Storage for System Strength: Store smartly for a sustainable, affordable, and secure system

STORE SMARTLY FOR A SUSTAINABLE, AFFORDABLE, AND SECURE SYSTEM

November 2025

“Europe is facing three major challenges: achieving independence from Russian gas; addressing the worsening effects of climate change; and maintaining competitiveness— keeping energy prices affordable for industry and citizens. Not having energy storage in the system is like receiving a toy on Christmas morning that has no batteries.

DAN JØRGENSEN, European Commissioner for Energy and Housing

Storage for System Strength builds on Elia Group’s previous work across the European energy landscape, including our earlier analyses on flexibility needs and system integration, by zooming in on the evolving role of energy storage. It is also a call to action for how we can unlock the full potential of storage, responsibly, sustainably, and strategically.

Energy storage systems in general and batteries specifically are a cornerstone of the future. They offer the potential to integrate renewables, support consumers and industries alike, and stabilise the grid.

As a key player in electricity transmission, supplying more than 30 million end users, Elia Group firmly believes in their strategic value for the grid. But the current storage surge has become a major strategic concern for grid operators, consumers, and regulators alike. The solution will therefore be one where we join

Today’s acceleration, marked by an increasing number of speculative projects, is creating severe pressure on grid capacity. Both Belgium and Germany, along with many other European countries, are facing a surge in connection requests that threatens to overwhelm our grids. In Germany alone, the volume of projects for TSOs amounts to a load equivalent to 100 million households. This is not a sign of healthy growth, rather it is a symptom of a system under strain.

The current “first come, first served” regulatory approach is being exploited by some actors who prioritise short-term profit. These so-called “zombie projects” clog the queue, delay other more mature projects, including data centres and industrial facilities and risk driving up costs for all consumers.

But this study goes further. How, where, and when storage operates also significantly impacts the future of the grid. As storage scales up, its behaviour increasingly impacts system efficiency and stability. Addressing both connection and operational integration is essential for ensuring that storage delivers value commensurate with the challenges we are facing today.

It is time to act.

it is time to prioritise mature, system-relevant projects. It is time to optimise where and how to operate storage to ensure grid efficiency. It is time to integrate flexibility, renewable generation, and storage as interconnected pillars to build a more sustainable, affordable, and secure energy system.

Rethinking the current approach will enable storage to unlock its full potential as a true ally of the system rather than an issue to solve. As one of the only companies with TSOs in two European countries, Elia Group stands ready to bring a European perspective and its expertise on the challenges the electrical system is facing today.

As guardians of the grid, we will continue to ensure security of supply, and enable economic development in the public interest, ensuring that our infrastructure remains a foundation for prosperity, resilience, and climate neutrality.

Frédéric Dunon Bernard Gustin Stefan Kapferer

CEO Elia CEO Elia Group CEO 50Hertz Transmission Belgium

© Bildquelle: LEAG Clean Power

Elia Group’s The Power of Flex study examines flexibility in Europe’s electricity system, focusing on consumer participation and decentralised solutions. It identifies storage as a key enabler for managing peak demand and integrating renewables. Battery storage is noted for its fast response and grid support potential. The report calls for scaling residential and utility-scale storage through market incentives and regulation, and stresses integrating storage into wider flexibility strategies alongside demand-side management and digital controls.

Elia Transmission Belgium publishes its Belgian Electricity system blueprint for 2035-2050. The study provides insights into Belgium’s options regarding its future energy mix and evaluates their technological and economic impacts. It finds that without a clear policy regarding electricity supply towards 2050, Belgium will likely end up in the most costly scenario. The study highlights the growing volatility of the energy system and the resulting importance of unlocking demand-side flexibility and storage across the system to manage this volatility. This will be essential for managing the energy system in the most cost-effective way and for limiting the economic curtailment of renewable energy sources.

FOCUS OF THIS STUDY

This Viewpoint study addresses key challenges related to energy storage within the electricity system, as defined by the European Union:

Energy storage means, in the electricity system, deferring the final use of electricity to a moment later than when it was generated, or the conversion of electrical energy into a form of energy which can be stored, the storing of such energy, and the subsequent reconversion of such energy into electrical energy or use as another energy carrier.

Electricity storage is more than deferral of energy over time. Alongside flexible generation (e.g., thermal generation units, renewable modulation, and so on), flexible demand (e.g., electrical vehicles, heat pumps, demand-side response, and so on) and interconnectors, storage has an important role in increasing the flexibility of the power system.

Elia Group publishes its Roadmap to Net Zero study on building a climateneutral European energy system by 2050. It concludes that Europe’s direct electricity demand can be met only if RES expansion triples and more interconnectors are built to balance uneven RES distribution. Interconnectors also smooth weekly wind fluctuations and reduce local supply dips. Short term flexibility such as storage and other means is key to balance the system in the short term.

The study Warmer Lichtsturm - Umgang mit Erzeugungsspitzen aus PV und Wind prepared within the framework of the 50Hertz Scientific Advisory and Project Board, examines the expected scope of the challenge of generation peaks from solar and wind power production. The analysis identifies a range of generation- and demand-side measures, including storage, to manage generation peaks, especially from PV. It is a conceptual short study that explores various possible solution approaches.

The latest Adequacy and Flexibility Study for Belgium, which covers the period 2026–2036, identifies energy storage, amongst other technologies, as a valuable enabler of system adequacy and flexibility in Belgium’s evolving electricity landscape. Significant growth in large-scale battery storage is anticipated. By 2036, largescale batteries are expected to significantly increase their share in the contribution to fast up- and downward flexibility, depending on the future generation mix. The study underscores the need for strategic integration of storage solutions, together with flexible demand and modulation of renewables, to ensure system resilience and cost-efficiency.

This study considers storage for the electricity system as assets that withdrawal electricity, store it in any kind of energy form and re-inject electricity at a later stage (also known as “power-to-power”). Other sector-coupled energy storage technologies, such as power-to-heat, power-to-cold or power-to-molecules, also store energy but are considered as flexibility providers from the perspective of the electricity grid.

The focus of the study is on the impact of storage on grids and the broader electricity system, aiming to identify how its benefits can be leveraged for the energy transition. While the analysis centres on battery energy storage systems (BESS), it also touches on long-duration energy storage (LDES) and emerging battery technologies. To meet the flexibility needs of the system, energy storage should be considered alongside other demand and generation flexibility as well as grid build-out.

Focus of this study: Storage for the electricity system

THE STUDY AIMS TO ADDRESS THE FOLLOWING KEY QUESTIONS

How can storage, on different timeframes, support RES integration alongside other flexibility providers?

2|What steps are needed to ensure energy storage is deployed and operated in line with grid and system needs to unlock its full potential system benefits?

3|How can energy storage contribute to a secure power system?

Over the past year, Elia Group has held discussions with over 50 companies, associations, universities, and think tanks to outline the Storage for System Strength study. We would like to sincerely thank the stakeholders below for their valuable input and feedback. The views and opinions expressed herein are those of Elia Group only.

THE STORAGE SURGE

ALIGNING MOMENTUM WITH SYSTEM REALITIES

“Energy storage technologies deliver major system savings across Europe. As deployment grows, storage will increasingly provide key grid services and take on more advanced roles—supporting stability, reliability, and decarbonisation. To realise these benefits, the EU legislative framework must evolve—ensuring fit-forpurpose grid connection procedures, stronger temporal and locational signals, and streamlined permitting.

The storage surge in Europe is well underway. While today large-scale battery projects are gaining momentum, storage has a much longer history. Pumped hydropower storage has been fundamental for over a century, and more recently smallscale batteries, such as home batteries, have been increasing. The conditions for batteries are evolving. Declining costs, supportive legislation, and attractive markets are all fuelling the rapid rise in large-scale battery projects and grid connection requests, also increasingly at higher voltage levels. In Belgium and Germany alone, large-scale battery connection requests at the TSO level already amount to nearly 250 GW.

Storage is an important technology in the transition to a decarbonised electricity system. Its versatility enables greater integration of renewables, contributes to the flexibilisation of grid offtake and delivers fundamental system services. Batteries, for instance, can smoothen electrical vehicle charging peaks, reducing stress on the grid. Other types of storage also have the potential to improve the competitiveness of electrification, enabling applications such as thermal storage operated in conjunction with an electrical heat pump.

However, speculative grid connection requests, driven by the current “first come, first served” approach and limited grid hosting capacity availability, are clogging the connection pipeline. The current volume of connection requests exceeds system requirements in prospective studies by as much as a factor of ten for 2040. It also

surpasses the capacity identified in grid development plans by a factor of two to ten in capacity. It, however, remains uncertain whether all of these projects will materialise, given the evolving market conditions. Nonetheless, the presence of mature projects backed by private investment is a strong sign of confidence in the energy transition.

Battery storage grid connection requests at TSOs

While this strong interest in additional storage is encouraging, it also brings challenges related to capacity allocation and operational integration. Purely marketdriven storage operation lacks visibility for intrazonal grid conditions, since these are not reflected in market prices. This can further aggravate already stressed areas in

the grid. Establishing the right frameworks now will help ensure that the storage surge strengthens the grid, rather than strains it.

Developing a decarbonised and affordable grid infrastructure of the future, maintaining an operationally secure grid, while unlocking the necessary flexibilities in

a timely manner, requires a multi-faceted approach. According to our analysis the following three solutions are invaluable conversation starters for ensuring that the battery storage surge contributes positively to the development of the electricity system of the future.

Battery storage connection requests in relation to grid planning

In relation to Federal Development Plan for 2034 (2022 version) in Belgium and Grid Development Plan (NEP Netzentwicklungsplan) for 2037 in Germany (2025 Scenario Framework)

“To be resilient against price shocks and geopolitical threats, it is crucial to integrate cheap renewable electricity into our grid. Whereas a modern and resilient grid is one cornerstone of the future energy system, sufficient storage capacity will always be an indispensable part. All storage technologies must play a role and should always be equally prioritised like renewables generation and grid modernisation.

ANNA STÜRGKH, Member of the European Parliament

CLERENS,

3 K Y M SSAG S

FROM BUILDOUT TO BEHAVIOUR

FROM VOLUME TO VALUE

Today’s grid connection process, often organised on a “first come, first served” basis, is no longer fit for purpose. Grid connection capacity should be allocated in alignment with policy objectives and the connection of mature projects should be prioritised.

A comprehensive revision of the process must address queue access management, study process, and capacity allocation in a holistic and coordinated way to ensure that limited available grid capacity is used in the broader interest of society.

As battery storage scales up rapidly, its operation must become grid aware. Today, battery storage operates in a grid-unaware manner, as market prices do not necessarily reflect local grid situations. This behaviour can increase redispatch costs, which in turn may necessitate additional grid buildout, leading to higher grid tariffs. Flexible Connection Agreements, introduced in the Electricity Market Design Reform of 2024, along with temporal and locational grid tariffs can provide grid signals to promote grid-neutral behaviour or even incentivise grid-beneficial operation.

FROM STORAGE TO SYSTEM SERVICE

Storage is a key pillar of the energy transition and must evolve from a market-driven role to providing essential system services, alongside renewables and other technologies.

Yet storage alone cannot deliver the full solution, we also need demand-side flexibility and renewable generation modulation. One critical gap remains: long-duration storage, which is indispensable for maintaining system resilience during extended periods of low renewable output, especially as the share of thermal power plants declines.

Storage is essential for the transition to cheaper and cleaner energy. It needs to be permitted and connected to the grid ASAP. And priority should be given to those storage investments that are of the most strategic value. Don’t do first come first serve. Identify the projects that matter most and get them permitted and grid-connected now.

FROM VOLUME TO VALUE FUTURE PROOFING GRID CONNECTION PROCESSES

Today’s grid connection process is still often organised on a “first come, first served” basis. While this principle is not explicitly advanced in European legislation, it was originally assumed by many national authorities as the way to level the playing field among grid user candidates. This approach is, however, no longer fit for purpose when it comes to building a grid that enables societal objectives outlined in national development plans, such as renewable integration and decarbonisation through electrification. It now gives rise to several challenges, particularly when one technology grows faster than anticipated and risks taking a disproportionate share of grid hosting capacity, leaving little left for other critical grid user categories, such as industry, renewables and so forth. Additionally, low entry barriers combined with limited grid connection availability and large application volumes fuel speculative applications. Lengthy connection queues hinder the realisation of mature projects that are ready to move forward.

We need a forward-looking approach that enables consistent and strategic grid development, creating a new and fairer playing field among all grid users and candidates. We must ensure that grid capacity is developed and allocated in line with policy objectives and in the broader interest of society. Additionally, introducing readiness and maturity criteria would help prioritise mature projects over speculative reservations.

A comprehensive revision of the grid connection process should address queue access management, study process, and capacity allocation in a holistic and coordinated way. Ultimately, the allocation of limited grid hosting capacity should also consider the impact on the system and society.

Connections reform is a key step to unlocking the investment required for a pipeline of projects that will drive growth, create jobs, and enable cleaner grid connections. We are implementing necessary reforms in Great Britain, creating the space for shovel-ready projects that are aligned with both current and future system needs, such as energy storage and other technologies.

GILES DICKSON, Chief Executive Officer, WindEurope

FINTAN SLYE, Chief Executive Officer, National Energy System Operator

An energy system based on renewable energy needs energy storage facilities, still the huge number of battery storage flooding the networks causes problems. Only with smart incentives that lead to an optimised integration of battery storage we can use their full potential, which we need for our efficient and sustainable energy system.

FROM BUILDOUT TO BEHAVIOUR

LEVERAGING GRID AND MARKET SIGNALS FOR ENHANCED BATTERY INTEGRATION

As large-scale battery storage scales up rapidly, its role within the energy system must evolve accordingly. Today, market prices, which do not capture local grid situations, drive storage operations. This results in storage being operated in a gridunaware way as it lacks the signals needed to guide assets toward more grid-beneficial or grid-neutral behaviour.

The impact of storage operation can be illustrated with a German example. According to our study for a load dominated region of Germany, a storage unit operating grid-unaware can increase already existing redispatch needs.

Grid-unaware behaviour contributes to rising redispatch costs, which in turn may necessitate additional grid buildout, leading to higher grid tariffs. Currently, storage faces no financial signals to align with grid needs, yet their impact on costs is ultimately borne collectively by grid users through tariffs. Without timely and well-designed updates to the regulatory framework, this trend risks system inefficiencies, this trend risks leading to system inefficiencies.

What does the figure show?

It remains an important question where storage facilities are deployed and how they are operated. As long as storage lacks clear signals to operate in a grid-neutral or gridbeneficial way, overloads may be created and additional grid expansion needs may rise.

To address this challenge, several short-term and long-term solutions are proposed. When selecting and implementing these measures, transparency and predictability for all parties should be key guiding principles.

Effect of grid-unaware BESS operation on TSO redispatch volume

Modelled based on historical DA and ID auctions for a load dominated region

The bars represent the volume of a TSO redispatch for a Germanspecific study of the spot market of 2024. They show how grid-unaware operation of battery storage of a given size, has decreasing and increasing effects on this volume.

What does this tell us?

Grid-unaware operation of storage can aggravate congestion and increase redispatch needs.

A distributed deployment of storage, both geographically and across all voltage levels, optimises overall system costs.

Co-locating storage with renewable generation further improves overall cost reductions. Importantly, our analysis shows that a system-optimal buildout of storage correlates strongly with solar PV volumes. This is because batteries are ideally suited for short-duration storage, enabling them to effectively integrate the daily fluctuations and peaks in solar generation.

Correlation of battery locations with other resources and load in the high-voltage transmission system

Result of a system optimisation with investments in grids and batteries for

Each dot represents one zone

What does the figure show?

The scatter plots visualise for each simulated zone in Europe, how much battery capacity is installed in relation to solar PV, wind and demand respectively. The trend line denotes the correlation index.

does

this tell us?

The installed capacity of solar generation correlates strongly with battery capacity. Both technologies are a good match for the efficient operation of the power system.

“Flexibility is the key enabler to integrate renewable energy into Europe’s grids. Battery storage plays a dual role: it strengthens flexibility by balancing variable generation and demand, and it enhances system stability through fastresponse capabilities. To unlock its full potential, system operators across the EU must recognise these capabilities and ensure they are properly valued in market and regulatory frameworks. This is why we need a clear EU flexibility strategy, one that prioritises storage and demand-side solutions to deliver a resilient, decarbonised energy system for all Europeans.

WALBURGA HEMETSBERGER, Chief Executive Officer, Solar Power Europe

Storage operation can impact the grid in different ways. Grid-straining storage operation can lead to higher peaks and, consequently, the need for more capacity and increasing system costs. Ideally, storage should be operated gridbeneficially to reduce peaks, allowing more grid users to connect while potentially also reducing grid buildout needs. To prevent inefficiencies of grid-straining behaviour, different measures are currently considered. Ensuring grid-neutral or gridbeneficial operation will require a balanced combination of regulatory and market instruments.

“Energy storage will play a critical role in integrating the rapidly increasing capacity of variable renewable energy, and TSOs across Europe currently report a rapidly increasing number of grid connection requests from batteries. For a cost-efficient energy transition, a holistic and coordinated approach to system planning is key. Batteries should be situated in locations that help alleviate grid congestion and that they follow a grid-friendly dispatch schedule, thus reducing overall system costs.

1| Optimising the use of available grid capacity via Flexible Connection Agreements

First among these instruments are Flexible Connection Agreements (FCAs), a tool introduced in the Electricity Market Design Reform of 2024, which promote grid-neutral operation and enable faster connection of grid users while maintaining system security. An FCA allows, under a set of agreed conditions, to limit and control the electricity injection into and withdrawal from the grid. This ensures that limited grid hosting capacities are used more efficiently, allowing more grid users to access the grid. However, FCAs alone are not a solution for congestion as a whole. While FCAs effectively prevent new congestion, they do not resolve existing ones. As such, FCAs represent an important first step toward grid-neutral behaviour, but they must be complemented by additional instruments such as temporal and locational signals to fully unlock storage’s benefits. Further development could also explore permanent FCAs, potentially incentivised through reduced grid tariffs to encourage flexible grid usage.

What does the figure show?

The curves show a hypothetical daily load curve and the impact of various storage operations on this load. The illustration focusses on the effect of increased or decreased peak loads due to storage charging and discharging as well as fluctuations and ramps.

What does this tell us?

Achieving grid-aware

BESS operation with FCAs

Modelled based on historical DA and ID auctions of 2024 for a load dominated region in Germany

*Grid-unaware storage has unintended effects on existing congestion. Depending on the region, the net effect is either positive or negative.

only TSO level considered, calculation of BESS dispatch in DA and ID market with perfect foresight. The battery can adapt its dispatch in DA market once it received the FCA signal.

Results may look different in an alternative climate year or with different trading strategies.

The energy transition will rely on flexible solutions that include storage technologies. These solutions will help the electricity system meet Europe’s decarbonisation targets while remaining reliable and affordable. A supportive regulatory framework around grid connection processes will be key to accelerate the integration of storage solutions, optimise the use of existing infrastructure, and enable grid-friendly operations. Acting now will strengthen system flexibility and resilience, ensure the best use of network capacity, and safeguard Europe’s long-term security of supply. At ENTSO-E, we are committed to work with legislators and partners to make this happen.

What does the figure show?

What does this tell us?

The mode of storage operation has a direct impact on peak load and volatility in power flows in the system. With grid-beneficial operation, the required grid capacity is reduced.

The plot illustrates how the operation of a battery storage in the spot market can affect grid congestions by either alleviating or aggravating them. Two cases are compared, where the battery is either operating grid-unaware or (at least) grid-neutral through the adoption of a flexible connection agreement (FCA).

FCAs do not induce increasing RD needs (by definition) and hence reduce the net redispatch needs. Redispatch cost savings exceed market revenues losses of batteries.

GERHARD CHRISTINER, Spokesman of the Board & Chief Technical Officer, Austrian Power Grid AG

Distinction

“Flexibility is the cornerstone for a renewable-based energy system, with energy storage technologies as its key enabler for balancing supply and demand in electricity, heat, and mobility. The storage market is ready: technologies are proven, and companies plan to invest over €200 billion in the coming years. What is now required is swift political action and a modern regulatory framework to unlock this potential and remove outdated barriers. This will create new value chains, drive innovation and keep Germany and Europe competitive in the global clean-energy market. Energy storage is no longer optional. It is the central enabler of a resilient, decarbonised, and cost-efficient energy system.

2| Ensuring operational predictability by limiting schedule changes

In Germany, limiting schedule changes is discussed as a means to prevent unexpected grid congestion resulting from short-term energy trading. By restricting a part of the asset’s installed capacity from last-minute power schedule changes, this mechanism helps reduce uncertainty around dispatch schedules and power flows, for example as a reaction to renewable forecasts changes. This approach maintains the flexibility needed to adjust to updated renewable forecasts closer to delivery, while ensuring operational predictability. It also allows for more energy storage to enter the grid without blocking grid access entirely.

Limiting schedule changes Trigger: Generation forecast drops significantly shortly before delivery

of schedule (market-based) + change towards more feed-in - change towards more withdrawal change not allowed change allowed Without limitations Change of schedule

3|

Temporal and locational signals

Temporal and locational signals in grid tariffs incentivise storage operation that supports grid efficiency. Through welldesigned, forward-looking tariff structures, storage operators could receive clear signals to align their operations with both market and grid needs. Such signals can indicate times and places with congestion through, for instance, higher tariffs. These signals could also financially incentivise grid-beneficial behaviour, for instance, through lower or even negative tariffs.

Achieving grid-aware BESS operation with price signals

Modelled based on historical DA and ID auctions of 2024 for a generation dominated region in Germany

What does the figure show?

The plot illustrates how the operation of a battery storage in the spot market can affect congestions in the grid by either alleviating or aggravating them. Three scenarios are compared in an analysis for the German day-ahead and intraday market of 2024, they differ in the price signals visible to the battery.

4| Behind-the-meter integration

What does the figure show?

As a reaction to the market situation, BESS located at a connection point with already heavily loaded lines, could cause an n-1 violation by feeding in additional electricity. Limiting the direction of schedule changes at selected places and certain times will facilitate to avoid such n-1 violations. Other BESS connected elsewhere will then provide the flexibility needed for the market.

What does this tell us?

Selected limitations of schedule changes will reduce congestion and related redispatch costs. It will also facilitate grid operations, while it is not compromising on the flexibility provided by the system as a whole.

What does this tell us?

Price signals can contribute to reducing redispatch. Especially when applied to offtake and injections. Negative grid tariffs incentivise redispatch-decreasing operation.

“With renewables scaling rapidly, the way we operate the electricity system is changing fundamentally. Storage will be key to enhancing flexibility and ensuring resilient, futureproof system operations. At the same time, we must ensure that appropriate operational and locational signals guide storage deployment so that it strengthens—rather than strains—the grid.

Behind-the-meter (BTM) integration of storage helps optimise existing grid connections and enhances overall grid efficiency. By being exposed to the limits of an existing grid connection, storage is more grid-aware and can even help to flatten

existing grid-user peaks. While front-ofthe-meter (FTM) set-ups currently benefit from a favourable regulatory framework, BTM configurations represent an important step towards more grid-aware storage. Regulatory frameworks should be designed to reflect the value each configuration brings to the energy system. As well as encourage both configurations to operate in a grid-neutral or even grid-beneficial way.

MANON VAN BEEK, Chief Executive Officer, Tennet

URBAN WINDELEN, Executive Director, Bundesverband Energiespeicher Systeme

“FROM STORAGE TO SYSTEM SERVICE ENABLING STORAGE TO SERVE THE SYSTEM HOLISTICALLY

“The Alps and the Nordics are Europe’s natural batteries, and pumped storage hydropower is the most mature, cost-efficient and scalable long-duration energy storage technology.

To meet our LDES needs, we must build momentum behind an ambitious pipeline of pumped storage hydropower projects. This will unlock flexibility, strengthen resilience and spur clean industrial growth.

Flexibility, renewable generation, and storage are all essential for achieving a more sustainable, affordable, and secure energy system. Demand-side and generation flexibility have the potential to already go a long way towards achieving system costs savings, our simulations project savings of up to around 13%. The model minimises system costs while expanding battery and cross-zonal transmission capacities under three flexibility scenarios, with respect to demand response, heat pumps, and electrical vehicles, for 2050. When battery storage is included in these calculations, the savings potential rises to around 15%.

As the share of thermal power plants in the energy mix declines, storage should expand its role as needed provider of grid services.

TSOs rely on ancillary services, such as balancing and voltage management, that were traditionally delivered by thermal units. Already today, and even more in the coming years, storage, alongside other technologies, will need to provide these essential services.

System resilience can also be strengthened by storage -alongside backup power plantsduring Dunkelflaute (periods of low wind and solar PV infeed) or Lichtsturm (periods of very high solar PV and wind infeed). This will require the timely development and deployment of innovative long-duration storage technologies to be able to cope with longer periods of low renewable energy infeed.

This shift is not optional: large-scale storage must evolve from a purely market-oriented actor to a core provider of system services, extending beyond the balancing markets. Frameworks should evolve so that batteries optimise from a system perspective and not only a market perspective. In the coming years, this evolution includes more advanced roles in voltage control, inertia provision and black start. However, the technical capabilities and procedural prerequisites to deliver these services are not yet fully available. For example, to provide inertia or black start services, storage systems must be equipped with grid-forming inverters.

What does the figure show?

The plot illustrates the relative cost savings for the European energy system in a 2050 scenario, comparing different levels of flexibility and battery deployment. The flex scenarios vary in the capacity of (flexible) consumption by electric vehicles, heat pumps and industrial demand response (see Information Box 1.1 in Chapter 1 for a detailed description).

What does this tell us?

Storage is, next to other flexibility means, an important contributor in making the energy transition more affordable.

The pathway to net-zero is possible, ongoing, and it requires robust renewables and electricity grid development, coupled with system-wide flexibility. Flexibility is a single term but encompasses a wide range of technologies and approaches, including storage, that should address diverse system and temporal needs. Locational and market signals need to guide investments and reward system services, thus, contributing to optimising the energy system and related costs. This will avoid additional stress on the grid and allow for viable business cases.

ANTONELLA BATTAGLINI, Chief Executive Officer, Renewables Grid Initiative

PAUL WILCZEK, Head of Energy Policy, Climate and Sustainability, Eurelectric

CALL TO ACTION

At Elia Group, we aim to co-create a robust framework for storage deployment and operations. That’s why we have already launched several initiatives and are committed to continuing the dialogue with all stakeholders.

We, Elia Group, also call on the European Institutions, Member States, and regulatory authorities to .

... introduce futureproofing grid connection processes provide clear recommendations in the European Grids Package and guidance on grid connections to:

• allocate grid connection capacity per technology in line with the main objectives of the Member States policies and societal ambitions

• prioritise the connection of mature projects: a “first needed and ready, first served” principle

• introduce readiness and maturity criteria to prioritise mature projects over speculative reservations

… integrate batteries by leveraging grid and market signals

ensure that future operational solutions for storage integration prioritise transparency and predictability for all stakeholders. As more BESS units connect to the grid, it becomes increasingly important to promote grid-beneficial or at least grid-neutral operation

in the European Grids Package and guidance on grid connections, provide recommendations to inspire national implementation of Flexible Connection Agreements (FCAs) across all voltage levels enabling faster connections while maintaining system security

continue to investigate temporal and locational signals for storage systems to incentivise optimal system use. These signals should reflect both network conditions and market conditions to ensure alignment between grid and market efficiency

…enable storage to serve the system holistically

continue to promote and activate consumer and generation flexibility alongside storage deployment, and provide policy priority actions to address key barriers in the upcoming Electrification Action Plan

step-up research and innovation funding for grid-supporting storage setups under Horizon Europe

establish clear technical requirements for BESS in line with the European Electricity Market Directive and Regulation to enable key ancillary services such as balancing, voltage management, black start, and inertia

update without delay the Connection Network Codes so all grid-connected assets, including storage, contribute to system security and resilience

unlock long-duration flexibility and energy storage in a timely manner

which will be essential to strengthen security of supply in a net-zero energy system

S TTING TH STORAG SC N

NAVIGATING THE BATTERY STORAGE SURGE: MAPPING

THE DRIVERS BEHIND THE BOOM

Europe is witnessing a transformation in its energy landscape. In recent years, battery energy storage has surged forward at an unprecedented pace, surpassing installation records year after year. By 2024, the European total battery fleet

had surpassed the 60 GWh mark, with around 22 GWh of new capacity added in that year alone (by comparison the total installed capacity in 2023 was around 39 GWh). This is a clear sign that battery momentum is growing (see Figure 0.1).

Development of BESS capacity in Europe (EU-27, UK, and Switzerland) FIGURE 0.1

Battery energy storage systems (BESS) come in various forms: from large-scale installations to commercial and industrial setups, and residential systems. The latter, often paired with rooftop solar photovoltaic (solar PV), are increasingly popular among households seeking energy independence and sustainability. Across Europe, grid connection requests for large-scale BESS are rising sharply. How these systems are integrated and operated will play a pivotal role in shaping the future of the electricity system.

The concept of electricity storage is far from new. For over a century, there has been pumped hydropower storage (PHS). Since the advent of the energy transition, this technology has been key in integrating variable renewable power production into the electricity system, providing energy storage, grid stability, and flexibility2 In 2024, Europe had 56 GW of PHS installed, with an additional 187 MW added that year3 The current surge in battery storage, however, is distinct in both its speed and scale. It is the rapid deployment and overwhelming volume of battery storage connection requests that truly set this new era apart.

in the European Union’. Available online: https://setis.ec.europa.eu/hydropower-and-pumped-hydropower-storage-european-union-0_en (last accessed on 14/11/2025).

3 International Hydropower Association (IHA). ‘Region Profile: Hydropower in Europe’. Available online: https://www.hydropower.org/region-profiles/europe (last accessed on 14/11/2025).

“Storage systems, such as pumped hydropower and large- or small-scale batteries, are an essential part of the energy transition. They can help balance renewable generation with demand, for example by shifting midday solar output to evening peak periods, and by enabling better integration of renewable electricity into the grid. To achieve this, we need geographically and temporally differentiated price signals that also consider network utilisation.

MIRA WENZEL, Project Lead, Energy Transition in the Power Sector, Agora Energiewende

ZOOMING IN: REAL-WORLD EXAMPLES

Belgium: Growing battery momentum

By the end of 2024, more than 990 MW of battery storage was connected to the Belgian grid. Of this, large-scale batteries represented approximately 250 MW, with an average duration of 2.8 hours4 The bulk of battery storage capacity is found in residential and smaller-scale installations connected to the distribution grid, with the largest of Belgium’s seven DSOs alone accounting for around 740 MW. Rapid growth in storage is anticipated at the transmission level: by the end of 2025, large-scale BESS capacity is expected to reach more than 540 MW, more than doubling within a year. In the distribution grid operated by the largest DSO, storage capacity is also forecast to increase, though at a more moderate pace, reaching around 860 MW.

Germany: Residential transformation

Germany presents a striking example of how battery storage can potentially reshape national energy systems. Since January 2020, the country’s installed battery capacity has skyrocketed from just over 1 GW to nearly 14 GW by August 2025 (see Figure 0.2a). Residential storage has been the primary driver of this growth, expanding from 0.51 GW to 11.7 GW in under six years. Large-scale battery installations have also grown, albeit more modestly, from 0.48 GW to 2.16 GW5

But the story does not end there. When looking at planned installations, the scale becomes even more striking. Available and new grid connections at the 380 kV level are limited. At the same time, grid connection requests are evidently massively oversubscribed. There are more than 200 GW of battery projects in the pipeline at the 4 TSOs in Germany alone (see Information Box 2.6).

4 Elia Transmission Belgium (2025). ‘Adequacy and flexibility study for Belgium. 2026-2036’. June 2025. p. 142. Available online: https://www.elia.be/en/electricity-market-and-system/adequacy/adequacy-studies (last accessed on 14/11/2025).

5 ISEA, CARL, and E.ON Energy Research Center at RWTH Aachen University (2025). ‘Battery Charts’. Available online: https://battery-charts.de/de/home-de/ (last accessed in Oct. 2025) and Figgener, J., Hecht, C., Haberschusz, D. Bors, J., Spreuer, K. G., Kairies, K.-P., Stenzel, P., Sauer, D. U. (2023). ‘The development of battery storage systems in Germany: A market review (status 2023).’ DOI: 10.48550/arXiv.2203.06762.

6a ISEA, CARL, and E.ON Energy Research Center at RWTH Aachen University (2025). ‘Battery Charts’. Available online: https://battery-charts.de/de/home-de/ (last accessed in Oct. 2025) and Figgener, J., Hecht, C., Haberschusz, D. Bors, J., Spreuer, K. G., Kairies, K.-P., Stenzel, P., Sauer, D. U. (2023). ‘The development of battery storage systems in Germany: A market review (status 2023)’. DOI: 10.48550/arXiv.2203.06762.

6b TSO: cumulative BESS in operation. Note: the 2025 figure includes BESS that are expected to be in operation by the end of the year.

6c DSO: installed power at DSO Fluvius, Fluvius (2025). ‘Energieopslagsystemen die gekoppeld zijn aan het distributienet’. Available online: https://opendata.fluvius.be/explore/dataset/1_22-energieopslagsystemen-gekoppeld-op-distributienet/information (last accessed on 16/10/25) [1kVA converted to kW with factor 1].

WHY A BATTERY ENERGY STORAGE SURGE?

With installations increasing and grid connection requests pilling up, what is driving this battery surge?

Declining battery costs

Since 2010, average costs of lithium-ion batteries have fallen by 90%, along with significant improvements in energy density and lifespan, compared to lead-acid batteries. The expansion of electromobility and advances in batteries for electric vehicles have spill-over effects that benefit batteries used for storage applications7 While 9 out of 10 lithium-ion batteries are currently used for transport electrification, the requirements for battery storage in the electricity system differ. Unlike electric vehicle batteries, which must be energy-dense, compact, and lightweight, BESS prioritise low cost and durability8 Declining costs translate into

falling battery prices. Prices for lithium-ion battery packs have been decreasing substantially over the past ten years (see Figure 0.3) due to various factors including cell manufacturing overcapacity, economies of scale, low metal and component prices, adoption of lower-cost lithium-iron-phosphate batteries, and a slowdown in electric vehicle sales growth9

In 2024, the global average lithium-ion battery pack cost dropped to 115 USD/kWh making BESS increasingly economically attractive. This represents only part of the costs associated with large-scale BESS. Additional costs (not included in the

battery pack) encompass, among other things, engineering, procurement and construction, grid connection (including inverters, equipment, and potentially transformers), and system controls and communication. While battery pack prices may continue to decline, these other cost components have already become more dominant. As a result, further reductions in overall battery system costs are likely to be limited. This also explains why it can be economically viable to use a battery intensively for just a few years and then replace it, since the battery itself represents only part of the total cost.

“The fastest growing parts of the energy transition—solar PV, batteries and electric vehicles—all require robust and streamlined processes for grid connection to ensure they’re able to continue their upward trajectory. These sectors together accounted for $1.3 trillion of the $2.1 trillion invested in the energy transition globally in 2024 and this share is set to rise even further this year.

7 International Energy Agency (2024). ‘Batteries and Secure Energy Transitions.’ World Energy Outlook Special Report. April 2024. p. 11 and p. 19.

8 International Energy Agency (2024). ‘Batteries and

9 BloombergNEF (2024). ‘Lithium-Ion Battery Pack Prices See Largest Drop Since 2017, Falling to $115 per Kilowatt-Hour: BloombergNEF’. 10 Dec. 2024. Available online: https://about.bnef.com/insights/commodities/lithium-ion-battery-pack-prices-see-largest-drop-since-2017-falling-to-115-per-kilowatt-hour-bloombergnef/ (last accessed on 14/11/2025).

10 BloombergNEF (2024). ‘Lithium-Ion Battery Pack Prices See Largest Drop Since 2017, Falling to $115 per Kilowatt-Hour: BloombergNEF’. 10 Dec. 2024. Available online: https://about.bnef.com/insights/commodities/lithium-ion-battery-pack-prices-see-largest-drop-since-2017-falling-to-115-per-kilowatt-hour-bloombergnef/ (last accessed on 14/11/2025).

COLIN MCKERRACHER, Head of Clean Transport & Storage, BloombergNEF

“The European market for battery storage is forecasted to grow by a factor of 15 between 2024 and 2030, supporting energy security, energy affordability and decarbonisation across Europe. Policymakers, network operators, asset owners, and system providers must jointly ensure that storage can unlock its full value, from grid-forming capability to network congestion management and beyond, based on cybersecure and robust global supply chains.

SARAH VAN CLEVE, Vice President, Sales & Commercial Excellence (EMEA), Fluence

A compelling business case for BESS with revenue stacking

Currently, investments in BESS present an attractive business case. They potentially offer revenue opportunities across a broad spectrum, from wholesale energy market arbitrage to ancillary services and hedging strategies. By dynamically adjusting their charging and discharging cycles, BESS can leverage multi-market optimisation to maximise revenue, based on price differences across various market segments right up to the hour of power

delivery11 Currently, the BESS business case is very attractive in the balancing market segment. In the future, the business case is expected to shift to spot market arbitrage that utilises, for example, the price differences between the day-ahead and intraday market (see Figure 0.4 for the sequence of power markets). BESS developers increasingly look into multi-stakeholder contracts as well as tolling agreements to secure long-term revenue.

Integration of variable renewable power generation

BESS help flatten out variable renewable power generation if they are operated accordingly and thereby contribute to system integration of renewables. Largescale BESS operators can contribute to system balancing through market participation, including related balancing and reserve markets. Additionally, BESS has the technical capability to provide ancillary services that are necessary for the secure and reliable operation of the system. As decarbonisation targets lead to a lower share of conventional synchronous generators in the power system, storage (alongside renewable power producers) can become a key provider of ancillary services. The establishment of markets for ancillary services, such as inertia procurement and black start capability, creates additional revenue opportunities for BESS operators while helping to integrate inverter-based renewable power producers like wind power and solar PV that could, for example, not provide black start on their own.

Another driver for the BESS surge is related to the residential and commercial behindthe-meter deployment. Behind-the-meter BESS refers to customer-sited stationary storage systems that are connected on the customer’s side of the meter12 In contrast to front-of-the-meter BESS, such as largescale battery storage that is connected either to the transmission grid or to the distribution grid, behind-the-meter BESS follows a different operation strategy. Often paired with rooftop solar PV systems — and potentially with charging systems for electric vehicles, heat pumps, or building energy management systems — residential behind-the-meter BESS is commonly used to optimise energy production and consumption behind the meter, delivering cost savings for households. This approach enables local optimisation by integrating on-site domestic solar PV production with home storage and household consumption, all managed behind the grid connection point. This may or may not align with a more global system optimisation.

Favourable policy and legislative framework conditions for storage

In addition to compelling market opportunities, favourable legislative and regulatory framework conditions for energy storage can further enhance the attractiveness of the business case for BESS operators. Such framework conditions include grid-fee exemptions, targets for storage capacity, research and development funding, as well as support schemes for storage operation and investment support upfront. For example, in Germany, there are grid fee exemptions for electrical energy storage systems until 202913 In Greece, there is a support scheme for the development of energy storage facilities based on a tendering procedure particularly benefitting BESS14 15 In Ireland, BESS are exempted from generation transmission use of system charges, leaving charges based solely on demand (demand use of system charges). Nonetheless, BESS is still exposed to 85% of the network charges there16 Importantly, the business impact on storage does not only depend on the policies in place, but also on their actual design and how they act in concert.

Naturally, the regulatory framework and policies adopted at the national level are only one part of the framework. These are embedded in the more expansive EU framework (see Deep Dive: Energy Storage Within the EU Framework in Chapter 0).

13 §118 (6) German Energy Industry Act. Available online: https://www.gesetze-im-internet.de/enwg_2005/__118.html

14 Aposporis, H. (2025). ‘Greece plans 4.7 GW of commercial battery storage projects’. March 14, 2025. Balkan Green Energy News. Battery. Available online: https://balkangreenenergynews.com/greeceplans-4-7-gw-of-commercial-battery-storage-projects/ (last accessed on 16/11/2025).

15 European Association for Storage of Energy (EASE) (2024). ‘State Aid: Overview of Greek Scheme to Support the Development of Electricity Storage Facilities’. Available online: https://ease-storage.eu/wp-content/uploads/2024/10/2024_EASE_StateAid_Greek_LINK.pdf (last accessed on 14/11/2025).

“Storage is flexibility made tangible: a Swiss Army knife that can integrate renewables at dawn, stabilise grids at noon, and defer infrastructure investments by dusk. But Swiss Army knives don’t replace toolboxes. We still need grids, backup, and cost discipline. Storage is an enabler, not an escape hatch.

Battery Energy Storage: Frequently Asked Questions’. Greening the Grid. Energy Storage Toolkit. Available online: https://docs.nrel.gov/docs/fy21osti/79393.pdf (last accessed on 14/11/25).

16 Economic Consulting Associates Limited (ECA) (2025). ‘Network charges for energy storage. Final Report’. 21 March 2025. Available online: https://www.energystorageireland.com/wp-content/uploads/2025/03/1070_Network-charges-for-energy-storage_210325.pdf (last accessed on 14/11/2025).

RUBEN BAETENS, PHD, Institute Coordinator, KU Leuven Institute for Energy and Society

WHY IS THE INCREASE IN BESS SIGNIFICANT?

Thanks to decreasing costs and different types of application, BESS has been growing in recent years and is expected to grow even further (see Figure 0.5). While residential storage accounts for a large part of the past increase in battery storage capacity17 in the future greater portions of BESS are expected to come from largescale installations with several gigawatts in the pipeline18

“With a shift to electricity, the time of energy use will grow in importance and end users will play an increasing role in providing flexibility and storage capacity. It is urgent to create the regulatory framework for this development. Policymakers need a good understanding of how storage and flexibility contribute to an efficient energy system, to avoid the planning of an obese system.

What does this tell us?

This figure shows the expected BESS capacities in Europe, as assumed in Elia’s recent Adequacy and Flexibility study19 It follows two different European scenarios:

+ Current commitments (2025): sticking to ambitions and current political commitments and;

+ Constrained transition (2025): a delayed transition scenario as described in the study.

Large-scale BESS operators are projected to account for the bulk of new storage deployment in the coming years, and are expected to follow a business strategy that is based on revenue stacking for maximising revenue. This does not explicitly account for the grid or system impact of BESS operation and location. It is, therefore, essential that the regulatory framework is revised to include effective provisions accounting for the grid and system impact of storage. Otherwise, large-scale deployment of BESS may cause unintended effects, such as higher grid expansion needs, increasing unpredictability and forecast errors arising from short-term schedule changes by BESS, fast ramps as a challenge for system stability, to name only a few. However, if appropriate framework conditions are in place, the system benefits for storage can be harnessed, turning it into a key enabler of the energy transition.

BESS can be key in enabling increasing shares of variable renewable power production and providing flexibility for the system, alongside controllable generation, flexible demand, and grid expansion. Now is the time to navigate the battery storage surge by setting the course for integrating BESS with a regulatory framework accounting for the grid and system needs right from the beginning.

17 SolarPower Europe (2024). ‘EU Market Outlook for Solar Power. 2024-2028’. Available online: https://www.solarpowereurope.org/insights/outlooks/eu-market-outlook-for-solar-power-2024-2028 (last accessed on 16/11/2025).

18 Elia Transmission Belgium (2025). ‘Adequacy and Flexibility Study for Belgium. 2026-2036’. June 2025. p. 58. Available online: https://www.elia.be/en/electricity-market-and-system/adequacy/adequacy-studies

19 Elia Transmission Belgium (2025). ‘Adequacy and Flexibility Study for Belgium. 2026-2036’. June 2025. p. 58. Available online: https://www.elia.be/en/electricity-market-and-system/adequacy/adequacy-studies

“Energy storage unlocks a new dimension in our energy system: For the first time, energy is not just produced or consumed— it can be shifted in time. This fundamentally solves one of the key challenges of the energy transition, making renewables reliable and secure. However, grid integration remains an issue. Even though batteries can physically support and stabilise the grid currently such behaviour is not incentivised. To fully realise these benefits, regulations must evolve to enable smart storage as a system asset.

NADINE BETHGE, Head of New Energy Systems, Association of Energy Market Innovators (bne)

ALMUT BONHAGE,

BEYOND BATTERIES: WHY STORAGE IS SO MUCH MORE

While the battery storage surge has received most of the attention recently, storage covers a broader range of technologies with varying technical capabilities. According to the EU:

Energy storage means, in the electricity system, deferring the final use of electricity to a moment later than when it was generated, or the conversion of electrical energy into a form of energy which can be stored, the storing of such energy, and the subsequent reconversion of such energy into electrical energy or use as another energy carrier20

The power of a storage system is measured in megawatts (MW), while its capacity is measured in megawatt-hours (MWh).

Storage can be considered a bridge between generation and consumption, as it can both withdraw or inject electric power into the system. In this respect, storage is neither generation nor consumption but constitutes a separate category in itself.

Depending on the type of storage, electrical energy is converted into potential, kinetic, chemical, or thermal energy:

Mechanical energy storage involves the direct storage of potential or kinetic energy. Along with thermal, it is one of the oldest forms of storage21 Examples include pumped hydropower storage, compressed air energy storage, flywheelbased energy storage systems, and gravity-based energy storage systems.

Electrochemical energy storage means that electrical energy is converted into chemical energy, and vice versa. It includes various types of rechargeable batteries, such as lead-acid batteries, redox flow batteries, and lithium-ion batteries. With their higher energy densities, lithium-ion batteries are the major driver behind the battery surge.

Electrical energy storage such as supercapacitors or ultracapacitors, uses electrostatic processes for storing energy. They are capacitors of high capacity and are frequently used for applications with fast charge and discharge cycles.

Thermal energy storage involves the storage of thermal energy for later use. It includes sensible heat storage, latent heat storage, thermo-chemical heat storage, thermal batteries as well as power-toheat storage systems that combine electrical boilers or heat pumps with thermal storage systems. When thermal storage is embedded in the heating sector, for example in heating networks, it also contributes to sector coupling, the decarbonisation across energy sectors.

Chemical energy storage such as power-to-gas or power-to-fuel, means that electricity is converted to and stored in the form of synthetic gases, such as hydrogen or methane or even in the form of fuels.

Energy storage extends well beyond batteries and includes a wide range of technologies with different technical characteristics, such as discharge duration, typical capacity and power, activation time, and round-trip efficiency.

Electrical

Thermal Storage

Chemical

Just as storage can be categorised by the form of energy conversion, it can also be distinguished by its discharge duration (see Figure 0.7 and Figure 0.8) and its activation time (see Figure 0.6). The activation time determines how fast a given storage technology can inject or withdraw electrical energy. Discharge duration indicates the length of time a storage technology is technically capable of providing power at its maximum output, or rated power, before its energy capacity is depleted23 This is called the nominal discharge duration.

While batteries mainly handle daily variations like those from solar PV, longerduration solutions, such as pumped hydropower storage, compressed air, and thermal energy storage cover broader variations.

Supercapacitors can quickly charge and discharge in just minutes or even seconds, which is a much faster rate than that of BESS. They are ideal for bridging short power disruptions and for delivering fast frequency response. Flywheels can be activated within seconds and discharge over minutes, making them a natural candidate for balancing short-term power fluctuations and for providing fast frequency response or fast reserves like frequency containment reserve.

23 National Renewable Energy Laboratory (NREL) (2019). ‘Grid-Scale Battery Storage. Frequently Asked Questions’. Grid Integration Toolkit. September 2019. Available online: https://docs.nrel.gov/docs/fy19osti/74426.pdf (last accessed on 16/11/2025).

24 Stute, J., Panitz, F. (Fraunhofer IEG, Fraunhofer Research Institution for Energy Infrastructures and Geotechnologies IEG) (2025). For references used for Figure 0.7, see Annex.

Large-scale lithium-ion battery storage systems activate within milliseconds and can discharge for hours, making them ideal for managing daily shifts in solar and wind generation. They also meet the conditions for ramping flexibility to address real-time variations in forecast errors25 if operated accordingly, and for contributing to balancing reserves. This type of short-term flexibility does not require delivery over a long duration.

Storage systems designed to balance generation and demand over extended periods, spanning several days or even weeks, just like seasonal cycles, have to

meet different requirements. Long duration energy storage (LDES) has a nominal discharge duration of at least eight to ten hours (depending on definition)26 and can extend towards several weeks. Depending on the nominal discharge duration (see Figure 0.8), there can be further differentiation into classical LDES (> 8 to 10 hours) and seasonal LDES (> 100 hours).

During times of low generation and high demand, such as doldrums with no solar and no wind power production, LDES can be a key contributor in filling this generation gap. Compressed air energy storage can be operated as long duration energy storage

from hours to weeks, depending on system design. Pumped hydropower storage offers a broad range of applications, with its duration, depending on capacity and system design, extending up to days or weeks27 To balance supply and demand over extended periods and across seasons, heat storage systems and the conversion of electricity into hydrogen, and back, become important solutions28

Energy round-trip efficiency is the percentage of electricity put into storage that is later retrieved29 The higher the roundtrip efficiency, the less energy that is ‘lost’ in the storage and conversion process. One of

the reasons for the recent surge in battery storage is the high round-trip efficiency (85 to 98%) of lithium-ion batteries (see Figure 0.6). The capacity of a storage system, how much it can charge or discharge, can be thought about just like a water tank. The larger the tank, the more it can absorb, store, and release. Market readiness and lifetime, that is, how many cycles a storage unit can be used, are other important factors impacting the commercial viability as well as the scope of technical applications of a storage technology.

25 Elia Transmission Belgium (2025). ‘Adequacy and Flexibility Study for Belgium. 2026-2036.’ June 2025. p. 70. Available online: https://www.elia.be/en/electricity-market-and-system/adequacy/adequacy-studies

26 According to a literature survey, while there is no uniform definition of LDES, the emerging consensus is even going towards 10 hours. In: Twitchell, J. et al. (2023). ‘Defining long duration energy storage’. Journal of Energy Storage 60. Available online: https://www.sciencedirect.com/science/article/pii/S2352152X22017753?via%3Dihub

27 vgbe energy e.V. (2024). ‘Hydropower in Europe: Facts and Figures’. Edition 2024. Available online: https://pulse.vgbe.energy/storedFile/b9a6ed24-c567-4e4d-80e7-d192a2afd986 (last accessed on 16/11/2025).

28 German Federal Ministry for Economic Affairs and Climate Action (2023). ‘Electricity Storage Strategy’. December 2023. Available online: https://www.bundeswirtschaftsministerium.de/Redaktion/DE/Publikationen/Energie/electricity-storage-strategy.pdf?__blob=publicationFile&v=6

29 U.S. Energy Information Administration (EIA) (2021). ‘Utility-scale batteries and pumped storage return about 80% of the electricity they store’. 12 February 2021. Available online: https://www.eia.gov/todayinenergy/detail.php?id=46756 (last accessed on 16/11/2025).

30 Panitz, F., Stute, J. (Fraunhofer Research Institution for Energy Infrastructures and Geotechnologies IEG) (2025) based on Rácz, V. (2025). ‘Exploring long-duration electricity storage solutions’. Presentation online workshop, Budapest.

Storage categories by nominal discharge duration30 FIGURE 0.8

DEEP DIVE: ENERGY STORAGE WITHIN THE EU FRAMEWORK

Energy storage is gaining importance within the European Union’s energy system, embedded in an evolving regulatory framework which seeks to reconcile decarbonisation with security of supply and affordability. The EU’s legislative trajectory reflects a clear recognition that large-scale electrification and the integration of renewable energy sources cannot be achieved without robust flexibility solutions, with storage playing a central role.

The Clean Energy Package laid the regulatory foundation, which introduced provisions for flexibility markets and consumer participation, while restricting TSOs and DSOs from owning storage except under strict conditions where the market fails to deliver. These principles remain, but recent reforms have significantly expanded the scope for storage deployment. The Electricity Market Design Reform, adopted in 2024, introduced structural changes to stabilise

electricity prices and enhance system flexibility. It seeks to empower consumers and suppliers to participate more actively in the power and balancing markets, through demand-response and storage solutions among other options. Also, the reform mandates to provide an option for market-based participation of storage in balancing and capacity mechanisms and enables the use of sub-metering for flexibility services, including storage.

Looking ahead, the EU is preparing a new wave of initiatives that will further shape the role of storage. The Clean Industrial Deal (2025) sets out a roadmap for competitiveness and decarbonisation, accompanied by non-binding but influential guidance on anticipatory investments, grid and storage infrastructure, and network charges. These guidelines aim to accelerate permitting processes, reduce administrative barriers, and ensure that tariff structures support system efficiency

without undermining investment signals in the Member States. The Deal is complemented by the Clean Industrial Deal State Aid Framework, which provides targeted flexibility for Member States to support storage projects, including through capacity mechanisms and industrial decarbonisation measures.

In parallel, the Action Plan for Affordable Energy seeks to address cost pressures, while the forthcoming Electrification Action Plan will outline strategies to accelerate electrification across sectors, which is expected to further amplify the need for storage as a flexibility backbone.

The upcoming European Grids Package will introduce legislative proposals to strengthen cross-border grid planning and streamline permitting for both grid and storage projects. This package will be accompanied by EU guidance on grid connections, designed to remove bottlenecks such as the “first come, first served” principle, and harmonise

connection procedures across Member States.

Together, these measures signal a decisive shift: storage is no longer a peripheral technology but an integral component of the EU’s internal electricity market design and its long-term climate neutrality goal until 2050. Its regulatory treatment, including market access, grid tariff design, state aid, and permitting, will determine the pace and scale of deployment.

FOR STORAGE TO BENEFIT THE SYSTEM,

WE NEED TO ACT NOW

The decarbonisation of the electricity sector is key for achieving the EU’s climate neutrality target by 2050 31 With battery deployment growing rapidly alongside traditional PHS, a mix of storage technologies is needed to enhance decarbonisation, affordability, and security of supply. Unlocking their full potential necessitates a consistent regulatory framework that considers grid and system needs from the outset.

1|

First, storage plays a vital role among the various types of flexibility needed to support the integration of renewable energy and drive decarbonisation. To keep the energy transition affordable, storage should be considered alongside demand-side and generation flexibility.

2|

Second, the location of storage is important, while grid-beneficial and grid-neutral operation is essential. We need a mix of reliable and efficient instruments with temporal and geographical signals to leverage storage strategically in line with grid and system needs.

3| Third, storage contributes to system security, reliability, and adequacy while also providing ancillary services. However, the uncertainty of power flows resulting from near-real-time trading brings short-term congestion risks that need to be addressed by targeted measures.

Decarbonisation involves electricity, heating, transport, and industry. For the electricity sector, integrating variable renewables, managing weather-related forecast errors, and electrifying heating require flexibility over different time spans and at different voltage levels. BESS can manage daily output variations, while long-duration energy storage addresses fluctuations over extended periods. Additionally, storage can support the electrification of the heating sector by enabling the use of periods when renewable power production is abundant, and prices are low. Combining demand-side, generation, and storage flexibility reduces the need for extra battery storage.

Deploying and operating storage in line with grid and system needs requires temporal and geographical signals reflecting the grid situation in addition to market signals.

Flexible connection agreements (FCAs) for new BESS can help avoid congestion risks potentially caused by grid-unaware market-optimised operation and enable more storage access to the grid. In the future, dynamic grid tariffs may incentivise grid-beneficial behaviour of BESS if implementation difficulties can be overcome. The geographical distribution of storage, such as locating BESS in areas with high solar PV generation, can further integrate renewables and reduce system costs. As grid connection requests from BESS and other grid users surge, it becomes clear that the “first come, first served” approach is no longer fit for purpose and that there is an urgent need for reform moving beyond “first come, first served”.

With fewer thermal power plants due to decarbonisation, storage operators, and renewable producers are becoming new providers of ancillary services, such as inertia, frequency and voltage control, and black start. Storage operators may either have to provide ancillary services due to connection requirements, or they can offer them voluntarily in specific ancillary services markets. Storage operators optimise revenues by leveraging their assets, but without appropriate policy instruments, particularly fastreacting BESS can exacerbate grid operation challenges. Connection requirements, limiting schedule changes and ancillary services markets are targeted measures for enhancing grid and system integration. Adequacy is the ability of an electricity system to meet the demand for electricity in accordance with reliability standards, alongside generation and demand-side flexibility. In the future, the question is to what extent large-scale BESS will contribute to adequacy.

STORAGE AND D CARBONISATION

A climate-neutral energy system is an essential part in stabilising the climate, protecting human health, and ensuring economic resilience. This requires a holistic approach that integrates multiple facets such as energy efficiency, electrification, renewable energy deployment, and the adoption of innovative low-carbon technologies across all sectors of society. This chapter focuses on three areas on the path towards a climate-neutral energy system.

The first section focuses on potential of storage for renewable energy sources (RES) in the system. Succesfully operating a system with a high share of RES penetration requires different types of flexibility, including storage, alongside demand-side response, to support RES integration. A balanced buildout of flexibility on different timescales is needed to succesfully make the energy transition.

The second section looks into managing forecast errors related to weatherdependent renewables and unpredictable load. In many regions of Europe, activating the existing flexible assets in the system, and providing the right signals is key to managing unpredictability. Storage can contribute to this, as well as being a candidate to provide additional flexibility, where this is needed.

The final section outlines the role energy storage can play in supporting electrification in the heating sector. Further electrification of the heating sector, particularly if it is combined with thermal storage, can capitalise on moments of abundant availability of renewable energy, and the related low prices, rather than heating as the demand occurs.

Energy Storage is a potential game changer in the energy landscape allowing to unlock considerable sustainability potential, but also requiring innovative market integration approaches.

PROF. DR. IR. JOHAN DRIESEN, KU Leuven

“Energy storage systems are essential for the future of climate-neutral energy systems. They allow electricity from fluctuating renewable sources, such as wind and solar power, to be stored until it is needed. Without reliable and efficient storage technologies, a stable power supply with a high proportion of renewables would not be possible.

1.1 ENABLING FURTHER RES INTEGRATION

LEVERAGING FLEXIBILITY: THE CONTRIBUTION TO INCREASING RES UTILISATION

Different types of flexibility, including storage, are needed to support RES integration. Batteries mainly support the integration of solar PV. However, the additional benefit of batteries decreases as more batteries enter the system.

The transition to a climate-neutral energy system requires not only the expansion of renewable energy sources (RES) but also their effective integration into the grid. Even though RES curtailment (deliberately reducing RES output) is not inherently negative or costly, it is still desirable to integrate as much renewable energy as possible. Reducing RES modulation can lower reliance on fossil fuels by enabling more renewable energy to be used, either immediately through increased flexible consumption or by storing it for use at a later moment.

RES, like solar PV and wind power, are variable and weather dependent. Their output fluctuates over time. Solar PV only generates during daylight hours and is affected by cloud cover and fog, while wind power can vary significantly from minute to minute and across seasons. In addition, unexpected outages of power plants add additional fluctuations to energy supply.

Similarly, demand is also not constant in time. Electricity demand fluctuates and includes unpredictable elements, influenced by weather, human behaviour, and so on. This means that renewable generation does not always match electricity demand. Flexibility in the energy system helps bridge this gap by adjusting consumption or shifting energy use in time, allowing more renewable energy to be used instead of curtailed.

Loss in renewable infeed due to renewable modulation in TWh FIGURE 1.1

Compared to a scenario with no flexibilities, flexibilities but no batteries, and all combined Simulation result from a European expansion model for 2050

Different types of flexibility are needed

Due to different weather patterns, a combination of different types of flexibilities works best to integrate renewables:

Electric vehicles can provide flexibility when parked and connected to a charging pole. They are able to absorb solar PV during sunny midday hours or wind energy during windy nights and potentially delivering vehicle-to-grid (V2G) services during high demand hours and/or low RES generation.

Heat pumps can shift energy use across hours or even days, when connected to thermal storage (e.g., hot water tanks), or by using the thermal inertia of buildings.

Demand-side response enable consumers, especially industrial and commercial users, to adjust their electricity consumption in response to renewable excess, low renewable output, and variation in energy prices. This can be shifting, reducing, or increasing consumption, depending on the needs, and capabilities of the system in question.

The above flexibilities are inherently available in the system. The more these flexibilities are unlocked, the more renewables can be integrated into the system (see Figure 1.1).

Batteries can additionally provide fast, short-duration flexibility (with typically 1.5 to 4 hour duration). On top of performing system Services, such as Frequency Containmnet Reserve (FCR) and automatic Frequence Restoration Reserve (aFRR), they are especially effective for integrating solar PV which has a predictable daily pattern: generation peaks around noon and drops

to zero at night. Batteries can store excess solar energy during midday and discharge it during evening demand peaks. This helps reduce the need for RES modulation.

In contrast, wind energy presents a different challenge. It often peaks during nighttime or in colder months, when solar output is low. Wind generation is more variable across hours, days, and seasons.

This temporal mismatch means that shortduration flexibility such as batteries are less effective at integrating wind energy, which would benefit more from long-duration storage solutions. Short-term flexibility, like that provided by batteries by batteries, can still contribute to managing the forecast errors of weather-dependent renewables, as discussed later this chapter.

Figure 1.1 shows the impact of flexibility and batteries on the amount of renewable energy that is modulated.

By unlocking flexibility, 15-35% of renewable modulation can be reduced. Additionally installing batteries, will further decrease renewable modulation by 30-40%.

While batteries are highly effective for RES integration at first, their marginal benefit decreases as deployment scales up. With more batteries in the system, saturation effects start to occur and usage of individual units decreases. This results in fewer cycles cycles per GW, lower individual contribution to system flexibility, and diminishing returns per unit. Figure 1.2 shows that the first installed battery capacities have the highest impact on renewable integration, while this is decreasing for higher capacities. The results are generated using a European expansion market model (see details in Information Box 1.1). The distribution of the batteries over the different European zones

remain the same, but the total amount home and large-scale batteries is scaled up and down. In a system with a high number of batteries of 900 GW in Europe, installing an additional 100 GW only reduces renewable modulation with 1% while this 100 GW would reduce it by 13% when there are no batteries installed yet in the system. Moreover, limitations in current grid infrastructure and market design can constrain the full utilisation of battery capacity. Without complementary measures—such as grid expansion, dynamic pricing, or coordinated control— the marginal value of each additional battery diminishes (see also Figure 1.7).

INFORMATION BOX 1.1

EUROPEAN EXPANSION MODEL: APPROACH AND SCENARIOS

Modelling approach

Linear expansion model that minimises system costs

Optimisation of the deployment of large-scale battery storage and cross-zonal transmission infrastructure

Assumed home battery capacities based on rooftop solar PV

Methodology based on TYNDP IoSN approach*

Geographical scope: Europe (EU27, UK, NO, CH and five non-EU Balkan countries)

Europe divided into 109 zones, where e.g. Germany is represented by 11 zones and Belgium by 3 zones

A Net Transfer Capacity approach adopted

Target year 2050 and historical climate year 2009 used

Limitations

Perfect foresight model: no short-term (market) effects

Only cross-zonal extra high voltage transmission: no inner-zonal, distribution, or vertical grid expansion

DIVERSIFYING ASSETS:

STORAGE AS ONE WAY OF PROVIDING FLEXIBILITY

As introduced earlier in this chapter, flexibility can come from various sources, including electric vehicles (EVs), heat pumps, demand-side response (DSR), and energy storage - each contributing to higher RES utilisation and reduced curtailment. Battery storage adds another layer of flexibility, particularly for integrating solar PV.

Optimal storage capacities strongly depend on the available flexibilities in the system. The more flexibilities are already unlocked, the less additional batteries contribute to RES integration and lowering system costs.

The optimal amount of large-scale battery capacity depends heavily on the level of flexibility already present in the system Figure 1.3 shows large-scale battery capacities for different flexibility scenarios in 2050. Those capacities come on top of 180 GW assumed home batteries. When other flexibilities are limited, batteries can provide significant benefits. But as more flexibility is unlocked—through EV’s, heat pumps and demand side response—the less additional value batteries are bringing to the system.

Since those flexibilities are already available in the system, it is essential that efforts are made to unlock these first.

In supporting specific technologies, such as storage, we must keep cost-efficiency of the entire system at the centre of decisions. Unlocking decentralised flexibility provides important potential in reducing total system costs, as shown in Figure 1.4. This can then be complemented by installing dedicated battery storage systems.

Electric vehicles represent a growing, distributed energy storage potential that can strengthen Belgium’s energy system. Through smart charging and Vehicle-to-Grid (V2G), EV batteries can provide the flexibility needed to integrate renewables, reduce grid costs, and enhance system security — turning mobility into a key enabler of the energy transition.

Relative cost savings in % for the European energy system for three levels of flexibility and battery deployment FIGURE 1.4

Simulation result from a European expansion model for 2050

“Storage is the glue of the future power system. The game-changer could be V2G: if Europe unlocks bi-directional charging at scale, EVs may supply massive flexible capacity, shrinking the addressable market for stand-alone shortduration batteries— though dedicated assets will still be needed for location-specific and multi-hour needs.

To keep the energy transition affordable, demand and generation flexibility should be considered alongside storage.

The results of the market expansion modelling (see Information Box 1.1) for 2050 show that batteries in combination with demand-side flexibility can create an additional 11-15% of cost savings in Europe in 2050.

It is therefore essential to prioritise unlocking flexible demand and generation before investing heavily in storage. Batteries can then be deployed strategically to provide

the additional flexibility needed to integrate more renewables. Due to large uncertainty, demand-side flexibility is assumed to be inherently present in the system by 2050, hence no additional costs were attributed to unlocking this flexibility.

The energy transition leads to a more decentralised mix of assets, distributed over different voltage levels. Flexibility needs to be present at all levels to successfully manage the integration of renewables, and support grid operations.

A diversified mix of assets needs to be activated, ranging from large-scale storage project on the mid- to- high voltage levels, to residential flexibility, provided by EVs, heat pumps, or domestic batteries.

MOVING BEYOND THE SHORT TERM: THERE IS MORE TO STORAGE THAN BATTERIES

Maximising RES integration requires a balanced buildout of flexibility on different timescales.

The availability of weather-dependent renewable energy sources (RES) fluctuates on different timescales, going from daily

variations to variations over the entire year. A balanced buildout of renewable generation, delivered through solar PV, onshore and offshore wind is essential to mitigate patterns of seasonal variation, and for avoiding structural mismatches between supply and demand

A typical seasonal pattern of electricity generation and demand in Europe 2050

Demand in Europe 2050 (Source: Roadmap to net zero, Elia Group, 2021)

Even when doing so, fluctuations in RES electricity generation remain a challenge. Managing these fluctuations requires not only a balanced buildout of RES, but also a complementary buildout and activation of flexible resources, along with interconnectors. This means that daily flexibility, like that provided by batteries, but also by demand response in EVs or heat

pumps, can be used to cover daily variations observed in solar PV patterns. Weekly flexibility, for example provided by thermal storage, along with interconnectors, can be used to cover variations in this timeframe, which could be caused by moving wind fronts. Whereas annual flexibility can assist in further integrating RES, to cover seasonal mismatches.

In Germany, in 2050 a bit over half of electricity generation would come from a combination of on- and offshore wind, and a bit over one third from solar PV. In the low flexibility scenario mentioned above, 5% of this generation would not be integrated in the system, but rather modulated.

FIGURE 1.5

ANALYSING RES INTEGRATION NEEDS

“

Battery storage is the cost saving Swiss knife of the energy transition. It provides a technologically and economically advantageous solution to virtually all system challenges: adequacy, balancing, congestion management, inertia, voltage regulation. It should be seen as facilitating smooth and cost-effective integration of more load and renewable energy in the system, rather than as a driver of congestions and grid investments.

Establishing the amount of RES modulation and timeseries of occurrences.

Adding different dummy flexible capacities, they differ in:

• Power-toenergy ratio

• Operational profile

Assessing the amount of additional RES integration, related to adding flexibility in the considered timeframe.

Compare the effect of adding flexibility operated following different strategies: • Daily

Weekly

Limitations

• Operational strategies and power-to-energy ratios are assessed independently

• Simplified approach with regard to interactions

• Switching at moments of highest marginal gain

Adding flexibility to the system is paramount for integrating RES. Figure 1.7 shows the increased integration of RES, in the German bidding zone, when adding additional flexible capacities, starting from the low-flex scenario mentioned above. In an initial phase the steepest increase of integrated RES, goes through daily flexibility, managing the daily fluctuations of weather-dependant renewables.

However, as more of these assets enter the system, their effect dampens out and eventually reaches a plateau, indicating that remaining, unmanaged fluctuations are operating on a longer timescale. Adding short-term flexibility does not further support RES integration, and may even lead to cannibalising effects. Additional RES integration then goes faster through adding weekly and annual flexibility, addressing the fluctuations on longer timescale, as shown in Figure 1.7, for Germany.

Maximizing RES integration goes through a balanced buildout of flexibility on different timeframes

Impact of adding 2500 MWh of additional flexibility, on different timeframes, for RES integration, under the low flexibility scenario. Simulation post-processing for a 2050 scenario in Germany

Different timescales of flexibility, as well as different voltage levels, are needed to maximise the integration of RES, these need to be complementary to the RES and interconnector build-out in the region. While short-term flexibility, such as batteries, have added value in terms of RES integration, there are limits to the capacity that can contribute to this purpose. A balanced buildout with flexibility on different timescales allows for the maximisation of the utilisation of these resources. This means moving beyond the focus on a single timescale or technology, and focusing rather on system needs, and a balanced activation and buildout of flexibility, as well as RES.

“• Annual profile

Non-optimised combination of different operational strategies

Non-optimised operation of individual assets

No indications of related technology

Battery storage systems in combination with photovoltaic systems should primarily charge at noon. For many of the solar home storage systems an intelligent charging strategy can be activated with just a few clicks. The advantages: the battery storage systems last longer due to reduced aging effects, their operation counteracts bottlenecks in the power grid on sunny days and, depending on the policy available, this strategy relieves the federal budget by millions of Euros annually.

DR.-ING. JOHANNES WENIGER, Research Associate, HTW Berlin

INFORMATION BOX 1.3

ENERTRAG VERBUNDKRAFTWERKE: GREEN ELECTRICITY FOR GREATER SECURITY OF SUPPLY 1

622 MW wind energy capacity

24 MW of solar capacity

The ENERTRAG Verbundkraftwerk in Uckermark stands as a model for integrating renewable energy sources into a stable and secure power system. This combined power plant merges wind and solar energy with heat generation, advanced storage technologies, and green hydrogen production. Unlike conventional setups, its components are directly interconnected, forming a self-sufficient energy ecosystem capable of delivering gigawatt-scale output.

A key innovation lies in its ability to plan and stabilise energy feed-in to the grid. By balancing fluctuations internally through battery systems, hydrogen reconversion, and wind heat storage, the plant ensures a continuous and predictable supply of electricity. This feed-in profile can be forecasted days in advance, allowing the Verbundkraftwerk to fully replace conventional fossil-based power plants.

22 MW of battery storage

The Uckermark facility includes wind farms, photovoltaic systems, electrolysers, and substations, which serve as central hubs for energy conversion and distribution. Surplus electricity is stored in a battery system or converted into hydrogen via an electrolyser. Additionally, the wind heat storage system transforms excess electricity into thermal energy, further enhancing grid flexibility.

0.56 MW of electrolysis

2 MW wind heat storage for thermal energy

Through the combination of these different production and storage technologies, the facility is able to absorb the weatherdependent variations of its renewable energy production, on different timescales. This includes daily variations, linked to the solar cycle, weekly variations linked to moving wind fronts, and longer-term variations, linked to seasonal differences.

By coupling renewable generation with intelligent storage and grid integration, the ENERTRAG Verbundkraftwerk Uckermark aims at combining climate protection and energy security. It offers a scalable, widely applicable model for the energy transition—one that is clean, reliable, and future-proof.

INFORMATION BOX 1.4

MITIGATING SOLAR EXCESS: THE ROLE OF STORAGE SYSTEMS

Excess feed-in from PV plants impose challenges

Solar excess refers to situations where photovoltaic (PV) generation exceeds electricity demand within a market area, typically occurring on sunny days with low consumption, such as weekends or holidays. Can storage systems help to mitigate negative effects?

As the deployment of new PV systems continues across Europe, instances of solar excess are becoming more frequent and pose growing challenges to system stability. In Germany, for example, more than 100 GW of PV capacity is installed in 2025, while peak load is 85-90 GW and

average load around 50 to 60 GW. In the Netherlands the ratio of PV capacity to peak load is even higher. In theory, PV alone could cover electricity demand for a few hours on a sunny day.

And more frequent and longer periods with negative prices at the spot market show the oversupply clearly. Solar excess can also lead to grid congestion and impose issues with frequency and voltage stability. Grid congestion results in costly redispatch measures. Rapid PV generation ramps impose challenges for the current balancing power mechanism.

Battery energy storage systems (BESS) offer a promising solution to absorb excess solar generation and release it when demand rises and the sun goes down. However, storage alone is not a silver bullet. It must be considered alongside demand flexibility and generation flexibility, which are often more cost-effective and system-friendly options.

For BESS, a distinction between residential and grid-scale is needed. Home storage systems are located close to the PV rooftop systems and operate largely behind the meter. However, these systems need smarter charging strategies to really have a large impact on solar excess at midday (see Chapter 2 for further analysis).

Grid-scale storage can also play a role. So far, stand-alone grid-scale BESS installations have shown higher profitability compared to co-located systems, due to the multi-market revenue models. From a PV operator perspective, however, adding a storage system increases the capture price of the PV electricity a lot. The deployment of gridscale BESS must be strategically guided to ensure it strengthens the overall system rather than merely adding capacity.

To fully address solar excess, regulatory and market-based initiatives are essential.

These may influence not only storage systems, but flexible demand and generation in the following ways:

Permanent capacity limitations for feed-in are simple to implement. They would encourage co-located systems and cable pooling. This would smoothen the usage of the grid connection capacity.

Remote control capabilities for PV and BESS installations for aggregators allow for more responsive system management, e.g. at times of negative prices.

Enabling energy arbitrage for home battery systems would unlock new flexibility at the household level. Access to wholesale markets through intermediaries would be needed who can use the swarm of storage systems for revenue optimisation.

Dynamic, time-variable grid tariffs would provide incentives and are suitable to shift withdrawal from or feed-in to the grid. This would address all types of grid users simultaneously.

In Belgium, overbuilding and cable pooling form a viable strategy to manage excess generation. These approaches are only beginning to gain traction in Germany after the amendment of the EEG law in 2025.

Enertrag, The ENERTRAG Verbundkraftwerk® Uckermark. ENERTRAG Verbundkraftwerk® Uckermark

Bundesverband WindEnergie

Some progress in managing solar excess better

is already visible.

In Germany it was observed during spring/summer 2025, that voluntary PV modulation has increased significantly.

On Sunday, May 11th 2025 at midday DA prices went down to -250 EUR/MWh.

Data shows that during that time more

than 50% of PV generation was curtailed by operators themselves (and not as a result of redispatch measures from DSOs or TSOs). On another note, it can be observed that negative spot market prices have become less severe.

1.2 MANAGING RES UNPREDICTABILITY

In most regions of Europe, including Belgium and Germany, existing flexible assets provide sufficient means to manage forecast errors. Activating these assets, and providing the right signals is key to managing RES unpredictability.

In our future energy system, flexibility will remain essential for managing and unexpected outages, and to handle shortterm forecast errors. The magnitude of the latter is expected to increase, as the importance of weather-dependent renewables in the electricity production mix grows, and electrical load increases, accompanied by its own prediction challenges.

In many cases, the short-term flexibility, needed to manage the forecast errors, does not require long-duration delivery. It can be therefore delivered through energylimited technologies such as storage, but also the role of demand-side response and generation-side modulation will be essential to manage these forecast errors.

sufficient to manage these errors. In regions where this is the case, focus should lie on ensuring the participation of these assets in the markets and services used to ensure system balance (being it in the Intraday market, the ancillary services or through implicit balancing.). In other regions, insufficient flexible assets might be present in the system, or they might already be operating at their limits at the moment of need. In this case, dedicated assets, such as BESS, could be needed.

While storage systems are ready to mitigate solar excess, relying solely on them is neither optimal nor economical. Demand and generation flexibility offer cheaper and more scalable solutions. If these flexibilities remain underutilised, storage will inevitably fill the gap - but at a higher cost. A coordinated approach that leverages all three pillars - flexible demand, flexible generation, and storage - is essential for a resilient and efficient energy system.

Unexpected variations in production and consumption, caused by unexpected outages of units, unpredictable load, or capricious output from weather-dependent renewables introduce the need for flexibility to keep the balance in the system. A future, highly electrified energy system, will have a high penetration of flexible assets, such as batteries, but also EVs, heat pumps, or flexible generation. These flexibility means can contribute to handling these forecast errors, and are, in many cases and regions,

Figure 1.8 shows the additional upwards flexibility needs, for handling worst case scenario forecast errors (p99), aggregated for Europe, under two of the scenarios described above, the low flex and high flex scenario. The results are obtained by assessing the flexibility needs caused by this worst-case forecast errors, and comparing them to the available margin on the flexible asset within the zone, as well as potential imports for neighbouring zones to provide this upwards flexibility. The analysis is performed per zone, and results are then aggregated over Europe.

“The energy system needs additional flexibility from storages, both in times of scarcity and abundance. The resulting price signals make battery storage an attractive investment opportunity, even without direct government support. This deserves positive recognition in today’s energy landscape.

Activating the flexible assets that are present in the system, corresponding to moving from the low flex scenario to the high, would result in a reduction of 15% in the required dedicated flexible capacity, and, most notably, reduce the time where these flexible capacities are present by 36%.

Figure 1.9 shows the impact on the occurrences where additional flexibility is only needed for a short time (8 hours or less). This figure shows a reduction in the occurrences of the need for additional flexibility, to cover short-term needs. In the high flex scenario, only 5 out of 38 considered zones require additional

flexibility means. These do not include Belgium and Germany, typically they are located at the edges of Europe, with large production potential compared to the load in the region, and limited interconnection capacity.

Activation of the existing flexible assets, including energy storage systems, in the different markets and services will be a top priority to manage the unpredictability of RES availability, and load. This requires the availability of the necessary market signals, and the exposure of these assets to these signals.

Activating inherent flexibility reduces the occurrences of the need for additional assets

FLEXIBILITY NEEDS FOR MANAGING FORECAST ERRORS

1. Assessing historic forecast errors 2. Assessing Expected improvement in forecasting

Assessing historic (2023-2024) forecast errors for the weather-dependent generation and load.

1.9

Impact on additional flexibility needs, under different scenarios. Simulation post-processing for a 2050 scenario in Europe

An improvement of 1% per year in forecasting accuracy is assumed, between the historic assessment, and the time of simulation (2050).

3. Identifying Flexibility needs for managing forecast errors

The location of these additional flexible assets needs to be aligned with grid realities. Locational aspects, such as the location of potential congestion, need to be considered when installing these assets. This is further discussed in Chapter 3.

4. Identifying available flexibility means

5. Identifying needs for dedicated flexibility

The extrapolated forecast error is applied on the results of the economic dispatch for the relevant generation technologies and the load.

This yields additional needs for flexibility in the system, to manage these forecast errors.

The residual margins on flexible generation and consumption is assessed, as well as the margin to export this available flexibility to neighbouring zones via interconnectors.

Comparing the flexibility needs and means, this yields an identification of the need for dedicated flexibility to manage these forecast errors

1.3 SUPPORTING ELECTRIFICATION IN THE HEATING SECTOR

The integration of thermal energy storage is one way to facilitate heat electrification and make the decarbonisation of heat more attractive.

The heating and cooling sector is an important energy consumer, with around half of EU final energy consumption is attributed to it. At the same time around 79% of the energy in the sector originates from fossil-based sources, making the decarbonisation of this sector an important

lever for the energy transition. The main decarbonisation pathway for heating and cooling lies in electrification, making the integration of heat and power sectors an important area of action to reduce greenhouse gas emissions  (GHGs).

Decarbonisation through electrification depends largely on the use of electricity from low-carbon sources. Furthermore, this also poses challenges in terms of the large consumption capacity needed to be

connected to the electricity grid. Thermal storage can be an important lever in bringing flexibility to heat consumption. It can allow for the use of lower-cost, low-carbon electricity, while keeping flexibility to avoid periods of grid strain, and at the same time guaranteeing reliability of supply. The potential of such technologies is large, however, development is still needed to demonstrate reliability and bankability.

“Long Duration Energy Storage is rapidly evolving, with a broad portfolio of novel technologies targeting both utility-scale and onsite applications. Their promise is significant, yet reliability and bankability remain to be validated.

PIETER-JAN JORDAENS, Program Manager Energy Transition, Sirris

THERMAL ENERGY STORAGE IN INDUSTRIAL APPLICATIONS: COMBINING

GRID SUPPORT WITH COST REDUCTION

The

central role of process heat

The heating sector represents a compelling area of analysis for decarbonisation and emission reduction in the context of climate targets, as approximately half of global final energy consumption is attributed to heat  This is particularly evident when examining heat demand and generation in

industrial applications, where around half of global heat consumption is associated with end-use industrial processes 4 The industrial sector is a major consumer of energy and a significant emitter of greenhouse gases. Within this sector, heat generation accounts for by far the largest share of energy demand. In Germany, industry represented approximately 28% of total final energy consumption in 2020. Of

this, 67% was used to generate process heat, corresponding to about 19% of Germany’s total final energy demand 5

Moreover, the vast majority of industrial heat (approximately 90%) is still generated from conventional, fossil-based energy sources 6

As a result, thermal energy accounted for 80% of industrial GHG emissions in Europe in 2018, with 75% of these emissions directly stemming from process heat applications 7

2 ENTSO-E. (2023), Study on Power and Heat Sectors: Interactions and Synergies. https://eepublicdownloads.blob.core.windows.net/public-cdn-container/clean-documents/Publications/Position%20papers%20and%20reports/2023/entso-e_integration_ power2heat_230130.pdf (last accessed on 30/09/2025)

3 Gilbert et al. (2023), Heat source and application-dependent levelized cost of decarbonized heat, Joule, Volume 7, Issue 1, 128 – 149, https://doi.org/10.1016/j.joule.2022.11.006.

4 Gilbert et al. (2023).

5 IN4climate.NRW. (2022). Prozesswärme für eine klimaneutrale Industrie. Impulspapier der Initiative IN4climate.NRW. Düsseldorf: IN4climate.NRW. https://www.energy4climate.nrw/fileadmin/Service/Publikationen/Ergebnisse_IN4climate.NRW/2022/prozesswaerme-fuer-eine-klimaneutrale-industrie-impulspapier-der-initiativein4climatenrw-cr-nrwenergy4climate.pdf

6 Gilbert et al. (2023).

7 Fraunhofer ISI (2024). Direct electrification of industrial process heat. An assessment of technologies, potentials and future prospects for the EU. Karlsruhe: Study on behalf of Agora Industry. www.agora-industry.org, p.16.

Electrification of heat as a pathway for decarbonisation

Despite the substantial potential for emission reductions, electrification of industrial process heat remains very limited. Currently, less than 5% of total industrial process heat demand across the European Union is met by electrified processes 8 Due to the complexity of the industrial sector, no singular pathway for decarbonisation exists. To date, electrification has primarily been applied in specific processes where it offers clear advantages, such as improved energy efficiency or simplified process handling9 Nonetheless, electrification is identified as a particularly high-impact and increasingly viable strategy, especially for low- and medium-temperature heat applications, which dominate many industrial processes. The efficiency of electrical heating technologies in general is considered higher than that of fuel-based technologies10

Further drivers and systemic benefits are that direct electrification technologies are already commercially available in various forms and are suitable for different temperature levels, industrial contexts, and offer several application potentials.

Electrification also supports sector coupling between electricity and heat, creating new opportunities for demand response11 In this context, final consumers, such as industrial facilities, can adjust their electricity usage in response to market signals, thereby contributing to grid stability through flexibility provision12

Furthermore, electrification aligns with broader system needs, it reduces fossil fuel dependency, facilitates the integration of variable renewables, and unlocks synergies in infrastructure and storage planning 13

Nevertheless, several challenges remain. The competitiveness of electric heating depends largely on the relative energy prices. Electricity is still significantly more expensive than fossil fuels in many markets 14

While some policy instruments, such as Carbon Contracts for Difference (CCfDs),

offer promising support by compensating higher operational costs, many markets still lack clear decarbonisation targets or investment incentives for renewable heat 15

Given economic conditions and geopolitical developments, at the time of publicaton, such as the war in Ukraine and rising global energy prices, the full electrification of industrial process heat remains challenging. These developments have intensified the urgency for industries to explore costeffective, flexible, and independent energy solutions16

As a result, interest is growing in the integration of thermal energy storage into industrial heating processes.

Integrating thermal energy storage

The integration of thermal energy storage (TES), meaning the storage of heat for later use, being it through sensible heat, latent heat or thermochemical presents a promising pathway to support the electrification of industrial process heat.

It thereby enhances the attractiveness of heat decarbonisation in industry. TES enables the temporal decoupling of electricity generation and consumption, offering system flexibility and facilitating the use of surplus renewable energy17 By mitigating the mismatch between intermittent generation and industrial demand profiles, TES supports the grid integration of renewables and contributes to overall system stability 18

8 Fraunhofer ISI (2024), p.17.

9 Fraunhofer ISI (2024), p.17.

10 Fraunhofer ISI (2024), p.42.

11 KEI (2024). Flexibilisierung elektrifizierter Industrieprozesse: Eine Analyse der technischen und ökonomischen Herausforderungen aus Unternehemens- und Systemperspektive. Cottbus: Kompetenzzentrum Klimaschutz in energieintensiven Industrien (KEI), p.21.

12 Directive (EU) 2019/944. (5.6.2019). Directive (EU) 2019/944 of the European Parliament and of the Council of 5 June 2019 on common rules for the internal market for electricity and amending Directive 2012/27/EU (recast) (Text with EEA relevance). https://www.legislation.gov.uk/eudr/2019/944/article/2 Art. 2 (20).

13 Fraunhofer ISI (2024).

14 Fraunhofer ISI (2024), p.68; BloombergNEF (2021). Hot Spots for Renewable Heat Decarbonizing Low-to Medium-Temperature Industrial Heat Across the G-20. Von https://www.wbcsd.org/wp-content/uploads/2023/10/Hot-Spots-for-Renewable-Heat.pdf

15 BloombergNEF (2021); KEI (2024), p.154.

16 Elia Group (2022). POWERING INDUSTRY TOWARDS NET ZERO. Our vision on anchoring industry in Europe. Bruxelles, Berlin. https://issuu.com/eliagroup/docs/powering_industry_towards_net_zero

17 Fraunhofer ISI (2024), p.68; KEI (2024), p.21; BNetzA. (2025). Diskussionspapier: Rahmenfestlegung Allgemeine Netzentgeltsystematik Strom (AgNes). Bonn: Bundesnetzagentur für Elektrizität, Gas Telekommunikation, Post und Eisen-bahnen: Große Beschlusskammer Energie. https://www.bundesnetzagentur.de/DE/Beschlusskammern/1_GZ/GBK-GZ/2025/GBK-25-01-1%233_AgNes/Downloads/Diskussionspapier.pdf?__blob=publicationFile&v=6

18 Fernandez, Go, Wong, & Früh. (2024). Review of challenges and key enablers in energy systems towards net zero target: Renewables, storage, buildings, & grid technologies. Heliyon, 10(23). https://doi.org/10.1016/j.heliyon.202

Heat supply via district heating systems offers the possibility of economically storing energy over long periods in large-scale heat storages. In the context of heat sector electrification, this provides substantial long-duration flexibility to the power grid, either via heat pumps and electric boilers during excess generation at low heat demand, or by supplying stored heat during cold dark doldrums.

From an economic perspective, TES improves the business case for industrial decarbonisation by enabling load shifting to low-price periods of electricity, reducing exposure to volatile fuel prices, and unlocking additional revenue streams through participation in flexibility markets 19

Moreover, TES can help avoid peak-load grid tariffs and carbon pricing, reduce maintenance requirements for combustion systems, and align with corporate decarbonisation strategies 20 Additionally, TES helps to facilitate waste heat utilisation, which is often emitted and lost. TES thereby also increases the efficiency of the entire process heat system 21 As energy costs represent a significant share of industrial expenses, TES integration can substantially reduce the cost burden while contributing both implicit and explicit flexibility to the energy system.

Unlocking energy cost savings via thermal storage and value stream differentiation

Different configurations and integration options of TES in industrial process heat generation reveal varying degrees of energy cost reduction across electrified process setups.

The comparison shows that direct electrification of industrial processes using only power-to-heat (P2H) assets, such as electric boilers or heat pumps, currently faces significant economic hurdles. It struggles to remain competitive with conventional, fossil-based heat generation.

Integrating TES into such electrification setups can lead to substantial energy cost savings by mitigating electricity costs and even benefiting from price volatility.

While the capital expenditure (CAPEX) of TES represents an additional investment, which can be a barrier for industries, industrial process heat is generally OPEXdriven. Indeed, electrified heating systems with TES represent an additional capital investment compared to classical systems for industrial process heat. This additional CAPEX is to be recovered by reduced OPEX, in comparison to the classical system. Therefore, long-term energy cost reductions offer a higher impact economic lever.

However, a postive return on investment remains challenging in the current market context.

Moreover, the operating mode of the TES significantly influences economic outcomes. By an optimisation of the storage operation mode following day-aheadmarket price signals, implicit flexibility is provided and energy cost savings via day-ahead price arbitrage are possible.

TES also enables participation in balancing markets, such as aFRR, by reserving capacity of the storage for things and mechanisms like downward flexibility others. This can open up additional revenue streams and, depending on market conditions, generate considerable energy and capacity remuneration. Ultimately, the configuration of heat generation reveals a trade-off between providing explicit flexibility to the electricity system and pursuing internal cost optimisation in the industry.

SIRRIS: THERMAL STORAGE IN INDUSTRY

John Cockerill: Molten salt thermal energy storage

Solar and thermal energy storage (TES) are increasingly important for enabling continuous, dispatchable carbonfree electricity. By storing thermal energy, typically via molten salts, these technologies help overcome the intermittency of renewables such as solar power. Concentrated Solar Power (CSP) plants, especially those employing solar towers, are at the forefront of deploying TES globally.

Within this evolving energy landscape, John Cockerill plays a role as a technology provider and innovator. The company is internationally recognised for its advanced solar receivers, which are central components in solar tower CSP plants. These receivers are manufactured and supplied by John Cockerill and allow heliostats (computer-controlled mirrors) to focus sunlight onto a central point, efficiently transferring thermal energy to storage media like molten salts, water, or solid particles. This expertise enables plants to reach high operating temperatures, thereby increasing

efficiency and flexibility for both electricity generation and industrial applications.

John Cockerill’s receivers can reach operating temperatures of 565°C with molten salt systems, and are being further developed for next-generation solid particle receivers, which aim for temperatures over 800°C. This capability is important, as higher temperatures translate to more efficient conversion to electricity or industrial steam.

The company’s contribution continues beyond solar receivers. John Cockerill also designs and supplies Molten Salt Steam Generators (MSSGs), the link between heat storage and power generation. Modern MSSGs must adapt to fluctuating electricity demand and frequent startup cycles. John Cockerill’s MSSG solutions emphasise flexibility, and reliability, in order to provide a central role in both the energy dispatch and the technical advancement of TES in CSP.

Research Engineer, Fraunhofer Research Institution for Energy Infrastructures and Geotechnologies IEG

19 Fraunhofer ISI (2024), p.36; KEI (2024), p.151; Systemiq; Breakthrough Energy. (2024). CATALYSING THE GLOBAL OPPORTUNITY FOR ELECTROTHERMAL ENERGY STORAGE. PROMISING NEW TECHNOLOGIES FOR BUILDING LOW-CARBON, COMPETITIVE AND RESILIENT ENERGY SYS-TEMS. https://systemiq.info/etes, p.7; LDES Council. (2022). Net-zero heat Long Duration

Energy Storage to accelerate energy system decarbonization. www.ldescouncil.com.

20 Rissman, J., & Gimon, E. (2023). Industrial Thermal Batteries: Decarbonizing U.S. Industry while Supporting a High-Renewables Grid. ENERGY INNOVATION: POLICY AND TECH-NOLOGY LLC, p.31; BVES (2025). Bundesverband Energiespeicher Systeme e.V.: Energiespeicher für Industrie und Gewerbe. https://www.bves.de/energiespeicher/industrie-gewerbe/ 21 BVES (2025).

RETHINKING OUR HEATING SYSTEMS: HEAT STORAGE FOR DISTRICT HEATING IN GERMANY

(The content in this section was provided by Dr.-Ing. Judith Stute and Dr.-Ing. Felix Panitz, Fraunhofer IEG)

Thermal LDES can aid in replacing fossil fuels, enabling electrification of heating and cooling, or capture surplus waste heat, thereby increasing system flexibility and renewable integration.

District heating networks are a key application for thermal LDES, as they allow for the deployment of very large storage capacities that would not be feasible at the individual building level. Larger storages are technically and economically more efficient because they achieve lower heat losses, better temperature stratification, and lower specific investment costs.

A practical example is the solar-thermal based district heating network in the German village of Bracht, which integrates a pit thermal energy storage of 26,600 m³.

This corresponds to an average of about 140 m³ (i.e., 8 MWh) per connected building—a scale that would not be feasible to install if each building were equipped with its own storage 22 Even more ambitious projects are planned: some German cities are considering pit thermal energy storages of 500,000 m³, with a single installation exceeding the total installed battery capacity of the country.

Figure 1.11 shows the development of storage capacity in Germany. The energy capacity of large thermal storage in district heating systems has surpassed that of the largely stagnant pumped hydropower storage (PHS) plants, while keeping in mind that the different forms of energy are only partially comparable. Since 2020, battery capacity has grown significantly.

The potential is significant. If all district heating systems were equipped with daily heat storages sized for summer operation, domestic hot water, they would collectively provide around 120 GWh of thermal capacity. This is more than twice the current installed thermal storage capacity in Germany and three times that of the electric storage capacity of PHS.

In EU-27, district heating already supplies about 477 TWh (final energy consumption) of heat and a share of 15% of total heat demand. Overall heat demand is expected to decline sharply by 2050, driven by improved building insulation. Nevertheless, the demand connected to district heating networks is projected to increase due to their expansion, reaching 530 to 700 TWh and more than 30% of total heat demand 23

Thermal LDES can support this expansion by replacing high-temperature fuels, and particularly fossil fuels, enabling electrification of heating and cooling, and improving the operation of capture surplus waste heat (or CHP), thereby increasing system flexibility and renewable integration 24 (End of provided content)

INFORMATION BOX 1.7

FRIEDRICH-WILHELM-LÜBKE-KOOG WIND HEAT REGION: GREEN HEATING, LESS CURTAILMENT

Flexible Heating as a Key to Grid Relief and Decarbonisation

Wir verbinden wind und wärme Modellregion F.-W.-Lübke-Koog

The Wind Heat Region project in FriedrichWilhelm-Lubke-Koog, Schleswig-Holstein, shows how integrating wind energy into local heating systems can support the integration of renewable energy and support climate goals. ARGE Netz, BurgerWindpark Lubke-Koog Infrastruktur, the municipality of Friedrich-Wilhelm-LubkeKoog, and IWO jointly launched this pilot project in October 2017. Between 2019 and 2020, residents of 13 households have used hybrid heating systems that switch between oil-fired heating and powertoheat with heat storages loaded with wind-generated electricity. This flexibility allows buildings to absorb excess wind power when the grid is congested, turning negative residual load into usable heat.

The project highlights the value of sector coupling—linking electricity and heat—to enhance renewable energy utilisation. By using wind energy locally, the community increases the use of locally produced electricity, reduces CO₂ emissions (by 34% across 13 buildings in two years), and increases energy autonomy. The model region benefits from its dispersed housing structure and proximity to a community-owned wind farm, making it ideal for decentralised energy solutions. Flexible heating not only supports grid stability but also empowers communities to actively participate in the energy transition. It proves that with the right infrastructure, renewable energy can be efficiently redirected to meet thermal needs, offering a replicable blueprint for other regions.

> Hybridheizung: Wärme aus verschiedenen Quellen <

22 Lang, Susanne; Panitz, Felix; Nikolov, Alexander; Drechsler,

23 Fallahnejad,

Haas,

Andreas; García, Luis Sánchez; Persson, Urban (2024): District heating potential in the EU-27: Evaluating the impacts of heat demand reduction and market share growth. In Applied Energy 353, p. 122154. DOI: 10.1016/j.apenergy.2023.122154.

24 Panitz, F., Stute, J. (Fraunhofer Research Institution for Energy Infrastructures and Geotechnologies IEG) (2025).

Björn; Ahrendts, Fabian; Meier, Nadezda (2024): Erneuerbar, effizient, regional - Potenziale von Großwärmepumpen in Brandenburg und Sachsen: Rosa-Luxemburg-Stiftung.

Mostafa; Kranzl, Lukas;

Reinhard; Hummel, Marcus; Müller,

Bundesverband WindEnergie

DUH: ENVIRONMENTAL IMPACT OF DIFFERENT STORAGE TECHNOLOGIES

Deutsche Umwelthilfe: ecological impact of storage

Energy storage systems are as important to our future energy system as grids and renewable energy sources themselves. As every infrastructure comes with an impact, it is crucial to think about energy storage not only from a technological but also from an ecological perspective.

In the past, mechanical pumped-storage hydroelectricity was the main technology used to store surplus renewable energy until it was needed. Today, however, technological developments mean that large- and residual-scale electrochemical battery storage systems are increasingly being used, marking the dawn of a new era in energy storage. In the future, chemical-based hydrogen and thermalbased heat storage systems will provide additional long-term energy storage capacity, enabling a fully climate-neutral energy system.

All of these technologies are essential for unlocking the power of renewable energy, but they all have an ecological impact, too. Pumped storage systems require a large area to be flooded with water. Battery storage systems, particularly those based on lithium, rely on critical raw materials such as lithium, cobalt, nickel and manganese. These materials need

to be mined, processed, and assembled, and this value chain is often associated with land grabbing, environmental destruction, toxic pollution, and high emissions. The production of hydrogen requires energy and water, both of which are scarce resources, especially when sourced in sensitive areas. Lastly, heat storage systems also require a specific amount of land to be permanently sealed by artificial infrastructure.

In order to build a responsible, climateneutral energy system, we must recognise and address these challenges. It is only natural that energy production, usage, and storage always have an impact. However, these impacts can be managed: some can be avoided, most can be mitigated, and the remainder should at least be compensated for. Transparent supply chains, environmental standards, human rights due diligence and circular economy principles can ensure that

storage technologies are produced using responsibly sourced materials.

Selecting storage sites and technologies carefully can prevent many potential impacts before they occur. Precise monitoring programmes can help us to better understand the impact of energy storage technologies and improve our management of them.

Finally, technological innovation and development can provide us with new opportunities. As well as improving what we already have, we can think beyond what is already established and consider a broader range of storage options.

Innovations such as gravity-based systems (e.g., concrete or sphere storage) and compressed air energy storage demonstrate that the future of energy storage is more diverse than it seems.

Careful application of a diverse range of improved storage options will enable us to find the best solution for each project, paving the way for a sustainable energy storage future.

INFORMATION BOX 1.9

OCTAVE: IPALLE SECOND LIFE BATTERIES

Octave is a Belgian cleantech company, founded in 2020, specialising in battery energy storage and advanced energy management services for businesses. Octave has delivered more than 80 MWh of battery energy storage capacity and operates one of the largest fleet of behindthe-meter batteries in Belgium.

Octave started with a circular battery concept where battery modules from electric vehicles are reused in a stationary storage system. When these batteries leave the vehicle, they typically still retain more than 80% of their usable capacity, making them suitable for further use. A landmark project is the collaboration with Ipalle at the Thumaide waste incineration plant, where Octave delivered a Belgianmade, MWh-scale second-life storage system using repurposed batteries from two car manufacturers. The site is directly connected to the Elia grid which makes it highly suitable for delivering ancillary services.

As the first mover in behind-the-meter energy storage, Octave developed an Energy Management System which offers comprehensive value stack of control applications for batteries and other flex assets such as solar PV and EV charging infrastructure. Octave also launched the Octave One, a range of first life LFP battery systems which can be tailored to projects from 100 kWh to several MWh.

STORAG AND AFFORDABILITY

The previous chapters demonstrate the need for energy storage, next to demand and generation flexibility, to integrate more renewables efficiently. Considering all flexibility options, storage has a key role to play in keeping the energy transition affordable, particularly when further flexibilisation of demand and generation becomes too costly. This chapter discusses how batteries can contribute to affordability and fair access for all. For these benefits to materialise, there are challenges to overcome, and this chapter discusses potential solutions to address them.

The first section focuses on storage contributing to stable and affordable prices. By deferring the use of electricity in time, storage can reduce the volatility of the residual load curve and spot market prices. Moreover, storage put downward pressure on ancillary service prices and can replace part of the conventional generation in delivering this service.

The second section focuses on how storage can optimise the use of the available grid infrastructure and grid buildout. Grid­beneficial storage can reduce congestion and grid expansion needs. However, currently, batteries typically operate grid­unaware, based on market prices which do not reflect intrazonal grid constraints. This can exacerbate congestion and increase grid expansion needs.

Therefore, a regulatory framework and market design is needed to unlock the grid benefits of storage. Grid­beneficial operation can be incentivised by contractual signals and dynamic grid tariff signals. Additionally, geographical distribution of storage can further reduce the need for excessive grid investments. Furthermore, by connecting behind the meter, storage assets are incentivised to optimise existing grid connection capacity and thereby relieve the local grid situation.

The third and last section focus on grid access. Connection requests, especially by batteries are surging, revealing the limitations of the current “first come, first served” approach. By having the right prioritisation framework among different usages, fair access to the grid for all grid users, including storage, can be ensured.

2.1 STABLE AND AFFORDABLE PRICES

Batteries bring undeniable advantages to the system, helping us stay on track with our decarbonisation goals and keeping the energy transition affordable.

1 They allow us to integrate more RES in the system, shifting electricity from surplus to deficit periods ­ both in the day­ahead market, matching demand and renewable forecasts, and in the intraday market, by addressing the errors in those forecasts. By doing so, batteries mitigate price volatility in these spot markets.

2 Additionally, batteries can cost­competitively offer ancillary services. For instance, they are already providing balancing services (FCR, aFRR) today. On top of this, they might also be able to provide other ancillary services (see Chapter 3).

STABALISING SPOT PRICES BY FLATTENING THE CURVE

As demonstrated in Chapter 1, energy storage supports the integration of renewable energy by shifting electricity consumption and injection in time. In addition, storage also helps reduce reliance on costly dispatchable power plants. Both effects can best be explained by demonstrating the impact of storage on the residual load curve. This is the part of the electricity demand that is not covered by variable renewable generation (solar and wind) and therefore must be covered by other generation sources. Figure 2.1 shows residual load curves for Germany during a typical summer and winter week in 2050, with and without batteries. The battery operation is a result of a European market optimisation, which is explained in detail in Information Box 1.1 in Chapter 1.

During the day, high solar generation causes a surplus of electricity generation, resulting in negative residual load.

Storage can absorb the excess electricity by charging at those moments (dark red area in lower half of figure 2.1), reducing the need to curtail renewable energy.

In the evening and at night, when solar generation drops, the electricity demand cannot be met with renewable generation alone, requiring dispatchable generation to fill the gap. By discharging (pink area), storage can help fill the gap and decrease the residual load.

This shifting of energy in time enhances the matching of renewable generation and demand curves, which results in a flatter residual load curve.

summer

Flattening the residual load curve also results in lower volatility of electricity prices. Batteries earn energy arbitrage profits from this shifting of electricity in time. They charge when prices are low and discharge when prices are high. Low spot market prices are typically associated with excess variable renewable generation. High prices are a result of insufficient variable renewable generation to cover demand and, therefore, requiring more expensive, thermal, peaking power plants to generate electricity.

Today, such peak power plants are typically fossil fuel based. In 2050, similar thermal peaking power plants will run on low­carbon fuels such as biogas or hydrogen. Figure 2.2 shows hourly market price profiles of an average day in a high­RES energy system in 2050 with and without batteries. The prices reflect the hourly marginal cost of the dispatch and serve as an indicator to what extent expensive peaking units are used. In the scenario without batteries, price fluctuations are significantly larger. With batteries, the system benefits from more stable prices due to their shifting of generation and consumption in time. Price

Comparing

This effect is even more important for intraday adjustments, where batteries can help to avoid extreme intraday prices and volatilities due to forecasting errors. Due to their fast ramping and switching capability, batteries are well suited to mitigate forecasting errors emerging from electricity demand and weather dependent RES. In doing so, electricity providers can re­balance their portfolios without needing to activate more expensive peaking units. Their fast­reacting capability, however, creates challenges for system stability and must be carefully managed (see Chapter 3).

Electricity storage systems engaging in energy arbitrage can help flatten the residual load curve, dampen the volatility of spot prices and reduce the use of peak power plants.

Sufficient market penetration and competition  however, are essential for ensuring that the expected benefits and decreases in price volatility fully materialise.

Demand, renewable generation and residual demand for Germany in GW

FIGURE 2.1

CONTRIBUTING TO AFFORDABLE PRICES FOR ANCILLARY SERVICES

On one hand, TSOs procure a variety of ancillary services through dedicated markets to ensure power reliability and quality for grid users. For instance, frequency regulation services for the balancing of power imbalances are procured via such markets  BESS are typically bidding in the FCR and aFRR markets at competitive prices. 3 However, there are already more potential providers of balancing capacity services than there is demand. These capacity reservation markets are expected to become saturated in the future.

“Elia’s innovative market design enables behindthe-meter batteries to provide both explicit and implicit balancing services. This has been crucial to Octave’s success and has positioned Belgium as one of the leading countries in behind-themeter battery energy storage. MAXIME

With more participants, including more large­scale energy storage, in the market, overall market efficiency is enhanced. Small additions are unlikely to have significant effect, as the price depends on the incumbent technology. Once a tipping point of participation by a cheaper technology is passed, the historically incumbent technology does not significantly influence price anymore and a decrease of prices is observed (see Figure 2.3). This reduces the revenue that can be earned per asset from ancillary services, as a specific asset will be selected less often and/or will have to bid at lower prices. Therefore, in the future, the share of BESS revenues from balancing capacity is reducing. It can be expected that they shift towards more energy arbitrage on wholesale markets, as explained in the previous section. At the same time, their participation in the provision of ancillary services without prior reservation (especially aFRR energy) will remain very relevant.

On the other hand, some services are not yet marketed, as they were traditionally a byproduct of synchronous generators. With the advancement of the energy transition and the declining business case for conventional, fossil­based generation, these services might have to be actively procured by TSOs across Europe in the future. Storage systems are technically

2 Chapter 3 dives deeper into the topic of ancillary services and to what extent energy storage systems are equipped to provide them.

3 This is shown in several revenue indices. For instance, Jonas Brucksch, Jonas van Ouwerkerk, Dirk Uwe Sauer (2025). ‘ISEA Battery Revenue Index’. Available online: https://batterycharts.de/revenue-index/ (last accessed on 07/11/2025).

capable of providing these services (see Chapter 3 for more information).

For example, Elia Transmission Belgium procures reactive power via tenders where BESS can also offer reactive power 4 Similarly in Germany, TSOs procure reactive power via tenders that allow BESS to participate since 2025 and they will start the marked­based procurement of inertia in January 2026 5 For black start capability, batteries can already bid in tenders, typically in combination with a generation asset. This indicates that there might be new revenue opportunities.

In sum, storage systems provide existing and new grid services at competitive prices, reducing the overall costs for these services and replacing a part of the conventional generation.

As storage assets diversify their revenue streams, business models and optimisation become increasingly complex, aiming to maximise profits through a combination of energy arbitrage and the provision of ancillary services. From a grid operation perspective, this introduces challenges: dispatch patterns become less predictable, which can lead to congestion and stability issues. Further insights into the benefits and risks of operational models are provided in Information Box 2.1.

4 Elia (2025). ‘Becoming a Voltage Service Provider’. Available online: https://www.elia.be/en/electricity-market-and-system/system-services/becoming-a-voltage-service-provider (last accessed on 16/10/2025).

5 Netztransparenz (2025). ‘Ancillary Services’. Available online: https://www.netztransparenz.de/en/Ancillary-Services (last assessed on 16/10/2025).

“Battery Energy Storage Systems (BESS) are not the only solution, but they are today’s strongest bet— fast, scalable, and capable of absorbing volatility. The challenge lies in optimisation. For BESS to be profitable, it must capture and stack value streams from wholesale markets and ancillary services alike. Every BESS project is unique—differing in duration, size, co-location, and grid connection—which makes revenue stacking highly individual. There is no one-size-fits-all approach. Success requires not only the right optimisation tools, but also deep market expertise.

ANDRÉ BOSSCHAART, Head of Analytics, Montel

SNICK, Co-founder & CEO, Octave Energy

© EngieBelgium

NAVIGATING COMPLEXITY: OPERATIONAL MODELS AND FUTURE OUTLOOK

There are different operational strategies for energy storage systems each with their objective, benefits and challenges from a grid and system perspective.

Within each and sometimes across operational strategies, several revenue streams can be stacked to contribute to the objectives. When different revenue streams from providing multiple services are combined, it is called revenue stacking For example, industrial behindthe-meter storage typically combines market-optimised (e.g., providing ancillary services) and on-site optimised operation (e.g., load and generation smoothing to avoid peak grid tariff charges).

stability issues due to fast-reacting storage

system preferences

Especially when participating in different markets to provide more than one service, different opportunities must be weighted against each other, and optimisation gets complex. As a result, dispatch profiles also become more complex, volatile, and hard to predict, while making use of the full capacity.

2.2 OPTIMISING GRID BUILDOUT

With the energy transition advancing, to connect new assets and further strengthen interconnections between regions. The growing need for infrastructure naturally leads to higher investment costs for TSOs and DSOs, which in turn puts pressure on the affordability for grid users. By using existing infrastructure and new grid expansions as optimally as possible, part of the investment costs can be avoided. This helps to keep the energy transition affordable.

First, this section dives into the benefits of optimising storage operations and what it means for the grid. Storage can optimise grid usage by locally reducing peak power flows (e.g., by netting production and consumption) and spreading those flows more evenly over time to avoid simultaneous peaks. This helps to defer or avoid some costly infrastructure upgrades. Flexible grid users, such as electricity storage, can play a vital role in this effort. To make use of their full potential, batteries would have to be operated in line with system and grid needs. Given that markets today do not take intrazonal grid constraints into account, energy arbitrage­driven batteries operate unaware of the grid. Therefore, they might exacerbate existing congestion, rather than contributing to relieving them.

Second, this section discusses how storage deployment and operations can be leveraged optimally. From the point of view of the flexible grid user wanting to contribute to grid and system needs, the following questions need to be answered:

Where to connect?

Incentives for optimal location needed.

2 How to connect?

A level playing field between behind the meter and front of the meter (and co­located or stand­alone) is another step towards unlocking storage benefits for the grid.

3 How to operate?

Storage operation can be aligned with grid needs by exposing it to additional constraints (e.g., via flexible connection agreements) or providing them with additional incentives (e.g., via smart grid tariffs).

All of these levers will play a vital role in ensuring that flexible assets are not aggravating existing congestion. To unlock the potential of storage, we therefore urgently need a solid framework that enables flexible assets, like storage, to actively contribute to grid optimisation.

Future outlook

Currently the battery business case is very attractive. On the one hand, balancing capacity markets are expected to become saturated, daily price spreads might be smoothed out due to more flexible market participants, there might be more voluntary curtailment of solar PV and potentially more restrictive regulation in the future. On the other hand, new revenue streams can arise and/ or more specialisation is possible. These potential developments make the future outlook for batteries uncertain.

POTENTIAL GRID BENEFITS OF STORAGE

Grid infrastructure is a limited resource. Reinforcements to the grid are costly and can take up to 15 years before they are in place. From an affordability and timing perspective, it is essential that grid infrastructure is utilised as efficiently as possible. This can allow more grid users to be connected and reduces costs.

Optimal utilisation of the available grid capacity means taking measures to make more use out of the available infrastructure. Storage systems can help with locally matching consumption and production, as well as spreading the transport of energy more evenly over time and thereby reducing congestion

Imagine a highway where all lanes in both directions are always used equally, without any traffic jams in the morning or evening, nor with empty lanes during the night. In this scenario, storage is the parking space next to the highway, where cars can park when the highway (in one direction) is crowded and to fill the lanes when there is little traffic in this direction on the highway. It is important to ensure cars are parked when there is a lot of traffic on the highway and enter the highway when it has capacity—and not the other way around.

In the power system, to alleviate grid congestion, the operation of the storage system must be opposite to the constraint present in the local network. The battery should inject when there is a lot of unmatched offtake locally and vice versa. This also makes the location of the storage an essential component in their overall potential to optimise the utilisation of the available grid.

Before exploring the benefits that storage can bring to the grid, it is important to understand how storage operations impact the grid. With the example of grid congestion, there are three different ways to describe storage operations from a grid perspective:

1 grid­straining: aggravates congestion;

2 grid­neutral: no impact on congestion;

3 grid­beneficial 7 reduces congestion.

When storage systems operate by responding to market signals without considering grid constraints, we call the operation grid­unaware. Grid­unaware operation can be at times reducing congestion, have no impact, but can also be grid­straining.

6 Grid operators can also take other measures such as allowing (temporary) overloads to reduce infrastructure reinforcement needs (e.g., dynamic line rating) or reconfiguring the grid topology more efficiently.

7 In order for storage operation to be truly grid-beneficial, all effects on the grid must be considered and not just the effects on congestion.

“Congestion within the German distribution grid has become frequent. A significant share of storage is connected to the lower voltage levels and, under the current economic incentives, can temporarily reinforce congestion. The right financial incentives, however, could realise the potential of storage to avoid congestion and, in particular, the curtailment of renewable energies.

When batteries exacerbate grid congestion, they also increase the need for grid expansion. This is because such batteries have high grid capacity requirements to always be able to inject and offtake compared to a normal consumer or producer. Think of the grid connection as a two-way highway. In the case of a battery, one lane in each direction would be blocked to make sure the car is able to travel in both directions, because batteries can quickly change their direction until close to real time which is hard to predict (see Chapter 3 for solutions to deal with unpredictability of fast-reacting storage). Meanwhile, for a consumer or producer, only one lane in one direction would be blocked as the car is always travelling in the same direction. The impact of batteries on the grid buildout is therefore highly dependent on how they are operated. To fully leverage their market benefits and optimise grid buildout, system­beneficial operation of storage systems is essential.

Moreover, the grid at lower voltage levels will also be affected by grid­unaware storage behaviour, as congestion is more frequent in the distribution grid as the analysis of University of Bayreuth and Forschungsinstitut für Informationsmanagement show (see Information Box 2.2). This underlines the importance of making storage operations aware of the grid situation at all voltage levels.

INFORMATION BOX 2.2

STORAGE AND GRID CONGESTION IN THE GERMAN DISTRIBUTION GRID

Scope

A study by the University of Bayreuth and the FIM Research Center investigated to what extent different battery storage systems would impact congestion within three selected distribution grids (DGs; Schleswig-Holstein Netz (SHN), Avacon (AVA) and Bayernwerk (BAY)). Each DSO operates thousands of kilometers of lines and cables on low, medium, and high voltage levels.

Approach

The study 1) simulates the dispatch of home batteries and large-scale batteries during the period of January 2024 to June 2025 and 2) analyses whether their charging behaviour aligns with or counteracts redispatch measures targeted at alleviating congestion within the DG. In the simulation, home batteries charge once PV generation exceeds consumption while largescale batteries optimise revenues at the day-ahead market. The study only considers redispatch which is caused by congestion within the distribution grid. (For more details on the simulation see Annex.)

Findings

Curtailment to alleviate congestion occurs more and more often in the selected DGs. Within the SHN grid, 67% of the hours during January 2024 to June 2025 experienced redispatch measures due to congestion within the DG. For redispatch measures with at least 100 appliances affected, the share of hours with curtailment is approximately 20% (see Figure below). While the share of hours with curtailment is comparable in the three DGs, the timing of the congestion is very different with respect to seasonal and daily patterns. In the BAY distribution grid, for example, the average curtailment profile largely follows solar feed-in.

The value of curtailment of wind and solar in the three DGs differs significantly (see Figure below). The study defines value of curtailment as the day-ahead electricity price weighted by curtailment volume which proxies the welfare loss or compensation costs spent for the curtailment. Vice versa, it indicates how much value a storage system could bring if dispatched during such curtailment hours. Due to relatively low DA prices on sunny days at midday, the market value in the BAY grid is much lower than in the wind-dominated north. Hence, a storage system that avoids curtailment in the SHN grid could reduce compensation costs much more than a storage system in the BAY grid.

During summer, Home batteries in the BAY grid charge in the morning, when little curtailment is recorded, and are already fully charged when the largest curtailment volumes (as a result of high PV feed-in) occur. During winter, in the SHN grid, there is only low solar PV infeed and irregular redispatch caused by within-DG congestion, such that saving potentials by home batteries are limited. The simulations of home batteries in SHN and AVA grids reveal more hours reinforcing than reducing congestion. In the BAY grid, it is the other way around.

Day-ahead market-optimised large-scale batteries do not impact congestion within the distribution grid for all three DGs during most of the time (85 to 88% of hours). In addition, large-scale batteries reduce congestion more often (double or triple) than reinforcing it. Therefore, based on the simulation results, large-scale batteries are more grid-friendly than home batteries in all three grids. When strong wind or solar PV feed-in leads to lower day-ahead prices, storage in wind- or solar PV-dominated areas tend to alleviate congestion. This analysis, however, excludes the impact on congestion in the transmission grid.

Key take-aways from the study

Home batteries should charge at times of high PV feed-in to alleviate congestion. If home batteries would react to day-ahead prices (similar to large-scale batteries in the simulation), their impact on congestion within DGs could be significantly improved. However, even large-scale batteries optimised on day-ahead prices sometimes still reinforce congestion. As prices do not reflect scarcities within the distribution grid, the grid impact of batteries eventually depends on wholesale market prices and the structure of the DG and may change.

PROF. DR. MARIE-LOUISE ARLT, Assistant Professor of ‘Information Systems Research, in Particular on Connected Energy Storage’, University of Bayreuth

“A grid-compatible rampup of large battery storage systems requires close cooperation between grid operators and storage providers. This begins with grid connection procedures, continues with a common understanding of gridsupporting behavior, and culminates in the joint development of solutions that neither overwhelm the grid nor prevent profitable business models for storage operators.

Unlike other grid users, storage systems are well­equipped to react quickly to signals provided to them and can combine market and grid signals to create most value for the system. Already today, storage systems optimise their operation on various markets (e.g., day­ahead, intraday, and balancing) based on price signals. This high flexibility potential should be used to provide the same value for the grid. Currently, this potential remains untapped as batteries operate in a grid­unaware way.

FfE (Forschungstelle für Energiewirtschaft, a German institute for energy economics) analysed the impact of grid­unaware storage operations on already existing TSO­level congestion in 2024 in three different regions in Germany 8 These analyses show that purely responding to national market prices can increase redispatching needs at certain times, while reducing them other times. When looking at the net effect of the analysed regions, grid­unaware

At the same time, significant grid capacity must be reserved for them to allow injecting or offtaking at full power at any time. This results in a need for substantial grid buildout. Batteries should therefore be made gridaware and their potential used to bring the most benefits for society.

operation can increase already existing redispatch volumes and potentially create addition redispatch needs (see Figure 2.4). The issue becomes especially critical when additional congestion worsens the already strained situation (e.g., during peak hours). In some years and regions, however, storage can also have net­zero or a net­reducing effect on congestion. However, congestion dynamics can quickly change with new grid users, changing profiles, and evolving grid configurations. Similarly, so do battery operations, reacting to evolving price signals. As a result, identifying regions where spot market­driven batteries provide consistent benefits over time, is impossible.

Impact of grid-unaware BESS operation on redispatch volumes in three German regions FIGURE 2.4

Battery dispatch optimised with FfE’s ‘eFlame’ model based on German DA and IDA1 prices and compared to regional redispatch needs in 2024

As the power grid is built to accommodate power flows of grid users, the type of storage operation has effects on grid expansion needs. This can be explained with a stylised example in Figure 2.5, which shows that grid­straining storage operation can lead to higher peaks than without storage in the system. To accommodate these higher peaks, more grid capacity is needed, increasing system costs. If grid­neutral storage operation can be ensured, previous peaks, and therefore, capacity needs, are not exceeded. Yet, the baseline available grid capacity could be used better. From a grid perspective, it would be ideal if storage was operated grid­beneficially which would smoothen grid utilisation and, importantly, reduce peaks to levels below the ‘no storage’ scenario. In the gridbeneficial storage operation scenario, less grid capacity would be tied­up, allowing more grid users to connect or reducing some grid expansion needs. Furthermore, analyses by the Reiner Lemoine Institut and NetzWende show that the dispatch

and grid expansion cost­minising battery dispatch profiles differ depending on the voltage level (see Information Box 2.3 for more details on study results).

To incentivise grid­neutral behaviour, or even grid­beneficial, appropriate signals need to be given, which can take multiple forms.

The location, operation, and connection set­up of storage are important dimensions for unlocking its full benefits for the grid and will be discussed in the next section.

“Many BESS projects receive non-firm grid connections — these flexible grid connections are considered a constraint rather than an opportunity. Incentivizing grid-friendly operation could transform this risk into locational value and accelerate smarter system integration.

FREDERIK JANSEN, Chief Technology Officer, Energy Solutions Group

Stylised example of the impact of storage operation on grid utilisation and grid capacity needs in load-dominated region FIGURE 2.5

DR. ANNA GRUBER, Managing Director, FfE

INFORMATION BOX 2.3

OPTIMAL STORAGE DISPATCH TO MINIMISE GRID EXPANSION COSTS AT DIFFERENT VOLTAGE LEVELS

A study conducted by Reiner Lemoine Institut (RLI) and NetzWende (NW) investigated the operational behaviour of battery storage systems to minimise grid expansion costs. For this, the authors modelled a future scenario for the year 2035 in Germany using the open-source grid models eTraGo and eDisGo as well as the interface eGo. The accumulated dispatch patterns of storage in the distribution grid is displayed for a sample week in summer and in winter.

Findings

In general, optimal charging and discharging patterns of storage systems in Case and Case 2 are not identical, but for a large part of sub-grids a broad matching can be observed. However, we need to pay attention to several details:

Approach

Calculate the optimal aggregated dispatch of storage in the distribution system. This dispatch was chosen such that the dispatch and expansion costs in the extra-high and high-voltage (eHV/HV) grid are minimised (Case 1). Grid expansion costs of the distribution grid are neglected in the optimisation of battery dispatch in this case.

2 Derive the optimal aggregated dispatch of storage considering only MV/LV grid expansion costs (Case 2). The dispatch is not predetermined by eHV/HV levels. The model utilises storage to smoothen the use of grid infrastructure in this case.

3 Compare the dispatch patterns of Case 1 and 2 (for more details on the simulation see Annex).

Local differences

The authors differentiate between 50 types for the MV/LV-grids, each one with a specific combination of assets, user, and topology. Local differences are visible for example during winter between the rural grids and the urban and suburban grids. Therefore, individual consideration of each grid type is needed for optimal results in the entire system.

differences

In the simulation, storage systems in Case 1 are charging/discharging at full capacity. In Case 2, however, the majority of batteries charges/discharges up to 50% (see Figure, 75% quantile). In Case 1, the storage pattern is optimised based on the grid expansion costs from the higher voltage levels and transferred to the storage units in the distribution grid. In Case 2, the aim is to keep the line loads low.

During summer, the dispatch patterns are more aligned between the two cases. While in summer, the patterns are clearly following a daily (solar driven) pattern, in winter these patterns are more fuzzy within the types of the distribution grids.

Expansion costs

In Case 2 grid expansion costs in the MV/LV level are almost 10% lower in comparison to Case 1. Therefore, optimisation of the dispatch based on the expansion costs in the eHV/HV level is less favourable for underlying MV/LV grid.

Key take-aways from the study

Good coordination between eHV/HV and MV/LV levels with respect to the deployment and use of storage capacities results in reduced grid expansion needs on all levels. It is important to co-optimise the grid at all levels together instead of separate optimisation.

Unused capacity of storage systems on the German MV/LV level could be used by the eHV/HV level and reduce the need for storage or the need for grid expansion there. However, new ways of coordination and cooperation would be needed to make that happen.

Battery storage systems offer considerable potential for integrating renewable energies and reducing grid expansion needs in both transmission and distribution grids. Their application, however, depends on the specific grid context. Coordinated measures across all grid levels are therefore essential to avoid inefficiencies and to fully harness the potential of battery storage for a costeffective energy transition.

UNLOCKING GRID BENEFITS

This section explores three fundamental levers for unlocking the potential of storage technologies: where to connect, how to integrate, and how to operate them. The order presented here follows the decision-making process of storage developers and operators, but not their importance. From a grid perspective, aligning storage operations with grid and system needs is most essential. Additionally, energy storage systems might also be employed as a grid asset in very select cases.

Where to connect? Locational incentives for storage deployment

System­ and grid­beneficial BESS operation is key for using their potential to optimise the utilisation of available infrastructure.

The choice of an efficient location for new storage units can further improve costefficiency from a system perspective. Moreover, unlike other grid users, such as industry, storage systems do not need any other specific infrastructure (logistical infrastructure, access to water, and so on).

Storage systems, therefore, have greater flexibility in choosing their location.

It is essential that BESS are geographically distributed across the grid. The spatial dispersion of BESS plays a critical role in:

maximising the grid hosting capacities for storage and other grid users; providing ancillary services and relieving local congestion; integrating (distributed) renewable generation; and

adding an additional layer of robustness for unforeseen events (see Chapter 3).

Solar PV is the main driver for large­scale battery deployment. Figure 2.7 shows the correlation between battery capacities and various parameters across European zones for 2050. As expected, those results show a clear positive correlation between solar PV generation and battery deployment. On the contrary, no such correlation is observed for wind generation or load. This is because batteries are ideal for short­term storage, suitable to integrate the daily cycles of solar peaks. Meanwhile, wind peaks can last for days which cannot be captured by

4h­batteries. The results indicate a slight negative correlation with load. This can be attributed to the modeling approach, which assumes that regions with higher load also have higher decentralised flexibility from electric vehicles, heat pumps and demand response.

flexibility), large­scale batteries are being installed.

Even though this cannot be assessed with the simplified European expansion market model, additional factors, like congestion are expected to be additional drivers for batteries. In zones where lines are frequently congested, batteries can play a role in relieving those congestion by operating in a grid­beneficial way.

The model also contains home batteries, but they are not depicted in the map as the investment in home batteries is not driven by system­level optimisation benefits but is based on local rooftop solar PV capacities.

The map also shows that concentrating batteries in regions with high solar PV generation relative to their 2050 assumed load is optimal from a system cost perspective (without taking lower voltage grid reinforcements into account). This explains the higher battery capacities observed in southern countries such as Italy and Spain, where significant solar PV installations are expected by 2050.

The market optimisation assumes systembeneficial operation of batteries, enabled by a market design that is forstering such behaviour. The model minimises total system costs by balancing the trade­off between extra­high voltage transmission grid expansion and large­scale battery buildout, identifying where storage can provide the greatest value to the system. More information about the model can be found in in Information Box 1.1 in Chapter 1.

Figure 2.6 shows the results from the European expansion model for a 2050 scenario focusing on identifying the costoptimal locations of large­scale battery installations. The map indicates that the deployment of large­scale batteries should be geographically dispersed (see Figure 2.6).

To summarise, expansion of large­scale batteries is small as long as there are sufficient other flexibility sources to capture the RES variability. In regions with relatively high solar PV capacities, compared to the size of load (and the available decentralised

Storage should be distributed geographically. Strategically placing

grid utilisation, thereby reducing system costs even further.

Tariffs and contracts should encourage behind-the-meter batteries. Otherwise we risk building highways to central storage— highways that will only create new traffic jams and take years to complete—while the real solution is already available today: local flexibility that keeps grids affordable and reliable. Behind-themeter batteries will deliver flexibility where and when it’s needed most.

CHRISTOPHE DEGREZ, Founder & Managing Director, Bnewable

Distribution of large-scale batteries in the European high-voltage transmission system, by installed capacity per load FIGURE 2.6

Simulation result of the European expansion model for a 2050 scenario in Europe

“Behind-the-meter storage is becoming a true enabler for industrial players—it allows them to smooth their peaks, optimise the use of their grid connection, and fully valorise onsite solar production. While today the best business cases often combine behind-themeter and front-of-meter operational models, growing grid constraints and local flexibility needs will make industrial storage a cornerstone of tomorrow’s energy landscape.

Why behind-the-meter? A step towards greater grid awareness

Optimising the utilisation of grid connections is essential for keeping grid costs, and the broader energy transition, affordable. By flattening peaks and/ or by respecting constraints at the level of the shared connection point, storage behind the meter can help limit the need for costly grid reinforcements.

The impact of storage on the grid is strongly influenced by its configuration: either front of the meter (FTM) or behind the meter (BTM). The two configurations fundamentally differ in their location relative to the connection point, access point, and coordination with other energy assets (see Figure 2.8). BTM storage is a storage system installed at the grid user’s side of the utility meter, typically at industrial sites, renewable generation facilities, or homes. FTM storage can be configured either as co­located or standalone. Co­located systems share a grid connection point with another asset but operate under separate metering, enabling coordinated yet distinct

operation. Standalone systems, by contrast, are fully independent in both physical connection and metering.

A BTM setup, where storage is integrated and its operation is optimised alongside other on­site generation and consumption assets, has a lower grid impact than a FTM configuration. In this set up, the assets are jointly exposed to the grid connection capacity constraints. This incentivises them to co­optimise grid usage by netting power flows without using the grid, essentially making them more grid­aware. As a result, such a BTM setup requires less grid capacity than the sum of the individual assets’ needs if they were operated purely grid­unaware in a FTM setup. As such, they minimise the risk of congestion. This results in a better grid utilisation and reduces some of the grid buildout need. Distributed BTM storage across multiple grid users also helps solve local congestion issues. This decentralised approach reduces the need for centralised interventions by the grid operator.

Theoretical use case

A theoretical use case compares BTM and FTM battery configurations, assessing the benefits for a synthetic Belgian industrial grid user and their impact on the grid 9

This hypothetical industrial grid user pays grid tariffs for the 70/36/30 kV grid in Flanders (Belgium) and has a yearly consumption of 215 GWh and a grid connection capacity of 50 MW. The storage unit is a 2­hour battery with a rated power of 12 MW. The battery optimises the grid user’s energy bill, which includes energy and grid tariff costs, under different operational constraints tied to each configuration, on a monthly basis. Under current regulation in Belgium, FTM batteries can be exempted from grid tariffs 10

In this use case the following set­ups are modelled: an industrial consumer without a battery (1), with a BTM battery (2), with a FTM battery exempted from paying grid tariffs (3), and a FTM battery without grid tariff exemption (4).

Figure 2.9 shows that BTM energy storage optimises and limits the offtake from the grid together with the industrial profile, while FTM storage co­located with industry results in higher peaks. For this, two sample days of the synthetic industrial load profile, the optimised storage dispatch in BTM and FTM set­up, as well as the combined profiles of consumption and storage are depicted.

The combined profiles show the impact on the grid. As both storage set­ups optimise revenues on spot markets, their profiles are largely similar. The graph clearly illustrates how BTM storage adjusts its dispatch profile to remain within the maximal grid capacity of 50 MW, during moments of high industrial demand. Meanwhile, the FTM storage units can charge during these

times, driving the offtake from the grid to 62 MW. From a grid perspective, a BTM set­up is therefore preferable.

Information Box 2.4 shows that household prosumers can minimise their total energy bill with a BTM battery.

“Behind the meter storage is more than technology—it’s part of the electrification journey for transport and beyond. It lowers grid costs, reduces congestion, adds value to PPAs, strengthens security of supply, and enables energy arbitrage where possible.

Sample days to illustrate the optimisation of the storage dispatch under different set-ups FIGURE 2.9

PROSUMER HOUSEHOLD STRATEGIES TO DEAL WITH SOLAR EXCESS

The number of hours with low or negative day-ahead electricity market prices increases each year. This is a particular concern for households with their own solar PV in Belgium who inject their excess into the grid. In hours of negative prices, they could be penalised for their injection. Therefore, self-consumption should be maximised at these times— but some surplus generation might remain. How should this surplus solar generation be handled? Prosumers are faced with three options: (1) do nothing and absorb the loss; (2) modulate the production of their solar PV to avoid injection at these times; or (3) store this excess energy in a home battery for later use.

Modulating excess solar is a competitive option

Based on the price conditions as they occurred in 2024, a Belgian home battery which optimises charging based on capacity-based grid fees has a payback period ranging from 7 to 16 years (depending on the investment costs related to battery installation). This assumes reference investment costs as described in TYNDP 2024 and a spread of 30% considering low and high price scenarios, compared to this reference. Generation modulation is found to be the most competitive option, in the reference and high battery cost scenarios, because no additional investment is needed and no losses occur. In these scenarios, reduced operational costs were found to be insufficient to recover the investment made.

However, prices of battery systems are rapidly decreasing. Furthermore, the deployment of plug and play systems reduces the overall investment even further. These developments could quickly alter this picture and further drive the deployment of home battery systems.

The figure above compares the operational costs for a prosumer in 2024, in case of (1) no alteration to the behaviour (natural load), (2) modulating the injection at negative prices (curtailed injection), (3a) natural charging, and (3b) optimised charging.

The operation mode of batteries has a significant impact on the savings that can be materialised. When the operated

in market-oriented way, cost savings of up to 30% can be materialised compared to natural charging.

A significant part of these savings is related to avoiding to pay by considering dynamic capacity-based grid fees. Therefore, grid fees 2 should be designed in such a way as to nudge towards system-oriented behaviour, in line with market and grid realities.

Home batteries can assist in managing the solar excess. However, at current prices, modulating production in moments of negative prices is the more competitive option. Decreasing battery costs could change this picture. In any case, operating batteries in a market-oriented way significantly reduces operational costs for the prosumer. The importance of grid fees in the cost structure for prosumer households is increasing. Thus, grid fees should be used to nudge towards system-oriented investment and operational decisions.

1. ENTSO-E (2024). ‘TYNDP 2024 Scenarios Methodology Report’. Available online: https://2024.entsos-tyndp-scenarios.eu/wp-content/uploads/2024/07/TYNDP_2024_Scenarios_Methodology_Report_240708.pdf (last accessed on 16/10/2025).

2. VREG (2023). ‘Wat is het capaciteitstarief en hoe wordt het berekend?’. Available online https://www.vlaamsenutsregulator.be/nl/wat-zijn-de-nieuwe-nettarieven-en-hoe-worden-ze-berekend (last accessed on 16/10/2025).

The design of network tariffs can influence prosumer investment and operational decisions

Network tariff signals also have an impact on design choices, as research by Jolien Despeghel and Johan Driesen at KU Leuven, Belgium shows:

In this research, an optimization model was developed and applied to the optimal sizing and operation of residential PV-battery systems. The investment decisions of 200 households are studied under both volumetric and capacity-based tariffs, and under different electricity price assumptions.

When shifting from a volumetric to a capacity-based network tariff, the electricity price per kWh withdrawn from the grid decreases. As a result, this leads to a median reduction in battery size up to 24.2%, a median decrease in self-sufficiency up to 11% and a greater incentive to reduce the peak power demand. The capacity-based network tariff does not deter households from becoming prosumers and installing a PV-battery system, as the equivalent annual cost is still lower than when they were consumers. However, the potential emission reductions of a prosumer are slightly lower under a capacity-based than volumetric network tariff. Regardless of the network tariff, the observed potential of reduced peak power demand could solely be sufficient reason for DSOs and policymakers to incentivize consumers to become a prosumer.

When the feed-in remuneration increases to a level above the LCOE of the PV-battery system, all consumers benefit from becoming a prosumer regardless of the level of selfsufficiency, and maximizing the installed PV system is the optimal solution. Furthermore, the investment driver shifts from minimizing grid withdrawal to maximizing feed-in. Reducing the peak demand charge is never the main investment driver in the studied scenarios.

Installing the maximum possible PV capacity is a way to hedge against potential electricity price increases and to future-proof the installation as the annual consumption is likely to increase due to household electrification.

How to operate? Constraints and incentives to optimise storage operations

In the dynamic energy landscape, signals need a temporal and geographical component, to reflect the local grid situation and address congestion risks (as described in the previous section). There are several different instruments which can provide such signals with differing effectiveness and efficiency.

Direct control instruments 11 (e.g., Flexible Connection Agreements or FCAs) enable the grid operator to constrain the operation of assets, for example, in response to anticipated or actual grid congestions, effectively limiting their injection and or offtake capacity during the activation. Coordinated control instruments (e.g., local flexibility markets) refer to instruments in which a central entity collects and processes information such as bids and schedules, and issues control and/or price signals to enable system­oriented behaviour. Implicit control instruments (e.g., grid tariffs) incentivise system­oriented behaviour through economic signals, thereby allow the optimising market­oriented and gridoriented operation via price signals.

11 Direct control and the following definitions and types of further control instruments are based on a grouping done in FfE (2025). ‘Anreizmechanismen zur Stromnetzentlastung’. Available online: https://www.ffe.de/wp-content/ uploads/2025/03/Whitepaper_Anreizsysteme.pdf (last accessed on 16/10/25).

“Connecting battery parks is essential for the energy transition. To accelerate progress in Flanders, the regulatory framework for connections must be further developed, first, to prevent batteries from negatively impacting existing grid hosting capacity, and second, to create a true win-win where batteries actively support grid reliability.

LIEVEN DEGROOTE, Head of Grid Development, Fluvius

Flexible Connection Agreements

Connecting storage systems through FCAs 12 enables faster grid access, removes the risk of congestion caused by this specific storage system, promotes gridoriented behaviour, and allows the integration of more storage capacity into the system while taking other grid users into account as well. FCAs, therefore, are needed now to ensure that large amounts of storage can be integrated smoothly into the system without creating congestion or aggravating existing ones.

FCAs are an established tool in countries like Belgium, Denmark, France, the Netherlands, and the United Kingdom to connect grid users faster by offering them temporary non­firm connection agreements to allow the injection/offtake capacity to be limited 13 TSOs and DSOs activate the FCA with a pre­defined lead time or in real­time when there is congestion. When the FCA is activated, the asset’s injection or withdrawal capacity is capped to the maximum power specified in the FCA. As such, FCAs are a solution for faster connection of grid users while ensuring system security. However, they do not systematically increase the available firm capacity in the grid. In fact, an asset with an FCA will typically use (a part of) the available margin and will thereby reduce the available firm capacity for all that come afterwards.

FfE analysed the potential redispatch impacts of a market­optimised battery with an FCA on the extra high voltage grid in two German regions in 2024 14 The analysis assumes perfect foresight of market prices and grid situations, FCAs are activated ex ante allowing for batteries to adjust their operation compared to a scenario without the FCA. Figure 2.10 shows that FCAs can effectively eliminate redispatch­increasing operation of batteries compared to the grid­unaware storage operation. For this, a capacity constraint must be introduced in hours of congestion to ensure that the battery operation in these hours is gridneutral and hence does not cause any additional congestion. Such FCAs also allow for some of the market­driven redispatch­reducing operation to be maintained, although it is not incentivised by the instrument 15

FCAs provide a high certainty for grid operators and therefore ensure a reliable grid for all grid users, because they allow TSOs and DSOs to impose strict limits on asset operators. However, it also means that additional constraints are imposed on these assets. As such, the asset operators cannot autonomously decide on a system­oriented behaviour. This limits the optimisation options for asset operators which impacts the cost efficiency of the tool from a market perspective. Figure 2.11 shows that the revenue losses from

wholesale trading (day­ahead and intraday auction) which battery operators incur from being restricted in some hours are below 5% in all analysed regions. However, on a societal level, these energy arbitrage revenues losses are recovered through decreased redispatch costs in the modelled regions. So, for the analysed regions, the FCAs result in an overall welfare gain.

By activating FCA restrictions in real­time, the volumes can be reduced as there is more certainty about the actual grid situation. Unlike some of the following instruments, FCAs that limit the electricity injection to or withdrawal from the grid are already implemented in European and national regulation.

12 A Flexible Connection Agreement (FCA) is an instrument for grid operators to manage congestion without the need for ad-hoc direct control over the connected asset (interference into operations). According to Directive (EU) 2019/944 Article 2 d (24c), FCAs are an agreed set of conditions to ‘limit and control the electricity injection to and withdrawal from’ the grid. Directive EU 2024/1711 (2024). Available online: https://eur-lex.europa.eu/legal-content/EN/TXT/HTML/?uri=OJ:L_202401711 (last accessed on 16/10/2025).

13 There are other types of contractually agreed limitation that can, e.g., limiting schedule changes, and which might be more applicable for other challenges as discussed in Chapter 3.

14 Additionally, another region was modelled with similar results. Please refer to the Annex for these results. In this analysis, the battery operation was optimised based on 2024 DA and IDA1 prices in Germany. An ex-ante capacity limit was provided to batteries to be considered in their optimisation.

15 These findings are robust to different trading strategies, such as spot only (DA and ID auction) or incl. balancing service provision, but do not consider the issues caused by close-to-realtime trading by batteries (to be further discussed in Chapter 3).

Generation-dominated, transit region Load-dominated region

Redispatch­increasing operation

Net

We see battery storage as a key enabler to make better use of existing grid infrastructure and keep system costs affordable. We already operate assets gridsupportively, for example by accepting dynamic operating conditions that reflect local grid needs. The key challenge now is to properly design frameworks that recognise and reward such system-beneficial operation, turning flexibility into a shared benefit for the grid, consumers and investors alike.

Improvement

FIGURE

CHRISTINA HEPP, Director Strategy, green flexibility

Dynamic grid tariffs

Providing temporal and locational grid incentives, via dynamic grid tariffs, can be part of the solution to incentivise gridbeneficial behaviour of batteries in the future. However, implementing dynamic grid tariffs today would be very challenging. Via smart grid tariffs, locational and/or temporal price signals could be sent to batteries. Currently, however, batteries are exempted from paying grid tariffs in Belgium and Germany. To reflect grid bottlenecks, these grid tariffs would have to vary over time and location 16 to best address congestion issues, that also vary over time and location. On the way there, variations could be limited to one dimension (e.g., time of use) and be fixed in advance or fully dynamic based on the local grid conditions and communicated with short notice. In general, such dynamic grid tariffs could be introduced for all grid users, but they especially make sense for assets that can react at short notice 17 such as battery storage systems.

Two additional dimensions can be considered in the tariff design:

1 Which type of operation is subject to grid tariffs? Offtake­only, injection­only, or for both. To incentivise grid­beneficial behaviour, dynamic grid tariffs should be applied for both injection and offtake. Otherwise, if there is no dynamic grid fees on injection, batteries can still strain the grid further by injecting (i.e., discharging) when there already is a surplus in the region. To return to the highway example: if cars would have to pay a higher fee for using the highway when there is traffic jam in their direction, they are signalled to avoid using the highway at such times, therefore freeing up space and potentially alleviating the traffic.

2 Are negative grid tariffs possible, meaning payments from grid operator to the asset for grid­beneficial operation? Typical grid tariff designs comprise one­way payments from grid users to the grid operator. Such a design can penalise grid­straining behaviour, meaning batteries have to pay (higher) grid tariffs when it is reinforcing congestion and implicitly incentivises grid­neutral and grid­beneficial operation with lower or zero tariffs. Alternatively, grid­beneficial operation could be explicitly incentivised with negative grid fees, where the grid operator would pay the storage facility during times when their operation is aligned with grid needs.

Assuming perfect foresight and a perfect grid signal via dynamic grid tariffs that allows for batteries to adjust their trading, the potential redispatch impacts of a market­optimised battery in a German generation­dominated region was analysed for 2024 18 Figure 2.12 shows that redispatch­increasing battery operation cannot be eliminated with any of the analysed dynamic grid tariff designs. For the offtake­only dynamic grid tariff, redispatchincreasing operation even rises compared to grid­unaware storage operation without grid fees. On the other hand, the figure shows that negative fees in Scenarios 1 and 3 clearly creates additional incentives for redispatch­reducing operation by the battery. All analysed dynamic grid tariff designs reduce the net redispatch 19

Determining correct dynamic grid tariff signals ex ante 20 and anticipate the reactions correctly is a complex undertaking.

Moreover, assets are not obliged to behave in a certain way but only receive a grid price signal which is weighted against the market price signal. Especially during hours with extreme price spreads, the grid tariff signal might not be sufficient to change the (potentially redispatch­increasing) operation. Therefore, dynamic grid tariffs do not guarantee the needed reliability to address congestion. This will also require complementary measures to ensure that residual congestion can be solved.

Figure 2.13 shows the economic impacts of the analysed dynamic grid tariffs compared

to the no grid tariff scenario. In Scenario 2, the redispatch cost savings offset the battery’s market revenue losses, resulting in a slight net economic benefit. The net economic benefit is higher for Scenarios 1 and 3. In those cases, the battery operator reaps these benefits through additional market revenues and negative grid fees received of the grid operator. In an ideal world, with a properly cost­reflective dynamic grid tariff component, the grid tariff incentives paid should be similar to the redispatch cost savings, such that the net effect for other grid fee payers would be neutral (as in Scenario 3).

16 It could also be either/or, but here we refer to variable over time and variable over location to effectively address regional redispatch needs.

17 Dynamic grid tariffs require suitable metering and control devices to be installed.

18 Additionally, two other regions were modelled with similar results. Please refer to the Annex for these results. In this analysis, the battery operation was optimised based on 2024 DA, ID-auction, and FCR prices in Germany. An ex-ante grid signal was sent to allow batteries to weigh market and grid signal in their optimisation.

19 Confirming the results of the consultation document and study of NEON, a German consultancy, for the German AgNes-Process. NEON (2025a and 2025b). ‘Netzentgelte für Großbatterien’. Available online: https://neon.energy/Neon-Netzentgelte-Gro%C3%9Fbatterien and https://neon.energy/Neon-Netzdienlichkeit-Gro%C3%9Fbatterien.pdf (last accessed 17/10/25).

20 Ex-post or close to real time determined tariffs are alternatives, but such grid price signals would be challenging to communicate. Moreover, it might be difficult for small consumers and small companies to predict their bills and react in the absence of aggregators.

region

operation Redispatch­increasing operation

Net redispatch impact

Other potential future instruments

Critical peak pricing grid tariffs refer to capacity­ or energy­based grid tariffs with fixed rates applied during high­stress periods on the grid. They could serve as a complementary instrument to dynamic grid tariffs. Their goal would be to ensure batteries responsiveness during critical grid situations, enhancing reliability of a certain peak capacity not being exceeded.

Local flexibility platforms can be used for a market­ or cost­based congestion management, as seen in Denmark, France, the Netherlands, and Sweden. Compared to the grid tariffs they can be more effective in reducing local congestion by requesting the needed quantity instead of providing a price signal. However, as assets are not obliged to provide these volumes, the reliability for solving the congestion is lower than for FCAs.

Several other instruments are possible but not further discussed here, including the redispatch of storage systems at cost. This section presented some examples of instruments from three categories: direct, coordinated, and implicit control instruments. These categories and their measures offer different benefits and have different downsides, which from a system perspective can be summarised as reliability and efficiency of the measure (see Figure 2.14). Hence, a mix of complementary instruments is most suitable to provide a solid framework for storage operations in line with system needs.

STORAGE AS AN ALTERNATIVE TO TRADITIONAL GRID ASSETS

Several studies and pilot projects have looked into the potential of replacing or complementing traditional grid assets with storage. Some findings are summarised here. Strategically deployed storage under regulated operation can, for example, temporarily increase grid capacity when immediate grid reinforcement is constrained .However, the economic viability of using storage as a grid asset remains limited to specific cases. Nonetheless, there are some concepts for using storage as a complement to traditional grid assets that TSOs and DSOs are discussing.

Virtual power lines include two batteries that are connected at different points to the grid and can, for a limited duration, boost the existing “line capacity” without building additional grids The French TSO, RTE, has piloted a virtual power line, called the Ringo project

Grid boosters enhance the utilisation of existing lines by serving as a back­up in case of an incident4 They enable power flows, that would otherwise exceed secure operational limits, with the battery providing contingency support. Examples of grid boosters currently under development include projects in Germany by Amprion5 Transnet BW6 and Tennet as well as in the Spanish Balearic Islands by Red Eléctrica8

At a local level, community batteries can support grids, enable higher residential solar PV integration and offer a more cost­efficient alternative to individual home batteries 9 For instance, the Australian DSO, Ausgrid, has already installed multiple community batteries in their grid, with the first one commissioned in 202110/11 Under the federal government’s Community Batteries for Household Solar program, there is an ambition to deploy 400 community batteries across Australia12

 When households generate more solar energy than they consume,

 the excess can be stored in community batteries for future use.

 These shared storage systems serve multiple users whose power demands occur at different times. Because their consumption patterns differ, a smaller battery can efficiently meet most of the collective electricity needs13

power line

 During periods of congestion on the respective line, a supply­side battery charges the energy that cannot be transported, thereby avoiding curtailment.

 Simultaneously, a demand­side battery discharges, relieving transmission constraints, while still meeting the energy needs.

 When grid capacity becomes available on the line (e.g., during low demand), the supplyside battery discharges to the demand­side battery.

Constraints of storage as a grid alternative

 In case of an incident in the grid, for example a power line becomes unavailable, and the flows are restricted.

 Therefore, power generation must be curtailed.

 To relieve the remaining power lines of surplus load.

 The battery on the load side discharges to maintain balance and ensure supply.

Unlike traditional grid assets, batteries cannot operate continuously. Their typical discharge duration ranges from two to four hours at nominal power. The longer the congestion lasts, the bigger the battery needs to be, and the less economically interesting it becomes compared to traditional grid reinforcements.

Identifying strategic locations to place storage can be challenging given how quickly local grid profiles evolve, including through new grid users, changes in grid topology, and other factors. This can entirely change power flow profiles at substations and an initially effective location to relieve grid constraints, can suddenly become obsolete. Additionally, land availability at substations can be another limiting factor, although using existing sites may help accelerate permitting and deployment compared to power lines.

Under EU Directive 2019/944, grid operators are not permitted to own, develop, manage, or operate energy storage facilities. A regulatory derogation may be granted only if no market actor is willing or able to provide the service at a reasonable cost, and if the storage is a fully integrated network component used exclusively to ensure system stability and security, but it cannot be used for balancing, congestion management, or market participation. Storage as a grid asset can also be implemented through third­party ownership or service models, where a provider owns (and operates) the battery, and the grid operator contracts specific regulated services via tenders. Such arrangements require clear agreements on availability, pricing, and responsibilities.

For instance, grid reinforcements could be constrained by permitting delays or supply chain issues: IEA (2023). ‘Building the Future Transmission Grid’. Available online: https://www.iea.org/reports/building-the-future-transmission-grid (last accessed on: 16/10/2025).

2 IRENA (2020). ‘Virtual Power Lines – Innovation Landscape Brief’. Available online: https://www.irena.org/-/media/Files/IRENA/Agency/Publication/2020/Jul/IRENA_Virtual_power_lines_2020.pdf (last accessed on: 24/09/2025).

3 RTE (2021). ‘Stockage d’électricité – Projet RINGO’. Available online: https://www.rte-france.com/projets/stockage-electricite-ringo#Leprojet (last accessed on: 24/09/2025).

4 Lippert, M. (2024). ‘Storage as a Transmission Asset in the Grid of the Future’. Presentation at ESGC 2024, organised by EASE. Available online: https://ease-storage.eu/wp-content/uploads/2024/10/1.6-ESGC-2024_Saftv_Michael-Lippert.pdf (last accessed on: 24/09/2025).

5 Amprion (n.d.). ‘Dezentraler Netzbooster’. Available online: https://www.amprion.net/Grid-expansion/Our-Projects/Dezentraler-Netzbooster/ (last accessed on: 24/09/2025).

6 TransnetBW (n.d.). ‘Grid Booster’. Available online: https://www.transnetbw.de/en/company/portrait/innovations/grid-boosterTransnetBW (last accessed on: 24/09/2025).

7 Fluence & TenneT (2023). TenneT and Fluence Media Kit. ‘Overview of Grid Booster energy storage projects and strategic deployment in Germany’. Available online: https://info.fluenceenergy.com/hubfs/TenneT%20Media%20Kit%202023_EN_final_web.pdf (last accessed on: 17/10/2025).

8 Red Eléctrica (2025). ‘Red Eléctrica inicia las obras de las baterías de Menorca en Mercadal’. Available online: https://www.ree.es/en/press-office/news/press-release/2025/02/ (last accessed on: 24/09/2025).

9 Ausgrid (n.d.). ‘Community Batteries’. Available online: https://www.ausgrid.com.au/In-your-community/Community-Batteries (last accessed on: 24/09/2025).

10 PV magazine Australia (2024): ‘Bondi battery marks step change for energy storage says Ausgrid’. Available online: https://www.pv-magazine-australia. com/2024/08/05/bondi-battery-marks-step-change-for-energy-storage-says-ausgrid/ (last accessed on: 13/10/2025).

11 RenewEconomy (2024). ‘Ausgrid installs first of many community battery installations in Sydney network’. Available online: https://reneweconomy.com.au/ ausgrid-installs-first-of-many-community-battery-installations-in-sydney-network/ (last accessed on: 13/10/2025)..

12 Department of Climate Change, Energy, the Environment and Water (2025). ‘Community Batteries for Household Solar Program’. Available online: https://www.dcceew.gov.au/energy/renewable/community-batteries (last accessed on: 13/10/2025).

13 KPMG (2020). ‘Ausgrid Community Battery Feasibility Study Report. Prepared for Ausgrid’. Available online: https://www.ausgrid.com.au/-/media/Documents/ Reports-and-Research/Battery/Ausgrid-Community-Battery-Feasibility-Study-Report-2020.pdf (last accessed on: 21/10/2025).

“Ausgrid is rolling out 5 MW community batteries at substations on the 11kV network. With Australia leading the world in household solar installations, these batteries not only help to soak up excess solar and reduce peak demand, but can also provide critical network support during emergency events. They unlock value by alleviating network constraints while supporting equitable customer access and bill savings. Simply put, they are cheaper for customers, better for the community and greener for the grid.

FELIX KECK, Distributed Energy Storage Commercial Director, Ausgrid

2.3 GRID ACCESS FOR ALL

The previous sections show how systembeneficially located, connected, and operated storage can enhance the affordability of the energy transition not just by reducing costs, but also by optimising grid utilisation. This section takes a step back to examine the first steps for getting connected to the grid, which is a key enabler for fair access of different user categories to the energy system.

Electrification is accelerating, alongside the rapid deployment of renewables and emerging technologies such as data centres and large­scale batteries. Driven by favourable business cases, low entry barriers, and speculation, grid connection requests continue to soar and clog the grid connection queue. In particular, connection requestions from battery projects have surged over the last years.

The current process requires a significant update for many reasons, but the storage surge is making its shortcomings especially obvious. It is not fit for handling such volumes, and the available grid capacity cannot accommodate all requests. Grid connection reform is needed to allocate the available grid capacity more effectively, ensure timely delivery of physical connections, and maintain fair access for all grid user categories.

Two core components underpin this reform: the grid connection process and the delivery of infrastructure. A comprehensive grid connection reform addresses five key pillars: queue management, study process, capacity allocation, grid infrastructure delivery and connection contract conditions. The following sections will primarily focus on the first three pillars.

CURRENT PROCESSES ARE NO LONGER FIT FOR PURPOSE

Across Europe and beyond, grid operators face an unprecedented surge in grid connection applications by generation and storage, often largely exceeding peak load (see Figure 2.15). For instance, between 2020 and 2025, the number of connection

requests in Belgium increased fourfold at the TSO level. Meanwhile at the distribution level, connection requests increased twofold between 2022 and 2024, with a significant surge in requests in 2025 (see Figure 2.16).

The grid connection queue size in different countries (source: BCG) 21

Number of connection studies at DSO and TSO in Belgium*

*End of August 2025

As highlighted in Chapter 0, storage connection applications are surging. The current TSO storage application pipeline covers over 300% of the respective peak demand in both Belgium and Germany 22/23 The storage volumes applying for grid connections go far beyond expectations in validated development plans (see Figure 2.17). It can be questioned whether all these projects will even materialise.

21 BCG (2025). ‘Mind the Queue: Connection Reform for the Electricity Grid’, p.5. Available online: https://www.bcg.com/publications/2025/mind-the-queue-connection-reform-for-the-electricity-grid (last accessed on: 21/10/2025).

22 Peak load in Belgium in 2024: 11,7 GW –– OpenDataElia (2025). ‘Load on the Elia grid’. Available online: https://opendata.elia.be/ (last accessed on: 21/10/2025).

23 Peak load in Germany in 2023: 73,7GW –– Bundesnetzagentur (2025). ‘Monitoring report 2024 Summery’, p.14. Available online: https://data.bundesnetzagentur.de/Bundesnetzagentur/SharedDocs/Downloads/EN/Areas/ElectricityGas/ CollectionCompany, SpecificData/Monitoring/MonitoringReport2024.pdf (last accessed on: 21/10/2025).

FIGURE 2.15

Unprecedented amount of connection studies ordered both at the TSO and DSO level in Belgium

FIGURE 2.16

Battery storage grid connection requests at TSOs in GW FIGURE 2.17

In relation to Federal Development Plan for 2034 (2022 version) in Belgium24 and Grid Development Plan (NEP – Netzentwicklungsplan) for 2037 in Germany (2025 Scenario Framework)25

Existing grid connection procedures cannot manage today’s surge in applications. The long queues and delivery delays are leading to frustrations, reducing investment appetite. The “first come, first served” approach is clearly showing its limits. While this principle is not explicitly advanced in European legislation, it was originally assumed by many national authorities as the way to level the playing field among grid user candidates. This approach is, however, no longer fit for

purpose when it comes to building a grid that enables societal objectives outlined in national development plans, such as renewable integration and decarbonisation through electrification. It now gives rise to several challenges, particularly when one technology grows faster than anticipated and risks taking a disproportionate share of limited available grid capacity (meaning both, available connection points and grid hosting capacity). This would leave little capacity for other critical grid user

categories, including industries and renewables. It creates a vicious circle: soaring applications for limited available grid capacity fuels speculation and uncertainty, leading to even less availability. Immature or speculative requests block the connection pipeline.

This not only delays viable projects but also threatens the timely availability of necessary assets, affecting network security and planning.

Not only are grid operators and developers affected by this, but investors, policymakers and industry as well. The current situation poses a serious risk to achieving climate targets and maintaining industrial competitiveness. The cost of inaction is high.

New concepts and a holistic framework are needed now to allocate available grid capacity wisely, in line with local and national strategic targets.

24 Elia (2023). ‘Federal Development Plan 2024-2034’, Available online: https://www.elia.be/en/infrastructure-and-projects/investment-plan/federal-development-plan-2024-2034 (last accessed on 21/10/25).

25 Netzentwicklungsplan Strom (2025). ‘Genehmigung des Szenariorahmens für den Netzentwicklungsplan Strom 2025-2037/2045’, Available online: https://www.netzentwicklungsplan.de/sites/default/files/2025-04/250430_Genehmigung_ Szenariorahmen_2025_2.pdf/ (last accessed on 21/10/25).26EnergyVille (2025). ‘PATHS2050 Coalition: Belgian Energy System Pathways 2025’. Available online: https://perspective2050.energyville.be/sites/paths2050/files/2025-04/PATHS2050%20 Coalition_2025_ExecutiveSummary.pdf (last accessed on: 06/11/2025).

26 EnergyVille (2025). ‘PATHS2050 Coalition: Belgian Energy System Pathways 2025’. Available online: https://perspective2050.energyville.be/sites/paths2050/files/2025-04/PATHS2050%20Coalition_2025_ExecutiveSummary.pdf (last accessed on: 06/11/2025).

INFORMATION BOX 2.6

GRID CONNECTION APPLICATIONS OF BATTERY STORAGE AT THE 4 TSOS IN GERMANY

Current status

Available and new grid connections at the 380 kV level are limited. At the same time, grid connection requests are evidently massively oversubscribed—there are more than 200 GW of battery projects in the pipeline at the 4 TSOs alone. Despite the intensive expansion and construction of new substations, we anticipate a significant shortage of available connection points in the foreseeable future compared to the requested capacity. The exceptionally high number of grid connection requests for large­scale battery storage systems, managed within the current “first come, first served” framework, will lead to irreversible lock­in effects in the short and medium term.

The 4 TSOs are currently developing proposals for a new grid connection process (the process excludes generators, which are subject to separate regulations in Germany).

This new approach will prioritise project maturity, grid benefit, and system security. However, since it is currently not legally possible to implement such a procedure under the existing regulatory framework, the 4 TSOs can only advocate for its introduction. Numerous constructive discussions with industry stakeholders have proven the support for the proposed 4 TSO concept which main characteristics will be finalised by the end of 2025.

Further considerations

In addition to this concept—which could soon allow the allocation of currently existing connection points— future models could involve, for example, the allocation of further available capacity through auctions. Looking ahead, connection capacity for certain technology (e.g., battery storage systems) may need to be limited to ensure appropriate consideration for other grid customers, such as industry, gas­fired power plants, and data centers. With 41 GW, the ‘scenario A’ target of the grid development scenario plan for large­scale batteries by 2037 has already been met through the grid connection commitments granted to date by all 4 TSOs.

MOVING BEYOND “FIRST COME, FIRST SERVED”

A new approach for the grid connection process should provide better access control to the grid connection queue and ensure more efficient and dynamic queue management, in the interest of the projects meeting transparent criteria in terms of maturity and/or having societal value. Active queue management, optimised study processes, and capacity allocation based on societal choices are key levers for moving beyond “first come, first served”. These components will be critical to objectivise the congestion expected in the future and thereby increase the predictability of the business case of current and candidate grid users.

Active queue management

Introducing clear readiness and maturity criteria ensures that capacity is reserved for well­prepared and viable projects while avoiding speculative, immature, or stalled projects from entering or holding up the queue.

Requesting financial commitments such as study deposit amounts and withdrawal penalties, can help to discourage speculation but alone are insufficient and more effective when complemented by other queue efficiency measures.

Greater transparency around capacity availability, criteria and specifications enable new grid users to develop targeted projects. This improves application quality, enhances process efficiency and supports better alignment between system needs, removing barriers of discrimination and allowing prospect applicants to sufficiently optimise their grid applications.

Optimised study processes

A coordinated and harmonised process across grid levels is needed to avoid shifting problems to other voltage levels.

Shifting towards a periodical application intake for grid connection requests allows for batch assessment rather than handling application individually. This approach helps manage efficiency in study processing for operators and transparency for applicants. It also provides more reliable grid planning data which quickly becomes outdated in continuous processes.

Capacity allocation based on societal choices

Grid capacity allocation should reflect societal needs and be linked to broader strategic targets such as industrial competitiveness, decarbonisation, and energy security. On a national and regional level, clear capacity allocation targets should be set for each category of grid users, in line with the strategic plans. This ensures that grid capacity does not simply go to certain fast­movers but is used where it delivers the greatest value for society. As such, a balance between all relevant groups of grid customers is maintained.

Capacity can be allocated through competitive mechanisms such as auctions or tenders, where projects that fulfil the set of multiple criteria best, win the right to connect to the grid. Criteria may include willingness to pay, cost effectiveness, socioeconomic and environmental benefits, technology mix, and more.

Energy storage has tremendous value for society that should be further unlocked. It creates strategic autonomy, increases market welfare and further accelerates the energy transition. In order to achieve those effects, we will need to develop the right frameworks for fast grid connections, equitable grid tariffs, clarity on provisions of services to Elia and a stable regulatory framework.

JOERI SIBORGS, General Manager Belgium, GIGA Storage

Moving beyond “first come, first served”

FIGURE 2.18 3 | Active access queue management

STORAG AND SYST M S CURITY

Chapter 1 demonstrated the need for storage systems to achieve decarbonisation targets. The contribution of storage systems to the affordability of the system is analysed in Chapter 2, which clarifies that storage must be considered alongside flexibilities from demand and generation.

This chapter explains how the deployment of various storage technologies can improve system security, reliability, and adequacy. Potential risks for the power system associated with storage operations are discussed. The valuable contributions that storage can make to these areas are also highlighted.

The first section focuses on the potential of storage for providing ancillary services. In light of decarbonisation targets, storage operators, alongside renewable power producers, can become a key provider of ancillary services, depending on the technological capabilities of a given technology.

The second section takes a deeper look at risks related to frequency stability and short-term congestion, as well as relevant mitigation measures.

While BESS offer significant benefits for grid stability and flexibility, the potential to participate in close-toreal-time trading can introduce new risks to system security.

The third and last section outlines how BESS can contribute to adequacy and the implications of decreasing derating factors for battery storage.

In addition, the importance of longduration energy storage is highlighted as it is needed to manage an energy balance that extends beyond hours or days.

“Germany’s power system faces a storage gap: high penetration with renewables, but too little flexibility. BESS offers precisely the kind of fast, valuable response the grid needs if deployed in ways that support system stability and welfare rather than add stress. By combining renewables with storage, we can close the gap, strengthen adequacy, and enhance resilience. The key lies in grid-serving concepts that align flexibility with secure operation, while accelerating electrification of transport and heat as well as the AI transformation.

GEORG GALLMETZER, Co-founder and Managing Director, ECO STOR

3.1 SUPPORTING GRID STABILITY AND FAST RECOVERY AFTER OUTAGES

Grid operators are responsible for operating the power system in a stable and reliable fashion.

Electric parameters such as grid frequency and voltage, among others, have to be kept within acceptable limits. Ancillary services include a variety of services beyond generation and transmission to meet these objectives at each voltage level 1/2 . Storage systems can provide or support many of these ancillary services.

Ancillary service is a service necessary for the operation of a transmission or distribution system, including balancing and non-frequency ancillary services, but not including congestion management3/4

The energy transition is leading to an increasing amount of inverter-based renewable power generators. As a consequence, the variable feed-in by wind generation and solar PV increases balancing needs and makes stable grid operation more complicated. In addition, there will be fewer conventional thermal generation plants. As these have played a key role in contributing to ancillary services, new providers will be required to ensure system stability. This is where both renewable generators and storage units come into play.

As shown in Figure 3.1, different storage technologies are suitable for specific ancillary services.

Panos, E. et al., IEA-ETSAP (2019/Update 2021). ‘Enhancing the flexibility in TIMES: Introducing Ancillary Services Markets’. p. 5.

2 Graebig, M., et al. (2023). ‘Sun, Wind & Wires. Atlas of an Energy System in Transition’. Ellery Studio. p. 42.

3 Directive (EU) 2019/944/EC of 5 June 2019 on common rules for the internal market for electricity and amending Directive 2012/27/EU (recast). OJ L 158/142. Art. 2 (48).

4 Directive (EU) 2019/944/EC of 5 June 2019 on common rules for the internal market for electricity and amending Directive 2012/27/EU (recast). OJ L 158/142. Art. 2 (49).

FREQUENCY-RELATED ANCILLARY SERVICES

BESS, pumped hydropower storage and LDES can provide frequency control services. BESS can particularly help maintain frequency stability in grids with high shares of renewables.

Grid operators procure balancing reserves on the balancing markets. These reserves are used by grid operators in case generation and consumption are not perfectly in balance to maintain a stable grid frequency of 50 Hz. In most markets across Europe, there are three types of products available (see Figure 3.2).

Frequency containment reserve (FCR) is the fastest control service to stabilise frequency in case of a sharp dip or rise and must be fully available within 30 seconds. Automatic frequency restoration reserve (aFRR) must be available within 5 minutes to replace the FCR and to further restore frequency to the set point of 50 Hz. Manual frequency restoration reserve (mFRR) follows after aFRR and must be available within 12.5 minutes (for more information see Annex).

To provide frequency control services it is essential that a storage unit can ramp up quickly enough for activation and meets the required duration criteria. BESS can ramp up or down within seconds, so they are particularly suitable for FCR and aFRR. Pumped hydropower storage (PHS) a few minutes for ramping, hence it is suitable for aFRR and mFRR. Other LDES technologies, such as compressed air energy storage and liquid air storage, also have the technical capability to contribute to reserves, mFRR in particular 5 Conventional grid following inverters are sufficient to provide balancing power, grid forming inverters are not needed. Potential balancing market participants need to undergo a process of prequalification to ensure that they fulfil the technical, organisational, and IT requirements for providing reserve power.

5 European Association for Storage of Energy (EASE) (2021). ‘Ancillary Services Energy Storage Applications Forms’. Brüssel. 2021. Available online: https://ease-storage.eu/wp-content/uploads/2021/08/Ancillary-Services.pdf

6 Graebig, M., et al. (2023). ‘Sun, Wind & Wires. Atlas of an Energy System in Transition’. Ellery Studio p. 61.

“With the shutdown of conventional generation we need alternatives that can ensure system stability. Grid-forming BESS are particularly well suited for this purpose, as their storage capability allows them to both supply and absorb power, and as they remain online even when neither the sun is shining, nor the wind is blowing. However, coordinated, rule-based control of grid-forming units is essential to ensure that their collective dynamic response delivers robust system stability across all operational scenarios.

INFORMATION BOX 3.1

GRID CONNECTION REQUIREMENTS OR VOLUNTARY PROCUREMENT OF ANCILLARY SERVICES

In general, there are three alternatives to procure ancillary services: through technical requirements, via market-based mechanisms, or by full integration with the TSO. PROCUREMENT

OF ANCILLARY SERVICES

1

1 Mandatory technical requirements

Conventional generators, renewable energy producers, and demand response facilities must comply with a set of technical standards and rules for obtaining grid connection. These are mandatory technical requirements without remuneration. Across Europe, these rules have been harmonised by network codes drafted by ENTSO-E, with guidance from the Agency for the Cooperation of Energy Regulators (ACER), to facilitate harmonisation and integration of the European internal

electricity market. The “family of network codes” comprises Connection Codes, Operations Codes, Market Codes, and Cybersecurity Codes. They set the framework at the EU level, for the most part as Commission regulations, and are legally binding for all Member States. For example, the Network Code Requirements for Generators (NC RfG) stipulates rules that generators must respect to connect to the grid, while the System Operation Guideline (SOG) lays

down what TSOs shall do in managing their grid.

The provisions stipulated by European network codes are incorporated into national grid codes and connection requirements. For example, in Belgium the national TSO Elia is responsible for drafting and updating the grid code. This process entails stakeholder consultations and eventually the final approval and adoption by the Belgian federal energy regulator.

In Germany, the institution of a technical regulator, the Forum Network Technology and Network Operation in the VDE (VDE FNN), is responsible for elaborating technical connection rules. At VDE FNN, relevant stakeholders are represented in project groups that draft the connection rules or grid codes, which also undergo public consultations. Related to that, VDE FNN has taken over the task on behalf

of the Federal Ministry for Economic Affairs and Energy of implementing European network codes at the national level. At present, the German rules for grid connection, the so-called Technical Connection Rules, are differentiated by voltage levels. So there is one for low voltage, medium voltage, high voltage, extra high voltage, and HVDC grids.

2 Market based provision

In addition to technical minimum requirements that need to be fulfilled by generators, storage operators, and demand response facilities to obtain grid connection, there are also ancillary services that are not mandatory, but where there is voluntary procurement.

Voluntary procurement is typically market-based with the aim of being transparent, non-discriminatory, and efficient. The balancing power market is the best-known example of it. In addition, in Germany an act on the market-based procurement of system services was adopted in 2020 to enable the delivery of additional ancillary services and incentivise competition among market participants in this area. Ancillary services addressed for market-based procurement are in particular black start capability, reactive power supply, and inertia.

Sources:

BMWE (German Federal Ministry of Economic Affairs and Energy) (2025). ‘Netzbetrieb und Systemsicherheit’. Available online at: https://www.bundeswirtschaftsministerium.de/Redaktion/DE/Dossier/NetzeUndNetzausbau/ netzbetrieb-und-systemsicherheit.html

ENTSO-E (2025). ‘What are Network Codes?’. Available online at: https://www.entsoe.eu/network_codes/ 12h EnWG (Energy Industry Act). Available online at: https://www.gesetze-im-internet.de/enwg_2005/__12h.html

German Federal Ministry of Economic Affairs and Energy (2025). ‘Netzbetrieb und Systemsicherheit’. Available online at: https://www.bundeswirtschaftsministerium.de/Redaktion/DE/Dossier/NetzeUndNetzausbau/netzbetrieb-undsystemsicherheit.html

Full integration

Finally, there is network equipment held by grid operators, such as overhead lines, cables, converters, and substations.

As for storage, there is a discussion on placing strategically large-scale battery storage systems in specific locations so that they can be used for congestion management if they are situated as controllable generation or load before a grid bottleneck. Based on certain criteria, there is the question of ownership and operation for such use cases.

DR.-ING. ECKEHARD TRÖSTER, CEO, Energynautics GmbH

NON-FREQUENCY-RELATED ANCILLARY SERVICES

Inertia

Pumped hydropower storage (PHS), compressed air energy storage, and gridforming BESS can provide inertia, while grid-following BESS cannot.

Grid-forming battery energy storage systems (GFM BESS) can detect frequency events within milliseconds and respond to them by adjusting power output instantaneously. This helps to mitigate frequency deviations in the power grid early and to reduce the risk of load shedding or blackouts. Using advanced control algorithms such as virtual synchronous machine control, GFM BESS mimics the

dynamics of a synchronous machine. This emulation creates a form of synthetic or virtual inertia replicating the stabilising effects of mechanical inertia. To sufficiently compensate the provision of inertia from large-scale thermal power plants, GFM BESS are a promising opportunity for providing the necessary inertia to all parts of the grid (see Figure 3.3).

As PHS plants and compressed air energy storage operate with a spinning generator while discharging and with a pump or compressor while charging, they inherently provide inertia in both operational modes.

INFORMATION BOX 3.2

GRID FORMING VS FOLLOWING INVERTERS

Grid-following (GFL)

‘Typical’ grid-following battery energy storage systems (GFL BESS) use a gridfollowing inverter that only injects or absorbs power by following the voltage and the frequency in the grid, inherently assuming the grid is stable. GFL BESS is well suited to contribute to frequency and balancing control services as long as there is a strong grid, meaning a grid with a short-circuit ratio (SCR) which is above a certain threshold.

Grid-forming (GFM)

Grid-forming battery energy storage systems (GFM BESS) have an advanced grid-forming inverter. In some ways, GFM BESS replicate the behaviour of synchronous generators, but can additionally help ‘form’ frequency and grid voltages rather than just ‘following’ them

Grid-following inverter Leader Grid-forming inverter

Voltage control

Grid-forming BESS, PHS, and compressed air energy storage can provide voltage control services.

To maintain the voltage within a certain range in AC grids, reactive power is used. Due to the local effect of injecting or absorbing reactive power, the location of the storage unit plays an important role. Therefore, a balanced geographical distribution of the assets is needed. BESS is more flexible in terms of location compared to PHS and compressed air energy storage, which require specific geological conditions.

With the increased penetration of variable RES and the therefore increased volatility in active power flows, more volatility in reactive power behaviour of the grid can be expected in the future. More sources of voltage control from geographically distributed assets would help managing this volatility.

Black start capability and system restoration

PHS is an important contributor to ensuring black start capability. Transmissionconnected BESS could evolve to take a more active role in grid recovery.

too short to cover an entire grid restoration process.

As more wind power and solar PV units are installed, due to its capability of independently setting frequency and voltage, GFM BESS can enhance system reliability when there is more fluctuating power feed-in and when there are grid failures. Nevertheless, not all inverters should be GFM. Some GFL inverters are needed to avoid conflicts. Research is still ongoing to identify a sound balance between the share of GFM and GFL.

GFMBESS-brief-2025.pdf

PHS can open the upper reservoir’s valves and let water flow through turbines, spinning the generator’s rotor that then generates electric power. Also, compressed air storage could in theory contribute to black start  Small diesel generators can be used to provide auxiliary power for the start of the operation.

Even today, BESS can play a significant role during grid restoration. Their technical characteristics make them ideally suited to operate in fragile grid conditions. During the restoration phase, the grid is highly sensitive to fluctuations, and BESS can help stabilise it either by acting as a controllable load or as a source of generation. Importantly, this passive role does not require grid-forming capabilities. However, the discharge duration of BESS is usually

To play an active role in black start and help restore the grid by restarting thermal plants or energisng renewable-powered sections, BESS must overcome technical, regulatory, and organisational hurdles. However, BESS would need to have a GFM inverter. Moreover, the effectiveness of BESS during a blackout depends heavily on their state of charge and parts of their capacity need to be reserved for the time of the event. Finally, BESS sites are usually uncrewed and cannot be operated remotely during a blackout unless communication infrastructure is made blackout-proof. This limits their immediate integration into restoration strategies.

“Storage systems such as pumped hydropower and batteries provide much-needed flexibility for a fully decarbonised energy system. Pumped hydropower storage, for example, is a fast, highly efficient, powerful and long-lasting system. It can store large amounts of energy and provide it flexibly, and it is also essential for grid stability, such as reactive power. These comprehensive capabilities must also be recognised accordingly in the current discussions about grid tariff structures for large-scale storage systems.

Principle of grid restoration process

FIGURE 3.4

ARIANE LAUTENSCHLÄGER

AVOIDING SYSTEM SECURITY RISKS

While battery storage systems offer significant benefits for grid stability and flexibility, their operation could potentially pose risks to system security. The risks presented in this section relate to frequency and voltage stability, to energy balancing as well as to short-term congestion. The corresponding solutions to mitigate these risks are under development or even implementation.

FREQUENCY AND VOLTAGE STABILITY RISKS & SOLUTIONS

Storage systems can switch from full charging to full discharging within seconds. Such rapid changes could be triggered by market price signals in combination with the obligation to adhere to balancing group schedules. Given a large enough price spread of two consecutive time slots, a storage unit would, for example, switch from fully charging in the low-price time slot to fully discharging in the high-price time slot—both times at full capacity (see Figure 3.5). These abrupt shifts in power flow can destabilise grid frequency and voltage, particularly when large-scale storage capacities are involved.

Power flow changes

The change of power flow will impact voltage in the surrounding network. Many of the voltage control agreements with synchronous generators expect only a gradual response and are not designed to cope with sudden changes. As a consequence, fast reacting devices are needed to provide voltage control. In fact, the storage system itself could be the source of voltage control.

The change of power flow may also impact grid frequency in case significant capacity of storage systems simultaneously change their operating mode. The balancing reserves for the continental European interconnected system are designed to cope with a loss of generation of 3 GW  In the future, a multitude of this capacity could switch operating mode theoretically at the same time. Then the grid frequency would jump or drop extremely.

Simultaneous action

The magnitude of the total storage capacity reacting to market price signals is difficult to quantify and depends on the business strategy of the storage systems, combining day-ahead (DA) and intraday (ID) markets (see Information Box 2.1, for market explanation see Glossary). Storage systems could be triggered by the same market prices, especially those from the auctions of the short-term market. Then they would behave the same way (synchronously) but independently of each other (not coordinated).

Deviations in grid frequency at the beginning of each hour and quarter of an hour are known from the past because in the entire system the power plants and loads are changing their schedules. In the first minute of the new time slot assets are switching to the new set point. So far, these frequency deviations did not harm system stability as the sum of all activities were cancelling each other out, and in addition balancing reserves were capable to handle larger deviations. However, due to the rising capacity

of fast acting storage systems, there is legitimate concern that independent but simultaneous optimisation of storage systems at the intraday market may harm frequency stability.

TSOs like 50Hertz and Elia have started several initiatives to bring forward innovative, sustainable solutions for the challenges mentioned above. A variety of technical and regulatory measures are under implementation or in the planning stage.

Inertia procurement

In Germany, an inertia market will be implemented. Designed to ensure sufficient system inertia, this market mechanism incentivises stakeholders to provide fast frequency response and synthetic inertia independent of traditional synchronous generation. In April 2025 the German regulator BNetzA decided upon the new procurement procedure for inertia in Germany, which will become operational in 2026 and end in 2031 9/10 The market applies technology-neutral pricing allowing a level playing field for BESS, flywheels, and other inverter-based technologies.

New connection requirements

The four German TSOs agreed on new grid connection requirements for storage systems connected at the transmission level 11 They cover, for example, ramp rates, grid-forming characteristics, and reactive power supply for storage systems 12 While not yet part of the European Network Code Requirements for Generators (NC RfG), these additional requirements are expected to be incorporated in the upcoming revision on the European level.

German network codes currently require general ramp rates of minimum 20 and maximum 40% per minute in relation to rated capacity of the asset (Elia in Belgium sets rates of 1 to 2% per second). The new connection rules in Germany now specify ramp rates of active power of 6 to 20% per minute, with the fastest allowed ramp taking 5 minutes to move from zero to full power, applicable to both charging and discharging, with some exceptions for direct grid operator instructions (see Figure 3.6).

9 Netztransparenz.de (2025). ‘Market-based procurement of inertia’. Available online: https://www.netztransparenz.de/en/Ancillary-Services/Frequency-stability/Market-based-procurement-of-inertia-of-local-grid-stability.

10 Bundesnetzagentur (2025). ‘Konzept […] Momentanreserve […]’. Available online: https://www.bundesnetzagentur.de/DE/Beschlusskammern/1_GZ/BK6-GZ/2023/BK6-23-010/BK6-23-010_beschaffungskonzept.pdf?__blob=publicationFile&v=2.

11 The new requirements were published in a position paper in December 2024.

12 Netztransparenz.de (2024). ‘Anforderungen Batteriespeichersysteme’. Available online: https://www.netztransparenz.de/xspproxy/api/staticfiles/ntp-relaunch/dokumente/%C3%BCber%20uns/studien%20und%20positionspapiere/anforderungen%20an%20 batteriespeichersystemen/2024_zus%C3%A4tzliche_technische_anforderungen_an_den_anschluss_von_batteriespeichersystemen_im_hos-netz.pdf.

ENERGY BALANCING RISKS AND SOLUTIONS

There is a conflict between two main priorities of the TSO: stable system operation vs adherence to schedules. On the one hand, grid operators need generators and consumers to follow rather flat ramps between 15-minute setpoints to have time to react with mechanisms in place in case of any imbalance in the grid. On the other hand, balancing group management prioritises strict adherence to stepwise schedules for supply-demand balance. Schedules use 15-minute values,

leading to a stepwise profile over time. Current ramping conditions are an attempt to bridge that gap but are not sufficient for the future, considering the increase in fast reacting storage assets and PV systems which inject their power usually in a continuous curve (see Figure 3.7). High imbalances between supply and demand at the beginning and end of each 15-minute time block must be avoided.

The current balancing reserve mechanism will not be able to handle large discrepancies between schedules and physics in the future. Shortening the imbalance settlement period to 5 minutes to allow for 5-minute trading contracts could help here, but this is currently not possible due to EU regulation, which is unlikely to change in the near future.

Imbalance settlement

Another option is to synchronise the speed at which the assets in the market change their setpoint (injection, withdrawal) from one period to the next. Ideally, this will eliminate deterministic deviations in the system balance. An adapted concept of imbalance settlement (Ausgleichsenergiesystem) to incentivise smooth ramping is already used in Switzerland and Austria and has recently been suggested by the four German TSOs as well. In principle, a distinction between the traded schedule with steps to the physical schedule with ramps is needed (see Figure 3.8). The flatter the physical ramps, the better it is for stable and costefficient grid operations.

SHORT-TERM CONGESTION RISKS AND SOLUTIONS

For storage systems it is attractive to participate in near real-time trading at the intraday continuous (IDC) market. Arbitrage trading and asset-backed trading can be utilised to increase revenues. Therefore, generation and load patterns of storage systems are not predictable, not even close to real-time, and grid operators are not able to forecast power flows in the grid appropriately. This uncertainty can lead to unexpected grid congestion. It can only be addressed through curative congestion management (i.e., in real-time). Many TSOs, however, rely on preventative congestion management.

Storage capacity continues to grow and so does the ID trading volume (see Figure 3.9). Power produced or consumed by flexible assets has often been traded back and forth multiple times beforehand. Market participants report that the intraday positions are changed up to ten times before delivery. The increase of algo-traders facilitate such short term adjustments of trading positions in order to optimise revenue.

The resulting unpredictability in terms of time, location, and magnitude of congestion becomes a serious concern for the grid operators.

At the German IDC market the liquidity increases enormously towards the end of the trading phase (see Figure 3.10). This means storage operators have good chances to find a counterparty on the power exchange for a transaction. The spread of transaction prices compared to the DA prices tends to increase similarly. Weather forecasts become more precise towards real-time and renewable operators may have to adjust generation schedules for their assets compared to earlier forecasts. This may result in ID transaction prices which deviate strongly from the DA price.

In Germany, for example, the major congestion management mechanism takes place at 21:00 the day before delivery (see Figure 3.11). Two to three hours before each delivery time slot the TSOs perform their last calculation to identify potential congestion. For these calculations, dispatch schedules of large assets as well as forecasts for renewable electricity generation and loads are used. All assets with 10 MW capacity or more and all assets which are connected to the 110 kV or to a higher voltage level need to provide such dispatch schedules per asset in addition to the regular balancing group schedules 13

Storage systems could also use assetbacked trading. This means they can take a trading position for a particular delivery period and decide later, depending on price development, to keep or to change this position (see Figure 3.12). It is uncertain whether a strong price change in the intraday market translates into a corresponding change of the schedule of a storage system. The extent of the optimisation of the storage system depends on several variables. These include its state of charge, the evolution of prices in the following hours, and other constraints or incentives from parallel markets (balancing reserves, OTC trading).

Congestion caused by both conventional and renewable generators are relatively predictable several hours in advance. In contrast, it is likely that storage operators will decide to change the direction of power flow at a time when it is invisible to the TSO’s congestion management.

Intraday market prices and volumes, Germany, selected weeks

FIGURE 3.10

“The “store-and-forget” approach is not sufficient for a sustainable energy supply: battery storage systems are truly versatile and should not be used purely for arbitrage on the market. It is essential that these systems are managed and work integrated with grids, production and demand — we need smart flexibility.

Limiting schedule changes

Flexible Connection Agreements (FCAs) can be an instrument for grid operators to facilitate congestion management by outlining an acceptable behaviour of connected market units. FCAs are currently widely discussed around Europe, in fact in several countries they are already implemented.

In Belgium FCAs allowing capacity limitation in real-time to avoid congestion, are already in place.

In Germany the TSOs discuss a different approach. To avoid potential congestion caused by short-term trading activities of BESS, one idea is to limit a close-to-realtime change in schedule in case these changes would create or exacerbate congestion. As such, it could be defined that a certain share of the asset’s installed capacity must no longer change its power schedule a few hours before delivery. Introducing a freeze on a portion of the BESS capacity once the final congestion calculation is initiated would help mitigate this risk of sudden congestion and improve operational predictability.

The results of the last congestion forecast provide guidance for the security assessments of operators in the control room, who may implement additional manual remedial actions based on the congestion forecast. Although monitoring systems notify the operators about congestion in real-time, the mitigation by manual remedial actions may be demanding. The German TSOs are working towards accelerating forecast and congestion processes, which will reduce the risk of short-term congestion. Given the high amount of connection requests from storage systems, an FCA which limits close-to-real-time trading could be used as a standard contract for new-to-connect storage systems.

3.3 STORAGE AND ADEQUACY: FILLING THE ADEQUACY GAP

Adequacy and flexibility are two pillars of a secure and reliable system  14 . As mentioned in Chapter 1, electricity energy storage constitutes a means of providing flexibility. Given the increasing number of connection requests for battery energy storage systems, how can storage help support system adequacy and address the capacity gap?

THE DERATING FACTOR OF STORAGE

Storage can contribute to adequacy, alongside power generators, flexible demand side assets, and interconnectors. The effective contribution of large-scale BESS to adequacy is positive, however, the per-unit contribution is expected to decrease with an increase of flexibility and storage in the system. Adequacy, therefore, is not the main reason for battery development. Long-duration energy storage (LDES) generally performs better at helping the system during scarcity situations per unit of installed power, compared to short-duration storage.

A technology’s contribution to adequacy is determined by its derating factor, which is used to measure the contribution of a technology during scarcity events. Storage is an energy-limited technology. Just like flexible demand side resources, storage experiences the highest variations in terms of derating factors. Different factors determine the variations in contribution to security of supply of storage which is reflected in the changing derating factor: 1) the amount of energy that can be

stored per unit of power, 2) the roundtrip efficiency, 3) the security of supply criteria of the country, and 4) the share of flexibility resources in the system.

First, a storage asset is able to discharge only when it has sufficient energy available. As an energy-limited technology, storage has a nominal capacity that can be sustained only for a limited time (e.g., four hours for large-scale BESS 15). The derating factor increases as the amount of energy that can be stored per unit of power raises.

Figure 3.13 shows estimated derating factors of certain technologies and assets including real examples from European capacity remuneration mechanism calculations as well as potential contributions of new LDES technologies in the future 16 In terms of adequacy, for a given installed power, LDES generally performs better than shortduration storage and can deliver a derating factor rivalling that of thermal power plants. As will be explained later, derating factors depend on the mix of installed generation technologies and the demand and generation profiles. As such the snapshot

presented in Figure 3.13 will change if the energy system changes.

The derating factors of storage technologies

FIGURE 3.13

“Wind energy and storage systems are natural partners. With batteries and thermal storages, wind parks live up to their full potential by supplying clean electricity even in times of low wind events, heating entire villages, and providing grid-stabilising ancillary services. If we want an energy system that is both decarbonised and secure, this is the way to go.

WOLFRAM AXTHELM, Managing Director, BWE German Wind Energy Association

Second, the round-trip efficiency of the asset is another key parameter. It is defined as the ratio of the energy output during discharge to the energy input during charging. It measures how effectively a storage technology stores and returns energy. This value can vary significantly between a battery (85 to 90%) and a pumped hydropower storage (60 to 80%). In a system with a lot of flexibility, it will be more optimal to first charge the technologies with the highest round-trip efficiency. When two scarcity periods are separated by only a few hours, a merit order of energy-limited technologies will apply. The technology with the highest efficiency is expected to charge first, making it the most likely to be available during the second scarcity period.

Third, the contribution to security of supply of storage technology depends on the metric used to express the reliability standard. Following EU regulation, the loss of load expectation (LOLE) is the main indicator for adequacy assessment. For example, in Belgium the LOLE is limited to no more than 3 hours per year. In Germany, the reliability standard is expressed in LOLE less than 2.77 hours. Since storage technologies are inherently energy-limited, their ability to contribute for adequacy diminishes as the reliability standard increases. In countries with higher LOLE thresholds, longer scarcity periods are tolerated, reducing the relative contribution of storage to adequacy which is reflected in a lower derating factor.

Finally, the contribution to security of supply from energy-limited technologies decreases with higher shares of flexibility resources in the system. The greater the number of energy-limited technologies in the system, the smaller the contribution of additional storage to adequacy becomes.

This is also illustrated by the results of the Elia’s most recent Adequacy and Flexibility study 17 Figure 3.14 depicts the required capacity of 4-hour large-scale batteries needed to fully close the adequacy gap identified in the EU-SAFE Current

Commitments scenario from 2028 to 2034.

It illustrates how increasing flexibility and integrating more large-scale storage into the system, will impact the contribution of energy-limited technologies to adequacy. In 2028, 400 MW of additional battery capacity will be needed to fully close the adequacy gap of 200 MW, corresponding to a derating factor of 50% 18 By 2034, if the entire gap were to be filled by batteries, an additional capacity of 8,300 MW would be needed. However, this could result in an effective contribution of only 2,200 MW, implying a derating factor of around 25% .

Additional nominal capacity of 4-hour batteries that would be required to fill the entire gap of the EU-SAFE-CC scenario

17 Elia Transmission Belgium (2025). ‘Adequacy and flexibility study for Belgium’. 2026-2036. June 2025. p. 247ff.

18 The derating factor is calculated as: the ratio between the nominal battery capacity and the adequacy need.

The deployment of demand-side response and the implementation of storage to support adequacy should not be viewed in isolation. Instead, they need to be considered as complementary elements to determine which amount of storage is favourable from an adequacy viewpoint. A balanced mix of battery storage and power plants reduces the need for additional firm capacity, as these units can operate both before and after real scarcity events. Battery storage can facilitate energy transfer, increase full load hours, and provide an optimal contribution towards closing the capacity gap.

INFORMATION BOX 3.3

ACTIVITY OF LONG VS SHORT DURATION STORAGE

FIGURE 3.14

Source: Elia Transmission Belgium (2024). ‘Belgian Electricity System Blueprint for 2035-2050’. Available online: https://issuu.com/eliagroup/docs/20240924_belgianelectricitysystemblueprint2035-205.

Elia’s 2025 Electricity System Blueprint study, showed that LDES is used more actively than short duration storage throughout the year, contributing to storing excess renewable energy and offsetting production from expensive gas-fired power plants.

Additionally, the study shows that storage systems with a higher efficiency are more actively used than their lower efficiency counterparts. Given their higher efficiency and resultant lower losses, they can take advantage of smaller price variations and are therefore used more often.

“Battery storage systems enjoy a strong boom in Europe. But besides short-term storage, long-term storage technologies are essential to store the significant surplus of renewable energy generated by, e.g., photovoltaics in the summer in a meaningful way. Adiabatic or diabatic compressed air storage technologies based on green hydrogen can be operated as mediumand long-term storage facilities, thus serving the critical dark windless period when even the last battery storage facility is discharged. The new generation of compressed air energy storage systems can be operated in a CO2-neutral manner and can provide energy over several days.

LONG-DURATION ENERGY STORAGE

(The content of this section was provided by Dr.-Ing. Felix Panitz and Dr.-Ing. Judith Stute, Fraunhofer IEG)

LDES provide the flexibility we need to get to net zero. Each LDES technology serves distinct roles in the energy system, from daily balancing to seasonal backup. In addition, as LDES links electricity with heating, cooling and fuel supply, it becomes a cornerstone for a reliable and cost-efficient decarbonised energy system.

Definition: LDES typically refers to various energy storage technologies that are able to discharge at rated power for at least 8 to 10 hours. LDES which have nominal discharge durations above 100 to 200 hours are often referred to as seasonal or ultralong-duration energy storage. These are particularly important for managing periods of excess generation and extended periods of low renewable output (known as dark doldrums or Dunkelflaute).

Types of LDES: For short-duration energy storage, the focus lies typically on power-topower applications. In contrast, LDES offers more diverse discharge outputs (see Figure 3.15). This versatility makes LDES essential for effective sector coupling. Depending on the discharge outputs, LDES systems connected to the electric sector can be grouped into three categories:

Power-to-power LDES: Electricity in, electricity out. These systems enable direct balancing of the electricity grid, providing grid services in both directions of power flow, while storing energy in electrochemical, thermal, chemical or mechanical form.

Power-to-heat or power-to-cold LDES: Electricity in, heat or cold out. These systems reduce dependence on fossil fuels in heating and cooling, for example in district heating networks or industry.

Power-to-molecules or power-to-X LDES: Electricity in, molecules out. In these systems, electricity is converted into chemicals or fuels that can be stored and later used directly. If reconverted into electricity, they are classified as power-topower LDES.

Electrochemical LDES technologies generally show high round-trip efficiency. Round-trip efficiency depicts the ratio of energy retrieved from a storage system to the energy originally put into it. Flow batteries are particularly promising, as power and capacity can be scaled independently. Metal anode and metal-air

INFORMATION BOX 3.4

batteries have potential at longer storage durations but so far show low technology readiness. Mechanical storage typically provides discharge durations of one day or more, with many of them being dependent on geographical factors. Thermal storage can reach higher discharge durations but has lower efficiency and technological

maturity, specifically for reconversion to electricity. Chemical storage technologies, despite low efficiencies, are uniquely suited for seasonal storage of very large energy volumes in power-to-power applications. Please see Chapter 0 for more details on LDES technologies.

(End of provided content)

PUMPED HYDROPOWER STORAGE IN EUROPE

Pumped hydropower storage (PHS) plays a special role. It can provide short-term and long-term flexibility, depending on design of the plant. It charges by pumping water to a higher reservoir and discharges by letting water drive turbines and generators while running down towards a lower reservoir. PHS can also provide multiple ancillary services such as inertia, voltage control, or frequency control.

PHS is well established in power systems for a long time — and nowadays it is on the rise again (see Figure). Due to growing curtailment of renewables, the increasing need for flexibility and storage, as well as national security considerations, PHS has a clear use case. Despite the long-term uncertainties in revenue forecasting, there is a growing pipeline of PHS projects in Europe. In 2025, the capacity under development was nearly three times as much as in 2023, according to a report from the International Hydropower Association

One driver could be the EU market design reform in 2024. Member States have to assess flexibility needs over five to ten years, and they are allowed to introduce support schemes promoting the deployment of low-carbon flexibility assets in case market conditions will not create sufficient incentives to stipulate such investments. Nevertheless, it is not so easy to find suitable geological conditions for PHS which would minimise construction costs and maximise efficiency during operation.

“Shifting a season will be key to harness sun energy and achieve the energy transition. There are various forms for long-term storage: from e-fuels to heat. Yet, the unfair and incomplete comparison with the cost of fossil gas is a challenge for markets and policymakers.

PROF. DR.-ING. INES HAUER, Chair of Electrical Energy Storage Technology, Technical University of Clausthal

PROF. FRANCESCO CONTINO, Professor, Université Catholique de Louvain

Case study: LDES can remove part of the thermal generation

LDES could replace parts of thermal generation needed for adequacy. Simulations show that this can be part of the solution to keep the lights on in the future.

Considering how much LDES contributes to adequacy, one might think that it would be easy to replace dispatchable thermal power generation with LDES. As noted before, however, derating factors depend on the mix of installed generation technologies and the demand and generation profiles. Notable for storage systems a cannibalisation effect occurs where adding more storage of a similar duration has diminishing returns in terms of contribution to adequacy. To illustrate this, a case study for Europe provides an initial assessment how realistic this is.

To replace the dispatchable thermal generation in Europe needed for periods where low carbon generation cannot cover the demand – so-called Dunkelflaute –several things are needed:

Long-duration flexibility is required to overcome long periods where no renewable production is available.

Short-duration flexibility is needed to shift renewable energy within the day to match daily consumption profiles.

The total energy production of the thermal generation must be replaced by new renewable generation.

To illustrate this, let’s take a closer look at potential dispatch results for Europe in 2050. For this exercise it is assumed that in Europe in 2050 there will be an installed capacity of 1,600 GW solar PV, 940 GW wind, and 75 GW nuclear 19

In addition, it is assumed that sufficient short duration storage is installed to reshape energy profiles within the day and that the European grid is reinforced sufficiently to act as a copper plate, so the problem that remains is how to move energy between days.

Figure 3.16 shows the total average daily generation and load of Europe in a randomly selected climate year. This figure shows a one-month period in 2050 where renewable production is not able to fulfil all demand. There are two large subsequent gaps of energy without enough time to recharge in between totalling 113 TWh. This is roughly equivalent to the battery capacity of billion electric vehicles (approximately four times more than the total number of passenger cars in Europe in 2025, all technologies combined).

Figure 3.17 considers another scenario in which the installed capacity of PV and wind were to increase to 2,700 GW and 1,200 GW respectively. Note that this is just one possible climate year, so the actual impact could vary, but the energy shortage would be significantly less. Here the missing energy is smaller, yet still significant at 31 TWh. In terms of power, however, the maximum average daily power that must be supplied to cover this missing energy, is still quite significant. This illustrates the fact that there is likely an optimal balance between renewable energy sources (RES), LDES and thermal generation, and demonstrates the sort of trade-offs that must be considered when making decisions about these technologies.

INFORMATION BOX 3.5

EVALUATION OF LDES

Economic aspects of LDES

Economic viability is central to the deployment of LDES. Their value derives from both direct revenues and broader system benefits, but current market design often fail to capture its potential. Revenue opportunities differ between power-to-power and sector-coupled LDES.

Power-to-power LDES can generate income from arbitrage, directly using price spreads in the electricity market to generate revenues. They can also provide grid services in both charging and discharging modes, while offering additional value as backup for critical electricity demand or by time-shifting renewable generation.

Sector-coupled LDES gain only limited revenues directly in the electricity markets, for example by charging during periods of low or negative electricity prices, thereby reducing renewable curtailment. Their main economic value comes from the provision of a product at discharge (i.e., heat, cold, chemicals, or fuels) which can be sold in other markets at times with high prices.

Revenues for both power-to-power and sector-coupled LDES systems are strongly influenced by CO2 prices, which shape both electricity market spreads and the cost of alternative supply in other sectors.

On the way to a decarbonised energy system, new system services and markets play a key role for the economic operation of LDES. In this context, flexibility and congestion services can be effectively provided by LDES. Grid bottlenecks often persist for several hours or longer. By absorbing excess renewable energy and releasing it later, LDES can lower redispatch needs and mitigate curtailment. A key challenge lies in aligning market incentives. If only short-term market participation is rewarded, there is a risk that LDES systems may prioritise higharbitrage short-term markets instead of delivering long-duration storage system benefits. Scientific analysis of costoptimal future decarbonised systems shows that Li-ion batteries are best used as “fast burst balancing resources” for short fluctuations, while LDES has the potential to directly substitute firm generation capacity 1

Barriers to LDES adoption

Despite their system value, LDES technologies face technical, economic, and regulatory barriers to their deployment. Technical barriers include the limited maturity of several storage technologies, low efficiency for some storage concepts, and restricted cycling capability. In addition, scaling up to the very large systems expected in the future brings new implementation and operational challenges.

Economic barriers relate mainly to high upfront capital costs and long project lead times, which create uncertainty for investors. Spot-market price spreads between months and seasons are not easily predicted and possibly too low for a valid business case. While larger thermal storages are often more costeffective, their scale requires substantial single investments, which contrasts with investors’ preference for risk diversification. This leads to hesitation in committing to large, efficient projects.

Regulatory and market design barriers are among the most pressing. The tariff framework for energy storage is highly

fragmented across the EU. Storage operators frequently face the same grid charges as other consumers (and in some cases also producers). Temporary exemptions offer limited long-term planning security. In most countries, there are no incentives for locating storage in grid-beneficial areas such as regions with frequent grid bottlenecks, high renewable generation, or available grid connection capacities, which reduces overall system efficiency. Current market design also does not adequately value long-duration flexibility, limiting the business case for LDES.

Market design must value long-duration flexibility. New instruments are required to reward LDES beyond today’s energy-only and short-term service markets. Timely action is critical. With long project lead times, Europe must act now to secure the LDES capacity needed by 2030 and scale to 2050 needs.

“Chemical, electrical and kinetic storages are all essential components for a resilient energy supply. We need to improve regulatory incentive structures so that remunerations for storage services adequately reflect their system value — where the value is indeed positive. For this, we also need a debate on how storage contributes exactly to resilience.

INFORMATION BOX 3.6

STORAGE FOR A RESILIENT INFRASTRUCTURE

Reconstruction of Horenka Hospital in Ukraine

In the wake of the war in Ukraine, Greenpeace Central and Eastern Europe, in collaboration with Ukrainian environmental organisations and local authorities, have spearheaded a green reconstruction project at Horenka Hospital near Kyiv. This initiative not only restored a healthcare facility but also showcased the potential of sustainable energy solutions—particularly heat pumps and solar power systems, combined with storage solutions—in rebuilding resilient infrastructure.

The hospital was severely damaged during the early days of the war and faced prolonged power outages and heating failures. To address these challenges, Greenpeace and its partners installed a modern heat pump system coupled with a

hybrid solar power plant. This combination was chosen for its energy efficiency, environmental benefits, and ability to operate independently of an unstable grid.

The heat pump draws thermal energy from the ground using vertical probes sunk 65 meters deep. This system ensures consistent heating even in harsh winter conditions and significantly reduces reliance on fossil fuels. To support the heat pump during power outages, a solar power system was installed on the hospital’s roof, along with a battery storage system. Currently, it covers 40 to 60% of the hospital’s electricity needs, with the potential to expand to full energy independence.

Greenpeace advocates for replicating this approach across Ukraine, urging European cities to partner in sustainable recovery initiatives.

DR. EVA SCHMID, Director Hydrogen & Resilience, German Energy Agency (dena)

© EngieBelgium

EUROPEAN EXPANSION MODEL

In Chapters 1 and 2, European market analyses for 2050 have been shown that were performed by an expansion market model. This model is based on the Identification of System Needs (IoSN) zonal model from the TYNDP 2024, covering 27 EU countries, Norway, Switzerland, UK and five non-EU Balkan countries (Albania, Bosnia, Montenegro, North Macedonia, and Serbia). The European system has been aggregated into 109 zones, where Germany is represented by eleven and Belgium by three zones (see Figure A.1).

ASSUMPTIONS AND DATA

The input data is mainly coming from the 2050 National Trends (NT) scenario in the TYNDP 2024 In line with recent developments, adaptations have been made for solar PV, offshore wind, and electrolyser capacities. A more conservative approach has been applied for offshore wind and electrolysers, whereas higher capacities have been assumed for solar PV to better capture its accelerated development trend.

Furthermore, detailed modelling for decentralised flexibilities from electric vehicles, heat pumps and demandside response have been incorporated to co-optimise their dispatch in system optimisation. For electric vehicles, the modelling approach from the TYNDP 2024 Scenarios Report2a has been adopted. Electric vehicles are modelled as batteries with assigned availability profiles to limit their flexibility to the system. Figure A.2 shows the availability profiles used for prosumer EVs, representing home charging, and the street EVs, representing public charging.

The model is used for analyses in the report identifying the drivers for battery deployment and the impact of batteries in a low-carbon European energy system in 2050. The results of the expansion model are shown in Figures 1.1, 1.2, 1.3, 1.4 and 1.5 in Chapter and Figures 2.1, 2.2, 2.7, 2.8 in Chapter 2.

TYNDP zonal model structure for Germany and Belgium FIGURE A.1

Table A.1 shows model characteristics, the implemented expansion candidates and the assumed capacities for

and electrolysers. The simulations were run in a 2-hourly resolution for historical climate year 2009. A simplified net transfer capacity approach was adopted for the transmission capacity between zones.

SCENARIO DEVELOPMENT

The

OPTIMISATION

The model minimises total system costs by co-optimising (1) investment decisions in extra-high voltage electricity infrastructure within and across different market areas and the deployment of utility-scale batteries, and (2) the operation of the energy system, meaning the usage of the transmission

and dispatch of generators and flexible loads, including fuel costs, operational and maintenance costs.

CASE STUDY ON REDISPATCH IMPACT OF BESS IN THREE GERMAN REGIONS WITH FfE’s ‘eFLAME’

In order to determine the dispatch of a hypothetical, front-of-the-meter, market-optimised battery in 2024, FfE’s modelling environment ‘eFlame’ 3 was used with inputs as depicted in Table A.2. It was assumed that the battery would have no effect on the market prices, but would receive or pay the historical cleared market price for the specific 15-minute interval that the battery bid in. The results of this case study are shown in Figures 2.5, 2.12, 2.13, 2.14, and 2.15 in Chapter 2.

INPUTS AND APPROACH

First, a baseline for each region is established. Assuming the battery operates on the day-ahead market and participates in intraday auction (IDA1), it optimises its dispatch with perfect foresight for a rolling horizon of 48 hours daily. The optimal dispatch determined by ‘eFlame’ is then compared to the three regional congestion profiles (without the battery) at TSO level in Germany, to determine whether the battery’s operation would have increased, decreased or had no effect on redispatch. No grid model was used for this analysis, so the redispatch-increasing effects might be understated, because the additional battery might use more than the remaining available margin.

While the market-driven dispatch of the battery is identical for all of Germany, its impact on redispatch depends on the regional congestion profile. Hence, the results differ for the analysed regions, although there total redispatch volumes in 2024 at the TSO level were similar. The two analysed generation-dominated regions have more injection restrictions, while the load-dominated region has mostly withdrawal restrictions due to the direction of the redispatch needed. An analysis of the redispatch impacts seems to suggest that the longer the duration of the congestion, the more the battery would have wanted to operate during those times if it were unconstrained (see Figure A.5). Moreover, the more hours there are with restriction in a region, the more hours with congestion there are when market opportunities are very attractive (very high or very low prices) and thus the higher the possibility that the battery may operate in a way that exacerbates this congestion (see Figure A.6).

FLEXIBLE CONNECTION AGREEMENT

WITH CAPACITY LIMITATION

For this use case, three scenarios were considered. A grid-neutral scenario which fully limits the injection or offtake capacity of the battery to zero so not aggravate the congestion. Moreover, a grid-neutral light scenario which limits the injection or offtake capacity of the battery to 25 % of its maximum power. Additionally, a gridpositive light scenario was analysed, which extends the grid-neutral light scenario by a mandatory minimum (charging/

discharging) power of 50 % of the battery’s maximum power in the opposite direction to the redispatch in the event of high redispatch demand for a maximum of 1.5 hours per day (no compensation is considered). The constraints introduced by the FCA are considered in the optimisation with ‘eFlame’ allowing the battery to adapt their trading accordingly compared to the baseline where constraints are not known,

impact of different types of capacity limitations in three German regions

thereby assuming that the information was available before market closure.

The results for all scenarios compared to grid-unaware BESS operation (without measure) are shown in Figure A.7 (an extension of Figure 2.13). The higher redispatch savings in the grid-positive light FCA design are due to the required RD-alleviating operation of the BESS in hours of high redispatch demand. Although this also has substantial effects on the BESS

revenue change, the resulting economic added value is in the same range as in the grid neutral scenario.

All scenarios were modelled for only spot market optimisation as well as spot markets and FCR. If limitations are announced well in advance, then FCR participation with 4-hour bidding blocks is heavily limited. These economic impacts show the effects based on 2024 data and should not be mistaken for forecasts.

Battery dispatch optimised with FfE’s ‘eFlame’ model based on German DA and ID auction prices compared to regional redispatch needs in 2024

impact compared to ‘grid-unaware storage operation’ in €/ kWinst p.a.

DYNAMIC GRID TARIFFS

For this use case, three scenarios were considered which are explained in Table A.3. If the batteries operation exacerbates grid congestion, the battery operator is charged a grid fee of 10 ct/kWh. When there are also negative grid fees, the battery operator receives 10 ct/kWh if the BESS operation alleviates redispatch needs. If the battery has no impact on congestion, no fee is paid or received.

The results for the offshore wind-dominated region are shown in Chapter 2 (see Figure 2.15). Figure A.8 shows the results for the generation-dominated, transit region and the load-dominated region compared to grid-unaware BESS operation (without a

grid tariff). A grid tariff that only incentivises charging such as the offtakeonly dynamic grid tariff (1) has limited impact on reducing redispatch in regions with high positive redispatch volumes, such as the load-dominated region. A grid tariff that only penalises redispatchincreasing operation (design (2)) achieves the lowest added value, but it is the only scenario that keeps the benefits for all grid fee payers rather than the battery operator. Grid fees paid by the BESS benefit all grid

users. Meanwhile, grid fees paid to BESS are costing all grid fee payers if they are not offset by redispatch cost savings.

Economic

FIGURE A.7

Economic impact of different types of dynamic grid tariffs in two German regions

FIGURE A.8

STORAGE AND CONGESTION IN THE GERMAN DISTRIBUTION GRID

The study by University of Bayreuth and Forschungsinstitut für Informationsmanagement investigates congestion in the distribution grid between January 2024 and June 2025. It only considers congestion within distribution grids (not the transmission grid). The results are presented in Information Box 2.2 in Chapter 2.

OPTIMAL STORAGE DISPATCH TO MINIMISE GRID EXPANSION COSTS

Reiner-Lemoine-Institut (RLI) and Netzwende (NW) analysed the optimal storage dispatch to minimise grid expansion costs in the eHV/HV and the MV/LV grid. For the eHV/HV grid, grid expansion costs are directly considered. For the MV/LV grid, load and generation shedding needed to avoid equipment overloads are used as a proxy and grid expansion needs are identified iteratively afterwards. The modelling was done using the open-source models eTraGo & eDisGo together with eGo as an interface for clustering and disaggregation. It follows a topdown approach from the eHV/HV to MV/LV level. The results are depicted in Information Box 2.3 in Chapter 2.

DATA AND APPROACH

For the study the following data was collected from different registries and institutions. DSOs publish the distribution grid redispatch data. In the study, redispatch in the grids of Schleswig-Holstein Netz, Avacon, and Bayernwerk was analysed. This data excludes redispatch measures caused by congestion within the transmission grid. The distribution grids were selected because of satisfying availability of redispatch data. Asset data was derived

from Marktstammdatenregister (MaStR) and weather data from Deutscher Wetterdienst (DWD). For the optimization of the dispatch of the large-scale storage system, day-ahead prices from ENTSO-E Transparency platform were used.

The grid of Schleswig-Holstein (SH) Netz is located in Northern Germany, it is predominantly rural with extensive wind resources. The grid of Avacon is in Central and Northern Germany covering mixed rural and urban areas. The grid of Bayernwerk is in Southern Germany. It is one of Germany’s largest distribution networks with a high penetration of solar PV covering mostly rural and suburban areas in the state of Bavaria.

For a proportion of plants affected by redispatch the authors of the study were able to allocate data from the MaStR to identify and cluster the type or size of the plant. These proportions varied among the DSOs and are 82% for SH Netz, 33% for Avacon, and 80% for Bayernwerk.

USE CASES

The home batteries use case is considering a typical PV home storage system installed in a single-family home. It is assumed that the objective is to maximise selfconsumption. The battery does not follow a smart charging approach, but it will charge as soon as PV generation exceeds load. Relevant parameters are a 5 kWh battery energy capacity with 8 kW rated power. The household’s demand profile is based on dynamised standard-load-profile data for a 5000 kWh household, provided by the association BDEW (German Association for

Electricity and Water Industry). The installed capacity of the PV system is 8kWp, while the generation profile is derived from the historical DWD weather data, which differs locationally. Thus, three representative locations in each of the three distribution grids were selected.

The (front-of-the-meter) large-scale storage use case has the objective to maximise profit on the day-ahead market. The battery has an energy capacity of 2 MWh and a power rating of 2 MW. A maximum of 10.5 charging cycles per week is assumed.

Historical day-ahead prices from the year 2024 for Germany are considered for the optimisation. As the day-ahead prices are the same in the German/Luxembourg market area, the optimised dispatch pattern of the battery is identical for all three locations.

The time series of the modelled battery dispatch and the curtailed power in the three regions were compared. Whenever the curtailed power was larger than zero, charging of the battery was marked as ‘beneficial’ (leading to a reduction of the

congestion), while discharging was marked as ‘unfavourable’ (leading to reinforcement of congestion). The number of 15-minute timeslots was accumulated for both ‘beneficial’ and ‘unfavourable’ for the given timeframe. The results and key findings are presented in Information Box 2.2 in Chapter 2.

The scenario ‘eGon2035’4 uses inputs from the German grid development plan NEP2021 (Scenario C2035)5 and various open-source datasets to determine electricity generation and demand in Germany. TSO and DSO power grids as well as several flexibility options are included in the model. Inputs to the models are, for example, demand (total capacity and hourly dispatch) as well as the capacity of all types of generation and flexibility options. The hourly dispatch of generation and flexible assets is a result of the optimisation.

eTraGo6 was used for techno-economic optimisation of the energy system in Germany and its neighbouring countries, identifying grid and storage expansion needs in the eHV/HV level, and optimising the flexibility deployment in the eHV/HV grid. It features a linear optimal power flow using PyPSA7 with 3000 AC nodes over one year for every fifth hour.

eDisGo8 was used to determine the need for grid expansion in the MV/LV grid and evaluate the potential of the optimal dispatch of batteries, demand side management, electric vehicles, and heat storage to reduce the need for grid expansion. The dispatch and curtailment of generators, as well as the dispatch and expansion of flexibility options resulting from eHV/HV grid are considered in the optimisation of the MV/LV grids. This optimisation features a non-linear load flow analysis using PyPSA, AC optimal power flow (OPF) to optimise flexibility dispatch and an automised grid expansion. 50 representative MV/LV grids were selected and modelled individually with a temporal resolution of every hour for two representative weeks (one summer, one winter).

4 C. Büttner, J. Amme, J. Endres, A. Malla, B. Schachler, and Cußmann (2022). ‘Open modeling of electricity and heat demand curves for all residential buildings in Germany’. Energy Informatics (5(1)).

5 BNetzA (2021). ‘Netzentwicklungsplan Strom 2035, Version 2021, 1. Entwurf, 2021’.

6 electricity Transmission Grid optimization. Available online: https://github.com/openego/eTraGo License: AGPLv3.

7 T. Brown, J. Hörsch, and D. Schlachtberger (2018). ‘PyPSA: Python for Power System Analysis’. Journal of Open Research Software (6(4)).

8 electricity Distribution Grid optimization. Available online: https://github.com/openego/eDisGo License: AGPLv3.

BEHIND-THE-METER OPTIMISATION

In Chapter 2, the theoretical use case of a synthetic Belgian industrial grid user with a 12 MW battery in three different set-ups and without a battery was modelled. The simplified model optimises charging and discharging schedules of a battery to minimise the total annual energy bill subject to technical and set-up constraints. These total costs consist of energy costs from buying electricity at day-ahead or intraday auction prices, and grid tariff costs including peak charges.

and compared:

DATA AND APPROACH

following parameter- and model assumptions are made:

Elia (n.d.). ‘Invoicing and tariffs’. Available online: https://www.elia.be/en/customers/invoicing-and-tariffs (last accessed on 07/11/2025). 10 Elia (2025) ‘Adequacy and Flexibility Study for Belgium’. Available online: https://www.elia.be/en/electricity-market-and-system/adequacy/adequacy-studies (last accessed on 28/10/2025).

OPTIMISATION PROBLEM

The formulation of the optimisation problem in this model consists of the objective function that minimises total costs of the following four different cost components: The energy cost is the net cost of electricity consumed from the grid minus revenue earned from selling electricity to the grid. To minimise the energy cost, the model adjusts the battery dispatch to charging when prices are low and to discharging when prices are high. The energy-based grid tariff cost is calculated by multiplying

the consumption from the grid with the withdrawal tariff and injection into the grid with the injection tariff. The monthly peak tariff cost is a grid tariff charge that is based on the highest hourly power consumption each month. The model aims to lower these monthly peaks by using the battery in set-ups (2) and (4). The yearly peak tariff cost is an additional grid tariff charge for using the grid in pre-defined annual peak periods. For Flanders, this charge is based on the maximum demand during

November to March, between 17:00 and 20:00 (excluding weekends and holidays).

The model schedules battery discharges during these times to reduce consumption from the grid and thereby lowers annual peak charges.

There are some technical constraints of the battery to be fulfilled related to its safe state of charge limits, its maximum power limit, and its monthly energy cycling limit. Additionally, a capacity constraint applies to the BTM set-up (3).

The model output consists of the charging and discharging schedule of the battery (dispatch optimisation). The monthly peak loads of all scenario set-ups are shown in Figure A.10. The analysis furthermore includes a breakdown of costs for each month of the year. The grid tariff costs are minimised only in the BTM set-up, while a FTM battery without exemption from grid tariffs leads to additional charges and scenarios (1) and (3) have the same grid tariff costs as only the industry is affected.

PROSUMER HOUSEHOLD STRATEGIES TO DEAL WITH SOLAR EXCESS

Information Box 2.4 depicts a simplified analysis of the economic viability of installing a battery in a prosumer household with solar PV. The analysis was done comparing different set-ups, operational strategies, and contracts, both in terms of energy supply and in terms of grid fees, of the prosumer.

DATA

The baseload consumer profile, used for this case study, was selected out of the available, anonymised consumption profiles, as provided by the Flemish Distribution System Operator Fluvius11 Profile 17 was used as its estimated total

consumption, that is its estimated solar self-consumption in addition to the given grid consumption, is close to the average electricity consumption of a Belgian household of 3,500 kWh per year). Table A.6 depicts the split of the consumption profile.

The consumption of the flexible asset is added on top of this base consumer profile, depending on the charging strategy or profile. Moreover, based on the injection profile related to profile 17, solar PV of 4.8 kW p is assumed to be installed at the residence. Scenarios with and without local solar production were simulated.

Additionally, a 2-hour 2 kW battery is considered for some prosumer use cases that combine household consumption, solar PV and the battery. The operational constraints of the battery are set by its power, state of charge (see Figure A.11 for an exemplified evolution of the SOC), cycle limits, and round-trip efficiency. All parameters are depicted in Table A.7.

11 Fluvius (2025), ’Verbruiksprofielen digitale elektriciteitsmeters: kwartierwaarden voor een volledig jaar.’, Available online: https://opendata.fluvius.be/explore/dataset/1_50-verbruiksprofielen-dm-elek-kwartierwaarden-voor-een-volledig-jaar/information/ (last accessed on 30/09/2025).

12 Elia (2025) ‘Adequacy and Flexibility Study for Belgium’. Available online: https://www.elia.be/en/electricity-market-and-system/adequacy/adequacy-studies (last accessed on 28/10/2025).

Exemplified evolution of battery’s state of charge evolution over the course of one day

USE CASES

Profiles

Natural load: Load profile as is.

Curtailed injection: When prices are negative, the PV production is modulated such that no injection takes place at negative prices.

Natural battery charging: The battery charges when excess PV production is available. When it’s not and the consumer requires more electricity, the battery is discharged first, before resorting to the use of electricity for the grid.

Optimised battery charging is also simulated, minimising the total cost of electricity consumption for the household, all the while remaining within the battery’s operation limit. Here,

electricity from the battery can also be sold back to the grid.

Contracts and prices

Three different price structures are considered:

A single level, flat rate contract

A classic, flat time of use contract, meaningie. with a day/night structure

A dynamic contract, based on day-ahead market prices

When a single level, flat rate contract is considered, the commodity price level is calculated based on a weighted average of the Power Base Load futures (Endex 101), and is adjusted every quarter (three months), following the formula below:

For the calculation in 2023 the average commodity price was estimated at 16.594 c€/kWh. On top of this 2.241 c€/kWh are added for purchasing guarantees of origin. Grid fees, taxes and levies are added to this price to arrive at the full electricity price. Fixed, yearly administrative costs amount to €55.30.

The considered day/night contract has a similar formula to calculate both the high and low price level:

For the calculation in 2023 the average commodity price was estimated at 14.676 c€/kWh for the low price level and 18.577 c€/kWh for the high price level.

On top of this 2.241 c€/kWh are added for purchasing guarantees of origin. Grid fees, taxes and levies are added to this price to arrive at the full electricity price. Fixed, yearly administrative costs amount to €55.30.

The dynamic contract is based on the day-ahead (Epex Spot) market prices, the hourly price is calculated as follows:

FURTHER EXPLANATION ON ANCILLARY SERVICES

BALANCING

POWER

There are three kinds of balancing power, each contributing over different time scales in terms of activation and duration: frequency containment reserve, automatic frequency restoration reserve and manual frequency restoration reserve13

Frequency containment reserve (FCR) is the fastest control service to stabilise frequency in case of a sharp dip or rise and must be fully available within 30 seconds. Its activation is frequency dependent. That means that the providers of FCR independently measure the grid

frequency at the location of generation or consumption and immediately respond to any grid frequency changes.

Automatic frequency restoration reserve (aFRR) is activated afterwards to replace the FCR and to further restore frequency to the set point of 50 Hz. It must be available within five minutes.

On top of this 2.241 c€/kWh are added for purchasing guarantees of origin. Grid fees, taxes and levies are added to this price to arrive at the full electricity price. Fixed, yearly administrative costs amount to €100.70.

Manual frequency restoration reserve (mFRR) follows after aFRR and must be available within 15 minutes. Whereas aFRR is activated continuously, mFRR is used rarely and usually just for a few 15-minuteperiods. Despite its name, nowadays mFRR is not called upon ‘manually’, instead there are merit order list servers.

Providers of FCR are required to offer it symmetrically, meaning they must deliver both positive and negative FCR. By contrast, aFRR and mFRR are divided into two distinct sub-products – positive and negative each of which can be provided independently.

Twelve European TSOs have entered a voluntary European partnership called FCR Cooperation for the joint procurement

and exchange of FCR, thereby creating the largest FCR market in Europe14 As for frequency restoration reserves – aFRR and mFRR – it is each TSO of a control zone that is responsible for restoring system balance. At the European level, TSOs cooperate on procuring aFRR by using a joint platform called PICASSO (Platform for the International Coordination of the Automatic frequency restoration process and Stable System Operation) and on procuring mFRR via the joint platform MARI (Manually Activated Reserves Initiative)15

TECHNICAL FUNCTIONALITIES RELATED TO

There are technical functionalities and configurations of components that are not considered an ancillary service themselves, but that are crucial for the provision of an ancillary service. As for frequency control, examples are ramping conditions and power oscillation damping.

Ramping conditions refer to how quickly power generation can increase or decrease— ramping up and ramping down, respectively.

While ramping conditions are not categorised as an ancillary service as such, they may be part of technical requirements laid down by grid operators that power generators may have to fulfil. To maintain frequency stability, system operators may specify ramping limits by setting minimum and maximum limits on rates of change at which power generators can increase or decrease their active power output16 To allow

enough response time for e.g. frequency and voltage control, large generators and consumers should not change their load too quickly. In that sense, ramping conditions support the management other ancillary services indirectly.

FREQUENCY

Power oscillation damping is also frequency related. In electricity grids with synchronous generators, there are inherently low-frequency oscillations caused by the interactions between generators or areas of the grid, often at frequencies between 0.1 and 2 Hz. If oscillations are not damped, but rather stimulated, like a person swinging a rope (Figure 14), then the oscillations become larger and larger and eventually uncontrollable. Resonance can be considered as the amplification of an oscillation which may finally lead to overloading17 To avoid this, power system stabilisers as part of

13 The following description is based on: Regelleistung.net (2025). ‘Welche Arten der Regelreserve gibt es’, Available online: https://www.regelleistung.net/de-de/Grundlagen/Welche-Arten-der-Regelreserve-gibt-es (last accessed on 07/11/25); Graebig, M., Erdmann, G., Uhlig, I., and Ellery Studio (eds.) (2023): ‘Sun, Wind & Wires. Atlas of an Energy System in Transition’. Ellery Studio. p. 60f.

14 In accordance with Art. 33 EBGL (ENTSO-E (2017). ‘Electricity Balancing Guideline (EBGL), Art. 33’, Available online: https://www.entsoe.eu/network_codes/eb/fcr/, (last accessed on 07/11/25).)

15 More information is available here: ENTSO-E (2025). ‘PICASSO’, Available online: https://www.entsoe.eu/network_codes/eb/picasso/ (last accessed on 07/11/25); ENTSO-E (2025). ‘MARI’, Available online: https://www.entsoe.eu/network_codes/eb/mari/ (last accessed on 07/11/25).

16 European Commission (2016). ‘NCRfG Guideline, Art. 15 (6e)’, Available online: https://eur-lex.europa.eu/legal-content/EN/TXT/PDF/?uri=CELEX:32016R0631 (last accessed on 07/11/25).

17 German Federal Ministry of Economic and Climate Action (2023). ‘System Stability Roadmap’, Available online: https://www.bundeswirtschaftsministerium.de/Redaktion/EN/Publikationen/Energie/system-stability-roadmap.pdf?__blob=publicationFile&v=5 p.19, (last accessed on 07/11/25).

GFM BESS may help damp low-frequency oscillations in the grid by modulating active power injection and absorption in counterphase to the oscillation, similar to a Power System Stabiliser (PSS) of a synchronous machine. For this purpose, a Power Oscillation

the synchronous generators’ control loops are used to damp these low-frequency oscillations. Inverter-based renewable power generation typically does not offer power oscillation damping18 Power electronic components and additional control mechanisms, however, may additionally be used to mitigate power oscillations and resonances in electricity systems with high shares of renewable power generation.

Damping (POD) controller can be explicitly designed into the active power control loop of a GFM BESS. In this way, GFM BESS may additionally improve the dynamic stability of a system with large shares of renewables.

GFM BESS can absorb harmonics caused by other nearby assets such as nonlinear loads etc. By reducing the harmonic distortion at

the point of connection, GFM BESS cleans up the voltage waveform and improves power quality for nearby sensitive loads or converters.

INERTIA

VOLTAGE AND REACTIVE POWER

In alternating current transmission and distribution grids, real power, abbreviated with a P, flowing from generators to loads is the electric power that is actually used. By contrast, reactive power, denoted by Q, flows—or oscillate—back and forth in equal amounts between its source and the load, but supplies no energy19 Yet, reactive power is essential for maintaining voltage within its required range and is hence procured by grid operators for regulating voltage control. Synchronous generators in power plants can produce reactive power and have traditionally supplied it in addition

to generating active power. The provision of reactive power comes at an opportunity cost for electricity generators because it reduces their thermal limits20 Motors, transformers and electric appliances, particularly those with coils or inductive components, consume reactive power. For the safe operation of electrical grid users, from small-scale household appliances to large-scale industrial machinery, voltage must be kept within a certain range to prevent disruption or damage. Additionally, supplying reactive power is essential for keeping voltage stability when transporting active power over long distances. This helps prevent voltage drops along the transmission line and minimises voltage fluctuations.

Inc. p. 384. 20 Stoft, S. (2002). ‘Power System Economics. Designing Markets for Electricity’. IEEE Press. John Wiley & Sons, Inc. p. 385f.

While frequency is a system-wide parameter of an interconnected power grid, voltage and the provision of reactive power is rather local or regional, and not system-wide. This is because the effect of a reactive power injection on voltage diminishes over the distance. By the same token, the impact of reactive power provision is quite dependent on the local specificities in the respective

part of the grid. Similarly to frequency control, voltage control is an ancillary service that is required permanently. Synchronous generators and condensers provide significant reactive power for voltage stability. Power electronics-based FACTS devices such as Static Synchronous Compensators (STATCOMs) and Static Var Compensators (SVCs) are advanced fast-acting devices capable of providing or absorbing reactive power and thereby rapidly regulating the voltage at the point of interconnection.

The formal definition of inertia in the context of power grids is ‘the property of a rotating rigid body, such as the rotor of an alternator (AC generator), such that it maintains its state of uniform rotational motion and angular momentum unless an external torque is applied’21 To elaborate: many synchronous power generators as well as large rotating motors have spinning parts that rotate at the grid frequency thereby contributing to keeping demand and supply in balance. System inertia is

the kinetic energy stored in these spinning parts22 If system frequency suddenly changes, for example due to the outage of a power plant, these parts will continue to spin, and the rotational motion will persist – even when the generator has lost power. This slows down the rate of change of frequency (RoCoF). The allowed RoCoF is +/- 1 Hz/s. In other words, inertia has a dampening effect and can help to smooth out sudden increases or decreases in frequency and prevent cascading failures,

even before frequency containment and restoration reserves are activated.

With less synchronous power generators, such as nuclear, coal- or gas-fired power plants, in the system, there is the need for finding new ways of inertia provision. Due to their technical characteristics, inverter-based renewable generators, such as wind turbines and solar PV, do not synchronise with the grid in a way that they

mechanically deliver inertia as the grid frequency changes.

One possibility is to technically mimic the stabilising effect of the mechanical inertia of synchronous generators as a control strategy for wind turbines and solar PV. This technical capability to replace the effect of the inertia of a synchronous generator to a prescribed level of performance is called ‘synthetic inertia’23

ISLAND OPERATION

Island operation becomes important when a part of the electricity grid becomes separated from the larger interconnected system. In this mode, the isolated part of the grid continues to operate independently and can still supply power to connected loads. As a prerequisite, there must be at least one power generator that has the technical capability of contributing to frequency and voltage control so that the operation of the islanded network remains stable24

Pumped hydropower and grid forming BESS can well support island operation. Grid forming BESS can initiate the black start in small grid islands. In addition, it can contribute to restoration with its flexibility to change from charging to discharging while the grid operator is ramping up generation and load and gradually reconnecting the grid islands. However, the limited charging/ discharging duration may also impose challenges in case the grid restoration process takes a long time.

21 European Commission (2016). ‘NCRfG Guideline, Art. 2 (33)’, Available online: https://eur-lex.europa.eu/legal-content/EN/TXT/PDF/?uri=CELEX:32016R0631 (last accessed on 07/11/25).

22 The explanation in this section is based on: National Energy System Operator – NESO (2025). ‘What is inertia?’, Available online: https://www.neso.energy/energy-101/electricity-explained/how-do-we-balance-grid/what-inertia (last accessed on 07/11/25).

23 ‘Synthetic inertia’ means the facility provided by a power park module or HVDC system to replace the effect of inertia of a synchronous power-generating module to a prescribed level of performance.’ according to European Commission (2016). ‘NCRfG Guideline, Art. 2 (34)’, Available online: https://eur-lex.europa.eu/legal-content/EN/TXT/PDF/?uri=CELEX:32016R0631 (last accessed on 07/11/25).

24 A formal definition is laid down in: European Commission (2016). ‘NCRfG Guideline, Art. 2 (43)’, Available online: https://eur-lex.europa.eu/legal-content/EN/TXT/PDF/?uri=CELEX:32016R0631 (last accessed on 07/11/25).

SAMPLES OF ELIA GROUP’S

ACTIVITIES ON ANCILLARY SERVICES

50Hertz plans and builds supercapacitors in its substations, also known as STATCOM. Supercapacitors, which store energy electrostatically, can rapidly charge and discharge within the range of seconds. Their rapid response dynamics enables them to contribute to balancing very brief power disruptions lasting just a few seconds. Due to their low storage capacity and duration, however, as well as high standby losses, they are not suitable as a storage option beyond these very short disruptions.

In Malchow, close to Berlin, the second generation of supercapacitors is under construction. The so-called E-STATCOM is provided by the Italian company NIDEC. It is capable of absorbing 150 MW of active power within 1.25 seconds. After its commissioning in 2028 it will ensure both voltage and frequency stability in the transmission grid25 In addition, 50Hertz invests into regular STATCOMS at several sub-stations (Lauchstädt, Weida, Ragow, Siedenbrünzow, Röhrsdorf). These devices have usually a rated capacity of 300 Mvar and are equipped with grid forming control software.

Within the Innovation Team of the Elia Group, the InPowEl project was initiated in 202426 It contains the development of Electro-Magnetic Transient (EMT) and Real-Time Digital Simulator (RTDS) models for BESS and E-STATCOM. Analysis of grid-forming and grid-following mode were performed. The goal is to identify

interactions between various technologies and the grid, as well as to recognise any limitations of EMT models and propose best practices for using them.

INERTIA MARKET IN GERMANY

The German inertia market operates based on a fixed-price model, rather than through auctions or tenders. This approach ensures transparency and predictability for participants. Key features include:

Fixed Price Determination: prices are set by an independent third party, ensuring neutrality and avoiding market manipulation.

Technology-Neutral Pricing: the price is independent of the technology used to provide inertia, allowing fair participation from various sources, including battery energy storage systems (BESS), flywheels, and other inverter-based technologies.

Price Announcement and Degression: prices must be announced for a two-year time horizon, with the possibility of variation within this period. A degressive pricing model is preferred to encourage

early market participation and rapid uptake.

Regulatory Flexibility: if the fixed price fails to attract sufficient participation or to meet system needs, adjustments can be made upon consultation with the BNetzA.

The market offers four distinct products, categorised by direction and availability:

Direction:

Positive inertia: supports frequency rise;

Negative inertia: supports frequency drop.

Availability Levels:

Basic product: 30% guaranteed availability;

Premium product: 90% guaranteed availability.

This differentiation allows TSOs to procure inertia services tailored to specific system needs and reliability requirements. The responsibility for procurement lies with the four German TSOs. The TSOs are obligated to accept every offer that meets the defined product and technical criteria. There is no volume cap. This open-access approach ensures that all qualified providers can

contribute to system stability, enhancing a non-discriminatory market environment. One of the goals of this procurement mechanism is to support the development of suitable inverters, specifically gridforming inverters, which will be needed to provide different system services provided by synchronous generators so far.

REACTIVE POWER MARKET IN GERMANY

50Hertz created a market for procurement of reactive power—the first of its kind in Germany. The market started in May 2025 and is split into 5 regions within the 50Hertz control area. Successful market participants receive a remuneration either for continuous or for discontinuous supply of reactive power 27 .

Details of the reactive power procurement mechanism:

Regional Procurement Zones: 50Hertz has defined multiple procurement regions within its control area. This regional approach ensures that reactive power is sourced where it is needed the most, reflecting the localised nature of voltage control.

Product Definition: reactive power products are specified based on technical parameters such as voltage level, location, and availability. Providers must meet these specifications to participate.

Open Participation: the mechanism is open to various technologies capable of providing reactive power, including battery energy storage systems (BESS), renewable generators, and conventional plants. This ensures a technology-neutral approach and a competitive environment.

Tendering Process: reactive power is procured through transparent tenders, allowing market participants to submit bids. The selection is based on predefined criteria including cost-effectiveness and technical suitability.

Contractual Framework: successful bidders enter into contracts with 50Hertz, which define the terms of reactive power provision, including availability obligations and remuneration.

Integration with Grid Operations: the procured reactive power is integrated into the system operation strategy of 50Hertz, contributing to real-time voltage control and long-term grid stability.

ADDITIONAL REFERENCES

DETAILED LIST OF REFERENCES

FOR FIGURE 0.6 AND FIGURE 0.7 IN CHAPTER 0

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HEATSTORE (2021). ‘Roadmap for flexible energy systems with underground thermal energy storage towards 2050’. Edited by GEOTHERMICA – ERA NET Cofund Geothermal. Available online: https://www.heatstore.eu/documents/HEATSTORE%20%E2%80%93%20Roadmap%20for%20flexible%20energy%20systems%20with%20underground%20thermal%20energy%20 storage%20towards%202050.pdf (accessed on 31/07/2025)

Hydrogen Underground Storage in Porous Reservoirs (Ed.) (2024). ‘Roadmap for successful deployment of underground hydrogen storage in porous reservoirs in Europe’.

Long Duration Energy Storage Council (LDES Council) (Ed.) (2021). ‘Net zero power. Long duration energy storage for a renewable grid’. With assistance of McKinsey & Company.

Long Duration Energy Storage Council (LDES Council) (Ed.) (2024). ‘2024 Annual Report. Long Duration Energy Storage Council’. Available online: https://ldescouncil.com/wp-content/ uploads/2025/05/2024LDESAnnualReport-1.pdf (last accessed on 17/11/2025).

Nadeem, F. et al. (2019). ‘Comparative Review of Energy Storage Systems, Their Roles, and Impacts on Future Power Systems’. IEEE Access 7, pp. 4555–4585. DOI: 10.1109/ACCESS.2018.2888497.

Panitz, F. et al. (2024). ‘Neue große Lasten – wer kann kurzfristig und flexibel mehr verbrauchen?‘ Ausführlicher Ergebnisbericht’. Part of study ‘Warmer Lichtsturm – Umgang mit Erzeugungsspitzen aus PV und Wind‘, pp. 52–65.

Rácz, V. (2025). ‘Exploring long-duration electricity storage solutions’. presentation online workshop, Budapest.

Revinova, S. et al. (2024). ‘Hydrogen in Energy Transition: The Problem of Economic Efficiency, Environmental Safety, and Technological Readiness of Transportation and Storage’. Resources 13 (7), p. 92. DOI: 10.3390/resources13070092.

Sepulveda, N. A. et al. (2021a). ‘Supplementary Information. The design space for long-duration energy storage in decarbonized power systems’. Nat Energy 6 (5), pp. 506–516. DOI: 10.1038/ s41560-021-00796-8.

Sepulveda, N. A. et al. (2021b). ‘The design space for long-duration energy storage in decarbonized power systems’. Nat Energy 6 (5), pp. 506–516. DOI: 10.1038/s41560-021-00796-8.

Shan, R. et al. (2022). ‘Evaluating emerging long-duration energy storage technologies’. Renewable and Sustainable Energy Reviews 159, p. 112240. DOI: 10.1016/j.rser.2022.112240.

Tarkowski, R., Uliasz-Misiak, B. (2022). ‘Towards underground hydrogen storage: A review of barriers’. In Renewable and Sustainable Energy Reviews 162, p. 112451. DOI: 10.1016/j.rser.2022.112451. Trevor A. et al. (2023). ‘Reservoir Thermal Energy Storage Benchmarking’. Idaho National Laboratory.

References used for Figure 0.6 (with input by Panitz, F., Stute, J. (Fraunhofer IEG, Fraunhofer Research Institution for Energy Infrastructures and Geotechnologies IEG) (2025)) Shan, R. et al. (2022); Sepulveda, N.A. et al. (2021b), (2021a); Energy Transition Expertise Centre (2023); Nadeem F. et al. (2019); Bolton, R. et al. (2023); European Commission (2020); European Association for Storage of Energy (2013); Rácz, V. (2025); Farivar G. G. et al. (2023); HEATSTORE (2021); Dias V. et al. (2020); DNV (2025); Tarkowski, R. and Uliasz-Misiak, B. (2022); Gas Infrastructure Europe (2021); Revinova, S. et al. (2024); Trevor A. et al. (2023); Hydrogen Underground Storage in Porous Reservoirs (2024); Grimm, J. et al. (2023); van Gerwen, R. et al. (2020); European Association for Storage of Energy (2018c), (2018a), (2018d), (2018f), (2018b), (2018e), (2018g); Panitz, F. et al. (2024).

References used for Figure 0.7 (Stute J., Panitz, F. (Fraunhofer IEG, Fraunhofer Research Institution for Energy Infrastructures and Geotechnologies IEG) (2025)) LDES Council (2021); Shan, R. et al. (2022); Rácz, V. (2025); Bolton, R. et al. (2023); Nadeem, F. et al. (2019); European Association for Storage of Energy (2018a), (2018c), (2018d), (2018f), (2018b), (2018e), (2018g); European Commission (2020); Long Duration Energy Storage Council (2024); Trevor, A. et al. (2023); Farivar et al. (2023); Gas Infrastructure Europe (2021); Hydrogen Underground Storage in Porous Reservoirs (2024); Panitz, F. et al. (2024).

GLOSSARY

ABBREVIATION TERM EXPLANATION

ACER Agency for the Cooperation of Energy Regulators European agency for further integration and coordination of the European energy market.

aFRR automatic Frequency Restoration Reserves An automatically controlled reserve, that can be activated by an automatic controle device. Its role is to restore the grid frequency to the nominal 50 Hz. It follows after FCR.

BESS Battery Energy Storage System

BTM Behind-the-meter

Batteries storing electrochemical energy with different technologies such as li-ion, lead-acid or flow batteries. They can differ in size, encompassing large-scale and industrial battery storage, as well as home storage systems. In this study, BESS is referred to as stationary storage systems.

BTM storage is a storage system that is connected downstream of the head meter at a grid user site typically at industrial sites, renewable generation facilities, or in homes.

CAPEX Capital Expenditures Expenditures for investments into an asset, for examples for storage systems, cables, transmission lines or power plants.

CCfD Carbon Contract for Difference Contract between the government and a company regarding the payment of the difference between a guaranteed price (strike price) and the actual, fluctuating carbon price (as seen on carbon markets) for each tonne of emission reduction delivered by the company through a low-carbon project.

CHP Combined Heat and Power A type of plant that simultaneously produces electricity and useful heat, resulting in higher fuel efficiency compared to power plants that only produce electricity and waste heat is not used at all.

CAES Compressed Air Energy Storage It stores energy by compressing air into e.g. underground caverns or tanks during charging. When discharging, the compressed air is heated and expanded to drive turbines, generating electricity.

Congestion A situation in the electricity system when physical flows on a transmission line or transformer exceed operational security limits.

Congestion management Coordinated actions taken by system operators to prevent or resolve grid congestion. It can be curative (in real time) or preventative (hours and days ahead).

FCR Frequency Containment Reserve The fastest balancing service used to stabilize grid frequency in case of sudden deviations. It must be fully activated within 30 seconds and acts as the first response to limit further deviations from the 50 Hz setpoint.

Front-of-the-meter FTM storage is a

system directly connected to the power grid without sharing its

point (or head meter) with other assets.

Gigawatt Unit of measurement for electrical power, equals to billion watts.

Grid-beneficial operation The operations of the grid-user take grid constraints into account, so that these constraints are alleviated.

GFL Grid-following

The capability of inverters to inject or absorb power by tracking the voltage and frequency of an existing grid, inherently assuming that the grid is stable. These inverters do not control or establish voltage and frequency themselves.

GFM Grid-forming The capability of inverters to establish and maintain stable voltage and frequency in a power system, without the need of another device providing setpoints for these parameters.

Grid-neutral operation

The operations of the grid-user take grid constraints into account, so that these constraints are neither alleviated nor aggravated.

Grid-straining operation The grid-user is operating the assets in such a way that grid constraints are aggravated.

Grid-aware storage operation Operation of grid user is optimised considering dynamic local grid constraints to reduce its impact on the constraints.

Grid-unaware storage operation Operation is optimised based on market prices, which do not reflect intrazonal grid constraints.

IDA Intraday Auction

IDC Intraday Continuous

ID Intraday Market

There are three cross-border Intraday Auctions in central Europe for trading of 15-minute contracts: at 3 PM and at 10 PM on the day before delivery for all 96 time slots of the following day, and at 10 PM on the delivery day for all 48 time slots after 12 PM on the same day. It is a sealed-bid auction with uniform prices as a result.

This market starts the afternoon before the delivery day (e.g. 3 PM or 4 PM depending on the type of contract and country). Gate closure is shortly before the delivery time slot starts (gate-closure differs from country to country, hour to 0 minutes). Trading is done in an open orderbook with individual transaction prices.

It is part of the electricity spot market following the DA market, usually starting on the day before delivery but allowing

ABBREVIATION

generate energy.

RD Redispatch The activation, by the SO, of power generation, storage, or demand facilities to adjust their output or consumption in order to resolve or prevent congestion in the grid.

RES Renewable Energy Sources In this report the term is mainly used for photovoltaic (PV), offshore wind, and onshore wind.

SHS Sensible heat storage Stores energy by heating or cooling a material (e.g., hot water tanks, molten salt, rocks). The material is typically heated with either electric boilers, heat pumps, or solar energy (solar heat collectors, concentrated solar power).

SDES Short-duration energy storage

Short-term flexibility

SoC State of charge

TYNDP

Ten-Year Network Development Plan

Storage systems capable of delivering energy for less than 8 hours at full capacity in the power system (in order to distinguish from long-duration energy storage, LDES).

The capabilities which are required to cover the expected and unexpected variations in the residual load in the intraday or balancing market time frame.

Remaining available energy stored in a storage unit at a given time, in relation to its nominal energy storage capacity, usually expressed in percent.

The ten-year network development plan offers a long-term European vision of the future power system and investigates how power links and storage can be used to make the energy transition happen in a cost-effective and secure way.

TES Thermal Energy Storage The storage of heat for later use, via sensible heat, latent heat, or thermochemical methods.

TSO Transmission System Operator Entity responsible for ensuring the efficient and reliable transmission of electric power on the high/extra-high voltage network, from large-scale power plants to distribution system operators.

V2G Vehicle-to-grid

Possibility to inject electricity from electric vehicles into the grid. In that sense, a fleet of electric vehicles can be used as a battery. Aggregators could manage EVs to either charge or inject power into the grid, responding to market prices or balancing needs.

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