In 2023, distribution network operators (DNOs) contracted a record 3.2 GW of capacity into local flexibility services. Currently, the highly localized, small volumes available in these markets make them better suited for distributed assets such as electric vehicles. However, the size of these markets has been growing by an average of 50% per year over the past four years. With two grid-scale batteries qualifying into the most recent tender round, could these services prove valuable in the future?
Flexibility services allow DNOs to manage constraints on the distribution network
Network constraints occur when the amount of power flowing through the network approaches its physical capacity. On the transmission network, NESO uses the Balancing Mechanism to manage network constraints, re-dispatching generators to change power flows.
However, DNOs have historically only managed constraints on the distribution network through physical reinforcement. Over time, the grid has become more decentralized, and distribution-connected assets more controllable. In response to this, DNOs have opened up flexibility markets to manage power flows on their networks and reduce the need for reinforcement.
Service definitions vary widely, but are beginning to be standardized
Six different DNOs operate the distribution networks in different parts of Britain. Each of these has a different demand for flexibility services and a different procurement process.
DNOs use several platforms for procuring flexibility services, including Piclo Flex, ElectronConnect, and EPEX local flex. In July 2024, Ofgem appointed Elexon as a single market facilitator for local flexibility services, so we should see greater alignment in the near future.
Grid-scale batteries currently only participate in one flexibility service
Despite the fragmentation of the market, there is a level of standardization in the types of services that operators can provide. The Energy Networks Association (ENA) provides a template for service design, although details still differ substantially between DNOs.
Peak reduction is typically a demand turn-down service, rather than a generation turn-up service. This is unlikely to be relevant to batteries, which would typically be exporting during times of peak demand.
Operational Utilization and Scheduled Availability services require providers to reserve capacity for dispatch. They are notified of dispatch instructions by 1:30pm at day-ahead. Day-ahead power markets close by 10am, meaning that this reduces trading flexibility. Assets contracted over the evening peak in the National Grid Electricity Distribution (NGED) DNO region received an average availability fee of £35/MW/hour. This is unlikely to compensate for this reduction in flexibility, when batteries would normally be earning the majority of their revenues through energy arbitrage.
Operational Utilization provides access to high utilization fees without limiting trading flexibility. This could make batteries likely to utilize the service. Functionally, this market acts similarly to the Balancing Mechanism on a local level. Providers submit demand turn-down or generation turn-up prices (similar to a Balancing Mechanism Offer) to an exchange. The DNO can dispatch them from the day-ahead stage up to 2 minutes before dispatch.
So far in the 2024/25 reporting year, two batteries have pre-qualified to provide Operational Utilization services to UKPN. These are Gresham House’s Wickham Market battery and Gore Street’s Lower Road battery.
Highly localized, small volumes limit the opportunity for grid-scale BESS
80% of the capacity contracted into local flexibility services in 2023/24 was in Operational Utilization services, in which assets are paid only when dispatched. This happens infrequently, limiting the size of the market.
Where the data is available, for NGED, the DNO dispatched just 1,340 MWh over the 2023/24 year across the 450 MW of pre-qualified assets. This means the average asset was dispatched for just 3 hours across the year.
Prices for these dispatches were high, however, averaging £400/MWh. If a battery were able to enter all of its capacity into this market, it might expect to make £1.2k/MW/year. Based on current revenues, this would provide a 2% revenue uplift.
However, a grid-scale battery would likely be unable to enter all of its capacity due to the highly localized nature of these markets. This 450 MW total was split across 24 individual locations, with an average of 19 MW available in each. When shared by an average of 2.5 assets, this leaves just 7.6 MW of available capacity per location.
Currently, lower-capacity, distributed sources of flexibility, such as electric vehicles, are better suited to the smaller contract sizes available across multiple locations. Over time, we expect to see an increase in individual contracted capacities. This could make them more attractive to grid-scale BESS.