IN Brief:
- Britain added 2GW of solar capacity over the past year, with output reaching a record 15.4GW in April.
- June wholesale prices after 7pm were more than twice their level at 2pm, according to Electric Insights.
- Storage, flexible demand, and other dispatchable capacity can shift or replace daytime generation as solar output falls.
Britain’s expanding solar fleet is increasing the requirement for electricity storage and other forms of flexibility as record daytime renewable output gives way to tighter evening conditions, according to the latest Electric Insights analysis commissioned by Drax and produced by academics at Imperial College London.
The report says Britain added 2GW of solar capacity over the past year, while solar output reached a record 15.4GW during April. During one half-hour period, zero-carbon sources supplied 98.8% of electricity, demonstrating how far the generation mix can move away from fossil-fired output when solar, wind, nuclear, and other low-carbon sources coincide.
The system challenge changes later in the day. Photovoltaic output falls quickly towards sunset while electricity demand can remain elevated or begin increasing, requiring other generators, storage, interconnectors, and flexible demand to replace several gigawatts of solar production over a comparatively short period.
Electric Insights found that wholesale electricity prices after 7pm during June were more than twice their level at 2pm. Prices also exceeded £500/MWh during periods of the month’s heatwaves, described by the report as the highest wholesale prices recorded during June, while the National Energy System Operator issued its first summertime Electricity Margin Notice.
The difference between midday and evening conditions illustrates why installed renewable capacity and dispatchable capability cannot be considered independently. Solar can reduce the requirement for gas-fired generation during daylight hours, but photovoltaic panels cannot extend production after sunset without electricity being stored or demand being moved to another period.
Britain’s summer operating conditions have already shown sharper daytime-to-evening changes as solar output grows, with heat-driven demand and relatively low evening wind creating a wider range of conditions for NESO to manage within a single day.
Batteries provide one route through that transition because they can absorb electricity when renewable production is abundant and discharge rapidly as solar output declines. Power rating alone does not determine their usefulness: a 100MW one-hour battery provides 100MWh of energy, while a four-hour plant at the same connection rating can sustain output much longer through an evening peak.
Pumped-storage hydro offers considerably larger energy volumes and longer discharge periods, although development is restricted by geography and projects take much longer to consent and construct. Flexible demand can address the same system problem from the opposite direction by moving industrial processes, vehicle charging, heating, cooling, or other discretionary loads away from stressed periods.
Interconnectors add another source of flexibility, but their contribution depends on electricity conditions in neighbouring markets. Widespread European heat or low wind can tighten several connected systems simultaneously, reducing the amount of import capacity that Britain can assume will be available during its own evening peak.
High temperatures create additional operational pressure. Air-conditioning and cooling loads increase electricity demand while thermal generating equipment and transmission assets can face reduced efficiency or tighter operating limits. A hot, still evening following strong daytime solar output can therefore combine several system stresses just as photovoltaic production falls away.
The Government’s Solar Roadmap targets panels on an additional three million homes and around 10GW of additional solar capacity by 2030. If delivered, that would increase the amount of low-marginal-cost electricity produced in daylight hours while making the residual demand left for other resources more variable unless storage and flexibility develop at a comparable pace.
The storage requirement cannot be measured simply by counting the capacity contained in Britain’s project pipeline. Grid location, connection date, energy duration, response speed, operating strategy, and commercial structure determine what an individual battery can contribute once it is energised.
A project waiting several years for a connection cannot assist a near-term evening ramp, while a battery behind a severely constrained part of the network may have a different system value from one located close to demand. The challenge is therefore to deliver the right mix of power and energy capacity rather than maximising a headline gigawatt total.
Solar and storage economics are also linked. Greater daytime photovoltaic output can increase the difference between lower midday and higher evening wholesale prices, strengthening the opportunity for energy arbitrage. If large volumes of batteries then compete to exploit that spread, the price differential can narrow, pushing projects towards combinations of wholesale trading, balancing, reserve services, and capacity-market income.
The Electric Insights figures do not suggest that further solar should be avoided. They show that the engineering consequences of solar growth increasingly extend beyond generation itself. Networks, storage, dispatchable generation, demand response, and control systems determine how much clean daytime production can be carried into the hours when the panels are no longer generating.
Britain is already demonstrating that very high shares of low-carbon electricity can be supplied during favourable periods. The next constraint is temporal rather than simply annual: delivering adequate power through the transition from a solar-rich afternoon to the evening peak without recreating dependence on high-cost gas generation every time daylight fades.
