Tag: Electric Insights

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.

The UK, Western Europe, Japan and parts of China saw their warmest June on record in 2025. Rising temperatures place growing strain on both public health and power systems. Across the world, 500,000 heat-related deaths occur each year, with 1,300 excess deaths in the UK alone last summer. The heat also lowers people’s productivity, with hot days (above 28°C) costing the UK economy an average of £1.2 billion per year.

Alleviating heat stress requires that homes and businesses are cooled to a comfortable temperature. Across the UK, rising temperatures mean the need for cooling is rising by 3% per year. In London, this is growing by 5% per year, faster than anywhere in the world. This is leading to more households purchasing air conditioners (ACs), as people no longer want to tolerate stiflingly hot nights.

The number of homes with ACs in the UK rose from 3% to 20% between 2011 and 2023, with a huge leap following the UK’s record-breaking 2022 heatwave. The Government are considering plans to extend the £7,500 grant for heat pumps to cover air-to-air systems, capable of both heating and cooling homes, which could further accelerate uptake. Each additional degree also means ACs must work harder to maintain the same indoor temperature, further increasing the amount of electricity consumed by a growing stock of ACs.

This problem is not unique to the UK. AC usage is rising across Europe, and with it summer peaks in electricity demand. In France, a country with relatively low ownership, the June heatwave saw peak electricity demand soar 25% above the typical off-season average.

Maximum daily temperatures in central England this year compared to the range of temperatures seen since 1900.

Thankfully, when it is hot and people need cooling the most, the sun is shining. Britain’s solar panels produce 40% more electricity on days that reach above 25 °C compared to days that don’t get above 20 °C. This means that when ACs are
running flat out, they can tap into a cheap and low-carbon electricity, minimising the grid and emissions impacts.

Rising temperatures still bring challenges for electricity supply. Transmission cables expand and sag in the heat, increasing the risk of faults and reducing the amount of power they can conduct by up to a tenth. Maintaining grid reliability as the UK warms will require improved cooling methods, upgrading to higher-capacity transmission and distribution cables, and updating asset ratings to reflect the impacts of climate change.

Power stations are also challenged by extreme heat. During June’s Mediterranean heatwave, all but one of France’s 18 nuclear reactors had to reduce output as river temperatures soared to 5°C above normal, meaning they could not be used for cooling. Overall, French nuclear output falls by more than 5 GW when daily-average temperatures rise above 24°C, despite elevated demand. Power stations also become less efficient on hot days as less efficient steam cooling reduces turbine output. Even solar panels are affected by the heat, as high temperatures reduce their efficiency in converting sunlight into power.

Britain must face the reality that it is now a hot country, with rising temperatures reshaping daily life and electricity use. Adapting to this new norm means building a robust electricity system capable of meeting growing summer demand and coping with extreme heat, all while reducing emissions.

Cooling degree days (CDD) measure the need for air conditioning by combining how hot it is and for how long.
Left: a map showing how rapidly annual CDDs are increasing per decade across Europe since 1980.
Right: the evolution of annual CDDs in London, where they are rising fastest in the world

Natural gas heats eight in ten UK homes and provides one third of our electricity. Half of the gas we consume is imported, one-quarter of which arrives by ship in the form of liquefied natural gas (LNG), primarily from the US. The colossal $750 billion US–EU energy pledge will reshape global gas markets, with implications for UK energy prices and security of supply.

The UK’s dependence on imported LNG is a relatively recent phenomenon. The first ever LNG shipment came from Algeria back in 1964, yet by 2005 it still formed just 3% of the UK’s imports. Globally, LNG has now overtaken pipelines as the main form of trade, quadrupling from 140 to 550 bcm between 2000 and 2024. Qatar, Australia, and the US are the three major players in LNG trade. Qatar, home to the world’s largest gas field, started exporting LNG in 1997 and became the world’s largest source by 2010.Australia overtook Qatar in 2018, as exports from the Western Territory soared. It was not until 2016 that the first payload of LNG left the US, but export capacity has since increased twelve-fold (from 10 to 120 bcm), crowning it the world’s largest supplier.

The growth of major LNG exporters has been driven by breakthroughs in production and transport technology. Floating LNG enables offshore gas extraction without the need for expensive pipelines, while giant Q-Max tankers cut shipping costs by carrying over 3.5 TWh of cargo per trip (enough to heat 300,000 UK homes for a year).

LNG importers are concentrated in Europe and Asia. Production in the US flows to both continents, while Australia and Qatar cater primarily to the burgeoning Asian markets. Russian and North Africa export smaller volumes, mostly to Europe. Russian gas continues to enter Europe as LNG via spot diversions, worth around €8 billion per year. Russia accounts for around one-third of all LNG imported to France (8 bcm) and Spain (7 bcm) and almost half that in Belgium (3 bcm).

Left: Global trade in natural gas since 2000. Right: The UK’s source of natural gas since 2000.

Britain today is both a major LNG importer and a gateway to the Continent. Last year, most shipments arrived from the US (68%), with smaller amounts from Qatar (7%), Trinidad and Tobago (6%) and Algeria (5%). The UK’s three LNG terminals at South Hook (21 bcm/year), Isle of Grain (33 bcm/year), and Dragon LNG (8 bcm/year) could supply almost the entire UK’s demand of around 700 TWh per year. Some of this capacity is used to sell gas on into Europe: LNG is re-gasified in Britain and exported to the Continent via pipeline when European prices outrun those at home.

The new US–EU energy pledge is huge on paper, but bumps up against physical market limits. Europe cannot purchase, and US supply-chains cannot produce, the target $250 billion per year of energy. Total US energy exports amounted to ~$300 billion in 2024, with the EU accounting for just $80 billion. Replacing all Russian oil and gas imports solely with US supplies would increase Europe’s imports by around $70 billion over three years. That said, even a fraction of this volume would present a lucrative opportunity for Britain as one of Europe’s gas trading hubs.

Rising imports of US LNG to Europe will re-shape global gas markets, with first news of the US–EU energy pledge supressing UK gas prices. However, tariffs on US energy could have the opposite effect, driving up European and, indirectly, UK prices. Since gas sets electricity prices ~90% of the time, LNG price shocks feed straight into wholesale electricity costs. The UK must watch global gas geopolitics as closely as renewable energy goals. While Britain works to decarbonise its grid, flexible gas remains essential for meeting demand, and affordable LNG is key to maintaining supply-chain flexibility.

The major flows of LNG around the world. Arrow width is proportional to the annual trade in 2024.

Britain saw its cleanest-ever quarter for electricity production. The average carbon intensity fell below 100 g/kWh for the first time in the three months to June. This marks a symbolic waypoint on the road to the government’s Clean Power plan, which targets “well below” 50 g/kWh by 2030. Power sector emissions have now fallen to the point where they are now lower than those from UK aviation, a reversal that would have been unthinkable a decade ago.

Behind the headline, the grid mix shifted in familiar ways. Solar output continued its surge from last quarter, again being 40% higher than the same quarter last year. Biomass generation also rose 18% year-on-year, but nuclear output fell by
12% due to a heavy period of planned maintenance.

Britain’s electricity demand continued to edge back upwards, recording its seventh quarter of successive growth. Demand last quarter was up 2% year-on-year, as the growing fleets of electric vehicles and heat pumps continue to add load. The upshot is that Britain is still managing to cut emissions within the power sector while it contributes ever more to decarbonising transport and heat.

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

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.