uncorrected/ Central Central Independent Uncorrected
Kingdom central settlement settlement aggregators
settlement not allowed
(plan for
central
settlement)
Source: JRC analysis adapted from Nordic Energy Research (2022)
In the Netherlands, the uncorrected model is applicable to the FCR product, while the new energy law ( 44)
proposes that the central settlement model ( 45) be applied in the future to the aFRR and mFRR products for,
among other things, facilitating independent aggregation (Nordic Energy Research, 2022). Currently, for aFRR
and mFRR, the Dutch TSO corrects the BRP perimeter after flexibility activations based on data shared by the
aggregator following an activation of flexibility. In addition, the aggregator needs to coordinate or make an
agreement with the customer’s supplier – a situation that is likely to change once the central settlement model
is fully adopted. As for the local flexibility services traded through GOPACS, the contractual model applies
(Armenteros, de Heer and van der Laan, 2021).
In Sweden, there are currently very few aggregators, none of which can be considered independent. One reason
for this is the current structure of balance responsibility (Färegård and Miletic, 2021). The aggregator needs to
sign a contract with the customer’s supplier and its BRP, in which the aggregator needs to negotiate with the

(44) https://www.rijksoverheid.nl/documenten/publicaties/2021/11/26/wetsvoorstel-energiewet-uht
(45) The exact model is to be specified by lower legislation, however, the national regulatory authority has indicated the central
settlement model as the most likely option to be adopted

24
supplier and/or BRP the conditions for the financial settlements linked to the imbalance caused and the
compensation to the supplier for the pre-bought energy. In addition, the supplier and its BRP can, in many cases,
act as competitor to the aggregator, unless they are the same actor, as in the integrated model (Färegård and
Miletic, 2021). To address this, the regulator proposed a regulatory framework for independent aggregators in
2021, with a proposition for legislative changes to the Swedish electricity act, planned to be enforced in
2022 ( 46). The proposed framework recommends the implementation of two different models for independent
aggregators – the split-responsibility model and either the central settlement model or the corrected model –
all complying with the requirements of the EU market electricity directive for independent aggregation. The
aggregator will be allowed to choose between these models or the integrated model currently in place.
In Norway, there are no independent aggregators commercially participating in any electricity market. The
integrated aggregation model is present, although is still facing some challenges; for example, entry barriers
to balancing markets is mostly limited to BRPs, meaning that BSPs cannot enter the market directly without
becoming BRPs themselves. In addition, aggregation is allowed only within one bid zone, and load and
generation cannot be aggregated in the same bid unless they belong to the same BRP (ENERGINET et al.).
Another model partially implemented is the split-responsibility model (also called the dual-supply model). Under
this model, the aggregator is required to have a contract with the retailer for the electricity supply, and it
requires new metering equipment (a sub-meter) for the flexibility asset (e.g. EV) as a basis for validation of
the delivered flexibility. Therefore, this model adds additional complexity, such as the need for dual billing for
the customer (ENERGINET et al.). Some ongoing pilot projects, such as NorFlex, are expected to provide useful
insights into the direction of flexibility provision by independent aggregators.

3.3.3. Balance responsibility

Article 15(2)(f) of the EU electricity market directive states that:
Member States shall ensure that active customers 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.
Similarly, Article 17(3)(d) indicates that:
Member States shall ensure that their relevant regulatory framework contains at least the following
elements: an obligation on 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.
In this context, this section provides an overview of the balancing and financial responsibility of the network
users providing flexibility services directly or through an intermediary (aggregator) and the contractual
relationship between the aggregator and the supplier / the supplier’s BRP.
In France – as the only country among those analysed that has opened access for independent aggregators to
all markets – independent aggregators do not need to assign or perform the BRP role in the balancing market,
as they act as ‘floating’ BSPs. However, they are exposed to imbalance penalties for any deviation from the
procured amount of flexibility. Nevertheless, independent aggregators participating in the wholesale and
capacity markets are required to assign or perform the role of a BRP.
In Germany, independent aggregators are allowed to participate only in the balancing market, and they do not
need to assign a BRP. Nevertheless, they need to hold a BRP certificate, issued by the customer’s BRP. Following
flexibility activation, they exchange energy schedules with the supplier’s BRP for the correction of the imbalance
perimeter (see Section 3.3.2.1 for an explanation of the corrected model).
Like in Germany, in the Netherlands, independent aggregators are allowed to participate only in the balancing
market, without performing the BRP role. However, they are exposed to imbalance penalties for any deviation
from the procured amount of flexibility.
In the United Kingdom, independent aggregators can participate in the balancing mechanism and for the
provision of RR, and they do not hold balancing responsibility. However, they need to register as VLPs
(equivalent to a BSP role) and they are exposed to penalties (at least the imbalance price) for under-delivery.

(46) https://ei.se/om-oss/publikationer/publikationer/rapporter-och-pm/2021/oberoende-aggregatorer–forslag-till-nya-regler-for-att-
genomfora-elmarknadsdirektivet–ei-r202103

25
It is important to mention here that, in the models in which aggregators need to assign a BRP or perform the
role of the BRP, the aggregator is balance responsible only for the period when flexibility activation occurs.
In Norway and Sweden, there are no commercially active independent aggregators and, therefore, experience
with market access of independent aggregators to mainly balancing and local flexibility markets is limited to
pilot projects. Currently, aggregators in these countries cannot participate in the balancing markets directly if
they are not also a BRP.
Table 4 summarises the implementation of balance and financial responsibility for independent aggregators.

3.3.4. Compensation mechanisms

Article 17 of the EU electricity market directive indicates that:
Member States may require electricity undertakings or participating final customers to pay financial
compensation to other market participants or to the market participants’ balance responsible parties, if
those market participants or balance responsible parties are directly affected by demand response
activation. Such financial compensation shall not create a barrier to market entry for market participants
engaged in aggregation or a barrier to flexibility. In such cases, the financial compensation 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 method for
calculating compensation may take account of the benefits brought about by the independent
aggregators to other market participants and, where it does so, the aggregators or participating
customers may be required to contribute to such compensation but only where and to the extent that
the benefits to all suppliers, customers and their balance responsible parties do not exceed the direct
costs incurred. The calculation method shall be subject to approval by the regulatory authority or by
another competent national authority.
This section provides an overview of the compensation mechanisms applied in the EU countries analysed.
In Germany, the aggregator compensates the supplier through the customer at retail price level for the sourced
energy. In addition to the retail price, the aggregator may compensate the supplier’s BRP to cover the
administration costs for schedule exchanges and it is up to the BRP (in negotiations with the aggregator) to set
the price.
In the United Kingdom, if the customer agrees to share their data, the supplier can charge the consumer for
the energy offered as flexibility and the aggregator would, in turn, compensate the consumer. If the customer
does not consent to share their data, there is currently no compensation between the aggregator and the
supplier, which corresponds to a ToE price equal to zero. This is, however, likely to change in the future,
particularly in view of the discussion on opening the wholesale market to VLPs (Nordic Energy Research, 2022).
In France, the formula for calculating the ToE price reflects the average sourcing cost for electricity and
differentiates between two types of sites: profiled and half-hourly settled sites (for industrial and commercial
consumers). In this context, the French TSO publishes the prices for the coming year in the preceding December
and the prices are fixed with a ToU component (peak/off-peak) and by season (winter/summer).
In the Netherlands, the compensation is agreed between the BRP of the supplier and the aggregator. Once the
central settlement model is fully in place, the price of the ToE or the formula for its calculation will be prescribed
by the regulator.
The Nordic Energy Regulators point to a trade-off between the degree of compensation to BRPs from
independent aggregators and the attractiveness of the independent aggregator business case. In this sense,
strict requirements for compensation are likely to form an entry barrier for independent aggregators
(ENERGINET et al.).

Table 5 provides an overview of the access of independent aggregators to different markets and their balance
and financial responsibility in the selected EU countries. It also summarises the compensation level (formula)
between the aggregator and the supplier for each country analysed.
Most of the traded flexibility in the markets mentioned above is offered by industrial and commercial
customers. Part of the reason for this lies in the lack of smart metering infrastructure (e.g. in Germany). In the
Netherlands, residential customers can only offer their flexibility within the supplier’s portfolio. Norway and
Sweden are still in the early stages of developing commercial flexibility markets at DSO level and there is a

26
lack of a regulatory framework for independent aggregators. France is the only country among the analysed
countries that allows the participation of residential customers in flexibility markets, normally applying the
central settlement model.

27
Table 5: Flexibility markets design
Market France Germany Netherlands Norway Sweden United Kingdom
characteristic
Market FCR, mFRR, RR, aFRR, FCR, aFRR, mFRR FCR, aFRR, mFRR Limited to trials Limited to trials FCR, Fast Frequency
access of wholesale market, (mFRR, intraday, Reserve (FFR), aFRR,
independent capacity market, local flexibility Fast Reserve (FR),
aggregators congestion markets) mFRR, Short term
management Operating Reserve
(STOR), wholesale
market, capacity
market, congestion
management
Balancing and — No need to — No need to — No need to Need to be/assign a Need to be/assign a — No need to
financial be/assign a BRP be/assign a BRP be/assign a BRP BRP BRP be/assign a BRP
responsibility (balancing market) (balancing market) (balancing market) (balancing market)
— Need to be/assign — Financial — Financial — Financial
a BRP (wholesale and responsibility (*) responsibility (*) responsibility: yes (**)
capacity markets)
— Financial
responsibility (*)
Type of Industrial/commercial Industrial/commercial Industrial/commercial Mainly Industrial/commercial Industrial/commercial
customers and residential industrial/commercial

Compensation — Corrected model: Retail price Not yet (to be Equal to zero if the
level retail price or (+ additional adopted in the future customers do not
approximation of the administrative costs) for the central – – share their data,
sourcing costs settlement model) otherwise paid to the
— Central settlement supplier (not
model: formula is set regulated price)
by the regulator
(*) At least for under-delivery.
(**) Only for under-delivery.
Source: JRC analysis adapted from Nordic Energy Research (2022).

28
4. Presentation of flexibility markets in Europe

4.1. NODES market platform

4.1.1. General information

— Date of foundation: early 2018
— Date of release of commercial market platform: early 2019
— Website: https://nodesmarket.com/
NODES is a flexibility market platform deployed in various pilot projects, with the most notable being:
— sthlmflex in Sweden, deployed by two Swedish DSOs (Ellevio and Vattenfall Eldistribution) and the national
TSO (Svenska Kraftnät);
— IntraFlex in the United Kingdom, deployed by the UK DSO Western Power Distribution;
— NorFlex in Norway, deployed by two Norwegian DSOs (Agder Energi and Glitre Energi) and the national TSO
(Statnett).
NODES was established by a Norwegian utility, Agder Energi (acting among other things as a DSO), and the
European power exchange Nord Pool. Since 15 December 2021, it has been owned 100 % by the former
(NODES n.d.). It was developed with the purpose of creating flexibility markets in which flexible assets at all
levels of the grid can sell flexibility to both DSOs and TSOs.
The following subsections present the general market architecture proposed by NODES (note that the specifics
in each deployed market can differ significantly, as shown in the following).

4.1.2. Pre-qualification procedures

Flexibility assets are registered in the NODES platform by FSPs. At the very least, the metering point
identification must be included. Before assets can be offered in the market, the local DSO must approve and
confirm that the asset exists in its grid and that they are in the right location.
As a general principle, the regulatory compliance and financial capacity of the FSPs is pre-qualified, as are the
technical characteristics of their flexibility assets. The former can be undertaken by the market operator
(NODES), while the latter falls under the local DSO’s responsibility. So far, regulatory, commercial and financial
capacity checks have been rather light owing to the pilot nature of the projects in which the NODES market
platform has been deployed (Stølsbotn and Eng, 2021). The financial risk from the seller side (FSPs) is
considered to be rather low, given that there are no penalties for partial delivery of flexibility (see also
Section 4.1.5), while, from the buyer side, network operators are considered financially trustworthy by default.
FSPs that are not BRPs (i.e. independent aggregators) are accepted in the marketplace.
The FSPs must undertake a system test in which they verify the trading and activation of their assets in a test
with the DSO. Once this test is completed, the FSP’s systems are approved, and additional flexibility assets can
be registered without undertaking another system test (Stølsbotn, 2021). Depending on the exact application,
DSOs may opt to exclude certain flexibility assets depending on their location. The pre-qualification process by
NODES takes 1 day, on average, subject to the level of automation of FSPs and DSOs (Stølsbotn, 2021).
As a general rule, the NODES market platform does not envisage minimum or maximum nominal capacity
limits for the flexibility assets.

4.1.3. Flexibility products

The NODES market platform accommodates trading of products aimed at network deferral, congestion
management and the enhancement of network resilience. The common feature is that, in all cases, the
flexibility assets have to offer real power injections/withdrawals. Trading of flexibility services aiming at
reactive power/voltage control is also soon to be tested in a pilot (Eng, 2022).
NODES envisages both a long-term market (LongFlex) and a short-term market (ShortFlex). Products in these
could have both an availability and an activation component. Minimum offer limits could be down to 1 kW, and
bids are divisible.

29
Based on the survey results, the NODES market platform foresees that steady-state voltage control, inertia for
local grid stability and island operation capability could be required as specific flexibility services by network
operators in the next 5 years. For all of them, market-based procurement could be the preferred option.

4.1.4. Market architecture

In its full conceptual implementation, NODES aims to offer a market platform for an integrated flexibility
marketplace in which FSPs trade with BRPs, DSOs and TSOs (NODES). As such, the services offered will include
portfolio optimisation (for BRPs), congestion management (both long term and short term, primarily for DSOs)
and frequency regulation services for the TSO. In principle, all of these actors would compete against each
other for flexibility services, even though in most actual pilot implementations the DSO has precedence over
the TSO in the procurement of flexibility (i.e. only the unused offers are passed to the TSO, often in aggregated
form). So far, in the projects in which the NODES market platform has been deployed, only network operators
are buyers of flexibility services (i.e. the BRPs’ participation as buyers of flexibility is not permitted).
In the LongFlex market, availability products (possibly with activation components too) are traded. In real
projects when the NODES market platform is deployed, products with weekly and seasonal (2–4 months)
availability have been deployed.
The ShortFlex market is a continuous, pay-as-bid market. The buyer network operator announces its flexibility
needs in advance and calls FSPs to submit offers, but the latter can also submit offers proactively. Trading of
activation products usually opens 7–10 days and closes 1–2 hours before physical delivery. Technically, the
MTU can be as low as 1 minute, but a common practice is to align the MTU with the imbalance settlement
period.
Regarding the spatial setup of the flexibility market, this is based on congestion zones, inside which an FSP can
aggregate its resources. The definition of congestion zones, and thus the level of acceptable aggregation, is
left to be defined by network operators for each specific test case. The idea of differently defined congestion
zones between the DSO and the TSO is supported. Under this concept, each TSO can aggregate offers from
several DSO congestion zones.
Offers in the flexibility markets where the NODES platform has been deployed are cleared based on their price
(per congestion zone). Conceptually, there are no price caps, and pay-as-bid is the pricing mechanism for
activation products. Technically, availability products can be priced based on either a pay-as-bid or a pay-as-
clear mechanism. In actual projects, the buying network operators either have opted for the former option or
predetermined the remuneration price.
Nominally, domestic end-customers could participate directly in the NODES flexibility markets. However, this is
very rare in practice, mainly owing to the lack of financial incentives and necessary technical acumen (Stølsbotn
and Eng, 2021). Therefore, the participation of assets belonging to residential consumers is made through
aggregators (e.g. as part of the electricity supply offer).
While, in principle, DSOs and TSOs can compete for flexibility based on price, network operators’ operational
security coordination has not yet been addressed in detail by the NODES market architecture. NODES envisages
that the lower level network operator (e.g. a local DSO) could restrict the higher level network operator (e.g. a
regional DSO) to activate flexibility in its grid if this could cause problems. However, the functionality of security
coordination is not developed yet as a standard feature (Stølsbotn, 2021).

4.1.5. Activation and settlement procedures

Activation of flexibility is made by FSPs upon successful clearance of their offers. Communication is made by
email, SMS and/or an application programming interface (API). In principle, there is nothing stopping the NODES
market platform from letting DSOs undertake the activation of flexibility remotely by direct access to the
flexibility assets, but this has not been requested thus far.
Usually, settlement and measurement periods ( 47) are the same. The NODES market platform has been
deployed in projects in which the settlement was in a 1-minute and 1-hour basis.
The NODES market platform permits both options regarding baselining: FSPs declaring their schedules and
baseline calculation based on a predefined method. For the latter, the default baseline is a simple average

(47) The measurement period is the time period during which the energy consumption or production is measured based on the technical
capabilities of the associated meter. The settlement period is the period during which the financial settlement of the activated
flexibility is made.

30
looking back 5–10 days, although the NODES team is exploring other options (Stølsbotn and Eng, 2021). Based
on the responses to the survey, FSP schedule declaration may provide a more sophisticated solution; it has
been the preferred option by the respondents, as it allows FSPs to better manage their assets and achieve
value-stacking. On the other hand, it is acknowledged that settlement based on FSP schedules opens
opportunities for potential gaming. This is why, in certain projects (e.g. in the sthlmflex flexibility market),
market surveillance processes have been introduced by the buying network operators when FSPs opt for
declaring schedules, such as an explanation of their baseline methodology, record keeping of consumption
data, and a comparison between the latter and baseline declarations. Finally, it is noted that, owing to the
inherent problems of flexibility products associated with a baseline – given that the latter can only be a
forecast, irrespective of the entity performing it – the NODES market platform also investigates products that
would not need the employment of a baseline, such as consumption caps ( 48), even though these have not been
employed so far in a real project (Stølsbotn and Eng, 2021).
The settlement of availability products is made only after the activation period. The remuneration level depends
on the level of submission of offers for activation (Eng, 2022).
In the pilot projects in which the NODES market platform has been deployed, no penalties are applied in the
case of partial delivery of flexibility, but there is a reduction in compensation. Nevertheless, the survey results
show that penalties may become relevant when flexibility markets reach full commercialisation stage.
The financial cost of imbalances caused by the activation of flexibility is borne by BRPs. However, NODES has
developed, in the context of the IntraFlex project, an information page service through which BRPs can see the
trades of FSPs with flexibility assets under the balance responsibility of BRPs (see also Section 4.3).

4.1.6. Lessons learnt and future developments

The structured interview provided some of the insights into the experience of the NODES market platform in
local flexibility market projects.
— FSPs are still experimenting with their business models. There is a difference between suppliers/BRPs who
also offer aggregator services and independent aggregators. The former are usually large, established
companies that see flexibility as a tool for portfolio optimisation, mainly in the wholesale market, while
local flexibility markets represent only a secondary revenue opportunity. Independent aggregators are
usually small technology firms exploring the option of offering additional services to their customers other
than the strictly technical setup of aggregation capabilities.
— Automation of pre-qualification procedures, as well as of trading functions, are key for the development
of a successful local flexibility market. In this respect, also of importance are the operational security
processes of DSOs, which in many cases lack the necessary level of observability and diagnostics to
maximise the value that could be offered by flexibility in the distribution system.
— The DSOs’ inadequate technical sophistication, previously mentioned, and the lack of regulatory incentives
for exploiting flexibility are identified as the two most significant barriers to the development of local
flexibility markets, with the latter being the most serious one. Even though utilisation of local flexibility will
be just part of the solution, it should be incorporated into the long-term planning of distribution networks,
which most often is not the case.
— APIs seem to be, for the NODE market platform, the preferred option for automating data processes
between the platform, FSPs and network operators. The interviewees seemed sceptical about the
harmonisation initiatives, stating that it could imply undue burden, especially for small FSPs, such as
harmonisation with the common information model (CIM) in Sweden. The need for data harmonisation (e.g.
of format of baseline declarations, metering data and trading offers) is acknowledged, but it should not
be dictated by network operators. Instead, FSPs must be an integral part of the harmonisation process.
The interviewees also referred to the EUniversal ( 49) Horizon 2020 project aiming at fostering
interoperability, of which NODES is a part.
— Regarding product design, experience of NODES shows that the existence of contracts of different temporal
scales (i.e. long, medium and short term) is beneficial because of the different technical characteristics of
flexibility assets.

(48) Under a consumption cap product, the FSP offers to limit the consumption of its bidding assets under a certain limit during a specific
time period.
(49) https://euniversal.eu/

31
As future milestones, the interviewees identified the evolution of some pilot projects employing the NODES
flexibility market platform towards a business-as-usual state in the next 2–3 years, as well as the revision of
the national regulatory frameworks for DSOs towards a more TOTEX approach, which is expected to happen in
different stages among the various countries.
Finally, the interviewees identified as the main benefit of independent market operators of local flexibility
markets their impartiality against both sellers (FSPs) and buyers (network operators). Instead, if local flexibility
markets are operated by network operators, the buying side may achieve a very dominant position, which in
the end would have a negative impact on liquidity.

4.2. sthlmflex project

4.2.1. General information

— Start date: 1 December 2020
— Country: Sweden
— Status: ongoing
— Network operators involved: Svenska kraftnät (TSO), Ellevio (regional DSO), Vattenfall Eldistribution
(regional DSO), E.ON Energidistribution AB (local DSO)
— Main webpage: https://www.svk.se/sthlmflex
In Sweden, the TSO offers a guaranteed amount of power withdrawal capability at each TSO/DSO interface
point (called a network subscription). A mechanism of temporary subscriptions comes on top, allowing the
guaranteed network subscription capacity to be temporarily exceeded upon agreement from the TSO, with a
financial penalty to be paid by the DSO.
The sthlmflex flexibility marketplace is deployed in the Stockholm area to address a lack of network capacity,
and it is a continuation of pilot projects on local flexibility markets developed in other parts of Sweden in the
context of the CoordiNet Horizon 2020 project ( 50).
The targeted flexibility services include investment deferral, operational congestion management and
enhancing network resilience. sthlmflex aims to enhance both TSO/DSO and DSO/DSO coordination. DSOs buy
congestion management services from FSPs, and trade network subscription capacity rights between
themselves, while the TSO buys mFRR services. Flexibility services are localised in three regional areas
(Stockholm north, Stockholm south and Stockholm city). Originally, this pilot project was intended to run from
1 December 2020 to 31 March 2021, but it was decided that it would be extended through two additional
winters in order to refine the details and increase incentives for even more players to participate in the market.
Originally, only Svenska kraftnät (TSO), Ellevio (regional DSO) and Vattenfall Eldistribution (regional DSO) were
participating in the pilot project. E.ON Energidistribution AB (local DSO) decided to be involved from the winter
of 2021/2022. The two regional DSOs operate the network in the voltage ranges between 24 kV and 220 kV,
while E.ON Energidistribution AB is one of the 15 local DSOs in the examined area operating below 24 kV.
Industrial and commercial customers, producers involved in the power and heat sector, and smaller assets via
aggregators, including independent aggregators, currently take part in the market.

4.2.2. Pre-qualification procedures

When FSPs express their interest in participating in the sthlmflex flexibility market, they have to declare for
each of the assets in their portfolio the installation identification, type of asset, nominal capacity and network
jurisdiction to which it belongs (Ellevio et al., 2021a). DSOs validate the metering points supplied by the FSPs
and approve the baseline methodology defined by them (see also Section 4.2.5). The pre-qualification process
for FSPs mainly verifies compliance with a minimum bid step size of 0.1 MW, along with successful
communication with the market platform (NODES). For seasonal contracts (see Section 4.2.3), there is also an
activation test of 1-hour duration each season. For participation in the balancing market, the pre-qualification
procedures defined by the TSO must be followed.
At regulatory level, FSPs have to sign a power of attorney agreement regarding metering data for all their
flexibility assets and sign a contract with the market operator (NODES).

50
https://coordinet-project.eu/pilots/sweden

32
On average, the pre-qualification process takes 14 days (Ersson, 2022).
For participation in the balancing energy market, FSPs must have an agreement with the respective BRPs, as,
among other things, financial compensation by the TSO is provided to the latter (Ellevio et al., 2021b).

4.2.3. Flexibility products

Thus far, only upwards flexibility services are traded in the sthlmflex marketplace (i.e. an increase in local
generation or a decrease in consumption).
The exact product specification changes as the project evolves. For the winter of 2021/2022, there were three
types of products: seasonal (traded in the LongFlex NODES market), weekly and short-term products (both
traded in the ShortFlex market).
Seasonal contracts include an availability compensation and an activation price. FSPs bid freely for both
components. The clearance of offers is made solely based on the price of the availability component. For the
activation component, there is a price cap (SEK 10 000/MWh (EUR 950/MWh) ( 51)). Seasonal contracts aim
mainly to act as lifelines to be used in a 10-year winter ( 52) or during a particular hard operation status. There
are two types of seasonal contracts (Ellevio et al., 2021a):
1. cold hours in the time intervals of 11–7 and 15–21 on working days – an FSP must be able to offer
flexibility for at least 2 hours during one of these two intervals or for 1 hour during both;
2. all hours in the time intervals of 11–7 and 15–21 on working days.
FSPs can bid for seasonal products for one to three seasons. It is noted that the two regional DSOs also have
bilateral availability contracts out of the sthlmflex market (Ruwaida et al., 2022).
Weekly contracts were introduced in the winter of 2021/2022. They too have an availability and an activation
component, but, in contrast with seasonal contracts, there is a predetermined price for the availability
component and free bidding only for activation with a price cap of SEK 2 800/MWh (EUR 266/MWh). FSPs can
offer flexibility for certain (or all) hours in the same time intervals as in seasonal contracts. One of the main
aims behind the introduction of weekly contracts was to increase liquidity in the market (Ruwaida et al., 2022).
As a result, availability compensation for weekly contracts is provided up to 40 MWh per week and in a step-
wise manner: the predetermined availability price is SEK 5 000/MWh (EUR 475/MWh) for the first 10 MWh and
then drops to SEK 2 000/MWh (EUR 190/MWh) for the remaining 30 MWh. In addition, it was guaranteed by
the buying network operators that at least two weekly auctions would take place during the market season of
2021/2022 (Ellevio et al., 2021a).
An important point is that FSPs must be able to offer their availability when the external temperature is –5°C
or lower for both seasonal and weekly products. This is because of the significance of heating loads in the
overall consumption. It is noted that availability contracts are called only in Stockholm north and Stockholm
city congestion areas.
Finally, ‘free bids’ are activation products traded in the continuous local flexibility market without a price cap.
For all products, the minimum bid size is 0.1 MW and bids are divisible (Ersson, 2022).

4.2.4. Market architecture

Trading is based on the aggregation of flexibility assets into portfolios per congestion area (Stockholm north,
Stockholm south and Stockholm city). The highest voltage within each congestion area is 220 kV. The flexibility
market provides the possibility for regional DSOs to use resources in the whole Stockholm region, independent
of the actual location of the resource. This happens with the activation of flexibility offers and simultaneous
swapping of subscription rights from one regional DSO to another. On the other hand, when both regional DSOs
require flexibility, they effectively have to compete.
Seasonal contracts are procured through an auction. Offers are evaluated based on the price solely of the
availability component. Auctions for weekly contracts are called on an ad hoc basis covering the next 7 days.
There is an announcement from the buying network operator, and the market platform (NODES) sends an email
notification. It is noted that FSPs requested an SMS to also be sent when a weekly auction is called (Ruwaida
et al., 2022). For both seasonal and weekly contracts, the clearing method is pay-as-bid, with the exception of

(51) Considering an exchange rate of SEK 1 = EUR 0.095.

(52) The term ‘10-year winter’ is used to describe a situation that can happen in 1 every 10 winters.

33
the availability component of the weekly products, which is predetermined by the buying network operators
(see the previous section). For all products, the MTU is 60 minutes, as is the wholesale imbalance unit period.
However, the latter in the near future will become 15 minutes.
The ‘free bids’ short-term market is organised on a continuous, pay-as-bid basis. It is possible for the FSPs to
enter flexibility offers as early as 1 week in advance of flexibility delivery and up to 2 hours before delivery.
The DSOs do most of the purchases at 9.30–10.30 on the day before the delivery; therefore, it is recommended
that the FSPs place their bids on the market no later than 9.00 the day before the delivery (Ellevio et al., 2021a).
The remaining flexibility offers, qualifying for mFRR services, then become available to the TSO. The timeline
aims to avoid conflicts with the wholesale spot electricity market. It should be noted that there are slightly
different product specifications between flexibility provision to DSOs and flexibility provision to the TSO (mFRR)
(Table 6).
Offers by FSPs (for all products) can be submitted either through an API or manually in the NODES web
platform.
It is noted that the financial penalty for a temporary subscription, if permitted by the TSO, presents an effective
price cap in the demand for flexibility by the DSOs. According to the published results of the sthlmflex market
for the winter of 2020/2021, available at the NODES website ( 53), the weighted average price of flexibility
offers by FSPs was consistently above the penalty price of a temporary subscription (by a factor of 1.87 or
more), making flexibility activation economically preferable only when temporary subscriptions are not
available.
Table 6: Differences in product specification between the sthlmflex market and the balancing market
Specification Congestion management (buyer: mFRR (buyer: TSO)
DSOs)
MTU 1 hour 1 hour
Notice period > 2 hours before delivery 0 minutes
Activation time The FSP must provide the full flexibility 15 minutes to full activation
offer at the start of the delivery period
Rules for ramping No Only in respect of activation time
Recovery rules No N/A
Minimum bid size 0.1 MW (*) 1 MW (**)
Minimum bid step 0.1 MW 1 MW (**)
Maximum bid size No No
Maximum bidding step No No
Divisible bids Yes Yes
Activation pricing Pay-as-bid Pay-as-clear for balancing; pay-as-bid
for congestion management in the
transmission network (***)
Penalties for non- Reduced compensation for partial As per balancing market rules
delivery delivery
(*) In contrast, the minimum participation size is 0.5 MW for availability contracts.
(**) Flexibility bids can be aggregated, but only from the same bidding zone and BRP or under contract.
(***) In the Nordic countries, the same order book is used for balancing and for congestion management in the
transmission network (i.e. for the latter, TSOs activate offers submitted in the balancing energy market).
Source: JRC analysis.

4.2.5. Activation and settlement procedures

Activation of a successful flexibility offer is made by the FSP after a signal coming from the market platform
(NODES) via an API, email or SMS.
FSPs can either declare a baseline position to the sthlmflex market platform or leave it to the market operator
to calculate a baseline based on historical data, with the default being to take an average of hourly
measurement data from 5 recent working days. For the former option to be allowed (FSP declarations), approval
by the network operators is required and, if necessary, bilateral talks (Ellevio et al., 2021a). In the experience
of the project partners, significant grid users (SGUs) prefer to declare schedules, while aggregators of smaller

(53) https://nodesmarket.com/sthlmflex/

34
flexibility assets prefer to be settled based on a baseline defined by the market operator. So far, there have
been no indications of any gaming behaviour by FSPs when they choose to declare their baseline (Ruwaida et
al., 2022).
FSPs have the option to use either flexibility asset sub-meters or metering data from the connection meters of
network operators. Network operators have the option to employ their own metering for flexibility assets above
1.5 MW.
— The measurement and settlement periods are both 60 minutes. If the FSP and the BRP are different entities
(i.e. in the case of independent aggregators), the balance responsibility falls upon the BRP. Moreover, there
are no arrangements for the independent aggregator compensating the supplier for the pre-bought energy
by the latter.
— In the case of partial delivery, there are no penalties, but there is a reduction in compensation for both
availability (if applicable) and activation components according to the following rules (Ellevio et al., 2021b):
● 100 % payment for delivery at 80 % or above;
● a linear reduction up to 40 % delivery;
● no payment for delivery below 40 %;
● the availability compensation is validated on a monthly basis.

4.2.6. Results, lessons learnt and future developments

The sthlmflex pilot market was put in operation for the first time during the winter of 2020/2021 (i.e. from
1 December 2020 to 31 March 2021. The flexibility market gave all regional DSOs the possibility of using
resources in the whole Stockholm region, independent of the actual location of the resource. The pilot project
achieved sector coupling between electricity and heat and led to a more effective use of the electricity network
(Ellevio et al., 2021c).
The winter of 2020/2021, according to the Swedish Meteorological and Hydrological Institute, was milder than
usual, with only a few cold weeks in February (not a 10-year winter). At the same time, the Stockholm region
had good access to local electricity production, and the transmission grid presented normal operating
conditions. It should be noted that the potential impact of COVID-19 on capacity needs has not been analysed.
The process for participants offering free bids began on 1 December 2020, whereas the process for larger
procurements of availability contracts started on 1 January 2021, with Vattenfall Eldistribution as the buyer.
In total, six flexibility providers became members in the flexibility market during the first market season, of
which four participated with free bids (Ellevio et al., 2021c). During January–March 2021, 2 276.4 MWh of
flexibility was activated to meet the level of both total subscriptions and individual transmission grid stations.
The calls for flexibility were particularly cautious in the first year, but they could have been double as much. It
is noted that the level of the bids would not have been sufficient in a 10-year winter. The average activation
price was SEK 485/MWh (EUR 46/MWh) and varied between SEK 200/MWh and SEK 5 000/MWh (EUR 19/MWh–
EUR 475/MWh). Temporary subscriptions had a cost ranging from SEK 244/MWh (EUR 23.18/MWh) to
SEK 246/MWh (EUR 23.37/MWh). Therefore, whenever there was the option of a temporary subscription, this
was an effective price cap for the flexibility market.
In the second market season of the winter of 2021/2022, the number of market participants increased to eight,
with five of them being aggregators, representing in total more than 2500 flexibility assets coming from all
sectors (public buildings, residential sites, commercial sites and industrial sites). Most of the flexibility came
from heat pumps of all sizes (small, medium and large heat pumps / district heating) and small EV chargers,
with the remaining provisioned by back-up generation units (e.g. in hospitals), ventilation systems and home
energy management resources. It is noted that, in Sweden, there are few cases of distributed generation
(Ruwaida et al., 2022).
The seasonal availability bids for the winter of 2021/2022 ranged from SEK 100/MWh (EUR 9.95/MWh) to
SEK 1 000/MWh (EUR 99.50/MWh). The maximum activation price ranged between SEK 860/MWh
(EUR 81.70/MWh) and SEK 10 000/MWh (EUR 950/MWh). A total volume of 40.5 MW was offered, from which
10 MW was offered only as a 2-year seasonal contract (Ruwaida et al., 2022). It is noteworthy that, according
to the publicly available market results, temporary subscription rights were either not permitted during

35
December 2021 by the TSO or were more expensive (by a factor of 1.19) than FSPs’ flexibility offers, making
the latter more competitive or the only available option for DSOs.
The survey results indicate that, in the future, reactive power flexibility services may be required, mainly
avoiding the injection of reactive power from the distribution system to the transmission system. Market-based
procurement can be an option, albeit with quite a different architecture, as, according to the stakeholders, long-
term contracts would be more suitable than short-term trading for such services.
During the interviews, the project promoters raised the following points (among others).
— The main challenge facing DSOs in Sweden comes from the rapid electrification of all sectors of the
economy (references were made to EVs, synthetic fuel production, and new industries such as fabrics, heat
production, data centres and fossil-free steel), which has been taking place especially in the last 3 years
and is expected to continue. Notably, this results in delays in new connections or, in extreme cases, in their
denial. Network expansion will also be required in the transmission system, but, owing to the long times
required, flexibility is seen as a measure to defer it, on the one hand, and as a means for serving the
growing electrical demand in the short to medium term (i.e. until 2030) on the other.
— As regards the integration of flexibility into long-term network planning, the interviewees indicated that
long-term contracts, like the seasonal contracts in sthlmflex, are more appropriate for this purpose, as
they effectively aim to ensure the security of the supply.
— The specification of flexibility products is one of the main areas of experimentation by project promoters,
during which it must be weighed up whether these specifications provide a clear business model for FSPs.
Nevertheless, a coherent evaluation of different options has not yet been conducted.
— The project promoters were reluctant to impose penalties for partial delivery of flexibility at this stage of
maturity of local flexibility markets. If these become relevant in the future, they should first be imposed
on availability components, given that they effectively offer reliability services to network operators.
— As regards the required settlement period and MTU of flexibility products, the interviewees expressed the
opinion that a 15-minute period (i.e. the same as the future imbalance settlement period in Sweden) is
adequate for congestion management, as failures from overloading have long time characteristics (i.e. it
takes a relatively long time to lead to a component failure). By contrast, for voltage regulation, flexibility
should be much faster.
— Data ownership, in particular the power of attorney for measurement data when these come from meters
not owned by network operators, posed a particular problem during the project. A standardised form is
being developed in Sweden for addressing the issue.
— The need for measurement data standardisation has been identified as crucial. More generally, DSOs and
TSOs in Sweden opt for standardisation based on the CIM protocol, but they understand that this could
impose considerable transition costs for FSPs. On the other hand, the final vision is that CIM would be used
in all electricity markets offering a harmonised framework, and thus would reduce barriers to market
participation. Overall, the interviewees expressed the view that the transition to CIM harmonisation was
going to be an evolutionary process.
— Regarding independent FSP–BRP relationships, the project promoters identified the key point as the
coordination between the various markets. Proper coordination between local flexibility markets and the
wholesale market could reduce the financial risk of BRPs by increasing their observability of independent
aggregators’ actions and giving them adequate room for hedging (e.g. in the wholesale intraday market).
An ongoing dialogue between DSOs and the TSO is taking place in Sweden, and in 2022 a common view
is expected to be developed regarding a product catalogue for flexibility services. A crucial point is that
only upwards flexibility is requested currently by DSOs, as congestion management issues in Sweden come
from increased electrical demand, as opposed to increased penetration of distributed generation (DG). This
could be the reason why independent FSP–BRP relationships are not considered to require a strong
regulatory framework at the moment; independent aggregator actions would lead to BRPs becoming
long ( 54) (which currently would not pose a significant financial risk).
— The project promoters assess that there is substantial flexibility potential in their distribution systems.
Barriers to mobilising this flexibility potential are not only technical but also organisational (e.g. for the

(54) A BRP that is long in the imbalance settlement has a larger actual generation (or lower actual consumption) than its position after
the gate closure of the Intraday market.

36
 back-up generators in public buildings). An additional layer of complexity comes from the fact that FSPs
have very different business models (e.g. an EV-charger aggregator versus an SGU), which also affects
their preferences regarding flexibility product specification, organisation of the market, data management
and settlement procedures.
The sthlmflex project will continue for 1 more year, after which the network operators will decide if they will
turn it into a business-as-usual approach. For the overall developments of local flexibility markets in Sweden,
it is noted that a new 2-year-long market project was set up in Gothenburg in February 2022 ( 55).

4.3. IntraFlex project

4.3.1. General Information

— Start date: October 2019
— End date: November 2021
— Country: United Kingdom
— Network operators involved: Western Power Distribution (DNO ( 56))
— Main web page: https://www.westernpower.co.uk/projects/intraflex
IntraFlex was a pilot project run by Western Power Distribution, a UK DNO, along with NODES and Smart Grid
Consultancy from October 2019 to November 2021. The main goal of the project was to create a link between
flexibility provision to network operators and wholesale market participation, with a particular focus on the
imbalance risk undertaken by BRPs when independent aggregators activate flexibility. In this respect, two
services specifically targeted at BRPs were initially envisaged:
1. an information service in which BRPs are continuously informed for the submitted flexibility offers in
order to make their own informed decisions, in either the day-ahead or the intraday market;
2. an ‘auto-rebalancing’ function that would automatically balance any deviations from flexibility
activation by trades in the wholesale intraday market ( 57).
However, during project execution, it turned out that the vast majority of BRPs were only interested in the
information service, while considering the ‘auto-rebalancing’ function as having limited value under current
volumes of flexibility activation, also given its complexity and risk. This was then dropped from the project
(Western Power Distribution n.d.). Furthermore, FSPs did not express interest in subscribing in the information
service, as they had no benefit to gain from it. Overall, the flexibility marketplace developed in the context of
IntraFlex acted as a local flexibility market for the provision of congestion management only to the DSO with
no balancing responsibility for FSPs.

4.3.2. Pre-qualification procedures

In the pre-qualification process, an FSP had to sign a membership agreement with the NODES market platform,
accepting the latter’s rulebook, and had to undertake a test trade. FSPs had to register their assets, specifically
the type of asset, metering point identification and location. Disclosure of the supplier in the registry has been
left to the discretion of the FSPs. An end-to-end system testing then had to be made with one asset per FSP,
based on which the buying network operator decided on approval (Western Power Distribution, 2021a).
Ultimately, FSPs had to sign an agreement with Western Power Distribution that set the legal framework for
the transactions between FSPs and the buying network operator (Western Power Distribution, 2021b).
Furthermore, the network operator verifies the legal trustworthiness of FSPs (e.g. convictions of serious
offences and breaches of obligations relating to the payment of tax or social security contributions). The whole
on-boarding process took approximately 4 months.

(55) https://nodesmarket.com/another-nodes-market-goes-live-effekthandel-vast/
(56) In this report, the terms DSO (Distributed System Operator), used in continental Europe, and DNO (Distribution Network Operator),
used in the United Kingdom, are employed interchangeably.
(57) In this respect, it is possible for the same flexibility activation to lead to two different trades: first, the trade of flexibility between
the FSP and the DSO and, second, the trade of the respective energy to the wholesale intraday market by the BRP.

37
4.3.3. Flexibility products
In the IntraFlex flexibility marketplace, only an activation product was developed. Moreover, the flexibility
product was defined by the DSO in terms of power (e.g. a demand reduction of 2 MW for a specific hour), rather
than in energy terms (e.g. 2 MWh for the specific hour). Otherwise, referring to the same example, the FSP
could provide in this time window a reduction of 4 MWh for half an hour, potentially leading to a network
constraints violation (Western Power Distribution, 2020). Therefore, measurements with a granularity of
1 minute have been employed. The minimum bid size was 1 kW.
The flexibility product was divisible, but FSPs could also submit fill-or-kill and minimum quantity offers ( 58)
(Western Power Distribution, 2020; Western Power Distribution, 2021c).

4.3.4. Market architecture

IntraFlex set up a continuous, pay-as-bid flexibility marketplace with gate closure 90 minutes before delivery.
Trade was organised per congestion zone and the MTU was 30 minutes, that is, the same as the imbalance
settlement period in the United Kingdom.
First, the DSO announced the forecasted flexibility needs 7 days in advance (i.e. at D-7), after which FSPs could
submit offers ( 59). Flexibility services were requested only for weekday afternoons and evening peaks. The DSO
set a price cap, i.e. effectively the DSO was submitting a bid sending at the same time notifications to FSPs.
The timing of the DSO submitting its first bid was one of the main test parameters of the IntraFlex project,
varying from 3 days before to close-to-real time. Another major design parameter was determining how the
DSO bids would increase progressively in the lead up to real time (in case the required volume was not met by
financially acceptable offers): different options included a linear increase in predefined steps in time (e.g. every
day) and volume (e.g. GBP 50/ΜW/30 minutes in each step) to not predetermined bid increases in both time
and price. The evaluation of offers was made solely on the basis of price.
According to the DSO analysis, longer pre-announcement periods led to competition in speed, favouring
(relatively) large generation units. By contrast, when the DSO bids closer to real time, competition as regards
price is promoted, favouring the participation also of FSPs with smaller and/or less predictable assets such as
EVs.

4.3.5. Activation and settlement procedures

Offers by FSPs were submitted in the NODES market platform either manually in a web portal or through an
API. The activation of flexibility was made by FSPs after a dispatching signal by the market platform (NODES).
Metering data were gathered and sent to the market platform through an API based on the same design as
the Flexible Power initiative (see Section 4.7.1) for presenting a low barrier to FSP participation. In most cases,
readings from the connection point meter were used, but, in certain cases, FSPs opted for assets’ submeter
measurements (especially for EVs). It is noted that the development of the necessary smart meter
infrastructure was a particular task undertaken by the network operator in the context of this pilot project.
Settlement was done separately for every single minute of the delivery period.
The baseline methodology defined by the network operator employed a daily profile with 48 half-hourly
periods, which was a significant departure from the current practice in the majority of UK flexibility auctions.
The baseline for each period was calculated from the average of the prior 5 completed weekday measurements
for that same period. The calculation was made on a daily rolling basis. Recognising that there may be
exceptions for some FSPs, FSPs had the option of either proposing an alternative method to more accurately
predict their baseline or defining explicitly in the NODES market platform the baseline of their portfolio; the
latter turned out to be their preferred option (Western Power Distribution, 2020; Western Power Distribution,
n.d.).
In the case of partial delivery of flexibility, there was no penalty, but there was a reduction in compensation
according to the following rules (Western Power Distribution, 2020):

(58) A fill-or-kill order is an order that must be accepted in its entirety. A minimum quantity offer is an order in which a specific minimum
quantity must be accepted.
(59) FSPs making offers proactively (i.e. without knowledge of DSO flexibility demand) is identified as a characteristic of liquid markets
in the project documentation. Nevertheless, Western Power Distribution pre-announces the required flexibility volumes in order to
attract offers owing to the relative immaturity of flexibility services provision. With variable in time and price bids, Western Power
Distribution tried to induce competition in price.

38
— 100 % payment for delivery at 95 % or above;
— a reduction of 3 % in payment for each percentage under 95 %;
— no payment for delivery below 63 %;
— no additional payment for over-delivery.

4.3.6. Results and lessons learnt

The IntraFlex project ran in two distinct trials. Six FSPs participated in each trial. Overall, 1 422 trades took
place, mostly in the second trial, with a total procured flexibility volume of 831 MWh. Offers ranged from 7 kWh
up to 5.1 MWh, while prices were in the range of GBP 60–360/ΜWh (EUR 72–432/MWh ( 60)).
A significant outcome was that, irrespective of the test parameters, the total requested flexibility volume was
never provided in full. This was mainly because, in certain periods, supply did not cover demand (given also the
price cap set by the DSO). In total, 73 % of volume was traded and 80 % was delivered (Western Power
Distribution, 2021c). One reason identified for the partial delivery was the absence of financial penalties for
under-delivery.
Regarding the issue of the information service, the interviewee expressed the opinion that FSP participation
should remain voluntary. A key outcome of the project was that, under current conditions, the auto-rebalancing
service was not of interest. This is, first, because of the low flexibility volumes with respect to BRPs’ portfolios
and, second, because the flexibility services required at the moment are in the upwards direction and BRPs do
not face a significant financial risk by being long under current conditions in the wholesale balancing market.
Nevertheless, according to the structured interview, this may change as flexibility volumes increase in the
future and/or imbalance prices change.
A significant positive outcome of the project for the buying network operator was the ease with which the APIs
that were developed were integrated into the NODES market platform. The employment of standardised APIs
is therefore seen as the main way forward for interoperability.
A particular barrier to the development of a more sophisticated flexibility market architecture in the United
Kingdom is the problematic roll-out of smart meters – even though some new flexibility assets such as EVs
have the required metering infrastructure – owing to the specific incentives provided. As regards EVs,
experience during the project showed that a pool of around 50 units permitted an effective forecasting of its
flexibility potential by the FSP (Western Power Distribution, 2021c).
Another criticality raised in the interview was the necessity of market architectures that facilitate value
stacking. The experience of the network operator shows that the value of flexibility for services exclusively to
the distribution system cannot cover the overall costs of flexibility assets, so as to make for a viable business
case on their own.
In contrast with the current, mainly long-term, procurement of flexibility in the United Kingdom, the interviewee
expressed the conviction that shorter procurement timelines offer advantages in terms of economic efficiency
and market participation by smaller flexibility assets such as EVs. In this context, the integration of local
flexibility markets within the wholesale market is an inevitable final step, but the model is unknown at present.
The high price of balancing capacity in the wholesale market at present, especially for dynamic containment
reserves, may limit participation in local flexibility markets by setting a high price floor for flexibility services
(Western Power Distribution, 2021c).
Finally, Western Power Distribution is going to continue developing innovation projects on flexibility, with future
work focusing on market architectures fostering value stacking for FSPs, implementing continuous forecasts
of flexibility needs into the market, and gathering experience with heat pumps. It was acknowledged in the
interview that the regulatory framework in the United Kingdom facilitates innovation by DSOs. Furthermore, it
is expected that the next budgetary period will focus more on implementation than on experimentation.

4.4. NorFlex project

4.4.1. General Information

— Start date: 2019

(60) Considering an exchange rate of GBP 1 = EUR 1.20.

39
— End date: 2022
— Country: Norway
— Network operators involved: Agder Energi (DSO), Glitre Energi (DSO), Statnett (TSO)
— Informative web pages:
● https://nodesmarket.com/case/norflex-tso-dso-making-local-flexibility-available-to-mfrr/
● https://www.ae.no/en/our-business/innovation/norflex-prosjektet2/what-is-norflex/
● https://www.statnett.no/en/about-statnett/research-and-development/our-prioritised-
projects/norflex/
NorFlex is an umbrella demonstration project that is being run from 2019 to 2022 by two Norwegian DSOs
(Agder Energi and Glitre Energi) and Statnett, the national TSO. The main focus of the project is the activation
of flexibility for network expansion deferral and congestion management in the distribution system, while
residual flexibility is aggregated to offer mFRR services to the TSO ( 61). The pilot project is divided into three
development phases: the proof of concept phase in 2019–2020, the proof of market phase in 2020–2021 and
the market ready phase in 2021–2022. Only during the final phase has flexibility trading taken place. During
the first phase, successful data exchanges were established, while, in the second phase, the necessary tools
for the DSOs (congestion forecasting) and FSPs (asset optimisation) were developed.
Independent aggregators participate in the pilot project thanks to an exception from the current regulatory
framework in Norway (NODES, 2022).

4.4.2. Pre-qualification procedures

Any flexibility asset must register in a flexibility data register (FDR) ( 62) before placing offers in the flexibility
market. The FDR is common to both the TSO and the DSOs for achieving a coordinated, efficient and secure
active system management process, given that a flexibility resource can deliver multiple flexibility services to
network operators. The concept of an FDR is central to the vision of Norway’s network operators on flexibility
(Pedersen, 2021a). It is important to note that the FDR belongs to the regulated domain. It is also clarified that
the definition of a flexibility asset in the NorFlex project extends below the connection meter, down to individual
device level (e.g. a floor heater).
Owing to the pilot nature of the NorFlex project, the developers chose not to impose any pre-qualification
processes other than registration in the FDR, the successful upload of metering data to it and effective data
communication with the trading platform (NODES). Therefore, all registered flexibility assets with a nominal
capacity above 1 kW qualify for testing in the NorFlex pilot. A particular focus of the project is testing the
technology that the aggregators use to collect data from flexibility assets.

4.4.3. Flexibility products

Both availability and activation products are traded in the NorFlex marketplace.
Availability products are procured 1 month in advance and are of weekly duration. Both the availability and the
activation price are predetermined by the buying party (DSO) and reflect the investment deferral opportunity
cost (Pedersen, 2021a).
The minimum bid size for both availability and activation products is 1 kW, and bids are divisible.

4.4.4. Market architecture

The NorFlex project set up a marketplace in which only network operators procure flexibility, with the DSO
having precedence over the TSO. Trading for flexibility services to the DSOs is organised per congestion area
in the 132 kV grid downwards. After the DSOs have covered their needs, the residual flexibility is made
available to the TSO mFRR market (from the winter of 2021/2022) in minimum blocks of 1 MW.

(61) Note that, in the Nordic countries, redispatching and countertrading are undertaken based on offers submitted in the mFRR order
book. Therefore, residual flexibility passed to the mFRR market can be used for both redispatching in the transmission system and
system balancing.
(62) For information on the FDR (or flexibility resources register) concept, see CEDEC et al. (2019).

40
Availability products are procured 1 month in advance. For activation products, continuous trading is employed.
Trading starts after the buying DSO publishes on the marketplace the volume and bidding price for the next
week for the time window 7.00–19.00 (for the winter of 2021/2022) (Pedersen, 2022). Moreover, in the winter
of 2021/2022, flexibility trading was also tested during night hours owing to congestions in the distribution
system caused by high levels of EV charging in response to wholesale price differentials. These price
differentials were pronounced in the winter of 2021/2022 owing to the energy crunch situation throughout
Europe. Announcements are made only to the marketplace and there is no dedicated communication to FSPs.
The aggregators can place bids up to 2 hours before activation, while the buying network operator can update
its bids during the trading period. The definition of the gate closure time 2 hours before delivery aimed, among
other things, to ensure coordination with the wholesale balancing market, to which uncleared flexibility offers
are passed.
The MTU is 60 minutes, which is equal to the current imbalance settlement period in Norway. The clearance of
offers is made based solely on price.
There is not an established TSO–DSO coordination platform at the moment. Work is ongoing on an additional
service at the FDR through which the TSO and DSOs will exchange information when they expect that flexibility
activation may affect parts of the network outside their responsibility.

4.4.5. Activation and settlement procedures

Activation of cleared offers in the order book takes place automatically by the buying network operator without
pre-announcement (Pedersen, 2021b).
The measurement period is 1 minute, and settlement is made based on this time granularity. The buying
network operators, through the FDR, also record measurements both 2 hours before flexibility activation and
2 hours after activation to better assess rebound effects, but they would like to extend this to continuous
recording to be able to assess baselines better in the future (Pedersen, 2021a).
Given that assets in the NorFlex flexibility market are defined at device level, measurement from submeters
are employed. Metered data are uploaded to the FDR, while the baseline is uploaded by the FSPs in the market
platform 24 hours before activation at the latest. Nevertheless, the baseline can be adjusted by the aggregator
up to 2 hours before activation (i.e. at gate closure).
Remuneration of availability products is made subject to the submission of activation offers. No penalties apply
for partially delivered flexibility services (for both availability and activation products), but reduced
compensation below 80 %. When flexibility provision is less than 50 % of the cleared offer, the remuneration
drops to zero. There is no additional remuneration for over-delivered flexibility.
Balance responsibility is undertaken by the BRPs of the flexibility assets. In the future, compensation by the
FSP to the BRP for the pre-bought energy by the latter is expected to be handled through the FDR.

4.4.6. Results, lessons learnt and future developments

In 2021, 28 weeks of trading took place in the pilot project. Most trading was fictional, in the sense that the
purpose was testing the trading process rather than solving actual congestions, which is only the case for
winter of 2021/2022. From 2022, flexibility offers that are not used by the DSOs are being forwarded to the
wholesale balancing market.
Currently, 10 FSPs participate in the NorFlex market, representing all types of end-customers (residential,
commercial and industrial) (NODES, 2022). Flexibility assets include batteries, electric boilers, ventilation
systems, greenhouses, EV chargers (alternating current (AC) and direct current (DC)) and other household
devices. The project developers aimed to include larger industries during the winter of 2021/2022. The liquidity
in the ShortFlex continuous market has proven to be larger than in the LongFlex owing to both the supply side
(the characteristics of the flexibility assets in participating FSPs’ portfolios) and the demand side (larger
variability of power flows in the network forcing the buying network operators to update their flexibility needs
closer to real time). On the other hand, the price of flexibility in the ShortFlex was significantly larger than in
the LongFlex.

41
According to the publicly available results ( 63), 225 MWh of flexibility was procured in the NorFlex market in
2021, with a weighted average price of NOK 6 593/MWh (EUR 659.3/MWh ( 64)).
Based on the survey results, network operators foresee that there will potentially be the need for steady-state
voltage control and fast reactive current injection flexibility services in the future.
Issues raised during the interview included the following (Pedersen, 2021a).
— Congestions are increasing in the Norwegian network, both at distribution and at transmission level. This
is because of three main factors: (1) the electrification process, especially in the transport sector, where
fast-charging stations pose a particular challenge, followed by new battery factories, data centres and
green hydrogen facilities; (2) an increase in wholesale exports; and (3) new wind capacity. In addition, the
network in Norway is quite old and requires modernisation.
— According to the interviewee, market-based procurement of flexibility should be the preferred option if
there are resources available. Regulated tools, such as special network tariffs and flexible contracts offered
in exchange for the right to disconnect demand at critical situations, should be used only as a back-up
solution.
— The preferred architecture for a flexibility market is a marketplace in which both DSOs and the TSO can
procure flexibility services from distributed sources. The interviewee were of the opinion that, for the mid-
term (i.e. for the next 10 years), direct participation of distributed resources in the TSO’s wholesale
balancing and redispatching markets may prove a costly direction, owing to the current lack of observability
of such assets by TSOs. Instead, procurement of services by local flexibility markets, also serving DSOs,
would be easier (i.e. a cascade market architecture).
— The lack of standardisation regarding data format and communication protocols is a significant barrier to
the development of local flexibility markets, introducing complexity and additional costs. This does not
concern only FSPs but extends also vertically, affecting the data exchange between DSOs and national
TSOs. Harmonisation to CIM is the long-term solution, but at present APIs are a practical way forward.
— Adaptation of FSPs’ systems to the two APIs employed in the NorFlex project, one for the NODES market
platform and the other for the FDR, proved both lengthy (1 year) and costly. Furthermore, in the case of
one FSP, it was unsuccessful. It is noted that the costs in all cases were undertaken by the project
promoters.
— A second challenge in the development of the flexibility market was grid tools for congestion forecasting
at DSO level. This required a considerable effort in increasing the observability of the distribution network
in which the pilot project was taking place, with the installation of 8 000 sensors. The whole process took
1 year.
— FSP business models are in development. The challenges faced by them include both how to value stack
between separate markets and the development of the required intelligence for portfolio optimisation,
including better prediction of their baselines. Moreover, trading automation by FSPs is currently less
advanced than that of network operators, who already deploy robots for setting bids.
— Overall, technological solutions for the various systems (e.g. grid forecasting and aggregator optimisation
tools) do exist, but they are still expensive, which has a negative impact on the business case. The
interviewees expressed the opinion that financial support should be provided for building the required
intelligence for flexibility provision, similar to the support given for RES development.
— On baseline methods, the establishment of baselines for heating loads proved particularly challenging.
Project promoters are still open to different options and they are testing different models with different
time resolutions. An alternative to FSP schedule declaration could be baselines being forecasted in the FDR
and then proposed to FSPs. For this, continuous measurement recordings from flexibility assets
complemented by other parameters (e.g. temperature) would be needed.
— Establishing baselines proved easier for flexibility coming from households, as opposed to office and public
buildings, because data availability on their consumption characteristics is high even at device level (e.g.
floor heating, water heaters and EV chargers), as many suppliers already collect these data. Medium-sized
and large industries already offer flexibility to the wholesale balancing market and have well-established

(63) https://nodesmarket.com/norflex/
(64) Considering an exchange rate of NOK 1 = EUR 0.10.

42
 baseline forecasts. Overall, these resulted in flexibility offers coming from FSPs having in their portfolio
industrial sites and/or (pools of) households being cheaper.
— Regarding penalties for partially delivered flexibility, these should probably be introduced in the future,
particularly for availability products.
— Meter data, as well as baselines, should be collected and validated in the FDR, which is in the regulated
domain, as opposed to the market platform, which is in the commercial domain. The main argument for
this is that congestion management and balancing are regulated processes run by network operators. The
FDR could undertake all data and intelligence processes for settlement verification, while financial
transactions would be under the responsibility of the market platform. In addition, a solid method regarding
the compensation between independent aggregators and BRPs could be established in the FDR. In fact,
this is the only option, according to the interviewee. Nevertheless, the interviewee questioned the value of
such a process for flexibility activation by small assets (e.g. below 100 kW) or the BRP’s actual interest,
given the natural variability of demand. Finally, the FDR could be the basis for the development of
additional flexibility products, such as for voltage control, given that it is the central point where all
necessary technical characteristics (location, type of asset, nominal capacity, etc.) and pre-qualification
compliance of assets are registered.
— It is accepted that flexibility for solving congestions in the distribution system will be priced higher than
flexibility provision for system balancing. How high this price differential can go is one of the parameters
about which the DSOs want to accumulate experience through the NorFlex pilot project. In addition, it is
expected that competition for services by flexibility assets connected to the distribution system will develop
in the future between DSOs and the TSO.
— The vision of the project promoters is heavily based on automation, as flexibility will be traded closer to
real time and with shorter MTUs, in line with the developments in the wholesale market.
— The national regulatory authority follows the project very closely and wants the project promoters to
provide recommendations, especially on the FDR and on overall data management considerations such as
cybersecurity, privacy and end-customer consent.

4.5. GOPACS

4.5.1. General information

— Start date: December 2018
— Status: ongoing
— Country: Netherlands
— Network operators involved: TenneT (TSO), Coteq (DSO), Enexis (DSO), Liander (DSO), Rendo (DSO), Stedin
(DSO), Westland Infra (DSO)
— Website: https://en.gopacs.eu/
GOPACS was one of the first TSO–DSO coordination platforms implemented for solving network congestions.
GOPACS is integrated into the existing sequence of wholesale markets by resourcing flexibility from existing
market platforms. So far, the only collaborating market platform has been the Energy Trading Platform
Amsterdam (ETPA) ( 65), but, from May 2022, the participation of EPEX SPOT ( 66) was also announced (Stufkens,
2022 ; EPEX SPOT and GOPACS, 2022).
All network operators in the Netherlands participate into the initiative, albeit with significantly differing levels
of flexibility service procurement through the platform, with the main buyers being TenneT (first by a large
extent) and Liander (second) ( 67). In the only currently connected wholesale market platform (ETPA), it is mainly
medium-sized and small commercial customers that operate. This platform represents only a small volume of
the total wholesale trade in the Netherlands, but the participation of EPEX SPOT, by far the largest power
exchange in the Netherlands, is going to change that.

(65) https://etpa.nl/
(66) https://www.epexspot.com/en
(67) The market data is available online (https://idcons.nl/publicclearedbuckets#/clearedbuckets).

43
4.5.2. Pre-qualification procedures
To participate in the intraday congestion spread (IDCONS – see the next section for the definition), market
parties must be connected to a trading platform that supports the product. In addition, they must sign the
IDCONS participation agreement (Stedin et al., 2019). After having received confirmation of completion of the
pre-qualification process by email, the relevant market party and the relevant trading platform receive
confirmation from GOPACS.
The IDCONS participation agreement contains:
— a declaration of acceptance of IDCONS product specifications;
— a declaration of acceptance of IDCONS privacy conditions;
— the name of the trading platform at which the market party wants to place orders for IDCONS;
— a list of the European article numbering (EAN) codes ( 68) that the market party wants to use on the trading
platform for IDCONS.
After having received the IDCONS participation agreement, grid operators have to first process the new EAN
codes internally before orders with these EAN codes can appear as IDCONS. This process includes an evaluation
of the impact of activated flexibility on the network. The pre-qualification process takes a maximum of 5
working days. After completion of this registration, the market party receives a confirmation by email.
The pre-qualification process does not contain an explicit check of the consent by the contracted party or
customer of the specified EAN codes. Obtaining consent is the responsibility of the FSP, as is coordination with
the BRP for the connection.
Finally, the pre-qualification process does not include physical (ex ante) tests (Stedin et al., 2019).

4.5.3. Flexibility products

A fundamental feature of the GOPACS architecture is that the buyer grid operator effectively undertakes
balancing responsibility in respect to the system. Therefore, any procurement is a combination of two orders
(a buy order and a sell order), packaged into a standardised product: IDCONS (Trienekens, 2020). The buy and
sell orders have the same format as intraday wholesale orders (simple bids of 15 minutes or 1 hour), and the
orders agree in terms of the starting time, volume and duration, but are in different areas. For example, when
a congestion occurs in one part of the network due to high load, one energy sell order will be procured by
GOPACS in that part of the grid. At the same time, in a non-congested area, an energy buy order will be
activated. As such, system imbalance is avoided. The price of the energy sell order will be higher than the price
of the energy buy order (otherwise the trade would take place in the wholesale intraday market). The network
operator that requests the flexibility pays the spread between the orders. There are no minimum or maximum
prices or volumes defined for IDCONS.
It is noted that DSOs in the Netherlands have long-term bilateral contracts with FSPs that can also be available
to the TSO. The central idea behind the IDCONS product specification (i.e. keeping system balance when
activating flexibility for congestion management) is also retained in the case of long-term contracts (Stufkens,
2022).

4.5.4. Market architecture

GOPACS, as already mentioned, is not a market platform, but it uses orders in existing wholesale electricity
markets. The ETPA is the first market platform to have joined GOPACS. Participating parties trade electricity by
placing buy orders and sell orders in the ETPA market platform.
In the ETPA, the flexibility offers that can be employed in GOPACS are seen as a subset of the wholesale
continuous intraday order book. FSPs have the option to offer the same flexibility at two different prices by
placing two orders (e.g. one portfolio offer for the intraday wholesale market and a second offer with locational
information, the EAN codes, which is necessary for participation in GOPACS). The flexibility provider is
responsible for avoiding double activations, and verification of compliance is conducted by the market platform
(i.e. the ETPA). Therefore, in principle, network operators and market parties (BRPs) compete for the same
flexibility, but, effectively, only offers that are not financially acceptable by the latter become available for the
former (assuming that both have the same level of trading automation and speed). The MTU in GOPACS is

(68) The EAN code is a unique number that identifies a connection to the electricity network.

44
15 minutes, the same as in the wholesale intraday market. Like the wholesale intraday market, GOPACS
employs pay-as-bid pricing and acts as a continuous procurement mechanism.
Grid operators pre-announce their flexibility needs (volume, time, duration and direction) to solve congestions
in specific areas (defined with postal codes and/or regions) less than 24 hours before activation, and sometimes
even only 6 hours in advance (Stufkens, 2022). They use their own tools and processes to determine
congestions and to evaluate the potential contribution of orders with location indication to solve the transport
restriction. There are some formal fixed congestion areas, but network operators can also form an ad hoc
IDCONS for solving congestions outside these (Stufkens, 2022). In all cases, along with location, the
fundamental criterion for the creation of an IDCONS is the price differential between the sell and the buy
orders. Furthermore, the grid operators prevent an IDCONS from causing or aggravating transport restrictions
elsewhere in the grid when they create them.
The nomination of orders as part of IDCONS is done according to the rulebook of the connected wholesale
trading platform. Therefore, cleared orders as part of an IDCONS are administered as a trade between the two
market parties involved. This means that the general rules, processes and agreements for the nomination of
such a trade of the relevant trading platform are applicable. FSPs participating in the ETPA are charged with
an entry fee, a monthly fee and a fee per interchanged MWh. Grid operators owe a fee to the market platform
for the use of IDCONS.
Figure 3 provides a schematic view of the GOPACS architecture, while Figure 4 depicts the grid and market
interactions.
Figure 3: GOPACS architecture

Source: EUniversal UMEI deliverable D2.1 ( 69).

(69) https://euniversal.eu/deliverables/

45
 Figure 4: Grid and market interactions in GOPACS

RT: Real-time
EMS: Energy Management System
DMS: Distribution Management System
SCADA: Supervisory Control and Data Acquisition
DERMS: Distributed Energy Resources Management System
GIS: Geographic Information System
ID: Intraday
Source: Presentation from Stedin ( 70).

4.5.5. Activation and settlement procedures

Given that GOPACS is not a market platform as such, but trading is done through a wholesale intraday
marketplace, activation and settlement procedures follow the provisions of the latter. In principle, settlement
is made on a congestion area portfolio basis, even though, in practice, most FSPs are rather small and have
only a single connection point (Stufkens, 2022).

4.5.6. Results and lessons learnt

So far, the main network operator making use of GOPACS is the Dutch TSO (TenneT), with Liander (DSO) coming
in second. Aggregate results for all network operators that have procured services through GOPACS are
provided in Table 7. The procurement unit flexibility cost for the DSO Liander is approximately 1.5 the cost for
the TSO (TenneT). This is mainly due to lower liquidity for solving congestions in specific parts of the distribution
network.
To date, around 500 FSPs have submitted offers for GOPACS. Generally, they are small in size and mostly
represent commercial, residential and greenhouse facilities with a portfolio capacity lower than 60 MW
(Stufkens 2022).
Table 7: Aggregate results for the flexibility services procured through GOPACS for 2021
TenneT Liander Enexis
Total activated flexibility volume (MWh) (*) 142 997.6 111.3 24.8
Total cost (EUR, thousands) 45 014 52 16
Average cost of activated flexibility (EUR/MWh) 314.8 467.2 645.2
(*) In the calculation, only the upwards volume is considered.
Source: JRC calculations based on the costs for using IDCONS for redispatch ( 71).
The following points were raised in the interview (Stufkens, 2022).

(70) https://www.slideshare.net/dutchpower/3-peter-hermans-stedin
(71) https://idcons.nl/publicexpenses#/expenses

46
— The main drive behind the development of GOPACS was to exploit the significant flexibility resources in
the distribution network. When the platform was developed, only the TSO had need of such services, but
DSOs were soon likely to encounter similar challenges in their network. The factors behind the increasing
congestions in the Netherlands are electrification and the expansion of the capacity of variable RESs
(vRESs: wind and solar photovoltic power generation units).
— The retainment of balance at system level was central to the market architecture of the GOPACS initiative
and this will remain so for all congestion management processes in the future. Furthermore, an intraday
market was preferred, as the project promoters chose to procure flexibility as close as possible to real time
when congestions occur.
— Standardisation of flexibility products and procurement processes also for long-term contracts is one of
the main goals of the network operators roadmap on flexibility. A second main goal is coordination between
different markets, and more specifically the procurement of flexibility coming from assets in the
distribution system for congestion management and for system balancing. It was noted that the Equigy
platform ( 72), which aims to facilitate the provision of system balancing services by DERs, is already rolled
out in the Netherlands. It was also noted that the rules for redispatching, including from sources in the
transmission system, are going to change in 2022 in the Netherlands, which adds another challenge to the
overall coordination effort. All in all, the interviewees had the opinion that the integration of the different
markets for network services will take time, even though the need is clear.
— Processes by DSOs regarding security analysis in their networks are improving. The TSO is already at an
advanced stage with the capability of running such analyses every 5 minutes. DSOs do not use the common
grid model, and the interviewee’ opinion was that they are still quite far from CIM harmonisation. Therefore,
coordination between DSOs and the TSO in GOPACS is not undertaken in a particularly automated way,
and each network operator is separately responsible for assessing the impact of an IDCONS formation in
its own area.
— Regarding the required network services from DERs in the next 5 years, the interviewees identified
frequency response as the most important one. Black-start capability is provided by large units and there
is no additional need, while inertia response is seen as a potential requirement only for the far future.
— At TSO level, flexibility is incorporated as an alternative to classic network expansion, with a significant
assessment criterion being the time to materialisation of each option.

4.6. enera Flexmarkt

4.6.1. General information

— Start date: February 2019
— End date: June 2020
— Country: Germany
— Network operators involved: TenneT (TSO), Avacon Netz (MV and HV DSO), EWE NETZ (MV and LV DSO)
— Main website: https://projekt-enera.de/
The enera Flexmarkt, which focused on network congestion management, was developed in the context of the
enera research programme under the smart energy showcase — digital agenda for the energy transition
(SINTEG) funding programme ( 73). The participating grid operators were EWE NETZ (MV and LV DSO), Avacon
Netz (MV and HV DSO) and TenneT (TSO). The market platform was provided and operated by the EPEX SPOT
power exchange.
The project has been rolled out in the counties of Aurich, Friesland and Wittmund. A particular characteristic of
the local power system is the very high renewable penetration, reaching 235 % of the local electricity demand.
Therefore, a particular goal of the project has been the reduction of renewable curtailment for alleviating
network congestions and of the associated costs for network operators. This contrasts with other local flexibility
markets reviewed in this report, in which the main source of congestions was consumption, rather than vRES
production.

(72) https://equigy.com
(73) https://www.sinteg.de/en/

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4.6.2. Pre-qualification procedures
First, flexibility providers had to register their assets into a FDR. The pre-qualification process included only the
technical characteristics of flexibility assets (mainly nominal capacity and location). In principle, no minimum
nominal capacity limits of flexibility assets were established, but, in practice, the participating assets were
relatively large (more than 500 kW) (Gertje, 2021a). Responsible for the whole pre-qualification process was
the connecting network operator. Overall, the pre-qualification process was rather light owing to the pilot nature
of the project (Gertje, 2021a).

4.6.3. Flexibility products

Flexibility products for short-term congestion management (up to TSO level) were traded in the enera
marketplace. The European power exchange EPEX SPOT operated the enera Flexmarkt using the same platform
as the existing intraday market, with small modifications, as market processes were quite similar. Using a well-
known market platform also led to low market entry barriers for flexibility marketers. Fifteen-minute and 1-
hour energy (activation) products were traded. In principle, there was no nominal minimum bid size, but, in
practice, the lowest bid was 50 kW (Gertje, 2021b). Bids were divisible. It should be noted that the unit
compensation for forced renewable curtailment paid by network operators represented an effective price cap
for the activation of flexibility.

4.6.4. Market architecture

Trade was organised in 23 different local market areas, each one corresponding to a local transformer. The
maximum voltage level per local market area was 20 kV, but flexibility activations inside each area could be
used for solving congestions up to transmission level (i.e. all upwards network operators were also included as
buyers of flexibility) (Gertje, 2021b). FSPs offered flexibility on a portfolio basis per local market area.
Flexibility trading was starting when a network operator was predicting a congestion, and a notification was
sent to FSPs through the market platform and via email. At the same time, FSPs could also place offers,
irrespective of whether or not there was an announcement by network operators. Notification of flexibility
demand by network operators depended on grid status forecast. A relatively good view on potential congestions
was possible 3 days ahead, but obviously the forecast became better closer to real time. On the other hand,
flexibility offers closer to real time were becoming more expensive, so there was a trade-off for buying network
operators. Overall, notification of flexibility demand took place between 3 days and 1 hour ahead (Gertje,
2021a).
Nominally, the gate closure time was 15 minutes before delivery, but most offers were cleared by network
operators some hours before (Gertje, 2021b; Lahmar 2021a). The enera Flexmarkt operated based on
continuous trading, similar to the intraday wholesale market. The MTU was 15 minutes. There was an order
book for each of the 23 local market areas, which was different from the order book of the wholesale intraday
market.
The evaluation of offers was made solely based on price. However, before the clearing of an offer, negotiation
between the buying network operator and the FSP could be made: the network operator either accepted the
offer or made a counteroffer. In the latter case, the FSP had to accept, deny or make a counteroffer in turn
(Gertje, 2021a). In practice, successful offers were mostly cleared without further negotiation and thus the
market operated mostly like having a pay-as-bid pricing mechanism.
The regulated penalty paid by network operators when RES are forcefully curtailed for solving congestions
effectively played the role of a price cap in the enera local flexibility market. Even though the rules governing
the calculation of this penalty are publicly known, the exact value is known ex ante to market participants
because this depends on the exact RES category that is curtailed (Gertje, 2021a). Given that regulated RES
curtailment was always available for solving congestions, the main aim of the enera Flexmarkt project was
economic efficiency.
Coordination between network operators was made in a cascading top-down direction: the upstream system
operator informed its downstream counterpart about the amount of power to procure via the marketplace and
notified its congestions. This information was processed by the downstream operator, which returned the
applicable capacity restrictions (i.e. the maximum amount of power that the upstream operator was able to
procure from each local market area) (enera, 2020). This also effectively meant that the downstream network
operator had priority regarding the utilisation of flexibility potential in its network (this is also the case for the
regulated redispatch procedure in Germany). The coordination processes between network operators were

48
conducted in isolation from the market platform and it was done in a separate grid prognosis tool developed
in the enera research project (Gertje, 2021a).

4.6.5. Activation and settlement procedures

Activation was made by the FSPs after clearance of their orders in the enera Flexmarkt. Communication was
made through the market platform.
Settlement was based on a comparison of the metered input (or output) of the flexibility assets against a
schedule provided by the flexibility providers per local market area, which acted as a baseline (Gertje, 2021b).
The measurement and settlement period was 15 minutes. In the context of the enera project, an ex post
methodology for the identification of possible inc-dec gaming was also developed (Stein, et al., n.d.).
Data communication was addressed in a centralised way. All of the required data, such as measurements,
baselines, cleared offers and RES forecasts, were delivered to a centralised data hub: the Smart Data and
Service Platform (SDSP). The platform was run by an independent data manager. This was an intentional choice
to ensure that no particular power network operator owned all of the data. In the SDSP, all of the relevant tools
for the functioning of the flexibility market were built, such as the FDR, the grid prognosis tool, the verification
of flexibility activation and the market platform (Gertje, 2021a).
Participation of independent aggregators was permitted in the enera Flexmarkt. The balance responsibility fell
on the BRP of the flexibility assets, which was then usually self-balancing in the intraday wholesale market. On
the other hand, the FSPs were compensating suppliers for the pre-bought energy by the latter. The level of
compensation was defined by bilateral agreements as per the German law provisions applicable at the time
(Lahmar, 2021b).
In the case of partial flexibility delivery, compensation dropped to zero, while there was no additional
compensation for over-delivery. In the contractual agreement for participating in the enera Flexmarkt, penalties
were also set for partial delivery of flexibility, but these were set to zero owing to the pilot nature of the project
(Gertje, 2021a).

4.6.6. Results and future developments

Overall, more than 4 000 orders were submitted and 130 transactions took place in the enera Flexmarkt (EPEX
SPOT, 2020). The flexible capacity participating in the project reached 360 MW by six FSPs. Flexibility resources
ranged from wind farms, biogas plants, photovoltaics and storage devices to power-to-gas, power-to-heat and
gas compressors (enera, 2020). Flexibility from the demand side was around 50 MW owing to the economic
characteristics of the area in which the pilot project took place (relative lack of big energy consumers) (Gertje,
2021a).
The enera Flexmarkt remained a pilot project and was not continued. A key reason for this were the regulatory
decisions regarding redispatching in Germany. Under current developments, redispatching remains a regulated
process in which demand cannot participate. The enera partners have submitted a proposal for a hybrid scheme
in which regulated redispatching and non-regulated assets (demand facilities and non-remotely controllable
distributed generation (DG) of less than 100 kW) offering their flexibility services based on free offers would
co-exist (enera, 2020). In June 2021, the Ministers Of Economics of the German Federal States adopted a
decision calling for the market-driven development and use of flexibilities in the distribution grid ( 74).
During the interview with the representative of EWE NETZ, the following interesting points were made.
— There was difficulty in recruiting FSPs. The flexibility market made a weak business case for them.
— Congestion management is an almost structural issue in the German network, particularly at transmission
level. Network operators face significant costs, especially as regards compensation to RESs, which must
be curtailed. Enhancing the economic efficiency of redispatching actions was one of the main reasons
behind the development of the enera Flexmarkt project.
— For mature local flexibility markets, penalties should be imposed in the case of partial delivery.
— According to the interviewee, the project was quite a success. However, the possibility of inc-dec gaming
is considered a significant issue posing a high risk, which possibly makes a rule-based approach to
redispatching safer. The risk of inc-dec gaming is further aggravated by the fact that the network operator

(74) https://nodesmarket.com/germany-master-plan-for-flexibility-in-brandenburgs-distribution-networks/

49
 must develop a forecast for vRES flexibility assets and cannot rely solely on baseline declarations by the
FSPs.
— The regulatory derogations provided in the context of the SINTEG research programme were fundamental
for the development of the enera project. Nevertheless, there could be more room for innovation.
— All relevant resources of network operators are now channelled into the implementation of Redispatch 2.0.
In the interviewee’s view, the development of local flexibility markets in a hybrid scheme could be a next
step when Redispatch 2.0 is fully implemented and consolidated.
During the interview with the representative of EPEX SPOT, the following notable points were made.
— EPEX SPOT expects a variety of services, beyond congestion management, to be procured through local
flexibility markets by DSOs in the future, with the first being voltage control / reactive power services.
Nevertheless, local flexibility markets for congestion management should be consolidated first.
— Both long-term/availability and short-term/activation products will probably be requested in future
flexibility markets, subject to the specific network needs in each case. Long-term contracts are aimed more
at network deferral, while short-term activation products are aimed at congestion management.
— Even though current short-term local flexibility markets follow the continuous pay-as-bid paradigm, the
interviewee held the opinion that auction-type pay-as-clear markets may be a valid alternative for the
following reasons: (1) better price formation, (2) better coordination between the different network
operators towards co-optimisation of the procurement process and (3) easier market monitoring. Given
that flexibility is not continuously needed by network operators, auctions would take place only when the
need would arise. In critical cases, a further possibility could be cascading auctions during the day. (It is
noted here that the Platone Horizon 2020 project ( 75) also investigates an auction-type short-term local
flexibility market architecture.)
— The current architecture of different markets for flexibility services (e.g. for congestion management in the
distribution system as opposed to system balancing) will continue for the foreseeable future. Nevertheless,
better coupling/coordination between them should start to be addressed.
— On baseline methods, both centrally defined baselines by the market operator and/or the buying network
operators and FSP schedules are valid approaches, depending on the specific technological characteristics
of the underlying flexibility assets.
— Penalties for partial delivery of flexibility may be needed in the future for fostering FSP responsibility.
— Contractual relationships between independent aggregators and BRPs is a difficult issue to address. A way
forward may lie in bilateral agreements with a back-up regulatory framework playing the role of a safety
net.
— Regarding the governance framework of future local flexibility markets, the interviewee held the view that
both market platforms operated by independent market operators and marketplaces run by network
operators will be developed in Europe. In the latter case, power exchanges such as EPEX SPOT would play
the role of service provider for the development of the market platforms.
— In the case of local flexibility markets run by independent operators, these could undertake legal
compliance of market parties and financial risk management. Technical pre-qualification procedures
should always remain under the buying network operators’ responsibility.
— According to the interviewee’s personal view, the main reason for the decision of the German regulator to
opt for the continuation of rule-based redispatching was the fear of inc-dec gaming. However, this decision
comes at the expense of reduced liquidity for congestion management services, as demand is left out and
there is a lack of incentives for incorporating flexibility as an alternative in long-term network development.
Furthermore, flexibility markets may be easier to implement technically. Overall, the interviewee expressed
the opinion that a hybrid model in which rule-based and market-driven flexibility provisions coexist, as
proposed by the enera project promoters, may become the way forward at some point in the future in
Germany.

(75) https://www.platone-h2020.eu/

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— Inc-dec gaming should be not considered a showstopper for the development of local flexibility markets,
but instead should be considered an issue of regulatory supervision and market surveillance, for which
methods can be developed (with statistical analysis being one of them).
— Effective national implementation of the recast electricity regulation and electricity market directive will
be catalytic for the development of local flexibility markets in the EU.
— Finally, it is noted that EPEX SPOT is planning to connect with GOPACS in the Netherlands, and it recently
invested in increasing its own technical capabilities for developing local flexibility market platforms ( 76).
Baseline provision and verification of flexibility activation are among the services intended to be provided.
Nevertheless, for the latter, network operator validation will always be crucial.

4.7. UK flexibility tenders

4.7.1. General information

— Initiation year: 2018
— Status: ongoing
— Country: United Kingdom
— Network operators involved: all UK DSOs
— Web page: https://www.energynetworks.org/creating-tomorrows-networks/open-networks/flexibility-
services
In December 2018, the first tenders for the provision of flexibility services to certain UK DNOs took place, with
the intention for this to become a business-as-usual activity. Separate tenders are called from each DNO, but
a structured harmonisation effort regarding the whole process of local flexibility procurement (standardisation
of contracts, product specification, baseline methodology, cost–benefit analysis against classic network
expansion, etc.) is undertaken in the context of the open networks programme of the ENA ( 77). The tenders are
aimed at network deferral, congestion management, reliability enhancement and support for network re-
energisation, and they led to long-term contracts between DNOs and FSPs.
An increasing volume of flexibility has been procured each year, reaching 2.9 GW in 2021 (ENA, 2022a). There
are two main platforms through which FSPs can participate in the tenders: Piclo Flex ( 78), which is an
independent trading platform used by Electricity North West, NIE Networks, SP Energy Networks and UK Power
Networks in 2021, and Flexible Power ( 79), which is a joint initiative by Western Power Distribution, Northern
Powergrid, Scottish and Southern Electricity Networks, SP Energy Networks and Electricity North West. It is
noted that, alongside flexibility tenders, DNOs in the United Kingdom also employ flexible connections as a
flexibility instrument.

4.7.2. Pre-qualification procedures

The procurement platform first performs an automatic pre-qualification for every flexibility asset (location,
voltage level, etc.) and then the DSOs perform a deeper screening based on pre-qualification questionnaires.
The latter are currently being digitalised in Piclo Flex (Anagnostopoulos, 2022). These questionnaires include
questions on the assets’ technical characteristics (location, voltage, minimum capacity, run-up and ramp-up
times, communication system, metering, and compliance with applicable network code requirements) and
flexibility providers’ commercial assessment (corporate regulatory obligations, legal offences, creditworthiness,
conflicts of interest, etc.). The assessment is conducted through dynamic purchasing systems, which either
belong to the DSO or are provided as a service by the market platform (ENA, 2020a; Anagnostopoulos, 2022).
The information gathered in the pre-qualification questionnaires forms the basis of a register similar to the
FDR. In principle, all types of assets are accepted, in every phase of development (i.e. from projects in the
planning stage to fully operational assets). The minimum required flexible provision capability of a flexibility

(76) https://www.epexspot.com/en/news/new-trading-platform-boosts-epex-spots-localflex-offer
(77) https://www.energynetworks.org/creating-tomorrows-networks/open-networks/
(78) https://picloflex.com/
(79) https://www.flexiblepower.co.uk/

51
asset varies between DNOs from 10 kW to 50 kW. The qualification period by the network operator is usually
2 weeks (Aithal, 2021; Anagnostopoulos, 2021a). Asset testing is conducted after a contract is signed between
a DSO and an FSP (i.e. after a winning offer by the latter in a flexibility tender) to verify the capability of the
assets to provide the flexibility product.

4.7.3. Flexibility products

Currently, there are four active power services, defined as follows (ENA, 2020b; Flexible Power, 2022).
1. Sustain. The network operator procures, ahead of time, a pre-agreed change in input or output over
a defined period to prevent a network going beyond its firm capacity. The requirement windows for
provision of the service are scheduled and fixed in the contract. This product aims at investment
deferral.
2. Secure. The network operator procures, ahead of time, the ability to access a pre-agreed change in
service provider input or output based on network conditions close to real time. Secure requirements
are declared 1 week ahead. Payments consist of a fee that is credited when the service is scheduled
and a further utilisation payment awarded on delivery. This product aims at congestion management.
3. Dynamic. The network operator procures, ahead of time, the ability of a service provider to deliver an
agreed change in output following a network abnormality (including scheduled maintenance).
Remuneration consists of an availability and a utilisation component. FSPs are expected to be ready
to respond to utilisation calls within 15 minutes. Dynamic availability windows are declared 1 week
ahead. This product aims at enhancing network reliability.
4. Restore. Following a loss of supply, the network operator instructs a provider to remain off supply,
reconnect with lower demand, or reconnect and supply generation to support increased and faster
load restoration under depleted network conditions. As the requirement is inherently unpredictable,
this product is based solely on a premium ‘utilisation only’ compensation component. FSPs that are
declared to be available for this service are expected to respond to any utilisation call within
15 minutes. This product aims at supporting re-energisation of the network.
A description of the parameters of each service is provided in Table 8 and Table 9. The divisibility of bids
depends on the DNO and the product.
For the abovementioned services, work is ongoing to standardise the parameters. Currently, six flexibility
product parameters for convergence and implementation have been proposed.
1. Minimum flexible capacity. This is the minimum flexible capacity an FSP may make available to the
DNO. This can be made up of aggregated or non-aggregated DERs.
2. Minimum utilisation. This is the minimum amount of time a DNO will require for the provision of a
flexibility service from an FSP, following a utilisation instruction.
3. Minimum utilisation duration capability. This is the minimum amount of time that an FSP must be able
to continually hold its contracted flexible capacity, in minutes.
4. Maximum ramping period. This is the maximum allowed time, once a utilisation instruction has been
issued or becomes active, for an FSP to reach its contracted flexible capacity.
5. Availability agreement period. This is the time period before a flexibility service is required by a DNO,
in which the DNO and the FSP may agree the FSP’s availability window.
6. Utilisation instruction notification period. This is the time period before a flexibility service is required
by a DNO, in which a DNO may issue a utilisation instruction to an FSP.
Other parameters that may be specified are the service recovery time and the maximum utilisations per service
window. The products generally have an availability and a utilisation compensation component, but the specifics
are defined in each tender. When they have both, FSPs must specify in their offers the price of both components.
Moreover, there have been some pilot projects on the procurement of reactive power flexibility services by
DNOs. In 2022, there will be a decision on whether these will also enter a business-as-usual status (Aithal,
2021).

52
Table 8: Summary of the active power services in the United Kingdom

Source: (ENA, 2020b).

Table 9: Specifics of the flexibility products

Source: (ENA, 2020c).

53
4.7.4. Flexibility procurement process
The tenders aim for long-term contracts that could reach up to 7 years ahead. They are organised by each DSO
per congestion zone. The voltage level in the congestion zones ranges from 11 kV to 132 kV, with the majority
of being at 33 kV (Aithal, 2021).
There are two procurement cycles per year for each DSO. Before a tender is called, DSOs usually publish
information highlighting indicative areas in which flexibility needs could arise in the near future (signposting).
When the tender is called, a DSO initiates a competition, asking for a specific flexibility product in a specific
congestion area and a specific service delivery period. The timing of the process is shown in Figure 5. The
awarding of contracts usually takes 2–3 weeks from the bidding window closure.
The DSO decides on the winning bids based on price (70 % weight) and technical characteristics above the
minimum requirements (30 % weight), which include (ENA, 2020a):
— an assessment showing that flexibility provision will not cause operational security violations in other parts
of the network;
— conflicts with other provided services;
— effectiveness;
— ramp rates (above flexibility product minimum requirements);
— energised status of assets;
— type of connection (flexible versus firm);
— type of metering.
The exact evaluation formula per tender is included in the call documentation. Further refinement of the bid
evaluation process is under way.
Price caps are defined by network operators, which are published before the submission of offers by FSPs. Price
caps correspond to the annualised cost of the alternative classic network investment, which is defined by a
common evaluation methodology (ENA, 2021a).
Accepted offers are communicated by DSOs to the procurement platform and from there to the flexibility
provider. A contractual agreement is then needed between the DSO and the FSP, which has been harmonised
(ENA, 2021b). The pricing mechanism is pay-as-bid for both availability and activation components.

Figure 5: Aligned procurement timescales in UK flexibility tenders

ITT: Invitation to Tender

Source: (ENA, 2020a).

54
4.7.4.1. Coordination between network operators
Each DSO launches its own tenders for specific parts of its network. Currently, the procurement of local
flexibility services and the procurement of system ancillary services by the TSO are very loosely coordinated,
with each network operator having separate procurement methods.
Conflicts arising from flexibility activation between different network operators have not been identified so far.
According to the experience to date, the activation of flexibility does not cause noticeable imbalances, as these
are lost in the ‘noise’ of demand and generation variability, but this could change in the future. This is also one
reason why the contractual relationships between independent FSPs and suppliers/BRPs have not been
analysed in detail yet in the open networks programme.
Nevertheless, the open networks programme has set out some generic guidelines for conflicts resolution in the
activation of flexibility services, which are based on enhancing network observability, data exchange and
consultation between interested parties (
Figure 6) (ENA, 2020d). A general principle suggested is that mitigation actions should primarily be the
responsibility of the procurer of flexibility services. FSPs also take on a significant part of the responsibility by
securing that they can honour at any time their contractual obligations to both DSOs and the TSO. Furthermore,
mapping of potential conflicts between the TSO and DSOs’ flexibility services was developed in 2021 (ENA,
2021c).
Regarding co-optimisation in the procurement of flexibility services by different network operators, this has
been identified as a priority for the future, but no particular steps have been taken so far. One of the main
reasons for this is that the TSO has moved to day-ahead and shorter time procurement windows for many
ancillary services; therefore, of more importance is the development of local flexibility markets closer to real
time. In addition, a greater level of harmonisation of pre-qualification procedures between the TSO and DSOs
was identified as a priority (ENA, 2021d).

Figure 6: Proposed conflict management cycle in the open networks programme

Source: (ENA, 2020e).

4.7.5. Activation and settlement procedures

FSPs activate flexibility after communication by the DSO, with the aim being full automation of the process,
mainly employing APIs (ENA, 2020f; Aithal, 2021).

55
For the settlements of the FSPs, a baseline is employed. A baseline tool is currently being finalised (ENA,
2022b). It is based on the UK DNOs’ core baseline principles for measuring the delivery of flexibility services,
which are simplicity, accuracy, integrity and replicability (ENA, 2020c). Three types of baseline methodologies
have been chosen:
1. a historical baseline (or rolling baseline), which is intended for all products, noting that, for the ‘sustain’
product, it should be applied only to flexible demand;
2. a historical baseline with same-day adjustments, which has the same applicability as a simple
historical baseline and is preferred when the utilisation instruction period is closer to real time (from
a week ahead and closer);
3. FSP nominations, which are applicable to all products except ‘sustain’, for which historical baselines
are low and historical data are not available; FSP nominations are considered most suitable when
submeter readings are available.
When there are no historical data available, there is a problem for baseline implementation for the ‘sustain’
and, at times, the ‘secure scheduled’ products, for which it was recommended that technology-specific
validation mechanisms be tested and more experience be accumulated. The reason for this is that long
utilisation instruction notification periods and long utilisation periods allow limited options for these products
(ENA, 2021e).
The settlement period is 30 minutes. When measurements with finer granularity are available, these are
averaged in this time window (i.e. the settlement is made on energy, not power, terms).
Remuneration of the availability component of successful offers is made after the activation period, depending
on successful activation of the flexibility service. Currently, no penalties apply, but there is a reduction in
remuneration in the case of partially delivered flexibility. Given the state of development of local flexibility
services, this is more of a practical choice than a theorised rule, so it may change in the future.
Independent aggregators are permitted in most UK electricity markets, including the TSO ancillary services
market and the capacity mechanism. There is not a strict formalised framework for the contractual
relationships between independent aggregators and suppliers, but an accreditation system (Flex Assure ( 80)) is
highly promoted by the overall market (Aithal, 2021).

4.7.6. Results, lessons learnt and future developments

Flexibility tenders by UK DNOs have reached a business-as-usual status. An increasing volume of flexibility is
being procured, reaching 2.9 GW in 2021 from 1.1 GW in 2020. Most flexibility comes from the commercial
and industrial sectors, while participation from the residential sector is still low (Aithal, 2021).
Regarding the overarching work made by the ENA on flexibility, notable developments include a methodology
and tool to compare flexibility deployment against classic network expansion (ENA, 2021a), the alignment of
procurement procedures among the UK DNOs, further improvements to the common baseline methodology
and the assessment of potential conflict areas between DNOs’ and the TSO’s flexibility services. Future work
will continue on all of these subjects and on interoperability across DNO and TSO systems, reviewing it further
and possibly adding new flexibility products, addressing barriers for FSP value stacking, improving the provision
and accessibility of curtailment information for flexible connections, and the development of common
methodologies for carbon reporting and monitoring across DNOs, along with Ofgem and the Department for
Business, Energy & Industrial Strategy. The timeline for the flexibility tenders at both distribution and system
level for 2022 has already been published.
Two interviews were conducted on the UK tenders, one with a representative of Piclo Flex and another from
the open networks programme (Anagnostopoulos, 2021b; Aithal, 2021). Notable points included the following.
— While the United Kingdom represents the largest market for local flexibility services in Europe, and with
more than 100 % growth between 2020 and 2021, liquidity still is relatively low with respect to the
requirements, with almost 50 % of the tendered volume not being covered.
— Long-term tenders were chosen as the preferred procurement architecture by DNOs for getting experience
in a secure and controlled way. While they will probably remain for the foreseeable future, both
interviewees had the opinion that the general direction will be towards closer to real-time flexibility

(80) https://www.flexassure.org/

56
 markets. It is noted that the same view was shared by the interviewee from Western Power Distribution
on the IntraFlex project.
— Independent aggregators represent a significant percentage of participating FSPs.
— The end-goal is coordinated flexibility procurement by network operators (DSOs and the TSO), but this is
going to be a lengthy process. More specific guidelines for conflict resolution are going to be developed in
2022. It is noted that this end goal may not necessarily mean a single flexibility market, but more than
one ‘flexibility exchange’, which operate in a coordinated way, similar to the situation in the wholesale
energy market, where there may be more than one power exchange in the same country (this is also the
case in the United Kingdom).
— A series of other services may be required by DNOs in the future, including inertia for local grid stability,
short-circuit current injection, black-start and island operation capability. These are in the context of the
transformation of UK DNOs to system operators of active distribution networks. Many of the required
flexibility services, if not all, are going to be procured through market-based mechanisms. An imminent
decision in 2022 is expected on whether the pilot projects on procurement of reactive power/voltage control
flexibility services will upgrade to business as usual.
— Communication protocols are still unharmonised between network operators. Future effort on harmonising
the functional specifications is already planned.
— The national regulatory authority, Ofgem, follows the open networks programme very closely and has set
up a ‘flexibility first’ approach on network development and operation, strongly incentivising the
procurement of flexibility services by DSOs.
— Besides the procurement process, Piclo Flex can optionally manage the operations (availability, dispatch)
and settlement (performance, invoicing) procedures. In addition, Piclo Flex is developing more capabilities
of a fully-fledged flexibility marketplace, such as facilitation of short-term competition, while it is
supporting the development of a common European framework for flexibility markets based on open APIs.

4.8. ENEDIS flexibility tenders

4.8.1. General information

— Date of initiation: June 2020
— Status: ongoing
— Country: France
— Network operators involved: ENEDIS (DSO)
— Website: https://flexibilites-enedis.fr/
In June 2020, ENEDIS, the main French DSO, launched its first flexibility tender. Tenders have been launched
as a business-as-usual case every year since 2020 (so far three tenders), amounting to 19 opportunities for
upwards flexibility services to date. ENEDIS is now encompassing downwards flexibility to solve injection
congestion issues (ReFlex project) and has published nine opportunities, which must now be detailed and
scheduled, consistently with new DER connection applications and their congestion creation.
It is noted that all calls, except one in which two bids have been submitted, ended null, as no offers were
submitted (ENEDIS, 2020b; ENEDIS, 2021).

4.8.2. Pre-qualification procedures

For each flexibility tender, FSPs can assess their eligibility through the Enedis website ( 81), checking their
delivery or measurement points (respectively in French ‘Point de Livraison (PDL)’ and ‘Point de Référence
Mesure (PRM)’). The module allows market players to test either a single metering identification or an imported
metering identification list. Results are immediate and can be exported (in the case of mass import). It is noted
that not all connection points inside a congestion zone are eligible for participation, as they may not be able to
offer the requested services due to the specifics of their electrical topology (Kuhn, 2021).

(81) https://flexibilites-enedis.fr/

57
When offers are submitted, FSPs must provide a detailed list of their portfolio’s flexibility assets per network
connection point and the technical characteristics. Technical characteristics – such as flexible capacity
compared with respective connection agreements and confirmation of location – are screened out by ENEDIS.
If portfolios include non-eligible sites, ENEDIS either disqualifies the offer or asks for a resubmission. There
are no minimum capacity limits for the participation of flexibility assets.
Assets participating in other electricity markets through a different legal representative cannot be declared by
the FSP under the penalty of rejection of the offer. Independent aggregators must have an agreement with the
respective BRPs for participating in the flexibility tenders.
Upon acceptance of an offer, two pre-qualification tests are undertaken: a test of communication between
ENEDIS and the FSP (non-compensated) and a test of flexibility activation (compensated).

4.8.3. Flexibility products

Depending on the case, the tenders aim at different flexibility services, such as investment deferral, short-term
congestion management and enhancement of reliability (e.g. the activation of flexibility in cases of planned
maintenance or after an outage in the network). Tenders are organised per congestion area, called ‘opportunity
zones’.
Product specifications include:
— eligibility zone,
— capacity per predefined period,
— full activation time,
— activation duration,
— neutralisation duration between activation (in hours),
— maximum injection ramp,
— notification period.
ENEDIS also provides an estimation of activated flexibility that will be needed in MWh/annum and the maximum
activation period.
In general, flexibility products have both an availability and an activation component. While product
specification characteristics are standardised, as mentioned above, the specific parameters change per call and
respective opportunity zone. Furthermore, in each call, a number of specific product options are requested in
terms of the aforementioned technical characteristics, with a different evaluation score for each one known
beforehand to potential participants. These specific product options are not divisible. Their minimum size is
500 kW and their minimum activation period is 30 minutes (Kuhn, 2021).
The main reason behind the specific product specification is the methodological approach taken by ENEDIS
regarding the cost–benefit analysis for employing flexibility, which, according to detailed feedback from the
interviewees, is summarised as follows. As per Article 32.1 of the clean energy package, flexibility must improve
the cost-effectiveness of network design or operations; therefore, flexibility competes against the best
alternative in terms of network investment, which ends up in requiring quite specific products for flexibility to
reach sufficient effectiveness. So far, for the sake of simplicity, a single winner for availability contracts (i.e. a
single contract) is considered by ENEDIS, while, for activation, ENEDIS will chose the best available flexibility
(Kuhn and Dupin, 2021). A detailed presentation of the methodology employed by ENEDIS for the valorisation
of flexibility can be found in (ENEDIS, 2017).

4.8.4. Procurement of flexibility

Long-term tenders are organised per zone. The procurement horizon varies from 5 to 44 months ahead of
flexibility delivery. Overall, tenders have been issued for 19 opportunities in 14 zones. The maximum voltage
in each zone has been 20 kV (the maximum voltage level in the ENEDIS network). Tenders have been issued in
2020, 2021 and 2022.
Procurement is made for a whole future year and flexibility is required for certain predefined periods of the
year (e.g. for December to March every day between 18.00 and 21.00 and between 22.00 and 24.00).

58
For energy products, the evaluation of offers is made solely based on price. For availability products, the
evaluation of offers depends on the purpose of the flexibility service. In most cases, when the service is the
alleviation of power congestions, the evaluation of offers is made solely based on price. However, when
voltage-related security constraints limit the effectiveness of flexibility sources, sensitivity factors per flexibility
asset connection point are employed in the selection of offers. The scoring criteria are disclosed beforehand in
the tendering materials.
Price caps, also called the propensity to pay, are imposed in the selection of offers, but these are not published
beforehand. They correspond to the difference between the effectiveness of flexibility (the reduction of lost
loads, valued as value of lost load (VOLL)) and the effectiveness of classic investment (the annualised cost of
the best alternative network expansion plus its effectiveness on VOLL and losses). The pricing mechanism is
pay-as-bid for both availability and activation components.
According to the survey results, ENEDIS and the TSO do not expect particular operational security issues in the
upstream network resulting from flexibility activations for the time being, owing to the relatively low volume
in this early phase of development of local flexibilities and the joint willingness to start local flexibilities. For
the same reason, for the time being, they do not expect noticeable system imbalances to be caused.

4.8.5. Activation and settlement procedures

The activation of a flexibility service is done via phone call or email by ENEDIS to the FSP. ENEDIS is working
on implementing API activation in the near future (Kuhn, 2021). In general, there is no pre-announcement for
activation of a contract (i.e. the product notification period is followed). If the flexibility product aims at
reliability enhancement (e.g. for outage management), the notification period can be as low as 0 minutes for
delivery 30 minutes later (Kuhn, 2021).
The measurement and settlement period is 30 minutes. A baseline is employed for the settlement. Eight
different baseline methods are proposed by ENEDIS, depending on the type of flexibility facility (demand
response, production units or mixed) and their size, to be chosen by the FSP, including the declaration of
schedules by the latter. More specifically, five baseline methods are proposed for demand-response facilities,
three are proposed for production facilities and two are proposed for mixed facilities. The FSP can define a
different baseline methodology for each type of facility (demand response, production or mixed) in its portfolio.
If a facility also provides flexibility services to the TSO, then the same baseline methodology has to be
employed for the two cases (flexibility provision to the TSO and flexibility provision to the DSO). In addition,
ENEDIS certifies beforehand and throughout the whole life of the contract the quality of the schedules provided
by FSPs if they have chosen this option. If they do not meet ENEDIS standards, schedules are rejected and a
default method is used (Kuhn, 2021).
Remuneration is made on a monthly basis, for both the availability and the activation components.
Remuneration of availability components is made after the activation period and subject to successful delivery.
Reduced remuneration plus penalties apply when flexibility is partially delivered, resulting, in extreme cases, in
the FSPs paying the buying network operator. There is no additional compensation for over-delivery (Kuhn,
2021).
Flexibility activations are considered as instructed imbalances in the calculation of the BRPs’ final position. This
effectively results in the FSPs undertaking balance responsibility for their cleared offers.
In addition, FSPs have to compensate BRPs for the energy pre-bought by the latter in the wholesale market
and offered by the former as flexibility. This will be done in the French DSO market starting in March 2023: it
will be covered by the contract and will rely on existing TSO rules (e.g. for the block exchange notification of
demand response (NEBEF) mechanism ( 82)) to define the compensation prices. The compensation will be a
function of the activated volume and will be dispatched among the affected BRPs (Kuhn, 2021).

4.8.6. Results, lessons learnt and future developments

All calls, except the one for which two bids were submitted, ended null, as no offers were submitted. For 2021,
this led to the calls being extended until the end of the year, although with no better results. According to the
survey and the structured interviews, reasons for the low liquidity in the flexibility marketplace included the
following.

(82) More information on the NEBEF mechanism is available on the RTE (the French TSO) website (https://www.services-rte.com/en/learn-
more-about-our-services/nebef-compensation-payment.html).

59
— This is an emerging market compared with the well-known TSO markets, which already offer significant
value to FSPs (e.g. the capacity remuneration mechanism).
— There is low availability of flexibility assets and relatively high capacity needs for the narrow congestion
zones. On average across the ENEDIS network, there has been, to date, only one LV flexible site per MV
feeder and less than one MV flexible site per HV/MV primary substation already active on national
mechanisms. Therefore, aggregators have to target a local zone and recruit enough flexible sites to respond
to ENEDIS tenders.
Other notable points made by the interviewees include the following.
— For the time being, of major interest is downwards flexibility. In general, owing to the strength of the
distribution network in France, uncapping the flexibility potential for upwards flexibility is not very urgent
from the DSO perspective.
— ENEDIS currently assesses the opportunity of implementing a market platform enabling continuous trading.
In this case, the envisaged gate closure time will be 2 hours before activation.
— Regarding network operators’ coordination, ENEDIS works with RTE (the French TSO) to share the flexibility
offers between system operators (common offers and shared visibility). It is a work in progress and it
should lead to a close coordination process once implemented. This is important to ENEDIS, given that,
currently, TSO markets (including the capacity remuneration mechanism) are much more attractive to FSPs.
— ENEDIS considers that a lower level network operator should have precedence in the procurement of
flexibility from assets in the distribution system.

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5. Synthesis of reviewed local flexibility markets
This chapter provides a consolidated view of the local flexibility markets examined based on the dimensions of
analysis followed in this work (pre-qualification procedures, flexibility product specification, market
architecture, and activation and settlement procedures). The similarities and differences are discussed. Finally,
major issues defining the evolution of local flexibility markets in Europe are identified, based on both a desktop
analysis and the interviews carried out.

5.1. Pre-qualification procedures

Table 10 provides a consolidated view of the pre-qualification procedures of the local flexibility markets
reviewed.
All of the marketplaces examined follow the concept of conditional (as opposed to dynamic) pre-qualification
procedures ( 83).
The depth of pre-qualification procedures depends on the features of the local flexibility market, that is, on its
pilot project or business-as-usual nature. Pre-qualification procedures are rather light for the former, with the
main prerequisites being that flexibility assets are placed inside the required congestion zone, as well as
successful communication with the market platform and/or the FDR and agreement with the market operator’s
rulebook. More mature flexibility markets such as those in the United Kingdom also encompass financial risk
analysis and compliance with relevant legal provisions through dynamic purchasing systems.
Asset declaration to a digital register (the market platform and/or the FDR) and a first automatic pre-
qualification stage regarding correct location can be considered good practice. Moreover, the general direction
is towards network operators accumulating detailed technical data of all participating flexibility assets (i.e.
towards the FDR concept). Importantly, the buying network operators are currently responsible for all matters
of pre-qualification, with market platforms playing only a facilitating role (asset registration and verification
of locational eligibility).
Flexibility assets’ minimum required capacity limits vary significantly in size but also in definition: in certain
markets, compliance is defined on a flexibility portfolio basis (e.g. sthlmflex), while, in others, it is defined on a
flexibility asset basis – especially those in which the FDR is central in the overall market architecture (e.g.
NorFlex). On the upside, the analysis did not show any indication of exclusion of flexibility assets on the grounds
of their technology, even though, in some cases, technology-specific weights are imposed in the evaluation of
flexibility bids (e.g. in the UK tenders).
Physical technical tests are, in most cases, either non-existent or minimal (e.g. an end-to-end system test for
one asset). However, it is noted that network operators are increasingly setting up verification processes of the
flexibility assets’ technical capabilities as part of the settlement procedures.
An emerging serious issue is the different pre-qualification processes and minimum requirements for
participation in local flexibility markets, on the one hand, and in TSO ancillary services markets, on the other.
This could induce additional costs for FSPs. Ideally, a single pre-qualification process should be established
enabling participation in all markets, as a means, among other things, to foster value stacking. Implementation
of the FDR concept could facilitate this (see also CEDEC et al., 2021).
Finally, the following issues may be critical in facilitating, or instead pose barriers to, the uptake of local
flexibility markets regarding technical and/or regulatory requirements.
— Data ownership and compliance with relevant legal provisions, especially when submeter measurements
are employed for settlement purposes.
— The definition of SGUs and whether flexibility assets (either individually or in an aggregated pool) fall into
this category. This will define whether real-time measurement exchanges to network operators will become
a regulatory obligation (CEDEC et al., 2021).
— Information and telecommunication technology interoperability requirements. If harmonisation with a
single protocol such as CIM is imposed quickly, this may lead to a significant cost barrier, especially for
small FSPs. While harmonisation may prove necessary in the long run (especially towards an integrated
TSO/DSO market), an easier way forward may now be represented by the employment of APIs, although
this might also prove challenging at times, as shown in the NorFlex project.

(83) For the difference between the two see CEDEC et al., 2019.

61
— The regulatory framework for the contractual relationships between independent aggregators and BRPs.
Very strict requirements, especially the necessity for BRP approval, may pose barriers to unlocking the
flexibility potential in the distribution system.

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Table 10: Consolidated view of pre-qualification processes among the flexibility markets reviewed
Process sthlmflex IntraFlex NorFlex GOPACS enera UK tenders ENEDIS tenders
Asset declaration Market platform Market platform FDR IDCONS FDR Procurement In flexibility offer
participation platform and pre-
agreement qualification
questionnaires
Technical — Metering points — Metering points — Metering points — Metering points Metering points — Metering points — Metering points
assessment — FSP baseline — Test trade — Successful — As per — Technical — Technical
methodology communication wholesale market characteristics characteristics
— End-to-end
— Minimum bid with market rules — Network code — Successful
system test for one
size of 0.1 MW platform and FDR compliance communication
asset per FSP
— Test trade — Minimum — Minimum with network
— Activation test nominal capacity of flexible capability operator
(seasonal 1 kW (10–50 kW, — Activation test
contracts only) depending on DSO)
— TSO compliance — Activation test
(for participation in
the mFRR market
only)

Regulatory — Power of — Agreement with Agreement with — Participation in a Very light/none FSP legal — Same legal
assessment attorney market operator’s market operator’s connected market trustworthiness representative for
agreement rulebook rulebook platform check by network all markets
— Agreement with — FSP legal — IDCONS operator — Contractual
market operator’s trustworthiness participation agreement with
rulebook check by network agreement BRPs for
— Contract with operator independent
BRPs (for aggregators
participation in the
mFRR market only)
Duration of pre- 14 days 14 days 0 days 5 working days 0 days 14 days During offer
qualification assessment
process
Source: JRC analysis.

63
5.2. Flexibility product design
Table 11 provides a consolidated view of the design of the flexibility products of the local flexibility markets
reviewed.
All of the marketplaces reviewed focus on congestion management flexibility services, with network deferral
the second most common focus and enhancement of network reliability (e.g. the activation of flexibility during
planned maintenance or forced outages) the third most common. The intended service defines to a great extent
the design of traded flexibility products. In most cases, short-term trading (i.e. 1 week ahead and closer to real
time) is employed for congestion management, while longer term contracts (months to years ahead) are used
for network deferral and reliability enhancement services. Only the two Nordic markets reviewed in this work
pass (aggregated) bids into the TSO balancing market.
Short-term products have only an activation component and are divisible. Ex ante explicit price caps do not exist
as such, but buying DSOs either actively submit bids (IntraFlex and, NorFlex) or compare offers to best
alternatives (e.g. subscription swap in sthlmflex or RES curtailment cost in enera). While, in most cases, these
are defined in energy terms, two marketplaces (NorFlex and IntraFlex) required flexibility provision in power
terms. For this, high temporal granularity of measurements was required, along with much finer flexibility
control by FSPs, given that settlement in this case is conducted on a 1-minute basis. It may be noted that certain
interviewees questioned the need for such fine resolution for congestion management, even though it was
acknowledged for voltage control services (see the feedback from the sthlmflex market in Section 4.2.6). While,
in most cases, flexibility offers are simple orders, IntraFlex permitted more sophisticated options such as fill-
or-kill and minimum quantity. Overall, flexibility products for short-term congestion management are fairly
similar to their respective products in wholesale markets (day ahead, intraday and balancing), with the main
difference being the minimum acceptable volume, with local flexibility markets permitting smaller volumes and
locational information.
The time horizon of longer term contracts varies widely between the marketplaces reviewed, ranging from
weeks to years ahead. Generally, they have an availability and an activation component. In all cases, FSPs bid
freely for seasonal and years-ahead contracts, but, for the weekly contracts employed in the two Nordic local
flexibility markets reviewed, network operators predetermine the price for either the availability compensation
or both. It is debatable whether this is a structural decision, as these two pilot projects focus, among other
things, on product experimentation, and weekly contracts were also introduced for fostering market liquidity.
Overall, availability products in the local flexibility markets reviewed diverge significantly from TSO balancing
capacity products in some fundamental characteristics as defined in EU law: Article 6 of the electricity regulation
states that balancing energy prices shall not be predetermined in contracts for balancing capacity (i.e. bids for
availability and activation components should be disentangled), and that balancing capacity should be procured
in the day-ahead time frame as the default option. This significant divergence could be a root cause for future
difficulties in integrating DSO and TSO flexibility markets, even though the underdeveloped market structure
for transmission system congestion management services will be on this fundamental. On the other hand, it is
indeed difficult to fathom how DSOs could procure network deferral and extent reliability enhancement
flexibility services based solely on short-term markets, similar to the provisions of the electricity regulation for
balancing capacity products, given the current state of maturity and the liquidity of distributed flexibility.
Especially for network deferral, for which long-term contracts seem more suitable, one could argue that the
appropriate analogy to system services products would be capacity mechanisms.
Referring to the terminology used in CEDEC et al. (2021), long-term contracts employed in the local flexibility
markets reviewed share the following attributes:
— locational information
— the duration of the contract
— the availability window
— the validity period
— the direction of activation
— the maximum quantity
— the activation period.

64
Buying network operators in most of the markets reviewed also try to define an indicative maximum number
of activations (frequency).

65
Table 11: Consolidated view of flexibility products among the flexibility markets reviewed
sthlmflex IntraFlex NorFlex GOPACS enera UK tenders ENEDIS tenders
Targeted flexibility services
Network deferral X — X - - X X
Congestion management X X X X X X X
Reliability enhancement X — — — — X X
Network re-energisation — — — — X —
System balancing X — X — — —
Direction of flexibility Upwards Mainly upwards Upwards and Upwards and Downwards Mainly upwards Upwards and
downwards downwards downwards
Type of products
Long-term contracts Seasonal — — — — Years ahead Years ahead
Availability component FSP bids — — — — FSP bids FSP bids
Activation component FSP bids — — — — FSP bids FSP bids
Weekly contracts Called on an ad — Procured on a — — — —
hoc basis monthly basis
Availability component Network operator — Network operator — — — —
defined defined
Activation component FSP bids — Network operator — — — —
defined
Short-term trading X X X X X — —
Bids specification
Minimum bid size 0.100 MW 0.001 MW 0.001 MW As per Intraday As per Intraday 0.010–0.050 MW Product dependent
Market Market
Divisibility X X X X X Depends on DNO No
Other Additionally, Flexibility product Flexibility product The IDCONS is a Compensation for Four distinct Specific product
network operators’ defined in terms defined in terms combination of a RES curtailment products differing options per tender
subscription rights of power of power sell and a buy acted as a price in their with different
trading order in the IDM cap parameters evaluation weights
Source: JRC analysis.

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5.3. Market design
A consolidated view of the key aspects of market design among the local flexibility markets reviewed is provided
in Table 12.
All of the local flexibility markets reviewed are organised spatially in local congestion zones, in which offers can
be aggregated in portfolios, similar to the zonal organisation of the wholesale market. A marginal exception is
seen in the ENEDIS tenders, in which certain connection points inside the zone may be exempted for technical
reasons. On the other hand, GOPACS goes further, combining firm congestion zone configurations with ad hoc
formation of IDCONS when necessary, based on the locational information of offers.
The level of harmonisation of long-term trading of flexibility among the markets reviewed is extremely low,
with the frequency of calls, evaluation criteria and products differing completely. This mimics the situation
regarding long-term contracts for system services such as capacity remuneration mechanisms, in which
national specificities play a decisive role. An interesting question is whether or not price caps should be published
and made available beforehand to the tenderers: on the one hand, this provides transparency, fostering liquidity,
while, on the other hand, it can increase procurement costs for buying network operators, especially in immature
markets. Of equal importance is how these price caps are defined: for this, a harmonised methodological
framework is missing.
Short-term flexibility markets are more harmonised, with continuous pay-as-bid trading being the standard.
Nevertheless, there are some noticeable differences. The start of trading depends on whether the buying
network operators publish their flexibility demand, which is a combination of forecast accuracy (which is better
the closer to real time forecasts are made), procurement cost expectation (which, in most cases, is higher closer
to real time) and liquidity (immature markets require longer trading periods). The gate closure time depends a
lot on the level of integration with wholesale markets: GOPACS, which utilises flexibility offers submitted in the
intraday market, has the shortest gate closure time. On the other hand, the Nordic marketplaces chose a nominal
gate closure time of 2 hours exactly so as not to coincide with the balancing market. The MTU follows the
imbalance settlement period, so it can be expected to become 15 minutes in the future in all cases. Another
interesting aspect is the manner that the buying party (network operators) participates in the trade: two main
approaches can be identified in this regard.
1. Network operators implicitly ‘bid’ by considering a shadow price cap above which flexibility offers are
rejected. This is the case when there is an alternative for solving the congestion, such as in the case
of sthlmflex (temporary subscription rights) and enera (rule-based cost of RES curtailment).
2. In IntraFlex and NorFlex, network operators try a more direct approach with active bidding for fostering
economic efficiency and a reduction of procurement costs. Moreover, in the latter case (NorFlex), this
is done in an automatic way through a robot showing a high level of sophistication.
Active bidding is especially noticeable, as no other European market-based procurement mechanism for grid
and/or system services network operators currently features a similar arrangement.
The integration of the emerging local flexibility markets with wholesale and TSO ancillary services is ongoing
and among the most challenging issues. Long-term tenders so far focus solely on services provided to DSOs. In
short-term trading, different levels of integration are seen. At the forefront is GOPACS, which utilises offers
from the intraday market, as long as these have locational information and are submitted to a connected power
exchange. Nevertheless, in the GOPACS project, flexibility provision is disconnected from balancing services,
following the arrangements at wholesale level. In the Nordic pilot projects, unused flexibility offers are passed
on to the TSO mFRR market. Thanks to the integration of system balancing and the transmission congestion
management procurement mechanism in the Nordics, distributed flexibility can be used for both services. On
the other hand, when FSPs must optimise their portfolio, they need to decide how to allocate their capacity
between participation in the wholesale energy market and the local flexibility market, making value stacking
more difficult.
Except for the case of GOPACS, in which a closer coordination mechanism between the TSO and DSOs has been
implemented (even though this is still a long way from co-optimisation of the procurement process), DSOs have
precedence in the procurement of distributed flexibility with respect to TSOs. Even though this may not be the
most economical solution, it is clearly easier to implement.
Finally, the investigation in this report provided some insights into the expected ‘merit order’ of flexibility
services. Flexibility procurement cost is expected to be lowest for market parties, followed by the TSO and finally

67
the DSOs. This is logical, given that the DSOs need flexibility with a locational ‘premium’ coming from a more
limited resource pool.

68
Table 12: Consolidated view of market design specifics among the reviewed flexibility markets
Design characteristic sthlmflex IntraFlex NorFlex GOPACS enera UK tenders ENEDIS tenders
Locational organisation Congestion zones Congestion Congestion Congestion zones and Congestion zones Congestion zones Congestion zones (not
zones zones connection points all points eligible)
Long-term contracts X — — — — X X
Evaluation criteria Availability offer — — — — 70 % price / 30 % On price except for
technical criteria voltage-related tenders
Call-up Once per year — — — — Twice per year Ad hoc
Price caps Published — — — — Published Non-published
In all cases, the pricing mechanism is pay-as-bid for both the availability and the activation components
Short-term market X X X X X — —
Start of trading D-7 D-7 D-7 D-1 to T-6h D-3 to T-1h — —
Gate closure time Nominal 90 minutes 120 minutes As per Intraday Market Nominal — —
120 minutes, in 15 minutes, in
practice at 09.00 practice some
D-1 hours before
MTU 60 minutes 30 minutes 60 minutes 15 minutes 15 minutes — —
DSO trading Implicit price caps Active bidding Active bidding None Implicit price caps — —
In all cases, continuous trading is employed, evaluation of offers are made based on price and the pricing method is pay-as-bid
Buying parties
DSO X X X X X X X
TSO For balancing and For balancing For congestion For congestion — —
—
congestion and congestion
BRPs — — — X — — —
Network operators’ coordination
Procurement rule DSO over TSO N/A DSO over TSO Separate procurement DSO over TSO N/A N/A
Security coordination Subscription None To be developed TSO/DSO analysis Cascading top- None None
rights through the FDR down
D-1 means 1 day before delivery, T-6h means six hours before delivery
Source: JRC analysis.

69
5.4. Activation and settlement procedures
Table 13 provides a consolidated view of the activation and settlement procedures among the local flexibility
markets reviewed.
Baselining is one of the most critical issues for a robust framework on the exploitation of distributed flexibility
(CEDEC et al., 2021). This is mainly because distributed resources do not generally take positions in the
wholesale market against which the change in generation or consumption patterns (i.e. the supply of flexibility)
can be measured. Therefore, it also relates to the level of integration of the various markets in which DERs
participate, which for local flexibility markets is rather low. GOPACS constitutes a notable exception by carrying
offers over directly from the wholesale intraday market.
The examination revealed that FSP declarations are permitted in all of the local flexibility markets reviewed,
complemented in some cases by a baseline option defined by the market or the buying network operator(s).
This is interesting given that it is also the method most prone to gaming, as FSPs can declare distorted baselines,
overestimating the actual flexibility provided. Nevertheless, it is generally preferred by many FSPs, and it is
considered more precise, especially for dispatchable assets (distributed generation or storage). In many projects,
network operators develop various surveillance methods, including a review of the baseline forecast
methodology of the FSPs, a comparison of FSP baseline declarations with historical measurements and
statistical analysis. Regarding market- or network-operator-defined baselines, the default method is based on
historical measurements (with and without same-day adjustments). It is noted that certain FSPs, especially
smaller ones and/or those with mainly demand response assets, prefer such externally defined baselines, at
least as an option. The question here is whether or not market and/or network operators can (or should,
considering the associated cost) develop the necessary sophistication for making baseline forecasts per
connection point and/or flexibility asset under a scenario of an expanding volume of flexibility provision. Another
ongoing issue is the alignment of baseline methods for services provided to different network operators (e.g.
the TSO as opposed to DSOs).
A relevant issue is also the meters employed for the settlement of flexibility provision. While, in wholesale
markets, connection meters are always employed, some of the local flexibility markets reviewed permit
measurements from the appliances’ submeters too, owing to requests from the involved FSPs or, in the case of
NorFlex, network operators’ preferences. The main argument is that a more precise assessment of the flexibility
provision is possible, given that the flexibility assets’ response is disengaged from the non-controllable
consumption and/or generation behind the main meter. While this has a lot of merit from a technical point of
view, it is a grey area in regulatory terms, because of data ownership, privacy and measurement data integrity
considerations. Another obstacle may be data format and communication protocols, as interoperability
standards for smart devices are only now being developed. Nevertheless, the pan-European network
associations are quite open to employing submeter data for the settlement of distributed flexibility, in all
markets, possibly in combination with main meter readings (CEDEC et al., 2021).
The settlement period usually follows the imbalance settlement period, except in the case of the IntraFlex and
NorFlex projects, in which flexibility products have been defined in power terms and high-granularity
measurements of 1 minute are employed. Again, this is a notable divergence from the wholesale markets, in
which all activation products are defined in energy terms.
Most of the local flexibility markets reviewed do not impose penalties for partially delivered flexibility, and
instead impose only reduced remuneration according to the same pattern: full remuneration is awarded above
a certain level without overcompensation for over-delivery, zero remuneration below a certain level and a linear
reduction in between. However, the specific limits differ significantly among the markets reviewed. The decision
not to impose penalties is mainly oriented towards market uptake facilitation, rather than being a principled
opinion. In fact, in most cases, the interviewees held the view that, as local flexibility markets mature, penalties
may need to be introduced, starting from the availability products. Again, the harmonisation of remuneration
and penalty rules for flexibility provision is still an ongoing issue, at least at national level.
In the majority of the local flexibility markets reviewed, balance responsibility is undertaken by BRPs and not
by the independent aggregator. Even though this can result in cross-subsidisation, it seems that current
flexibility volumes are rather low and, in the case of upwards flexibility, it does not create a significant financial
risk for the BRPs. Regarding compensation by the independent aggregator to the supplier/BRP for the energy
pre-bought by the latter in the case of demand response, a rather disparate picture is emerging from the
investigation, ranging from a well-defined regulated approach (e.g. in France) to no action at all (e.g. in the
United Kingdom). Again, significant factors for addressing the issue (or not) are the volume of flexibility with
respect to the natural variability of demand and the integration of distributed flexibility and of the independent

70
aggregator business model within the other electricity markets (wholesale, balancing and capacity remuneration
mechanisms).

71
Table 13: Consolidated view of settlement procedures among the reviewed flexibility markets

Procedure sthlmflex IntraFlex NorFlex GOPACS enera UK tenders ENEDIS tenders

Baselines

FSP schedules X X X X X X
As per wholesale
Market/network operator X X — market rules — X X
defined

Market surveillance X — X — X — X

Metering

Connection meter X X — X X X X

Sub-meters X X X — — — —

Settlement period 60 minutes 1 minute 1 minute 15 minutes 15 minutes 30 minutes 30 minutes

Flexibility partial delivery

Compensation Full > 80 % Full > 95 % Full > 80 % Pro rata Full ≥ 100 % DNO and product Tender specific
specific
Zero < 40 % Zero < 63 % Zero < 50 % Zero < 100 %

Penalties No No No Imbalance price Yes (equal to 0) No NEBEF rules

Independent aggregators–BRP relationship

Balance responsibility BRPs BRPs BRPs BRPs Voluntary FSP

As per wholesale
Energy compensation Future Bilateral accreditation
No No market rules NEBEF rules
development agreements system
Source: JRC analysis.

72
6. Critical notes on the evolution of local flexibility markets in Europe
In this chapter, criticalities regarding the current state and possible evolution of local flexibility markets in
Europe are discussed, based mainly on the interviews conducted in the context of this work, along with a more
general desktop review of the subject.

6.1. State of evolution of local flexibility markets in Europe

Local flexibility markets in Europe are currently in the emerging phase. While in the United Kingdom and in the
Netherlands, they have reached a business-as-usual state, in the rest of Europe they are at the pilot project
stage with various levels of ambition, with the most developed examples encountered in the Nordic countries.
One could expect a larger deployment of market-based procurement of distributed flexibility for network
services given both the mandate of the electricity directive and the considerable number of national and
European projects on the subject (for the latter, the interested reader is invited to see Dikaiakos (2020) and
Frontier Economics and ENTSO-E (2021)).
Three main drivers behind the need to develop local flexibility markets have been identified in this work:
1. short- and long-term ‘freeing’ of distribution capacity for accommodating the electrification process
(e.g. in the two Nordic projects);
2. unlocking the flexibility potential in the distribution system for congestion management services mainly
in the transmission system (e.g. GOPACS);
3. the management of the distribution grid under increased penetration of distributed vRES facilities (e.g.
the enera project and the ENEDIS tenders).
Rapid electrification creates an immediate demand for congestion management solutions in the distribution
grid. While the long-term (optimum) solution will probably include classic network expansion, utilisation of
distributed flexibility offers a quick way forwards for accommodating the increased electricity demand.
Therefore, the main driver is not only (or mainly) economic efficiency in the management of the distribution
network; it also includes respecting the fundamental responsibility of DSOs to serve existing and new customers.
With large conventional plants retiring owing to the decarbonising process, as well as technical, regulatory and
policy factors favouring the proliferation of DERs, utilising the latter’s capability for system and network services
at transmission level will become increasingly important. The pace of this process will depend fundamentally
on the evolution of all underlying factors: the rate of decommissioning of transmission-connected conventional
plants, infeed variability and ancillary services provision by new large RES plants ( 84), the state of the
transmission network, lead times for network expansion, and the proliferation pace of DERs.
Perhaps unexpectedly, this investigation showed that management of the distribution network under increased
distributed vRES penetration is the least pressing driver for the development of local flexibility markets. Under
such conditions, the utilisation of local flexibility focuses instead on economic efficiency rather than on
maintaining operational security: the network operators usually have other options for the latter, such as flexible
connections or, in the worst case, rule-based forced curtailment of vRES – an instrument widely employed (e.g.
in Germany).
The drivers behind the development of a local flexibility market significantly affect decisions on a range of
issues. The first driver (rapid electrification) implies that key relevance is attached to market liquidity increase.
A laxer framework regarding the contractual relationships between independent aggregators and BRPs is
accepted, also considering that upwards flexibility currently poses a low financial risk for the latter. Partial
delivery of flexibility is not penalised, and reduced remuneration is imposed only under a certain threshold (e.g.
below 80 % in the Nordic projects). Moreover, products such as weekly contracts are introduced, with the explicit
aim of attracting additional market players / flexibility volume.
If the key aim of the local flexibility market is congestion management in the transmission system, key
considerations include integration with the wholesale market, the regulation of contractual relationships
between independent aggregators and BRPs, the MTU and settlement period, and penalty rules for partial
delivery of flexibility. A characteristic case is GOPACS, which is the most integrated with the wholesale market
structure.

(84) The latter factor will depend mainly on overall market design rather than technical capabilities, which are already mostly present.
Disentanglement of the revenues of large RES plants from short-term electricity markets will dampen the attractiveness for providing
ancillary services.

73
Finally, even in the more mature cases (e.g. in the UK flexibility tenders), available flexibility provision cannot
cover all of the demand, at all times, of network operators, at least within economically acceptable limits. The
main reason is business case immaturity, both in general terms (i.e. concerning distributed flexibility per se) and
with specific regard to flexibility services to DSOs. However, there are indications of underlying technical-
economic reasons, too: while most of the network operators interviewed were convinced of the considerable
flexibility potential in the distribution system, factors such as the cost of the required intelligence for
aggregation (e.g. baseline forecasts and interoperability requirements between devices and systems) and
variations in the time demand response capability (e.g. in respect of external temperature or during peak
commuting times) reduce the available resource in practice. This implies that a combination of tools will be
needed for the management of the distribution system during the energy transition, both in the long term (i.e.
network expansion) and in the short to medium term (i.e. flexible connections or preferential network tariffs for
demand curtailment availability, as a security back-up to local flexibility markets).

6.1.1. Shift towards short-term local flexibility markets

Even though the current state of play of local flexibility markets in Europe does not permit a definitive view on
their future characteristics, a key outcome from all of the interviews conducted in the context of this work is
the expectation of moving into short-term spot markets. Longer term contracts through tender procedures will
continue to be procured in many cases in the mid-term as a reliability back-up and as the most obvious way to
incorporate flexibility into the long-term development of distribution networks. However, as the liquidity of
distributed flexibility increases and DSOs get more experience in it, short-term (i.e. less than 1 week ahead)
spot markets will probably become more important in the overall procurement process. Reasons behind this
include:
— an increase in liquidity by offering the possibility to smaller assets (e.g. EVs) to participate in the
procurement process. This is because such assets can have a good forecast on their flexibility potential
only close to real time;
— a lower volume risk for network operators owing to better grid forecasts closer to real time;
— expectations of better price formation, although evidence from the flexibility markets reviewed showed
that, in some cases, longer term contracts led to lower activation prices than short-term markets in projects
in which both mechanisms coexist; nevertheless, given the state of play of these projects, this evidence
may be circumstantial.
A significant barrier to the development and consolidation of short-term markets as the main procurement
mechanism for local flexibility is the current difficulty of integrating them with wholesale markets, which is
discussed in more detail in the next section.

6.2. Level of integration of local flexibility markets with wholesale markets

Given the emerging character of local flexibility markets, their integration with wholesale electricity markets is,
in most cases, low, with the notable exception of GOPACS. Most of the projects reviewed extend, at best, to
coordination with the TSO flexibility services market (i.e. for balancing and/or congestion management),
employing a hierarchical structure in which the DSOs always take precedence in the procurement of flexibility.
While co-optimisation of flexibility procurement for grid services has been identified as the end goal by all
interviewees, it seems we are still a far way from that. The reasons for this, and its impacts, are discussed in
more detail below.

6.2.1. State of integrated security analyses among different network operators

The level of TSO–DSO coordination regarding operational security analyses is one of the fundamental factors
defining the level of coordination in flexibility procurement. Mainly owing to legacy organisational structures,
originating from the old unidirectional power system, each network operator until recently was to a great extent
responsible for the operation of its own part of the network, with little interaction with the other network
operators. Network codes, and especially the system operation guideline ( 85), as well as the overarching
principles set in the clean energy package, were milestones towards closer coordination between TSOs and
DSOs, regarding power system operation and planning of both. Nevertheless, we are in the implementation
phase of all relevant changes.

(85) Commission Regulation (EU) 2017/1485 establishing a guideline on electricity transmission system operation.

74
TSOs have generally reached a high level of sophistication of operational security analyses, having the capability
for almost continuous real-time assessments of the state of the transmission network, increasingly better
forecasts regarding the relevant probabilistic variants (e.g. RES output) and enhanced controllability capabilities
through the deployment of smart grid technologies (e.g. phase-shifting transformers). This is not the case for
distribution systems in Europe, for which the main problem is probably the lack of observability, an increasingly
salient issue at lower voltage levels. This considerably affects the procurement processes for flexibility by DSOs
regarding required volume, time of procurement and type of requested products. The less accurate the
operational security assessment is, the more flexibility has to be procured as a safety margin, and availability
products procured long in advance are favoured.
The disparity of network operational ‘intelligence’ between transmission and distribution systems makes a
hierarchical, cascading coordination structure the only practical choice at present. Relevant to this is also the
lack of data and communication protocols harmonisation, with CIM implementation identified in all network
levels as the main solution. However, this will take time and may also impose undue transition burdens on FSPs,
especially the smaller ones.

6.2.2. Emergence of transmission/distribution system operator competition for flexibility

services
A first glance, in the current structure of markets for flexibility coming from assets in the distribution system,
it may appear that DSOs are favoured, either by setting up a market in which they are a monopsony or by
having precedence in the procurement process against the TSOs. However, this is a misleading view: the key
indicator is the liquidity of flexibility offers to DSOs against offers by DERs to TSOs.
Wholesale markets, including for system services, are much more mature than the emerging local flexibility
markets for services to DSOs, representing a much clearer business model for FSPs. Moreover, there are
instances in which the remuneration for system services is much higher than the expected remuneration for
services in the distribution system: this is, for example, the case in France, where participation in the capacity
remuneration mechanism represents quite a lucrative business opportunity, leaving little interest in participation
in the new flexibility tenders for services in the distribution system (also considering the price cap defined by
ENEDIS). In addition, under the current state of networks in Europe, there are cases in which distribution systems
have less demand for flexibility services than the system for frequency ancillary services or the transmission
network for congestion management (see, for example, the flexibility volumes procured in GOPACS by the TSO
as opposed to the DSOs), making a weaker business case regarding revenue flow certainty for FSPs.
Liquidity problems for local flexibility markets can be expected to be more acute when these are disengaged
completely from the rest of wholesale markets. A hierarchical, cascading system in which DSOs have precedence
in the procurement process over TSOs can be a practical way forwards, as unused FSP offers are automatically
transferred to the latter. A complementary measure could be collaboration between DSOs and TSOs in the
utilisation of services offered by distributed assets to the latter: an example could be the obligation of DERs
participating in the capacity remuneration mechanism to also offer their flexibility to the DSOs (i.e. for the
capacity remuneration mechanism to act simultaneously as an availability product at both system and
distribution network level).
In practice, however, prices for wholesale ancillary and transmission system congestion management services
constitute an opportunity cost for FSPs when they contemplate their offers to emerging local flexibility markets.
This has to be acknowledged by DSOs and can be a good initial guide for assessing the competitiveness of
flexibility against other options such as classic network investment. This also highlights the importance of steps
towards co-optimisation of the procurement of services to network operators (both DSOs and TSOs) as a means
to drive costs down, especially for DSOs.

6.2.3. Barriers to flexibility service provider value stacking

Most of the interviewees were of the opinion that the provision of local flexibility services to DSOs does not
provide enough revenue streams to make a viable business case for FSPs on their own. Therefore, value stacking
is critical for increasing the flexibility offered by DERs.
Taking into account the general structure of the European internal energy market for electricity, a market party
must in general optimise its portfolio among a multitude of energy and ancillary services markets ( 86). An

(86) As a general rule, the different electricity markets in Europe include capacity remuneration mechanisms, over-the-counter contracts,
forward markets, day-ahead markets, intraday markets, balancing capacity markets, balancing energy markets, market-based
procurement for congestion management in the transmission system and, finally, local flexibility markets.

75
important point is that these markets are separated (i.e. a market party has full responsibility for how to position
its assets among different time frames and products for maximising its profits). This disjointed market
architecture is a rather distinctive feature of the European electricity market set-up. In other jurisdictions (e.g.
in the United States), co-optimisation in the procurement of different products is the norm, with energy trading
in the day-ahead market being co-optimised with reserves provision and transmission capacity allocation.
While the European framework gives much more freedom to market parties, portfolio optimisation may prove
a daunting task, especially for emerging parties such as small FSPs. For local flexibility markets, in particular,
this comes on top of technological challenges such as accurate baseline prediction, which adds risks to an
emerging and not yet consolidated business model. The integration of flexibility procurement at DSO and TSO
level (with better coordination in the form of a common order book as an intermediate step) could facilitate
value stacking for FSPs, with beneficial effects for the liquidity of distributed flexibility.

6.3. Role of the regulatory framework in the development of local flexibility markets
National regulatory frameworks play a major role in empowering DSOs to take a more active role both as buyers
of distributed flexibility and in facilitating others’ use of flexibility resources in their own networks to enable
system-wide benefits. In all of the countries analysed in this report, DSOs’ revenues models are based on
incentive regulation using a TOTEX approach. In addition, DSOs’ efficient cost (TOTEX in most of the countries
analysed) is benchmarked against comparable DSOs in terms of several outputs, such as the quality and
reliability of supply and efficient network operation (the level of network losses), to account for more cost-
effective operation and planning of their distribution networks. This regulatory framework provides incentives
to DSOs to investigate solutions for the operation and planning of their networks beyond classic network
expansion.
Furthermore, R & D represents a critical part of the innovation incentives provided to the DSOs and, more
specifically, of the way this cost is treated within the DSOs’ revenue model. In most of the EU countries analysed
(e.g. France, Germany, Norway and the United Kingdom), R & D cost is partially recovered by increasing the
revenue allowance upon compliance with a set of eligibility requirements and directly passed through tariffs
(and therefore is not subject to efficiency benchmarking).
In the United Kingdom, there is a clear regulatory impetus for the deployment of flexibility solutions (mainly
market-based), among others, through the NIA used to finance small R & D and demonstration projects and the
IRM to fund roll-outs of trialled innovations that have environmental benefits and provide value for money for
consumers. Both cases are financed through yearly adjustment to the revenue allowance. Furthermore, NIC is
competition through which few large development and demonstration projects run by TSOs and DSOs are
selected for funding. To a significant extent, the quick development of local flexibility markets in the United
Kingdom can be attributed to the supportive regulatory framework.
To further facilitate innovation, most of the countries analysed have also implemented regulatory
experimentation, usually in the form of regulatory sandboxes. Some of the local flexibility markets/projects,
such as NorFlex (Norway) and enera (Germany) have been developed owing to a regulatory sandbox. It is noted
that regulatory experimentation is not constrained solely to market-based procurement of distributed flexibility,
but in some cases includes other procurement methods (e.g. pilot regulation on network tariffs in Sweden).
Of relevance to the development of local flexibility markets is also the existence of a regulatory framework for
the participation of demand-side flexibility in all electricity markets, and more specifically the emergence and
market access of independent aggregators. In this context, France is one of the leading countries in Europe with
a regulatory framework for demand-side participation, which has been in place since 2014. Demand-side
flexibility and independent aggregators can participate in the day-ahead and intraday, balancing, capacity, and
TSO and DSO congestion management markets. Similarly, the regulation in the United Kingdom allows access
of independent aggregators to almost all markets, except wholesale markets (day-ahead and intraday). In
Germany and the Netherlands, access of independent aggregators is limited to participation in the balancing
market, whereas, in the Nordic countries (Norway and Sweden), no independent aggregators are commercially
active in any electricity market. Independent aggregators are, in principle, allowed to participate in local
flexibility markets, but many issues around their participation, such as balance and financial responsibility and
the transfer of energy, are not yet clearly regulated, except for in France. However, in France, the results of
local flexibility tenders have been rather disappointing so far. All in all, how the business case for the provision
of local flexibility services will be affected when a more consolidated regulatory framework for the financial
relationships between independent FSPs and suppliers/BRPs is established is an ongoing issue to be considered.

76
7. Conclusions
Growing renewable energy generation levels and electrification of end-use sectors, such as transport and
heating, affects the ability of DSOs to ensure smooth operation of their networks, with the ageing of European
distribution networks an additional complicating factor. In this respect, flexibility procurement presents an
alternative to classic network investment that could be, in some cases, more economically advantageous and
quicker to implement than network expansion.
The EU electricity directive describes market-based procurement of flexibility services by DSOs as the preferred
option, whereas CEER takes a more conciliatory approach, considering all options (market based, rule based,
network tariffs and connection agreements, or a combination thereof) as equal alternatives. Currently, flexibility
procurement for distribution network operation and planning is under development, with various degrees of
maturity and a variety of methods employed among European countries. The regulatory framework for DSOs’
revenues and the specific national situation of the distribution network play a significant role in the level of
flexibility procurement and in the preferred method(s).
Market-based procurement of flexibility services by DSOs is still a niche practice in most countries. Among the
cases reviewed in this report, three countries (France, the Netherlands and the United Kingdom) take a business-
as-usual approach to market-based procurement, two (Norway and Sweden) have developed pilot projects and,
in Germany, a rule-based approach was in the end chosen as the main option. Nevertheless, even among the
countries in which market-based procurement can be considered to have reached a business-as-usual stage,
there are significant discrepancies in terms of procured volumes and levels of market maturity: DNOs in the
United Kingdom systematically procure local flexibility services and in increasing volumes each year, backed by
a supportive regulatory mandate. In the Netherlands, GOPACS is a well-established mechanism, and the recent
collaboration with EPEX SPOT is expected to further increase liquidity in the market for flexibility services by
assets in the distribution system. On the other hand, the flexibility tenders in France have produced rather
disappointing results so far, owing to, among other things, more attractive business alternatives for FSPs, as
well as the design of the tenders (specific, non-divisible products) and the price caps imposed by ENEDIS.
Even though local flexibility markets are, at best, at a maturing stage, certain initial insights on emerging trends
regarding their design characteristics can be gleaned.
— Regarding pre-qualification procedures (and the part of settlement processes that deals with flexibility
delivery verification), the concept of the FDR seems to be popular. Nevertheless, a potential barrier for FSPs
may be the different requirements for participation in local flexibility markets, on the one hand, and in the
wholesale, balancing and capacity markets, on the other. In this respect, requirements on data
interoperability by network operators and data ownership by regulators will probably play a critical role.
— Regarding market architecture and flexibility product design, long-term contracts (seasonal and longer)
seem better for addressing network deferral and reliability services, while short-term markets seem more
suitable for operational support, such as congestion management services. While a good level of
convergence on short-term products is emerging, long-term contracts vary widely among the local flexibility
markets reviewed. Trade is generally organised in local congestion zones, and short-term trading follows
the continuous, pay-as-bid paradigm. A harmonised methodological framework for setting price caps is
missing, with each jurisdiction following its own approach. Regarding penalties for partial delivery of
flexibility, again there are significant differences: pilot projects tend to enforce only a (mostly proportional)
reduction in remuneration (with the exception of the enera project, in which remuneration fell to zero for
any level of partial delivery), while, in France and the Netherlands, there are financial penalties. The United
Kingdom follows the first approach, even though it can be considered the most mature local flexibility
market, although this could change in the future.
— On settlement procedures, baselining seems to be one of the most critical issues. Network operators still
experiment with different methods, but FSP declaration is in almost all cases one of the options. When this
is followed, verification processes are established that try to mitigate potential gaming opportunities, but
these usually necessitate the recording and processing of a large number of data, including local
meteorological conditions. Also critical will be whether settlement will be permitted based on submeter
measurements, for which end customers and FSPs should consent to providing data on an asset basis
rather than a connection point basis.
The integration of local flexibility markets with wholesale and balancing markets and security coordination
between DSOs and TSOs are still ongoing issues. Three distinctive cases can be discerned.

77
 1. A local flexibility market in which the DSO is a monopsony. This is the case for France and the United
Kingdom. While the development of security coordination between the distribution and transmission
systems when DSOs procure flexibility is among the stated future goals in both cases, so far it is
implicitly considered that, backed so far by experience, flexibility activation for solving network
constraints in the distribution system does not cause noticeable issues in the transmission system,
mostly because of the relatively low volumes.
2. A local flexibility market in which the DSO has precedence in the procurement. This is the case in the
pilot projects of Germany, Norway and Sweden, where DSOs pass unused offers to the TSO. This also
implies a cascading security coordination process.
3. A local flexibility market in which both DSOs and the TSO procure distributed flexibility on an equal
footing. This is the case in the Netherlands, which, among other things, necessitates a coordinated
security analysis between the network operators involved.
The partial, at best, integration of local flexibility markets with the rest of electricity markets is problematic in
two main ways. First, value stacking for FSPs becomes more difficult. Second, distributed flexibility is not
necessarily optimally procured between the different network operators. Both factors involve the risk of an
emerging suboptimal competition for flexibility coming from assets in the distribution system between DSOs
and TSOs, with the former so far at a disadvantage, given that markets for system (TSO) ancillary services are
much more mature. For the business-as-usual local flexibility markets, this has particularly been the case in
France, but such indications also exist in the United Kingdom and in some of the pilot projects reviewed in this
report. The issue of possible market fragmentation pertains also to the Netherlands: while GOPACS can be
considered the most integrated local flexibility market for congestion management services to both DSOs and
the TSO, a parallel platform, Equigy, is planned as a means for procurement of distributed flexibility for system
balancing services.
As regards the risk for market fragmentation, there are indications of a risk of regulatory fragmentation
regarding the participation of FSPs in different markets, particularly independent aggregators. The survey and
interviews conducted in this work showed that, in most cases, BRPs assume balance responsibility, while
compensation for ToE does not exist. This can be attributed to the emerging nature of local flexibility markets,
many of which are pilot projects, as well as the fact that, in most cases, regulation for independent aggregators
is only now being developed. In addition, an ongoing issue is how the liquidity of local flexibility markets and
the price of services may be affected when the regulatory framework on aggregation becomes consolidated.
Regarding the relationship between the regulatory framework and the development of local flexibility markets,
only initial comments can be made in this work. In all of the cases examined, an incentive-based framework
exists for the DSO revenue model. This helps DSOs to investigate methods other than classic network
investment for the operation and planning of their networks, although to various degrees owing to the
significant differences in the specificities of the national regulatory frameworks. The analysis also showed that
innovation incentives, including regulatory experimentation such as in the form of sandboxes, can be very
helpful in the first steps of local flexibility markets. Finally, we have to note that the United Kingdom represents
a distinctive case, as it has a regulatory mandate and policy vision clearly promoting the use of flexibility, which
to a significant extent explains the relative success of local flexibility markets in this jurisdiction.

7.1. Future work

This work reviewed specific cases of local flexibility markets. The choice of cases reviewed was based on a
combination of the level of maturity, distinctive features and insights ( 87) gained into the development of local
flexibility markets in Europe. It is noted that a series of major Horizon projects on distributed flexibility are
ongoing and their results are expected to play a significant role in the development of local flexibility markets
(we refer here to Coordinet ( 88), OneNet, Interrface, Platone and EUniversal). Therefore, future work should
incorporate these projects too. A decisive question is how many of these, as well as of the pilot projects reviewed
in this report, will lead to business-as-usual local flexibility markets? In addition, if they do not lead to business-
as-usual local flexibility markets, what are the underlying reasons for this? Moreover, the analysis should
probably expand to market platforms aiming to procure distributed flexibility for system and network services

(87) This was, for example, the case for the enera Flexmarkt, which, albeit a pilot project without continuation, stands as an alternative
to the final decision taken in Germany to follow a rule-based approach for congestion management services.
(88) While Coordinet was reaching its end in June 2022 and the pilot projects developed in its context were mature enough to be reviewed,
the authors chose to focus on sthlmflex, which can be considered a spin-off of the Swedish cases.

78
beyond those aimed at DSOs (e.g. the Equigy platform) and the interrelation of such initiatives with local
flexibility markets.
A second major work stream was a deeper assessment of the regulatory framework pertaining to distributed
flexibility, including the provisions on independent aggregators. This work showed that the risk here of regulatory
fragmentation between different services/markets and/or EU countries was substantial. In this regard, a
significant role will be played by the network code for demand response that is currently under development ( 89)
and its national implementations.
Finally, a third major future work stream should probably be a more detailed examination of the data
management requirements on distributed flexibility at both the technical (e.g. harmonisation of communication
protocols and IT systems) and the regulation (e.g. data ownership and data privacy provisions) levels. Both of
these issues have been touched upon in this report, but the importance and depth of the subject, closely related
to the EU action plan for digitalising the energy sector ( 90), deserves a stand-alone, dedicated analysis.

(89) https://www.acer.europa.eu/events-and-engagement/news/acer-initiates-drafting-new-framework-guidelines-demand-response
(90) https://ec.europa.eu/info/law/better-regulation/have-your-say/initiatives/13141-Digitalising-the-energy-sector-EU-action-plan_en

79
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List of abbreviations
aFRR automatic frequency restoration reserve
API application programming interface
BRP balance responsible party
BSP balance service provider
CAPEX capital expenditure
CEDEC European Federation of Local Energy Companies
CEER Council of European Energy Regulators
CIM common information model
CRE Commission de Régulation de l’Énergie (French regulatory authority)
DER distributed energy resource
DNO distribution network operator
DSO distribution system operator
EAN European article numbering
E.DSO European Distribution System Operators
ENA Energy Networks Association
ENTSO-E European Association for the Cooperation of Transmission System Operators for Electricity
ETPA Energy Trading Platform Association
EV electric vehicle
FCR frequency containment reserve
FDR flexibility data register
FSP flexibility service provider
GOPACS Grid Operators Platform for Congestion Solutions
HV high voltage
IDCONS intraday congestion spread
IRM innovation roll-out mechanism
LV low voltage
mFRR manual frequency restoration reserve
MTU market time unit
MV medium voltage
NEBEF block exchange notification of demand response
NIA network innovation allowance
NIC network innovation competition
OPEX operational expenditure
R&D research and development
RAB regulatory asset base
RES renewable energy source
RIIO revenues = innovation + incentives + outputs
RR replacement reserve

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SDSP Smart Data and Service Platform
SGU significant grid user
SINTEG smart energy showcase – digital agenda for the energy transition
ToE transfer of energy
TOTEX total expenditure
ToU time of use
TSO transmission system operator
USEF universal smart energy framework
VLP virtual lead party
vRES variable renewable energy source

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List of figures
Figure 1: Energy policy documents with reference and relevance to flexibility .................................... 5
Figure 2: USEF aggregator implementation models ................................................................22
Figure 3: GOPACS architecture .......................................................................................45
Figure 4: Grid and market interactions in GOPACS ..................................................................46
Figure 5: Aligned procurement timescales in UK flexibility tenders................................................54
Figure 6: Proposed conflict management cycle in the open networks programme ...............................55

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List of tables
Table 1: Possible flexibility services procured by different actors in the local flexibility markets reviewed ..... 5
Table 2: DSO revenue models ........................................................................................11
Table 3: Solutions to flexibility procurement ........................................................................19
Table 5: Flexibility markets design ...................................................................................28
Table 6: Differences in product specification between the sthlmflex market and the balancing market .......34
Table 8: Summary of the active power services in the United Kingdom ..........................................53
Table 9: Specifics of the flexibility products .........................................................................53
Table 10: Consolidated view of pre-qualification processes among the flexibility markets reviewed ..........63
Table 11: Consolidated view of flexibility products among the flexibility markets reviewed ....................66
Table 12: Consolidated view of market design specifics among the reviewed flexibility markets ..............69
Table 13: Consolidated view of settlement procedures among the reviewed flexibility markets ...............72

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Annexes
Annex 1. Survey on Flexibility Marketplaces in Europe

Personal information
Name and Surname:
Affiliation:
1. Pre-qualification of Flexibility Service Providers (FSPs) and flexibility assets
1.1 When does the prequalification process takes place?
• Before registration into the marketplace
• Before submission of flexibility offers
• After successful flexibility offers are cleared
• No pre-qualification process

Could you provide some more details?

1.2 The pre-qualification process:

• Validates the regulatory, commercial and financial capacity of FSPs

• Validates the technical characteristics of flexibility assets
• Both

Could you provide some more details including which entity is responsible for each part of the prequalification
process?
In case of validation of flexibility assets’ technical characteristics: Which technical characteristics are verified in
the prequalification process? What are the tests performed?
1.3 During the prequalification process are certain assets/locations excluded because activation of flexibility
from them would cause operational security violations in some parts of the network?
• Yes
• No
If yes, could you provide some more details?
1.4 Are there minimum nominal capacity limits for the flexibility assets?

• Yes
• No

1.4.1 If yes, how much is the limit (in kW)?

1.5 Are there maximum nominal capacity limits for the flexibility assets?

• Yes
• No

1.5.1 If yes, how much is the limit (in kW)?

1.6 On average, how much time takes the prequalification process (in days)?
1.7 Please provide any other information regarding the prequalification process you consider relevant
2. Procured flexibility services
2.1 At which flexibility services does the marketplace aim? (multiple choice)

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 • (Long-term) investment deferral
• (Short-term) congestion management
• Resilience (e.g. support to fault-restoration or re-energisation)
• Reactive power/voltage control
• Other (please elaborate)

2.2 What other services could be required in the foreseeable future (i.e. in the next 5 years)? (multiple choice)
• Steady-state voltage control
• Fast reactive current injection
• Inertia for local grid stability
• Short-circuit current injection
• Black-start capability
• Island operation capability
• Other (please elaborate)
2.2.1 For which of the above services do you believe market-based procurement could be the preferred option
(e.g. against a rule-based approach)? (multiple choice)
• Steady-state voltage control
• Fast reactive current injection
• Inertia for local grid stability
• Short-circuit current injection
• Black-start capability
• Island operation capability
• Other (please name the services)
3. Trading parties
3.1 Who are the buyers of flexibility in the marketplace? (multiple choice)
• DSOs
• TSO
• BRPs
3.2 Any other comments you deem relevant?
4. Level of aggregation
4.1 The bidding area of the marketplace is organised per:
• DSO responsibility area
• Congestion area (more localised)
4.1.1 What is the highest voltage level in the congestion area (in kV)?
4.2 Offers by FSPs are organised per:
• Delivery points of flexibility assets
• Bidding areas in the marketplace
4.3 Please provide any additional details you consider relevant
5. Flexibility products
5.1 What kind of flexibility products are traded in the marketplace?
• Availability (capacity) products
• Activation (energy) products
• Both
5.1.1 In case availability products are traded:
• The activation price is pre-determined by the bying party (e.g. the DSO)
• The activation price is part of the FSP’s offer for the availability product
• FSPs awarded with availability contracts bid freely in the short-term market
5.1.2 In case availability products are traded, what is the maximum procurement horizon (in months)?
5.1.3 In case availability products are traded, what is the minimum procurement horizon (in months)?

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5.2 What is the minimum bid size (in MW)?
5.3 What is the maximum bid size (in MW)? (please insert 0 if not applicable)
5.4 Are bids divisible?
• Yes
• No
5.5 What is the Market Time Unit (i.e. minimum activation period) (in min)?
5.6 Are there additional technical specifications for the flexibility products? (multiple choice)
• Notice period
• Time to full activation
• Ramping limits
• Recovery rules
• Other
5.6.1 Could you provide the technical details?
5.7 Please provide any additional details you consider relevant
6. Evaluation and clearance of flexibility offers
6.1 Are offers evaluated based on:
• Price
• Price and other criteria
6.1.1 In case that other criteria are employed too, could you elaborate?
6.2 In the evaluation of offers:
• All offers are considered that have the same effectivenes on solving congestions
• Sensitivity factors are employed
6.2.1 Could you provide some details on the calculation process of sensitivity factors (e.g. timing, method,
etc.)?
6.3 Are there price caps above which offers are rejected?
• Yes
• No
6.3.1 In case there are price caps, are these published before flexibility offers submission?
• Yes
• No
6.4 The pricing mechanism for capacity products is:
• Pay-as-bid
• Pay-as-cleared
• Other
6.4.1 In case of ‘other’, please elaborate
6.5 The pricing mechanism for activation products is:
• Pay-as-bid
• Pay-as-cleared
• Other
6.5.1 In case of ‘other’, please elaborate
6.6 Activation products are traded in:
• Auctions
• Continuous trading

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6.6.1 Could you provide some information on the start of trading and the gate closure time?
6.7 Regarding activation products, the network operator:
• Announces flexibility needs in advance and calls FSPs to provide flexibility services
• Activates offers from the oder book without pre-announcement
6.7.1 What is the average time between announcement and activation?
6.8 Please add any additional information you consider relevant regarding evaluation and clearance of
flexibility offers
7. Coordination between network operators
7.1 What is the coordination scheme between network operators?

• Non-applicable (in case there is a single byer of flexibility)

• The lower-level network operator has precedence in the procurement of flexibility (e.g. the DSO against
the TSO)
• The higher-level network operator has precedence in the procurement of flexibility (e.g. the TSO against
the DSO)
• Network operators compete on equal footing (the network operator offering the higher buying price
clears the flexibility offer)
• Co-optimisation
• Other

7.1.1 Could you provide some details on the co-optimisation process?

7.2 How is it secured that activations of flexibility will not cause operational security violations in other parts
of the network (outside the responsibility of the buyer network operator)?
8. Activation of flexibility
8.1 Does the network operator has direct access to flexibility assets?
• Yes
• No, activation of flexibility is made by the FSP
8.1.1 If activation of flexibility is made by the FSP what are the means of communication between the
network operators and the FSPs (phonecall, e-mail, market platform, other)?
9. Settlement procedures
9.1a What is the measurement period?
9.1b What is the settlement period?
9.1c If the settlement period is different than the measurement period, are the measurements averaged for
each settlement period or another method is employed?
9.2 How the baseline is calculated?
• Based on a methodology defined by the market operator and/or the buying network operator
• Based on schedules provided by FSPs
• Both options are permitted
9.2.1 Could you name the baseline methodologies employed?
9.2.2 In case both options are permitted, which one is preferred by FSPs according to your experience?
9.3 Which of the two aforementioned methods (baseline against schedule declaration by FSPs) do you believe
that estimate best the actual flexibility provision? In your view, what are their pros and cons?
9.4 At which stage the settlement of availability products takes place?
• Upon offer clearing
• After the activation period and only if activation offers were actually submitted
• N/A (no availability products in the marketplace)

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9.5 In case of flexibility not delivered:
• Only a reduction of remuneration applies
• Penalties are imposed
9.5.1 In the case of availability products, do penalties apply only to the activation/energy component or also
to the availability/capacity component?
9.6 Please provide any additional information regarding settlement procedures you consider important
10. Financial relationships between FSPs and BRPs
10.1 Can individual end-customers participate in the marketplace without an aggregator?
• No
• Nominally yes, but it is very rare
• It is already done by industrial consumers
• It is already done by industrial and commercial consumers
• It is already done by all types of consumers
10.2 Is participation of independent aggregators permitted in the marketplace?
• Yes
• No
10.2.1 In case that the FSP and the BRP of a flexibility asset are different entities, who assumes balance
responsibility for the flexibility provision?
• The FSP
• The BRP
10.2.2 In case that the FSP and the BRP of a flexibility asset are different entities, does the FSP compensates
the BRP (Supplier) for the energy it offers as flexibility?
• Yes
• No
• 10.2.2.1 Does the compensation of the BRP is defined by regulation or by bilateral agreements?
Could you provide some specifics?
10.3 How the System imbalances caused by flexibility activation are treated?
• They fall into BRP responsibility
• They fall into FSP responsibility
• They fall into network operator responsibility
• Other
10.3.1 Could you elaborate?
10.4 Please provide any additional information you regard relevant on settlement procedures

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