COMMISSION STAFF WORKING DOCUMENT Reform of Electricity Market Design Accompanying the documents Proposal for a Regulation (EU) of the European Parliament and of the Council amending Regulations (EU) 2019/943 and (EU) 2019/942 as well as Directives (EU) 2018/2001 and (EU) 2019/944 to improve the Union’s electricity market design Proposal for a Regulation (EU) of the European Parliament and of the Council amending Regulations (EU) No 1227/2011 and (EU) 2019/942 to improve the Union’s protection against market manipulation in the wholesale energy market
Date: 2023-03-14
Institutions: Directorate-General for Energy, European Commission
Subjects: consumer protection, electricity supply, energy cooperation, energy market, market abuse, market stabilisation, market supervision, renewable energy, security of supply, wholesale trade

EN 

  EN 

   EUROPEAN COMMISSION  Strasbourg, 14.3.2023  SWD(2023) 58 final  COMMISSION STAFF WORKING DOCUMENT Reform of Electricity Market Design    Accompanying the documents Proposal for a Regulation (EU) of the European Parliament and of the Council amending Regulations (EU) 2019/943 and (EU) 2019/942 as well as Directives (EU) 2018/2001 and (EU) 2019/944 to improve the Union’s electricity market design Proposal for a Regulation (EU) of the European Parliament and of the Council amending Regulations (EU) No 1227/2011 and (EU) 2019/942 to improve the Union’s protection against market manipulation in the wholesale energy market {COM(2023) 147 final} - {COM(2023) 148 final}  
 
 
1.  Context .............................................................................................................................................. 3 

1.1.   Recent energy crisis and European response ............................................................................ 3 

1.2.   Electricity markets in Europe .................................................................................................... 6 

1.3.  Areas for improvement in electricity market design highlighted by the energy crisis ............ 11 

1.4. 

Public consultation on Electricity Market Design .................................................................. 13 

2.  Making Electricity Bills Less Dependent on the price of Fossil Fuels ........................................... 16 

2.1.   Supporting the Power Purchase Agreement (PPA) market ..................................................... 17 

2.2.   Contracts for Difference (CfD) for new decarbonised investments ........................................ 23 

2.3. 

 Improving Forward Markets .................................................................................................. 34 

2.4.   Enabling energy sharing .......................................................................................................... 41 

2.5. 

 Offshore Transmission Access Guarantee ............................................................................. 46 

3.  Limiting revenues of inframarginal generators ............................................................................... 49 

4. 

Improving the efficiency of short-term markets ............................................................................. 51 

4.1. 

4.2. 

 Intraday Gate Closure time .................................................................................................... 52 

Sharing of order books and minimum bid size ....................................................................... 55 

5.  Facilitate and incentivise non-fossil flexibility services for renewables integration ...................... 56 

5.1. 

5.2. 

Introduction ............................................................................................................................. 56 

Procurement of flexibility service by system operators and tariff regulation ......................... 60 

5.3.  Use of sub-meter data for the settlement and observability of demand response and flexibility 
services ................................................................................................................................................ 64 

Incentives for non-fossil flexibility such as demand response and storage,  and remuneration 

5.4. 
schemes ............................................................................................................................................... 67 

6.  Towards better consumer protection and empowerment ................................................................ 74 

6.1. 

Introduction ............................................................................................................................. 76 

6.2.  Offers and contracts to better protect consumers against volatile prices ................................ 77 

6.3.  Risk management .................................................................................................................... 79 

6.4.   Enabling energy sharing .......................................................................................................... 80 

6.5.   Facilitating demand response and increasing choice of contract through sub-metering ......... 82 

6.6.  Right to access energy through Suppliers of Last Resort........................................................ 86 

6.7. 

6.8. 

Price regulation as an emergency measure ............................................................................. 87 

Increased protection from electricity disconnection for vulnerable customers and energy poor
90 

7.  

Enhance the transparency of the energy market and protection against market manipulation ... 92 

7.1.  

Introduction ............................................................................................................................. 93 

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7.2.   Better data collection and market monitoring ......................................................................... 98 

7.3. 

Strengthening of investigation, harmonisation of fines to better protect against market abuse
101 

8.  Generation and system adequacy for a decarbonised electricity system ...................................... 102 

8.1.   Generation adequacy and Capacity Mechanisms .................................................................. 102 

8.2. 

Locational signals ................................................................................................................. 107 

9.  Concluding remarks ...................................................................................................................... 109 

ANNEX I: Additional summary of the public consultation on Electricity Market design ....................... 112 

1.  Overview of respondents .............................................................................................................. 112 

2.  Answers from professional/non-citizens respondents ................................................................... 112 

3.  Answers from citizens ................................................................................................................... 123 

3.1. 

“Slovakian campaign” ........................................................................................................... 123 

3.2.  Views of the other around 120 individual citizens ................................................................ 124 

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1.  Context  

1.1.   Recent energy crisis and European response 

Over the last two years, energy prices have been significantly higher than in recent decades. Prices 
started  rising  rapidly  in  summer  of  2021  when  the  world  economy  picked  up  after  COVID-19 
restrictions  were  eased.  Subsequently,  Russia’s  invasion  of  Ukraine  and  its  weaponisation  of 
energy sources by withholding capacities from spot markets have led to substantially lower levels 
of gas delivery and increased disruptions of gas supply, further driving up the gas prices. High gas 
prices have an influence on the price of electricity from gas-fired power plants as they are often 
needed to satisfy electricity demand, as illustrated by Figure 1 below.  

Figure 1: Evolution of the EU electricity wholesale prices (€/MWh) – weekly average 

Platts.  
Source: 
Note: Wholesale (EU5) stands for the weighted average of prices of main EU electricity markets 
(DE, ES, FR, NL) and Nordpool market (NO, DK, FI, SE, EE, LT, LV). 

Global 

S&P 

The Commission has been fully engaged since the beginning of the energy crisis to mitigate the 
effects of high-energy prices on European citizens and companies, and developed, closely with 
Member States, a series of policy responses at a remarkable pace.  

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As an immediate reaction to global dynamics and rising prices, the EU provided an energy prices 
toolbox1 in  October  2021  with  measures  to  address  high  prices  (including  income  support,  tax 
breaks, gas saving and storage measures). This coincided with Russia’s manipulation of energy 
markets through intentional disruptions of gas flows which led not only to skyrocketing energy 
prices, but also endangered security of supply. To address this, the EU took swift action to diversify 
gas supplies and to accelerate energy efficiency and the deployment of renewable energy.   

Following  the  Russian  invasion  of  Ukraine  in  February  2022,  the  EU  responded  with  the 
REPowerEU  plan2  on  18  May  2023  –  a  plan  for  the  Union  to  rapidly  end  its  dependence  on 
Russian fossil fuels as soon as possible through 3 pillars: energy savings, diversification of energy 
supplies and accelerated roll-out of renewable energy to replace fossil fuels in homes, industry and 
power generation. The plan includes an increase from 9% to 13% of the binding Energy Efficiency 
Target under the ‘Fit for 55' package of European Green Deal legislation, as energy savings are 
the quickest and cheapest way to address the energy crisis and reduce bills. With respect to this 
last pillar, the Commission proposed to increase the headline 2030 target for renewables from 40% 
to 45% under the “Fit for 55” package. Faster deployment of renewables and further electrification 
of demand are necessary for a definitive end to the current emergency as they will immediately 
and structurally reduce demand for fossil fuels and contribute to the decarbonisation objectives in 
the power, heating and cooling, industry and transport sectors. Due to the continuous improvement 
of their cost competitiveness, including their low operational costs, an accelerated renewables roll-
out will have a positive impact on energy prices across the EU. Furthermore, the faster deployment 
of renewable energy, together with increased energy system integration, will contribute to fossil 
fuels phase-out, on which the EU has been highly dependent in the past, and will therefore support 
the security of energy supply.  

To  address  dependence  and  to  enhance  energy  security,  the  Union  introduced  a  gas  demand 
reduction  target3  in  2022,  which  has  been  exceeded  this  winter,  as  well  as  minimum  filling 
obligations for gas storage4. The level of gas storage has been comfortable during this winter and 
all Member States are currently on track to meet their intermediate targets ahead of next winter.   

In  addition  to  the  REPowerEU  plan,  the  Council  adopted  on  6  October  2022  an  emergency 
intervention to address high energy prices in the EU. The Council Regulation introduced common 
measures to reduce electricity demand and to collect and redistribute the energy sector's surplus 

1  

2  

3  

4  

Communication  from  the  Commission  to the European Parliament,  the  European  Council, the  Council, the 
European Economic and Social Committee and the Committee of the Regions Tackling rising energy prices: a 
toolbox for action and support - COM/2021/660 final 

Commission Staff Working Document COM(2022)230 - https://eur-lex.europa.eu/legal-
content/EN/TXT/?uri=COM%3A2022%3A230%3AFIN&qid=1653033742483 
Council  Regulation  (EU)  2022/1369 of  5  August  2022  on  coordinated  demand-reduction  measures  for  gas   
https://eur-lex.europa.eu/legal-content/EN/TXT/?uri=CELEX%3A32022R1369 
Regulation  (EU)  2022/1032  of  the  European  Parliament  and  of  the  Council  of  29  June  2022  amending 
Regulations (EU) 2017/1938 and (EC) No 715/2009 with regard to gas storage   https://eur-lex.europa.eu/legal-
content/EN/TXT/?uri=celex%3A32022R1032 

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revenues to final customers. On 22 December 2022, the Council adopted a Regulation laying down 
a temporary framework to accelerate the deployment of renewable energy projects. The Council 
also reached an agreement on the operationalisation of the EU Energy Platform for gas purchase 
and on a temporary Market Correction Mechanism capping the gas prices. 

The  EU  has  also  responded  to  the  crisis  with  a  temporary  State  Aid  regime  to  allow  certain 
subsidies to soften the impact of high prices, agreed and implemented a strong gas storage regime, 
price limiting measures to avoid windfall profits in the gas market and effective demand reduction 
measures for gas and electricity.   

High  energy  prices  have  affected  manufacturing  costs  for  most  sectors  of  the  economy,  in 
particular the energy-intensive industries. In parallel, the price of commodities has also increased. 
On  1  February  2023,  the  Commission  issued  the  Communication5  about  “A  Green  Deal 
Industrial  Plan  for  Net-Zero  Age”,  which  put  forward  several  measures  to  enhance  the 
competitiveness  of  European  industry  and  to  support  the  accelerated  transition  to  climate 
neutrality. The Plan aims to provide a more supportive environment for the scaling up of the EU's 
manufacturing  capacity  for  the  net-zero  technologies  and  products  required  to  meet  Europe's 
ambitious climate targets. This Communication also included a chapter on energy which explains 
that “the competitiveness of many companies has been severely weakened by high energy prices”. 
It  also  highlights  that  “long-term  price  contracts  could  play  an  important  role  to  enable  all 
electricity users to benefit from more predictable and lower costs of renewable power”. The energy 
price crisis has shone a particular spotlight on EU electricity markets, the electricity generation 
mix in  EU countries  and the continuing influence of fossil-fuel  generated electricity on energy 
bills, despite growing shares of renewable electricity. Long-term price contracts could serve not 
only the needs of electricity consumers in the EU, but also support the accelerated deployment of 
renewable energy necessary to meet our Green Deal objectives, the 2030 emissions and the 2050 
net-zero target as set out in the European Climate Law6.  

In its conclusions on 15 December 2022, the European Council invited the Commission to submit 
in early 2023 a proposal “on the structural reform of the EU’s electricity market, including on 
the effect of gas prices on electricity prices, making it fully fit for a decarbonised energy system 
and facilitating the uptake of renewable energy”7.  In parallel  to  the emergency proposals,  the 
Commission therefore started working on proposals to reform the functioning of the electricity 
market.  

5 

6 

7 

COM(2023)62 COM_2023_62_2_EN_ACT_A Green Deal Industrial Plan for the Net-Zero Age.pdf 
(europa.eu) 
Regulation (EU) 2021/1119 of the European Parliament and of the Council of 30 June 2021 establishing the 
framework for achieving climate neutrality and amending Regulations (EC) No 401/2009 and (EU) 
2018/1999 (‘European Climate Law’)    https://eur-lex.europa.eu/legal-
content/EN/TXT/?uri=CELEX:32021R1119 
https://www.consilium.europa.eu/media/60872/2022-12-15-euco-conclusions-en.pdf  

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This  Staff Working  Document sets  out  the explanation and rationale behind the Commission’s 
proposals  for  a  structural  response  to  the  high  energy  prices  experienced  by  households  and 
businesses and to ensure secure, clean and affordable energy for households and businesses into 
the future. The Commission aims to create a buffer between short-term electricity markets and the 
impact on consumer bills, while at the same time improving the functioning and oversight of those 
markets. This will protect consumers, stabilise prices, and ensure that the lower cost of renewable 
electricity is better reflected in electricity bills. Moreover, a renewable based energy system will 
be crucial to ensure an affordable, sustainable and independent energy supply and these proposed 
reforms  aim  to  provide  long-term  price  signals  to  boost  the  deployment  of  renewable  energy 
through improvements to the regulatory framework.   

This reform, if adopted, will benefit not just household consumers but all energy end-users and 
will also enhance the competitiveness of Europe’s clean energy industries. The energy transition 
in Europe needs to be supported by a strong clean technology manufacturing basis. These proposed 
reforms  support the affordable electrification of industry and Europe’s position as a global leader 
in terms of research and innovation in clean energy technologies. 

The proposed reform will be subject to ordinary co-legislative procedure.  

1.2.   Electricity markets in Europe 

  State-of-Play 

A well-integrated and interconnected EU energy market is the most cost-effective way to ensure 
secure and affordable energy supplies to EU citizens and companies. Through common energy 
market  rules  and  cross-border  infrastructure,  energy  can  be  produced  in  one  EU  country  and 
delivered to consumers in another. This keeps prices in check by creating competition and allowing 
consumers to choose energy suppliers.  

The EU electricity market is the result of successive packages of legislation and reforms adjusted 
to changes in market developments and to take advantage of technological development. The most 
recent changes came as part of the Clean Energy for All Europeans8 legislative Package, which 
was designed to deliver on the EU’s Paris Agreement commitments for reducing greenhouse gas 
emissions and  to  make the EU electricity  market fit  for the  clean energy  transition.  The Clean 
Energy Package contains revised rules to support the integration of a greater share of renewables 
and new technologies, by ensuring a level playing field and greater flexibility. It has also enabled 
the  emergence  of  new  and  innovative  products  and  measures  on  retail  electricity  markets  – 
supporting energy efficiency and renewable uptake and helping consumers to have more control 
over their energy bills through emerging services for providing demand response. Furthermore, 
these  rules  build  on  the  increasing  digitalisation  of  the  energy  system,  enabling  enhanced 

8  

https://energy.ec.europa.eu/topics/energy-strategy/clean-energy-all-europeans-package_en  

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flexibility through active participation by consumers, which will remain a key element of future 
electricity markets and systems. 

The current electricity market design has delivered well over the years, allowing Europe to reap 
the  economic  benefits  of  a  single  energy  market  under  normal  market  circumstances,  ensuring 
security of supply, increasing socio-economic welfare and supporting the decarbonisation process. 
Cross-border  interconnectivity  also  ensures  safer,  more  reliable  and  efficient  operation  of  the 
power system. Over the past years, before the global energy crisis, Member States benefitted from 
lower electricity prices thanks to the single market delivering cheaper electricity across Europe, 
increasingly from renewable sources.   

In its report published in April 2022 ACER has estimated that the average yearly gain from the 
integrated electricity market for European consumers is about  EUR 34 billion per  year1. These 
benefits  can  be  illustrated  by  enhanced  security  of  supply  as  a  result  of  cross-border  energy 
exchanges,  the  optimisation  of  electricity  production  to  prioritise  the  least  costly  technologies 
across Europe and price competition  between  all technologies including  renewables, flexibility 
demand response and storage.  

  The merit-order system’s contribution to decarbonisation and security of supply 

Given the overarching objective of decarbonisation and the role that fossil fuel technologies still 
play in the EU electricity system and in influencing the price of electricity, particularly in the short-
term markets, it is useful to clarify why the merit-order approach remains fit for purpose for these 
markets. The EU electricity market is based on a model that keeps the overall cost of the electricity 
system as low as possible for consumer. Generators are incentivised to reduce costs and bid as 
cheaply as possible into the market to ensure they are dispatched. Generators bid into the market 
based on their marginal costs (how much it costs them to run for a given timeframe). This creates 
a stack of bids that are then ranked from lowest to highest (the so-called “merit order”). The market 
price is  the price of the last producer needed to  meet  the demand for the given timeframe. All 
producers  who  bid  below  that  price  are  selected  and  receive  that  price.  The  producers  bidding 
above that price are not selected. The market price makes it possible for the generator to cover the 
cost of fuel (e.g. gas) as well as the cost of investment production capacity (e.g. wind farm).   

This model supports decarbonisation because renewables are cheap to run and therefore always 
dispatched  by  the  market.  Even  small  renewables  producers  without  sophisticated  bidding 
capabilities receive the market price. It also incentivises flexibility because reducing energy use or 
using energy storage is often cheaper than running a fossil fuel power plant so a demand response 
or stored energy bid is prioritised over a fossil fuel generator.  It is more transparent because it 
mitigates the effect of information asymmetry and reveals generators’ true costs, also improving 
competition by providing information for new business models.  

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In addition, the EU market integration is uniquely positioned to respond to short-term security of 
supply issues. If demand is higher in a certain country (e.g. during a cold spell or an unplanned 
outage), then the higher price naturally attracts imports from the surrounding neighbours for the 
hours needed. The longer-term benefits for security of supply are also evident as the integrated 
market enables the sharing of generation and reserves, making the system more flexible and overall 
less expensive for consumers.9  

When considering any reforms to the market design, it is important to bear these elements in mind 
as European consumers expect that the electricity system will continue to function reliably as we 
electrify the economy and decarbonise our energy system. Current market rules can stimulate a 
competitive and innovative energy sector, encouraging new technologies and ways of operating 
the system to integrate more renewable energy and reach the net-zero target. 

o  Expected evolution of the market 

According to the European Commission Staff Working Document implementing the REPowerEU 
plan10, 592 GW of solar PV capacity and 510 GW of wind capacity are required by 2030 to achieve 
the 69% share of renewable electricity modelled by the Commission. This requires average annual 
additions of 48 GW for solar PV and 36 GW for wind.  

Looking at the recent pace of RES investments - see  

9  

10  

This aspect was highlighted in a 2016 IEA country review of France. 
https://iea.blob.core.windows.net/assets/2264b835-3acb-4816-adb7-
893d7b6d3696/Energy_Policies_of_IEA_Countries_France_2016_Review.pdf  
Commission Staff Working Document COM(2022)230  https://eur-lex.europa.eu/legal-
content/EN/TXT/PDF/?uri=CELEX:52022SC0230&from=EN  

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Figure 2 below, a significant acceleration of the roll-out of renewable energy will be required over 
the coming years to meet the decarbonisation objectives. This presents an opportunity for the EU 
to  foster  greater  energy  independence  from  imported  fossil  fuels.  Through  targeted  changes  to 
support the evolution of the market design, there is also an opportunity for greater independence 
for  consumer  bills  from  short-term  markets,  where  prices  are  heavily  influenced  by  fossil-fuel 
generated electricity. 

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Figure 2: volume of RES installed capacity in EU, and projection of RES to reach "Fit-for-55" 
and “REPowerEU” targets 

Source: Eurostat (NRG_INF_EPCRW), Wind Europe, Solarpower, PRIMES for years 2025 and 
2030 (linearly interpolated in between) 

To quantify the effect of gas-fired generation on electricity prices, DG Energy and the European 
Commission’s Joint Research Centre (JRC) applied the METIS power system model to simulate 
the hourly dispatch of the European power system for the years 2022 and 203011. The results show 
that, of all fossil fuels,  natural  gas was the most  significant  price setter for electricity  in  2022. 
Moreover,  the  share  of  hours  in  which  fossil  fuels  set  the  price  exceeded  the  share  that  these 
technologies have in electricity generation. 

Adding more renewable generation to the fuel mix will eventually moderate this effect12. By 2030, 
renewable sources are expected to provide more than two thirds of the EU’s electricity. However, 
fossil  fuels  are  expected  to  still  set  electricity  prices  during  a  significant  number  of  hours. 
Therefore,  it  is  important  to  accelerate  the  uptake  of  demand  response  solutions  that  reduce 

11  

12  

Upcoming JRC report. The objective of this analysis is to identify the number of hours in which gas fired and 
other fossil-fired generation technologies are setting the electricity price. The analysis considers the spill over 
of prices across borders as gas fired generation can also influence electricity prices in neighbouring price zones. 
The  model  was  tested  against  overall  electricity  statistics  reported  for  the  year  2022.  It  does  not,  however 
represent a full reanalysis of all electricity markets, given the conceptual approach of the model and since as 
many parameters necessary for this purpose are not reported. The power system of 2022 is represented by the 
installed  capacities  and  by  commodity  prices,  as  reported.    For  the  year  2030,  the  model  represents  the 
assumptions also made for the policy scenarios for delivering the European Green Deal. 
For Member States which have decided to invest in nuclear energy, this technology can have a similar effect. 

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consumption and hence prices in peaks by reducing the role of gas. Also, accelerating investment 
in storage will help to keep prices at check. Further results of the assessment by DG Energy and 
JRC on price-setting technologies in Europe are to be published in a JRC report. 

The findings of this analysis demonstrate that a certain amount of fossil fuel technologies will still 
be needed for system operation and meeting electricity demand in 2030. However, this does not 
mean that consumers should be fully exposed to these prices on their electricity bills. By ensuring 
a faster rollout of renewables, that more flexibility can enter the market in competition with fossil 
fuel technologies and that more electricity is sold on a long-term basis, it will be possible to phase 
out fossil fuels more quickly and to create a buffer between consumers and short-term markets. 
For Member State which have decided to rely on nuclear energy as part of their generation mix, 
this technology and the related investments can also play a role in this respect.  

1.3.  Areas for improvement in electricity market design highlighted by the energy crisis 

There has been a strong focus in recent years on integrating national markets and ensuring that the 
EU's cross-border, short-term markets are efficient, support security of supply and the integration 
of renewables. This has been achieved through introducing market coupling whereby the entire 
EU electricity system is dispatched in an optimal way with electricity flowing to those markets 
that need it most. It is therefore essential that Member States continue to implement the existing 
legislation fully in order to deliver the efficiency, emissions reductions and flexibility potential 
with the existing generation fleet. Indeed, existing legislation also provides for the protection and 
empowerment of consumers and the enablers to unlock the flexibility in the system, meaning that 
its full transposition and implementation is the foundation for a more consumer-centric electricity 
market.   

However, it is important to acknowledge that, although the current market design has over many 
years delivered an efficient, well integrated market, the energy crisis has highlighted a number of 
shortcomings, which the reforms proposed by the Commission aim to address. The energy crisis 
has highlighted the following issues in the current EU electricity market design: 

o  The  sharp  increase  in  natural  gas  prices  observed  since  Autumn  2021  has  strongly 
influenced wholesale electricity prices. This is due to the fact that, in many hours, gas-fired 
generation  is  needed  to  meet  electricity  demand  and  therefore  often  remains  the  price 
setting technology in the electricity market, even though clean energy sources, which have 
low marginal costs, represent an increasingly larger share of power generation.  

o  The current regulatory framework regarding long-term instruments has proven insufficient 
to protect large industrial consumers, SMEs and households from excessive volatility and 
higher energy bills. Whilst short-term price spikes can in genu emission 

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o  eral incentivise consumers to reduce or shift their demand, sustained high prices over a 
longer period have translated into unaffordable bills for many consumers and companies.  

o  As the revenues from many inframarginal generators, who are not subject to any scheme 
that imposed a revenue ceiling, are dependent on the short-term market prices determined 
by  the  marginal  pricing  system,  the  crisis  has  led  to  unexpectedly  higher  commercial 
returns for inframarginal generators while, in parallel, end-consumers were suffering from 
high prices. 

o  The  extreme  price  volatility  and  short-term  emergency  interventions  may  undermine 
investment signals and future investment appetite, which may put at risk the achievement 
of the EU decarbonisation objectives. At the same time, investments in  decarbonisation 
and green technologies need to be accelerated for the EU to meet its ambitious Green Deal 
objectives.  With  rapidly  increasing  shares  of  wind  and  solar  in  the  electricity  mix, 
investments in flexibility, firm generation capacity and storage must also be accelerated. 
They should go hand in hand with investments in the electricity grid, which will also be 
needed  to  cope  with  new  system  challenges,  such  as  higher  electrification  of  demand, 
distributed energy sources, fast  demand response, less predictable electricity flows with 
intermittent generation patterns.  

o  Short-term markets are needed to ensure an efficient dispatch of all resources, maximising 
renewables generation. Although these markets have delivered the objective of ordering 
the different electricity sources efficiently and pricing scarcity, the integration of flexibility 
sources such as storage or demand response is not happening at the speed and scale needed. 
Prices signals are necessary to orient the consumption or generation at the right time and 
place, especially with further electrification of the demand and increasing investment in 
renewables.  Further incentivising investments in flexibility as well as delivering correct 
price signals will drive the generation and consumption at the right time of the day and in 
the right location within Europe.  

o  Retail  markets  need  to  further  protect  and  empower  consumers.  The  energy  poor  and 
vulnerable customers have been hit hardest by price increases. If consumers had been better 
able to access renewable energy or provide demand response, they would not have been 
impacted as much during this crisis as well as helped alleviate the impact of high gas prices. 
At the same time many suppliers effectively passed on the risks from wholesale markets to 
customers  –  as  fixed  price  contracts  were  removed  from  the  market.  Despite  the  Clean 
Energy Package, too often practice in relation to electricity markets continues to be based 
on the old generation-led paradigm. Instead of active customers choosing energy efficient 
and renewable based energy solutions – they must take the price risk of gas-fired electricity. 
Demand response solutions find it difficult to participate either in wholesale markets or in 
providing  grid  support  services  to  network  operators.  While  the  installation  of 
decentralised renewable generation is booming – particularly among households, the full 

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benefits are not being fully realised. Wider energy sharing is not enabled and provisions 
on energy communities have only been spottily implemented so far. Active participation 
in the energy market is inaccessible to lower-income households.   

o  Finally, recent developments on the market and the experience of implementing Regulation 
(1227/2011)  on  Wholesale  Energy  Market  Integrity  and  Transparency13  “REMIT 
Regulation” over last decade have shown that REMIT and its implementing rules require 
an update to remain fit for purpose. The wholesale energy market design has evolved over 
the past years and not all data is effectively reported. The existing REMIT framework needs 
to be updated to tackle all new challenges, including enforcement and investigation in the 
context of new market realities. 

The Commission has also observed that some provisions of the Clean Energy Package are not fully 
implemented  across  the  Union.  This  is  the  case  in  particular  for  demand  response  and  storage 
where  an  aggregator  framework  is  still  missing  in  the  majority  of  Member  States  and  non-
discriminatory access to all electricity markets is not ensured. Furthermore, the ongoing bidding 
zone  review  is  investigating  whether  alternative  configurations  could  lower  system  costs  and 
increase  economic  efficiency  and  cross-zonal  trade  opportunities.  It  is  also  crucial  that  the 
provisions  on  streamlined  permitting  are  rapidly  implemented  both  for  renewables  and  trans-
European networks for energy (TEN-E). The full implementation of existing legislation will be 
crucial to enabling the energy transition at least cost to all.  

1.4. 

Public consultation on Electricity Market Design 

To  support  its  work  on  the  proposals  to  improve  the  functioning  of  the  electricity  market,  the 
European Commission launched a public consultation about the reform of the electricity market 
design on 23rd January 2023. The European Commission received 1369 contributions to the public 
consultation.  This  includes  among  others  a  large  number  of  citizens  (725),  companies  (277), 
business associations (181) and NGOs (53). 

Table 1: Overview of the contributions received, by type of respondent 

13  

Regulation (EU) No 1227/2011 of the European Parliament and of the Council of 25 October 2011 on 
wholesale energy market integrity and transparency  https://eur-lex.europa.eu/legal-
content/EN/TXT/?uri=CELEX%3A32011R1227  

13 

 
 
 
 
 
 
 
 
                                                 
The  majority  of  companies  and  business  associations  expressed  support  for  market-based 
mechanisms and explained the need to keep market price signals in place to avoid distortions.  

Several NGOs expressed the need for support for RES investments, as a massive RES rollout is 
needed in the coming years to meet EU decarbonisation ambitions. In their view, this could be 
achieved by supporting the development of PPAs or CfDs for example. 

Most contributions from individual citizens, besides the coordinated campaign from Slovakia14, 
came  from  France  and  Germany.  Additional  responses  came  from  Austria,  Belgium,  Czechia, 
Slovakia, Sweden. 

o  Citizens  expressed  diverging  views  and  for  many  questions,  the  share  of  “no  answer” 

responses is significantly higher than for other stakeholders. 

o  The clearest conclusion is that a broad majority of responding citizens consider the use of 
PPAs, CfDs and forward hedging as efficient ways to mitigate the impact of short-term 
markets on the price of electricity paid by private and industrial consumers and to support 
investments in new capacity. Only a small minority of respondents did not answer these 
questions. 

o  For all other questions, the share of “no answer” is rather high or no clear preference can 

be identified. 

14  

See Annex for details 

14 

 
 
 
 
 
 
 
 
                                                 
The Commission also held a stakeholder workshop on 15 February 2023 to gather views on the 
public  consultation.  Overall,  there  were  over  70  participants,  representing  NRAs,  industry, 
environmental NGOs, academia, and business representatives.  

In light of the above, the Commission has prepared several proposals to ensure that consumers – 
both households and companies – can access affordable and secure energy from sustainable and 
renewable  sources  both  now  and  in  the  long  term.  The  Commission  recognises  that  market 
arrangements are needed to  support these objectives, and where necessary, that they  should be 
adjusted and improved to do so in line with the rapid increase of renewables in the electricity mix. 
The present document sets out these proposals which aim at delivering a more resilient electricity 
market for Europe. The present document aims at supporting the Commission proposals around 
the following topics: 

  Making Electricity Bills More Independent from the Short-Term Cost of Fossil Fuels 

  Driving Renewable Investments 

  Alternatives to Gas to Keep the Electricity System in Balance 

  Lessons Learned from Short Term Market Interventions 

  Better Consumer Empowerment and Protection 

  Stronger Protection against Market Manipulation 

15 

 
 
 
 
 
 
 
 
 
2.  Making Electricity Bills Less Dependent on the price of Fossil Fuels 

Feedback from public consultation 

Many respondents explained that short term markets need to be complemented by longer term 
price signals, as the ones put in consultation by the Commission: CfDs, PPAs, forward markets. 
The majority of respondents to the consultation found that CfDs, PPAs and forwards were an 
effective  way  to  mitigate  short-term  market  fluctuations  in  electricity  prices  and  to  support 
investment  in  new  capacity.  These  instruments  are  complementary  and  the  right  equilibrium 
between the different tools should be found. For instance, respondents warned about potential 
cannibalisation risk of the forward market by PPA and CfDs, as a  roll-out of PPAs and CfDs 
may reduce liquidity in the financial forward market. 

The majority of respondents explained that there should not be a mandatory scheme, and that 
the freedom of choosing the relevant contracts should be maintained. Overall feedback is that 
the liquidity on forward markets is insufficient, CfDs could lead to price regulation, and PPAs 
would benefit from standardisation and more transparency.   

The energy crisis has highlighted the fact that consumers are exposed to electricity price volatility, 
and the need to introduce reforms to allow consumers to benefit from greater price stability. The 
Communication15  about  “A  Green  Deal  Industrial  Plan  for  Net-Zero  Age”  also  highlights  that 
“long-term price contracts could play an important role to enable all electricity users to benefit 
from more predictable and lower costs of renewable power”.  

As explained above, recent high electricity prices in the short-term markets stem from the influence 
of high prices for natural gas and other fossil fuels. More investment in renewables is therefore 
needed because, when these dominate the electricity mix and energy bills are less dependent on 
short-term markets, it means not only that less fossil fuel generation is needed, but it also leads to 
lower prices for consumers due to the low operational costs of renewable energies. For Member 
States that have decided to rely on nuclear energy, the relevant  investments can meet a similar 
objective.  All  routes  to  market  should  remain  open  for  investments  in  low-carbon  generation 
capacities,  and  in  particular  renewables,  to  ensure  that  we  can  achieve  the  speed  and  scale  of 
deployment needed. The benefits  of these  low carbon sources can be brought  to  consumers by 
ensuring that long-term markets and contracts with stable prices increasingly constitute a larger 
share of the energy component of the final electricity bill. This can be achieved in several ways: 

15  

COM(2023)62 COM_2023_62_2_EN_ACT_A Green Deal Industrial Plan for the Net-Zero Age.pdf 
(europa.eu) 

16 

 
 
 
 
 
 
 
 
 
                                                 
1.  Companies  can  contract  directly  over  the  long-term  with  power  producers.  The  present 
reform  aims  at  supporting  the  development  of  the  Power  Purchase  Agreement  (PPA) 
markets, which are private contracts between producer and consumer over the long-term 
(typically 5 to 10 years and up to 20 years in the current practice). 

2.  Member States can contract over the long-term on behalf of consumers. The present reform 
aims at clarifying ways for Member States to support the roll-out of renewable and low-
carbon generation by ensuring predictability of revenues for new investments through two-
way Contracts-for-Difference (CfDs) (typically more than 10 years). This type of contract 
brings  greater  price  stability  to  consumers  because  revenues  collected  by  the  Member 
States when market prices are above the contracted price will revert to the consumers, and 
vice versa. 

3.  Improving the functioning of the forward market (up to 3 years ahead) to give consumers 
and suppliers the ability to correctly cover their price exposure. A well-functioning forward 
market  will incentive the development  of fixed-price contracts  with  consumers, thereby 
bringing greater price stability to the final consumers. 

4.  Enabling  consumers  to  contract  directly  with  renewable  energy  sources  through  energy 
sharing. The present reform aims to enable energy sharing between active customers to 
give a wider group of consumers the opportunity to hedge against volatile wholesale market 
prices and control their energy bills. 

Another way to bring the benefits of low-cost renewables to the consumers would be to introduce 
more locational granularity in market prices. This is discussed further in section 8.2 below. 

2.1.   Supporting the Power Purchase Agreement (PPA) market  

Feedback from public consultation 

Overall,  stakeholders  generally  see  the  use  of  Power  Purchase  Agreements  (PPAs)  as  an 
effective  way  to  mitigate  short-term  market  fluctuations  in  electricity  prices  and  identified 
several  measures  to  strengthen  their  uptake.  However,  there  are  also  potential  risks  and 
challenges that need to be carefully considered. 

The  use  of  PPAs  is  widely  considered  an  effective  way  to  mitigate  the  impact  of  short-term 
market fluctuations on electricity prices paid by the consumers, including industrial consumers, 
according to a large majority of stakeholders in the energy sector. These stakeholders include 
national or local administrations, regulators, market operators, energy companies, independent 
energy  suppliers,  industrial  consumers  and  associations,  energy  communities,  academia  and 
think  tanks,  citizens,  and  NGOs.  The  majority  of  stakeholders  identified  supporting 

17 

 
 
 
 
 
 
 
 
 
standardisation  of  contracts,  pooling  demand,  and  providing  insurance  against  risks,  either 
market  driven  or  through  publicly  supported  guarantee  schemes,  as  effective  measures  to 
strengthen the roll-out of PPAs. 

Some stakeholders, mainly energy professionals, also identified other ways to strengthen the 
use of PPAs for new private investments, such as improving access to finance and facilitating 
cross-border  PPAs.  However,  there  were  mixed  responses  from  stakeholders  on  whether 
stronger incentives should be provided to existing generators to enter into PPAs for a share of 
their capacity, with potential benefits including lower costs in the short term, and challenges 
such as market distortion, higher costs in the longer term and potential conflicts with existing 
contractual obligations. 

The majority of stakeholders did not consider that stronger obligations on suppliers and/or large 
final customers to hedge their portfolio using long-term contracts would contribute to a better 
uptake  of  PPAs.  However,  opinions  were  mixed  among  companies  in  the  energy  sector  and 
energy communities. 

Some stakeholders also identified potential risks associated with increasing the uptake of PPAs, 
including  reduced  liquidity  in  short-term  markets,  an  unequal  level  playing  field  between 
undertakings of different sizes or located in different  Member States, and increased costs for 
consumers. However, a majority of stakeholders did not consider increasing the uptake of PPAs 
would entail risks as regards increased electricity generation based on fossil fuels. 

o  Introduction 

A Power Purchase Agreement (PPA) is a commercial long-term contract (usually between 5 and 
10 years, up to even 20 years in the current practice) between a generator and a buyer, whereby 
the latter purchases a specific volume of electricity from the former at a predetermined price over 
a certain period16 providing price certainty over the long-term for energy consumers. PPAs provide 
the main alternative to public support schemes for renewable energy generation projects.  

For project promoters, a key benefit of PPAs is the predictability and long-term stability of price 
and  cash  flows  they  provide.  This  allows  PPAs  to  serve  as  collateral  in  the  financing  of  new 
projects, including renewable energy projects. Through a PPA, the buyer enjoys access to power 
generation  to  meet  its  electricity  demand  at  a  fixed  price  over  the  long  term  and  thus  a  hedge 
against price uncertainty. This can significantly strengthen the competitiveness of industrial off-
takers. In most cases, as a result of a renewable PPA, the off-taker will also receive the related 
guarantees of origin which is often an additional motivation to enter into a PPA. Private off-takers 

16  

The buyer in a PPA is normally a private company. Nevertheless, public entities can also procure electricity 
for their own consumption from renewable energy generators through PPAs. 

18 

 
 
 
 
 
 
 
 
                                                 
use  renewables  PPAs  as  credible  instruments  to  demonstrate  their  adherence  to  sustainability 
criteria in their energy consumption. Finally, from the point of view of governments, PPAs offer 
an alternative avenue to foster the deployment of renewables towards their targets or commitments, 
without committing public funds. 

o  State of play 

On  the  back  of  the  continuing  cost  decreases  of  renewable  energies,  the  overall  volume  of 
renewables  PPAs  in  Europe  (including  the  UK  or  Norway)  has  increased  exponentially  since 
crossing the 1 GW threshold in 2016. After reaching 8 GW in 2021, early data for 2022 indicate a 
first-ever drop in the volume of such deals (to below 7 GW). An initial assessment suggests that 
this change of trend may have resulted from a number of mixed signals: increased price volatility, 
uncertainty about future price levels, inflation and increased prices of raw materials. These factors 
have made the agreement on the price more complex, while also increasing the attractiveness for 
generators of selling on the short-term market. Regulatory initiatives to address the environment 
of high electricity prices have also contributed to uncertainty.   

Until  2021,  the  growth  of  PPAs  was  largely  attributable  to  a  small  group  of  companies  in  the 
information technology sector. The 2022 data shows a noticeable increase in interest for PPAs by 
the industry energy-intensive sector17. Nevertheless, the market remains accessible only for large 
credit-worthy companies. 

In terms of geographic distribution, the use of PPAs is still limited to a core group of Member 
States: so far only in five of them more than 1 GW of cumulated deals have been reported18 and 
more than 20 GW in the EU as a whole. In this regard, 2022 has brought new interest, with deals 
now reported in half of the Member States19. 

17  
18  
19  

Re-source platform 
Spain, Finland, Denmark, Sweden and Germany - Re-source platform 
Re-source platform 

19 

 
 
 
 
 
 
 
 
 
                                                 
Figure 3: Evolution of the PPA market in Europe 

Source: Windeurope Intelligence platform 

A  PPA  market  study20  for  the  European  Investment  Bank  estimated  the  aggregated  volume  of 
PPAs required by renewable energy promoters in the EU to range between 140 TWh and 480 TWh 
by 2030, the higher figure being equivalent to 170 GW of capacity (8.5 times above the current 
PPA level) and to 23% of solar and wind generation by 2030. The study adds a second demand 
estimation based on the EU’s renewable hydrogen policies presented in 2022, leading to a range 
of between 360 TWh and 980 TWh by 2030. 

In other words, the EU PPA market is gradually expanding to new countries and sectors and the 
market estimates dynamic growth. Nevertheless, this market remains far from its full potential due 
to a range of obstacles and barriers. 

o  Obstacles and barriers 

There is a significantly differentiated development of PPAs in the EU. One of the main obstacles 
that  prevents  a  PPA  market  from  flourishing  are  price  risks  linked  to  the  uncertainty  of  future 
electricity price developments and the long duration of the contract. Before the crisis, many off-
takers expected the electricity prices to fall, which reduced the attractiveness of a long-term lock-
in of a stable price. Many potential off-takers are not aware of the advantages of a PPA, which 
remains a relatively new offer. Since the PPA market is still in its early years, contracts are not 
standardised  yet,  leading  to  high  transaction  costs,  limited  liquidity  and  limited  availability  of 

20  

Commercial Power Purchase Agreements. A Market Study including an assessment of potential financial 
instruments to support renewable energy Commercial Power Purchase Agreements. Final report prepared by 
Baringa, March 2022  

20 

 
 
 
 
 
 
 
                
 
 
                                                 
PPAs  of  different  sizes  and  durations,  in  particular  shorter-term  contracts  (as  from  3-year 
maturity). When the off-taker requests a generation profile fully adapted to its consumption needs, 
it adds an additional layer of complexity. Furthermore, in many Member States renewable energy 
developers have opted for stable revenues from public support schemes providing often a 100% 
protection  from  market  risks  over  the  long-term  (longer  than  10  years).  Long  permitting 
procedures have also hampered the availability of new projects and thus the development of the 
PPA market. 

Another particular problem with signing PPA contracts is the difficulty of establishing the credit 
worthiness of potential buyers. For developers, finding a client with a strong credit rating is often 
a requirement to secure financing for a renewable energy project on the back of a PPA. However, 
in some Member States, many entities with an appropriate energy footprint for PPAs are not rated 
by any major ratings agency, even if they do not experience financial difficulties. For off-takers, 
the  main  obstacle  is  to  find  PPAs  that  match  their  consumption  profile  and  the  length  of  their 
business cycle. The variability of the generation from renewable installations leads to additional 
complexity and costs in managing volume imbalances through an energy provider or in the spot 
market.  Finally,  the  PPA  market  has  not  been  available  to  small-  and  medium  size  enterprises 
mainly for two reasons: 1) the limited electricity consumption of a SME requires a multi-buyer or 
aggregated PPA to make an interesting offer to a project developer, and 2) the signing of a PPA 
still represents a complex deal entailing high transaction costs and requiring energy management 
expertise.  

There are also some regulatory barriers hampering PPAs at national level, such as obstacles to the 
signature  of  direct  contracts  between  generators  and  off-takers.  In  some  cases,  the  issuance  of 
Guarantees of Origin requested by the off-taker is hindered due to national legislation.  In most 
Member  States,  with  some  clear  exceptions,  there  has  also  been  limited  attention  given  to  the 
promotion of PPAs, building policies to promote renewable energy generation projects on public 
support schemes. If the pipeline of renewable energy is constrained by political or administrative 
factors  and  the  government  issues  renewable  energy  auctions  commensurate  with  its  total 
decarbonisation ambitions, the result can be a situation where most or all projects receive public 
support. This  is  why it is crucial that,  in  order to send a  clear medium-term signal  to  the PPA 
market,  Member  States  take  into  account  the  potential  for  PPAs  to  cover  part  of  their 
decarbonisation objectives, as spelled out in their National Energy and Climate Plans, and plan 
their public support auctions accordingly. 

o  Current EU framework 

The 2018 Renewable Energy Directive contains a definition of renewables PPAs and mandates 
Member States to assess the related “regulatory and administrative barriers” and remove them, if 
unjustified,  while  ensuring  that  PPAs  are  not  “subject  to  disproportionate  or  discriminatory 
procedures  or  charges”.  The  2021  proposal  to  revise  the  Directive  introduced  amendments  on 
renewables PPAs, including the need for Member States to explore credit guarantees to promote 

21 

 
 
 
 
 
 
 
renewables PPAs and to ensure that the generator can transfer the related Guarantees of Origin to 
the buyer. 

Finally,  the  same  Directive  mandates  the  inclusion  of  “policies  and  measures  facilitating  the 
uptake”  of  renewables  PPAs  in  the  National  Energy  and  Climate  Plans  (NECPs).  Only  some 
Member States have clearly signalled what share of the targeted deployment they expect PPAs to 
cover. The 2021 proposal to amend the Directive inserts a reference to renewables PPAs as an 
instrument  to  achieve  the  Member  States’  contribution  to  the  EU  renewable  energy  target, 
alongside public support and mandates Member States to provide in their NECPs “an indication 
of the volume of renewable power generation supported by” renewables PPAs. 

The Electricity Market Regulation, on the other hand, does not explicitly refer to PPAs but ensures 
that “long-term electricity supply contracts” can be negotiated “over the counter” in order to “allow 
market participants to be protected against price volatility risks on a market basis, and mitigate 
uncertainty on future returns on investment.” 

EU  legislation  therefore  recognises  PPAs,  including  renewables  PPAs,  as  private  commercial 
bilateral agreements that are compatible and complementary with organised short-term and long-
term markets. In addition, the legislation aims at establishing a level playing field for renewables 
PPAs  in  achieving  the  EU’s  renewable  energy  targets,  alongside  public  support  and  merchant 
investments. 

Beyond  legislative  texts,  the  Commission  adopted  in  May  2022,  as  part  of  the  REPowerEU 
package, a recommendation to Member States to promote renewables PPAs, accompanied by a 
guidance21. 

A higher volume of PPAs will contribute to the achievement of the EU 2030 target for renewables 
without the need for public support. PPAs can also contribute to transfer the benefits of low-cost 
renewables to consumers and provide them with stable prices. Although it can be expected that, 
based on the current legislative framework, PPAs will become gradually more popular across the 
EU, their promotion through regulatory means is justified in view of the significant environmental, 
economic and social benefits stemming from the accelerated and wide-spread development of the 
PPA market. 

o  Commission proposals 

The proposed amendment to the Electricity Regulation therefore builds on existing legislation and 
guidance to ensure that Member States create the conditions necessary for a bigger PPA market to 

21  

Opinion of the European Economic and Social Committee on Communication from the Commission to the 
European Parliament, the Council, the European Economic and Social Committee and the Committee of the 
Regions — EU Solar Energy Strategy (COM(2022) 221 final) and Commission recommendation on speeding 
up permit-granting procedures for renewable energy projects and facilitating Power Purchase Agreements 
(C(2022) 3219 final) https://eur-lex.europa.eu/legal-content/EN/ALL/?uri=CELEX:52022AE3515   

22 

 
 
 
 
 
 
 
                                                 
develop. There is a range of policy instruments to address the current shortcomings in PPA markets 
across the EU, which can be used by Member States and enabled by EU legislation: 

-  The risks associated with a payment default by the potential buyer remains a key obstacle 
for the signature of PPAs. National governments should ensure that all conditions are in 
place for the market  to  provide the required financial instruments  to  cover against such 
risks  when  the  potential  buyer  has  the  necessary  financial  stability.  Given  the  intrinsic 
difficulties  associated  with  new  markets,  governments  shall  ensure  that  instruments, 
including  guarantee  schemes,  are  in  place  to  unlock  demand  for  PPAs  from  private 
operators  that  face  difficulties  in  accessing  the  PPA  market.  Such  guarantees  can  be 
designed in a way that do not constitute State aid. 

-  State aid for renewable generation and PPAs are perceived as two alternative channels to 
finance renewable electricity project, but they can also be complementary. Member States 
should ensure that bidders to public tenders are allowed to (and can in practice) reserve 
part  of  the  project’s  generation  for  a  market-based  revenue  stream,  in  particular  one  or 
several PPAs. Combining State aid and PPAs in a single project can facilitate the financing 
of new projects and reduce risk exposure. Going further, governments shall endeavour to 
use   evaluation criteria in the public tender to  incentivise the access to the PPA market for 
customers that face entry barriers This instrument can be used either to kickstart a PPA 
market in Member States where it is lacking or to expand its reach to smaller operators 
where a PPA market is already in place. 

Finally, PPAs can be expected to play a role in any obligation on electricity suppliers to hedge in 
order to protect consumers from possible supplier failures (see section on consumer protection and 
empowerment).  

2.2.   Contracts for Difference (CfD) for new decarbonised investments 

Feedback from public consultation  

A  large  majority  of  professional  respondents  (70%)  consider  the  use  of  two-way  CfDs  as  an 
efficient way to mitigate the impact of short-term markets on the price of electricity and to support 
investments in new capacity, where investments are not forthcoming on a market basis. 

Similarly,  a  majority  of  professional  respondents  (60%)  consider  that  new  publicly  financed 
investments  in  inframarginal  electricity  generation  should  be  supported  by  way  of  two-way 
contracts for differences or similar arrangements, as a means to mitigate electricity price spikes 
of consumers while ensuring a minimum revenue.  

23 

 
 
 
 
 
 
 
 
With  regards  to  scheme  design,  most  participants  also  consider  that  two-way  CfDs  schemes 
should  not  be  mandatory,  not  be  imposed  retroactively,  and  should  focus  exclusively  on  new 
investments for which prices should be determined via competitive auctions or tenders. 

When asked about  the risks of requiring new publicly supported inframarginal  capacity to  be 
procured  on  the  basis  of  two-way  CfDs  or  similar  arrangements,  a  majority  of  respondents 
(including national authorities22) cite the risk of distortion on short-term markets.  

Other risks mentioned are: the impact on the development of PPAs and forward markets, budget 
risk for Member States when market prices decrease, termination risk when market prices are 
high, competition risk by favoring established or dominant technologies leading to non-optimal 
energy  mix,  risk  of  inefficient  redistribution  mechanism  to  consumers,  risk  that  supported 
consumers would be less inclined to use demand management technologies,  risk of ending up 
with a fragmented EU market if CfDs are not applied in an uniform way, risk of inappropriate 
energy mix, as opposed by market prices. 

Most of these risks are associated with a poor design of two-way CfDs. When asked about the 
design principles for two-way CfDs, respondents suggest the following procurement principles 
and pay-out design: 

- 

- 

- 

to decouple the payout from the dispatched volume; 

the  payout  to  cover  only  partially  the  volume  produced  to  leave  exposure  to  market 
signals; 

the payout to be based on a proper reference price (possibly over a longer time period) to 
avoid inefficient trading behaviour; 

-  payout suspension in certain situations (e.g., negative prices); 

- 

- 

- 

- 

- 

- 

a price corridor as opposed to a fixed strike price; 

financial nature as opposed to contracts with physical delivery; 

accompanied by tools ensuring that generated volume is made available on the forward 
market; 

to be procured on a voluntary basis, as opposed to mandatory imposition of CfDs; 

to be procured by technology neutral tenders. Strike price should be defined as a result of 
a competitive process, not as a cost-plus regulation; 

to be shielded from potential intervention limiting producers revenues; 

22  

From CZ, DK, EE, FI, FR, HU, LT, MT, NL, ES 

24 

 
 
 
 
 
 
 
                                                 
- 

two-way  CfDs  should  comply  with  approved  taxonomy  criteria  to  avoid  subsidising 
technologies which are not climate friendly. 

Regarding  eligible  technologies,  the  majority  of  respondents  answered  that  two-way  CfDs 
should only be offered to new low-carbon inflexible capacity and only in case new investments 
are not forthcoming on market-based terms. They explained that flexible resources should remain 
exposed  to  price  variations.  Some  respondents  also  cite  non-competitive  but  promising 
technologies which the market is unable to deliver (such as immature renewables and innovative 
technologies).  Most  of  them  agreed  that  fossil  energy  sources  should  be  excluded.  Many 
respondents insisted on the voluntary nature of CfDs, as opposed to mandatory CfDs. 

Some respondents explained that the allocation of CfD revenues should be a prerogative of each 
Member State, either to consumers (through levies) or to investments that facilitate the energy 
transition. Others recommended that the revenues should be channeled back to all consumers on 
an  equal  basis  according  to  their  electricity  consumption.  Yet  some  others  suggested  that  the 
subsidy  should  not  be  proportional  to  the  consumption  but  primarily  allocated  to  the  lowest-
income households or used towards subsidising a minimum consumption for basic needs. 

A wide majority of professional stakeholders (83%) oppose giving Member States the possibility 
to  impose  two-way  CfDs  on  existing  generation  capacity.  Furthermore,  especially  national 
regulators  and  market  operators  see  high  or  very  high  risks  that  imposing  regulated  CfDs  on 
existing generation capacity would mean locking in existing capacity at excessively high prices 
determined by the current crisis. 

Only 31 respondents defined the appropriate terms and conditions for two-way CfDs for existing 
generation. These respondents – mainly French and Spanish23 - advocate for price-regulation on 
existing  assets.  The  French  respondents  explained  that  regulated  two-way  CfDs  on  existing 
generation should be limited to the specific case of existing nuclear fleet  to avoid a dominant 
position and address competition issues. 

23  

French  authorities,  Commission  de  régulation  de  l'énergie  ,  RTE  Réseau  de  Transport  d'Électricité,  EDF 
(Electricité de France), Parliamentary Group  - La France Insoumise, France Chimie, MEDEF - Mouvement 
des entreprises de France (only for low carbon assets), CLEEE (Comité de Liaison des Entreprises ayant Exercé 
leur  Eligibilité  sur  le  marché  de  l'Electricité),  French  Fédération  Forge  Fonderie,  French  Verkor,  French 
ERAMET,  French  VICAT,    French  SUD  Energie,  AFEP  -  The  French  Association  of  Large  Companies, 
Association Française Indépendante de l'Electricité et du Gaz, Spanish Ministry for the Ecological Transition 
and  the  Demographic  Challenge,  Feníe  Energía  S.A.,  FORTIA  ENERGÍA  S.L,  ASOCIACIÓN  DE 
COMERCIALIZADORES  DE  ENERGÍA  ELÉCTRICA  (ACENEL),  Asociación  de  Empresas  con  Gran 
Consumo de Energía - AEGE, Asociación Empresarial de Pilas, Baterías y Almacenamiento Energético 

25 

 
 
 
 
 
 
 
 
 
 
                                                 
o  State-of-play 

The Council of European Energy Regulators (CEER) report24 found that the volume of supported 
renewable electricity increased from 489 TWh in 2018 to 529 TWh in 2019 in the EU and in terms 
of installed capacity this increased from 257 GW in 2018 to 269 GW in 201925. A large share of 
RES generation has therefore received State support - as illustrated by Figure 4 below. 

Figure 4: Renewable electricity subsidised in 2019 (volume and %) 

Source:  European  Commission,  based  on  CEER  2021  Status  Review  of  Renewable  Support 
Schemes report 

However, a significant and increasing volume of renewable production has also been brought to 
the market without receiving any State support in particular as regards onshore wind and solar PV. 
Furthermore, a study on offshore wind competitiveness26 shows that the price paid for power from 
offshore wind farms across Northern Europe fell significantly over the past eight years. The study 
concludes that offshore wind power generation can be considered commercially competitive in 
mature markets.  

In  light  of  the  above,  it  is  important  that  long-term  State  contracts  are  a  complement  to  other 
privately funded projects (such as for example the Mankala model in Finland). Therefore, Member 

24  
25  

26  

CEER (2021) Status Review of Renewable Support Schemes in Europe for 2018 and 2019 
Data includes information for EU 27, excluding Poland, Finland and the Netherlands for which there was no 
complete information 
”Offshore wind competitivenes in mature markets without subsidy” - Malte Jansen, Iain Staffel, Lena 
Kitzing, Sylvain Quoilin, Edwin Wiggelinkhuizen, Bernard Bulder, Iegor Riepin and Felix Müsgens - 
https://www.nature.com/articles/s41560-020-0661-2 

26 

 
 
 
 
 
 
 
 
 
 
                                                 
States should consider the significant potential for the PPA market (see above), alongside other 
market arrangements and public support. 

When public support is needed to ensure predictability in operating revenues for new investments 
in fossil-free generation that would not come forward without support, the instrument used should 
be  appropriately  designed  to  be  as  least  distortive  as  possible  to  ensure  value  for  money  for 
consumers.  The  Commission  observes  that  a  wide  range  of  State  support  schemes  co-exist, 
depending on the Member State27:  

  Feed-in tariffs (FITs): FITs usually involve long-term agreements on fixed volumes and 
prices tied to the cost of production of the energy in question. This protects producers from 
risks inherent in renewable energy production both in relation to the volume and price and 
encourages  investment  and  development  that  otherwise  might  not  take  place.  FITs  are 
usually  differentiated  by  technology  and  size  to  reflect  the  different  generation  costs 
between  the  various  renewable  energy  technologies.  The  support  level  of  FITs  is 
determined through administrative procedure, which can lead to overcompensation due to 
the risk of a long reaction time to respond to changes in renewable energy production costs. 
Also, FITs may disconnect the producer from market signals and incentivise production 
when not needed. 

  Fixed feed-in premiums (FIP)28: A FIP allows producers to receive a premium on top of 
the market  price  for their electricity  production,  with  electricity from renewable  energy 
sources typically sold on the electricity spot market. Hereby, FIPs provide an incentive for 
RES operators to respond to price signals of the electricity market, resulting in a somewhat 
more responsive supply compared to FITs, also being more cost-efficient support schemes 
for the government to increase renewable energy installations. However, during the high 
price crisis, many installations benefiting from FIP, on top of high market prices, led to 
claims that they were accruing “windfall profits”.  

  Sliding  feed-in-premiums  also  known  as  Contracts  for  Difference  (‘CfD’):  A  CfD 
entitles the beneficiary to a payment equal to the difference between a fixed ‘strike’ price 
and a reference price, such as a market  price, per unit of output (also  known as sliding 
premium). One-sided CfDs aims to guarantee a minimum price to the producer. This type 
of contract would therefore not address the challenge of excessive remuneration in a high 
price environment since there would be no limitation on the revenues. Two-way CfDs also 

27  

28  

Other support schemes are green certificates, investment grants, taxes or levies. These are not covered in the 
current Staff Working Document 
Fixed feed-in premiums (‘FIPs’) were introduced in several EU member states following the criteria laid down 
in  the  General  Block  Exemption  Regulation  from  2014  (‘GBER’)[1]  and  the  State  Aid  Guidelines  for 
Environmental Protection and Energy (‘EEAG’)[2]. There was a shift from FIT to a progressive mandatory use 
of FIP and competitive bidding. 

27 

 
 
 
 
 
 
 
                                                 
involve payback from beneficiaries to the State for periods during which the reference price 
exceeds the strike price.  

In recent years, there has been a move towards a greater use of two-way CfDs. Figure 5 below 
shows  the  increase  in  the  share  of  competitive  procurements  that  utilise  two-way  CfDs.  Such 
contracts provide new investments with revenue certainty, thereby reducing investors’ capital cost, 
while  avoiding  excessive  returns  for  investors  and  overcompensation  from  Member  States  in 
periods when market prices are high. In other words, the State will be shielded from high market 
prices when the wholesale price is above the strike price, but will bear the financial cost when the 
market price is below the strike price. The reverse can be said for the renewable developer.  

Figure 5: Distribution of renewables auction per support scheme (2014-2021) 

Source: European Commission analysis29 based on Aures2 dataset 

The main advantage of two-way CfDs – when designed in an appropriate way – is to ensure stable 
revenues  for  the  generators,  while  limiting  excessive  revenues  in  a  high  market  prices 
environment,  and  they  would  at  the  same  time  also  alleviate  the  pressure  of  high  prices  on 
consumer bills if the revenues are channeled back to consumers.  

29  

The  table  is  based  on  an  analysis  of  383  auctions  between  2014-2021.  The  figure  reports  only  concluded 
auctions.  The  data  includes  observations  for  the  following  countries  Croatia,  Denmark,  Estonia,  Finland, 
France,  Germany,  Greece,  Hungary,  Ireland,  Italy,  Lithuania,  Luxembourg,  Malta,  Netherlands,  Poland, 
Slovenia, Spain. The data includes one observation per auction, regardless of the number of lots included in 
the auction (in the Aures2 dataset a number of auctions are multi-technology and include different entries per 
technology. We have treated all these entries as a single auction. Two auctions for Portugal have been excluded 
as it was unclear what was the remuneration scheme. The hybrid auctions included a mixture between sliding 
and fixed premiums. 

28 

 
 
 
 
 
 
 
 
                                                 
To illustrate this point, at the height of the crisis in August 2022, France estimated that it would 
collect EUR 30.9 billion from renewable-power producers over two years30, as the energy crisis 
boosted wholesale price levels beyond the guaranteed revenues under the existing RES support 
scheme.  The  excess  revenues  collected  ultimately  benefit  the  end-consumers  and  thereby 
significantly reduce the impact of gas-fired power generation on the end-consumer bills. 

On the other hand, existing FIP schemes that did not include a cap on revenues led to some Member 
States paying a premium to producers, on top of already high market prices.  

To quantify the potential effect of CfDs, DG Energy applied the METIS power system model to 
simulate the potential revenues generated if 75% of new RES capacity would be subject to two-
way CfDs as from 2023. The results estimate that such schemes would allow Member States to 
collect about [4.5-6 bn] EUR in 2023, [9-12bn] EUR in 2024, [13.5 – 18 bn] EUR in 2025 (and so 
on) to return to companies and households. 

o  Design principles for two-way CfDs 

Several  types  of  two-way  CfDs  are  currently  in  place,  with  advantages  and  disadvantages, 
depending among others on how the reference price index and the reference volume are defined. 
When providing State support through CfDs, it is of utmost importance that these contracts are 
designed  in  a  way  that  drives  the  required  investments  in  renewables  and  other  low-carbon 
generation cost-effectively while minimising market distortions and keeps the right incentives in 
place  to  respond  to  market  price  signals  and  optimise  the  dispatch  of  renewable  electricity 
generation accordingly.  

The reference price used to define the payment plays a significant role in potential behavioural 
distortions  and  inefficiencies  of  dispatch.  When  designed  inappropriately,  two-way  CfDs  risk 
inducing “produce and forget” behaviour – by incentivising production in all situations, even when 
prices are negative. To mitigate this issue, some Member States have included a discontinuation 
of the premium payment when spot prices are negative. However, such a mitigation clause – easily 
applicable in the single price day-ahead market - is difficult to apply in the intraday market or the 
imbalance market, since these timeframes are traded on a continuous basis with no single price 
signal representative for all market parties. To address the risk of market distortion, other Member 
States have delayed the publication of the CfDs premium31 until after-market closure, in an attempt 
to restore normal bidding behaviour.  Respondents to the public consultation also explained that a 

30  

31  

Délibération  de  la  CRE  du  3/11/2022  relatives  aux  charges  de  service  public  de  l'énergie  (CSPE)  : 
https://www.cre.fr/Documents/Deliberations/Decision/reevaluation-des-charges-de-service-public-de-l-
energie-pour-2023  
For example by using the effective Day-Ahead prices as reference (which are known only ex-post after the 
bidding in the Day-Ahead Market), as opposed to using ex-ante reference prices based on historical averages 

29 

 
 
 
 
 
 
 
 
                                                 
price corridor, rather than a fixed strike price, would help incentivise producers to react to short-
term supply and demand fluctuations. 

In  a similar way, the  reference volume  used to  define the two-way CfDs  payout  also  plays  an 
important role in preventing potentially inefficient market behaviour. To address this risk, several 
respondents to the public consultation have expressed the idea of decoupling the CfDs payout from 
actual production levels: 

-  Some  respondents  to  the  public  consultation  have  submitted  the  idea  of  designing 
“capability-based CfD”, by which the underlying volume determining the payment is based 
on  the  expected  generation  rather  than  on  actual  injected  energy.32  In  their  view,  the 
decoupling of the CfDs payout from the actual injection avoids potential market distortions 
and inefficient dispatch.  

-  Others suggested the introduction of “financial wind CfDs”33, as a hybrid form of CfDs 
and forward contracts to mitigate risks and keep incentives to react to market price signals. 
Financial wind CfDs work as a stream of fixed monthly payment to the producer, while the 
producer pays back the spot market revenue of that month to the government.  

-  ACER  has  suggested  the  use  of  a  Collar  instrument  with  cap  and  floor,  by  which  the 
generator revenues are calculated based on production when prices are high, but based on 
available  capacity  when  prices  are  low,  to  keep  incentives  for  the  producer  to  react 
appropriately to market price signals. 

-  An academic has suggested using CfDs with a sliding premium ‘flexibility contracts’ to 
expose generators to the desired degree of price exposure.34 Under this type of contract, 
the  generator  receives  the  strike  price  plus  a  flexibility  bonus  per  unit  produced.  The 
flexibility bonus is the equivalent to the difference between the market price and a reference 
average  price  calculated  over  an  extended  period.  To  avoid  capacity  withholding  the 
contract can also include a penalty. This kind of CfDs exposes capacity owners to price 
and incentivises dispatch when it is most needed.   

All  of these schemes have advantages and drawbacks. Each design will have an impact  on the 
electricity system, the value for money for consumers and the full integration of renewables into 
the market. Careful consideration is needed depending on the Member State, technology type and 
the reinforcement plans for grid infrastructure in that area. Therefore, location is a crucial feature 
when contracting two-way CfDs. Commission analysis from the Joint Research Center (JRC) has 

32  

33  

34  

See for instance, Newbery, D. (2022): “Designing an incentive-compatible efficient renewable electricity 
support scheme”, Cambridge Working Paper Series 
See Schlecht, I., Hirth, L., and Maurer, C. (2022) “Financial Wind CfDs” Working & Discussion Papers / 
Preprints, EconStor Direct 
Fabra, N., (2022) “Electricity Markets in Transition: A proposal for reforming European electricity markets” 
CEPR Discussion Paper 17689. 

30 

 
 
 
 
 
 
 
                                                 
highlighted the risk of extremely high dispatch costs by 2040, if renewables projects are selected 
solely based on criteria such as highest full-load hours, CfDs price or the available land. In their 
view, the auction for CfDs supporting low-carbon investment should incorporate some locational 
elements. This could be implemented by selecting the auction winners not only based on bid price, 
but by running on expansion model that would select the best combination of bids that achieve the 
auction targets (in MW or MWh) while minimising system costs. 

o  Current EU framework 

Currently, the legislative framework applicable to renewable energy sources is contained in the 
Directive 2018/2001 on the promotion of the use of energy from renewable sources (‘Renewable 
Energy  Directive’)35.  Articles  4  to  6  contain the  relevant  principles  applicable  to  the  design  of 
support  schemes  for  renewables,  applicable  without  prejudice  to  Articles  107  and  108  TFEU 
dealing with State Aid and the related legislation and guidelines36.  

The main principles applicable to design of support schemes for electricity from renewable are 
included  in  Article  4  of  the  Renewable  Energy  Directive.  In  particular,  support  schemes  must 
provide  incentives  for  the  integration  of  electricity  from  renewable  sources  and  ensure  that 
renewable energy producers respond to market price signals. The Directive provides two possible 
tools for such support schemes: either a sliding or a fixed market premium. Finally, the support 
must  be  granted  through  open,  transparent,  competitive,  non-discriminatory  and  cost-effective 
procedures. Furthermore, Article 6 of the Renewable Energy Directive prevents Member States 
from modifying the existing support schemes and establishes that they should publish a long-term 
schedule anticipating the expected allocation of support. 

The 2022 Guidelines on State aid for climate, environmental protection and energy (‘CEEAG’) 
include an additional set of principles applicable to support schemes for renewables which require 
state aid, taking into account the binding and ambitious climate targets for 2030 and 2050. The 
CEEAG establish that when assessing whether aid is compatible with the internal market under 
Article 107 of the Treaty, the Commission will analyse whether the aid facilitates the development 
of  an  economic  activity  and  whether  it  does  not  unduly  affect  trading  conditions  to  an  extent 
contrary to the common interest. 

35  

36  

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 
Communication  from  the  Commission  –  Guidelines  on  State  aid  for  climate,  environmental  protection  and 
energy 2022 and the following two texts under review; Commission Regulation (EU) No 651/2014 of 17 June 
2014 declaring certain categories of aid compatible with the internal market in application of Articles 107 and 
108 of the Treaty; Communication from the Commission Temporary Crisis Framework for State Aid measures 
to  support  the  economy  following  the  aggression  against  Ukraine  by  Russia  (it  includes  a  section  on 
accelerating  the  deployment  of  renewables  to  simplify  the  requirements  for  this  deployment;  given  the 
measures are temporary, they will not be described further here). 

31 

 
 
 
 
 
 
 
                                                 
The 2022 Guidelines on State aid for climate, environmental protection and energy (‘CEEAG’) 
establish, among other principles, that aid must be designed to prevent any undue distortion to the 
efficient functioning of markets and, in particular, preserve efficient operating incentives and price 
signals.  For  instance,  beneficiaries  should  remain  exposed  to  price  variation  and  market  risk, 
unless this undermines the attainment of the objective of the aid. Finally, incentives must not be 
provided for the generation of energy that would displace less polluting forms of energy.37 

o  Commission proposal 

In order to reach its decarbonisation targets and the objectives set out in REPowerEU to become 
more energy independent, the EU needs to accelerate the deployment of renewables at a much 
faster  rate.    Some  Member  States  are  also  envisaging  new  investments  in  other  forms  of  low 
carbon, non-fossil fuel electricity generation, such as nuclear. To achieve this, it is crucial that all 
possible investments from the private sector are mobilised first, in order to limit the pressure on 
the public budget. Next, when needed to ensure that the necessary investments take place, public 
support  schemes  should  not  crowd  out  private  investments.  It  is  equally  important  for  support 
schemes to be well-designed, reflecting the experience from the energy crisis and to mitigate some 
of  the  risks  explained  by  respondents  to  the  public  consultation.  As  outlined  above,  many 
renewable support schemes today are still based on a market premium (a top up on the market 
price) which led to uncapped and excessive publicly financed returns in the period of market price 
spikes.  

 Publicly supported schemes can contribute to long-term price stability and help to lower the cost 
of energy for consumers and businesses in times of high energy prices. Therefore, the Commission 
would like - in the context of this reform - to describe more precisely the principles leading to an 
appropriate design of national support schemes complementing the existing design principles in 
the Renewable Energy Directive: 

  Where public support is needed to trigger new investments in new low carbon non-fossil 
fuel generation, this should be done via a two-way CfD or a similar contractual formulation 
which provides, in addition to a revenue guarantee, for an upward limitation on the market 
revenues  of  the  generator  concerned.  The  payout  of  long-term  support  schemes  should 
therefore  include  an  upward  limitation  of  the  revenues,  to  avoid  any  overcompensation 
using public funding. New investments in electricity generation include investments in new 
power generating facilities or investments aimed at repowering existing power-generating 
facilities, including to prolong their lifetime for example. 

  The design of two-way CfDs scheme should include the following features: 

o  The payout of the schemes should be in line with the principles set out in Article 
4(2) and 4(3), first and third subparagraphs, of Directive (EU) 2018/2001, and be 
defined to minimise behavioural distortions and keep the incentives to respond to 

37  

Paragraphs 123 and 126 of CEEAG.  

32 

 
 
 
 
 
 
 
                                                 
the market price signals. The two-way CfDs should indeed be designed so as to 
avoid a “produce and forget” approach. In addition, the limitation to set out direct 
price support schemes in the form of two-way contracts for difference should not 
apply to demonstration for which other types of direct price support schemes may 
be better placed to incentivise the uptake of innovative technologies which do not 
yet benefit from the necessary economies of scale to limit investment costs. 

o  The design of these tenders should allow the participation of projects in the auction 
that  intend  to  cover  part  of  their  production  with  a  PPA  or  other  market-based 
mechanisms. 

o  The revenues collected when the reference market price is above the strike price 
should  revert  to  electricity  consumers  in  a  uniform  manner,  based  on  their 
consumption,  in  order  to  allow  all  consumers  to  benefit  from  the  scheme  on  an 
equal basis. This allocation should be done in such a way that 1) it does not remove 
the incentives for consumers to shift their consumption to periods when the prices 
are low; and 2) does not undermine competition between electricity suppliers. 

o  The scheme includes penalty clauses in case of early termination of the contract by 
the producer, with the aim of avoiding that producers opt-out from the contract in 
periods  of  high  prices  where  they  would  have  been  obliged  to  pay-back  the 
revenues above the contract strike price. 

  As regards the scope of  application of these principles, it should be limited to  low carbon and 
renewable  energy  technologies  with  low  and  stable  operational  costs  and  to  low-carbon 
technologies  which  cannot  provide  flexibility  to  the  electricity  system,  while  excluding  (as 
mentioned above) technologies that are at early stages of their market deployment. 

o  Two-way CfDs for existing generation capacity 

The Commission proposal applies to instances where public support is granted for new investments 
in low-carbon, non-fossil fuel generation technologies. Member States’ decision to impose two-
way CfDs retroactively on existing generation capacity intervening in producers’ market revenues 
could be highly detrimental for the investment climate due to the uncertainty it causes for ongoing 
and future market-based investment decisions. The possibility for Member States to adopt such 
measures at any point in time would seriously hamper investors’ ability to estimate their income. 
This, in turn, would increase investments’ risks and the cost of capital, at the expense of consumers, 
and  ultimately  impact  the  efficiency  and  pace  of  the  energy  transition.  This  is  because  such 
measures could affect investors’ confidence about future revenues, thereby negatively impacting 
the  future  investments  needed  to  reach  EU  decarbonisation  objectives.  As  highlighted  by 
respondents to the public consultation, regulatory decisions to impose two-way CfDs could also 

33 

 
 
 
 
 
 
 
 
lead to compensating operational inefficiencies. In addition, they could lower incentives for cost-
efficient operation and market behaviour, thereby hampering competition in the market. Moreover, 
such a decision raises significant concerns among respondents about locking in existing capacity 
at  excessively  high  price  levels,  with  a  resulting  budget  risk  for  Member  States.  A  retroactive 
requirement would also entail high legal risks (identified by a significant share of the respondents 
to the public consultation) and would be incompatible with the provisions in RED II preventing 
the  revision  of  support  granted  to  renewable  energy  projects  when  it  affects  their  economic 
viability. 

2.3. 

 Improving Forward Markets 

Feedback from public consultation 

While  the  large  majority  of  professional  respondents  (83%)  consider  forward  hedging  as  an 
efficient way to mitigate exposure to short-term volatility for consumers, only a minority (18%) 
consider that the liquidity in forward markets is currently sufficient to meet this objective. 

Half  of  respondents  (54%)  consider  that  the  creation  of  virtual  hubs  for  forward  contracts 
complemented with liquid transmission rights would improve liquidity in forward markets. 

Regarding potential ways to support the development of forward markets through changes in 
the electricity market framework, respondents cite: 

-  Mandatory regional virtual hubs for trading forward contracts across all EU countries. 

- 

Introduction of Financial Transmission Rights (FTR) obligations instead of FTR options.  

-  Revision of the collateral requirements, in terms of eligible collaterals, potential EU or 
State-based participation, possibility of cross-margining between the different clearing 
houses. Respondents welcome the European Commission's proposal to amend EMIR. 

-  To stimulate market making activities.  

- 

Improve  cross-border  trading  via  Long  Term  Transmission  Rights  (LTTRs)  for  more 
than one year, more tenders, secondary market, rights with longer maturity (up to Yr+3), 
as  well  as  seasonal  and  quarterly  products.  Several  respondents  also  call  for  a  strict 
implementation of Forward Capacity Allocation Guideline Article 30, forcing TSOs to 
support liquidity for cross-zonal hedging.  

-  More frequent auctions of transmission rights.  

-  Stimulating the use of counter-trading by TSOs.  

34 

 
 
 
 
 
 
 
 
-  Reduce barriers to entry such as licencing, heavy bureaucratic requirements, reduction 

of minimum trading volume, lowering entry-threshold to exchanges. 

-  Regulatory certainty and visibility: respondents explained that market intervention create 

mistrust and unwillingness to commit for longer timeframes.  

-  Long-term hedging obligation on suppliers.  

-  Putting  an  obligation  to  generators  that  receive  CfDs  to  offer  at  least  part  of  their 

generation on the forward market.  

-  Avoid  market-distortive  subsidies  for  competitive  technologies  reducing  competitive 
pressure thereby minimising demand for market-based hedging. Limiting the scope and 
duration of subsidies. 

-  Provide support schemes to support the development of flexibility, demand response and 

storage solutions.  

-  Development of new products as suitable hedging tools for renewables production. 

-  Making longer forward contracts than what is currently possible. 

-  Fewer  bidding  zones  with  a  balance  of  natural  buyers  and  sellers  respectively,  not 

restricted by national borders. 

- 

Increase transparency and visibility in all transactions. 

-  More emphasis on investments in the transmission grids.  

-  Lowering  the  technical  price  limits  for  shorter  term  markets  (especially  day-ahead) 

would lower risks in the forward markets.  

With regards to hub trading, 78 respondents with experience of the existing virtual hubs in the 
Nordic countries (57 companies, 11 business associations, 1 academic, 1 NGO and 2 others) 
rate this experience rather or very positively, with an average score of 6.4 (out of 10).  

Many  respondents  explain  that  Nordic  hub  product  has  been  successful  in  providing  more 
liquidity  than  what  single  zone  futures  would  have  had.  In  their  view,  virtual  hubs  are  an 
interesting instrument  to combine several  markets  to  a larger, more liquid  market. However, 
they insist on the importance of complementing financial futures with other instruments such 
as  LTTRs  or  Electricity  Price  Area  Differentials  (EPAD)  to  enable  them  to  work  across 
borders.    Many  of  the  20  respondents  attributing  a  low  score  (≤  5)  justify  it  by  the  lack  of 
liquidity  in  EPADs  and  complained  that  forward  transmission  capacity  is  not  offered 
sufficiently.  

35 

 
 
 
 
 
 
 
In contrast with what market players recommended, European TSOs warned that forecasting 
how much capacity will be available in 3 years would only be feasible at a low level of accuracy. 
They explained that, if such a forecast is overestimated, too many LTTRs will be issued. The 
question of who is in such cases liable for the resulting excessive LTTR payouts would need to 
be clearly answered. If TSOs (via TSO tariffs end consumers) end up paying, there would be a 
shift of financial risks from market participants to TSOs and end consumers. European TSOs 
explained that capacity made available for maturities superior to one year will most likely have 
a limited guaranteed volume due to the difficulty of anticipating grid situation several years in 
advance.  

European TSOs also explained that switching to FTR obligations would lead to better alignment 
with forward/future products, more price discovery and higher tradable volumes. But it would 
potentially  require  a  higher  collateral  need  and/or  the  introduction  of  a  new  mark-to-market 
collateral mechanism as there is no cap for the potential losses of a market participant in an FTR 
Obligation scheme. 

o  State of Play  

Both consumers and suppliers need effective and efficient forward markets to hedge their price 
exposure  and  decrease  the  dependence  on  short-term  prices.  The  recent  energy  crisis  has  been 
rewarding consumers who had hedged their price exposure in the past. Renewable generation is 
highly dependent on weather conditions and hence, volatile. The rapid deployment of renewable 
generation  over  the  coming  years  will  increase  the  need  for  hedging  opportunities  due  to  the 
expected growing price volatility in the years ahead. The future forward electricity market design 
needs to provide sufficient hedging opportunities. 

According  to  ACER’s  policy  paper  on  the  further  development  of  the  EU  electricity  forward 
market38, the European electricity forward market appears to be struggling with many issues, such 
as insufficient liquidity, accessibility, competition and transparency as well as concentrated market 
power. Supply and demand for hedging instruments is fragmented into different bidding zones and 
trading  venues,  with  most  of  them  suffering  from  a  lack  of  liquidity  -  preventing  market 
participants from hedging their price exposure efficiently.  

This  lack  of  liquidity  is  particularly  apparent  for  instruments  with  longer  maturities  and/or  in 
smaller bidding zones. It is revealed through high bid-ask spreads – where the difference between 
the price that someone is willing to pay (the bid) and to sell (the ask) - is wide. Tighter spreads are 
a sign of greater liquidity, while wider bid-ask spreads occur in less liquid markets. This lack of 

38https://acer.europa.eu/sites/default/files/documents/Position%20Papers/Electricity_Forward_Market_PolicyPaper.
pdf  

36 

 
 
 
 
 
 
 
 
                                                 
liquidity and possibilities to trade appears mainly in smaller bidding zones, but also in zones with 
a dominant market player who can exercise market power, or in zones with few physical assets.  

The resulting market fragmentation at EU level can be illustrated by an indicator known as the 
“churn rate” i.e. the number of times electricity generated in a market is subsequently traded. The 
wide variation between bidding zones can be seen in Figure 6 below. The churn factor varies from 
around 8 for the German bidding zone to around 0.15 for the Hungarian bidding zone. 

Figure 6: churn factors in major European forward markets – 2016-2020 

Source: ACER Market Monitoring Report 2020, Electricity wholesale volume 2020 

Market participants in illiquid bidding zones are often “proxy-hedging” themselves in the forward 
markets of neighbouring bidding zones, complementing this hedge with zone-to-zone LTTRs39. 
The Forward Capacity Allocation Guidelines40 created a single pan-European platform of TSOs 
(Joint Allocation Office - JAO), established in October 2018, to explicitly allocate monthly and 
yearly auction-based cross-zonal transmission rights. 

o  These transmission rights are however not issued often: they are typically auctioned only 

at specific times (once a year and once a month).  

o  There  is  barely  any  secondary  market  for  these  transmission  rights.  ENTSO-E  policy 
paper41 explains that "the LTTR market displays a relatively high degree of concentration: 
the first 27 participants (12 % of the total) hold more than 75 % of the allocated volumes, 
and the first 11 (4.9 % of the total) hold more than 50 % of the market. Furthermore, the 

39  

40  
41 

In  central  Europe,  two  kinds  of  LTTRs  are  currently  issued:  physical  transmission  rights  (PTRs)  and  FTR 
Options.  The  JAO  hosts  a  pan-European  platform  (i. e.  the  Single  Allocation  Platform)  that  performs  the 
explicit allocation of LTTRs on all European borders and for all maturities. 
https://eur-lex.europa.eu/legal-content/EN/TXT/PDF/?uri=CELEX:32016R1719&from=EN  

ENTSO-E 

policy 

paper 

– 

EU's 

Electricity 

Forward  Markets 

–  December 

2022 

https://www.entsoe.eu/news/2022/12/23/eu-s-electricity-forward-markets-policy-paper/ 

37 

 
 
 
 
 
 
 
 
                                                 
secondary  market  for  LTTRs  appears  to  be  stagnant  as  only  2 %  of  capacity  allocated 
through monthly auction was re-sold by market participants”. 

o  The length of these transmission rights is inadequate, as they are mostly limited to one-
year ahead while hedging on the forward market usually takes place up to 3 years ahead. 
Beyond  the  3-year  timeframe,  the  direct  interests  of  consumers  and  producers  to  hedge 
their  operations  diminishes  significantly  and  what  remains  is  the  interest  to  hedge 
investments 

o  Several zone-to-zone transmission rights are required to hedge between non-neighbouring 

bidding zones, increasing the complexity and difficulty to hedge. 

Proxy-hedging activities exacerbate the lack of liquidity in illiquid bidding zones, while still not 
allowing participants to correctly cover their price risk for the reasons highlighted above. As a 
result,  market  participants  in  small  bidding  zones  face  discrimination  in  market  access  and  an 
uneven playing field, as they are not able to cover their price exposure to the same extent as market 
participants  from  large  and  liquid  bidding  zones.  This  situation  does  not  incentivise  market 
participants to cover their risks nor to offer fixed price contracts to end-consumers. 

In the Nordics, trading has been organised around the notion of a virtual hub for many years. A 
virtual hub is not a trading venue as such, but rather an aggregation of bidding zones characterised 
by a reference price. A hub has a reference system price, against which market participants can 
hedge their price exposure. The system price is an unconstrained market clearing reference price 
for the Nordic region. It is calculated without any congestion restrictions by setting capacities to 
infinity42.  To  complement  the  Nordic  hub,  financial  instruments  called  Electricity  Price  Area 
Differentials  (EPADs)  are  issued  to  enable  market  participants  to  cover  the  price  difference 
between the hub and their respective zone. Market participants can issue EPADs on an auctioning 
platform and a secondary  market  takes place on  Nasdaq. The  creation of a hub has allowed to 
enhance liquidity by aggregating volumes from individual bidding zones. However, in the public 
consultation, respondents complained about the declining liquidity of EPADs and explained that 
forward transmission capacity is not offered by TSOs. 

When looking at the application of the Nordics model to the Core region, ACER simulations show 
that hub-based trading would significantly improve the price correlation between the hub and all 
bidding zones43 compared to a situation with current bidding zones-based trading – as illustrated 
by  Table  2  below.  A  Core  hub  would  therefore  allow  market  participants  from  all  underlying 
regions to improve their hedging opportunities on the forward market, leading to greater benefits 
to both producers and end-consumers. To be successful, it is of utmost importance for the hub to 
be complemented by liquid long-term transmission rights.  

42  
43  

https://www.nordpoolgroup.com/en/trading/Day-ahead-trading/Price-calculation/ 
Except in DE where the price correlation would only slightly decrease 

38 

 
 
 
 
 
 
 
                                                 
Table 2: price correlation between bidding zones: comparison between a core hub and DE hub 

Source: ACER presentation of the policy paper on the further development of the EU electricity 
forward market – 7 December 2022 

ENTSO-E  policy  paper  further  explains  that  “zone-to-hub  FTRs  could  be  complementary 
instruments  to  the  default  zone-to-zone  products.  This  can  be  beneficial  for  providing  stable 
hedging opportunities for market participants in small, illiquid bidding zones. As an alternative 
for the forward market of their own illiquid market, they would prefer to hedge themselves on the 
hub forward market if this one has more liquidity. Via zone-to-hub, FTR market participants can 
adequately hedge themselves against the price differences of the spot price of their own market 
against  the fixed forward contract  on the hub. The paper further explains  that “a hub makes it 
easier for market participants to trade between non-neighbouring bidding zones.” 

o  Commission proposal 

The Commission is of the view that there is room for improvement in the way long-term cross-
zonal capacities are used to further integrate forward markets. Existing forward markets do not 
function as an integrated forward market, which prevents many EU consumers and suppliers from 
covering  their  long-term  price  exposure  efficiently  and  thereby  increases  their  dependence  on 
short-term markets price. 

Building on the experience in the Nordic market, the Commission proposes a transition to hub-
based hedging, complemented with accessible longer-term zone-to-hub transmission rights. 
The  establishment  of  virtual  hubs,  by  providing  a  reference  price  index,  will  enable  to  pool 
liquidity and provide better hedging opportunities to market participants. Virtual hubs are intended 
to reflect the aggregated price of several bidding zones and are characterised by a reference price; 
which should be used by market operators to offer forward hedging products. The hub price may 
represent the volume-weighted average of the day-ahead prices from the regions included in the 
hub  definition  (or  another  calculation  method  ensuring  highest  price  correlation).  Zone-to-hub 
transmission  rights  would  be  issued  frequently,  with  a  long  maturity  (up  to  3  years  ahead), 
financially settled and offering continuous access to a secondary market.  The allocation of zone-

39 

 
 
 
 
 
 
 
 
 
to-hub  capacity  could  be  computed  based  on  a  statistical  approach  applied  to  past  available 
capacity44. 

It is expected that hubs would attract demand for futures linked to these hubs - because all long-
term  transmission  rights  would  be  linked  to  these  hubs  -  and  that  power  exchanges  would 
subsequently offer trading with such futures without the need for regulatory intervention.  This 
measure does not imply a duplication of reporting on top of requirements imposed by financial 
markets legislation.  

The Electricity Regulation would therefore require ENTSO-E: 

-  To submit a proposal to establish the regional hubs, including definition of their regional 

scope; 

-  To  submit  a  proposal  regarding  the  calculation  of  the  hub  price,  based  on  an  objective 

methodology. 

The Single Allocation Platform would then issue long-term financial transmission rights (in the 
form of obligations) on behalf of TSOs and allocate them on a regular basis and in a transparent, 
market-based and non-discriminative manner. 

With regards to collateral requirements, the Commission has taken several measures to respond to 
the challenges faced. Last year, the Commission adopted a Delegated Regulation45 on temporary 
emergency  measures  on  collateral  requirements  to  alleviate  the  liquidity  pressure  on  energy 
companies. Furthermore, with regards to derivatives, the Commission has adopted – in line with 
advice from ESMA – two measures designed to ease liquidity stress some energy companies are 
currently experiencing.  The first  measure  raises  permanently the commodity  clearing threshold 
from €3 billion to €4 billion. It means that energy companies will be allowed to enter into more 
over-the-counter transactions without being subject to margin requirements. The second measure 
will temporarily (validity: 1 year) expand the list of eligible assets that can be used as collateral to 
meet margin calls, e.g. adding public guarantees and uncollateralised bank guarantees, subject to 
conditions. Thirdly, on 7 December 2022, the Commission adopted a proposal to amend the EMIR 
Regulation46 in which, among other measures, the Commission proposes that the range of eligible 
collateral  for  non-financial  counterparties  (including  energy  companies)  clearing  in  EU  central 
counterparties is extended to uncollateralised bank guarantees, public guarantees and public bank 
guarantees, whether or not these counterparties access the CCP directly. 

44  
45  

46  

For example, the minimum available capacity in a certain % of all times during the observation period 
https://ec.europa.eu/finance/docs/level-2-measures/emir-rts-2022-7536-annex_en.pdf 

Proposal for a REGULATION OF THE EUROPEAN PARLIAMENT AND OF THE COUNCIL amending 
Regulations (EU) No 648/2012, (EU) No 575/2013 and (EU) 2017/1131 as regards measures to mitigate 
excessive exposures to third-country central counterparties and improve the efficiency of Union clearing 
markets 

40 

 
 
 
 
 
 
 
                                                 
2.4.   Enabling energy sharing 

Feedback from public consultation 

Stakeholders  generally  support  the  idea  of  giving  customers  the  right  to  deduct  off-site 
generation  from  their  metered  consumption,  under  certain  conditions.  This  provision  could 
encourage  local  renewable  energy  production  and  efficient  energy  sharing,  including  within 
energy communities or peer-to-peer exchanges, without affecting other elements of the energy 
bill such as taxes, levies and network tariffs.  

However, stakeholders have raised concerns, such as the need to harmonise protocols for data 
creation,  management  and  transmission,  to  ensure  cost-reflective  network  tariffs,  to  avoid 
double counting of network charges and to  encourage co-location of production and flexible 
consumption. Care should be taken when implementing such a provision, as it may lead to unfair 
subsidies or cross-subsidisation of network costs to poorer consumers without generation assets.  

Stakeholders have diverging views on the potential impact of introducing a right for consumers 
to deduct off-site generation from their metered consumption on the location of new renewable 
energy generation facilities. Some believe that this would provide an incentive to build capacity 
close  to  consumption,  while  others  fear  that  it  would  lead  to  negative  incentives,  excessive 
installation of renewables and huge investment needs in the grid. There are also concerns about 
the potential socialisation of costs and regulation to establish a distance limit between off-site 
generation and consumption points.  

Respondents suggested that any provision should be implemented as localised as possible, based 
on factors such as ease of implementation, network capacity and cost reflectivity, as well as loss 
allocation  and  the  calibration  of  tariffs  to  reflect  the  actual  location  of  generation  and 
consumption on the grid. Respondents also stressed the importance of balancing generation and 
consumption  within  the  same  bidding  zone  and  considering  network  topology  rather  than 
geographical distance to limit complexities. 

o  Current state of play 

The  crisis  has  shown  that  smaller  consumers  are  excessively  exposed  to  wholesale  price 
fluctuations  and have limited access  to  more affordable renewable  energy.47 Under current  EU 

47   MMR_2021_Energy_Retail_Consumer_Protection_Volume.pdf (europa.eu), pp. 17-18. 

41 

 
 
 
 
 
 
 
 
 
 
                                                 
legal  framework,48  consumers  without  private  ownership  rights  over  suitable  space  have 
limited possibilities to engage with renewables directly,49 they need to  either find consensus 
with their neighbours to install solar PV on the roof of their multi-apartment building or be able to 
invest in an energy community50. In some Member States wider energy sharing schemes allowing 
for  collective  self-consumption  of  off-site  generation  facilities  within  a  local  perimeter  started 
emerging51 but not in most as such schemes are not explicitly recognised at EU level.  

In general, the emergence of enabling frameworks for energy sharing at national level has been 
patchy and slow with some of these schemes remaining out of scope of energy consumer rights 
and protection framework,52 which can be attributed to the lack of a clear and harmonised enabling 
framework for energy sharing at EU level.53 This is slowing down the uptake of renewables,54 and 

48  

The Electricity Market Directive enables energy sharing only for citizen energy communities (see Article 16 
(3)  (e)).  The  Renewable  Energy  Directive  enables  energy  sharing  for  jointly  acting  self-consumers  within 
multi-apartment building and renewable energy communities (see Article 21 (4) and 22 (2) (b)). 

50  

49   Many citizens cannot access solar PV due to financial (CAPEX intensity, low return on grid exports), spatial 
(heritage  buildings,  lack  of  ownership  rights  over  rooftop)  and  administrative  constraints  (decision-making 
rules  for  multi-apartment  residents  and  set  up  of  energy  community).  See  Solar  Power  Europe  (2023), 
’Framework  for  collective  self-consumption  -  Solar  Power  Europe  White  Paper’.  Moreover,  alternative 
instruments such as corporate PPAs are difficult to engage with for SMEs. See European Commission (2022). 
Staff  Working  Document  –  Guidance  to  Member  States  on  good  practices  to  speed  up  permit-granting 
procedures for renewable energy projects and facilitating Power Purchase Agreements – Accompanying the 
Commission Recommendation on Speeding up permit-granting procedures for renewable energy projects and 
facilitating Power Purchase Agreements.  
Approximately 10.000 energy communities are currently operational across the EU, mostly in West European 
countries, see energy-communities-map (europa.eu).  Low-income families often face a financial entry barrier 
to energy communities. In Germany, the average minimum financial contribution – individuals buy shares to 
become  members  –  amounts  to  545  €.  See  Hanke,  F.,  Guyet,  R.,  &  Feenstra,  M.  (2022).  12  -  Energy 
communities’ social role in a just energy transition (S. Löbbe, F. Sioshansi, & D. B. T.-E. C. Robinson (Eds.); 
pp. 195–208). Academic Press. https://doi.org/https://doi.org/10.1016/B978-0-323-91135-1.00027-4.  
51   Wider energy sharing schemes at national level go beyond multi-apartment building and energy community 
level. See for example in Portugal where energy can be shared between 2-20 km radius depending on voltage 
levels where the self-consumption unit is connected to. See Decreto-Lei n.º 15/2022, de 14 de janeiro | DRE). 
Other examples can be found in countries such as France, Spain, Slovenia and Lithuania.  
Some emerging energy sharing arrangements are based on investment, rental or lease agreements rather than 
sales agreements. This has implications in terms of applicable consumer protection rights. See in this regard, 
BEUC (1 February 2023), ‘Consumer rights in energy communities: a how-to guide to make energy 
communities go mainstream’ (Consumer rights in energy communities: a how-to-guide to make energy 
communities go mainstream (beuc.eu)).  
See Roland Tual et al. (2022), Energy sharing regulation in the EU – REScoopVPP first policy and market 
recommendations’.  
Solar growth is driven by regulatory incentives and internal rates of return. In PT, a framework for energy 
sharing and collective self-consumption has according to E-REDES triggered a growth of these schemes with 
four operational initiatives and 30 more under registration, involving 220 participants. Greenvolt Comunidades, 
an  investment  company  in  Portugal,  has  already  signed  65  projects  to  be  implemented  as  collective-self 
consumption  projects,  which  correspond  to  circa  35  MW  (3  MW  already  concluded  and  3MW  are  under 
construction). See Greenvolt Comunidades - Comunidades de Energia. In Greece, under the impulse of volatile 
wholesale market prices, energy sharing projects, based on virtual net-metering, increased by 62,5% in number 

52  

53  

54  

42 

 
 
 
 
 
 
 
                                                 
leaves  a  wider  group  of  consumers  vulnerable  to  unfair  commercial  practices  and  unable  to 
decouple from volatile wholesale market prices55. 

o  Commission proposal 

An enabling framework for energy sharing in the Electricity Market Directive is added to clarify 
relevant  roles,  rights  and  responsibilities  of  involved  actors,  and  operationalise  existing 
frameworks  for  energy  communities56  and  multi-apartment  residents57,  as  well  as  wider  ones, 
where excess production is shared with off-site consumers by individual prosumers, or a group of 
consumers jointly lease, rent or own an off-site generation or storage facility managed by a third-
party facilitator.  For more information on different use cases and how energy sharing can help 
empower consumers, including energy poor households and tenants, see section 6.4. 

Consumers shall have the right to have injected electricity deducted from their total metered 
consumption  within  a  set  time-interval  and  within  the  same  bidding  zone  for  the  purpose  of 
calculating the energy component of their energy bill. This shall be without prejudice to applicable 
taxes  and  network  charges  to  total  metered  consumption.  System  operators  or  other  relevant 
designated  bodies  will  have  the  responsibility  to  put  in  place  the  necessary  back-end  IT 
infrastructure to operationalise this right. Member States such as Belgium58, Austria,59 Lithuania, 
Luxembourg,  Portugal  and  others60  have  shown  that  it  is  possible  to  implement  this  model 
relatively quickly (1-2 years) and at a reasonable cost.61  

The  Commission’s  proposal  will  leave  several  dimensions  of  energy  sharing  framework  to  the 
discretion of individual Member States, including the calculation and allocation methods for the 
sharing  of  renewable  energy,  the  possibility  to  implement  the  model  in  stages  (from  local  to 
bidding zone level), the appropriate measures to ensure accessibility to energy poor and vulnerable 

to 

GW 

when 

combining 

and 140.3% in capacity within one year time. See The GreenTank (2023), ’Energy Communities in Greece and 
its lignite areas #3’.  
A  study  commissioned  by  Federal  Ministry  for  Economic  Affairs  and  Energy  in  Germany  estimates  that 
the  Mieterstrom  model.  See 
approximately  3.8  million  households  could  have  access 
https://www.bmwk.de/Redaktion/DE/Publikationen/Studien/schlussbericht-mieterstrom.html.  In  Lithuania, 
projections suggest that by 2030 there could be 170-190 thousand prosumers with total installed capacity of 
1.2-1.3 
See 
self-consumption. 
https://www.vz.lt/pramone/2022/06/06/2030-m-gaminantys-vartotojai-pagamins-7-lietuvos-elektros-
energijos-poreik.  
See for example Hyperion, where a community of consumers organised through a cooperative form have shared 
ownership over solar PV. 
See  Solar  Power  Europe  (2023),  ’Framework  for  Collective  Self-Consumption:  SolarPower  Europe  White 
Paper‘. 
See Energiedelen en persoon-aan-persoonverkoop | VREG. 
See https://energiegemeinschaften.gv.at/messung-und-aufteilung/. 
Such as Spain, Italy, France. 
See Aliene van der Veen et al. (2023), ’multi-supplier models and decentralised energy systems: energy sharing 
implementation approaches’. 

offsite 

onsite 

and 

55  

56  

57  

58  
59  
60  
61  

43 

 
 
 
 
 
 
 
                                                 
households,  and  the  design  of  model  contracts  with  fair  and  transparent  contractual  terms  and 
conditions  for peer-to-peer trading  agreements  between households as  well  as  rental, lease and 
investment agreements. When participating to energy sharing, final customers shall continue to 
benefit  from  all  consumer  rights  as  final  customers,  without  prejudice  to  peer-to-peer  trading 
between households. 

o  Benefits for consumer bills and renewables deployment 

By  operationalising  and  enabling  at  EU  level  existing  and  wider  energy  sharing  arrangements 
within a single bidding zone, a wider group of consumers will have the opportunity to hedge 
against  volatile  wholesale  market  prices  and  control  their  energy  bills.62  In  turn,  this  can 
mobilise  additional  private  capital  investments63  in  roof  and  ground-based  renewable  energy 
(including wind turbines in offshore and rural areas) and increase the uptake of renewables.64 With 
the  integration  of  storage  and  when  exposed  to  time-differentiated  price  signals  and  accessible 
flexibility markets, energy sharing can also contribute to cost-effective deployment and integration 
of renewables.65 

Estimates  show  that  in  2022  a  collective  of  40  residential  consumers  engaged  in  sharing  of 
electricity produced for 50% from solar and 50% from wind could have saved as much as 1269 
EUR in Denmark, 999 EUR in Romania, 1213 EUR in France, 1045 EUR in Belgium, 1220 EUR 
in  Italy,  1040  EUR  in  Greece  and  765  EUR  in  Portugal.66  Benefits  are  lower  in  100%  solar 
scenarios due to lower self-consumption rates. When household demand is met using 50% solar 
and 50% wind installations, self-consumption increases from 39.6% to around 66% on average 
across these seven countries, illustrating the importance of allowing for sufficient  geographical 
flexibility for the integration of wind technology.67 

62 

63 

64 

65 
66 

67 

In Lithuania, 9267 households out of 40577 prosumers produce electricity in remote parks. In Belgium, which 
has  operationalised  energy  sharing  in  2022-2023,  there  are  above  2000  consumers  participating  to  energy 
sharing.  
It  is  estimated  that  6.5-12.8  billion  EUR  of  citizen  capital  could  be  invested  in  Germany  alone. 
Seehttps://www.ioew.de/publikation/energy_sharing_eine_potenzialanalyse. 
See  Borna  Doračić  et  al.  (2020),  ‘Prosumers  for  the  Energy  Union:  mainstreaming  active  participation  of 
citizens in the energy transition‘.  
See SmartEn (2022), ’Demand-side flexibility: quantification of benefits in the EU’.  
Marten Ovaere (2023) ’Collective energy sharing: Cost-Benefit Analysis and Survey Evidence of the 
Willingness to Invest’.  
Marten Ovaere (2023) ’Collective energy sharing: Cost-Benefit Analysis and Survey Evidence of the 
Willingness to Invest’. 

44 

 
 
 
 
 
 
 
 
 
                                                 
Table 3: The average benefits of collective self-consumption across the seven studied countries, 
for the market conditions in 2020 and 2022 and for a 100% and a 50% solar / 50% wind 
generation mix. 

Year of the data used  
Degree of self-consumption   Collective 
100% solar 
Generation mix  

2020 

2022 
Collective 
100% solar 

50% solar 50% 
wind 

50% solar 50% 
wind 

Self-consumption (%) 

Benefit  of  self-consumption 
(€) 
Benefit of surplus energy sold 
(€) 
Total benefits (€) 
Investment cost (€) 

39.69 

66.12 

39.44 

65.96 

272.53 

442.04 

586.00 

930.24 

61.57 
334.10 
2234.92 

33.69 
475.72 
2447.29 

292.30 
878.30 
2234.92 

148.88 
1079.12 

2488.72 

Payback  period  for  constant 
market conditions (years) 
5.59 
Source:  Marten  Ovaere  (2023),  ‘Collective  energy  sharing:  Cost-Benefit  Analysis  and  Survey 
Evidence of the Willingness to Invest’. 

 7.22 

2.57 

2.33 

To  operationalise  the  right  to  energy  sharing,  cost  impacts  are  expected  for  consumers,  retail 
suppliers and system operators.68 System operators will have to invest in the order of a few million 
euros to put in place the back-end IT infrastructure; a cost that can be seen as a wider digitalisation 
effort of market processes.  Active consumers will continue to use the grid to share electricity and 
to meet their excess demand contributing to investment and operational costs of the overall energy 
system.  

System operators should be able to recover all costs incurred and across all network users to avoid 
cost-socialisation to lower-income households that cannot participate to energy sharing due to the 
high financial entry barriers for individual69 and joint70 investments. Active consumers may reduce 
at  times  congestion  at  higher  voltage  levels,  depending  on  location  of  relevant  injection  and 
consumption points, as well as the level and timing of congestion at transmission and distribution 

68  

69  
70  

See  Aliene  van  der  Veen  et  al.,  ’multi-supplier  models  and  decentralised  energy  systems:  energy  sharing 
implementation approaches’ (2023) (to be published). 
See https://www.irena.org/publications/2022/Jul/Renewable-Power-Generation-Costs-in-2021. 
For example, it costs on average 545 EUR per share to join an energy community in Germany. See Hanke, F., 
Guyet, R., & Feenstra, M. (2022). 12 - Energy communities’ social role in a just energy transition (S. Löbbe, 
F.  Sioshansi,  &  D.  B.  T.-E.  C.  Robinson 
195–208).  Academic  Press. 
https://doi.org/https://doi.org/10.1016/B978-0-323-91135-1.00027-4. 

(Eds.); 

pp. 

45 

 
 
 
 
 
 
 
  
                                                 
level in each Member State. Flexibility markets and time-differentiated network tariffs are the most 
appropriate  instruments  to  provide  monetary  incentives  for  relevant  congestion  management 
services. 

 Depending on the setup per Member State, traditional retail suppliers are expected to incur costs 
related to billing for individual prosumers, and to face difficulties with forecasting of consumption 
profiles leading to increased imbalance risk and higher unit supply costs.71 Suppliers should be 
able to recover costs effectively incurred due to the activation of energy sharing from involved 
consumers. 

2.5. 

 Offshore Transmission Access Guarantee  

Feedback from public consultation 

Many respondents acknowledged the particular challenges facing offshore renewable energy 
projects located in an offshore bidding zone. It was highlighted that a coordinated investment 
program to ensure that the transmission capacity and offshore capacity develop in tandem as a 
hybrid project would be the best guarantee of access to markets and would mitigate the need for 
this  provision.  Overall,  out  of  the  314  respondents  to  the  question,  200  consider  that  a 
Transmission Access Guarantee (TAG) is appropriate to support offshore renewables projects.  

Some respondents believe that a TAG is necessary to avoid discrimination compared to onshore 
renewables in larger bidding zones who would receive compensation for curtailment, and they 
state that it would de-risk investments and support the development of offshore PPAs. Others 
do not believe that it goes far enough to support the development of offshore renewables and 
that it should also cover some form of price support for renewables projects.  

However,  some  concerns  were  also  raised  such  as  needing  to  ensure  a  level  playing  field 
between  onshore  and  offshore  generation  and  competition  between  technologies,  cross-
subsidisation, costs for consumers (regarding both compensation level and development of grid 
infrastructure),  ensuring  that  project  operators  are  not  overcompensated,  need  to  ensure 
futureproofing for a combination of gas (H2) and electricity offshore in future.  

o  State-of-play 

One of the key pillars for enabling the decarbonisation objective will be offshore renewables. With 
enormous untapped potential, increasingly competitive prices (i.e. levelised cost of electricity) and 

71  

Leen Peeters et al. (2022), 'Muse Grids impacts: A critical stocktaking across various aspects of community energy’. 

46 

 
 
 
 
 
 
 
 
 
 
                                                 
technological global leadership, the EU is well placed to exploit offshore renewable resources. The 
policy direction set by the Commission’s offshore renewable energy strategy72 has been confirmed 
at political level by Member States at numerous occasions, including the Esbjerg Declaration73, 
the Marienborg Declaration74, the NSEC Joint Statement75 in 2022 and the non-binding sea-basin 
goals76 agreed by Member States in 2023 pursuing TEN-E Regulation77.  

The strategy, setting the overall policy direction, was complemented with a guidance on electricity 
market arrangements78 describing how the establishment of offshore bidding zones (OBZs) is the 
most efficient and affordable way for consumers to integrate large-scale offshore renewables into 
the  system  when  these  are  connected  via  hybrid  interconnectors.  With  OBZs,  among  other 
benefits, electricity flows are optimised accounting for physical reality, minimising redispatching 
costs  that  are  borne  by  consumers  and  would  substantially  increase  with  other  market 
arrangements, and increasing security of supply by not pushing TSO corrective actions towards 
real time. To attain such and other benefits, Member States may decide to implement OBZs, while 
it is not a mandatory market arrangement. 

In addition, the strategy outlined a number of follow-up activities aiming at promoting the rapid 
and efficient deployment of offshore renewables. One was a study79 analysing the market risks 
that offshore renewable plants in an OBZ interconnected to several markets may face. The main 
risk identified is a volume risk, where offshore wind farm operators in an interconnected system 
may at times not be able to export the energy that they would be able to produce if the TSOs do 
not give enough transmission capacity to the market80. The uncertainty in generation volumes that 

80  

COM/2020/741 final 
The Esbjerg Declaration - Regeringen.dk 
The Marienborg Declaration - Regeringen.dk 
220912_NSEC_Joint_Statement_Dublin_Ministerial.pdf (europa.eu) 

72  
73  
74  
75  
76   Member States agree new ambition for expanding offshore renewable energy (europa.eu) 
77  
78  
79  

Regulation (EU) 2022/869 
SWD(2020) 273 final 
https://energy.ec.europa.eu/system/files/2022-
09/Congestion%20offshore%20BZ.ENGIE%20Impact.FinalReport_topublish.pdf 
The  European  Commission  took  due  consideration  of  the  findings  of  the  studies  ‘Market  arrangements  for 
offshore  hybrid  projects  in  the  North  Sea’  and  ‘Support  on  the  use  of  congestion  revenues  for  offshore 
renewable energy projects connected to more than one market’ as well as extensive feedback from stakeholders, 
noting that the major additional risk that offshore renewable plants experience in comparison to onshore plants 
is a volume risk as outlined. On the other hand, the price effects in an OBZ stemming from an optimised market 
arrangement reflect the value of both the renewable and transmission assets, as is the case for onshore assets 
in  well-designed  bidding  zones.  Incorporating  “price  compensation”  to  mirror  OBZ  prices  with  onshore 
bidding zones and linking them to congestion income would not only suppress the appropriate signaling of the 
value  of  the  assets  (lowering  incentives  for  demand  such  as  hydrogen  to  emerge  nearby),  but  also  could 
introduce substantial detrimental effects such as cross-subsidisation and additional pressure on the financing 
of interconnectors. Where possible, Member States should strive to give visibility on the market arrangement 
applicable to offshore assets ahead of the respective tender procedures. The market arrangement is not expected 
to alter substantially whether there is a need for State aid for offshore projects; cooperation mechanisms such 

47 

 
 
 
 
 
 
 
                                                 
the renewable plant operator can practically offer to the market represents a risk for the project 
developer  over  which  they  have  no  control.  It  is  a  risk  that  is  particular  to  offshore  renewable 
assets, given that onshore renewables are not connected directly to interconnectors. TSOs through 
ENTSO-E are working on a new way of calculating capacities (Advanced Hybrid Coupling) that 
should  improve  certainty  of  access  to  the  hybrid  interconnectors.  However,  even  when  this  is 
implemented, there might still be occasions where market access is removed or reduced.  

o  Commission proposals 

To address  this  risk, the Commission  proposes to  develop a  “Transmission Access  Guarantee” 
(TAG) where the TSOs responsible for limiting the export possibilities of offshore wind farms 
would compensate the offshore producer for any market time units where the border is closed or 
reduced, not allowing the export of energy that could have otherwise been offered to the market. 
This compensation would be paid from the congestion income collected by TSOs when borders 
are congested and is consistent with the principle of one of the current allowed uses of congestion 
income:  guaranteeing  the  availability  of  cross-border  transmission  capacity.  This  congestion 
income re-allocation would therefore incentivise TSOs not to reduce transmission capacity made 
available to offshore wind farms, while targeting such reallocations to the source of the risk81. The 
Commission  proposes  to  amend  the  Electricity  Regulation  to  enable  a  Transmission  Access 
Guarantee,  thereby  ensuring  market  access  for  offshore  renewables,  with  further  implementing 
details  to  be  set  out  in  upcoming  amendments  to  the  Guideline  on  Capacity  Allocation  and 
Congestion Management.82  

It is useful to highlight that this proposal carefully balances the perspective of offshore developers 
who are seeking to de-risk these investments with the views of TSOs and NRAs who expressed 
concerns about maintaining a level-playing field, avoiding cross-subsidisation and minimising the 
costs to consumers. The proposal takes on board these concerns by limiting the TAG to addressing 
the “volume risks” associated with these investments i.e. market access for offshore renewables 
that might be affected by TSO actions. However, it does not cover the revenue uncertainty that 

81  

82  

as those indicated in the Renewable Energy Directive (e.g. joint projects or joint support schemes) may prove 
useful to promote further cross-border offshore renewable projects. 
A non-targeted reallocation would not be feasible, with growing needs to finance hybrid and other transmission 
projects, and considering that ACER notes that already 95% of the annual congestion income is used for the 
priority  objectives  established  by  the  Electricity  Regulation  in  support  of  the  market  (Use  of  Congestion 
Income 2021 ACER Monitoring Report of 11 October 2022) 
It should also be noted that OBZs in interconnected markets maximise social-welfare in the region, which may 
at times impact, to a limited extent, the revenues of offshore wind farm operators to the benefit of consumers, 
reflecting  the  real  value  of  transmission  infrastructure  needs.  The  study  ”Support  on  the  use  of  congestion 
revenues for Offshore Renewable Energy Projects connected to more than one market“ raises serious concerns 
about any reallocation of congestion income for this price risk, which would lack a market basis and risk cross-
subsidisation  and  discrimination.  More  appropriate  ways  of  addressing  revenue  certainty  and  sustainability 
where  necessary  are  corporate  PPAs  and  joint  support  schemes  based  on  contracts  for  difference  set  by 
cooperating Member States. 

48 

 
 
 
 
 
 
 
                                                 
comes from participating in the electricity market. This “price risk” is better addressed by private 
PPAs or public support as outlined in earlier sections of this document.  

3.  Limiting revenues of inframarginal generators 

Feedback from public consultation 

A majority of respondents were against maintaining a revenue limitation on inframarginal 
generators, and highlighted the following risks and shortcomings of such an option: 

  The  inframarginal  revenue  cap  and  its  heterogenous  implementation  across  Member 
States have created uncertainty and complexity for investors and give negative signals 
for new investments; 

  The  measure  is  difficult  to  implement,  and  its  administrative  costs  are  high  when 

compared with its benefits; 

  The uncoordinated implementation is undermining the integrity of the market; 

  The  emergency  situations  should  be  dealt  only  during  emergency  situations,  and  not 

beyond; 

  The  inframarginal  revenue  cap,  when  set  at  a  low  level  as  some  Member  States  did, 

might lead to generators reducing their production while the cap is in place; 

  Distributional concerns are better handled outside the market structure, for example via 

social policies. 

Only  a  minority  of  respondents  supported  the  idea  that  some  form  of  revenue  limitation  of 
inframarginal generators should be maintained. They signaled that it would ensure that excess 
profits are channeled back to final consumers, and some of them claimed that the drawbacks 
from  the  current  inframarginal  revenue  cap  derive  from  the  short  timeframe  for  its 
implementation. 

o  State of play 

During  the  current  energy  crisis,  temporary  emergency measures have been put  in  place under 
Council Regulation 2022/1854 of 6 October 2022 on an emergency intervention to address high 
energy prices. One of these measures is the so-called inframarginal revenue cap which limits the 
revenues of inframarginal generators. The aim of introducing this inframarginal cap was to limit 

49 

 
 
 
 
 
 
 
 
 
 
the impact of the natural gas prices on the revenues of all inframarginal generators and to generate 
revenues allowing Member States to mitigate the impact of high electricity prices on consumers. 

The inframarginal revenue cap was proposed and adopted as one of the emergency measures  for 
tackling the energy crisis due to its advantages when compared with other alternatives, namely 
that  it  does  not  entail  an  increase  in  gas  consumption  and  does  not  impact  the  outcome  of  the 
electricity market, so that there is no artificial change to the technologies used to meet demand, 
and  no  distortion  of  the  cross-border  flows,  both  within  the  EU  and  between  the  EU  and  its 
neighbours. 

However,  during  its  implementation,  several  Member  States  and  stakeholders  have  pointed  at 
several challenges and risks of the inframarginal revenue cap: 

-  The  heterogenous  implementation  across  Member  States  (for  example,  several  Member 
States, as provided for in the Emergency Regulation opted for a lower cap level below 180 
EUR/MWh,  differentiated  by  technology  or  a  different  implementation  period  than 
provided in the Regulation) has resulted in a patchwork of national measures across the 
EU,  with  stakeholders  reporting  that  the  linked  regulatory  uncertainty  might  end  up 
hindering new investments in the EU.   

-  The measure is only effective when market prices are above the cap. Some Member States 
have reported that in a low-price scenario, the benefits retrieved by the measure might not 
compensate for the cost of implementing it. 

-  Difficulties  in  implementing  the  measure,  since  it  requires  to  establish  revenues  from 
inframarginal producers. Some Member States have implemented the measure in  a way 
that it also affects energy sold under long-term contracts, which are not dependent on spot 
prices.  This  did  not  only  create  an  additional  layer  of  investor  uncertainty,  but  it  also 
hinders the attractiveness and stakeholder confidence in forward markets. 

o  Commission proposal 

While well-designed ad-hoc time-limited measures can bring benefits in times of energy crises, 
embedding the inframarginal revenue cap or similar emergency measures as a permanent feature 
of the market design would entail unnecessary risks and costs, namely: 

o 

o 

the risk of harming the forward markets, that have been identified as a key component to 
ensure price stability for the consumers, by decreasing its reliability and liquidity; 

the  risk  of  affecting  the  investment  attractiveness  of  the  technologies  needed  for  the 
electricity system decarbonisation; 

50 

 
 
 
 
 
 
 
 
The Commission will continue to monitor the effect of inframarginal revenue cap measure after 
the second reporting date (set on 30 April 2023). By then, the Commission expects to have a better 
view of potential revenues collected and net impact for the end-consumers. Such conclusion will 
then feed the discussion on the potential prolongation of the Regulation beyond 30 June 2023.  

4.  Improving the efficiency of short-term markets 

Feedback from the public consultation 

Intraday markets 

The majority of respondents consider that short-term markets are functioning well, and do not 
see an alternative to the marginal pricing model. Liquidity and level playing field are however 
quoted as weaker elements. 

Moving the closure of cross-zonal intraday trades closer to real time is a welcome change 
by  many  respondents,  in  particular  market  participants.  It  is  considered  as  a  key  aspect  to 
integrate  further  renewables,  since  they  are  highly  weather-dependent  and  their  production 
forecasts  improve  closer  to  real  time.  However,  it  will  be  important  to  consider  operational 
security when getting closer to the time of delivery, and possibility to adapt some design element 
of the balancing market. 

The majority of respondents consider that market operators should share their liquidity also 
for local markets. Respondents who disagree consider that this would harm innovation. TSOs 
note  that  the  remaining  liquidity  will  be  shared  on  European  balancing  platforms  (for 
prequalified  units).  Furthermore,  some  note  that  with  the  development  of  local  flexibility 
markets, sharing liquidity between local and zonal wholesale markets will be important, through 
coordination and data exchanges.  

Day-ahead markets 

The majority of respondents consider that mandatory participation in the day-ahead market 
(notably for generation under CfDs and/or PPAs) would not be an improvement compared to 
the  current  situation.  Such  measures  could  however  be  envisaged  if  a  concerning  drop  of 
liquidity is witnessed. 

51 

 
 
 
 
 
 
 
 
 
 
 
Freedom to choose trading venues is considered as fundamental. However, transparency is a key 
element, hence the importance of liquidity in organised marketplaces. 

On the issue of reflecting further locational and technology based information in the bidding 
in the market, further locational information could help reflecting the physics of the grid and its 
congestions in the market design. However, portfolio bidding and aggregation remain critical 
functionalities for many market participants to preserve. Locational tags can be useful and could 
ease regulatory oversight. 

EU Emission Trading System 

Many  respondents  did  not  reply  to  the  question  on  the  EU  emission  trading  system  and  its 
incentive on the development of low carbon flexibility and storage. Most respondents were in 
favour of the EU emission trading system, explaining that the market can decide freely where 
and how it is most efficient to abate emissions. They explained that, by internalising costs of 
carbon emissions, emitting becomes more expensive, making low-carbon flexibility and storage 
solutions  more  attractive.  However,  some  stakeholders  expressed  their  reluctance  since  the 
prices for carbon emissions are volatile and sensitive to regulation changes, which might dampen 
the willingness for capital intensive investments in generation. Few stakeholders opposed the 
EU emission trading system, criticizing the price increase for end consumers and highlighting 
the need for EU industry to remain competitive in the global markets. 

4.1. 

 Intraday Gate Closure time 

o  State of play  

The Clean Energy Package built on previous legislative packages to put a focus on short-term 
markets  and  related  price  signals  in  order  to  support  the  development  of  variable  and  more 
distributed  generation.  Functioning  short-term  markets  (day-ahead,  intraday  and  balancing)  are 
indeed a key tool for the integration of renewables in the electricity system, as they enable trading 
of surplus and shortages of energy closer to the time of delivery, especially for those resources that 
are more flexible such as demand response or storage. The price reflected by short-term markets 
gives  a  signal  of  scarcity,  encouraging  market  participants  to  react  to  it  and  guaranteeing  that 
different  assets  are  used  in  the  most  efficient  manner.  It  is  also  crucial  for  security  of  supply 
because higher prices attract imports ensuring that electricity flows to where it is most needed. 
Keeping this price signal is key to enhance flexibility and integrate variable renewables reliably in 
the system. 

Intraday markets  are especially important for the integration of renewable energy at the least 
cost. While most electricity is traded the day-ahead of delivery or before, it is only a couple of 

52 

 
 
 
 
 
 
 
 
 
hours closer to the time of delivery that wind and solar producers can accurately estimate their 
actual  electricity  production.  However,  since  they  sell  their  production  in  the  markets  before 
having an accurate estimation, they often produce more or less electricity than what they sold. It 
is thus important that they can balance their position as close as possible to the time of delivery, 
and that they have trading opportunities via a liquid market. 

EU day-ahead and intraday electricity markets are coupled, meaning that the dispatch of generation 
and demand response is organised across Europe in a single process. The European cross-border 
intraday market currently closes one hour before the time of delivery. Some Member States have 
enabled trading closer to the time of delivery at national level, as illustrated in Figure 7 below. 

Figure 7: Intraday gate closure times in different Member States 

Source: Nominated European Market Operators (NEMOs) 

Trading closer to the time of delivery enables market participants to balance their position, and in 
particular to optimise the integration of variable renewables in the power system. Figure 8 below 
shows how trades increase drastically when getting closer to the time of delivery, illustrating the 
importance of these very short-term trades for market participants. 

53 

 
 
 
 
 
 
 
 
 
 
 
Figure 8: Traded volumes of electricity depending on the time before delivery of electricity (yearly 
in 2021 to the left, monthly in the second half of 2022 to the right) 

Source:  CACM  Annual  report  2021  (CACM  Annual  Report  2021  (nemo-committee.eu))  and 
NEMOs 

o  Commission proposal 

While short-term markets seem to deliver adequate price signals, further improvements could lead 
to increased efficiency. 

The Commission proposes to set the cross-border intraday gate closure time closer to real time, 
in order to allow market participants to trade as close as possible to the time of delivery of the 
electricity. 

54 

 
 
 
 
 
 
 
 
 
 
 
 
4.2. 

Sharing of order books and minimum bid size 

Since  EU  day-ahead  and  intraday  electricity  markets  are  coupled83,  liquidity  and  therefore  the 
efficiency of the markets has considerably increased. Figure 9 below illustrates how trades have 
increased  when  Member  States  have  joined  the  common  intraday  coupling  platform  (called 
XBID). 

Figure 9: Number of trades before and after the XBID platform go-live in selected Member States 

Source: NEMOs 

However, as soon as the cross-border intraday market closes, these benefits disappear: within the 
same bidding zone, market participants can no longer trade with each other if they do not bid on 
the  same  power  exchange  platform,  considerably  decreasing  the  liquidity  and  opportunity  for 
matching the variability of renewables close to real time. 

o  Germany  provides  a  relevant  example,  as  approximately  40%  of  all  intraday  trades  are 
executed in the last hour before the time of delivery – this percentage is steadily increasing 
as more renewables connect to the system. Ahead of the last hour before the delivery time, 
the two NEMOs active in Germany, Nord Pool and EPEX, experience substantial levels of 
activity in terms of buy and sell orders being matched and resulting in actual trades. One 
hour before the delivery time, when the cross-border intraday market closes, the liquidity 
in the shared intraday platform drops to almost zero, with no order receiving a match or 
resulting in a trade84 Commission proposal 

The Commission proposes to increase the liquidity in the intraday market also when cross-border 
trade is not possible, by extending the benefit of the coupling of intraday market through sharing 

83  

84  

The market coupling is organised by nominated electricity market operators (NEMOs) and there can be more 
than one NEMO in a Member State 
Source: Nordpool 

55 

 
 
 
 
 
 
 
 
 
                                                 
of  the  order  books  within  bidding  zone.  This  will  improve  the  competition  and  liquidity  of 
intraday trades, as it will maximise the opportunities for market participants to trade shortages and 
surpluses  of  electricity.  This  will  contribute  to  better  integrating  variable  renewables  in  the 
electricity system. 

In  addition,  the Commission  proposes to  set  the  minimum bid  size for intraday and day-ahead 
market  to  100 kW or less in  the Regulation,  to  ensure that a maximum of flexible sources can 
participate in the market. This would provide a coherent framework for market parties in different 
short-term markets: it would align with what has been implemented in the day-ahead and intraday 
market coupling and with the foreseen change for balancing markets in the future Network code 
on Demand response85. 

5.  Facilitate and incentivise non-fossil flexibility services for renewables 

integration 

5.1. 

Introduction 

o  State-of-play: Flexibility needs  

Flexibility solutions,  together with  grid developments, are necessary to  cope with  variations in 
electricity generation from renewable resources, and to enable the electricity system and grid to 
adjust  to  the  variability  of  generation  and  consumption  patterns  across  different  time  horizons. 
They  will  enable  an  optimal  use  of  electricity  generation  from  renewable  resources  and  will 
minimise curtailments thereby supporting the decarbonisation objective and limiting the costs of 
the  electricity  system.  To  illustrate,  Germany  curtailed  6  146  GWh  of  renewable  electricity  in 
2020, 5818 GWh in 2021, and 5419 GWh in the first half of 202286. 

Figure 10 below illustrates the increasing trend in  flexibility needs87 towards 2030 in  different 
time horizons. 

85  
86  
87  

Framework Guideline on Demand Response, ACER, 2022 
Zahlen Ganzes Jahr2021.pdf (bundesnetzagentur.de) 
The estimation of the flexibility needs was based on the methodology described in section 2.2.1 of the European 
Commission report Mainstreaming RES Flexibility portfolios - Design of flexibility portfolios at Member State 
level  to  facilitate  a  cost-efficient  integration  of  high  shares  of  renewables  as  tasked  by  the  European 
Commission.  Compared  to  the  original  methodology,  some  simplifications  were  applied  by  ACER,  e.g.  to 
calculate the residual load, only information on load and wind and solar generation was used, as information 
on other intermittent renewable sources and must-run generation was not available to ACER. 

56 

 
 
 
 
 
 
 
 
 
 
 
                                                 
Figure 10: expected evolution of flexibility needs in the EU 

Source: ACER (Final assessment of the EU wholesale Electricity market design, April 2022) 

The variability introduced by increasing shares of renewable generation will further increase those 
flexibility needs. Figure 11 below illustrates the 2030 residual load88 curve in the EU, averaged 
per hour and across all Member States. 

Figure 11: Daily flexibility needs  

Source: JRC, Flexibility requirements and the role of storage in future European power systems 
2022 

More specifically, daily flexibility needs are expected to increase on average by 133% across all 
countries between 2021 and 2030. Across Member States, 2030 daily flexibility needs will vary 

88  

Residual load indicates the production left for conventional power plants  to meet demand, after taking into 
account renewable generation 

57 

 
 
 
 
 
 
 
 
 
 
 
 
                                                 
between  4%  and  17.5%  of  total  demand.  Comparing  2050  to  2030,  daily  flexibility  needs  will 
further increase on average by 250% in the EU89. 

  Development of non-fossil flexibility 

Generation,  storage  and  demand  can  provide  flexibility,  each  with  different  characteristics. 
However, the role of gas in providing flexibility to the system is still dominant currently. Fossil-
fuel  free  flexibility  such  as  demand  response  (reduction  of  the  consumption  or  shifting  the 
consumption in time) and storage has the potential to reduce the role of natural gas in the short-
term market.  

Cumulative installations of batteries and pumped hydro reached respectively 10 GW and 40 GW 
in 2022, with volumes expected to reach more than 50 GW for batteries and 50 GW for pumped 
hydro by 203090. The Italian TSO Terna recently carried out an assessment on storage needs for 
203091 : the storage capacity needs are estimated to be around 15 GW, which is about 15% of the 
total  variable  renewable  capacity.  It  must  be  noted  that  peak  power  is  not  the  only  relevant 
parameter when assessing the need and how storage could contribute to fill the flexibility need: 
how long it can charge or discharge for is also an important element. 

Around 21 GW of demand response has been active in the system in 20199293. Some estimations 
highlight  a  potential  of  more  than  130  GW  of  demand  side  flexibility  in  2030  (the  impact 
assessment for the CEP94 estimates a potential of 160 GW and a study from DNV GL estimates a 
total of 164 GW upward flexible power and 130 GW of downward flexible power95). This potential 
is not being developed today at the speed and scale required to support our decarbonisation targets, 
nor equally within EU Member States.  

89  
90  
91  
92  

93  

94  

95  

JRC, Flexibility requirements and the role of storage in future European power systems 2022 
Delta-EE and EASE European Market Monitor on Energy Storage 2022 
Terna (2022): Documento di descrizione degli Scenari 2022. 
COMMISSION STAFF WORKING DOCUMENT IMPACT ASSESSMENT Accompanying the document 
Proposal for a Directive of the European Parliament and of the Council on common rules for the internal market 
in electricity (recast) Proposal for a Regulation of the European Parliament and of the Council on the electricity 
market  (recast)  Proposal  for  a  Regulation  of  the  European  Parliament  and  of  the  Council  establishing  a 
European Union Agency for the Cooperation of Energy Regulators (recast) Proposal for a Regulation of the 
European Parliament and of the Council on risk preparedness in the electricity sector 
The companies represented by the European business organisation SmartEn are currently responsible for 13 
GW of flexible demand (source: SmartEn) 
COMMISSION STAFF WORKING DOCUMENT IMPACT ASSESSMENT Accompanying the document 
Proposal for a Directive of the European Parliament and of the Council on common rules for the internal market 
in electricity (recast) Proposal for a Regulation of the European Parliament and of the Council on the electricity 
market  (recast)  Proposal  for  a  Regulation  of  the  European  Parliament  and  of  the  Council  establishing  a 
European Union Agency for the Cooperation of Energy Regulators (recast) Proposal for a Regulation of the 
European Parliament and of the Council on risk preparedness in the electricity sector 
https://smarten.eu/wp-content/uploads/2022/09/SmartEN-DSF-benefits-2030-Report_DIGITAL.pdf 

58 

 
 
 
 
 
 
 
                                                 
The Clean Energy Package adopted in 2019 has been an important step in attempting to bring more 
flexibility  in  form  of  demand  response  and  storage  services  to  the  electricity  markets  and  to 
improve their integration across the EU. It sets out that renewables, demand response and energy 
storage  should  be  able  to  participate  in  all  markets,  that  every  final  customer  has  the  right  to 
participate in demand response schemes, and that system operators have a legal basis to access and 
use flexibility services.  

In addition, the EU Strategy for Energy System Integration of 2020  stressed the importance of 
flexibility as key to facilitate sector integration through electrification of end use sectors based on 
renewables – industry, buildings and transport. For example, electric vehicles can participate in 
demand response enabled through smart charging, thus allowing to optimise the electricity grid. 
To ensure this, the Commission proposal on the revised Renewable Energy Directive of July 2021 
(subject to negotiations to be agreed by end of March) contains specific requirements to facilitate 
non-discriminatory participation of electric vehicles and storage assets in the flexibility services 
and  to  increase  awareness  of  customers  and  relevant  market  actors  of  those  possibilities  via 
transparency requirements for system operators to provide data on the actual share of renewables 
and greenhouse gas emissions content in the electricity supplied.      

While the timely and correct transposition of the related provisions of the Clean Energy Package 
is crucial to develop this flexibility, it can be observed that transposition is lagging behind in the 
majority of Member States. Non-fossil flexibility sources, such as demand response and storage, 
are progressively participating in the wholesale markets following the implementation of the Clean 
Energy Package, but the development remains slow.  

Figure 12 below illustrate the opening of the short-term wholesale markets to demand response in 
EU Member states. 

59 

 
 
 
 
 
 
 
 
 
Figure 12: Development of demand side flexibility in wholesale markets  

Source: 
2022.pdf) 

SmartEn 

(https://smarten.eu/wp-content/uploads/2023/02/DSF-Market-Monitor-

Demand  response  is  also  increasingly  participating  in  the  ancillary  services  market  but  the 
development remains heterogenous between Member States, and overall slow96.  

5.2. 

Procurement of flexibility service by system operators and tariff regulation 

Feedback from the public consultation 

  The majority of respondents consider that a stronger role of operational expenditures for 
system operators’ remuneration would incentivise the use of demand response, energy 
storage  and  other  flexibility  assets.  Some  respondents  point  out  that  in  addition  to 
incentivising  demand  response  and  energy  storage,  a  stronger  role  of  operational 
expenditures would greatly incentivise the use of grid enhancing technologies, such as 
Dynamic Line Rating, Advanced Power Flow control, innovative solutions and digital 
platforms  etc.  National  regulatory  authorities,  TSOs  and  DSOs  agree  and  note  that 

96   When looking at the percentage of balancing capacity volume procured from DSR facilities in comparison to 
total  procured  balancing  capacity  for  mFRR,  and  percentage  of  balancing  energy  volume  activated  from 
demand-side response facilities in comparison to total annually activated balancing energy for mFRR.  
Survey on Ancillary services procurement, Balancing market design, ENTSO-E, 2021  
Available  here:  https://eepublicdownloads.blob.core.windows.net/public-cdn-container/clean-documents/mc-
documents/balancing_ancillary/2022/2022-06-20_WGAS_Survey.pdf, p.179 and p.183. 

60 

 
 
 
 
 
 
 
 
 
 
                                                 
different regulatory regimes coexist in Europe for the treatment of costs. They agree that 
the use of efficient and innovative solutions (that lead to smarter use of the grid) should 
be better incentivised to complement the vast investments in the physical grid that are 
necessary to reach the EU’s climate neutrality goals. 

  Several  respondents  point  out  that  a  stronger  role  of  operational  expenditures  in  the 
system operators’ remuneration is not sufficient because of a time-lag for recognising 
operational  expenditures  in  the  remuneration.  In  most  national  regulatory  systems, 
OPEX would only be adapted with a considerable time-lag. Several respondents propose 
the introduction of further incentives to better manage flexible resources. 

  Several respondents advocate for increased network transparency, in particular on grid 
congestion,  to  further  incentivise  flexibility.  Respondents  also  propose  performance 
indicators  linked  to  renewables  integration.  Some  respondents  call  for  the  further 
development  of  decentralised  flexibility  markets  as  a  market-based  mechanism  for 
system operators to procure flexibility services. 

o  State of play 

Investment in grids will be key to enable the integration of high shares of renewable energy and 
for accommodating the electrification of end users. They are becoming a growing share of the total 
investments of the energy transition. In fact, the share of costs related to electricity grids increased 
from 27% to 37% of the supply costs (grid costs and generation costs) between the 2010s and the 
2020s, with a total of electricity grid investments over the current decade estimated at EUR 584 
billion97.  It  is  essential  that  transmission  and  distribution  tariffs  reflect  such  developments, 
encouraging  projects  that  support  the  long-term  network  needs,  are  cost-reflective  and  give 
incentives for the deployment of smart electricity grids and innovative solutions that contribute to 
the reduction of network losses. 

In addition, enhancing the digitalisation of the energy system will also be instrumental to achieving 
our energy and climate goals. NRAs are currently defining common smart grid indicators, as well 
as objectives for these indicators, so that they can monitor smart and digital investments in the 
electricity grid annually as of 2023. 

An efficient use of the grid is needed to limit the costs of the energy transition. The use of non-
fossil  flexibility  services,  such  as  demand  response  and  storage,  by  system  operators,  be  it  for 
balancing services activated by TSO or for congestion management or other grid services activated 
by TSOs and DSOs, can contribute to an efficient use of the grid and an efficient operation of the 

97  

https://energy.ec.europa.eu/news/member-states-agree-new-ambition-expanding-offshore-renewable-energy-
2023-01-19_en 

61 

 
 
 
 
 
 
 
 
                                                 
electricity  system.  It  is  therefore  important  that  TSOs  and  DSOs  have  the  right  incentives  to 
procure such flexibility services.  

The  Electricity  Directive  already  sets  out  that  the  DSOs  should  be  incentivised  to  procure 
flexibility services based on market procedures, in order to efficiently operate their networks and 
to avoid costly network expansions.  

Both TSOs and DSOs are launching local initiatives to further develop and use flexibility services, 
through  different  types  of  tools  ranging  from  data  sharing  to  a  local  marketplace  for  specific 
services98. 

Table  4  below  illustrates  some  national  initiatives  developing  market-based  procurement  of 
services, in particular for congestion management by the DSOs. 

Table 4: market design specifics in some local flexibility markets 

Source: JRC, Local Electricity Flexibility Markets in Europe, 202299 

98  

99  

Review of Flexibility Platforms, A report prepared by Frontier Economics for ENTSO-E, September 2021. 
Available here: 210957_entso-e_report_neutral_design_flexibility_platforms_04.pdf (azureedge.net) 
Local Electricity Flexibility Markets in Europe, JRC Technical Report, European Commission, 2022. 
Available here:  

62 

 
 
 
 
 
 
 
 
 
 
                                                 
While these initiatives constitute a very good starting point, their scope and application remain 
limited.  

Additional incentives are needed to further enhance the use of flexibility solutions as an alternative 
to grid development, where possible. In that respect, in most Member States, the current regulatory 
framework treats capital expenditures (CAPEX) of system operators, such as network expansion 
costs, different from their operational expenditures (OPEX), resulting in a bias in favor of capital 
expenditure.  This  could  disincentivise  system  operators  from  choosing  a  flexibility  solution 
resulting in operational expenditure rather than an investment in infrastructure resulting in capital 
expenditure. Removing this bias in the regulatory framework will allow system operators to select 
the most cost-efficient solution for their networks. 

All Member States concerned by an initiative of market-based procurement of flexibility services 
by the DSOs listed in Table 4 above have adopted a TOTEX (total expenditure) approach for the 
remuneration of system operators, which allows the DSOs to choose OPEX or CAPEX or a mix 
of both to meet network demands without a regulatory bias towards capital expenditures.  

o  Commission’s proposal 

The  Commissions  reiterates  that  a  full  implementation  of  the  Clean  Energy  Package  is  key  to 
unleash  non-fossil  flexibility  assets,  such  as  demand  response  and  storage100.  Moreover,  the 
Commission  together  with  ACER  has  started  the  work  on  new  rules  to  further  support  the 
development  of  demand  response,  including  rules  on  aggregation,  energy  storage  and  demand 
curtailment,  and  to  address  remaining  regulatory  barriers.  A  study  will  be  conducted  in  2023, 
underpinning the drafting of the Network Code. 

In the present reform, the Commission proposes to further develop regulatory frameworks based 
on relevant expenditures necessary to operate the network in the most efficient way and finding 
the right balance between capital expenditure and operational expenditure. This would incentivise 
system  operators  to  further  develop  innovative  solutions  to  optimise  existing  grid  and  procure 
further flexibility services.  

Grid investments play a crucial role for the energy transition and there is a need for a predictable 
and forward-looking regulatory framework for such investments.  Transmission and distribution 
grids  will  need  to  evolve  rapidly  to  be  able  to  incorporate  the  vast  amounts  of  new  renewable 
generation and new electrified and digitalised demand. An example comes from the high offshore 
renewable ambitions indicated by Member States, where network development planning will give 
visibility  on  long-term  network  needs  both  in  new  offshore  grids  as  well  as  onshore 

100  

For example, in relation to Article 17(4) of the Electricity Directive, Member States should ensure that it is 
implemented in a way that ensures the financial compensation is fair and does not create a market entry 
barrier. 

63 

 
 
 
 
 
 
 
                                                 
 
reinforcements. These investments, also anticipatory investments in some cases, would need to be 
planned for in the respective tariff regimes. 

Additionally,  the  ongoing  work  on  smart  grid  indicators  is  crucial  to  guide  and  speed  up 
investments in smart and digital electricity grids and will help to operationalise the shift in tariff 
structures, incentivising an efficient mix of operational and capital expenditure. 

5.3.  Use of sub-meter data for the settlement and observability of demand response and 
flexibility services 

Feedback from the public consultation 

  The majority of respondent would welcome the use of sub-meter data, including private 
sub-meter data, for settlement/billing and observability of demand response and energy 
storage and considers that the use of sub-meter data would support the development of 
demand response and energy storage. Some respondents noted that the use of submeter 
data  creates  a  big  market  potential  as  it  opens  the  door  for  multiple  market  actors, 
including  demand  response  providers  and  storage  providers,  to  become  active 
simultaneously on one connection point. Sub-metering would allow active consumers to 
sell their flexibility to the markets, participate to energy communities, proceed to energy 
sharing or peer-to-peer transactions, contract different suppliers for different appliances 
behind the main meter, or to offer services to system operators. 

  Respondents stressed the need to ensure the quality of the sub-meter data and to verify 
the  consistence  with  the  main  meter.  Several  respondents  considered  that  the  sub-
metering system must be certified  

  Several respondents consider that the Measurement Instruments Directive 2014/32/EU 
(MID) would need to be reviewed as its requirements are too restrictive and hamper the 
use of sub-meter data. Other respondents call for a clarification of the applicability of 
MID to sub-meter data. 

  Some  respondents  voice  concerns  about  using  sub-meter  as  this  data  could  bring 
significant complexity and create risk of gaming between the meters. The focus should 
stay on the full roll-out of smart metering systems, which should remain the central point 
of measurement.  

  Several respondents consider that the role of sub-meters and their use should be further 
defined and detailed in the future network code on demand response to be developed on 
the basis of Art. 59 of the Electricity Regulation 2019/943. 

64 

 
 
 
 
 
 
 
 
 
o  State of play 

The Electricity Directive provides for the deployment of smart metering systems in all Member 
States to facilitate the more active participation of customers in the electricity market and in the 
energy  transition.  However,  not  all  Member  States  have  completed  the  full  rollout  of  smart 
metering  systems  and  the  share  of  final  household  customers  having  a  smart  metering  system 
installed varies significantly among Member States.  

Basing the measurement of demand response and flexibility services on smart metering systems 
installed  by  DSOs  risks  limiting  the  development  of  demand  response  to  markets  with  full 
deployment of smart metering systems, depriving some customers from the possibility to engage 
and  value  their  flexibilities  as  well  as  preventing  electricity  system  from  benefitting  from  the 
flexibility of customers without smart metering systems. 

Figure 13: Status of the roll-out of electricity smart meters at the end of 2021 

Source: ACER Market Monitoring Report 2021101  

101   Annual Report on the Results of Monitoring the Internal Electricity and Natural Gas Markets in 2021 - Energy 
here: 

and  Consumer  Protection  Volume,  ACER/CEER,  October 

Retail 
MMR_2021_Energy_Retail_Consumer_Protection_Volume.pdf (europa.eu) 

2022.  Available 

65 

 
 
 
 
 
 
 
 
 
 
                                                 
Even where smart metering systems are installed, the technology is not always able to provide the 
level of granularity of data needed for the measurement of certain services and will thus not allow 
to tap into the full flexibility potential of the demand side.  

If sub-metering systems providing data with appropriate accuracy are available, system operators 
should be entitled to use sub-meter data (including from private sub-meters) for settlement and 
observability processes of demand response and flexibility services, including energy storage. The 
use of sub-meter data should be accompanied by requirements for the sub-meter data validation 
process to check and ensure the quality of the sub-meter data. 

o  Commission proposal 

The  Commission  proposes  to  enable  system  operators  to  use  sub-meter  data  (including  from 
private sub-meters) for settlement and observability processes of demand response and flexibility 
services  to  support  the  development  of  these  services  and  facilitate  the  participation  of  active 
customers in electricity markets. 

The  use  of  sub-meter  data  should  be  accompanied  by  requirements  for  the  sub-meter  data 
validation process to check and ensure the quality of the sub- meter data.   

The principles and roles for the use of such data will be detailed in the future network code on 
demand response, including rules on aggregation, energy storage and demand curtailment based 
on Article 59(1), point (e) of the Electricity Regulation 2019/942.  

This  provision  is  linked and complements the provision  that customers shall have the right  for 
more  than  one  meter  installed  in  their  premises  and  sub-metered  consumption  to  be  separately 
billed  and  deducted  from  the  main  metering  and  billing  (see  section  “Adapting  metering  to 
facilitate  demand  response  from  flexible  appliances”  in  the  section  on  “Better  consumer 
empowerment and protection”).  

66 

 
 
 
 
 
 
 
 
 
 
 
 
Incentives for non-fossil flexibility such as demand response and storage,  and 

5.4. 
remuneration schemes 

Feedback from the public consultation 

Demand response 

The  majority  of  respondents  consider  appropriate  to  enable  a  product  to  foster  demand 
reduction  and  shift  energy  at  peak  times  as  an  ancillary  service,  aiming  at  lowering  fuel 
consumption and reducing the prices. However, many respondents also consider that such peak 
shaving actions should happen through wholesale markets, without any intervention from the 
TSO, and that such a product could be a barrier to these developments. Such a product could be 
considered as specific and transitory solutions to kick start demand response. 

Some respondents note that all ancillary services should favor carbon-free solutions, or that the 
services should be reviewed to better enable demand response participation. 

The majority of respondents do not recommend some form of demand response requirements 
that  would  apply  in  periods  of  crisis.  They  mainly  consider  that  developing  market-based 
solutions to promote demand reduction can prevent these crisis situations before they occur and 
can  spur  further  investment  into  flexibility  assets.  However,  some  market  participants 
recommend  a  demand  reduction  target  as  a  permanent  feature.  If  such  concept  should  be 
pursued,  some  respondents  consider  it  should  take  the  form  of  critical  peak  pricing  auctions 
(some form of dynamic capacity mechanisms for peaks), while transparency on the need and 
auctions would be key. 

Respondents share several proposals as way forward to further develop demand response, 
energy storage and other flexibility assets: 

-  The full implementation of the Clean Energy package provisions should remain a top 
priority, opening all market to demand response and storage. Some respondents ask for 
more oversight from the European Commission and ACER in this respect and encourage 
sharing of best practices. The future Network Code on Demand Response should provide 
the necessary provisions to address any remaining barriers.  

-  Providers of demand response and storage should be able to stack value from different 

markets (including local congestion management). 

-  Alternative market-based mechanisms providing long-term investments signals such as 
capacity remuneration for demand response and storage could be desirable, to reach 
the necessary levels of storage and demand response development, which come together 
with renewable targets. 

67 

 
 
 
 
 
 
 
 
-  Targets for flexibility (demand response and/or storage) could be set at national level, 
through e.g. a grid designed at 95% of the peak load in network development plans, or 
through  requirement  for  balance  responsible  parties  or  suppliers  to  reduce  their 
perimeter’s peak load. 

-  The minimum bid size on short term markets could be lowered, to enable smaller actors 

to participate. 

-  Transparent and easy access to  prices; dynamic publication of imbalance settlement 

prices with no delay 

-  Auctions  for  CfDs  could  consider  hybrid  assets  (renewables  +  storage);  CfDs  for 

flexibility could be in a form of public support scheme. 

-  Stronger locational and temporal signals could be given in prices or grid tariffs. 

-  Flexible grid connection agreements could be more used. 

-  Local flexibility markets should be incentivised. 

-  Consumers  contracts  should  keep  demand  response  incentives  (limitation  of  the 
volume at fixed price, critical peak period contracts as a pure spot price reference). 

-  Scarcity pricing to boost demand response. 

-  Flexibility registers to accelerate the development of harmonised products for system 

services and enable single registration point for flexibility assets. 

-  System operators could own storage in specific and limited situations, to ensure an 

efficient grid management. 

-  A  clarification  of  demand  response  versus  energy  efficiency  as  a  service  may  be 

needed. 

Regarding electrical vehicles development, some respondents note that visibility is needed, and 
that controllable/bidirectional charging stations should be encouraged. 

Capacity mechanisms 

The majority of respondents  consider that the current  setup  for  capacity  mechanisms is  not 
adequate  to  respond  to  the  investment  needs  as  regards  firm  capacity,  in  particular  to  better 
support the uptake of storage and demand side response. They fear a lock-in effect in fossil-fuel 
based technologies.  While existing CRMs already allow participation of demand response and 
storage, future designs should enable them to participate to the full extent possible and further 
incentivise carbon-free solutions. 

68 

 
 
 
 
 
 
 
Respondents share the following proposals: 

-  To consider not only the peak load, but also rapid variations of renewables (“flexibility 

adequacy”); 

-  To smoothen the process; 

-  To contemplate more targeted capacity remunerations (such as interruptibility); 

-  To further consider national assessments; 

-  To better harmonise European approaches, and address cross-border barriers for sharing 

resources; 

-  To bring capacity mechanisms as a full part of the market design. 

Some  respondents  consider  capacity  mechanisms  are  not  suitable  as  a  robust  investment 
framework,  since  they  cannot  deliver  a  one-size-fits-all  signal  that  targets  all  type  of 
investments. Specific support schemes may be better fit to ensure proper investments, going 
beyond pure security of supply question (such as renewables integration and the corresponding 
flexibility need).  

o  State of play 

Over the period 2019-2022, demand response participation in capacity mechanisms has increased 
to over 4 GW, while storage is still at very low levels (below 300 MW in 2022)102.   

102  

ACER, Security of EU electricity supply in 2021: Report on Member States approaches to assess and ensure 
adequacy 

69 

 
 
 
 
 
 
 
 
 
 
 
                                                 
Figure 14: Capacity remuneration through capacity mechanisms per type of technology in EU-27 
2019-2022  

Source: ACER (Security of EU electricity supply in 2021: Report on Member States approaches 
to assess and ensure adequacy) 

Despite a trend towards diversification, most of the long-term contracted capacity is allocated to 
natural gas and coal/lignite power plants. Although this will reduce when new emissions’ limits 
come  into  force  in  2025,  capacity  mechanisms  are  still  expected  to  continue  to  support  fossil-
fueled power plants beyond 2030103. 

103   ACER 

70 

 
 
 
 
 
 
 
 
 
 
                                                 
Figure 15: Long-term contracted capacity and costs by type of technology in the EU-27 on the 
period 2026-2035 

Source:  ACER, Security of EU electricity supply in 2021: Report on Member States approaches 
to assess and ensure adequacy 

This  trend  shows  the  difficulty  for  non-fossil-fuel  based  flexibility  (like  demand  response  and 
storage) to effectively compete in the electricity system as a buffer to renewables variations. 

In some Member States, there has been a significant increase in the participation of energy storage 
and  demand  response,  in  particular  in  recent  auctions.  As  an  example,  Poland  awarded  over 
1.5 GW for demand response out of a total of 5 GW for 2027 in the latest auction of its capacity 
mechanism104.  In the latest auction of the Italian capacity mechanism, storage accounted for about 
30% of the total newly allocated capacity for 2024 (3,8 GW)105.  Such developments are lower in 
some other Member States: Ireland awarded 490 MW of demand response and about 450 MW of 
storage, against 8,8 GW of total awarded capacity for 2025-2026106. Belgium awarded 287 MW 
of demand response and 41 MW of storage over a total of 4.4 GW of contracted capacity for 2025-
2026107. 

In Member States with existing capacity mechanisms, efforts to encourage non-fossil flexibility  
participation can be based on additional “green and flexible” criteria as provided for in the state 

104  
105  
106  

107  

https://www.pse.pl/documents/20182/98611984/Wyniki+aukcji+głównej+na+rok+dostaw+2027 
https://www.terna.it/it/sistema-elettrico/mercato-capacita 
https://www.sem-o.com/documents/general-publications/T-4-2025-26-Final-Capacity-Auction-Results-
Report.pdf 
https://www.elia.be/en/grid-data/adequacy/crm-auction-results 

71 

 
 
 
 
 
 
 
 
                                                 
aid guidelines (CEEAG)108. However, when a Member State does not have a capacity mechanism 
or where the amount of non-fossil flexibility such as demand response and energy storage coming 
from these mechanisms proves to be insufficient to support the Member States’ renewables’ target, 
it should be possible to further support required flexibility. A dedicated capacity payment could 
be  envisaged  as  a  solution  (further  details  in  the  next  section),  enabling  further  renewable 
integration, in  the form  of non-fossil  flexibility support schemes such as  demand response  and 
storage. 

As an example, in France, the participation of consumers in balancing and wholesale markets is 
further  boosted  by  dedicated  capacity  payments.  As  a  temporary  measure,  demand  response 
providers  are  remunerated  via  regular,  competitive  tenders.  This  mechanism  has  shown  an 
increased interest over the past years. 

Table 5: Participation in capacity auctions dedicated to demand side response in France - 

Source: ACER, Security of EU electricity supply in 2021: Report on Member States approaches to 
assess and ensure adequacy 

Belgium  is  also  considering  launching  a  dedicated  scheme  for  low  carbon  technologies  (new 
storage and batteries, as well as demand response) to procure capacity for winter 2024-2025109. 

Finally, demand response should be allowed to further contribute to integrating renewables in the 
system  and  help  coping  with  critical  situations  in  the  electricity  system.  Where  market 
development is unsatisfactory, such a role of demand response could take the form of a dedicated 
ancillary product, to be used by the system operator. This would allow using renewables at their 
full potential, by shifting the consumption to a moment with higher renewables production. 

Furthermore, when consumption is high and the renewables’ generation insufficient to cover it, 
demand reduction could partially replace the use of gas power plants, contributing to lowering the 
prices and the gas consumption volumes110.  

108  

109  
110  

COMMUNICATION FROM THE COMMISSION Guidelines on State aid for climate, environmental 
protection and energy 2022 (2022/C 80/01) 
Formal public consultation on the Functioning Rules for the tender for low carbon capacities (elia.be) 
Based on observed hourly generation during the period between January and August 2022, a reduction of 5% 
during the 10% hours displaying the highest level of demand for electricity would bring the average demand 
during these hours to the level of the first non-selected peak hours. This would therefore result in a smoothening 

72 

 
 
 
 
 
 
 
 
                                                 
Figure 16: illustration of demand side flexibility effect  

Source : Compass Lexecon, Study on the quantification of Demand Response benefits to electricity 
suppliers and consumers in Europe in 2030 on its way to achieve deep decarbonisation, 2021111 

o  Commission proposal 

The Commission proposes to request NRAs, based on inputs from transmission and distribution 
system operators, to periodically assess the need for flexibility in the system, based on harmonised 
methodology, proposed by ENTSO-E and EU DSO entity and adopted by ACER. Based on the 
national assessments, ACER should give an overview at European level, with recommendations 
of cross-border relevance. The Member States could use this assessment to determine a national 
objective for  non-fossil  flexibility  such  as  demand response  and storage,  also  reflected  in  their 
NECP. 

The  Commission  proposes  to  support  the  development  of  clean  flexibility  solutions  with  low-
carbon capacity payments by making clear in the Recitals how the Electrcity Regulation and State-
aid guidelines can be read together to create a low-carbon capacity mechanism112 (i.e. by setting 
a low CO2 cap and adding flexibility requirements).  

In addition, the Commission proposes to make it possible for Member States to design a non-fossil 
flexibility  support  scheme  in  the  form  of  a  capacity  payment,  to  enable  renewable  targets  and 

of the hourly consumption profile. Moreover, since gas is generally the marginal technology during the hours 
with the highest demand, this targeted 5% reduction can lead to a reduction of gas consumption estimated 
around 1.2bcm over a 4-month period. This represents around 3.8 % of gas consumption for power over the 
same period. Recent studies110 show that the current potential of demand response could fulfil the mandatory 
target, having a positive impact on electricity prices and on volumes of gas savings 

111  
112  

http://dr4eu.org/wp-content/uploads/2021/05/CL-DR4EU-DSR-study-06052021_vdef.pdf 
CEEAG Art. 345 

73 

 
 
 
 
 
 
 
 
 
                                                 
based on the assessment described above. Such additional support scheme should be designed as 
a competitive bidding process.  The dimensioning  of the scheme should take fully into account 
investments which come on a pure market basis or through a capacity mechanism whilst aiming 
at phasing out fossil sources from the mix. Such a scheme would provide more stable revenues to 
non-fossil flexibility  (such as  demand response  and storage),  while preserving full  exposure to 
market price signals.  

Finally, the Commission proposes to allow system operators to develop a “peak shaving” product, 
to  incentivise  consumption reduction at  peak time (i.e., in  times of high demand for electricity 
and/or  limited  generation  from  renewables).  System  operators  could  then  call  for  demand 
reduction during certain hours of the day, and the consumers would get paid for this reduction. 
Such  product  could  help  to  decrease  fossil  fuel  generation  and  optimise  the  use  of  renewable 
electricity.  

6.  Towards better consumer protection and empowerment 

Feedback from the public consultation 

Energy sharing 

See section 2.4 

Right to a second meter/sub-meter 

The consultation found that majority of respondents supported introducing a right for customers 
to  a  second  meter/sub-meter  to  distinguish  electricity  consumption/production  by  different 
devices. However, cost-effectiveness and ownership were caveats. The implementation of sub-
metering  was  divisive,  with  some  favouring  customer  choice  and  installation  by  service 
providers,  while  others  insisting  on  DSO  oversight.  The  main  meter  according  to  some 
respondents should remain the central point of measurement, balance settlement, and billing. 
Sub-meters were supported if there is  a single source of truth  for billing and settlement,  and 
compensation agreements are in place, and there are no lock-in effects. Harmonised protocols 
for data creation, management, and transmission were suggested to provide accurate, stable, and 
transparent  data.  Sub-meters  supporting  demand  response  and  storage  were  seen  as 
complementary to smart meters in developing flexible, efficient and sustainable electricity, and 
fostering competition. It was argued that sub-metering should be encouraged to reduce barriers 
for new entrants in the market, so long as it does not compromise system security. It was also 
pointed out that the Electricity Directive already includes useful provisions promoting flexibility 
and tools to support it, while details on the role and use of sub-meters as means for flexibility 
should be set in the future network code on demand response. A minority viewpoint cautioned 

74 

 
 
 
 
 
 
 
 
 
that  implementing  sub-metering  without  specific  safeguards  would  create  a  new  category  of 
final customers without the same rights and responsibilities as other retail electricity customers. 

Offers and contracts  

Stakeholders have diverging views about the obligation for suppliers to offer fixed-price and 
fixed-term  contracts  for  households.  While  some  stakeholders  explain  that  such  obligations 
violate  free  market  principles  and  argue  that  market-based  fixed-price  contracts  should  be 
offered voluntarily, majority of consumer organisations, NGOs and public authorities support 
the introduction of such obligation. Some stakeholders propose to offer hybrid contracts, with 
both fixed and dynamic pricing, to meet different individual needs. Respondents suggested that 
customer choice should guide the duration of such contracts, with suggestions ranging from a 
fixed duration of one year to a range of three months to five years while the biggest support was 
for one year contracts 

Respondents  agreed  that  termination  fees  for  fixed  term  and  fixed  price  electricity  contracts 
should  reflect  costs  and  not  undermine  competition  and  the  ability  of  consumers  to  switch 
suppliers  and  contracts.  While  many  stakeholders  would  welcome  further  clarification  of 
termination fees, only some agree with mandating national regulatory authorities to establish ex 
ante  approved  termination  fees.  Also,  consumer  organisations  as  well  as  some  industry 
representatives mentioned that the existing provisions in the Electricity Directive are sufficient. 
Representatives of regulatory authorities pointed out that it is difficult to set ex ante termination 
fees for fixed-price, fixed-term contracts because different suppliers have different costs. Risk 
management for suppliers 

Most respondents across different stakeholder groups supported the establishment of prudential 
obligations  on  suppliers  to  ensure  they  are  adequately  hedged.  However,  some  respondents 
mentioned that such rules would impede the entry of new suppliers and harm competition. While 
many agreed that this is a common regulatory approach to mitigating the risk of supplier default, 
some  pointed  out  that  suppliers  should  hedge  for  the  share  of  their  retail  portfolio  that 
corresponds to fixed-price contracts. According to a few stakeholders, suppliers should have the 
freedom to choose their hedging policy, but stress tests could be imposed as a prerequisite for 
licensing electricity sales. A minority of respondents suggest that such obligations should be 
differentiated for small suppliers and energy communities. 

Suppliers of last resort 

Stakeholders mentioned that the supplier of last resort mechanism was implemented across the 
EU  but  its  design  varies.  Majority  of  respondents  believe  that  the  EU  regulatory  framework 
should set general rules for and responsibilities of suppliers of last resort providing further clarity 
but some stakeholders pointed out that certain aspects should be left to the national level as the 
situation in retail markets differs.  

75 

 
 
 
 
 
 
 
Regulated prices 

Respondents are equally divided on the question of regulated prices. Majority of public authority 
respondents are in favour of including an emergency framework for below cost regulated prices. 
The advantage seen would be the possibility of preparing functional tools in the national market 
model that would allow price regulation to be easily activated in exceptional cases. Majority of 
business associations and companies believe that regulated below-cost prices distort the market, 
cancel  the  price  signal  and  reduce  incentives  to  invest  in  renewables  and  energy  efficiency. 
Emergency  measures  should  therefore  be  implemented  outside  the  electricity  market.  They 
recognize  however  in  comments  that  in  spite  of  their  opposition  regulated  prices  could  be  a 
solution for energy poor and vulnerable consumers. If price regulation is introduced, it should 
be time-limited and only address essential energy needs. They also mention more appropriate 
social policies and tools to protect less flexible or more vulnerable consumers from unlimited 
exposure  to  potential  extreme  or  sudden  increases  in  retail  prices.  Some  respondents  from 
companies also suggest that consumers of all types be ultimately protected from extreme price 
fluctuations by hedging products offered in combination with dynamic price contracts. 

6.1. 

Introduction 

Energy prices significantly increased throughout 2021 and 2022 due to Europe’s overreliance on 
gas. During this period, several countries reported an increase in exits due to a significant increase 
in supplier bankruptcy. Many remaining suppliers have passed their risks onto their customers – 
for  example  by  only  offering  contracts  which  track  wholesale  market  prices.  This  resulted  in 
customers being exposed to extremely volatile wholesale energy prices. This was the case not only 
for those who had a variable tariff but also for those who were initially protected from wholesale 
price volatility by being on a fixed-price contract. Consequently, many households, not only those 
who  are  most  vulnerable  but  increasingly  also  middle-income  families,  have  been  facing 
difficulties when paying their bills.  

Moreover, crisis context also revealed that consumers lack understanding regarding what contract 
they  were  on.  For  instance,  many  people  were  not  aware  that  the  contract  they  signed  up  for 
foresees electricity prices that were linked to wholesale prices. Many also thought that the prices 
they were paying for electricity were fixed for the entire duration of the contract which was often 
not the case.  

There was a major movement of customers onto regulated, capped or otherwise protected variable 
offers.  Member  States  developed  different  measures,  targeted  or  untargeted,  to  keep  energy 
affordable for all households and businesses. These measures are nevertheless very expensive and 
weighing on national budget. 

In addition to putting affordability into question, consumers have been lacking opportunities to 
engage in the market – benefiting from multiple contracts or benefiting from low-cost renewables. 

76 

 
 
 
 
 
 
 
6.2.  Offers and contracts to better protect consumers against volatile prices 

o  State of play 

Fixed-price contracts can protect consumers from short-term price volatility.  

Since the end of 2021 and even more throughout 2022, suppliers reduced their offers and fixed-
price  and  fixed-term  contracts  became  scarce.  In  several  markets,  consumers  are  left  with  the 
option to sign up for electricity contracts with a tariff linked to wholesale prices or to fixed-price 
tariffs which incur substantial risk premiums. The vast majority of contracts now available allow 
suppliers  to  change  the  price  they  charge  at  any  time.  This  was  often  insufficiently  clear  to 
customers  who  believed  that  they  had  entered  into  fixed  price  contracts  and  illustrates  low 
awareness about and understanding of offers. 

Consumer organisations reported examples where suppliers switched customers from fixed-price 
contract to variable price without adequate information, announced significant price increase on 
page 2 of a letter with energy tips, unilaterally terminated open-ended contracts with customers 
who did not accept imposed price increases or where suppliers did not advertise the full price of 
electricity when a new tax was introduced.113  

Lack of understanding of electricity offers is also demonstrated by several surveys by consumer 
organisations and regulators. A survey done by the Belgian National Regulatory Authority, CREG, 
showed  that  half  of  the  consumers  was  not  aware  whether  they  had  a  fixed  or  variable  priced 
contract and that one in two also felt not sufficiently informed about the difference between fixed 
and  variable  prices.114  According  to  the  research  commissioned  by  the  Irish  Energy  regulator, 
CRU, the comparison of electricity offers is difficult for majority of consumers.115  

113   An  electricity  market  that  delivers  to  consumers,  BEUC  position  paper  on  the  upcoming  revision  of  the 

provisions on consumer rights in the Electricity Directive, October 2022 
CREG, Rapport relatif à l’enquête et l’étude sur le comportement des consommateurs résidentiels sur le marché 
de détail belge de l'électricité et du gaz naturel, June 2021. 
CRU Residential Electricity & Gas Market Survey Results 2022 

114  

115  

77 

 
 
 
 
 
 
 
 
 
                                                 
Figure 17: Consumer difficulty with comparing offer in Ireland 

Source: CRU Residential Electricity & Gas Market Survey Results 2022 

As suppliers are facing a significant increase in hedging, it is likely that consumers will have less 
access to fixed price contracts  in 2023. At the same time, consumers may need to be provided 
information as to how such changes may impact them financially.116 

o  Commission proposal 

The Commission’s proposal enables consumers to have access to wide range of offers so that they 
can choose the best deal for them. To ensure consumers have sufficient choice, suppliers with more 
than 200 000 customers will be obliged to offer fixed-price contract for at least 1 year, and at least 
one  fixed  price  contract  will  need  to  be  available  in  all  Member  States.  This  mirrors  already 
existing obligation for large suppliers to offer dynamic price contracts.117 Suppliers will be free to 
determine  the  price  themselves  but  will  not  be  allowed  to  unilaterally  modify  the  terms  and 
conditions before such contract expires.  

Offers  will  need  to  be  designed  in  a  way  to  incentivise  final  customers  to  save  electricity  and 
should be clearly communicated to consumers prior signing the contract. Irrespective of the type 
of contract consumers are on, they will always be provided with clear pre-contractual information 
in a simple and consumer-friendly format.   

116   Annual Report on the Results of Monitoring the Internal Electricity and Natural Gas Markets in 2021 - Energy 
here: 

and  Consumer  Protection  Volume,  ACER/CEER,  October 

Retail 
MMR_2021_Energy_Retail_Consumer_Protection_Volume.pdf (europa.eu) 

2022.  Available 

117   Article 11, Directive 2019/944 

78 

 
 
 
 
 
 
 
 
                                                 
6.3.  Risk management 

o  State of play 

Under  stable  market  conditions,  suppliers  make  long  term  commitments  to  their  customers  to 
supply them energy – often at fixed prices. To fulfil these obligations they must either have access 
to their own generation facilities or buy the electricity from the wholesale market.  If suppliers 
have  made  firm  commitments  to  their  customers,  without  buying  the  necessary  electricity  on 
forward markets (i.e. hedging) then they are vulnerable to increases in wholesale prices – in effect 
they are speculating on  low prices  continuing, risking significant  losses  when wholesale prices 
rise.  There  are  several  hedging  instruments  (long-term  forward  and  financial  futures  contracts) 
which have been available and traded for many years, see section 2 above).  

Not all suppliers are equally able to access these hedging products. Energy community suppliers 
hedge by trying to match the consumption of their members with their own production capacity.  
Energy  communities  with  sufficient  installed  capacity  have  shown  at  times  greater  resilience 
against  volatile  wholesale  market  prices  than  commercial  suppliers.118  However,  in  countries 
where RES support has been less consistent,119 these initiatives remain to a larger extent dependent 
on external production in order to meet the full demand of their customers at all times. As these 
initiatives  struggle  to  obtain  necessary  bank  guarantees  and  scale  to  access  power  purchase 
agreements,120 they need to operate on day-ahead and intra-day wholesale market leaving them 
exposed to volatile wholesale market prices and leading to a loss of membership, customers and 
liquidity. 

The  crisis  showed  that  some  suppliers  did  not  hedge  their  supply  portfolio  sufficiently  which 
resulted in some of them going bankrupt when wholesale prices started to increase.121  According 
to  the  ACER-CEER  market  monitoring  report  there  was  a  significant  increase  in  supplier 
bankruptcy following unprecedented wholesale energy price increases in 2021. For example, in 
Czechia,  sixteen  suppliers  went  bankrupt  between  October  2021  and  January  2022.  The  major 
supplier, Bohemia  Energy,  had  1  million  customers.  In  Germany,  several  electricity  and  gas 
suppliers  went  insolvent  or  terminated  their  contracts  with  household  customers  in  2021.  This 
wave  of  bankruptcies  and  contract  terminations  affected approximately  950,000 household 
customers, who had to involuntary switch to other suppliers. 

This imposes real costs on consumers – who must find a new supplier at short notice – often during 
periods of high prices – and whose own financial planning is disrupted. Moreover, supplier failure 

118  
119  
120  

See for example Ecopower CVBA: Samen investeren in hernieuwbare energie · Ecopower. 
For example, Ireland, Spain, Italy and Romania. 
European Commission (2022). Staff Working Document – Guidance to Member States on good practices to 
speed  up  permit-granting  procedures  for  renewable  energy  projects  and  facilitating  Power  Purchase 
Agreements – Accompanying the Commission Recommendation on Speeding up permit-granting procedures 
for renewable energy projects and facilitating Power Purchase Agreements. 

121  

ACER-CEER Market Monitoring Report 2021 

79 

 
 
 
 
 
 
 
                                                 
results in the socialisation of some of their costs, including network charges owed to TSOs and 
DSOs and potentially imbalance costs. This is because the costs of unpaid network charges owed 
by the failed supplier are often passed on to other market participants or all consumers.  

Moreover,  supplier  failures  during  a  crisis  can  also  result  in  a  breakdown  in  competition  at 
precisely the time when consumers should benefit most – and are most interested in switching. 
Member States may feel compelled in this situation to implement major interventions to protect 
consumers.  

o  Commission proposal 

While prudent suppliers already voluntarily implemented appropriate hedging, the experience of 
the crisis has shown that some suppliers did not – either because they tabled on additional profits 
from lower market prices or because they had difficulty accessing longer term contracts. This last 
concern should be less preeminent in the context of the envisaged improvements to longer term 
markets and improved access to PPAs - which can be used as hedging instruments.  

The Commission’s proposal will oblige all suppliers’ responsibility to have in place and implement 
appropriate hedging strategies in order to limit the risk of changes in wholesale electricity to the 
economic viability of their contracts with customers. It will be for Member States to assess those 
strategies.  An  appropriate  strategy  should  take  into  account  the  supplier's  access  to  its  own 
generation and capitalisation of the supplier as well as its exposure to changes in wholesale market 
prices.  

The appropriateness of the hedging strategy will also depend on their size and business model. In 
this  regard,  the  proposal  also  calls  on  Member  States  to  endeavour  to  ensure  accessibility  of 
hedging products such as PPAs for energy communities. 

6.4.   Enabling energy sharing 

Energy sharing can be an effective instrument to empower consumers that do not have available 
space, technical capacity and/or financial means to become prosumers in an easy and cost-efficient 
way. This group of consumers can access renewable energy by leasing, renting or investing in a 
renewable  energy  generation  or  storage  facility  and  sharing  the  generated  electricity  among 
themselves (model 1), or a single prosumer can empower other consumers, including low-income 
families by sharing with them excess production (model 2). 

80 

 
 
 
 
 
 
 
Model 1. Sharing of energy generated by a facility that is collectively owned, leased or rented 

by consumers

Tenants  and  homeowners  without  (exclusive)  ownership  rights  over  the  common  rooftop  of  a 
multi-apartment  building,  or  residential  consumers  with  unsuitable  rooftops  face  difficulties 
accessing  low-cost  renewables.  Enabling  joint  investments  in  and  leasing  or  renting  of  off-site 
generation facilities may help overcome such barriers. Examples of this model range from energy 
communities  sharing  electricity  produced  by  community  owned  renewable  energy  installations 
(e.g., Hyperion) to citizens in Lithuania investing in remote solar PV parks to share the electricity 
it generates122. 

Model 2. Sharing of excess energy generated by a facility of an individual  prosumer with 
other consumers.  

122  

See CLEAR-X collective purchasing campaign. 

81 

 
 
 
 
 
 
 
 
 
 
                                                 
Low-income households face difficulties to access low-cost renewables due to the high level of 
capital  expenditure  for  solar  PV123 as  well  as  high  financial  entry  barriers  for  joint  investment 
initiatives124.  Enabling  individual  prosumers,  including  public  bodies  to  share  energy  can  help 
overcome such barriers, as exemplified in Spain,125 Portugal,126 and Greece127. In addition, this 
model would allow for individuals to share excess electricity with their neighbours,128 as well as 
larger companies sharing excess electricity with families and companies129. 

The empowerment of consumers through energy sharing leads in turn to a growth in renewable 
energy investments, as well as financial benefits derived from the decoupling from the wholesale 
market dampening the effect of high and volatile wholesale markets on consumers’ energy bill, as 
discussed in section 2.4. 

6.5.   Facilitating demand response and increasing choice of contract through sub-metering 

o  State of play 

Fit-for-purpose smart meters can help manage high-energy prices and demand for electricity by 
providing accurate measurements, eliminating estimated bills, and allowing consumers to adjust 
their usage based on market signals. The data collected by smart meters can help energy providers 
and network operators manage demand, while also creating opportunities for consumers to actively 
participate in the energy market and developers to create new services and products. 

The  roll-out  of  smart  metering  systems  is  moving  slower  than  it  was  initially  foreseen.  It  is 
estimated that currently over 50% of EU electricity consumers have access to a smart meter. Based 
on  the  data  from  the  ACER/CEER  Market  Monitoring  Report,  at  the  end  of  2021,  in  twelve 
Member  States  the  rollout  rate  of  electricity  smart  meters  has  reached  an  80%  penetration  or 
higher. Denmark, Estonia, Spain,  Finland, Italy, Luxembourg, Sweden, recorded a 98% rollout 
rate or higher, followed by Malta, France, Latvia, the Netherlands and Slovenia, with rollout rates 
between  88%  and  93%.  In  seven  other  Member  States  (Portugal,  Austria,  Ireland,  Romania, 
Poland, Hungary, Greece), penetration of smart meters is lower than 80%, with a wide scale roll-
out being underway in most of them. 

123  
124  
125  
126  
127  
128  
129  

https://www.irena.org/publications/2022/Jul/Renewable-Power-Generation-Costs-in-2021. 
For example, in Lithuania, it costs between 1379-1400 EUR for 1kW share in solar PV park. 
E.g., “Zero. Energia de proximitat” programme in Valencia, Spain. 
E.g., Santa Casa Misericordia in Portugal. 
E.g., Municipality of Larissa, Greece. 
See Energiedelen en persoon-aan-persoonverkoop | VREG. 
E.g., Edificio PCInvest. 

82 

 
 
 
 
 
 
 
 
 
                                                 
Table 6: Roll-out of smart meters in electricity across the Member States 

Share of 
metering 
points 
ACER/CEE
R 

Real time / 
hourly 
energy 
pricing 
ACER/CEER 

46.6% 

X 

Cost Benefit 
Analysis 

/ 

Positive (2010) 
Positive 
(Flanders) 
Inconclusive 
(2018) 
Negative (2013) 
Inconclusive 
(2014) 
Negative (2016) 

Negative (2013) 
Positive 
Positive 
Positive (2012) 
Positive 
Positive (2008) 
Positive (2013) 

AT 

BE 

BG 
CY 

CZ 

DE 
DK 
EE 
EL 
ES 
FI 
FR 

0.0% 

0.0% 
0.0% 

0.0% 

0.0% 
100% 
99.7% 
2.6% 
99.6% 
99.9% 
90.0% 

HR 

Positive (2017) 

0.0% 

HU 

IE 

IT 

LT 
LU 
LV 

MT 

NL 
PL 

PT 

RO 
SE 
SI 

Pending (2018) 

Negative (2017) 

Positive (2014) 

Inconclusive 
(2018) 
Positive (2016) 
Positive (2017) 

No CBA 

Positive (2010) 
Positive (2014) 

Positive (2015) 

Positive (2012) 
Positive (2015) 
Positive (2014) 

7.8% 

37.5% 

98.5% 

6.4%132 

98% 
90.4% 

93.0% 

87.4% 
15.4% 

52.0% 

17.7% 
100% 
88.1% 

Additional information 
Update from Member States (EC request: ARES(2022)7302800) and 
National Regulatory Authority Reports 

CBA revision 
(where 
applicable) 

Roll-out in progress; planned roll-out targets: 
40% by end of 2022, and 95% by end of 2024 
According to 2022 NRA Report, 80% penetration is foreseen in Flanders by 
end  2024  and  100%  by  2029.  In  Wallonia  and  Brussels-Capital  Region 
rollout to niche cases. Based on ESMIG131  in Belgium in 2020 was 9%. 

N/A130 

Planned roll-out milestones: 200 000 smart meters by Q3 2024, 400 000 by 
Q2 2026 (a delay to this timeline is possible). 
Decision for selective roll-out of 1.7 million smart meters by 2027 (e.g. LV 
customers with over 6 000 kWh annual consumption, energy communities, 
consumers with generation). Roll-out to commence Q3 2024.    
Plan of installing over 20 million smart meters by 2030. 

N/A (decision to 
roll-out) 

420 thousand smart meters have been installed. Plan of installing 7.3 million 
meters. 
By the end of 2019, 99.64% (out of 28.362 million meters of up to 15 kW) 
had been installed.  

N/A 
N/A 
N/A 
N/A 
N/A 
N/A 

According  to  2020  NRA  Report,  nearly  all  MV  Billing  Metering  Points 
(BMPs)  and  LV  non-household  consumers  have  smart  meters  installed. 

7.9% of all LV BMPs (non-household and household) have a smart meter.  N/A 

Roll-out  in  progress;  according  to  national  plan  2.25  million  will  be 
installed  by  2024.  By  November  2022,  1.064  million  meters  had  been 
installed.  

Plan to install 1.2 million smart meters by 2026.  
110 thousand meters had been installed by October 2022. 

Full  roll-out  has  been  concluded  (residential  and  commercial  customers 
with 60A per phase). Second generation smart meters roll-out commenced 
in 2020, 15% (of total meters) had been installed by October 2022. 
Large scale roll-out in progress;  88.5% smart meters (of a total 8.4 million) 
had been installed by October 2022.  
19.65%  of  smart  meters  had  been  installed  by  Q2  2022.  Deployment  is 
ahead of schedule which foresees 80% by 2028. 
Full roll-out to be implemented by 2024.  
4.5 million meters out of 6 million (75%) had been installed by November 
2022. 

N/A  (roll-out  in 
progress) 
N/A 

N/A (decision to 
roll-out) 
N/A 
N/A 

N/A 

N/A 
N/A 

N/A 

N/A 
N/A 
N/A 

X 
X 
X 

X 
X 
X 

X 

X 

X 

130   Not applicable due to positive assessment. 
131  
132  

ESMIG data based on figures from Berg Insight Report (April 2021). 
Commission’s calculation based on information provided by Member State. 

83 

 
 
 
 
 
 
 
 
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
 
  
  
  
  
  
  
  
  
  
  
  
  
                                                 
Inconclusive 
(2013) 

SK 
Sources: ACER/CEER Market Monitoring Report (October 2022), bilateral updates by Member 

Selective  roll-out  of  431.5  thousand  smart  meters  (around  23%  of  LV 
supply points) concluded at the end of 2021.  

Planned  for  Q1 
2023 

0.0% 

X 

States and National Regulatory Authority Reports. 

Smart meter data with sufficient granularity allow consumers to have a detailed insight to their 
energy use and save energy by adapting their consumption habits, as well as to select the most 
suitable pricing contract and reduce their bills. This is also particularly important in the context of 
the current energy crisis for reducing or shifting demand, especially at critical times for the system, 
and thus avoiding expensive fossil fuel generation.  

In  Member  States  where  smart  meters  with  appropriate  functionalities  are  available,  more 
advanced pricing schemes such as dynamic price contracts or/and time-of-use tariffs are in place, 
providing the option to consumers to respond to price signals and shift their consumption from 
periods of high electricity prices to periods of cheaper electricity (price-based demand response), 
as  well  as  to  participate  in  incentive  based  demand  response  providing  for  instance  ancillary 
services to the system.  

While traditionally, consumers have had only one main supplier, this is expected to change with 
the  rollout  of  new  technologies  such  as  heat  pumps  or  electric  vehicles  and  related  charging 
infrastructure. Consumers might want to have a fixed price contract to protect themselves from 
market volatility for their basic domestic services, while for consumption that can be automatized 
such as a heat pump, they might want to combine their own generation through solar panels with 
digital  solutions  to  engage in  the energy market  and benefit  from  lower  prices  during off peak 
times. 

The roll out and uptake of demand response has been slower than desired. One of the reasons for 
this  has  been  the  very  complex  relationships  between  suppliers  and  aggregators.  The  greatest 
demand response possibilities often come from individual appliances – in particular behind-the-
meter storage, heat pumps and electric vehicles. Enabling dedicated suppliers and aggregators to 
offer  contracts  covering  just  these  appliances  could  help  both  speed  up  the  roll  out  of  these 
appliances and increase the amount of demand response in the system. The Electricity Directive 
already provides that customers are entitled to more than one supplier, but this has been seen to 
require a separate connection point increasing costs for customers significantly.  

According to a report on the potential of demand-side flexibility prepared by DNV and smartEn133 
over  70%  of  upwards  DSR  flexibility  (decrease  of  consumption)  and  over  95%  of  downwards 
DSR flexibility (increase in consumption) could be covered by electric vehicles, heat pumps and 
batteries behind the meter in 2030. 

133   Demand-side flexibility: Quantification of benefits in the EU", smartEn and DNV, 2022. Available 

here:  Demand-side flexibility: Quantification of benefits in the EU DNV 

84 

 
 
 
 
 
 
 
 
                                                 
 
 
Figure 18: Demand side response potential per technology 

Source: ’Demand-side flexibility: quantification of benefits in the EU’ (2022). 

Activation  of  this  about  120  GW  potential  may  require  in  many  cases  additional  metering  to 
provide  more  representative  data  of  energy  consumed  and  realised  by  this  units.  As  keeping 
separate  circuit  and  meter  for  this  installation may  cause  additional  costs  (additional  capex  for 
construction  and  additional  network  charges  in  case  of  energy  transfers  within  premises)  large 
portion of this potential may be lost to the system. 

o  Commission proposal 

The Commission proposes to change the current provisions of the Electricity Directive to clarify 
that customers who wish to have the right to have more than one meter (i.e. a sub-meter) installed 
in their premises and for such sub-metered consumption to be separately billed and deducted from 
the main metering and billing. 

The proposal will allow consumers to conclude a contract  with more than one supplier at their 
premises. This is to allow consumers with heat pumps and electric vehicles, using dedicated sub-
meters, to contract with different electricity suppliers and benefit from innovative electricity offers. 
Where smart meters with the appropriate functionalities are not available, alternative tools such as 
dedicated metering devices that are connected to or embedded within appliances that have flexible 
loads, can be used, as referenced in section 5.3. 

At the same time, the proposal is to avoid possible barriers such as the requirement for a separate 
grid connection for supply or restrictive rules on sub-meters (similar to those observed during the 
rollout of smart meters). 

85 

 
 
 
 
 
 
 
 
6.6.  Right to access energy through Suppliers of Last Resort 

o  State of play 

The energy crisis and several supplier bankruptcies, as discussed under section 6.3. on prudential 
supplier obligations, showed the important role of suppliers of last resort134 which are currently 
only an option in EU legislation.  

All Member States have implemented a system of supplier of last resort, either de jure or de facto. 
In all Member States but Finland and Malta, electricity supplier of last resort (SOLR) mechanisms 
safeguard customers in the case of supplier failure and guarantee continuous electricity supply. In 
some countries, SOLR mechanisms are also in place to protect inactive consumers or to further 
protect consumers struggling with paying their bills. SOLR could be incumbent suppliers or even 
DSOs.135 

However, the implementation varies significantly (in terms of scope, designation procedures, the 
role of National Regulatory Authorities, price setting mechanism, contractual conditions etc.) and 
price levels are generally higher than average prices.   

During  the  crisis,  supplier  of  last  resort  processes  underwent  a  “stress  test”,  revealing  some 
limitations. All customers were at risk of losing the right of universal service, customers suffered 
from  even  higher  prices  and  uncertainties  of  procedural  and  timing  aspects  of  SOLR  services 
besides  widespread  reluctance  of  suppliers  towards  greater  customer  acquisition  during  critical 
circumstances.  

Recent bankruptcies also indicated that the transition to a supplier of last resort was in some cases 
not very smooth and led to situations where consumers were worried that they may lose access to 
electricity. In some cases, consumers received very limited information on what happens with their 
electricity supply, which supplier they were being assigned to and what were the next steps after 
their supplier went bankrupt. 

o  Commission proposal 

To ensure continuity of supply for consumers when a supplier fails, The Commission’s proposal 
will oblige Member States to transparently appoint suppliers of last resort. The proposal aims to 

134  

In 2021, approximately 70 electricity and 60 gas supplier failures initiated the start of SOLR across Europe. 
Source: ACER-CEER Market Monitoring Report 2022 

135   Annual Report on the Results of Monitoring the Internal Electricity and Natural Gas Markets in 2021 - Energy 
here: 

and  Consumer  Protection  Volume,  ACER/CEER,  October 

Retail 
MMR_2021_Energy_Retail_Consumer_Protection_Volume.pdf (europa.eu) 

2022.  Available 

86 

 
 
 
 
 
 
 
 
                                                 
 
improve the overall concept of supplier of last resort, especially clarifying the role of the supplier 
of last resort and strengthening the information about the process when customers are switched 
onto the supplier of last resort. 

6.7. 

Price regulation as an emergency measure 

o  State of play 

The possibility during the crisis to allow Member States to cap prices for households and SMEs 
has clearly proved useful as several Member States have taken the opportunity to extend existing 
schemes or to create new one in very short timelines. Even Members States that before the crisis 
opposed to the idea of introducing some form of price setting intervention have evolved on the 
subject, during the crisis.  

87 

 
 
 
 
 
 
 
 
 
 
Table 7: Overview of the price setting intervention during the energy crisis. (Source: Commission) 

Source:  The  table  is  based  on  notifications  from  Member  States,  reporting  from  National 
Regulatory Authorities and measures self-assessed by Member States. 

In spite of the high number of price intervention schemes developed during the crisis, there are 
significant  downsides  to  regulated  prices.  In  particular,  they  can  reduce  energy  efficiency 
incentives and undermine competition to the long-term detriment of consumers. These concerns 
underline  the  normal  rules  applicable  in  the  Electricity  Directive  2019/944,  which  the  Council 
Regulation  (EU)  2022/1854  of  6  October  2022  on  an  emergency  intervention  to  address  high 
energy prices136 derogates from. If similar increases in energy prices were to occur again in the 
very short term or in spite of all the other measures to reduce exposure of consumers to short-term 

136  

EUR-Lex - 32022R1854 - EN - EUR-Lex (europa.eu) 

88 

 
 
 
 
 
 
 
 
                                                 
price  volatility,  without  specific  provision  in  the  Electricity  Directive  or  a  prolongation  of  the 
Council  Regulation (EU) 2022/1854, Member States would not be able to apply such measures.    

o  Commission proposal 

The Commission’s proposal will put in place a special derogation procedure where Member States 
can at times of emergency apply for price intervention for households and SMEs, below cost, for 
a limited volume of electricity consumption, and for a limited period of time. Under the proposal, 
the Commission will be responsible for determining the reality of the emergency situation based 
on pre-set criteria. 

Definition of the trigger of emergency 

Under the proposal, the Commission will define the possibility of activating this article when a 
regional or Union-wide price crisis is reached when the three cumulative criteria are met:  

  Very high prices in wholesale electricity markets at least two and a half times the average 
price during the previous five  years occur  which  are  expected to  continue for at  least  6 
months ;  

  Sharp  increases  in  electricity  retail  prices  of  at  least  70%  occur  which  are  expected  to 

continue for at least 6 months;  

  The wider economy is being negatively affected by the increases in electricity prices. 

 These criteria reflect the basis on which the equivalent provisions in Council Regulation (EU) 
2022/1854 of 6 October 2022 on an emergency intervention to address high energy prices were 
justified. By removing the need to propose and adopt new legislation, the Union will in the future 
be better placed to face similar situations. The Commission already monitors closely developments 
on energy markets, will be able to assess all available data to assess the need for future activation 
of  these  thresholds  (incl.  ENTSO-E  transparency  platform,  available  data  on  retail  market  by 
National  Regulators  Authorities,  Eurostat  data…).  In  doing  so  it  will  of course  also  be  able  to 
engage closely with Member States and national authorities. 

Definition of the consumption threshold 

Regulated prices are effective in lowering the price of energy faced by end consumers – however, 
they  have  several  potential  negative  consequences.  Below  cost  regulated  prices  can  end  up 
encouraging  energy  use  –  and  subsidising  high  consumption  (the  example  is  often  given  of 
subsidising heating swimming pools). This is the opposite of what is needed in an energy crisis. 
Another negative impact is compensating suppliers for supplying below cost can put strain on the 
public budget. A cap on the consumption covered mitigates both of these impacts.  

89 

 
 
 
 
 
 
 
 
The  Council,  in  its  2023  recommendation  on  the  economic  policy  of  the  euro  area137  then 
recommend to “replace broad-based price measures with a cost-efficient two-tier energy pricing 
that ensures incentives for energy savings.”  

The  Commission’s  proposal  reflects  this  approach  and  restricts  regulated  prices  to  80%  of  the 
median consumption for households and to 70% of historical consumption for SMEs, in line with 
Temporary  Crisis  Framework138.  This  will  give  the  opportunity  to  keep  incentive  for  demand 
reduction.  The  approach  based  on  consumption  ceilings,  allowing  a  price  signal  for  demand 
reduction is already implemented in several Member States schemes.139 

Increased protection from electricity disconnection for vulnerable customers and 

6.8. 
energy poor  

o  State of play 

The energy crisis has exposed already energy poor and vulnerable consumers across the internal 
market  to  additional  higher  energy  costs,  further  eroding  their  ability  to  continue  paying  their 
energy  bills.  In  spite  of  the  unprecedented  and  costly  support  measures  that  have  been  made 
available across the EU, many vulnerable families are facing a stark choice between paying for 
their energy and buying other essentials or falling into debt and risk seeing their supply cut off. 
Civil society organisations active on the ground have been warning that the majority who do not 
pay are those who have the greatest difficulty140. 

Protection from disconnections exists in the Electricity Directive. It is referred implicitly in Article 
28(1)  in  relation  to  obligation  to  define  vulnerable  customers.  In  general,  Member  States  have 
established disconnections from electricity due to non-payment to protect vulnerable households 
on  specific  days  (e.g.,  weekends),  seasons  (e.g.,  winter  truce,  summer  truce)  or  specific 
circumstances (e.g., consumers critically depending on electricity for life-supporting appliances). 
A few countries do not apply any “truce” for disconnections, but rather use period of reminders to 
avoid disconnections. Overall, it is not in the interest of the supplier to disconnect a customer for 
debt, which would be an additional cost, but to retain it at least until the point of full repayment. 

At the same time, Article 10(11) requires that electricity suppliers provide all household consumers 
with adequate information on alternative and appropriate measures to disconnection, sufficiently 
in  advance  of  any  disconnection  due  to  non-payment,  such  as  payment  plans,  assistance  from 

2023 Euro area recommendation (europa.eu) 
EUR-Lex - 52022XC1109(01) - EN - EUR-Lex (europa.eu) 

137  
138  
139   AT, HR, NL, DE, RO 
140  

BEUC-X-2022-106_Letter_Introducing_moratoria_in_the_energy_and_financial_sectors.pdf; 
https://righttoenergy.org/wp-content/uploads/2022/03/Gas-crisis_-Civil-Society-Response.pdf. 

90 

 
 
 
 
 
 
 
 
 
                                                 
social  services,  energy  efficiency  advice  and  financial  support  to  manage  their  energy  use  and 
costs, alternative supply contracts and any other alternatives to counter disconnection, including 
disconnection  moratoriums  and  bans.  It  has  to  be  acknowledged  that  the  way  in  which 
communication is approached has an impact on encouraging a vulnerable customer to engage with 
the process, due to additional cultural and social barriers.  

However, there seems to be a risk that the interpretation and practical implementation of these 
provisions  may  lead  to  uneven  outcomes  across  Member  States,  with  regard  to  the  level  of 
consumer protection and support available for the most vulnerable. Evidence in the last Retail and 
Consumer Protection Market Monitoring Report published by ACER and CEER141 confirms this 
preliminary  assessment. To give an example:  there is  a considerable variation in  disconnection 
duration  in  electricity  across  Member  States,  with  reminders  and  warnings  ranging  from 
approximately two weeks (10 working days) to nine weeks (see Figure 19 below). It is commonly 
understood that a lengthier disconnection process increases the likelihood of payment or allows 
customers to seek alternatives.  

Figure 19: Legal minimum duration of the electricity disconnection process in EU MSs, Great 
Britain and Norway – 2021 (Number of working days). 

Source: ACER-CEER, Annual  Report on the Results of Monitoring the Internal Electricity and 
Natural Gas Markets in 2021 Energy Retail and Consumer Protection Volume. 

141https://www.acer.europa.eu/sites/default/files/documents/Publications/MMR_2021_Energy_Retail_Consumer_Pr
otection_Volume.pdf. 

91 

 
 
 
 
 
 
 
 
                                                 
Article  59  of  the  Electricity  Directive  requires  national  regulators  (NRAs)  to  monitor,  among 
others, disconnection rates. However, based on the most recent figures in the ACER Retail and 
Consumer Protection Market Monitoring Report142, it should be noted that disconnection rates due 
to non-payment among household customers are currently only reported by a minority of NRAs.. 
Besides, the responses to the public  consultation  suggest  that further  clarity and reassurance is 
needed  on  the  framework  in  place  for  protection  from  electricity  disconnection  for  vulnerable 
customers.  

Along these considerations, on 12 December 2022, the Commission facilitated the signing of a 
Joint  Declaration  to  enhance  the  protection  of  all  consumers  during  this  winter143  by  key 
stakeholders,  representing  consumers,  regulators  and  energy  suppliers  and  distributors,  who 
committed to taking a series of voluntary measures, including not to disconnect the particularly 
vulnerable. This initiative reflects the willingness of key stakeholders to take their part, in close 
cooperation, and sets out the grounds for the need and scope for further action. 

o  Commission proposal 

The Commission’s proposal will require Member States to take all appropriate steps to ensure that 
the most vulnerable of EU citizens are adequately protected from disconnection at least at “critical 
times”, period to be defined according to national circumstances. This initiative comes from the 
recognition of the need for increased efforts and greater social cohesion at critical time of response. 

Enhance the transparency of the energy market and protection against 

7.  
market manipulation 

Feedback from public consultation 

  Most  of  the  respondents,  including  private  companies,  business  associations,  market 
operators and national authorities, agree on the need to extend the scope of REMIT by 
adapting the framework to the evolving market circumstances to cover all current and 
future markets  and products,  specifically to all of those referred in  the EU wholesale 
energy  legal  framework.  The  majority  of  TSOs,  some  market  operators  and  business 
associations  are  in  favour  of  clarifying  and  updating  definitions  of  wholesale  energy 
markets and wholesale energy products. Additionally, the need to clarify the notions of 
market  manipulation,  insider  information  and  insider  trading,  to  be  coherent  to  those 
included in financial regulations was highlighted. 

142   ACER-CEER, Annual Report on the Results of Monitoring the Internal Electricity and Natural Gas Markets 

in 2021 - Energy Retail and Consumer Protection Volume 
https://energy.ec.europa.eu/declaration-enhanced-consumer-protection-winter_en. 

143  

92 

 
 
 
 
 
 
 
 
 
                                                 
  Some  regulators  argue  that  the  supervision  task  performed  over  PPATs  could  be 
harmonised and reinforced by enlarging the supervision scope. It was often highlighted 
that the REMIT framework could benefit as well from extending its cooperation duties 
to other regulatory bodies such as national tax authorities, the European Securities and 
Markets  Authority  (ESMA),  the  EUROFISC  group  or  other  bodies  including  the 
European  Commission  by  exchanging  information  and  data  or  forming  investigation 
groups. 

  Various  respondents,  especially  the  national/local  authorities  as  well  as  some  private 
organisations believe that the current cross-border supervision is not effective enough; 
therefore, ACER’s role could be enhanced in those cases involving multiple cross-border 
participants since it is best positioned to monitor cross-border issues at European level. 
Some  respondents,  including  regulatory  bodies,  business  associations  and  market 
operators, think that the REMIT framework should correct discrepancies among Member 
States  by  harmonising  administrative  and  penalty  sanctions  applied  by  the  NRAs  at 
national level by applying a common regime in the EU. 

  Lastly,  there  is  also  a  strong  support  from  many  stakeholders  on  the  fact  that  ACER 

should have power and duty to issue binding guidance. 

7.1.  

Introduction 

Regulation  1227/2011  on  wholesale  market  integrity  and  transparency  (‘REMIT’)  ensures  that 
consumers and other market participants can have confidence in the integrity of  electricity and 
natural gas markets, that prices reflect a fair and competitive interplay between supply and demand, 
and that no profits can be drawn from market abuse. The current context of high prices and high 
volatility on the wholesale energy markets and the unprecedented changes observed in the ways 
of trading (e.g., the rise of high frequency trading) constitute an important argument to revise the 
existing legislative framework. In case of no actions and lack of REMIT enhancement, the Union 
and Member States are not sufficiently equipped to protect the wholesale energy markets against 
market abuse. 

There  is  therefore  a  need  to  urgently  ensure  that  REMIT  framework  is  up  to  date  and  robust. 
Further  improvements  would  increase  transparency,  monitoring  capacities  and  ensure  more 
effective investigation and enforcement of cross-border cases in the EU to support new electricity 
market design. 

93 

 
 
 
 
 
 
 
 
 
 
 
o  Status quo: How does REMIT work? 

The scope of REMIT was designed over a decade ago to accommodate the operational complexity 
of physical energy markets and specificities of the energy sector (electricity and natural gas) and 
to appropriately complement the market  abuse legislation covering the financial sector.  Market 
abuse  covers  market  manipulation  and  insider  trading.  REMIT  prohibits  market  participants  to 
engage  in  or  attempt  market  manipulation.  This  includes  entering  into  false  or  misleading 
transactions, positioning the price at an artificial level, transactions involving fictitious devices or 
deception,  and  the  dissemination  of  false  or  misleading  information.  REMIT  further  obliges 
market participants to publicly disclose their inside information and prohibits using or disclosing 
inside  information  or  recommending  other  persons  to  use  inside  information  –  with  few  strict 
exemptions. 

REMIT applies to ‘wholesale energy products’. It includes (i) contracts for the supply of electricity 
or natural gas where delivery is in the Union; (ii) derivatives relating to electricity or natural gas 
produced, traded or delivered in the Union; (iii) contracts relating to the transportation of electricity 
or natural gas in the Union; (iv) derivatives relating to the transportation of electricity or natural 
gas in the Union. However, contracts for green certificates and emission allowances do not fall 
under REMIT. 

Wholesale energy products are traded in the ‘wholesale energy markets’ which means any market 
within  the  Union  on  which  wholesale  energy  products  are  traded.  Wholesale  energy  markets 
encompass both commodity markets and derivative markets, which are of vital importance to the 
energy and financial markets, as price formation in both is interlinked.  

Market participants have to report all wholesale energy market transactions at EU level to ACER. 
ACER is legally mandated to collect all relevant trading data in wholesale energy markets and to 
monitor the European wholesale energy markets (electricity and natural gas). 

When a REMIT breach is found in EU wholesale energy markets, the final enforcement decision 
of  such  a  breach  lies  with  the  relevant  regulatory  authority.  ACER  facilitates  the  delivery  of 
consistent decisions at European level from the regulatory authorities, by coordinating the follow-
up  of  any  possible  REMIT  breach.  ACER  also  coordinates  with  the  European  Securities  and 
Market Authority (ESMA), financial authorities, competition and other relevant authorities. ACER 
has, however, no powers to conduct investigations. 

o  Why is reform necessary?  

Gaps in REMIT data as well as a lack of enforcement of reporting obligation on the EU level are 
resulting in monitoring framework that is not sufficiently robust to fully protect against market 
abuse on the EU wholesale energy market into the future. Moreover, the decentralised enforcement 
system based on national investigations is not efficient in more complex cross-border cases which 
can result in insufficient market surveillance and oversight. 

94 

 
 
 
 
 
 
 
Data collection, enforcement of reporting and market monitoring 

There are various inconsistencies in the definitions of market abuse as well as for other definitions 
between  REMIT  and  the  EU  financial  market  legislation.  These  inconsistencies  cannot  be 
explained  by  the  specificity  of  wholesale  energy  products.  For  instance,  while  MAR  defines 
market  manipulation  as  the  fact  of  entering  into  any  transaction,  issuing  any  order  to  trade  or 
entering into any other behaviour that can give false or misleading signals or set the price at an 
artificial level, the REMIT definition of market manipulation focuses on transactions and orders. 
The  category  ‘or  any  other  behaviour’  is  missing  from  the  REMIT  definition,  what  prevents 
REMIT from capturing certain behaviours such as capacity withholding, which by definition do 
not involve any order or transaction on the market. Moreover, there is no effective framework to 
disclose inside information. 

Moreover,  under  the  current  REMIT  framework,  ACER’s  supervisory  powers  over  Registered 
Reporting  Mechanisms  (RRMs)  are  very  limited  having  a  negative  impact  on  integrity  and 
transparency of the EU wholesale energy. The quality of the data that ACER receives and uses to 
fulfil its mandate of monitoring the EU wholesale energy markets in order to detect possible market 
abuse  is  in  question.  Article  8  of  REMIT,  in  connection  with  Article  11(1)  of  the  REMIT 
Implementing Regulation144, provide for the obligation for reporting parties to register with ACER 
for reporting purposes. In 2022, approximately 17 different non-compliance events (categories) 
have been identified. Altogether around 80 potential non-compliance issues had been detected. In 
effect, potential non-compliance issues have been opened for around 30 RRMs. 

According to Article 15 of REMIT, persons professionally arranging transactions (PPATs) shall 
notify  to  regulatory  authorities  their  suspicions  of  market  abuse.  They  shall  also  establish  and 
maintain effective arrangements and procedures to identify market abuse. Around 44% of the total 
number of active PPATs arrange transactions on products for delivery in multiple Member States 
(there are in total 48 PPATs arranging transactions in more than one country). Their oversight and 
the enforcement under Article 15 of REMIT proved to be very complicated and inefficient, due to 
the fact that: (i) the regulatory authority of the Member State where the PPAT is established has 
no  incentive  in  supervising  if  the  PPAT  complied  with  its  Article  15  obligations  in  relation  to 
products  for  delivery  in  another  Member  State  and  (ii)  the  regulatory  authority  of  this  other 
Member State has no jurisdiction over a PPAT not established on its territory.  In 2021, only 12 
PPATs were submitting suspicious transaction reports (STRs) to NRAs. These 12 PPATs notified 
81 out of the 129 STRs received in 2021. Overall, only about 10% of the PPATs submit STRs to 
NRAs. Improving the supervision of PPATs is crucial to ensure that all of them put arrangements 
in place to effectively monitor their market and to detect and report market abuse to NRAs and 
ACER. 

144  

Commission  Implementing  Regulation  (EU)  No  1348/2014  of  17  December  2014  on  data  reporting 
implementing Article 8(2) and Article 8(6) of Regulation (EU) No 1227/2011 of the European Parliament and 
of the Council on wholesale energy market integrity and transparency Text with EEA relevance 

95 

 
 
 
 
 
 
 
                                                 
The recent energy crisis showed that timely and efficient information exchange between relevant 
authorities is of utmost importance to supervise and monitor markets. The Commission is currently 
not included in the potential sharing of REMIT information, but the energy crisis has demonstrated 
that it would benefit from ACER’s REMIT information to increase market insights. In addition, 
information exchange between national competent authorities under Regulation (EU) No 596/2014 
on market  abuse and national regulatory authorities is  supposed to  take place at  national  level, 
whilst  information  sharing  under  REMIT  with  relevant  national  authorities  is  exclusively 
mandated  to  ACER.  This  creates  inefficiencies  in  the  cooperation  of  competent  authorities  at 
national  level.  Therefore,  all  burdens  for  data  sharing  possibilities  between  relevant  national 
authorities, ACER and the Commission should be reduced. 

Moreover, the increasing share of financial instruments traded on EU energy markets also calls for 
a stronger cooperation between energy and financial regulators, including ACER and ESMA. 

Finally, with the diversification of EU natural gas supply in the aftermath of Russian invasion of 
Ukraine, and in line with the REPowerEU plan, the EU’s LNG market has grown in importance. 
Over  the  last  months,  LNG  has  become  critical  in  ensuring  gas  security  of  supply  in  the  EU, 
replacing most of Russia’s supply of pipeline gas (which represented 40% of the total imports at 
the start of 2022 and now is below 10%). However, the pricing of LNG imports within the EU 
could still be unduly influenced by existing infrastructure bottlenecks and questions remain as to 
the representativeness of the current indexes. At the same time, perceptions of malfunctioning in 
the financial markets for energy undermine public trust. 

In conclusion, gaps in data, lack of data reporting enforcement and outdated scope of data coverage 
calls for urgent improvements in order to strengthen Union and Members States’ ability to monitor 
and efficiently supervise wholesale energy market. High quality and complete data constitutes a 
fundamental  requirement  for  effective  protection  against  market  abuse  cases,  especially  during 
crises.  

Investigations and enforcement of REMIT breach cases  

The shortcomings identified in the current framework mostly relate to the decentralised model. 
While ACER is in charge of monitoring wholesale energy markets at EU level, any investigatory 
and enforcement powers lie at national level and hence regulatory authorities have full discretion 
on  whether  to  follow-up  on  a  suspicious  reporting  by  ACER’s  market  surveillance.  This 
decentralised approach leads to the following consequences:  

jurisdictional  gaps,  rendering  REMIT 

o  The diversity of ways in which REMIT was implemented at  national  level  is  at  the 
origin  of 
inapplicable  under  certain 
circumstances  and/or  to  certain  behaviours.  On  this  matter,  ACER  estimates  that  at 
least  10%  of  all  closed  cases  were  closed  because  of  a  lack  of  investigatory  or 
sanctioning powers by the NRAs; 

96 

 
 
 
 
 
 
 
o  Regulatory authorities have been allocated uneven resources across Member States and 
national procedural rules further restrict their competence, which leads to the under-
enforcement of REMIT; 

o  A  need for  prioritisation  makes NRAs favour cases of national  nature over those of 
cross-border nature. This claim is supported by the statistics reported in Figure 21 and 
Figure 22 that illustrate the percentage of national and cross-border cases that reached 
the investigation stage, and the percentage of national and cross-border cases that led 
to a sanction; 

o  Individual  NRAs  are  not  well  equipped  to  handle  cases  of  a  multi-market  or  cross-
border dimension, and their enforcement actions focusing on national effects only are 
limited by nature. 

Figure 20: Percentage of cases that reached the investigation stage 

Source: ACER’s Case Management Tool – Business Intelligence (2022) 

Figure 21: Percentage of cases that led to a sanction 

Source: ACER’s Case Management Tool – Business Intelligence (2022) 

97 

 
 
 
 
 
 
 
  
 
 
              
  
In conclusion, significant  shortcomings  in  the investigation and enforcement system  require an 
urgent change,  the justification of which became even more obvious with the energy crisis, to 
ensure that all suspicious behaviours can be quickly investigated and penalised, where necessary. 

Fines set by national regulatory authorities 

REMIT is  not  prescriptive as to  the level  of the  fines that regulatory authorities can impose at 
national  level  to  sanction  a  REMIT  breach.  The  implementation  of  REMIT  at  national  level 
resulted in discrepancies between the sanctioning practices of Member States. It notably raises the 
issue of the maximum  amount of the fine that the regulatory  authority  can issue as a sanction, 
which  is  insignificant  in  some  Member  States,  and  therefore  not  a  deterrent.  For  example,  the 
maximum  amount  of  the  pecuniary  sanction  for  a  breach  of  the  obligation  to  disclose  inside 
information  can reach up to  8% of the total  turnover of the market  participant in  one  Member 
States, when it is only 10,000 EUR in another.  

The actual deterrence and effectiveness of sanctions issued by regulatory authorities is at stake.  

In  conclusion,  urgent  action  is  required  to  strengthen  and  harmonise  the  sanctions  regime  at 
national level to ensure that illegal behaviours on energy market, if identified and confirmed, can 
be effectively and proportionally penalised. 

7.2.   Better data collection and market monitoring 

Adaptation of the scope of REMIT to current and evolving market circumstances  

Due to further integration of the EU energy market, it is beneficial to extend the scope of data 
reporting to new electricity balancing markets and coupled markets as well algorithmic trading. 
Market coupling and the use of algorithmic trading over recent years have led to an increase of 
85% of collected data to 4.4 billion records collected in 2022 alone.  

Considering  the  existing  interlinkages  in  terms  of  market  impact  between  spot  and  derivative 
wholesale energy products, there is a need for stronger, more established and regular cooperation 
between energy and financial regulators, including ACER and ESMA. 

As an immediate follow-up for the amendment of REMIT Regulation 2011, there is also a need to 
revise REMIT Implementing Regulation from 2015 to ensure consistency with the new measures 
and provisions in the amended REMIT Regulation. Any changes in the electricity market design, 
but  also  the  intended  scope  increase  to  hydrogen  markets  in  the  Hydrogen  and  Gas 
Decarbonisation Package and LNG market developments as a result of the increased importance 
of LNG trading need to be reflected in the REMIT Implementing Regulation in order to have a 
meaningful data collection for market monitoring purposes.  

98 

 
 
 
 
 
 
 
 
In addition, order book providers should be fully subject to the reporting obligations under Article 
8  of  REMIT,  and  the  reporting  needs  to  happen  in  a  consolidated  manner  at  EU  level.  It  is 
necessary to cover explicitly the order book providers such as the operators of the single day-ahead 
market coupling, the intraday market coupling and the EU balancing platforms to ensure better 
market transparency and enhance market monitoring. 

Improving process for the collection of inside information and market transparency  

It is necessary to align the process for the collection of inside information to the one existing for 
collecting trade data reporting in order to facilitate monitoring to detect potential trading based on 
inside information and the data quality of collected information. Inside information is currently 
relying on web feeds. This does not allow to make use of the data quality rules in the collection of 
inside information and instead requires handling data quality of inside information collected from 
15 Inside Information Platforms manually. Hence, to strengthen the transparency of EU wholesale 
energy markets, it is necessary to further streamline mandatory disclosure of inside information by 
market participants through platforms. In order to ensure a level playing field of inside information 
platforms at EU level and their continuous reliability, ACER should have supervisory powers over 
them and assess their compliance with relevant technical standards to which these platforms should 
adhere. 

Moreover, a centralised, more robust and coordinated monitoring of wholesale energy markets by 
extending  the  notification  obligation  also  towards  ACER  would  bring  additional  benefits  for 
transparency of the market. 

It is of utmost importance to ensure robust enforcement of data reporting in order to monitor the 
energy  market.  Financial  regulation  and  ESMA  powers  could  serve  as  a  blueprint  and  best 
practices should be used as well for the energy market. 

The REMIT Regulation applies to trading in wholesale energy products.  It is without prejudice to 
the application of  Regulation (EU) No 600/2014145, Directive 2014/65/EU146 and Regulation (EU) 
No  648/2012  147  as  regards  activities  involving  financial  instruments  as  defined  under  Article 
4(1)(15) of Directive (EU) 2014/65 as well as to the application of European competition law to 
the practices covered by this Regulation. 

145  

Regulation (EU) No 600/2014 of the European Parliament and of the Council of 15 May 2014 on markets in 
financial instruments https://eur-lex.europa.eu/legal-content/EN/TXT/?uri=celex%3A32014R0600  

146   Directive 2014/65/EU of the European Parliament and of the Council of 15 May 2014 on markets in financial 

147  

instruments https://eur-lex.europa.eu/legal-content/EN/TXT/?uri=celex%3A32014L0065  
Regulation (EU) No 648/2012 of the European Parliament and of the Council of 4 July 2012 on OTC 
derivatives, central counterparties and trade repositories https://eur-lex.europa.eu/legal-
content/EN/TXT/?uri=CELEX%3A32012R0648  

99 

 
 
 
 
 
 
 
  
                                                 
Enhance supervision of reporting parties and data sharing 

To  better  monitor  the  wholesale  energy  market,  ACER  should  be  equipped  with  additional 
supervisory tools such as the improvement of the supervision of the compliance with the reporting 
obligations  at  EU  level.  It  is  equally  important  to  better  supervise  Registered  Reporting 
Mechanisms  (RRMs)  and  to  ensure  that  ACER  can  take  administrative  sanctions  for  potential 
breaches of the REMIT reporting obligation defined in Article 8 of REMIT, including supervisory 
powers  accompanied  with  the  possibility  to  adopt  administrative  sanctions  and  other 
administrative measures.   

Last  but  not  least,  it is  beneficial to  allow  and facilitate the exchange of  REMIT data between 
relevant  national  authorities  (e.g.,  tax  authorities),  ACER  and  the  Commission.  This  would 
increase the coordination between relevant public authorities and allow acting faster and in more 
informed manner. 

Enhance supervision of persons professionally arranging transactions (PPATs) 

The effective application of Article 15 of REMIT requires that PPATs are obliged to notify their 
suspicions to ACER as well as to the regulatory authorities, and not only exclusively to NRAs. 
Furthermore,  ACER  should  have  supervisory  and  enforcement  powers  over  PPATs  arranging 
transactions in at least three Member States, to palliate the lack of enforcement of Article 15 by 
NRAs. 

Enhance market transparency through an LNG price assessment and benchmark 

Given the need to provide for stable and predictable pricing for LNG imports on a structural basis, 
which  are  indispensable  to  ensure  a  continuous  supply  of  gas  to  Europe,  Council  Regulation 
2022/2576148 established, a daily LNG price assessment and LNG benchmark. It tasked ACER to 
create within a short time frame an objective price assessment tool on the physical deliveries of 
LNG  into  the  Union,  and  over  time  a  benchmark,149  on  a  daily  basis,  whereas  the  LNG  price 
benchmark will be published as of 31 March 2023.  

In  line  with  the  commitment  taken  upon  adoption  of  the  Council  Regulation  the  current 
amendment  of  the  REMIT  Regulation  should  establish  the  LNG  price  assessment  and  LNG 
benchmark as a permanent element of REMIT framework. 

148  

149  

Council Regulation 2022/2576, of 19 December 2022, enhancing solidarity through better coordination of gas 
purchases, reliable price benchmarks and exchanges of gas across borders 
https://aegis.acer.europa.eu/terminal/price_assessments 

100 

 
 
 
 
 
 
 
 
                                                 
Strengthening of investigation, harmonisation of fines to better protect against market 

7.3. 
abuse 

Stronger role for ACER in investigations of significant cross-border REMIT cases 

REMIT would  benefit from  a better alignment of its definitions  of market  abuse with  the ones 
existing under the financial legislation. These alignments would ease the applicability hence the 
efficiency of the REMIT framework. 

The  exercise  of  investigatory  powers  for  cross-border  cases  at  EU  level  would  bring  an  added 
value. ACER is already in charge of monitoring of the EU wholesale energy market, therefore it 
is best placed to perform investigations to deal with certain selected cases while maintaining the 
role  for  regulatory  authorities  in  remaining  cases.    The  cases  over  which  ACER  should  have 
jurisdiction for investigation are those where: 

- 
- 

- 

- 

at least three products delivered in different Member States are affected; 
two or more products delivered in different Member States are affected and the legal or 
natural person carrying out the acts is registered or established in a third Member State or 
outside the EU; 
the REMIT information considered is likely to significantly affect the prices of wholesale 
energy products for delivery or potential delivery in at least three Member States; or 
the NRA does not take the necessary measures in a timely manner to comply with a request 
to open an investigation from the Agency under Article 16(4)(b). 

In exercising its powers, the Agency shall take into account the inspections in progress or already 
carried out in respect of the same cases by a regulatory authority pursuant to this Regulation as 
well as the cross-border impact of the investigation. 

On completion of its actions,  ACER  should draw up a report which should  be made public.  If 
ACER  concludes  that  the  breach  of  this  Regulation  took  place,  it  shall  inform  the  regulatory 
authorities of the Member State or Member States concerned accordingly and require that such a 
breach is dealt under REMIT.  

Figure 22 below displays the evolution of cases with cross border elements and the evolution of 
the  cases  that  would  fall  under  ACER’s  jurisdiction  according  to  the  envisaged  new  ACER 
competences. 

101 

 
 
 
 
 
 
 
 
 
Figure 22: Evolution of the stock of REMIT cases over time       

Source: ACER data (until 2022). Estimates from 2023 based on evolution in the previous years 

and DG COMP performance parameters. 

At the end of 2022, there were 15 open REMIT cases that would fulfil above mentioned criteria 
(around 4.3% of the total stock of cases), 11 of which were notified in 2022. The growth in the 
number of cross border cases that will eventually meet these criteria is substantial higher than the 
general growth in the number of REMIT breach cases (last 6 years: 20% vs 7.7%). 

Harmonisation of fines set by regulatory authorities at national level 

Having  converging  levels  of  fines  at  EU  level  is  an  important  element  of  the  efficient 
implementation  and  enforcement  of  the  REMIT  framework.  Therefore,  it  is  necessary  to 
harmonise  the  level  of  fines  that  can  be  imposed  at  national  level  by  indicating  a  minimum 
threshold  for  the  maximum  administrative  pecuniary  sanctions  per  type  of  REMIT  breach. 
Harmonisation shall be set to ensure the deterrence, proportionality and effectiveness of sanctions. 

8.  Generation and system adequacy for a decarbonised electricity system 

8.1.   Generation adequacy and Capacity Mechanisms 

Feedback from public consultation 

On the topic of how to further accelerate the deployment of renewables, a broad majority of 
stakeholders mentioned that speeding up permitting procedures, boosting flexibility and fully 

102 

 
 
 
 
 
 
 
                     
 
 
 
 
 
implementing  the  existing  legislation  would  make  a  significant  impact.  Furthermore,  the 
importance  of  necessary  grid  investments  (including  the  deployment  of  more  flexibility)  to 
overcome current bottlenecks and facilitate more connection capacities was widely mentioned. 
The usefulness of identifying ‘renewable go-to-areas’ and efforts to improve public acceptance 
were also mentioned. 

Most of the respondents acknowledge that the power system has evolved into a system with a 
higher  amount  of  renewable  generation  capacity.  Some  consider  that  Capacity  Mechanisms 
should be treated as a permanent feature of the European energy market to ensure that firm and 
reliable  capacity  is  made  available  to  support  the  increasing  penetration  of  intermittent  RES 
capacities. 

A majority of respondents have noted that the current regulatory framework applies strict pre-
requisites  for  the  introduction  of  a  Capacity  Mechanism  and  that  the  approval  process  is 
cumbersome  and  lengthy.  They  call  on  the  Commission  to  facilitate  Member  States' 
introduction  or  amendment  of  capacity  mechanisms  through  faster  and  clearer  approval 
processes.  Many would like a clear, harmonised framework at EU level on capacity mechanisms 
to  grant  visibility  and stability to  investors.  In contrast,  other stakeholders (especially TSOs) 
have  suggested  shifting  the  decision-making  process  around  Capacity  Mechanisms  to  the 
national authorities. 

On the adequacy assessment, many stakeholders have argued that the responsibility to assess 
the  necessity  of  a  capacity  mechanism  should  lie  with  the  Member  States.  They  invite  the 
Commission to reconsider the role of national adequacy assessments as complementary to the 
ERAA, since they provide more granular and dedicated sensitivities. They ask for a review of 
the ERAA approval process, with a strengthened role of Member States.  

Unlike some Member States that have advocated for the expansion of the capacity market access 
for the most emission-heavy generators, a large majority of stakeholders have suggested to align 
capacity mechanisms with climate neutrality objectives and to favour the participation of fossil-
free  technologies.  They  suggest  that  the  Commission  reviews  and  decreases  the  current 
emissions  threshold  in  order  to  accelerate  decarbonisation  of  the  power  system  and  to  avoid 
lock-in effects of fossil fuel technologies. 

Most respondents have argued that the current capacity mechanism set-up does not drive the 
necessary investments to demand-side and storage technologies. For a flexible, decarbonised 
grid,  they  recommend  capacity  mechanisms  to  be  market-based  in  order  to  increase 
competitiveness and remove barriers to ensuring the participation of all resources.  

As outlined in previous sections, to reach net-zero by 2050, and the 2030 and 2040 targets before 
then, a substantial increase in investments in our energy system is needed. These investments will 

103 

 
 
 
 
 
 
 
 
not just be in renewable energy but also in the enabling technology and infrastructure. Technology 
advancement and a dynamic and competitive European energy sector will be crucial to these goals. 
Public policy can support this shift and create certainty on the direction of travel for our European 
businesses and manufacturing sector.   

This  is  because  the  energy  system  is  becoming  more  complex  and  future  looking.  Regarding 
infrastructure, TSOs and DSOs should account for long-term needs, such as meshed offshore grids 
based on hybrid interconnectors, smart electricity grids enabling market-based demand response 
and  energy  communities,  and  streamlined  permitting  regulatory  frameworks  for  renewables, 
including go-to renewable areas. National regulatory authorities should increasingly promote the 
development  of  grids  that  consider  the  medium  and  long-term  system  needs  and  be  fully 
transparent  about  capacities  available  for  new  connections.  Grids  are  typically  financed  via 
network  tariffs,  complemented  with  congestion  income  for  cross-border  transmission  projects. 
Transmission  and  distribution  network  tariffs  should  be  regularly  updated  to  account  for  the 
changing energy system and increasingly active role of distribution system operators. In addition 
to  considering  operational  expenditures  as  outlined  in  Section  5.2,  other  relevant  aspects  that 
NRAs should review when setting network tariffs or their methodologies, for example, are how 
they  set  long  term  incentives,  for  example  to  shift  peak  demand  and  support  technologies  that 
increase  the  efficiency  and  operability  of  the  grids.  This,  in  turn,  would  support  consumers  in 
having a more resilient energy system at affordable prices. To alleviate part of the impact that the 
substantial grid investment might trigger on electricity consumers, Member States may want to 
make use of public budgets150. 

Moreover, the smarter use of our overall energy system architecture and the increasing rollout of 
energy efficiency measures throughout the EU will serve to use our grids as efficiently as possible 
and also reduce or shift electricity consumption peaks. This, in turn will integrate renewables fully 
into  the  grid  and  reduce  the  amount  of  dispatchable  capacity  needed  for  when  the  wind  is  not 
blowing or the sun is not shining. 

In  addition  to  the  long-term  contractual  support  for  investments  in  renewables  discussed  in 
previous sections, the Commission is aware that lengthy permitting procedures and the availability 
of connection agreements are among the biggest challenges faced by renewables developers. The 
Commission  fully  supports  faster  permitting  procedures.  On  the  issue  of  grid  connections,  the 
Commission proposes greater transparency from TSOs and DSOs on the availability of connection 
capacity.  

However, it is also the case that for the foreseeable future, fossil-fuel based dispatchable capacity 
will be needed to meet peak demand and ensure security of supply. We have seen, in particular, in 
the last 10 years that the number of hours that fossil fuel generation runs in the market is decreasing 
all  the  time.  As  noted  in  section  1.2,  this  trend  is  expected  to  continue  with  higher  levels  of 

150  

See Guidelines on State aid for climate, environmental protection and energy 2022 (2022/C 80/01), chapter 4.9 

104 

 
 
 
 
 
 
 
                                                 
renewables  penetration  and  increasing  competition  from  demand  side  response  and  storage 
pushing  out  fossil  fuel  technologies.  For  the  moment,  however,  certain  amounts  are  needed  to 
ensure generation adequacy and security of electricity supply. Capacity Mechanisms have been 
introduced  in  several  EU  countries  to  give  more  revenue  predictability  and  ensure  security  of 
supply, enabling Member States under certain conditions, to provide subsidies to power generators 
and  other  technologies,  such  as  demand  response  and  storage.  These  mechanisms  can  play  an 
important  role  in  ensuring  the  adequacy  of  the  electricity  system  and  foster  investments  in  the 
capacity  needed  to  complement  the  deployment  of  intermittent  renewables  installations,  the 
production of which is weather dependent.  

As they can have a significant impact on the internal electricity market and because the costs of 
these mechanisms are paid by electricity consumers, the Clean Energy Package introduced, for the 
first  time,  a  framework  at  European  level  to  govern  capacity  mechanisms.  To  ensure  that  the 
internal market level-playing field is preserved, the legislative framework prescribes that subsidies 
are granted only when an adequacy issue exists or will arise in the future. Moreover, the current 
legislation also mandates that capacity is procured in a competitive auction open to all providers 
that  can  contribute  to  ensure  security  of  supply.  This  reduces  the  costs  for  consumers,  fosters 
competition,  and  ensures  investments  in  new  capacity,  including  demand  response  and  storage 
which have been coming forward more and more through these auctions across Member States151.  

The Electricity Regulation allows Member States to set technical performance standards and CO2 
emissions’  limits  that  restrict  participation  in  these  mechanisms  to  flexible,  fossil-free 
technologies152. The recently revised State aid  rules go  a step further: they encourage Member 
States to introduce green criteria in capacity mechanisms and contain stricter rules for the approval 
of subsidies to coal and gas-fired power plants. This enables Member States to design green and 
flexible  capacity  mechanisms,  and  support  investments  into  low  carbon  technologies.  The 
Commission proposes to clarify this in the amending Regulation with a Recital explaining how the 
Regulation and State-Aid Guidelines can be read together to design a green and flexible capacity 
mechanism.  

In  addition,  from  discussions  with  Member  States  and  stakeholders  as  part  of  the  public 
consultation, it is clear that the procedure for the adoption of capacity mechanisms is perceived as 
being burdensome and lengthy. It is often the case that discussions in the State aid approval process 
tend to focus on the need for the capacity mechanism. The introduction of a capacity mechanism 
is  subject  to  the  identification  of  an  adequacy  concern  in  the  European  resource  adequacy 
assessment (ERAA) and in the national resource adequacy assessment (NRAA). Both assessments 
must be based on the ERAA methodology and are the subject of an ACER opinion. According to 

151  
For example, 1.5GW of demand response came forward in the recent auction in Poland in January 2023. 
152   As of 2025, coal-fired power plants that still operate in the market are no longer able to receive subsidies under 
capacity mechanisms due to the emissions limit in Article 22 of the Regulation. Member States may go further 
with stricter emissions limits.   

105 

 
 
 
 
 
 
 
                                                 
the  ERAA  methodology,  the  identification  of  the  adequacy  concerns  should  be  based  on  one 
central reference scenario. This facilitates decision-making but also makes it challenging due to 
the current unpredictability of global events and their effect on the energy sector. The Electricity 
Regulation envisages the possibility of having more than one scenario, however.  

In order to simplify the approval process, the Commission will work with ENTSO-E and ACER 
to introduce more than one scenario in the methodology for the identification of adequacy concerns 
that Member States could use to justify the introduction of a capacity mechanism. At the same 
time, in order to preserve the role of the European assessment in limiting costs for consumers and 
to preserve the EU level-playing field, the scenarios would need to be reasonable, realistic and 
sufficiently  circumscribed  to  avoid  that  that  they  are  a  pretext  to  justify  over-procurement  of 
capacity, which is very costly for consumers and companies.  

Apart from these avenues that will be pursued by the Commission, Member States with adequacy 
concerns can also look at the options possible at national level under the capacity mechanism rules 
and elsewhere to support security of supply. For example, as discussed in section 5 on flexibility, 
Member States should consider whether new schemes to support flexibility and demand response 
can  address  their  flexibility  needs.  This  could  be  a  simpler  way  than  introducing  a  capacity 
mechanism in the first place. In addition, there is also the possibility under the capacity mechanism 
rules for Member States to set their own reliability standard at national level. This means that, even 
under the existing scenario, Member States can opt for a more secure reliability standard than they 
had in the past, which although more costly, insures the system against adequacy risks to a higher 
degree.  

Furthermore, as part of the ongoing bidding zone review process, Member States can ensure that 
their bidding zones reflect structural congestion. Where economically beneficial to do so, Member 
States could  reconfigure their bidding zone to  use the grid most efficiently  and  ensure that the 
market can support security of supply. When applying a capacity mechanism in a Member State 
with more than one bidding zone, it enables targeted investments where they are most needed as 
the locational elements are inherent in the design.   

Indeed,  as  the  patterns  of  electricity  flows  change  with  the  many  new  investments  needed  to 
decarbonise and electrify the energy system, stronger locational price signals may be needed into 
the future to ensure that investments take place where they are needed. To ensure that the system 
can continue to work reliably at national level and across borders, we should strive for an electricity 
market that reflects the physical reality of the grid and supports incentives for cross-zonal long-
term contracting.  

106 

 
 
 
 
 
 
 
 
 
8.2. 

Locational signals 

Feedback from public consultation 

Only 37% of professional respondents expressed support for a more granular approach to market 
prices.  Among  categories  of  respondents,  a  majority  of  academics,  TSOs,  regulators, 
environmental organisations, EU citizens, NGOs and public authorities support a more granular 
approach  while  the  approach  is  globally  not  supported  by  business  associations,  energy 
companies, energy suppliers and industrial consumers. 

o  Respondents  see  the  following  benefits:  reduced  overall  energy  system  development 
costs,  reduced  need  for  electricity  grid  reinforcement  due  to  improved  matching  of 
market and physics, promotion of competition and innovation, improved integration of 
distributed energy resources (such as demand response and energy storage) into the grid, 
and competitive hydrogen production costs. In their view, this approach can lead to a 
more flexible, efficient, and sustainable energy system, with improved energy security 
and reliability, and lower costs for energy consumers.  

o  Some  respondents  explained  that  locational  pricing  enable  the  direct  inclusion  of 
congestion  and  network  constraints  into  the  electric  market  price,  while  the  current 
zonal design may provide financial incentives to create congestions in real-time if not 
well-configured.  In  their  view,  a  zonal  design  hampers  the  efficient  integration  of 
offshore bidding zones and large scale flexible assets and demand response. 

o  Others  explained  that  granular  locational  signals  would  help  taking  appropriate 

investment decisions (including for hydrogen production). 

o  A regulator explained that a nodal design would strongly simplify the European design, 
as  there  would  be  no  need  for  (i)  a  bidding  zone  review;  (ii)  a  capacity  calculation 
methodology;  (iii)  analysing  if  this  capacity  calculation  methodology  is  non-
discriminatory; and (iv) a redispatching and cost sharing methodology. 

On the other hand, respondents against the idea highlighted the following: 

o  Some  highlighted  the  following  risks:  potential  lack  of  liquidity  in  smaller  bidding 

zones, risk of market dominance, and risk of high local prices.  

o  Others explained that they do not see the benefits for the day-ahead and intraday markets, 
but that locational signals are needed in more short-term markets e.g. for flexibility for 
system needs.  

107 

 
 
 
 
 
 
 
 
o  Some respondents explained that it could raise distributional challenges to societies as 
prices  might  differ  considerably  within  countries  which  could  go  against  political 
objectives of a country.  

o  They  also  explained  that  transparency  on  the  price  formation  process  risks  being 

significantly reduced (due to complex algorithm).  

Several  respondents  explained  that  it  is  possible  to  introduce  locational  elements  in  several 
alternative ways:  tariffs, improved bidding zone configuration, integrating so-called "dispatch 
hubs" in the market coupling, nodal market design, location dependent investment incentives 
also considering ancillary services, and/or by taking real congestion into account in the market 
coupling. 

About  implementation,  respondents  explained  that  such  a  development  requires  a  political 
consensus as well as long technical implementation time. In their view, there could be a focus 
on the most congested bidding zones first – and different levels of spatial granularity may be 
applied across the EU, depending on regional/national specificities. 

Many respondents consider that a change to more granularity represents a fundamental change, 
which requires a deeper analysis, which does not seem feasible in the desired timeline of the 
market  design  reform.  In  their  view,  such  analysis  could  be  used  as  input  to  a  more 
comprehensive market design reform aiming at future-proofing the electricity market design for 
the net zero system. 

Under the current market design, wholesale electricity prices only represent supply and demand 
for the whole bidding zone, without taking into account the actual geographical location of that 
supply  and  demand  within  the  bidding  zone  and  the  actual  physical  limits  of  the  transmission 
system that may exist. The concept of bidding zones is static and not designed to swiftly adapt to 
changes in  grid or composition/location of supply  and demand, as any  configuration change is 
subject to the bidding zone review process153. 

In a more granular market, the market structure would appropriately reflect congestions in the grid 
and electricity prices will in general be lower at locations with abundant production of electricity 
from  renewables  than  in  areas  where  fossil-fuelled  generation  is  needed  to  meet  demand.  This 
allows  local  consumers  to  reap  the  benefits  of  renewables  and  –  at  the  same  time  –  provide 
incentives for new electricity intensive industries to locate there, which is also crucial in light of 
the EU hydrogen objectives. At the same time, it would make electricity more costly in regions 
where  the  potential  for  renewables  is  lower  for  space  or  environmental  reasons,  potentially 
increasing the need for more transmission networks in that area. 

153  

Pursuant to Commission Regulation (EU) 1222/2015 of 24 July 2015 establishing a guideline on capacity 
allocation and congestion management 

108 

 
 
 
 
 
 
 
                                                 
While the present proposal does integrate some locational elements in the current market design, 
a  deeper  change  to  move  to  more  locational  pricing  would  require  significant  changes  to  the 
legislative framework and to the current market design. The Commission will however continue 
to analyse the effect, possible benefits and risks of stronger price signals. In particular, it will study 
which level of granularity brings the most benefits to European citizens, enables the most efficient 
use of renewables, and how to overcome potential implementation challenges. 

9.  Concluding remarks 

In  conclusion,  this  package  of  reforms,  if  adopted,  is  expected  to  significantly  improve  the 
structure and functioning of the European electricity market. It is another building block to enable 
the delivery of the Green Deal objectives; it takes stock of the shortcomings revealed by the energy 
crisis and seeks to address them. 

It would protect and empower consumers currently facing high and volatile prices by creating a 
buffer between them and short-term markets. This proposal can decouple the high prices of fossil-
fuel  technologies  operating  in  the  electricity  market  from  the  energy  bills  of  consumers  and 
businesses.  More  long-term  contracting  in  the  form  of  PPAs,  CfDs  and  forward  markets  will 
ensure  that  the  part  of  the  electricity  bill  exposed  to  short-term  markets  is  greatly  reduced.  In 
addition, including a hedging obligation on suppliers and an obligation for fixed price contracts 
will significantly reduce the price volatility of electricity bills. Consumers will also have better 
information on offers before signing up and Member States will have an obligation to establish 
suppliers of last resort and can enable access to regulated retail prices in a crisis. The right to share 
energy is a new feature that will support the decentralised rollout of renewable energy and give 
consumers more control over their energy bills.  

This  reform  would  also  enhance  the  competitiveness  of  EU  industry  in  a  way  that  is  fully 
complementary to the Net-zero Industry Act. Member States will be required to ensure the right 
conditions exist for PPA markets to develop, thereby providing industry access to affordable and 
clean electricity over the long term. The improvements to the forwards markets will provide far 
greater access to cross-border renewables for industries and suppliers up to three years in advance, 
a significant improvement on today. Overall, public support schemes for renewables will increase 
the energy independence in Member States and the penetration of renewables into the system while 
supporting local jobs and skills. 

Finally,  if  adopted,  this  reform  will  accelerate  the  rollout  of  renewables  and  tap  into  the  full 
potential of firm generation capacity and flexibility solutions to enable Member States to integrate 
ever higher levels of renewables. The Commission proposes that Member States assess their need 
for power system flexibility and introduces the possibility for new support schemes for demand 
response and storage. The proposal also introduces extra possibilities for renewables to trade closer 

109 

 
 
 
 
 
 
 
 
 
to  real  time  at  cross-border  and  national  level.  In  this  way,  the  market  can  better  support  the 
integration  of  renewables  and  the  business  case  for  flexibility  solutions  that  can  contribute  to 
security of supply.  

This proposal responds to the request from the European Council to assess ways of optimising the 
functioning of the electricity market design in the context of the energy crisis. It aims to protect 
consumers, creating a buffer between them and short-term electricity markets through longer-term 
contracting and to make those short-term markets work in a more efficient way for renewables and 
flexibility solutions, with better regulatory oversight. This proposal ensures that the market rules 
remain  fit  for  purpose  to  drive  the  cost-effective  decarbonisation  of  the  electricity  sector  and 
increase its resilience to energy price volatility.  

110 

 
 
 
 
 
 
 
 
 
 
 
Figure 1: Evolution of the EU electricity wholesale prices (€/MWh) – weekly average ............... 3 
Figure 2: volume of RES installed capacity in EU, and projection of RES to reach "Fit-for-55" 
and “REPowerEU” targets .......................................................................................................... 10 
Figure 3: Evolution of the PPA market in Europe ....................................................................... 20 
Figure 4: Renewable electricity subsidised in 2019 (volume and %) .......................................... 26 
Figure 5: Distribution of renewables auction per support scheme (2014-2021) ......................... 28 
Figure 6: churn factors in major European forward markets – 2016-2020................................. 37 
Figure 7: Intraday gate closure times in different Member States ............................................... 53 
Figure 8: Traded volumes of electricity depending on the time before delivery of electricity 
(yearly in 2021 to the left, monthly in the second half of 2022 to the right)................................. 54 
Figure 9: Number of trades before and after the XBID platform go-live in selected Member 
States ............................................................................................................................................. 55 
Figure 10: expected evolution of flexibility needs in the EU ........................................................ 57 
Figure 11: Daily flexibility needs ................................................................................................. 57 
Figure 12: Development of demand side flexibility in wholesale markets ................................... 60 
Figure 13: Status of the roll-out of electricity smart meters at the end of 2021........................... 65 
Figure 14: Capacity remuneration through capacity mechanisms per type of technology in EU-
27 2019-2022 ................................................................................................................................ 70 
Figure 15: Long-term contracted capacity and costs by type of technology in the EU-27 on the 
period 2026-2035 .......................................................................................................................... 71 
Figure 16: illustration of demand side flexibility effect................................................................ 73 
Figure 17: Consumer difficulty with comparing offer in Ireland ................................................. 78 
Figure 18: Demand side response potential per technology ........................................................ 85 
Figure 19: Legal minimum duration of the electricity disconnection process in EU MSs, Great 
Britain and Norway – 2021 (Number of working days). .............................................................. 91 
Figure 20: Percentage of cases that reached the investigation stage .......................................... 97 
Figure 21: Percentage of cases that led to a sanction.................................................................. 97 
Figure 22: Evolution of the stock of REMIT cases over time ..................................................... 102 

Table 1: Overview of the contributions received, by type of respondent ...................................... 13 
Table 2: price correlation between bidding zones: comparison between a core hub and DE hub
....................................................................................................................................................... 39 
Table 3: The average benefits of collective self-consumption across the seven studied countries, 
for the market conditions in 2020 and 2022 and for a 100% and a 50% solar / 50% wind 
generation mix. ............................................................................................................................. 45 
Table 4: market design specifics in some local flexibility markets ............................................... 62 
Table 5: Participation in capacity auctions dedicated to demand side response in France - ...... 72 
Table 6: Roll-out of smart meters in electricity across the Member States .................................. 83 
Table 7: Overview of the price setting intervention during the energy crisis. (Source: 
Commission) ................................................................................................................................. 88 

111 

 
 
 
 
 
 
 
 
 
ANNEX I: Additional summary of the public consultation on 
Electricity Market design 

1.  Overview of respondents 

I am giving my contribution as 

2.  Answers from professional/non-citizens respondents 

Answers to the open questions have been summarised directly in the Staff  Working Document 
under each sub-sections. Therefore, this annex focuses on answers to the multiple choice questions. 

Organisation size 

Micro (1 to 9 employees) 

Answers  Ratio 

141 

22.93% 

112 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Small (10 to 49 employees) 

Medium (50 to 249 employees) 

Large (250 or more) 

139 

102 

233 

22.6% 

16.59% 

37.89% 

To which category of stakeholder do you belong? 

a) National or local administration 

b) National regulator 

c) Transmission System Operator 

d) Distribution System Operator 

e) Market operator 

f) Energy company with generation assets 

g) Independent energy supplier with no generation assets 

h) Company conducting business in the energy sector no 
included in f) or g) 

Answers  Ratio 

27 

7 

25 

42 

35 

4.39% 

1.14% 

4.07% 

6.83% 

5.69% 

154 

25.04% 

23 

65 

3.74% 

10.57% 

i) Industrial consumer and associations 

161 

26.18% 

j) Energy community 

k) Academia or think tank 

l) Citizen or association of citizens 

m) Non-governmental organisations 

n) Other 

No Answer 

15 

39 

4 

72 

68 

0 

2.44% 

6.34% 

0.65% 

11.71% 

11.06% 

0% 

113 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Do you consider the use of PPAs as an efficient 
way to mitigate the impact of short-term markets 
on the price of electricity paid by the consumer, 
including industrial consumers?

No; 100; 
20%

Yes; 392; 
80%

Do you consider that the following measures would be effective in strengthening the roll-out of 
PPAs? 

a) Pooling demand in order to give access to smaller final 
customers 

b) Providing insurance against risk(s) either market driven 
or through publicly supported guarantees schemes (please 
identify such risks) 

c) Promoting State-supported schemes that can be 
combined with PPAs 

d) Supporting the standardisation of contracts 

e) Requiring suppliers to procure a predefined share of 
their consumers’ energy through PPAs 

f)  Facilitating cross-border PPAs 

No Answer 

Answers  Ratio 

324 

52.68% 

337 

54.8% 

280 

45.53% 

288 

100 

266 

141 

46.83% 

16.26% 

43.25% 

22.93% 

114 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
In addition to the measures proposed in the 
question above, do you see other ways in which 
the use of PPA for new private investments can 
be strengthened via a revision of the current 
electricity market framework?

No; 125; 
30%

Yes; 286; 
70%

Do you see a possibility to provide stronger 
incentives to existing generators to enter 
into PPAs for a share of their capacity?

No; 166; 
41%

Yes; 235; 
59%

Do you consider that stronger obligations on 
suppliers and/or large final customers, including 
the industrial ones, to hedge their portfolio using 
long term contracts can contribute to a better 
uptake of PPAs?

Yes; 108; 
26%

No; 313; 
74%

Do you consider that increasing the uptake of PPAs would entail risks as regards:  

(a) Liquidity in short-term markets 

Yes 

No 

No 
Answer 

159 

242 

214 

(b) Level playing field between undertakings of different sizes 

203 

187 

225 

(c) Level playing field between undertakings located in different 
Member States 

185 

187 

243 

(d) Increased electricity generation based on fossil fuels 

46 

341 

228 

(e) Increased costs for consumers 

159 

230 

226 

115 

 
 
 
 
 
 
 
 
 
 
 
Do you consider forward hedging as an 
efficient way to mitigate exposure to short-
term volatility for consumers and to support 
investment in new capacity?

Do you consider that the liquidity in forward 
markets is currently sufficient to meet this 
objective?

No; 75; 
17%

Yes; 363; 
83%

Yes; 78; 
18%

No; 354; 
82%

In your view, would requiring electricity 
suppliers to hedge for a share of their supply 
be beneficial for consumers and for retail 
competition?

Do you consider that the creation of virtual 
hubs for forward contracts complemented with 
liquid transmission rights would improve 
liquidity in forward markets?

Yes; 140; 
34%

No; 268; 
66%

No; 147; 
46%

Yes; 171; 
54%

If yes, do you consider that such virtual 
hub(s) should be developed at national, 
regional or EU level?

Do you have experience with the existing 
virtual hubs in the Nordic countries?

National 
level; 21; 
14%

EU level; 
61; 40%

Regional 
level; 71; 
46%

Yes; 100; 
31%

No; 220; 
69%

116 

 
 
 
 
 
 
 
 
 
 
In case you have experience with the existing virtual hubs in the 
Nordic countries, how do you rate this experience?

18
16
14
12
10
8
6
4
2
0

0

1

2

3

4

5

6

7

8

9

10

Do you consider the use of two-way cfds or 
similar arrangements as an efficient way to 
mitigate the impact of short-term markets on 
the price of electricity and to support 
investments in new capacity (where 
investments are not forthcoming on a market …

Should new publicly financed investments in 
inframarginal electricity generation be 
supported by way of two-way CfDs or similar 
arrangements, as a means to mitigate 
electricity price spikes of consumers while 
ensuring a minimum revenue?

No; 145; 
30%

Yes; 334; 
70%

No; 176; 
40%

Yes; 266; 
60%

Without prejudice to Article 6 of Directive (EU)2018/2001[1], 
should it be possible for Member States to impose two-way CfDs 
by regulatory means on existing generation capacity?

Yes; 67; 17%

No; 339; 
83%

How would you rate the following potential risks as regards the imposition of regulated CfDs on 
existing generation capacity? 

117 

Negligible risksLow risksMedium risksHigh risksVery high risksNo AnswerLegitimate expectations/legal risks13253564221257Ability of national regulators/governments to accurately define the level of the price levels envisaged in these contracts111845140149252Locking in existing capacity at excessively high price levels determined by the current crisis situation16359210799266Impact on the efficient short-term dispatch20556773136264 
 
 
 
 
 
 
 
 
 
 
Would it be enough for existing generation to be 
subject only to a simple revenue ceiling instead 
of a revenue guarantee?

Do you consider that a transmission access 
guarantee could be appropriate to support 
offshore renewables?

Yes; 53; 
16%

No; 279; 
84%

No; 117; 
39%

Yes; 183; 
61%

Do you see any other short-term measures to accelerate the deployment of renewables? 

Do you consider that some form of revenue 
limitation of inframarginal generators 
should be maintained?

Should the modalities of such revenue limitation 
be open to Member States or be introduced in a 
uniform manner across the EU?

Yes; 93; 
22%

No; 337; 
78%

Member 
States; 
110; 32%

EU; 233; 
68%

118 

YesNoNo AnswerAt national regulatory or administrative level38522208In the implementation of the current EU legislation, including by developing network codes and guidelines30745263Via changes to the current electricity market design177161277Other14054421012345678910No Answer(a) the effectiveness of the measure in terms of mitigating electricity price impacts for consumers16133482261891219518264(b) its impact on decarbonisation2142836198915638278(c) security of supply19139311691224748292(d) investment signals2274525154443717273(e) legitimate expectations/legal risks19328252013867607302(f) fossil fuel consumption17018351661857724327(g) cross border trade intra and extra EU173282415111532516332(h) distortion of competition in the markets175362419514068222304(i) implementation challenges159313423391137119315 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Do you consider the short-term markets are functioning well in terms of: 

Do you see alternatives to marginal pricing as 
regards the functioning of short-term 
markets in terms of ensuring efficient 
dispatch and as regards the determination of 
cross border flows?

Do you consider that the cross-border 
intraday gate closure time should be moved 
closer to real time (e.g. 15 minutes before 
real time)?

Yes; 77; 
17%

No; 57; 
18%

No; 374; 
83%

Yes; 257; 
82%

Do you consider that market operators 
should share their liquidity also for local 
markets that close after the cross-border 
intraday market?

Would a mandatory participation in the day-
ahead market (notably for generation under 
CfDs and/or PPA’s) be an improvement 
compared to the current situation?

No; 38; 
17%

Yes; 180; 
83%

Yes; 65; 
21%

No; 247; 
79%

In particular, do you think that a stronger 
role of OPEX in the system operator’s 
remuneration will incentivize the use of 
demand response, energy storage and other 
flexibility assets?

Do you consider that enabling the use of sub-
meter data, including private sub-meter data, 
for settlement/billing and observability of 
demand response and energy storage can 
support the development of demand response 
and energy storage?

No; 91; 
30%

Yes; 217; 
70%

No; 63; 
19%

Yes; 265; 
81%

119 

YesNoNo Answer(a) accurately reflecting underlying supply/demand fundamentals36673176(b) encompassing sufficiently liquidity33184200(c) ensuring a level playing field304101210(d) efficient dispatch of generation assets36358194(e) minimising costs for consumers261147207(f) efficiently allocating electricity cross-border32276217 
 
 
 
 
 
 
 
 
 
 
 
Do you consider appropriate to enable a 
product to foster demand reduction and shift 
energy at peak times as an ancillary service, 
aiming at lowering fuel consumption and 
reducing the prices?

Do you consider that some form of demand 
response requirements that would apply in 
periods of crisis should be introduced into the 
Electricity Regulation?

No; 119; 
31%

Yes; 260; 
69%

Yes; 141; 
42%

No; 198; 
58%

Do you see any further measure that could be 
implemented in the shorter term to 
incentivize the use of demand response, 
energy storage and other flexibility assets?

Do you consider the current setup for capacity 
mechanisms adequate to respond to the 
investment needs as regards firm capacity, in 
particular to better support the uptake of 
storage and demand side response?

No; 80; 
22%

Yes; 279; 
78%

Yes; 87; 
24%

No; 279; 
76%

Do you see a benefit in a long-term shift of the 
European electricity market to more granular 
locational pricing?

Would you support a provision giving 
customers the right to deduct offsite 
generation from their metered consumption?

Yes; 129; 
37%

No; 220; 
63%

No; 128; 
39%

Yes; 202; 
61%

(a) Would it affect the location of new 
renewable generation facilities?

(b) Should it be restricted to local areas?

No; 81; 
33%

Yes; 163; 
67%

No; 82; 
34%

Yes; 159; 
66%

120 

 
 
 
 
 
 
 
 
 
 
 
(c) Should it apply across the Member 
State/control/zone?

Yes; 74; 
35%

No; 136; 
65%

Would you support establishing a right for 
customers to a second meter/sub-meter on 
their premises to distinguish the electricity 
consumed or produced by different devices?

Would you support provisions requiring 
suppliers to offer fixed price fixed term 
contracts (ie. which they cannot amend) for 
households?

No; 95; 
33%

Yes; 191; 
67%

Yes; 110; 
36%

No; 195; 
64%

If such an obligation were implemented what should the minimum fixed term be? 

(a) less than one year 

(b) one year 

(c) longer than one year 

(d) other 

No Answer 

Answers  Ratio 

32 

76 

39 

63 

5.2% 

12.36% 

6.34% 

10.24% 

405 

65.85% 

121 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cost reflective early termination fees are currently allowed for fixed price, fixed term 
contracts: 

Do you see scope for a clarification and 
possible stronger enforcement of consumer 
rights in relation to electricity?

Would you support the establishment of 
prudential obligations on suppliers to ensure 
they are adequately hedged?

No; 101; 
42%

Yes; 137; 
58%

No; 129; 
45%

Yes; 156; 
55%

Would such supplier obligations need to be 
differentiated for small suppliers and energy 
communities?

Should the responsibilities of a supplier of last 
resort be specified at EU level including to 
ensure that there are clear rules for consumers 
returning back to the market?

Yes; 74; 
34%

No; 141; 
66%

No; 119; 
48%

Yes; 131; 
52%

Would you support including an emergency 
framework for below cost regulated prices 
along the lines of the Council Regulation (EU) 
2022/1854 on an emergency intervention to 
address high energy prices, i.e. for 
households and SMEs?

(a) If such a provision were established, should 
price regulation be limited in time and to 
essential energy needs only?

No; 29; 
16%

Yes; 77; 
31%

No; 170; 
69%

Yes; 154; 
84%

122 

YesNoNo Answer(a) Should these provisions be clarified?15549411(b) If these provisions are clarified should national regulatory authorities establish ex ante approved termination fees?76106433 
 
 
 
 
 
 
 
 
 
 
(b): Would such provisions substitute on long 
term basis for direct access to renewable 
energy or for energy efficiency?

(b): Can this be mitigated?

Yes; 61; 
42%

No; 84; 
58%

Yes; 22; 
19%

No; 94; 
81%

(c): Would such contracts reduce incentives 
to reduce consumption at peak times?

(c): Can this be mitigated?

No; 39; 
26%

Yes; 112; 
74%

Yes; 39; 
32%

No; 82; 
68%

3.  Answers from citizens 

3.1. 

“Slovakian campaign” 

Almost  all  of  the  more  than  550  responses  from  Slovakia  appear  to  be  part  of  a  co-ordinated 
campaign.  Slovakian  citizens  consider  PPAs  as  an  efficient  and  risk-free  way  to  mitigate  the 
impact  of  short-term  markets  on  the  price  of  electricity  but  are  of  the  opinion  that  current  EU 
legislation prevents existing generators to enter into PPAs. They advocate a stronger obligation on 
suppliers and/or large final customers to hedge their portfolio, the standardisation of contracts and 
facilitating cross-border PPAs. They advocate to give national regulators the power to prevent the 
export of electricity to other Member States. 

These respondents support giving Member States the right to impose two-way CfDs on existing 
generation,  despite  legal  risks  and  are  of  the  view  that  public  support  schemes  should  exclude 
renewables that do not generate at least a minimum number of hours per year. They also strongly 
advocate increasing competence and independence of the national regulator. 

123 

 
 
 
 
 
 
 
 
 
 
 
 
Almost all respondents which are part of the co-ordinated campaign oppose a revenue limitation 
set at EU level. They see it as task of the national regulator.  They also consider that emissions 
trading hampers competitiveness and should be abolished. 

Overall,  they  consider  that  short-term  markets  are  functioning  well  and  respondents  see  no 
alternative to marginal pricing. They do not support a change in the cross-border intraday gate 
closure time or the proposed measures to incentivise flexibility with the exception of a product to 
foster  demand  reduction  and  shift  energy  at  peak  times  as  an  ancillary  service  and  increasing 
awareness and promotion of mini- and micro-resources. Mandatory participation in the day-ahead 
market is supported, since it would put downward pressure on prices in their view. A long-term 
shift  to  more  granular  pricing  is  considered  beneficial  as  is  stronger  enforcement  of  consumer 
rights. 

The  respondents  explained  that  REMIT  should  be  improved  in  order  to  prevent  speculative 
practices by market participants in a timely manner. 

3.2.  Views of the other around 120 individual citizens  

Most  contributions  from  individual  citizens,  besides  the  co-ordinated  campaign  from  Slovakia, 
came from France, Slovakia and Germany. A few responses came from Austria, Belgium, Czechia, 
Slovakia, Sweden. Those citizens have diverging views and for many questions the share of “no 
answer” responses is significantly higher than for other stakeholders. 

A clear majority of these citizens considers the use of PPAs as an efficient way to mitigate the 
impact of short-term markets on the price of electricity paid by private and industrial consumers. 
Only  a  small  minority  of  respondents  did  not  answer  this  question.  A  majority  of  them  also 
considers  forward  hedging  as  an  efficient  way  to  mitigate  exposure  to  short-term  volatility  for 
consumers and to support investment in new capacity. Only a small minority did not provide an 
answer to this question. For all other questions, the share of “no answer” is rather high and no clear 
tendency can be identified. 

Only a small number of citizens responded to the questions related to REMIT. These responses 
mainly indicate concerns about high energy prices or if electricity markets are functioning to the 
benefit of consumers. 

124