Tag: Electric Insights

Clean power got a major boost this quarter. The next renewables capacity auction (AR7) opened, with over £1 billion for new offshore wind projects. It offers longer contracts for some technologies, and higher maximum strike prices (up 11%) in the hope of attracting more capacity. Renewables and nuclear supplied two-thirds of Britain’s electricity in September, and clear skies throughout summer helped solar set new output records, briefly meeting over 40% of national demand. A sunny Saturday in August saw demand met by the transmission system sink to a modern-era low, as rooftop solar PV meant more power than ever was generated locally.

The weather now very much calls the shots, dictating power prices, system balancing and infrastructure stress. Our second article digs into the Royal Meteorological Society’s new State of the Climate for the UK Energy Sector report, charting how “dunkelflaute” and stormdriven surpluses affect power prices and security, and what this means for planning over the next decade.

Building the infrastructure to utilise clean power is the other side of the story. National Grid’s Great Grid Upgrade is the biggest overhaul to the transmission network since the 1960s. We look at its 17 major projects, from the Eastern Green Links to ‘Offshore Hybrid Assets’ that aim to cut curtailment and move Scottish wind power to southern demand centres. Flexibility is also booming: Britain’s battery storage capacity surged past 6 GW, with hundreds of projects under construction or given the go-ahead. We map the UK’s energy storage pipeline, identifying Scotland’s Central Belt and England’s industrial heartland as hotspots, and discuss the move towards larger and longer-duration storage, such as pumped hydro, thermal and hydrogen.

Carbon prices have risen 75% so far this year, after the UK and EU agreed to re-link their emissions trading systems. Our fifth article analyses this shift and its effect on industry, imports and bills. Falling gas prices have muted its impact on electricity generation costs. Ofgem cut the energy price cap for the first time in a year, but the 7% fall in July has been short-lived, as the cap edged back up by 2% in October.

The Government has set three Clean Power 2030 targets, covering the amount of clean electricity produced and overall carbon intensity. Progress towards these has been solid over the past 15 years, but has faltered in the most recent quarter, with the share of clean power falling and carbon emissions rising slightly.

A grey, still Wednesday in January revealed how the weather now calls the shots on Britain’s power system. Real-time prices spiked to over seven times the winter average (an eye-watering £2,900/MWh), and the system operator spent £21 million balancing supply and demand that day. The Royal Meteorological Society’s latest “State of the Climate for the UK Energy Sector” report shows how weather-driven changes in renewable output and demand drive power prices, and how extreme weather events increasingly impact on our energy infrastructure.

Throughout November 2024, calm and cloudy conditions led to below-average wind and solar generation. Fortunately, the long wind drought coincided with mild temperatures that reduced demand for electricity, muting price impacts. Similar conditions during January 2025 combined with freezing conditions in a so-called “dunkelflaute”event which led to large spikes in the wholesale price. Despite tight margins, there was no disruption to supplies as the National Energy System Operator (NESO) used interconnectors, stored energy and fast-start gas to balance supply and demand.

High winds and sunny skies led to the opposite problem in summer. Too much wind and solar generation through August 2024 meant that while wholesale prices were low, keeping the grid in balance was more difficult, and thus more expensive. Wind farms were required to curtail their output extensively, at a cost of over £40 million (the highest monthly total on record). This raises balancing costs which ultimately filter through to consumers.

The weather not only moves prices, but is increasingly damaging Britain’s energy infrastructure. Seven named storms hit the UK over the 2024–25 season (April to April). Storm Darragh (6–7 December 2024) left 2.3 million customers without power across Wales and central and northern England, while Storm Eowyn (24 January 2025) left >1 million customers disconnected across Scotland and northern England. Most faults were caused by high winds and/or flooding damage. Localised outages were also caused by extreme rainfall during the summer, and lightning damage during heavy thunderstorms in May.

When renewable output is low and demand is high over winter, wholesale power prices can spike. Net demand refers to electricity demand minus output from wind and solar, and its anomaly means how far net demand deviates from its long-term average. In contrast, balancing costs can spike during the opposite conditions in summer: when renewable output is high and demand is low.

Weather variability will become increasingly important

By 2035, wind and solar capacity is expected to more than triple, and electricity demand would be >50% higher as we electrify transport (via electric vehicles) and heating (via heat pumps). The RMetS report tests the resilience of the future power system, by modelling how the “dunkelflaute” events of January 2025 would play out. These conditions would be even more challenging for our future clean power system, as higher demand (from electrified heating) would coincide with stalled output from renewables.

Simply building more wind and solar farms is not enough. Even with triple the current capacity, their output would remain minimal on the bleakest days. In 2025 we faced a 35 GW gap between supply from wind / solar and electricity demand, which could be met by the nation’s fleet of gas-fired power stations. By 2035 this becomes a 75 GW gap – impossible to meet with our current fleet of power stations. To plug the gap, new technologies are needed: stronger interconnectors, ways to make demand flexible, firm low-carbon generation, and longer-duration types of energy storage, such as pumped hydropower and green hydrogen (see Article 4). One key opportunity for the future power system is the ability to store excess electricity when conditions are favourable (such as on 13 January when it was windy and mild), to be used later when conditions are more challenging (such as the following week when wind output fell close to zero).

Weather’s impact on electricity is no longer background noise, it is the driving force behind both prices and outages. As supply and demand become increasingly swayed by the elements, weather-dependent cold, calm, dark spells become the power system’s defining tests. The answer is to hedge this risk across both time and space by building in flexibility to harden our power system against future challenges.

The mismatch between demand for electricity and supply from weather-driven renewables during January 2025 (left), and simulated for the power system in 2035 (right). The the red and grey shaded areas show demand net of renewables, which is a core metric that determines how much flexibility is required to ‘top up’ wind and solar or reduce demand to keep the lights on – the higher the value, the more flexible the system needs to be.

Earlier this year, National Grid announced the Great Grid Upgrade: 17 projects that form the largest overhaul since the creation of our modern ‘supergrid’ in the 1960s. New offshore interconnectors and targeted upgrades to onshore networks, pylons and substations will strengthen the links between Scotland, England and the North Sea to move clean power from where it is generated to where it is needed. At a cost of £19bn, this expansion represents two-thirds of National Grid’s planned investments to 2030.

Britain’s grid was originally built to transmit electricity from centralised power stations to nearby towns and cities, but the way we produce and use power is changing rapidly. Wind power now provides 30% of Britain’s electricity, but is concentrated in windy Scotland and the North Sea, while demand is highest in the densely-populated South East.

Demand for electricity is also set to rise by 50% by 2035 as we turn to electricity for heat and transport, while new AI and data centres come online. This means even more electricity must be shifted around the country. Today, congested transmission lines mean we cannot use all the electricity we generate. This comes at a cost, with consumers paying >£1 billion so far this year to curtail wind farm output that could not be used. With network upgrades, more clean electricity can be used, lowering bills for everyone.

The UK’s high voltage electricity transmission network, and interconnectors to neighbouring countries. The Great Grid Upgrade and other planned projects are highlighted in red. Data from OpenStreetMap via OpenInfraMap.

Upgrading electricity networks is like building roads: the more routes there are available, the less likely you will hit traffic on any one route. The Great Grid Upgrade includes four new subsea cables (Eastern Green Links 1–4) to connect Scotland’s wind farms to the South and East of England. Other projects include the Sea Link cable from Suffolk to Kent to carry power from the planned Sizewell C nuclear reactor, and reinforcements to various lines throughout the country.

In addition, new interconnectors to France, Belgium, the Netherlands and Germany are planned or under construction, to help smooth out supply and demand over the wider continent. These include Nautilus (to Belgium) and LionLink (to the Netherlands), so-called “offshore hybrid assets”, which also connect to offshore wind farms, meaning that power can be sent to whichever country needs it more.

Most of the UK’s network upgrades are still in the planning stages, with onshore projects facing strong opposition from local groups concerned about the visual and environmental impacts of pylons. The Norwich-Tilbury transmission line received over 20,000 pieces of community feedback since its consultation launched in 2022, and 40,000 people signed a petition calling for less visible alternatives, resulting in 10% of the line being replaced with underground cables. Similar factors also led to the de-facto ban on onshore wind from 2015–2024, despite it offering the cheapest form of new-build electricity in the UK.

Opposition to new transmission pushes up the cost of electricity, as the alternatives of underground and offshore cables are 4.5 and 11 times more expensive than traditional overhead lines. Extensive delays in planning mean the problem (and cost) of curtailment stays with us for longer. Both the Government and National Grid have rejected large-scale underground cabling, with the Government instead proposing that residents near new pylons receive up to £2,500 off their energy bills over the next decade.

In the short term, the Great Grid Upgrade will mean construction traffic, new pylons on the skyline and billions in upfront costs. But we can learn from the Victorians, who built big with railways and sewer systems that caused disruption at the time, but created a legacy that benefitted the UK for a century since. Rather than continuing to pay to throw clean energy away, then pay again to replace it where it’s needed; it is time to build a grid that can see us through for decades to come.

Energy storage is essential to keep any clean power system running smoothly. Unlike traditional power plants, wind and solar farms cannot be ‘dispatched’ to meet demand, so storing energy in periods of high renewable output and releasing it when needed is a key pillar of the UK’s Clean Power Mission.

Battery energy storage systems (BESS) are now Britain’s largest form of energy storage. They use the same core technology as mobile phones and electric vehicles (lithium-ion cells), but on a much larger scale. Installed. BESS capacity has risen sharply over the past decade, from almost nothing in 2015 to over 6 GW today, enough to power 1.3 million homes for a day. BESS operators now make most of their money via arbitrage – buying low and selling high – but they can also “stack” revenues across other grid services (e.g. also providing balancing and frequency response). Falling battery costs and Britain’s grid lagging behind renewables expansion have created attractive investments.

The UK’s current and future energy storage infrastructure, separated by the class of technology and stage of project development.

The Government expects 23–27 GW of BESS will be needed by 2030 in their Clean Power Action Plan, three to four times current capacity. Industry is well equipped to deliver this, with 45 GW of battery projects consented or under construction. Most existing projects are in England, but Scotland has become a key growth area due to high wind output and tight network constraints (see Article 3).

The UK’s largest battery is in Moray, Scotland, with 200 MW of power and 400 MWh of energy capacity, and another 100 MW due to be added in 2026. It was built to ease congestion from nearby offshore wind farms, and could power 50,000 homes for a day. The UK’s National Wealth Fund is also planning a £500 million joint venture to deliver 1.4 GW of storage by 2028, with the first projects in Angus, Perth and Kinross.

Batteries can only hold a few hours’ worth of electricity. The Moray battery fully charges or discharges in just 2 hours. This means batteries pair well with solar PV’s daynight cycle. On the other hand, the UK’s wind output varies over days and weeks, while heating demand is highly seasonal. Mediumduration and long-duration storage (MDES and LDES) are needed to support the future energy system, and cut our reliance on firing up expansive gas power plants to fill these gaps. The Government anticipates 4–6 GW are needed by 2030 in their Clean Power Action Plan (rising to 11–15 GW by 2050).

The closest we currently have to long-duration energy storage is 2.8 GW of pumped hydroelectric storage, spread across four sites in Wales and Scotland. These use surplus electricity to pump water uphill and release it again to generate electricity when needed. These date from the 1960s to 1980s, and no new pumped hydro has been built in the UK for forty years. A wave of new developments are planned though, with 11 new projects at various stages of development in Scotland and Wales, which could add a combined 10 GW of capacity (200 GWh of energy), one-quarter of Britain’s daily demand.

Hydrogen is also a potential option for long-duration energy storage, which could last for weeks or months. Hydrogen can be produced by splitting water using wind or solar power, with the Government targeting 10 GW of low-carbon hydrogen production by 2030. Liquid-air, compressed-air, iron-air batteries, storing heat underground in aquifers, and a whole host of other technologies offer promising options to ride through longer shortfalls in supply.

Unlike BESS, long-duration storage does not present an obvious investment opportunity. Long-duration technologies are more expensive as it is more difficult to store electricity for long periods. They also charge and discharge less frequently (seasonal cycles rather than daily cycles), reducing arbitrage opportunities. Incentives are needed to encourage investment. The Planning and Infrastructure Bill introduced a “cap and floor” scheme to de-risk investments by topping up profits earned by long-duration storage (>8 hours) if they are low (and clawing them back if they are excessive). Applications opened this year and contracted 3–8 GW by 2035. Ofgem has waved a further 77 projects (29 GW) through to the final stage of assessment of the Government’s ‘super battery’ support scheme.

Together with grid expansion and more interconnection, storage is the glue that can hold together abundant renewables and reliable, affordable power. Batteries and long-duration storage solve different problems and need different support. Backing both types of technology, Britain can reduce its reliance on expensive gas, improve energy security, and make clean power dependable year-round.

The UK’s carbon market, which sets the cost of emitting CO2, is experiencing a strong rally this year. The carbon price is up 75% since January, pushing up the cost of generating electricity from fossil fuels.

For two decades, the European Union’s Emissions Trading Scheme (ETS) has placed a price on emitting carbon, giving companies the incentive to reduce emissions. The UK has run its own carbon market since 2021, separating from the European ETS as part of the Brexit negotiations. Through 2022, UK prices stayed aligned with the much larger European market, as their designs and the strictness of their targets were similar.

UK carbon prices tumbled in 2023, at one point falling to less than half of European prices. The UK’s ETS Authority issued more allowances to emit carbon, just as a faltering economy meant actual emissions were lower than anticipated. From 2024, the UK’s price settled around £18 per tonne lower than Europe’s price. £18 is a special number: it is how much the UK charges in addition to the ETS price for carbon emissions from major power stations.

This £18 ‘Carbon Price Support’ was instrumental in kick-starting the UK’s rapid decarbonisation of electricity a decade ago, making coal power more expensive than gas, and making low-carbon alternatives more economically viable. It had a downside though, putting British power stations at a disadvantage against imported electricity. In the first half of 2021, a British gas-fired power station paid £65 for each tonne of CO2 emitted, but one in Belgium or the Netherlands paid only €44 (£38). In the first half of 2025 this has equalised, with £62 paid in Britain versus €73 (£61) on the continent.

Carbon prices in the UK and Europe, converted to £/tonne. Forecasted prices from OBR, Reuters, BloombergNEF, Enerdata, and Simon Kucher.

At the end of January this year, the FT reported that talks had begun to rejoin the UK to the EU ETS. The UK carbon price jumped by 13% in a single day. At the UK-EU Reset Summit, both sides committed to take this forwards. Once linked, UK carbon prices would reconverge with those in the EU.

The upshot is that prices have risen by 75% since the start of this year. As every 2.5 MWh of electricity produced from gas power stations produces 1 tonne of CO2, this is putting upwards pressure on power prices. The rise has been modest though, adding £8/MWh over the last nine months, and has been more than offset by the fall in wholesale gas prices.

Even if European carbon prices stand still, relinking the markets would see UK carbon prices rise by a further 25%. It will reduce red tape though, as British businesses will avoid having to pay Europe’s new Carbon Border Adjustment Mechanism (CBAM), which comes into force next year. This will see Europe charge its ETS price on all carbon-intensive imports to the bloc, such as iron and steel, aluminium, fertilisers, and of course, electricity. The link may also add some certainty for businesses, making investments into cross-border projects such as interconnectors look more secure.

Looking forwards, projections for the ETS price point in one direction: up. Analysts see carbon emissions costing anywhere from £60 to £140 per tonne in 2030, as political will to decarbonise ratchets up, and free permits granted to some heavier industries are phased out. This will add further to the cost of generating electricity from gas, but with Government aiming to greatly reduce its share by then, this should have a weaker impact on the prices we pay for electricity.

Changes to the cost of generating electricity from a gas-fired power station in Britain (in £/MWh), between January and September of 2025.

Solar power shone this summer, with output rising 30% year-on-year. Capacity grew by 2 GW over the last twelve months, with projects such as the Cleve Hill Solar Park coming online in Kent. At 373 MW, it is four times larger than any other solar farm in the country, and over the coming months it will be supported by a 150 MW co-located battery.

Greater output from solar, biomass and wind helped to offset nuclear power falling by more than a quarter year-on-year. Britain’s nuclear fleet endured new lows, as maintenance and refuelling operations clashed with unplanned faults. Even so, grid emissions stayed near record lows, only slightly higher than summer 2024.

Britain’s electricity supply mix in the third quarter of 2025.

Demand told a different story: reaching 62.1 TWh over the third quarter, up 3.2% year-on-year. This is the fastest pace of growth since 2011, aside from the post-Covid rebound. Electrification continues to accelerate, with battery-electric and plug-in hybrids accounting for one in three new cars sold so far in 2025. Sales were helped by the launch of new models from Chinese carmaker BYD, with the UK now the largest international market for the world’s largest maker of EVs.

Finally, 30 September marked the one-year anniversary of Britain’s last coal-fired power station being turned off. The power system took its first coal-free year in its stride.

Installed capacity and electricity produced by each technology.[1,2]

[1] Other sources give different values because of the types of plant they consider. For example, BEIS Energy Trends records an additional 0.7 GW of hydro, 0.6 GW of biomass and 3 GW of waste-to-energy plants. These plants and their output are not visible to the electricity transmission system and so cannot be reported on here.

[2] We include an estimate of the installed capacity of smaller storage devices which are not monitored by the electricity market operator.

Summer delivered a string of extremes on Britain’s power system. Solar passed the 14 GW mark for the first time on 8 July, leaping above the previous 13.2 GW record. Meanwhile, biomass set a monthly record in supplying 9% of the country’s electricity during July. Interconnectors ramped up on 24 August, importing more than 30% of Britain’s demand over the day, the highest on record. An abundance of clean electricity on 6 September saw negative prices plunge to a new low of –£99/MWh, as over 23 GWh of wind output has to be curtailed, costing consumers more than £1.1 million. Finally, nuclear generation slumped to its lowest output this century, dipping below 2 GW on 24 September, as a shortlived trip compounded longer unit outages.

The tables below look over the past sixteen years (since 2009) and report the record output and share of electricity generation, plus sustained averages over a day, a month, and a calendar year. Cells highlighted in blue are records that were broken in the third quarter of 2025. Each number links to the date it occurred on the Electric Insights website, so these records can be explored visually.

The UK’s energy politics moved fast this quarter. Ministers ruled out a move to zonal power prices, which would have seen wholesale prices vary around the country based on regional supply and demand. Instead, they opted to accelerate planning and grid build-out, with major implications for where projects go and who pays for them. The government also agreed to go forwards with a 44.9% stake in the Sizewell C nuclear project, the biggest domestic clean-power investment in a generation. Scotland also approved Berwick Bank, which, at 4.1 GW, will be one of the world’s largest offshore wind farms. Looking abroad, China began building the Yarlung Tsangpo hydropower mega-project, which will have similar output to Britain’s entire electricity consumption.

This quarter, we look at how Britain’s power system is gearing up to run on zero fossil fuels. NESO’s 2025 target of being able to operate without emissions is edging closer, backed by new frequency response and voltage services that let the system lean on renewables, storage, and demand response. Next, we look at how the rapid rise of solar power has turned Economy 7 on its head. The legacy tariff, which offers discount electricity overnight, is out of sync with 2025 Britain: power prices are now lower in the daytime than overnight as solar power has surged by 40% in just a year.

The UK saw its hottest and driest spring on record, with heat waves punctuating June and July. Extreme heat is a power system issue, not just a weather headline. Article 4 explores how heatwaves push up electricity demand, reduce generator
and transmission output, as well as what it will take to maintain reliability as our summers intensify. Finally, Article 5 looks at the global liquified natural gas (LNG) market: how it overtook pipeline gas as the biggest source of world trade, and Britain’s role as a gateway between the US and Europe. With the potential sale of the Isle of Grain terminal, this position in the global LNG supply chain may evolve.

Central England temperatures during the second quarter (April-June) of each year since 1900.

Back in 2016, Britain had its first ever zero-coal hour. Then, 8 years later, the last coal-fired power station shut forever. However, we are still heavily reliant on fossil fuels. Gas has been burnt to provide electricity every hour of every day since the 1980s. Phasing out gas is the next step on the road to clean power, and a major milestone may be just around the corner. Since 2019, NESO has been preparing the electricity system to be capable of running with zero fossil fuels when there is sufficient renewable output for short periods by 2025.

Running with zero fossil fuels has been a multi-year project because it is technically much more difficult than phasing out a single fuel (coal). The grid relies on inertia, a service that absorbs fluctuations in supply and demand, like shock absorbers. Inertia is essential for keeping the lights on, but is only produced by conventional power stations – coal and gas, plus nuclear, biomass and hydro. The grid must also balance output from variable renewables using dispatchable power – options that are available instantly to meet demand. This means gas and other sources will remain essential for managing peaks in demand and shortfalls in wind and solar power for years to come.

Since 2020, NESO has introduced new tools to keep the grid stable without fossil fuels for short periods of time, such as the Dynamic Containment service for rapid frequency control, better voltage management, and systems to restart the network using clean power. It also trialled new ways for homes and businesses to offer flexibility, tested market changes to encourage low-carbon solutions, and ran the Demand Flexibility Service to reward shifting electricity use.

To date, the grid has never operated with less than 6 GW of conventional generation, and gas alone has never fallen below 0.74 GW. Turning off all gas plants, even briefly, will be moving the power system into new territory, and so must be handled carefully. The minimum fossil fuel generation fell steadily through the 2010s. In 2010 it had never gone below 12.5 GW, but by 2018 it was reaching below 2.5 GW. After that, progress stymied, as we started hitting the current limits of operability.

The minimum hourly share of Britain’s electricity generation from fossil fuels each quarter since 2010, and how much lower this could have been if all curtailed wind energy could have been used.

Around this time, curtailment of wind power picked up sharply, as the grid could no longer handle peak output. Wind farms have to be shut off, and generators elsewhere in the country (usually gas) turned on to replace their output. If that curtailed electricity could instead have been used, Britain could have theoretically reached zero need for fossil fuels back in 2019, and renewables plus nuclear could have supplied all the country’s demand for over 250 hours last year.

Britain is not alone in moving away from fossil fuels. Worldwide, seven countries have so far managed to run their electricity systems with no fossil fuels for at least a month, including Sweden, Tajikistan, and Costa Rica. Some large countries have managed to get below 10% fossil, including France (due to high nuclear share) and Brazil (extensive hydropower). Britain’s best so far is 22%, ahead of 30% in Germany, 50% in the US, Japan and South Korea, and 56% in China.

Getting to even short periods of zero-carbon electricity will require more than just new technology. It will mean upgrading the grid to handle higher peaks in renewables, expanding storage, and making full use of flexibility from homes, businesses, and industry. It will also take faster connections for clean energy projects and investment in backup solutions that don’t rely on fossil fuels.

The lowest monthly-average share of fossil fuels in national electricity mixes.

Ever since Britain had an electricity market, power prices have followed demand. High during the day when people are working, low overnight when they sleep. This summer, that logic has turned on its head, as supply of renewable electricity
becomes a bigger factor than demand.

The Economy 7 tariff was introduced back in 1978, giving households lower prices for power consumed overnight. This encouraged people to shift their consumption, especially with night storage heaters, to make sure there was sufficient demand to keep the expanding new fleet of nuclear reactors running 24/7.

Fast forward to 2025 and this pricing pattern has turned on its head. Over the second quarter, daytime power prices were lower than those overnight for the first time ever. The rapid rise in solar PV over the last two years means the grid is being flooded with clean power on sunny afternoons, helped by the sunniest Spring on record with 40% more sunshine hours than average.

Solar pushes down the need for conventional generation during daylight hours, and with it, power prices. The boom is set to continue as small-scale solar costs tumble and English housebuilders must legally install solar panels on new homes by 2027. The UK’s latest solar roadmap seeks to more than double installed capacity to over 45 GW by 2030.

Britain’s solar PV capacity, with new installs each year.

Prices are not just going down, becoming more prone to spikes. Prices during the evening peak, once the sun is setting, are growing relative to average prices. Back in 2010, a mid-merit power station could expect to turn on at 7 am and run through till 10 pm when demand started falling. Now, a contingent of stations need to turn on at 7, and then either shut down or dial back their output to minimum at 9 am once the sun is rising. Then they must ramp back up for just a couple of hours in the late evening.

Just as a gym membership becomes worse value for money if you only go twice a year, power stations must charge more if they operate less frequently. Fewer running hours mean that capital costs, insurance, and other fixed expenses need to be repaid from less output, while start-ups and running at minimum load are less efficient and so require more fuel, and induce more costly wear and tear.

California gives us a glimpse into the future. Their operator coined the term “duck curve” over a decade ago to describe declining midday demand and prices. Now the duck has flown the nest, as a huge build-out of batteries charges up on
midday sunshine to fill the morning and evening peaks. In many sunny regions, falling energy storage costs mean it is now possible to achieve nearly 90% continuous year-round solar power generation for around £75/MWh. If Britain is to tame its own duck curve, it will need rapid deployment of storage to soak up cheap midday solar and release it when it’s really needed.

The average daily profile of Britain’s wholesale power prices during the second quarter of each year from 2001 through to
2025, shown relative to the average price in the quarter.