Tag: Electric Insights

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. Data from Ember

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.

This quarter was defined by record-breaking solar output and the lowest ever carbon emissions. Solar power broke all hourly, daily, and monthly records. At 1 PM on 10 May, it supplied more than 40% of Britain’s electricity demand for the first time. That month also saw both the cleanest day on record (averaging 28 grams of CO2 per kWh of electricity consumed), and then the lowest ever instantaneous carbon intensity of just 6 g/kWh. June then extended the run of milestones, with solar power averaging more than 3.4 GW over the month, well above the previous record of 2.8 GW.

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 second quarter of 2025. Each number links to the date it occurred on the Electric Insights website, so these records can be explored visually.

3 Note that Britain has no inter-seasonal electricity storage, so we only report on half-hourly and daily records. Elexon and National Grid only report the output of large pumped hydro storage plants.
The operation of battery, flywheel and other storage sites is not publicly available.

2025 got off to a turbulent start. Spain and Portugal suffered Europe’s largest blackout in over a decade, sparking considerable debate over the causes and solutions. The US imposed, then partially revoked, tariffs on all countries. Stock markets and oil prices slumped over fears of a global recession and reduced trade. Natural gas prices in the UK have fallen by a third since the start of the year, from £42 to £28 per MWh, bringing relief to both household and industry energy bills. This contributes to the large fall expected in Ofgem’s energy price cap from July onwards.

In contrast, the UK’s carbon price has increased by a quarter over the same period, from £52 to £64 per tonne of CO2. Nearly 20% fewer permits are being issued this year to align the market with the Government’s stricter netzero cap. At the same time, investors are rushing to buy permits over speculation that the UK and higher-priced EU emissions trading schemes will be linked.

Ofgem announced major reforms to grid connections, in an effort to unblock new investment in clean electricity generation. Article 2 discusses how this can help plug the shortfall in meeting the Government’s Clean Power 2030 targets. Investment in new solar PV capacity continued to gather pace, in part because planning laws around new utility-scale solar farms were relaxed. Combined with a particularly sunny start to spring, this means solar output is smashing records, so far it is 40% higher than just a year ago. This raises concerns about how far net demand will fall during sunny afternoons later in the Summer, discussed in Article 3.

Alongside solar PV, electric vehicles (EVs) and heat pumps are also taking off. The UK became Europe’s largest market for EVs in 2024, topping German sales for the first time. Article 4 looks at the impacts this will have on electricity demand going forwards, in particular increasing peak demand. Finally, hydrogen has been touted for decades as an alternative to electricity for powering our vehicles and heating our homes. We look at areas where hydrogen’s progress is stuck in the starting blocks, and where it could make a material difference to the UK’s decarbonisation.

Wholesale fuel and carbon prices since the start of 2024.

UK is being held back by its creaking planning system. Examples are abundant, from spectacular delays and cost overruns of HS2 to the nationwide shortfall of 4 million homes. The power sector faces similar challenges. New projects are waiting more than 10 years for a grid connection, which threatens to derail our energy transition. Britain has made strong progress on decarbonisation, generating more than 65% of electricity from clean sources in 2024. However, fears are growing that the Government’s target of 95% clean power by 2030 is unachievable without reforms to expedite grid access.

Mind the gap

Britain’s wind, solar and storage capacity must all more than double in just the next five years to meet the Government’s Clean Power 2030 targets. This makes it essential that projects are built and connected to the grid at a faster rate than has been seen at any point during the last two decades. Last July, Ember warned that the target for 50 GW of offshore wind was “out of reach”. The gap has narrowed since a larger budget was allocated to the sixth round of CfD auctions, driving more renewables uptake. However, Cornwall Insight recently projected that while existing plans would deliver 83 GW of wind and solar capacity, this is still 32 GW short of the Government’s minimum target.

Connection queue crisis

The connection queue is the list of projects with signed agreements to be plugged into the grid, but are not yet built. A project’s position in this queue dictates when it can start selling power. The previous “first-come, first-serve” rules meant developers could lock in grid connections at low cost for speculative projects with no firm plans to progress – akin to a holidaymaker claiming the hotel sunbeds with their towel at 6 am, only to then snooze in their room all day. The queue is now occupied by hundreds of “zombie” projects which delay connections for shovelready projects. By February 2025, the queue contained projects totalling 765 GW, enough to match Britain’s average electricity demand 25 times over.

Historical build rates for wind, solar, and energy storage projects in Britain, and the average rates needed over the next five years. For each technology, the five-year window with the highest build rate is highlighted, and these rates must triple on average to meet the Clean Power 2030 targets.

Ofgem’s Reform package

The Planning and Infrastructure Bill introduced in March promises to cut average waits by up to 7 years by switching to the “first-ready, first-connect” principle. Ofgem’s Connections Reform Package from April enacts these rules, creating two ‘Gates’ within the queue. Gate 2 provides firm dates to schemes that are both ready to connect (with finance, planning consent and land rights) and aligned with the 2030 Clean Power capacity requirements. Gate 1 instead offers indicative dates for projects that are either not ready or not strategically aligned.

More than half of the 765 GW queue may be downgraded to Gate 1, however, Gate 2 alone will not be enough. If all Gate 2 projects could be delivered by 2030, offshore wind and battery storage capacity would reach their targets, but onshore wind and solar PV would fall more than 10% short

Will it be enough?

It is too early to say whether these reforms will unlock the required investment. Detailed network modelling is still in progress, but early analysis from Ofgem shows the potential for undersupply of both solar and onshore wind, even if all projects in the Gate 2 queue are operating by 2030. Still, Ofgem estimates this package will save around £5 billion (£200 per household) on reinforcing the grid by prioritising projects that are in the parts of the country most in need of new supply.

Even with these reforms, meeting our 2030 targets will be a profound challenge. Uncertainty over the future structure of the electricity market following REMA, alongside fears of recession mean that developers are struggling to finance projects. Issues around local consent and supply-chain pressures present further barriers to build-out. Developers need clarity around market reform, supply-chain support, and further policies to lessen the burden of local consent. All eyes will be on next summer’s results from the seventh round of CfD auctions – an important indicator of the success of reforms – as they will determine what additional support will be required to stay on track with decarbonising the power system.

The impact of Ofgem’s reforms on the connection queues for solar, wind and battery storage, and how the remaining ‘Gate 2’ pipelines stack up against the Government’s 2030 targets. ’Built’ includes projects under construction, and only transmission-connected projects (rooftop solar is excluded).

Solar PV has raced from a green fringe technology to a global front-runner. The world spent close to half a trillion dollars on solar panels last year, more than every other generating technology combined. Since 2010, solar PV has leapt from just 7% to over 70% of all new power capacity added globally. Even Britain, more famous for drizzle and fog than blue skies, has ridden this wave. Installed capacity as of March exceeded 18 GW, with Government policy aiming to expand this to 45 GW by the end of the decade.

Demand for rooftop PV systems has roared back to life, with 57,000 systems installed in the first quarter of 2025, the best start to the year since 2012. With Ofgem’s price cap for electricity now almost 28 p/kWh, Which Magazine estimates that home solar systems can pay back their original cost in as little as 10 years.

Cuts to red tape now mean more businesses can install solar PV without planning permission, and the New Homes Bill aims to make rooftop PV standard on all new builds from 2027. Larger utility-scale solar farms are also coming online after they started receiving approvals from the Energy Secretary.

Britain has also enjoyed the sunniest start to spring on record. The Met Office confirmed that England enjoyed its sunniest ever March and April back to back. This all adds up to make 2025 a record year for solar power. Britain broke its record PV output twice at the start of April, hitting a peak of 12.2 GW on 1 April, and then 12.7 GW on 6 April. This year, cumulative generation to the end of April has been 40% higher than any other year.

Every silver lining has its cloud though. This rapid increase in solar generation raises concerns over how to manage the system on sunny summer afternoons. The National Energy System Operator (NESO)’s Summer Outlook warns that transmission-level demand could fall below 13.4 GW, eclipsing the COVID-era lows. This might leave the operator no choice but to issue unprecedented “negative reserve” notices, forcing inflexible plants, such as nuclear reactors, to back off when solar floods the grid.

Greater investment in large-scale energy storage, such as batteries and pumped hydro, alongside other sources of flexibility will be essential to managing this new wave of solar PV plants. Britain’s challenge may soon shift from making clean electricity to making room for it.