The evolving Battery Energy Storage Systems (BESS) landscape in the UK

Battery Energy Storage Systems (BESS) help manage the variability of renewable generation by storing electricity when production is high and releasing it when demand increases. BESS assets have become a cornerstone of the UK’s clean energy transition, and the UK currently has around 6.1GW of installed BESS capacity, with several times that amount in development.

The utility of BESS becomes particularly evident in Scotland, which generates far more wind power than it consumes. Much of the demand is in the south of England, but the grid between the two regions has limited capacity. As a result, excess electricity cannot always be delivered where it’s needed, and wind farms are sometimes forced to switch off, a costly process known as curtailment. Batteries help by storing surplus power, reducing curtailment and enabling better use of renewable energy. Batteries also support the grid in real time. They can respond quickly to help keep the system stable, taking part in services that control frequency, voltage, and the balance of supply and demand.

Because BESS can perform a range of functions, from storing energy to providing real-time grid support, their importance will only grow as renewables make up a larger share of the UK’s power mix. As deployments increase, the technology is also evolving quickly. Projects are now being built which are larger, able to supply power for longer, or even directly connected to renewable energy assets, a process called co-location. In the following sections, we explore how these changes are shaping the design and operation of BESS assets across the country.

How changing market needs have shaped the duration of BESS assets?

In 2021, most BESS projects in the UK earned their income from ancillary services, with a key route to market being balancing the grid’s frequency, also known as frequency response services. As more batteries have entered the market and competition has increased, revenues from frequency response have declined. This is a result of a saturated market, with more assets bidding to provide frequency response services. At the same time, new opportunities have opened in the wholesale and arbitrage markets, where batteries buy electricity when prices are low and sell it when prices rise.

These new revenue opportunities have directly influenced the duration of BESS assets. Developers are now building systems with longer storage capacities - typically two to four hours - allowing them to participate more effectively in wholesale trading and balancing activities. An asset with a longer duration, say 2 hours, can discharge energy at full power for a 2-hour period before needing to recharge. This means it is better placed to benefit from periods of very low or high energy prices. Forecasts indicate that projects with three to four hours of storage are likely to achieve the best financial performance for systems commissioned between 2026 and 2030, a function of the increasing importance of arbitrage opportunities in the UK market.[1]

Government policy is also evolving to match these new market needs. One of the most important recent measures is the Long Duration Energy Storage (LDES) Cap and Floor scheme, introduced to encourage investment in assets that can discharge for eight hours or more.

For investors, the LDES Cap and Floor scheme provides greater revenue certainty by guaranteeing a minimum (floor) and capping the maximum (cap) return over the project’s life. This helps de-risk projects and make longer-duration assets more attractive to capital providers looking for stable, long-term returns.

24.5 GW of LDES capacity is under consideration for policy support, of which 4 to 6 GW is expected to be deployed by 2030. Though LDES and shorter-duration BESS assets perform different functions within a grid system, the level of LDES deployed is expected to impact future BESS revenues by crowding out some revenue opportunities.

How does location strategy impact BESS in the UK?

Regional differences in renewable generation and electricity demand mean that BESS assets in different parts of the country experience distinct market conditions. Projects in the north, where renewable generation is concentrated, often face grid constraints and periods of excess power, creating opportunities for batteries to charge at low or even negative prices. In contrast, assets in the south are closer to major demand centres and have greater opportunities to discharge during peak demand periods when power prices are higher.

These differences are reflected in market activity. Bid volumes, representing the absorption of excess energy by BESS, are highest in northern Scotland, while offer volumes, representing the supply of power back to the grid, are more common in southern England.

To account for these geographic variations, the government considered the adoption of zonal pricing in the UK, which would divide the country into geographical zones, each with its own price based on local supply, demand, and grid constraints. The zonal pricing proposal was deemed unfeasible in July, and instead, the government has decided to reform the Transmission Network Use of System (TNUoS) charges. TNUoS charges recover the cost of installing and maintaining the transmission system. BESS assets located farther from demand, such as those in northern Scotland, face higher TNUoS costs due to increased transmission requirements. In contrast, projects closer to demand in the south can benefit from lower or even negative TNUoS charges and, in some cases, receive payments for helping to reduce congestion.

As deployment accelerates, location strategy is becoming an increasingly important part of BESS project planning. Developers and investors must weigh how regional grid dynamics, policy design, and market access can shape both operational performance and long-term returns.

How are BESS operators maximising revenue in a changing market?

As the BESS market evolves, so too does the way projects generate income. The range of revenue sources available to operators has expanded, allowing batteries to earn money from several different markets and services, and build out what is known as a “Revenue Stack”, i.e. various revenues from a series of different service offerings. These include wholesale trading, the Balancing Mechanism, and ancillary services. This diversification has encouraged new commercial approaches as investors seek to earn the best returns.

Given the complexity of the market, it is common for asset owners to contract a third-party optimiser. This optimiser is typically an expert in power trading and will control the battery’s daily operations, placing bids on either a day-ahead or intra-day basis. The optimiser is reimbursed via a percentage fee on any revenues that it earns. BESS revenues earned in this context are notoriously variable, and there is widely recognised merchant risk present when pursuing this route to market. Factors such as the selected optimiser, duration of the asset, and its location all play key roles in determining the level of asset returns.

Given this variability, an increasing number of investors are seeking more predictable income, favouring contracted routes to market to reduce some of the merchant risk present. Some common contracted revenues are:

1. Capacity market contracts: These are payments from government entities for sites to provide spare capacity in the event that significant capacity drops off the grid, i.e. a gas power plant or interconnector cable trips. These payments are automatically received on top of other trading revenue, regardless of trading strategy or performance.
2. Tolling arrangements: These are contracts with a third party whereby asset owners contract out their asset to a third party who will trade the battery themselves for an agreed period of time, paying the asset owner a fixed fee in return. This provides consistent revenues but means any upside above the contracted fee is kept by the third party. Any capacity market contracts are usually excluded from this agreement and paid to the site owner.
3. Floor price arrangements: These are agreements with a third party to guarantee a minimum floor of revenue. Usually agreed with the battery’s optimiser, these carry a higher cost but provide both fixed revenues and merchant upside should the optimiser outperform the floor.

Lenders increasingly prefer projects that include mechanisms like these to provide some bankable base cash flows with which to size debt.

By contrast, investors with a higher risk appetite are targeting merchant revenue. They participate directly in wholesale markets and the Balancing Mechanism, taking advantage of price volatility to capture upside returns. The availability of both contracted and merchant strategies has broadened the pool of capital entering the sector, attracting investors with varied experience and financial objectives.

The UK’s market design is also evolving in ways that create new opportunities. The planned move from 30-minute to 15-minute settlement periods - time blocks used to measure and settle electricity use and payments - will allow operators to respond more precisely to short-term price fluctuations and capture additional value during brief periods of imbalance. Alongside this, advances in optimisation software are enabling batteries to make faster, data-driven trading decisions across multiple markets. Together, these developments are creating a more flexible and competitive commercial landscape for BESS in the UK.

How are grid connection reforms shaping the next phase of BESS deployment?

New BESS projects can only move forward if they get a connection to the electricity grid. However, long waiting lists and limited space on the grid have caused delays across the sector. To help fix the problem, the National Energy System Operator (NESO) is changing how grid connections work.

The new connection approach replaces the traditional first-come, first-served model with a criterion that evaluates project readiness and alignment with CP30 targets, prioritising projects that are ready to build and have the largest contribution towards reducing emissions.  This change marks a major shift in how connection capacity is allocated, ensuring that projects with the greatest potential to support renewable integration and system flexibility are granted earlier connection dates. NESO is in the process of reorganising the entire grid queue with updated connection dates expected by early next year. As results are released, we are likely to see some advanced projects benefit from having their grid connection dates moved forward, whilst less advanced projects will very likely see significant delays to their grid connection dates.

Under the old connection methodology, around 144GW of BESS capacity had secured connection dates through to 2038. To achieve the CP30 target for BESS, 27GW of capacity is required by 2030, a significant increase from current deployment level of 6.1 GW. Therefore, the new connection process is likely to favour some BESS projects that are ready to build by granting them earlier connection dates. This will accelerate delivery timelines and unlock investment in BESS projects.

Another important factor is whether the BESS project connects to the transmission or distribution network. Transmission-connected projects face higher connection charges, which add to significant upfront development costs, while distribution-connected projects (typically less than 100MW) face lower charges and can be sited more flexibly. There is also a regional element to the CP30 reforms with zonal caps for both transmission and distribution BESS capacity across the UK. Investors are incentivised to build out sites for both transmission and distribution connections in CP30 geographic zones which have spare capacity. These trade-offs shape how government policy forces developers to plan and deliver projects within an evolving regulatory environment that increasingly favours readiness and contribution to system value.

What are the trade-offs between stand-alone and co-located battery projects?

As the market evolves, developers are adopting different approaches to project design, with both stand-alone and co-located BESS systems playing important roles. Co-located BESS projects, where batteries are built alongside renewable generation such as solar or wind, have gained traction as a potential route to market. This allows batteries to store excess energy produced during periods of high generation and release it when output falls, helping to reduce curtailment and make better use of available renewable power.

In theory, strategically co-locating BESS assets can improve the economics of renewable energy projects. By sharing land, grid connections, substations, and supporting infrastructure, developers can lower capital costs and increase overall efficiency. BESS is particularly effective at addressing price cannibalisation, which occurs when oversupply of solar power lowers prices. BESS assets can offset this by storing power to sell when demand is high and supply is low, such as in the evening. Some sources indicate that two-thirds of solar projects currently in planning are expected to include some element of BESS co-location, though there is currently not a large operational fleet of co-located sites.[2]

Stand-alone BESS projects, by contrast, are sited independently of renewable assets and are primarily optimised to respond to grid-level needs like frequency response, capacity market, balancing mechanism, etc. This provides greater flexibility in choosing locations near demand centres or constrained parts of the network, where access to wholesale trading and balancing opportunities may be stronger.

The decision between stand-alone vs. co-located projects ultimately depends on site characteristics, connection costs, and revenue potential. Developers are assessing each project on its ability to capture value from local grid conditions and market participation rather than following a single preferred model.

Why are BESS projects getting bigger, and what does that mean for the market?

The average size of BESS projects in the UK has been on the rise, with completed sites averaging at 92 MW in Q1 2025, up from 63 MW in Q1 2024.[3] This growth in size is driven by strong policy incentives and market opportunities. To meet the government’s Clean Power by 2030 (CP30) targets, which aim to deliver between 23 and 27GW of battery capacity by 2030, policy support is being directed toward larger systems. A recent example is the Thorpe Marsh facility, a 1.45GW stand-alone BESS project which recently received £200 million equity investment from the National Wealth Fund. This reflects a shift toward assets capable of delivering sustained flexibility and supporting renewable generation over extended periods.

Developers are also building larger systems to capture economies of scale. Constructing a single high-capacity project can be more cost-effective than multiple smaller installations, particularly given the limited number of viable grid connection sites. Larger assets allow developers to make more efficient use of available infrastructure and improve project returns. The planning process can also be complicated and costly, making it easier to plan a single large project as compared to managing several smaller ones. These factors are collectively driving the rise of utility-scale BESS projects across the UK.

What's next for the BESS landscape?

As the UK accelerates renewable deployment to meet its CP30 targets, the need for system flexibility will continue to grow, keeping BESS at the heart of the energy transition. For developers and investors, key considerations such as duration, size, connection type, and location will determine both project strategy and long-term value. Market dynamics now vary widely by region and asset type, influencing how risk and revenue are balanced. While some investors will continue to seek stable, contracted returns, others will look to capture merchant upside in an increasingly dynamic market. With sustained policy support and a rapidly maturing sector, BESS is set to play an even greater role in shaping the UK’s future power system.

Sources

[1] GB BESS: How does CapEx impact the duration you select for your battery? - Research | Modo Energy

[2] BESS Co-location in Europe: A Bumpy Road to Commercial Maturity – Pexapark

[3] UK battery storage activity soars, bigger projects: H1 2025 recap