Everything you always wanted to know about battery storage

Types of energy storage technologies

Energy storage systems are classified by the form of energy that electricity is converted into. 

BESS are now a cornerstone of modern flexibility strategies, whether installed as large-scale, stand-alone, co-location facilities or integrated behind the meter in homes, businesses and industrial sites. They help shave peak demand, optimise self-consumption and provide backup power during outages. When co-located with renewable energy installations, they also empower producers to manage their portfolios more effectively and offer valuable services to grid operators.

Today, lithium-ion batteries dominate the market, thanks to their high round-trip efficiency – often close to 90% – and their suitability for storage durations from seconds to several hours. However, growing demand for lithium has sparked interest in alternative chemistries, including sodium-ion, sodium-sulphur and metal-air batteries (see Question 10: What does the future of battery storage look like?). For even longer durations, flow batteries are emerging as a viable solution, capable of storing energy for up to 100 hours, though with slightly lower efficiencies of 50–80%.

To learn more, visit Everything you always wanted to know about flexibility.

Variable renewable energy (VRE) integration

Energy storage helps integrate wind and solar power by absorbing surplus generation that would otherwise be curtailed. The stored energy can then be released when demand increases or network constraints occur, improving utilisation of renewable resources and reducing revenue loss. 

The value of storage depends on its ability to capture surplus generation when it occurs and release it when it is needed. The timing, duration and volume of surpluses vary across renewable technologies and power systems, reflecting broader challenges, such as structural mismatches between electricity supply and demand – which storage can address.

Energy arbitrage (energy shifting)

Energy arbitrage involves charging storage when electricity prices are low and discharging when prices are high. This value stream depends on wholesale electricity markets with granular pricing. While price fluctuations exist in all markets, their scale varies, meaning not all liberalised markets currently offer price spreads large enough to support viable storage arbitrage business models. However, growing shares of VRE and rising electrification are expected to increase price volatility, with higher prices during periods of strong demand, and very low (or even negative)² prices when renewable generation is abundant. Although arbitrage is not essential for system reliability, it can reduce inefficiencies, smooth price extremes and lower overall generation costs, improving the functioning of electricity markets.

Arbitrage opportunities occur across different timescales:

• Daily: Driven by high daytime solar generation lowering midday prices and typical day–night demand patterns 
• Weekly: Linked to lower demand over weekends, creating longer surplus periods
• Seasonal: Occurring in systems with strong seasonal demand patterns or hydropower-dependent regions with dry seasons

Storage systems typically prioritise daily arbitrage first, followed by weekly and seasonal opportunities.

BESS (1-4 hours) is ideal for daily arbitrage due to their modularity and fast response, enabling daily cycling between periods of high solar/low demand and low solar/high demand. Pumped hydro and CAES are more suitable for weekly cycles thanks to their longer discharge durations. Hydrogen storage, while inefficient and costly for short-duration use, may be viable for seasonal storage as it can store large volumes of energy.

Larger storage systems generally increase arbitrage potential by enabling greater charging and discharging capacity. However, this benefit creates a trade-off: large-scale storage can influence market prices. Extensive charging can raise prices, while large-scale discharging can lower them, shrinking the price gaps that arbitrage relies on. As a result, arbitrage becomes less profitable when storage capacity grows too large relative to the market. This effect is particularly strong because storage can both buy and sell electricity, meaning it shapes prices more directly than generators like solar PV. As more storage is deployed, it smooths price differences across the system, further reducing arbitrage opportunities. Consequently, an efficient outcome requires a balanced level of storage capacity and storage operators typically need additional revenue streams—such as ancillary services—to remain profitable as arbitrage margins decline.

Congestion management

Congestion management aims to prevent or relieve overloading of grid infrastructure. It depends heavily on local grid conditions and can last from hours, days to several months, for example during summer period of high cooling demand. The most direct solution is to expand grid capacity, but grid reinforcement requires large investments and take years to complete. As a result, alternative technical solutions are often deployed. These assets must remain on standby during high-risk periods and be able to deliver energy continuously for several hours when activated. 

BESS currently dominates congestion management due to its fast response. Other multi-hour technologies like flow batteries could compete if costs fall. CAES and pumped hydro can also provide this service but are geographically constrained. Non-storage alternatives include Flexible AC Transmission Systems (FACTS) – i.e. power electronic devices for power flow and voltage control – distributed energy resources (DERs), demand response and conventional power plants that are re-dispatched by system operators. As batteries are typically only reserved for congestion management during specific high-congestion risk periods (often announced a day ahead), they can provide other services when not on standby.

Balancing services (ancillary services)

Balancing services maintain the real-time balance between electricity supply and demand. Forecasts are never perfectly accurate, and unforeseen disturbances – such as generation or transmission outages – can cause sudden imbalances. Balancing services help stabilise the system during operation. 

Historically, balancing services were provided by dispatchable fossil fuel plants, which reserved part of their capacity to ramp up or down as needed. Today, any asset capable of rapid adjustment can contribute, including BESS, demand-side flexibility (such as smart EV charging) and industrial load management. Balancing reserves are activated at different time scales, ranging from frequency containment reserves (FCR, within seconds), to automatic frequency restoration reserves (aFRR, within minutes), manual frequency restoration reserves (mFRR, within tens of minutes), and replacement reserves (RR, within hours). In systems with declining inertia due to high shares of inverter‑based resources (such as solar PV), frequency can drop more rapidly after a disturbance. To address this, Fast Frequency Response (FFR) services are introduced, providing milli-second responses that complement FCR and help stabilize the grid in low‑inertia conditions. Batteries, as inverter‑based resources controlled by power electronics, are particularly well suited to deliver these very fast responses to short frequency deviations.

BESS is currently most widely used for primary reserves due to its ultra-fast response and high power-to-energy ratio. For secondary reserves, BESS with longer discharge durations and pumped storage hydro are common. Technologies like CAES and flow batteries may also participate but tend to be less competitive and better suited as replacement reserves. 

Other system services

Energy storage can also provide specialised services that are becoming increasingly important in some power systems.

• Power quality management addresses voltage fluctuations that affect sensitive offtakers such as semiconductor facilities and data centres. These disturbances are usually sudden but brief, so short discharge durations are therefore sufficient. BESS is suitable because its inverter can inject and absorb reactive power, although capacitors and flywheels can also be used.
• Microgrids are small power systems that can operate independently or disconnect from the main grid when necessary. The required storage duration depends on the renewable sources supplying the microgrid and whether the goal is round-the-clock renewable power or only partial displacement of fossil fuels. Lithium-ion BESS is currently the most common option due to its relatively low cost and modularity, but it is often not the most efficient for continuous renewable supply. Flow batteries could be better suited for longer-duration operation but remain limited by cost. Hydrogen storage in tanks is being deployed in several island communities as a promising alternative.
• Black start refers to the ability to restart the power system after a blackout. Only a short burst of energy – often just a few minutes – is required to restart generators, which can then take over bulk power production. Moderate power capacity is needed to restart large generators (>100 MW), but fast ramping speed is not essential because load is restored gradually. However, grid-forming capability is required to re-establish system voltage and frequence. While any storage system can provide power to help generators restart, BESS systems are currently the most capable of performing a full grid black start.

Behind-the-meter (BTM) storage

BTM storage helps homes, businesses and industrial sites manage local electricity demand. This includes peak shaving, reducing power bills and matching on-site solar or wind generation to demand. BTM storage also provides ancillary services and participates in wholesale or demand response programmes, individually or through an aggregator such as a virtual power plant (VPP) if the capacity is too small. Battery storage is generally preferred because most BTM applications require daily cycling.

Long-term duration energy storage (LDES)

LDES most commonly describes storage systems capable of discharging for 6 hours or more. Initially, LDES can address daily or weekly surpluses, but as renewable penetration grows, it will be increasingly important for monthly or seasonal storage.

Lithium-ion BESS are not ideal for LDES due to discharge duration limits, requiring multiple parallel systems at higher cost. Pumped hydro, CAES and flow batteries are better suited for long-duration storage, though geography (hydro storage, CAES) and cost (flow batteries, hydrogen) can limit adoption. Despite these challenges, Li-ion BESS is emerging as a key LDES solution. For example, a UK cap-and-floor support scheme introduced in 2024 saw over 70% of submitted LDES projects use battery systems⁴, highlighting their competitiveness even for long-duration applications.

When a BESS is co-located with generation – such as solar PV – the project delivers both generated and stored electricity. While the result can be viewed as a blended LCOE/LCOS metric, in practice only LCOE is typically applied in such cases.

LCOS indicates the selling price of stored electricity during discharge that is required to break even on the total project costs, making it a useful benchmark to compare different energy storage technologies. However, LCOS does not capture all sources of value. Some services – such as frequency response – depends less on the volume of energy and more on the power capacity made available. In these cases, the economics are not fully reflected by an energy-based metric alone. In addition, the discharge duration of different technologies is a key factor in assessing the economics of storage options.

To illustrate these dynamics, we compare BESS, pumped storage hydro and hydrogen storage (using salt caverns) across different use cases. This explores how both the volume of energy to be shifted and timescale of shifting the stored energy affect technology choice. Representative load and supply (solar and wind) profiles were generated for daily, weekly and seasonal surplus cases to estimate the energy capacity required for each case. The BESS, PSH and hydrogen storage were then sized according to this capacity.^5,6

The figure above shows how the cost of storage shifts across timescales. For daily cycling, BESS delivers the lowest LCOS, followed by PSH and then hydrogen. As duration increases, the ranking changes. PSH delivers the lowest LCOS for weekly cycles, while hydrogen storage emerges as the lowest-cost option for yearly cycles. This reflects a key dynamic: the economic attractiveness of each storage option depends heavily on storage size and duration. While the total energy shifted remains broadly similar in the three cases, longer durations require much larger storage volumes, driving up LCOS, particularly for some technologies.

For BESS, rising LCOS is mainly driven by high capital expenditure (CAPEX). Longer storage durations require stacking more modular units, which increases cost. Although BESS benefit from high round-trip efficiency (about 85%-90%) and low charging costs, these savings are outweighed by high CAPEX. For yearly storage duration, underground hydrogen storage becomes the most economical. Its LCOS remains similar around USD 403-507/MWh regardless of duration. This is because salt caverns used for hydrogen storage are very large, allowing high CAPEX to be distributed across significant volumes. As a result, its LCOS is much less sensitive to scaling costs but more affected by high operating expenditures (OPEX) and low efficiency. Its round-trip efficiency is around 39% due to energy losses in converting electricity to hydrogen and back again through gas turbines.

Overall, no single technology fits all needs. A portfolio approach is key: BESS for fast response and shorter-duration flexibility, PSH for medium-duration balancing and green hydrogen for long-term, seasonal storage. 

Most hardware components have relatively similar unit costs and scale linearly with system size, since battery racks are modular This means total hardware cost increases with capacity. In contrast, “soft costs” – such as permitting, labour and project development – vary by region and are often the main driver of cost differences between projects. The cost breakdown of total BESS CAPEX reflects this mix of hardware and soft costs.

Battery costs have fallen sharply over the past decade, driven by economies of scale, technology improvements and supply chain optimisation (see Question 10: What does the future of energy storage look like?). A major factor has been the global lithium market, where oversupply led to a steep price drop in the past years. Although prices briefly rose in 2022 – marking the first increase in over a decade – they are not expected to return to earlier peak levels.  
 

Battery supply chains are increasingly shaped by geopolitics as critical minerals like lithium, cobalt, and nickel are concentrated in a few regions (see Question 10: What does the future of energy storage look like?). This exposes the sector not just to price volatility, but to broader political risks, including trade policies and resource nationalism. The key geopolitical risk is shifting from price fluctuations to availability. While battery costs are expected to keep declining partly due to overcapacity in China other regions such as the EU, US, and ASEAN face the challenge of building domestic manufacturing. This is particularly difficult given China’s strong control over the midstream supply chain, including mineral processing and cathode and anode production.

BESS projects typically combine two to six services.⁸ The most frequent pairings include energy arbitrage, frequency services and renewable integration (to smooth and better match variable wind and solar power with electricity demand that may also be used for e.g. capacity firming, ramp rate control or time-of-use shifting of energy).

As the energy transition progresses, both the size of markets and the type of grid services required begin to shift. In power systems with high shares of variable renewables and declining thermal generation, demand for balancing services initially increases. These include fast-acting frequency containment (FCR and even FFR in low-inertia systems) and slower frequency restoration services (aFFR and mFFR), which together rebalance supply and demand, stabilising the grid.  

Over time, however, these markets begin to saturate. Value creation then moves towards energy shifting – using batteries to store excess renewable generation and release it later when demand is higher.

China has taken a policy-driven, nationwide approach. Energy storage was first highlighted in the 2014-2020 Energy Development Strategic Action Plan⁹, and the current Special Action Plan for Large-Scale Construction of New Energy Storage (2025–2027)¹⁰ continues to drive growth. Li-ion BESS are deployed under the “New-Type Energy Storage Systems (NTESS)” programme, alongside CAES, flywheels and supercapacitors. Around 30 provinces have unveiled individual deployment plans since 2019¹¹ spanning the entire BESS ecosystem – from raw materials and battery manufacturing to grid and end-user applications.
Rapid utility-scale growth has been driven by provincial mandates pairing new solar and wind projects with storage, typically 5-30% of installed capacity.^12,13 Capacity leasing has become a key business model, contributing up to half of BESS revenues. While participation in wholesale electricity markets remains limited to certain provinces, ongoing nationwide electricity market reforms, including the launch of inter-provincial spot markets, are expected to expand opportunities for BESS.

In the United States, growth is concentrated in California (CAISO) and Texas (ERCOT). High penetration of solar and wind – 45% of power generation in CAISO¹⁴ and 40% in ERCOT¹⁵ – create frequent opportunities for BESS through energy arbitrage and ancillary services. Long-term revenue is supported by CAISO’s capacity market contracts, which ensure security of supply. While CAISO increasingly deploys four-hour systems, ERCOT favours shorter, one- to two-hour systems optimised for price volatility and ancillary services. As ancillary service markets become saturated, more BESS are moving towards energy arbitrage. Despite these challenges, both regions remain profitable and continue to expand rapidly, with ERCOT recently surpassing CAISO for total operating capacity.

The United Kingdom leads Europe in BESS capacity, with most utility-scale systems standalone and only 33% co-located with renewables.¹⁶ Growth has been enabled by market design. With the power system facing low inertia and the integration of more low-carbon technologies, a Dynamic Containment (DC) service17 was introduced in 2020 to replace Firm Frequency Response (FFR - It is not the same as “Fast Frequency Response” used in other markets for ultra-fast milli-second services) and target frequency response services from BESS, yielding high BESS revenues.¹⁸ This was followed by a split into Dynamic Containment High & Low frequency products (DCH & DCL) as the market evolved. 
Capacity market auctions, both four years ahead (T-4) and one year (T-1) provide the bulk of capacity market volume and offer up to 15-year contracts.¹¹ Rapid BESS uptake has saturated frequency services markets,  with the share in revenue stacking down from 80% in 2022 to just 20% in 2024.¹⁹ Value is shifting towards energy arbitrage in the lead-up to 2030, with improved access to the UK’s Balancing Mechanism through the Open Balancing Platform introduced in 2023 to improve BESS participation.²⁰

Other markets
Beyond the leading BESS markets, countries are progressing at different speeds, shaped by renewable penetration, system needs and regulatory maturity. 

BESS deployment at scale depends heavily on the regulatory environment. As countries expand the deployment of BESS to support higher shares of variable renewable energy, regulators play a central role in creating the enabling conditions. Insights drawn from international case studies across different market contexts and stages of development provide strategic guidance for future BESS implementation.

Read more on How to unlock battery storage potential?

Unlocking the full potential of BESS depends on a supportive regulatory environment that facilitates BESS viability and scalability. Implementing policy and regulatory enablers and addressing common regulatory challenges reduces investment risk and enhances the cost-effectiveness of BESS.  The energy market structure determines how each of these framework conditions should be designed to create such an enabling environment. 

Regulation and market design

Countries are at different stages in designing and implementing policies for utility-scale battery storage. At a minimum, the regulatory framework must allow BESS to participate in energy markets and system operations.

Ownership structures shape how BESS is deployed and reflect the underlying market design. In vertically integrated power systems, utilities typically own and operate BESS assets directly, enabling coordinated optimisation across generation, transmission, and distribution. In liberalised markets, transmission system operators are typically restricted from owning BESS assets to avoid conflicts of interest arising from their role as regulated grid operators. Assets are thus owned by private investors or independent power producers, bringing operational expertise and capital but with less control and shared revenues. Emerging markets tend to adopt hybrid models, involving a mix of utilities, private investors and third parties, as regulation evolves.

Traditionally, BESS has been treated as both generation and load, leading to taxes being applied twice: the “double taxation” problem, therefore clear classification of assets is necessary.
 

Clear rules are critical. Market participation rules define how storage assets access and compete in energy markets, while grid rules govern access, network charges and system integration. Permitting frameworks –  including land use, environmental impact and safety – are especially important given that BESS is often located near critical infrastructure and carries risks such as thermal runaway and fire. Compliance with international standards, fire protection measures and proper emergency planning can mitigate these risks. Many regulators are introducing streamlined, centralised and fast-track permitting procedures to speed up deployment. Operational rules then ensure reliable day-to-day functioning of the BESS.

Procurement 

Procurement defines how BESS is contracted. Mechanisms include auctions, capacity schemes (to ensure generation and storage capacity can meet peak demand), system services contracts (to maintain grid stability and reliability) and deployment or performance mandates for utilities or developers to install or procure a minimum level of storage capacity.

In vertically integrated markets, procurement is centrally directed through regulated planning and mandates, top-down by the state-owned utility or regulator. 
In competitive wholesale markets, BESS developers compete for opportunities through transparent processes like auctions, often stacking revenues across multiple services, strengthening the overall business case for investment. 
Emerging markets often use hybrid approaches, blending mandates, negotiated contracts and early-stage auctions to attract private investment as they transition towards more competitive frameworks. As markets evolve, system services procurement frameworks are introduced gradually, with their effectiveness at mobilising BESS deployment critically shaped by the pace of transition and regulatory clarity. Rising shares of variable renewables are a key driver, increasing the need for flexibility services like peak shaving and grid balancing.

Remuneration

Remuneration determines how BESS earns revenue and recovers costs. Various mechanisms include capacity payments (fixed payments to storage owners for making power available to the grid, regardless of whether it is actually dispatched), energy market revenues (earned by buying cheap electricity and selling it back at higher prices), ancillary service payments (for providing grid stability services), feed-in tariffs (guaranteed fixed prices paid per unit of electricity discharged into the grid) and power purchase agreements (PPAs, long-term contracts with buyers that guarantee a fixed price for electricity delivered over a defined period).

In vertically integrated systems, centrally controlled BESS dispatch can lead to underutilisation or misclassification if not explicitly prioritised in system optimisation.  Fixed tariffs make it difficult to remunerate standalone BESS, as there is little or no dynamic pricing and limited mechanisms to compensate ancillary services. Clear distinctions between standalone (used for grid services) and co-located BESS are needed to enhance renewable dispatchability. Effective policy needs to enable remuneration for both capacity- and energy-based services. To learn more, see What is the difference between capacity- and energy-based services?. 

In competitive wholesale markets, BESS can access multiple revenue streams, with market price signals driving investment and enabling revenue stacking. However, increasing BESS deployment can “self-cannibalise”, eroding returns as assets compete. Battery degradation (wear and tear over time) adds operational and financial complexity. 
In emerging markets, revenue streams are often unclear due to limited spot pricing and ancillary service markets. Governments therefore rely on interim tools such as preferential tariffs (reduced or guaranteed electricity prices for specific technologies to encourage investment) or PPAs to provide certainty. This is evident in regions like ASEAN, where solar is predominantly contracted through feed-in tariffs or utility PPAs, leaving standalone BESS with limited commercial incentives.

Environmental 

Sourcing: Battery manufacturing is energy-intensive and therefore relatively carbon-intensive. Mining, processing, production, use and recycling must be evaluated²¹ through lifecycle assessments (LCA), which quantify potential environmental impacts of a product within a system boundary.²²

• Battery manufacturing requires large amounts of electricity and heat for processes such as refining, electrode production, and cell assembly. When powered by fossil fuel, this energy demand translates into relatively high carbon intensity. Facilities using renewable electricity can significantly reduce this footprint. For illustration, CO₂ emissions for manufacturing an 80 kWh lithium-ion battery would range between 2400 kg and 16,000 kg.²³ Carbon emissions largely come from mineral refining, cathode/anode production and manufacturing processes. One study attributes 74% of all greenhouse gas emissions to the coating, formation and drying processes,²⁴ while another cites 61.5% from cathode production and electricity use.²⁵ Coal-based electricity increases emissions further.
• Battery chemistry is also crucial. Lithium iron phosphate (LFP) batteries produce about one-third fewer emissions per kWh than high Nickel-Manganese-Cobalt (NMC) batteries. In NMC batteries, emissions are mainly from critical mineral processing (55%), cathode/anode materials (25%) and manufacturing (15%). For LFP, the breakdown is roughly 35%, 15% and 50%.²⁶ Strategies to reduce emissions should therefore focus on cleaner cell production and renewables-based electrification. BESS operation contributes minimal to emissions. The source of electricity for charging can influence emissions, especially if coal-powered.

End-of-life (EoL): How a battery is managed at the end of its life significantly affects its lifecycle impact. Automotive batteries typically reach EoL at around 70% of their initial capacity (8-10 years).²⁷ Grid-connected batteries currently have no standard EoL definition. In most projects, batteries are used until capacity declines to around 80% of the original level (<15 years),²⁸ though they remain technically usable down to about 60%. Once a battery reaches its EoL, there are three main options:

• Business as usual – continued use of the battery, now without any performance guarantee from the supplier and with reduced benefits.
• Reuse in other less demanding services or parts – potentially risky if the operational history is unknown. A key challenge is developing screening, testing and grading protocols for second-life applications. Currently, no standardized process, universal guidelines, or fixed playbook exists for repurposing decisions. It depends on the battery’s individual condition, economic viability, and safety compliance.
• Decommissioning – battery disposal or recycling. In the EU, materials must be disposed of according to national or European requirements, including in the Batteries Directive (2006/66/EC) and the Waste Framework Directive (2008/98/EC). 

Currently, lithium-based battery recycling costs remain much higher than raw material production costs, due to the complex, energy-intensive process. Ongoing research aims to reduce costs, but recycling today is primarily driven by environmental considerations rather than economics. 

Social and economical

The Asia-Pacific region plays a dominant role in the global battery supply chain, with Australia, China, Japan and South Korea accounting for nearly half of the world’s installed energy storage capacity.²⁹ However, the raw materials that make up batteries are sourced globally:

• LFP batteries (the leading chemistry for utility-scale storage): Australia is the largest lithium producer, while Argentina and several African nations contribute to supply growth (DNV analysis based on S&P data).

• NMC batteries: The Democratic Republic of Congo supplies most of the cobalt, while Indonesia and China dominate nickel production.

Manufacturing adds further complexity. Critical components like electrolytes, anodes and cathodes are mostly produced in China, while cell manufacturing and final assembly can occur elsewhere, such as Vietnam, Thailand and Indonesia. These plants depend on imported components, creating a highly fragmented supply chain spanning mining, refining, processing and assembly. Managing risks across this chain is challenging, especially upstream, where visibility is limited due to multiple intermediaries and traders. This underscores the importance of robust traceability and risk management strategies.

Labour-related issues are the main risk in the mineral supply chain. Current regulations on supply chains, labour and transparency are country-specific, making global standardisation challenging. To address these risks, key due diligence steps should be carried out throughout the project – from the pre-development to decommissioning – with particular focus before financial closure or construction, including supply chain mapping, traceability studies and sampling.

Safety

Safety risks are most significant during battery operation. High energy density presents a risk of thermal runaway, an uncontrolled energy release and chain reaction that rapidly raises cell temperature, produces off-gases and can cause fire or explosion. This can also lead to spilled liquid electrolyte or the release of poisonous gases, which can impact workers’ health and safety as well as wildlife habitats. Identifying potential causes of failure at each stage is critical to designing effective mitigation strategies and ensuring safe operation.

Cost trends differ by region.³² For example, China benefits from mature supply chains and high production capacity, keeping costs low. The US faces higher costs due to tariffs, labour and permitting costs, with prices expected to reach China’s levels only after 2035. In Europe, supply chain challenges (e.g., constrained access to battery cells and critical minerals) and domestic production policies (e.g., local manufacturing, stricter sourcing rules) mean costs remain above the global average. These differences underscore the need for localised strategies for each region to scale storage deployment and achieve cost parity across global markets.

Short-duration BESS, mainly for ancillary services will drive steep LCOS declines up to 2030. Beyond that, longer-duration systems (2 to 4 hours) for energy shifting will moderate cost reductions but remain cost-competitive as renewable energy penetration rises.

Innovation and future uses in battery storage

Critical mineral supply risks are spurring innovation in alternative batteries. Geopolitical and raw material constraints for lithium-ion, lithium-iron-phosphate (LFP) and nickel-manganese-cobalt (NMC) systems are pushing the industry to develop battery technologies that are lower cost, use readily available and abundant materials and support a more resilient, sustainable battery ecosystem.³³

Several alternatives show promise in the medium- to long-term. These could outperform conventional Li-ion batteries in energy density, safety, lifespan, charging speed and economic feasibility while being scalable in production and materials.³⁴

Solid state batteries (SSB) are the most technologically mature emerging option, though current market share is below 1%. Using Li-metal anodes, SSB offer higher energy density, improved safety (as they do not contain flammable liquids) and longer lifespan. While technical challenges, including volume changes during charging or discharging, still need to be overcome,³⁵ SSB are well-suited automotive applications in the medium- to long-term. Commercial-scale adoption is expected between 2025–2030, representing a gradual evolution rather than a disruptive shift from Li-ion technology.³⁴

Sodium ion batteries (SIB) are rapidly advancing, with commercial SIB products already available.³⁶ By replacing lithium with abundant sodium as charge carriers, these batteries offer safety and cold-weather performance advantages. Lower energy density makes them more suited for grid storage, though some companies are also targeting mobility applications. Existing production facilities can be quickly repurposed, enabling faster scale-up.⁷

Cross-sector applications and distributed flexibility 

Cross-sector utilisation of battery storage is emerging, especially through the convergence of electric mobility, buildings, distributed solar PV and distribution grid management. In this context, batteries are not only storage assets for mobility or household self-consumptions—they can also become a source of flexibility for distribution sector, helping grid operators manage local peaks, reverse power flows, voltage constraints and congestion. If deployed at scale and actively managed, bidirectional charging could reduce total electricity system costs by 2.5-13% annually by 2040, depending on uptake of bidirectional vehicles and infrastructure.^38,39 

Vehicle-to-grid (V2G) and vehicle-to-home (V2H) systems remain nascent due to challenges like double-charging costs and the need for grid code alignment, smart meter roll-out and standards harmonisation to ensure compatibility between vehicles and charging points, as well as aggregator and grid operators. Car owners for example will only adopt these systems if the benefits are compelling. 
At the distribution level, it can help shift EV charging away from local peak periods, absorb surplus solar generation during the day and discharge when electricity demand or prices are high. This makes bidirectional charging a potential distribution grid flexibility resource, particularly in the areas where EV uptake, rooftop solar and local network constraints overlap. 
For households, V2H can also deliver direct savings – estimated at EUR 300-730 per year for a typical home with solar PV – by using their electric cars as flexible storage.^38,39  
Beyond individual users, residential batteries, EVs and other battery energy storage assets are increasingly aggregated into virtual power plants (VPPs). Already operating in countries like the US, Germany, UK and Australia, VPPs enable distributed storage to provide grid services like balancing power, peak reduction, congestion management, and where technically feasible, voltage and frequency support. In Germany, this model is helping replace fossil-based generation, while offering incentives such as free or discounted electricity to battery owners.⁴⁰ However, the value of VPPs is highest when aggregation is designed around both system-wide needs and local distribution-grid conditions, since unmanaged responses can worsen local congestion or create new peaks in distribution feeders. 

At the same time, digitalisation and AI are enabling new business models. These include peer-to-peer electricity trading between producers and consumers or via integrated storage facilities. Platform-based systems use storage as a flexibility resource for regional congestion management and local energy markets, expanding the role of batteries beyond traditional grid support.⁴⁰ 

To scale these models, smart meters, digital grid models, interoperable data systems, DER management platforms are needed, so that the grid operators and aggregators can understand where flexibility is available, verify its delivery and dispatch it within the network limits. For distribution utilities, these capabilities are essential to turn consumer-owned batteries and EVs into operational resources rather than unmanaged loads or generators. Dynamic tariffs, flexible connection agreements, and local flexibility procurement can further help align consumer-owned batteries with grid needs. Over time, peer-to-peer trading and local energy markets can play a larger role but they need to be embedded in distribution grid operation frameworks, to ensure that trading outcomes do not conflict with physical grid constraints.