Commission Notice on Guidelines on future proof network charges for reduced energy system costs
Date: 2026-01-09
Institutions: Directorate-General for Energy, European Commission
Subjects: consumer protection, distributive trades, electrical energy, electricity supply, energy consumption, energy grid, price of energy, renewable energy, security of supply, single market








C_202600126EN.000101.fmx.xml












Official Journal of the European Union


EN
C series













C/2026/126


9.1.2026







            COMMISSION NOTICE ON GUIDELINES
         
on future proof network charges for reduced energy system costs
(C/2026/126)

I.   Introduction

The European electricity network is a fundamental pillar of the European economy. It is the most interconnected in the world, with a myriad of processes and actors working seamlessly to deliver secure, affordable and increasingly non-fossil electricity, while at the same time integrating vast levels of renewables into the overall energy mix. Rising electricity demand, accelerating electrification of end uses, and the accelerated deployment of renewables all require changes to optimise the way electricity grids are designed and operated. In hours of high level of renewable generation, low or negative electricity prices – which set a new record last year (1) - reflect the need for the system to be more flexible and avoid inefficient curtailment while at the same time allowing energy to be used where the cheapest energy sources are available and when it is the most cost efficient for the overall system.
Furthermore, the widespread deployment of renewables (which are frequently located where conditions are the most suitable, not necessarily near centres of demand or where the grid is already well-reinforced) must be supported by an efficient integration into the network. This calls for significant investments into electricity grids. Investments of around EUR 730 billion for distribution and EUR 477 billion for transmission including offshore grid developments are likely needed until 2040 (2) to advance the internal energy market and expand grid capacity. These investments will be instrumental in enabling the connection of new clean generation projects that ultimately drive down the average wholesale electricity price and are needed to reach European climate goals. A recent ACER report estimated that, until 2050, the annual investment rates of the past decades could double. It also estimates that investments in the transmission level will account for a smaller portion of this (about one third) compared to the distribution level (about two thirds) (3).
This will have a direct impact on network charges, which in recent years, have represented between 24-29% (4) of the electricity bill for households. While the energy price component is expected to decrease, grid costs are expected to become an even larger item on electricity bills. A smart and efficient design of network charges will be instrumental in increasing the infrastructure’s efficiency to optimise overall system costs, this is crucial for EU competitiveness and ensure affordability of electricity for consumers.
The EU is dedicated to pursuing the decarbonisation objective while enhancing energy affordability and security. This is pivotal for competitiveness of European industries, as outlined in the Clean Industrial Deal (CID), which also addresses the need to support strategic autonomy, secure vital supply chains and maintain economic prosperity for EU industry. As part of the CID the Commission adopted the Action Plan for Affordable Energy in February, with eight impactful actions aiming at decreasing energy costs for citizens and businesses, most of them to be delivered in the short-term. The Action Plan examined the factors driving up energy prices and identified energy supply costs, taxation as well as network and system costs as key areas to address in order to help reduce the energy bills for European consumers.
To ensure that the necessary build-out of the electricity grid happens in the most cost-effective manner, it has to go hand in hand with the optimal use of the infrastructure.
The design of network tariff methodologies has a significant impact on this as it can provide the necessary incentives for all system users to adjust their behaviour in a way which helps to reduce the overall system cost.
This document implements a key action (Action 1 (a)) in the AEAP and provides guidance to national regulators, who are responsible for designing network tariff methodologies, on how this can best be achieved. As set out in the AEAP, the Commission after publishing theses Guidelines, may, if necessary, put forward a binding legislative proposal on tariff methodologies (5).
The objective of these Guidelines is to support national regulators in designing tariff methodologies that make the best use of the existing grid infrastructure and contribute to minimising required additional investment, thereby helping to deliver more affordable energy. It recommends a significant shift in the way network tariffs are designed in line with the needs of a decarbonised energy system with greater user participation through decentralised energy production, energy system integration, storage, demand side flexibility and the availability of smart meters. Instead of relying on the overall amount of consumption, it proposes more granular calculation methods which financially incentivise grid users to adjust their energy use or shift it towards times and places where the cheapest energy sources are available and when it is the most cost efficient for the energy system and the consumers overall, with the view to make the best use of the existing grid infrastructure and minimise required additional investment. This is occurring already for electricity prices, with dynamic price contracts widely available in Member States (6) but grid tariffs generally are still quite flat regarding time or location of use (7).
While no “one-size fits all”, this document provides guidance to Member States and National Regulatory Authorities (‘NRAs’) for a forward-looking and efficient set of methodologies to optimise the use of existing grid, contribute to grid expansion at least cost and ensure a fair and cost-reflective allocation of grid charges while encouraging European competitiveness, deeper electrification and decarbonisation. In this respect, local contexts are important, such as the level of electrification or generation and load profile in a given area, which determines the ability of network users to react to incentives. By lowering overall system costs, benefits will be felt by all consumers – households and industrial – into the future.
II.   What are network tariffs?

Network tariffs are what all users connected to the system pay for the service of having the possibility to have electricity transported from the point of production to where the electricity is used. Tariffs allow for the cost recovery of investments into transmission and distribution grid assets, smart meters, the cost of maintenance and repairs of the existing network, running system services on a daily basis as well as the costs of transmission and distribution system operators. Costs that can be recovered by network tariffs include capital expenditure related to infrastructure investments (‘CapEx’), operational expenditure related to the daily management of the system (‘OpEx’), remuneration of the system operators, the cost of network losses, costs of system balancing and ancillary services, costs of congestion management, and others.
Network tariffs are complex in their design, needing to balance the different system needs while encouraging cost-effective multi-annual network investment decisions and strong incentives for keeping overall operational system costs in check. They are set for regulatory periods (typically of 4-5 years), during which the NRA determines the level of the tariff remuneration (i.e. allowed revenues for system operators) and the tariff methodologies, which determine the incentives for the system operators and also how to allocate the total costs among network users in the form of network charges. This regulatory cycle provides stability while mid-period adjustments or annual revisions are frequently used to ensure that the allowed system operator revenue levels as well as network charges levels are consistent with the necessary actions of the system operators to manage any change in circumstances.
III.   Legal framework

a.   Independent National Regulatory Authorities are competent

Under EU legislation, network tariff design is the responsibility of the independent NRA. (8) NRAs have “
               the duty to fix or approve, in accordance with transparent criteria, transmission or distribution tariffs or their methodologies, or both
               ”
                (9). Member States are obliged to guarantee the independence of the NRA and ensure that it exercises its powers impartially and transparently. For that purpose, the NRA must be legally distinct and functionally independent from other public or private entities, act independently from any market interest and take autonomous decisions, independently from any political body (10). The independence of NRAs from national governments and parliaments in relation to the exercise of their tariff powers has been tested and upheld by the European Court of Justice (‘the Court’).
The Court has consistently found that NRAs shall take their own decisions autonomously and solely in the public interest, so as to ensure compliance with the objectives pursued by the electricity Regulation (11) and the Electricity Directive (12), without being subject to external instructions from other public or private entities.
The Court has found that the NRAs’ core task of fixing and approving tariff methodologies must not be subject to external intervention. Indeed, intervention from government, parliament, in particular in legislative forms, and other public bodies other than NRAs is limited to restating the general principles set out in the Electricity Directive and Regulation and the establishment of general policy guidelines, insofar as they do not relate to the catalogue of core competences of the NRA set out in the Electricity Directive. This was set out in judgments in relation to Germany in 2021 (13), to Belgium (14) and to Slovakia in 2020 (15).
The Court has also ruled that the government cannot appoint or dismiss the NRA’s leadership, due to disagreement over the content of the tariff methodology
                (16).
Additionally, it is important to note that tariff setting is a complex task, and it is crucial that Member States ensure the NRA is appropriately resourced. The Electricity Directive requires that the Member State ensures the NRA has “
               all the necessary human and financial resources it needs
               ”
                (17) in order to perform its tariff-setting tasks well, and in accordance with EU legislation. In some Member States, the system operators propose their own tariff, and it may be the case that the NRAs do not have the resources necessary to fully interrogate the details and improve the methodology.
This is an issue that all Member States should look into at national level, while the Commission will ensure that the independence of national regulators in defining network tariff methodologies is duly protected and safeguarded under national law.
b.   Network tariff design principles

As outlined above, the NRA has the competence to set the tariff regime. However, this is not without boundaries in EU legislation. The principles for the development of network tariffs are set out in the Electricity Regulation, including its subsequent amendments in the Electricity Market Design Reform Package. (18) A basic principle enshrined in Article 18 of the Electricity Regulation is that network charges should be cost-reflective and encourage efficient use of the existing grid by providing price signals for network users to adapt their behaviour. Indeed, according to the Regulation, network charges must be “
               cost-reflective, transparent, take into account the need for network security and flexibility and reflect actual costs incurred…
               ”. In addition, the tariff regime should support “
               overall system efficiency
               ”, provide “
               price signals to consumers and producers
               ”, “
               locational signals at Union level and take into account the amount of network losses and congestion caused, and investment costs for infrastructure
               ”
                (19).
Additional principles for tariff design further demonstrate the acknowledgement of co-legislators of the increasing need for incentives to increase the flexibility and responsiveness of network users’ behaviour. For example, Article 18(2) of the Electricity Regulation requires incentives to provide appropriate short- and long-term incentives including anticipatory investments (20) to foster the integration of renewables, flexibility, optimisation solutions for existing grids, demand response and to contribute to the objectives of the National Energy and Climate Plans.
To support NRAs in their national design of the tariff regime and mitigate the risks of market fragmentation, the Agency for the Cooperation of Energy Regulators (‘ACER’) produces a report every two years on transmission and distribution tariff methodologies. The most recent report was published on 26 March 2025
                (21) and highlights best practices and contains recommendations for NRAs. NRAs should take account of these reports in their work while also considering national specificities. This guidance therefore also builds on ACER’s observations.
The legislation requires the network charges to be transparent, take into account the need for network security and flexibility and reflect actual costs incurred insofar as they correspond to those of an efficient and structurally comparable network operator and are applied in a non-discriminatory manner. Those charges shall not include unrelated costs supporting unrelated policy objectives (22).
Traditionally, electricity networks tariff regimes were split between CapEx and OpEx under regulatory prices controls, with a strong bias for CapEx investment in infrastructure which is typically regulated via a certain expected rate-of-return on investments. However, this approach needs to be updated in order to adjust to the overarching policy of decarbonisation and increased electrification, along with the decentralisation of energy production. Article 18 of the Electricity Regulation was amended in 2024 to reflect this. The legislation now requires a total expenditure (‘TotEx’) approach in that tariffs should “
               reflect the fixed costs of transmission system operators and distribution system operators and shall consider both capital and operational expenditure to provide appropriate incentives to transmission system operators and distribution system operators over both the short and long term including anticipatory investment, in order to increase efficiencies including energy efficiency.” In this way, tariff methodologies should encourage holistic thinking about system needs and the most efficient solutions to meet these needs (23). This approach can allow NRAs to incentivise transmission system operators (‘TSOs’), distribution system operators (‘DSOs’) and market participants to invest in cost effective systems that allow for flexibility and optimal use of the grid rather than a more traditional approach of building out the grid. (24)

In addition, Article 6a of the Electricity Directive (25) seeks to address the challenge of scarce grid capacity that many Member States are facing (26). In some Member States, once the grid has reached a certain amount of connected capacity, it is not possible to connect more unless grid users accept to adapt their behaviour in a system-friendly manner, and thus increase the local connection capacity. In these circumstances, storage and demand flexibility could be used to alleviate pressure on the grid by increasing the consumption of the local generation when and where the local grid is highly congested, and by supplying electricity outside of the system peak and when grid capacity is available.
Article 6a therefore sets out that the NRA should develop a framework for TSOs and DSOs to offer the possibility of non-firm (27) lexible connection agreements in areas where there is limited or no network capacity availability for new connections. The intention is to balance operational security with the need to enable connections for new grid users beneficial for a congested system. The practice of offering non-firm connections already exists in some Member States but now it will be required comprehensively across the entire EU. This practice should not delay necessary grid reinforcements and Article 6a further states that conversion to firm connections should be ensured, based on established criteria once the grid is reinforced. However, in areas where the NRA or another competent authority has deemed grid reinforcement not to be the most cost-efficient solution, then flexible connection agreements should be enabled on a permanent basis, including for storage. Given that these types of connection agreements do not offer unrestricted access to the network, the network charges applied to users with these types of connections should reflect this.






Member State practice – The Netherlands





Most countries apply some level of flexibility for network users under flexible connection agreement regimes, including conditions to limit injections to and withdrawals from the network. Flexible connection agreements are usually offered on a voluntary basis with the aim of supporting system balancing, reducing system peaks and reducing the need for grid injections. The Netherlands offers three types of flexible connection agreements: fully flexible; minimal availability agreements; timeslot agreements. Fully flexible agreements are available at the distribution and transmission level only in congested areas. Users with these agreements only pay a tariff for their monthly peak, not for contracted capacity. Minimal availability agreements are available on the transmission network inside and outside congested areas. Users cannot increase their actual peak, even when there is capacity and are guaranteed contracted capacity 85% of the time. These users pay a tariff for their monthly peak but not for contracted capacity. Timeslot agreements are available on distribution networks inside and outside congested areas and have access to grid capacity during contracted timeslots. They pay part of the tariff for contracted capacity and a tariff for their monthly peak.
These flexible arrangements have been introduced due to increasing congestion in several areas on the grid in the Netherlands and allow new grid users to gain partial access, at least, to the grid and incentivise current grid users to free up capacity by changing their connection agreements.




Finally, to acknowledge the changing role that distribution systems are playing – most new renewables projects are connected at the distribution level – the Regulation sets out that network charges should not discriminate between production connected at the distribution level and at the transmission level. Given that the Commission Regulation (EU) 838/2010 contains limits on network charges that can be applied to producers at the transmission level, it is useful to clarify how these Regulations should be read together. Given the principle of non-discrimination in the Electricity Regulation, the view of the Commission is that the ranges set out in Regulation 838/2010 should be the starting point for the calculation of network charges to be applied to producers at the distribution level. However, given the principle of cost-reflectivity, this does not mean that they are required to be exactly the same. Differences in charges could be justified due to reduced or additional system costs that may arise from the fact of being connected at distribution level.
IV.   Towards a more efficient Network Tariff Design

European energy systems are undergoing a paradigm shift. In the past, large, centralised dispatchable generation covered the demand of predictable loads. However, the power system now features larger shares of decentralised and intermittent renewable electricity, and electricity demand is expected to increase (28) as we decarbonise and electrify new sectors of the economy. The electricity grid is also experiencing changes in patterns of electricity flows due to a high concentration of renewable power in certain areas of the grid and increased distributed generation at the household level (for example, rooftop solar). Within this context, the role of the electricity network and underlying charges is also evolving. Network tariffs can have an influence on steering investments and also influencing the behaviour of users already connected to the grid; tariffs can encourage or discourage the flexibility needed to keep system costs minimised. Therefore, while cost recovery is a key purpose of network tariffs, they may also provide significant incentives to both system operators and users to achieve particular objectives.
Regarding locational signals, increased decentralised generation from renewable and other sources has implications for overall system costs especially at distribution level (29). Therefore, a smarter design of network tariffs, with appropriate incentives, can help to direct investments in generation closer to demand (and vice-versa) or where the grid capacity already exists (e.g. in places where there is decommissioning of fossil fuel power plants or former large industrial demand), ensure grid-friendly network usage and hence help – over time – to reduce costly network congestion, to reduce overall investment needs and to minimise network costs for all users. It can also help to direct investments in non-fossil flexibilities, such as storage and demand-response, to locate these flexibilities e.g. near areas characterized by significant variable renewable generation. Together with other measures, locational signals in the network tariff design can strengthen locational investment signals for grid users and hence improve overall cost-effectiveness..
In a system with increasing levels of flexibility needs, the principle of cost-reflectivity must reflect this to ensure that the allocation of network costs among system users fairly corresponds to how much they cost or support the system. Otherwise, NRAs risk not taking actual costs that users generate for the grid correctly into account, leading to those network costs being charged to others. By way of illustration, compared to today’s figures, flexibility requirements will more than double by 2030 and be seven times as large by 2050 (30). One key area where network tariffs can play an invaluable role is that of lowering the peak demand. Electricity grids are generally dimensioned to cover peak demand and any incentives through network charges for energy consumers to reduce the peak leads to a reduction of energy system investments to cover it.
Network tariffs alongside the energy component of the electricity bill can provide incentives to adjust behaviour in network utilisation. Capacity charges and dynamic tariffs (energy and grid) can encourage behavioural responses to shift usage to times outside the peak where significant capacity is available (31). Therefore, dynamic tariffs can help to address flexibility needs and therefore limit the need for other costly measures like the procurement of flexibility (32) .. It can help to partially lower network expansion needs, and thus the network charges paid by consumers in their electricity bills, while at the same time directly reducing bills for consumers in a position to make their electricity use more flexible.
A crucial consideration for NRAs is the complexity of the design. The tariff methodologies need to incentivise behaviour to reduce system costs but also be sufficiently understandable and predictable to consumers enabling them to react to price signals. The ability to react may not be the same for all network users, depending on their profile, but with further penetration of electrified resources (e.g. batteries, electric heating and EVs), the roll-out of smart metering systems and automation capabilities enabled by a robust aggregator framework, network users’ ability to respond to time signals are expected to significantly increase in time. Regarding new technologies and grid users – such as electric vehicles and energy communities – the 2025 ACER report (33) contains more detail on possible approaches to tariff design in this area and provides examples of Member State practice.
The lack of ability to react to price signals (e.g. lack of smart meters) is a barrier to capturing all of the benefits of a more efficient tariff regime and therefore calls for a balanced and comprehensive approach to change management. Tariff methodologies should, where relevant, recognise current capability limitations with potential for possible “opt-ins” to certain elements or a more gradual shift over time that is well-communicated to all and gives users the opportunity to adapt. Last but not least, predictable grid tariffs, where price levels and/or peak periods, or the methodology to establish them, are transparently defined ex ante with sufficient anticipation, are important to harness the full potential of consumers’ flexibility.
In relation to smart meters, although their rollout is a key enabler for changing consumer behaviour, it is not the only precondition for unlocking the full potential of a more dynamic and cost-reflective tariff design. On the technical side, the digitalisation of the network is also crucial to increase its efficiency and allow for adaptability according to the impact of changing generation and consumption patterns on the network. To this end, incentive-based regulation can incentivise system operators to implement the key changes necessary.
Regarding demand-side aggregation, the aggregator framework in Member States should be implemented completely to fully realise the market potential. Aggregators, working on their behalf, can reduce the perception of complexity for consumers. Their business model can foster the speedier uptake of automated and flexible solutions to allow the most cost-effective utilisation of the grid, without placing undue burden on consumers.
Finally, changes to the design of network tariff methodologies are taking place in the broader policy context where industrial competitiveness and decarbonisation are priorities in the face of increasing global competition. The evolution of tariff design therefore, should reflect the starting point of the economic sectors involved, support the uptake of clean energy and ensure there is an appropriate incentive regime to encourage behavioural change while avoiding excessive costs.
V.   Expected Benefits

The overall benefits to be expected from such a shift are very significant: lower costs for managing the grid, reduced inefficient congestion, improved ability to absorb larger shares of renewable generation, where relevant, and reduced overall need for grid reinforcements.
For example, in a recent report published by the Dutch government, the estimated total investment needs until 2040 for the electricity in the Netherlands is EUR 195 billion but, importantly, analysis also shows that making better use of the network could reduce the cumulative investment by up to EUR 22.5 billion for the Netherlands alone (34). Similar effects have been demonstrated in other Member States, where more cost reflective network charges have significantly reduced peak load consumption and hence the necessary build-out of the electricity grid.
Indeed, in a study focussed on Germany, Agora Energiewende modelled how dynamic tariffs including dynamic grid charges can effectively activate household demand-side flexibility (35). Their study found that there is potential to shift over 100 TWh of load to align with households’ needs in 2035. This accounts for over 10% of the total annual electricity consumption, around half of household electricity consumption and exceeds previous expectations regarding available demand-side flexibility potential. The study also found that, by reducing the load on the low-voltage grid and consequently reducing the need for expansion, the additional costs for grid expansion due to the integration of flexible demand (electric vehicles, heat pumps and home storage), can be almost halved from EUR 10.5 billion to EUR 5.8 billion. All electricity customers, in turn, benefit from reduced grid costs and especially those contributing to support system integration.
The benefits of activating flexibility on the demand side can lead to significant additional savings on top of reduced network expansion. The same Agora Energiewende study found that the use of demand-side flexibility is nine times cheaper than generation-side alternatives in Germany. If the flexibility potential of electric vehicles, heat pumps and home energy storage systems is used intelligently, the need for flexibility on the generation side from sources such as gas-fired power plants and large batteries can be considerably reduced, with savings amounting to EUR 5.4 billion for Germany for 2035.
Analysis on the expected individual benefits of changes in tariffs for users categories and technology types have also been assessed. A report commissioned by SmartEN (36) showed that the more cost-reflective a network tariff, the slower the rate of growth in the aggregate peak load (and thus necessary network expansion) even with rising levels of electrification. When considering high levels of EV adoption, a future-proof tariff design can bring different levels of benefits which, according to this study, could reduce the increase in peak load (and the corresponding dimensioning of the grid) by 23.7% using a dynamic volumetric tariff i.e. the smarter the tariff, the higher the benefit (37).
VI.   Individual Design Elements

a.   Interplay between Transmission and Distribution charges

Transmission and distribution charges are applied in electricity networks and the share of distribution charges tends to be much higher than that of transmission charges in terms of overall costs. In 2023, for example, the overall amount of transmission network charges in the EU was around EUR 20 billion and distribution network charges around EUR 60 billion (38). It is crucial to capture all costs, and the practice of cost cascading is applied in all EU Member States on a top-down basis, i.e. from higher to lower voltages. Cost cascading means that network users pay the costs of the voltage level of their connection and the cost relating to other voltage levels they may use. This explains why distribution charges are more significant as distribution customers pay for the network they are connected to (distribution networks tend to be longer and denser), and for higher voltage networks that feed into the distribution network. Transmission costs may appear on the customer bill explicitly as a transmission charge or may be included implicitly in the distribution charge.
This model, while logical for electricity systems where electricity flowed from generators at a higher voltage level to consumers at low voltage networks is less adapted to a new reality where more generation is connected at the distribution level. (39) Already in 2016, analysis from the Commission indicated that between 60-90% of new connections around the EU were at distribution level (40), and a 2024 study by Eurelectric (41), estimated that, by 2030, 70% of renewables are expected to be connected to distribution grids. At the same time, the concentration of large renewable installations in areas of high resources creates the need to reinforce the transmission system to bring that generation to consumers in other areas. This complex trend requires careful consideration by NRAs in the context of cost-reflectivity. NRAs may wish to consider altering how they apply the cost cascading principle in the changing circumstances when there is more and more generation connected to the distribution system. NRAs should coordinate with each other in developing new approaches to this trend.

While cost cascading may still be justified, a more sophisticated approach could better ensure cost-reflectivity as generation becomes prevalent in distribution networks, even at low voltage levels. NRAs should therefore take account of the changing generation/consumption profiles at the distribution level when applying cost cascading.

b.   Reducing peak load through capacity charges

There is a wide variety across Member States as to how network charges are constructed and, in many cases, Member States use a combination of methods. In the EU, network charges are usually based on volumetric network tariffs (EUR/kWh), capacity-based network tariffs (EUR/kW), fixed network tariffs (EUR/year), or on a combination of all three. For NRAs developing national tariff methodologies, the ACER best practice report recommends that they should identify the key drivers of network costs and set charges that correlate with those cost drivers.
In the evolving context of the energy transition, some Member States are experiencing an increasing disconnect between the simple volumetric network charges (in EUR/kWh) and the underlying drivers of those costs. A recent SmartEN study (42) highlights that this disconnection is becoming increasingly visible particularly through the rollout of rooftop solar because solar generation often does not coincide with the aggregate peak demand. For example, on a winter evening in northern Europe when peak demand occurs, solar PV would not be generating any electricity, and the costs for system operators to dimension the system to that peak consumption level is therefore not captured. A relevant capacity element added to the tariff can therefore better reflect the individual contribution to overall peak system need. Capacity tariffs can, in such cases and when combined with a time-of-use energy element to the tariff, be a useful tool for incentivising consumers to reduce their peak load, especially at times when the grid risks being saturated, limiting the associated network expansion costs. The success of measures such as this is dependent on the rollout of smart meters in member States. With the deployment of smart meters, more flexible network tariff schemes should evolve in a way that will incentivise users to better manage their connection capacity without unduly penalising them.

NRAs should use tariff design to incentivise the reduction of peak load consumption, including through adding a capacity element to the tariff structure that reflects peak load, combined with a time-of-use energy element to the tariff, especially at times when the grid risks being saturated, to reduce the cost of network expansion to the level needed.







Member State practice – Flanders, Belgium and Sweden





In Belgium, capacity-based charges were introduced for the transmission system in 2012 and a time-of-use signal for yearly peak consumption was introduced in 2016, followed by the introduction of a monthly peak tariff in 2024. The aim of the tariff structure was to provide clear price signals to minimise the synchronous peak, thus avoiding the need for further grid investment. Evidence shows that the industrial synchronous peak decreased by 4% between 2019 and 2024 despite the actual volume of withdrawals increasing by 10%. It is expected that the tariff structure will also lower the frequency and intensity of renewable curtailment on the system.
Also, in the Belgian region of Flanders, a capacity-based tariff introduced at the distribution level in 2023 has already led to a measurable reduction in peak load, of around 1-3%, mostly due to changes in when EVs are charged (43). It is calculated on the basis of the consumer’s average monthly peak and demonstrates that consumers can and do react to incentives and price signals.
In Sweden, the NRA announced in April 2025 (44) comprehensive plans to introduce a new grid tariff consisting of four components, including a new time-differentiated capacity charge, determined by the peak load consumption. The purpose of this capacity fee is to provide price signals to consumers reflecting how their current use of the network affects future investment needs. The goal is to reduce the need for network expansion and instead create space for more people to use the network. The NRA has set out that this capacity charge and other elements of the new tariff (a volumetric energy charge, capacity charge and customer-specific charge) should reflect the costs that the grid companies have for each customer or customer group.




c.   Time-of-use elements

Adding a time-of-use (ToU) element to volumetric energy charges increases cost-reflectivity as it incentivises users to produce or consume electricity in a way that reduces system peaks and utilises the full potential of renewable energy when abundant. Traditionally, grid tariffs were either static with the same price for each hours or contained a basic temporal difference with higher charges for day rates and lower charges for night rates. Today, with the deployment of smart meters, the ToU elements can be far more sophisticated and reflect the real-time use of the grid. Moving users from the peaks reduces investment needs across the entire network since usage at peak times is often a cost driver for new investments. In addition, grid tariffs should also stimulate consumption during peak renewable production times when demand is flexible, such as filling battery storage or charging electric vehicles, for example.
With the expected high additional deployment rates of distributed generation and demand (e.g. e-vehicles and electric heating), time-of-use and locational incentives are instrumental not just to incentivise network users to adapt their behaviour, but also to remove barriers, drive electrification and reduce overall energy bills. The widespread deployment of smart meters is a fundamental enabler to unlock the flexibility potential of time-of-use tariffs and, where deployment is lagging behind (45), it should be addressed with urgency to future proof the electricity system.
The central role of dynamic time of use (‘ToU’) tariffs was analysed by Agora Energiewende in a study focused on the potential for flexibility at household level in Germany (46). It found that the use of dynamic ToU grid tariffs can reduce grid expansion costs at the low voltage level by around 50% compared to the case where no price signals at grid level are present and flexibility only reacts to the market price signal. Furthermore, it found that households with dynamic tariffs could save EUR 600 per year in the long term. These significant financial savings also imply lower electricity costs for all consumers if dynamic time of use tariffs are widely used.
Moreover, with the rollout of electric vehicles, the benefits of flexible network use become more apparent. SmartEN (47) found that the costs of charging electric vehicles was up to 30% more expensive under a non cost-reflective tariff compared to the more cost-reflective network tariffs, demonstrating how tariffs can remove barriers to the deployment of electric vehicles. The benefits of smart charging was also studied by the Regulatory Assistance Project (RAP) who published a report in March 2025 (48) with a case study of the French region of Essonne. The required grid capacities were modelled considering low and high flexibility (based on time-of-use network fees) and a scenario with 10% of bidirectional charging. The study found that the annual costs of network reinforcements expected through to 2040 can be reduced to about EUR 2.1 million per year in the high flexibility scenario compared to EUR 2.8 million in the low flexibility scenario, a potential saving of 25% per year.
In 2023, ACER reported that ToU signals are more frequently used at distribution level compared to transmission level. The level of the complexity varies but 21 out of 28 countries apply static time-of-use charges in distribution tariffs and about one-third in transmission tariffs. While more advanced differentiation in time and location through fully dynamic tariffs could further increase tariffs’ cost-reflectivity and incentivise efficient network behaviour, NRAs need to balance this with complexity of design, the level of smart meter rollout in a given country and interplay with dynamic retail pricing. In the 2025 report (49), ACER provides an overview of the different ToU tariff designs that Member States currently have in place, including detailed analysis of the variety of designs, as well as the considerations that NRAs should keep in mind for their national design.

NRAs should include time-of-use elements in tariff structures, to correlate cost allocation with peak network usage in order to incentivise efficient use of the network. Different approaches can be used for time differentiation, from the simpler (e.g. peak/off-peak, seasons, weekdays/weekends) to the more complex (i.e. where smart meters can allow for a very dynamic time-of-use element).







Member State practices –Spain, Sweden and Portugal





Spain and Sweden have introduced time-of-use elements to their network charges (50).
In Spain, the tariff structure applies energy and capacity-based charges (75% of the tariff is capacity-based at the transmission level and is 84.6% at the distribution level). Additional charges are levied for excess power withdrawal above the contracted capacity and the time-of-use element is divided into six periods, depending on the season, day of the week and time of day. The purpose of this pricing structure is to incentivise efficient behaviour, allowing for increased consumption outside of system peaks and therefore reducing the requirement for investment in electricity networks. The evidence suggests that this tariff methodology reduced transmission and distribution charges by 5.6% between 2019 and 2020. While the biggest savings are available to customers better able to adapt to price signals, even consumers who did not adjust their consumption at the low voltage level experienced a reduction on 0.6% in charges.
In Sweden, all DSOs will move to dynamic time-of use network tariffs from 2027. This highlights the needs for increasing automation and need to ensure customers are aware of the benefits of dynamic tariffs. The potential for flexibility is very significant, with 1.2 million (out of 4.7 million) households using an electric heat pump and the increasing penetration of electric vehicles. At transmission level, the tariff has a time-differentiated energy-based component, which is based on actual hourly market prices per bidding zone.

In Portugal, a pilot project
 (51)
was carried out at transmission level between June 2018 and May 2019 to study changes to the time-of-use structure of the network tariff for large consumers. The new time-of-use scheme that resulted from the project is characterised by a stronger signal in the peak periods and time-of-use schedules with regional differentiation (separating the grid into 3 areas). Based on the cost-benefit analysis, a net benefit of EUR 50 million was estimated to take place over a time horizon of 23 years, as a result of a demand response of 2.2% during the super peak period (approximately the 300 hours per year of highest usage). The main driver of the net benefit was the reduction or postponement of network investments due to lower peak demand.




d.   Locational elements

Locationally diversified network tariffs can incentivise efficient network behaviour of grid users in situations where the overall cost of network operation and necessary network expansion is also driven by pressures caused by injections/withdrawals in specific grid locations. This is particularly relevant in Member States which suffer from significant internal network congestion.
Network tariffs can in such circumstances help to provide network users with better incentives to adjust their behaviour so as to contribute to a lower overall congestion level. Locational signals, embedded into network tariff methodologies in the form of injection or withdrawal charges can, if properly designed, also support more efficient dispatch decisions, especially in large bidding zones. Locational incentives can also be included in consumer tariffs, with discounts for those consumers that locate in areas of surplus generation or existing robust grid infrastructure. This can be combined with other types of locational incentives.
Locational aspects can also be relevant for the network charges applied to generators for injection. Generators currently either do not pay any injection charges or very low injection charges in over 60% of Member States. According to ACER, in most Member States, the share of network charges paid by generation is small, at 13,7% for transmission charges and 4.1% for distribution charges in 2023 in those Member States that apply charges to generators. (52) The scope for injection charges is currently also limited by ranges set out in EU legislation (53). Where they are introduced, these injection charges could, for example, take the form of higher charges for generators locating in areas where there is a surplus of generation and low demand, and discounts for generators in areas of high demand and insufficient generation. Such charges should however be designed so as not to discriminate against specific types of generation (54) and synergies (e.g. the electrification of ports and offshore renewables deployment) should be considered. Locational incentives are particularly relevant in areas where grid upgrades are not a viable or cost-effective solution, although NRAs should be mindful that this does not avoid the need for strengthening the grid in areas with higher renewables potential.
Network tariffs therefore currently have only a limited effect in steering the behaviour and investment decisions of generators. In systems with internal congestion, the responsible NRAs could consider relying to a greater extent on injection charges as a way to reduce or time-shift peak supply in certain locations where the grid is particularly congested and thereby strengthen the relevant investment incentives and lead to a more secure operation of the system. They could also consider relying on a locational differentiated connection charging regime, as is the case in some Member States, to incentivise location of new system users more closely reflecting benefits for the overall energy system. (55)


NRAs should promote the use of locational signals in network tariffs as they provide signals for more useful siting of necessary generation and consumption on the grid. Attractive or reduced tariffs can stimulate consumption in places and at times where grid is available and demand is lower than available generation at that network location. Also injection charges can be a useful way to incentivise behaviour and investment decisions of generators. Where transmission and distribution-connected generators pay injection charges, these should be designed so as to include time-of-use and locational elements to alleviate congestion and incentivise the most efficient use of networks. They may be particularly relevant where grid upgrades are not a viable or cost-effective solution.







Member State practice – Denmark, Portugal and Romania
 (56)






Denmark has included several design elements in the network charges to enable locational incentives. It considers differentiated connection charges based on the geographical location of the network user (based on generation surplus areas versus demand surplus areas) and the use-of-network charges are also calculated by using a locational factor, whereby producers in areas with high demand surplus pay lower charges, thereby reducing bottlenecks. From 2023, injection charges apply for distribution costs (before only for transmission costs) and new legislation in 2023 also widened the possibilities for industrial-scale co-located production and consumption with one connection point to the grid with the aim of encouraging the co-location of RES and consumption. In addition, a locational element is also currently under consideration on the consumption side, similar to that of production.
In Portugal network tariffs are applied based on the voltage levels involved in transmitting energy from generation to consumption. The calculation depends on the location of the production installation used for self-consumption and whether there are energy flows from lower to upper voltage levels. (57)

In 2025, Romania introduced an injection charge for producers connected to the distribution system where electricity generated in part of the network exceeds demand and is transported to other parts of the network for consumption. The intention of the charge is to compensate for losses due to the transit of electricity. Previously it was only consumers who paid network charges at the distribution level and had to pay for the cost of losses due to the transit of electricity from the areas of surplus production. This injection charge is applicable to electricity producers with a capacity above 5MW and connected to two distribution networks (out of a total of eight networks). This new measure addresses the issue of appropriate cost allocation where those causing the network cost, in this case network losses, pay for it. In principle, the measure should function as an incentive for electricity producers to locate in zones with demand surplus.




e.   Specific calculation methods for certain user categories

Some NRAs apply specific tariff regimes and calculation methods to certain types of users, such as energy-intensive users, prosumers, energy communities, and other groups. Such specific tariffs regimes are often motivated by considerations of affordability and competitiveness of the user categories concerned. At the same time, such special regimes do not contribute to a lowering of overall network costs but merely shift these costs to other user categories.
These special tariff regimes are not excluded under the relevant rules but need to be justified by the relevant NRA in light of the broader principle of cost-reflectivity. Pure volume discounts or exemptions for specific users without any justification may not be in line with the cost-reflectiveness principle, for example. It would in particular be important to demonstrate that, bearing in mind the specificity of the grid in question, the consumption profile of the user category in question justifies the conclusion that they create less cost for the network per MWh of electricity consumed. In addition, as evolution in tariff design will incentive all grid users to use the system more efficiently, this will contribute to reduced system costs that will benefit all users.
In addition, in order to maintain an incentive for behavioural change of the relevant consumer groups, the NRA is recommended to combine special tariff regimes with the necessary conditions to justify their cost-reflectivity, e.g. by requiring that the relevant network users adjust their consumption profile, to the extent possible, in such as way as to lower the impact on the grid. Indeed, in certain conditions, specific types of users may contribute to reducing overall system costs in terms of their flexibility potential (e.g. bi-directional charging, energy communities). Network tariffs can be used to incentivise grid friendly behaviour from these specific users.


Special tariff regimes can be offered to specific classes of grid users; however, the NRA should provide objective grounds that these grid users, based on their consumption profile, have a lower impact on the overall cost of the electricity network.

f.   Storage

Energy storage comes in many forms and is increasingly important to the operation of a decentralised electricity system, based more and more on renewables. It can provide flexibility, stability and security for the electricity system and, in some cases, reduce the requirement for more expensive grid development. Flexibility becomes far more important as we increase renewables penetration (58).
There are many types of energy storage and they can provide different services to the electricity system. The applications are wide and include generation support (e.g. reduction of curtailment, system support), services to the transmission and distribution systems (e.g. investment deferral, voltage control), ancillary services and services to support consumption behind the meter (e.g. peak shaving, electric vehicle integration including system support from bi-directional charging (59), management of cost by reacting to time-of-use signals). Storage operators do however require the correct incentives so that investments take place at the right locations and so that charging and discharge happens when they lower overall system costs. If charging and discharging instead happens with no consideration of the congestion status on the grid, the rising share of storage would instead contribute significantly to the challenges of cost-effective grid management.
Grid tariff methodologies should most importantly be designed so as not to hinder the development and roll-out of storage. This in particular prevents charging regimes whereby storage sites are subjected to double-charging (60), i.e. needing to pay both generation and consumption charging.
Network tariffs can also make a contribution towards setting the right investment and behavioural incentives for storage operators. To achieve this, NRAs should carefully consider whether full exemption regimes, whereby the storage operators do not make any contribution to network cost recovery, are justified in line with the cost-reflectiveness principle. Depending on the specificities of the national system in question, it may in this context be necessary to differentiate between storage sites based on their location and the time at which they charge and discharge. ACER (61) recommends that if a network user both withdraws from and injects into the grid, both network uses should be considered when setting the tariffs, by properly taking into account the potential cost-offsetting effect and the overall cost-impact to the network.

Network tariffs for electricity storage can be used to incentivise grid friendly behaviour by storage operators, to direct storage investments to the most appropriate areas and to incentivise charging/discharging at times of most utility to the electricity system. Tariff regimes should account for the particularities of storage, avoid “double charging” of storage facilities and be mindful that this could discourage deployment of storage assets, while reflecting the overall cost-impact of the storage on network costs.

g.   Role of public budget

Given the pressure on electricity bills, the need for significant investments into the grid and the necessity to ensure the affordability of electricity and the competitiveness of our industry, Member States may choose to allocate funding to the electricity network from the general government budget, including via allocating specific part of cohesion or other available EU funding to grid investments (62). Such injections of public funds to support overall network costs can be considered in line with the applicable legal requirements and the principle of cost-reflectiveness provided they meet a number of requirements:






—


The injection of public funds must be done in a non-discriminatory way and cannot selectively favour specific user categories;










—


The amount injected must be sufficiently limited so as to preserve the level playing field between Member States and so as to ensure that the incentive effect of network charges on consumer behaviour is preserved;










—


The injection should only cover the additional costs resulting from measures to accelerate decarbonisation and market integration, such as interconnectors, major network upgrades or offshore grid connection infrastructure and certain specific needs in the network such as investments that reduce waiting times for grid connections. For example, the injection of public funds can in this context enable faster depreciation for grid investors and avoid price spikes for consumers.




While the benefits of additional funding for investments are clear, these investments are not made in a vacuum, since the NRA and System Operators will generally have an agreed multi-annual investment plan with a focus on efficient investments in place already. Member States should therefore coordinate closely with the NRA on the integration of any allocation of public funding for this purpose, notably ensuring consideration to all societal costs and benefits in public support allocation. Member States and NRAs should monitor the share of network costs covered by public funds versus the share borne by network users. This can help to ensure that all funding is spent efficiently (63).
Where public support is used, it is important to ensure that it is targeted and results in overall positive gains for the economy. It should therefore not delay investments in certain infrastructure or distort the optimal location of power plants. In this context, NRAs should periodically assess the macro-economic costs and benefits of the public support for networks for the economy.
The role that Member States can play in de-risking particular infrastructure investments is also explored in the Commission Guidance on Anticipatory Investments for developing forward-looking electricity networks, published in June 2025 (64).

Members States are allowed to inject general government funds into the overall network charges budget within the applicable legal framework, provided this is done in a non-discriminatory manner, does not favour particular categories of network users, does not undermine incentives to adjust behaviour so as to lower overall system costs, and only covers the additional costs resulting from measures to accelerate decarbonisation and market integration.

h.   Incentive based regulation of grid operators

The above considerations concern the allocation of the overall network costs to particular user categories and consumption profiles. The overall affordability of the energy system and grid is however also dependent on the way the compensation for network operators is calculated. This has to be done in such a way as to provide the best possible incentives for grid operators to reap any potential for cost-efficiencies.
As explained above, Article 18 of the Electricity Regulation already requires a shift to a total expenditure (ToTex) approach which considers both capital and operational expenditure. Furthermore, Articles 32 and 51 of the Electricity Directive (65) require that network development plans include the use of demand response, energy efficiency, energy storage facilities or other resources as alternatives to system expansion. This provision incentivises transmission and distribution system operators to fully consider whether OpEx-intensive solutions which provide for a more effective use of the existing grid are viable alternatives to more costly investments in new grid infrastructure. For example, in France, the NRA expects (66) that appropriately reflecting flexibility solutions as an input to grid capacity sizing should bring significant savings for the power system; savings for the TSO alone are estimated to be nearly EUR 7 billion over fifteen years. Furthermore, the French DSO ENEDIS is testing the use of flexibilities (overlapping between consumption and production and between sectors, balancing, local flexibility) to optimise the sizing of its grid in a project expected to bring EUR 250 million savings by 2035 (67).
NRAs can go further than this and introduce more incentive-based regulation for grid operators. Traditionally incentive-based regulation and system operator performance has mainly focused on reliability of supply, number of outages and their length. However, in a more interconnected and changing environment, and given the increasing need for regional and international coordination, NRAs could also consider new performance incentives around innovation (such as use of grid enhancing and digitalised technologies), cooperation and adherence to deadlines for joint TSO and DSO projects at EU level. In the recent past, a large amount of projects have been implemented with significant delays, sometimes up to several years of delays. These delays implicitly represent significant welfare loss opportunities for the EU end-consumers. Therefore, NRAs could cooperate to identify key projects with a collective responsibility for TSOs (whether at EU or regional level), and collectively implement incentives for timely delivery in the design of network tariffs.
At national level, NRAs could also incentivise TSOs to better contribute to a more integrated electricity market by partly linking network tariffs design with the EU level targets such as the minimum 70% threshold to make available for trade in Article 16(8) of the Electricity Regulation (EU) 2019/943.
Last, to build on the current best practice sharing that takes place via ACER’s biennial exercise on tariff reporting, NRAs could look into systems to compare performance, such as peer reviews or comparative benchmarking for cost-effective grid management at both TSO and DSO level. For DSOs, in particular, this could be linked to key challenges and their new responsibilities under EU legislation covering topics such as waiting times for grid connection (68), climate resilience, methods for accommodating more decentralised resources and promoting flexibility and digitalisation such as smart grid indicators.

To ensure cost-effective grid operation and the delivery of important projects contributing to the integrated market, NRAs should assess the potential for incentive-based regulation and adapt the related set of performance indicators and benchmarks for network operators.







Member State practice – France and Belgium





In February 2025, the French NRA CRE has finalised the network tariff design for the next four years.
Under this design, CRE implemented several incentives measures, in particular on the optimal use of the interconnectors (and the application of the 70% minimum threshold), the speed of grid connections offers to users and the lifting of barriers to the use of flexibility solutions by system operators. CRE will apply enforcement measures as regards the French TSO’s connection to the balancing platforms by introducing a financial incentive to connect to the PICASSO platform by April 2025 and a monthly penalty that increases progressively for each additional month of delay.
In Belgium, the NRA CREG issued a Decision (69) supporting the Innovation Plan of the TSO in December 2024. The innovation incentive contained in the tariff is recurring and aims to counteract the traditional CapEx bias by reducing the risk borne by the TSO when pursuing particularly ambitious innovation projects. Funding is allocated to each project is based on the expected costs and benefits. The NRA ensures that network users receive a fair share of the benefits from (successfully completed) innovation projects through reduced tariff-related costs and/or increased quality of services provided by the TSO.




i.   Managing the Transition to a Future Proof System

As explained above, a more future-proof network tariff system has the potential to lower the cost of managing and upgrading the electricity grid and can therefore contribute to a more affordable electricity system for grid users.
However, abrupt changes in network charge design can also create significant short-term impacts on individual consumers and generators. NRAs therefore need to be mindful of the short-term distributional impacts of any change and should design the shift to a more future-proof network tariff system in an inclusive and transparent manner. Electricity bills – and the network tariffs contained in them - have to be understandable and transparent for the population to drive the behavioural change needed for a more cost-effective power system, as well as accompany energy consumers to understand how they could benefit from lower prices by better supporting energy system integration. Energy consumers, empowered by clear public information, will have the possibility to benefit from lower network charges by better supporting flexible energy system use.
To foster public acceptance of the shift to a more future-proof network tariff system, the relevant changes should as much as possible be accompanied by broad stakeholder consultations allowing interested user groups to contribute.
Changes to network tariff methodologies should be announced with sufficient advance notice, so as to give users time for the necessary adjustments to their behaviour and consumption patterns before a new system enters into force. Network charges methodologies should provide the necessary certainty and predictability.
Finally, it can also be justified to accompany the introduction of new network tariff methodologies with temporary solutions for specific user categories (for example, certain industrial processes, which may be currently less flexible) which provide voluntary opt-in elements or phase-in certain changes to their network tariff exposure over longer periods.

A well-planned and careful approach to household and industrial consumers is required to enable users to adapt to the design of more cost-reflective tariffs. Thorough stakeholder involvement and a gradual phase-in of the relevant changes should be envisaged to manage short-term effects on particular user categories.

VII.   Conclusion

A fully decarbonised electricity system will enable European consumers to benefit from affordable homegrown energy, enhancing the EU’s competitiveness and energy security. To achieve this ultimate goal, a fit-for-purpose tariff methodology is required to ensure that the benefits of decarbonisation will be felt by all consumers through cheaper renewable electricity and more affordable network charges on their bills.
The way that the cost of the network is assigned to different user categories bears significant unused potential for a more cost-efficient use of the existing electricity grid. When this potential is fully realised, it can help to maintain affordability and direct investment to where it is the most needed while limiting the investment needs in the grid and increasing the ability of the grid to absorb a greater share of renewable generation and supporting energy system integration.
To achieve these gains, a significant shift in the way network costs are currently allocated in many Member States is needed. Whilst the principle of cost-reflectiveness remains key for the design of network tariff methodologies by NRAs, the application of this principle needs to reflect the changing needs of the electricity system as regards the integration of renewable generation, rising levels of network congestion and rising flexibility needs.
Instead of being purely dependent on the overall amount of electricity consumed or the capacity of the network connection, network users should be better incentivised to adapt their behaviour to optimise the use of the electricity system.
To ensure that the shift to such an incentive based system is as smooth as possible and does not put an excessive burden on individual user categories, NRAs should make the necessary adaptations with sufficient advance notice to allow users to adapt and provide for gradual phasing in where possible, thereby ensuring certainty and predictability for network users. NRAs should continue to share best practice and maintain an ongoing exchange with ACER on tariff design. Finally, NRAs should continuously monitor the effectiveness of their tariff designs to ensure they are cost-reflective including price signals that can support efficient investment decisions and optimised use of the network, ultimately benefitting European consumers. The Commission will follow up with NRAs and ACER through a workshop to further share best practice and assess the implementation of this Guidance.


(1)  ACER (2025) Key developments in European electricity and gas markets https://www.acer.europa.eu/monitoring/MMR/electricity_gas_key_developments_2025.

(2)  
            Final report Trinomics/European Commission: Investment needs of European energy infrastructure to enable a decarbonised economy, 2025.

(3)  ACER (2024) Electricity infrastructure development to support a competitive and sustainable energy system: https://www.acer.europa.eu/sites/default/files/documents/Publications/ACER_2024_Monitoring_Electricity_Infrastructure.pdf.

(4)  ACER (2024) Retail market Monitoring report: https://www.acer.europa.eu/sites/default/files/documents/Publications/ACER-CEER_2024_MMR_Retail.pdf.

(5)  This is without prejudice to the exclusive competence of the European Court of Justice to authoritatively interpret Union law.

(6)  Article 11 of the Electricity Directive (EU) 2019/944 requires that consumers have access to dynamic electricity price contracts.

(7)  ACER (2025) highlights the significant room for improvement in applying time-of-use elements to transmission and distribution tariffs and its increasing importance with further penetration of distributed generation and flexible resources (e.g. batteries, electric heating and EVs). https://www.acer.europa.eu/sites/default/files/documents/Reports/2025-ACER-Electricity-Network-Tariff-Practices.pdf.

(8)  In ACER’s report tariff setting is described as a three-step process:
first, the allowed or target revenues of the system operators (including the remuneration method for TSO or DSO costs) are determined. second, the tariff structure is defined. third, the costs/revenues are allocated to each of the tariff structure’s items (i.e. charges paid by network users).
(See ACER tariff report 2025, p. 71-72).

(9)  Article 59(1)(a) of the Electricity Directive.
In section 6.2 of the ACER report on network tariff practices (2025), ACER refers to drawbacks in the publication of tariff information and provides a list of recommendations that should be followed to enhance transparency requirements (Article 18 of the Electricity Regulation).

(10)  Article 57 of the Electricity Directive.

(11)  Regulation (EU) 2019/943 of the European Parliament and of the Council of 5 June 2019 on the internal market for electricity (the ‘Electricity Regulation’).

(12)  Directive (EU) 2019/944 of the European Parliament and of the Council of 5 June 2019 on common rules for the internal market for electricity and amending Directive 2012/27/EU (the ‘Electricity Directive’).

(13)  Case C-718/18 European Commission v Federal Republic of Germany, Judgment of 2 September 2021.

(14)  Case C-767/19 European Commission v Belgium, Judgment of 3 December 2020.

(15)  Case C-378/19 European Commission v Prezident Slovenskej republiky, Judgment of 11 June 2020.

(16)  In the 2020 judgment against Slovakia Case C-378/19 European Commission v Prezident Slovenskej republiky, Judgment of 11 June 2020., the Court held that “
            the power to nominate and dismiss the board of the national regulatory authority or, in the absence of a board, its top management must be framed strictly in legislation and exercised on the basis of objective criteria which are clearly and exhaustively set out and verifiable
            ”. Furthermore, the “
            power of nomination and dismissal must … be exercised in such a way that the independence of that authority is guaranteed […]
            ”.

(17)  Article 57(5)(b) of the Electricity Directive.

(18)  Regulation (EU) 2024/1747 of the European Parliament and of the Council of 13 June 2024 amending Regulations (EU) 2019/942 and (EU) 2019/943 as regards improving the Union’s electricity market design, and Directive (EU) 2024/1711 of the European Parliament and of the Council of 13 June 2024 amending Directives (EU) 2018/2001 and (EU) 2019/944 as regards improving the Union’s electricity market design.

(19)  Article 18 para (1-3) Electricity Regulation (EU) 943/2019.

(20)  Commission notice on Guidance on anticipatory investments for developing forward-looking electricity networks (2025).

(21)  
            2025-ACER-Electricity-Network-Tariff-Practices.pdf.

(22)  Article 18, para (1 &2) of the Electricity Regulation (EU) 2019/943.

(23)  In order to promote innovation and move away from CapEx bias in grid investment, RAP advocates allowing for revenue-capped cost recovery based on total expenditure and rewarding system operators for specific performance outputs that promote the energy transition to incentivise network innovation.

Incentivising Network Innovation – RAP Blueprint.

(24)  Action 12 in ACER, Unlocking flexibility: No-regret actions to remove barriers to demand response


A new approach for a changing world | Frontier Economics.

(25)  
            Directive (EU) 2024/1711 of In the European Parliament and of the Council of 13 June 2024 amending Directives (EU) 2018/2001 and (EU) 2019/944 as regards improving the Union’s electricity market design.


(26)  As announced in the Industrial Action Plan for the European automotive sector and the European Steel and Metals Action Plan (2025), the European Commission will put forward a guidance on managing grid connections in Q4 2025.

(27)  Connections that are not guaranteed to be able to export or import the full power requirement at all times.

(28)  Electricity consumption in the EU is expected to increase by around 60% by 2030 (EU Action Plan to accelerate the roll-out of electricity grids for Grids, 2023).

(29)  Between 60-90% of new connections are at distribution level (Clean Energy Package Impact Assessment, 2016).

(30)  JRC 2023 “Flexibility requirements and the role of storage in future European power systems”.

(31)  Importantly, there is significant capacity on distribution grids outside of the peak times – the average utilisation of the network at low voltage level in the EU is between 2-21%. JRC (2018) DSO Observatory.

(32)  Dynamic tariffs encourage an implicit change in consumer behaviour, while flexibility procurement brings explicit change behaviour through contracted arrangements.

(33)  ACER (2025) https://www.acer.europa.eu/sites/default/files/documents/Publications/2025-ACER-Electricity-Network-Tariff-Practices.pdf.

(34)  
            https://open.overheid.nl/documenten/e914cc94-ffcd-42dd-9989-bf7c3fdd44f9/file.

(35)  Agora Energiewende and Forschungsstelle für Energiewirtschaft e. V. (2023): The benefits of energy
flexibility at home https://www.agora-energiewende.org/fileadmin/Projekte/2023/2023-14_DE_Flex_heben/A-EW_326_energy_flexibility_at_home_WEB.pdf.

(36)  SmartEN (2025) https://smarten.eu/wp-content/uploads/2025/03/FTI-Consulting-Report_smartEn_03-2025_DIGITAL_V2.pdf.

(37)  SmartEN (2025) The study used the cost of EV charging as a proxy for electrification and found that an annual subscription charge could bring a reduction of 8.1%, a 3-part Time-of-Use element, seasonal subscription charge, a benefit of 13.8% and the dynamic volumetric tariff 23.7% compared to a flat, volumetric tariff. https://smarten.eu/wp-content/uploads/2025/03/FTI-Consulting-Report_smartEn_03-2025_DIGITAL_V2.pdf.

(38)  ACER report on network tariff practices, 2025.

(39)  
            Electricity price statistics - Statistics Explained - Eurostat

See Figure 5 for the share of transmission and distribution costs paid by domestic customers.

(40)  Clean Energy for all Europeans Package, Impact Assessment, 2016.

(41)  Grids for Speed (2024) https://powersummit2024.eurelectric.org/wp-content/uploads/2024/07/Grids-for-Speed_Report_FINAL_Clean.pdf.

(42)  SmartEN (2025) https://smarten.eu/wp-content/uploads/2025/03/FTI-Consulting-Report_smartEn_03-2025_DIGITAL_V2.pdf.

(43)  ULB Demand Flex project (2025) https://demandflex.polytech.ulb.be/en/publications-1.

(44)  EI (2025) “Utformning av tariffer för överföring av el”
            https://ei.se/om-oss/lagar-och-regler/stallningstagande.

(45)  In 2023, the percentage of consumers with smart meters was under 50% in 11 EU Member States: https://www.acer.europa.eu/sites/default/files/documents/Publications/ACER-CEER_2024_MMR_Retail.pdf.

(46)  Agora Energiewende and Forschungsstelle für Energiewirtschaft e. V. (2023): The benefits of energy
flexibility at home https://www.agora-energiewende.org/fileadmin/Projekte/2023/2023-14_DE_Flex_heben/A-EW_326_energy_flexibility_at_home_WEB.pdf.

(47)  SmartEN (2025) https://smarten.eu/wp-content/uploads/2025/03/FTI-Consulting-Report_smartEn_03-2025_DIGITAL_V2.pdf.

(48)  RAP (2025) https://www.raponline.org/wp-content/uploads/2025/03/RAP-ICCT-Hildermeier-Jahn-Schmidt-Bernard-Ragon-Basma-Savings-from-smart-charging-electric-cars-trucks-in-Europe-Mar-2025.pdf.

(49)  ACER (2025) Best Practice Report.

(50)  ACER (2025) Best Practice Report.

(51)  ACER (2023) Best Practice report & https://www.erse.pt/atividade/consultas-publicas/consulta-p%C3%BAblica-n-%C2%BA-101/abertura/


(52)  ACER report on network tariff practices (2025) https://www.acer.europa.eu/sites/default/files/documents/Reports/2025-ACER-Electricity-Network-Tariff-Practices.pdf.

(53)  
            Commission Regulation (EU) No 838/2010 on laying down guidelines relating to the inter-transmission system operator compensation mechanism and a common regulatory approach to transmission charging. Justification set out in recital 10, i.e. that a range is established so that variations in transmission charges paid by producers should not undermine the internal energy market.

(54)  Article 18(2)(f) requires tariff methodologies to contribute to the achievement of the objectives set out in the integrated national energy and climate plans.

(55)  There are locational signals for producers in Denmark, both in injection and in connection charges.
See ACER report on network tariff practices (2025)

https://www.acer.europa.eu/sites/default/files/documents/Reports/2025-ACER-Electricity-Network-Tariff-Practices.pdf.

(56)  ACER report on network tariff practices (2025) https://www.acer.europa.eu/sites/default/files/documents/Reports/2025-ACER-Electricity-Network-Tariff-Practices.pdf.

(57)  ACER (2025) 2025-ACER-Electricity-Network-Tariff-Practices.pdf.

(58)  Based on Commission projections, the penetration of renewables in Europe will increase to 69% of demand by 2030 and 80% by 2050. To accommodate this, the levels of flexibility will have to increase to 24% (288 TWh) of electricity demand by 2030 and to 30% (2,189 TWh) by 2050. https://joint-research-centre.ec.europa.eu/jrc-news-and-updates/future-eu-power-systems-renewables-integration-require-7-times-larger-flexibility-2023-06-26_en.

(59)  Bi-directional charging allows electric vehicles to not only draw power from the grid to charge their batteries but also send electricity back to the grid or power devices when needed.

(60)  Article 15(5) of the Electricity Directive (EU) 2019/944.

(61)  ACER (2023) Best practice report on tariffs.

(62)  To the extent that public funds are used to support system operators in legal or natural monopoly activities, this may not be subject to State aid control (see points 373 to 375 CEEAG and the Commission Notice on the Notion of State aid. Where this is not the case, State aid approval can be required (see for instance case SA.113565, decision of 21 June 2024, on the German hydrogen core network). This is without prejudice to an assessment under State aid provisions and guidelines.

(63)  To the extent that public funds are used to support system operators in legal or natural monopoly activities, this is may not be not subject to State aid control (see points 373 to 375 CEEAG and the Commission Notice on the Notion of State aid. Where this is not the case, State aid approval can be required (see for instance case SA.113565, decision of 21 June 2024, on the German hydrogen core network ). This is without prejudice to an assessment under State aid provisions and guidelines.

(64)  Commission notice on Guidance on anticipatory investments for developing forward-looking electricity networks (2025).

(65)  Electricity Directive (EU) 944/2019, as amended. Articles 32(3) “
            The network development plan shall also include the use of demand response, energy efficiency, energy storage facilities or other resources that the distribution system operator is to use as an alternative to system expansion”
             & Article 51(3) “
            When elaborating the ten-year network development plan, the transmission system operator shall fully take into account the potential for the use of demand response, energy storage facilities or other resources as alternatives to system expansion, as well as expected consumption, trade with other countries and investment plans for Union-wide and regional networks.”
            


(66)  CRE (2023) “Report on the performance of system operators in the development of a smart electricity grid”
            https://www.cre.fr/fileadmin/Documents/Rapports_et_etudes/2023/2024-02_Rapport_indicateurs_eng.pdf.

(67)  Agora Energiewende (2024) “Boosting flexibility in distribution grids”
            https://www.agora-energiewende.org/fileadmin/Projekte/2023/2023-23_EU_boosting_flexibility/24-0184_Rev.2_DNV_Report_Agora_Energiewende_-_Boosting_flexibility_in_distribution_grids.pdf.

(68)  To further support national processes, the Commission plans to publish a Guidance on Grid Connection in Q4 2025.

(69)  CREG (2024) https://www.creg.be/fr/publications/decision-b658e/90#:~:text=Sur%20les%2014%20propositions%20de,aux%20crit%C3%A8res%20de%20l'incitant.


ELI: http://data.europa.eu/eli/C/2026/126/oj
ISSN 1977-091X (electronic edition)