Tag: Electric Insights

‘Dunkelflaute’ must surely be an early contender for the 2025 Oxford Dictionary word of the year. A German word meaning ‘dark doldrums’, it is used in the energy world to describe a dark, cold, calm spell of weather during which very little energy can be generated with wind or solar power.

In December and January, Britain faced two spells of so-called dunkelflaute. The first, hitting around the 12 December, saw wind – the largest source of energy in the UK last year overall – drop to 6% of total supply. In response gas power stations ramped up to their highest output ever recorded, supplying more than 73% of Britain’s electricity and sending power prices soaring. Wind output dropped suddenly again in the New Year causing prices to hit £2,900/MWh (40 times their average) on 8 January.

This winter has demonstrated some of the challenges we must address in reaching a clean power system over the next five years. The combination of a long cold snap and low wind speeds left Britain’s power system relying heavily on natural gas and imports, drawing down the nation’s gas storage to ‘concerningly low’ levels, and coming close to generation falling short of peak demand. Options for low-carbon flexibility are urgently needed – both investing in new technologies and maintaining existing sources – as electricity supply and demand become more dependent on the weather.

Daily average electricity mix in Britain during mid-December, highlighting the dunkelflaute period, and the difference between output from dispatchable or baseload technologies which we control, and those that are influenced by the weather or foreign power markets.

Gas was not the only technology to help during the shortfall. Biomass and runof- river hydro plants increased their output by 40% and 60% on the peak day (12 December) compared to the weekends before and after. While this helped meet the shortfall of wind, the impact was muted as Britain has relatively little capacity of either technology. In previous years, coal power stations would have also helped to meet demand, but the last one closed in September. Pumped hydro storage and batteries helped meet the evening peak on the 12th, but these only supply power for a few hours, and so cannot help with multi-day shortages.

Interconnection with neighbouring countries also provides flexibility, but on the 12th, when we most needed them, imports from abroad fell by half relative to the surrounding days. Britain’s neighbours were suffering from the same wind drought, as weather systems are often the size of continents. More power could have flowed into Britain, but only if our prices rose high enough. This exposes a key problem with relying on interconnection to solve capacity shortages, which leaves countries competing for a limited supply of power at the same time.

Altogether, this leaves gas as the only large-scale source of flexibility in the country. This is a risky proposition on three fronts: affordability, energy security, and our climate goals.

The cost of our gas dependence: We are still reeling from the gas price crisis. Gas is very much the ‘crutch’ of the grid, and British electricity is more strongly swayed by gas prices than in any other European country. Gas sets the price of electricity in 98% of hours, despite meeting only a third of demand. That means Britain’s electricity prices track almost perfectly with gas prices, leaving consumers particularly vulnerable to price shocks, as seen during the recent gas price crisis.

The change in electricity and natural gas prices on Britain’s wholesale markets over the last decade, indexed to the 2010–19 average. Gas prices include the cost of carbon emissions, and prices increased by over 50% between February and December last year, dragging electricity prices up with them.

Energy security at risk: Relying so heavily on a single technology in times of system stress is leaving all our eggs in one basket. Capacity was tight on 12 December and 8 January, causing the National Energy System Operator (NESO) to issue rare Capacity Market Notices, a ‘blackout prevention system’ used to encourage generators to prepare extra capacity just in case. Britain’s last coal plant has retired and all bar one nuclear plant is coming towards their end of life. This all comes just as peak electricity demand is expected to grow from electric vehicles, heat pumps, AI, and data centres. Unless more capacity is built or existing capacity has its lifetime extended, Capacity Market Notices will be increasingly common in the future.

The carbon challenge: Gas is the most polluting fuel remaining on the grid. In just five years, government aim to run a clean power system. This means having just 5% of electricity produced from fossil fuels, down from over 25% today. These plans include retaining almost all the current gas capacity to cover rare but intense periods of low renewable output. Put together, this means gas plants will see fewer operating hours in the future, just as coal plants did over the last decade. Either they will need to charge more for their output to cover costs, or the system will need to move towards paying for availability more than for output (e.g. capacity payments).

Scaling down gas will largely be achieved by scaling up wind and solar power, but that further intensifies the challenges posed by weather variability. Both the CCC and NESO recognise that a balanced approach is needed, using all the tools at our disposal – flexible low-carbon generation, long-duration energy storage, interconnectors and a continued (but increasingly limited) role for gas. Looking ahead, policy frameworks envisage the arrival of more low-carbon dispatchable power from 2030 onward. This includes power stations equipped with carbon capture and storage (CCS), hydrogen, and long-duration storage. All of these play little or no role in today’s power system, so the task now is to define a clear strategy for scaling and deploying these resources at pace, while avoiding cost escalation to consumers due to all the new investments. By planning for Britain’s future energy needs and taking strategic action now, government, industry and investors can break free from paying for expensive volatile gas imports, and seize the opportunity of clean, stable, and lower cost electricity.

The UK is currently stifled by electricity prices that are among the highest in the world. UK industry is spending 60% more per unit of electricity than any other European nation, but the reasons behind this are complex. Despite renewable energy expanding from 15% a decade ago to over 40% of the grid mix today, the structure of the electricity market means that fossil fuels, and particularly gas, continue to set power prices.

Several factors keep the UK’s electricity prices high. First, Britain’s infrastructure is a barrier. Being an island makes it costly to build interconnectors with continental Europe, limiting their capacity. This isolation limits the ability to import cheaper electricity from overseas when demand is high or renewable output low. Britain also lacks transmission capacity within its borders, so we are spending hundreds of millions of pounds on compensating wind farms that are unable to deliver power due to network congestion. Upgrading and expanding the grid to handle increasing renewable capacity involves significant costs, which are ultimately passed on to consumers.

Consumer electricity prices around the world in 2023, paid for by large industry (left) and medium-sized households (right). Prices in the UK are compared against thirty countries across Europe and other developed nations, inclusive of taxes and converted into GBP. Data from the Department for Energy Security and Net Zero.

Second, there are the costs imposed by energy policies. Around a quarter of a typical UK electricity bill comes from policy costs, including environmental taxes and subsidies. While these measures support the green transition, they also raise prices. Most of these levies are applied to electricity but not to gas, a choice that works against decarbonisation by making electric vehicles and heat pumps less attractive. In addition to the ‘environmental & social’ cost category shown below, policies that charge for carbon emissions lead to higher wholesale prices (and are included in that category).

Support for renewable generators from Feed-in Tariffs and similar schemes falls under ‘environmental costs’. Older generators receive payments on top of the wholesale price, however high it is. More recent wind farms and biomass plants were instead awarded fixed-price Contracts for Difference, meaning they repay the government whenever wholesale prices exceed contract prices. During the 2022–23 price spikes, these renewables were saving consumers money.

The elephant in the room is the wholesale cost, which rose by two-thirds over the last five years, and makes up the largest share of our bills. This is an issue of how we price electricity. Britain’s electricity industry holds an auction every day in which generators bid the price they would be willing to generate for. The highest bid that is needed to meet demand then sets the price for all generators. Some of our gas-fired plants are almost always needed to meet demand, so they set the price and that reflects their costs. This ‘marginal’ price is then paid to all generators, even ones that run 24/7, as the electricity they produce is worth just as much as that from any plant. Most markets work in this way: Saudi Arabia’s oil is cheap to produce but gets a very similar price to higher-cost oil from the North Sea. The underlying economic principle is so widespread that it’s known as the Law of One Price.

The breakdown of the average British household electricity bill. Data from Ofgem, for a standard consumer paying by direct debit.

The irony of gas setting prices when renewables provide most of the energy is not lost on consumers, sparking discussions on pricing reform. Instead, we could pay each generator what they bid into the auction (the ‘pay as bid’ principle). Wind farms and nuclear reactors currently bid low prices into these auctions, as their variable costs (for fuel, maintenance) are low. However, if they only received these variable costs, they could never recover their upfront investment, so developers would not build any new ones. If auctions instead paid each generator their own bid (as has been proposed several times), renewable generators would simply raise their bids to the expected price (justifiably), and it would get much harder to decide which plants should be running. For the time being, the price of gas is going to drive the price of electricity.

Another proposal is zonal pricing, where regions see different wholesale prices based on local generation. Areas with abundant wind, like Scotland and parts of northern England, could see lower prices, and new farms would not be compensated when the grid could not accept their output. Such reforms must be balanced against concerns that smaller markets could increase power price volatility, making generator profits less predictable. The added uncertainty could reduce investors’ ability to secure low-interest financing for renewables, and thus hold back new projects.

While UK electricity prices are high, we are not alone in this situation. Electricity prices rose sharply across the continent in the wake of the Russia-Ukraine war, and similarly they have all begun falling back towards pre-crisis levels. The UK sits roughly in the middle of the pack, with prices rising to a peak of 4.7 times their 2019 average, and now sitting 70% above. Norway and Sweden have seen the smallest rises, thanks in part to their abundant hydroelectric and nuclear resources. Conversely, Ireland has experienced the largest increases, driven by the rising electricity demand from data centre operations (see Article 5). Ultimately, the sharp rise in power prices reflects wider energy geopolitics, rather than an isolated phenomenon in Britain.

A new industrial revolution is underway, with companies and countries competing for dominance in artificial intelligence. Rather than factories and coal, this race needs data centres and electricity. Data centres are the backbone of the internet, delivering everything from search results to video streaming, and now increasingly they crunch answers to questions posed to AI chat tools. Worldwide, data centres consume more power than the UK and this is set to more than double by 2030. The Government recently commissioned the AI Opportunities Action Plan which calls for drastic action to boost the UK’s AI and computing capabilities. But how will scaling up the number of servers and power-hungry computer chips impact electricity demand?

The Government agreed to take forward all recommendations from the Action Plan, including to expand the UK’s sovereign compute capacity by at least 20x by 2030. This requires rolling out infrastructure UK-wide and setting up AI Growth Zones with fast-track access to the power network and planning approvals. This is critical to the growth of the AI industry as it can take years for new grid connections to be approved. A new AI Energy Council will be appointed to assess energy demands and accelerate investment in clean energy for data centres.

Globally the world’s data centres consumed around 500 TWh of electricity in 2024, overtaking British electricity demand in 2021. Forecasts see continued growth at 10–20% per year until the end of this decade. Since the release of ChatGPT in 2022, investment in generative AI has caused a surge in data centre energy consumption. Global power demand from AI increased by three times between 2023 and 2024 and is forecast to overtake total demand in Britain by 2030.

Global electricity consumption from data centres and AI models, compared to Britain’s total electricity demand. Historical data and forecasts aggregated from BNEF, Goldman Sachs, McKinsey, IEA, and NESO.

The huge cost of training AI models has made headlines recently. OpenAI spent over $100 million training ChatGPT 4 and Elon Musk plans to spend $3–4 billion on training xAI. However, electricity forms only a small portion of this cost. Current models require 300–1300 MWh per training run, costing around $25,000–100,000. The next suite of models could feature 100 times more parameters, increasing costs, but new model designs may counter this. DeepSeek, a Chinese startup, reportedly trained a leading model for just $6 million.

The energy required to manufacture a car is small relative to the fuel consumed over their lifetime. The same is true of AI models, which are trained once, and then run millions of times to answer questions, generate videos and the like. It is their usage (known as inference) which will stretch power grids. Answering a generative AI prompt request consumes ten times more electricity than a standard internet search. ChatGPT cost around $0.36 per query in 2023, or $700,000 per day. The cost of inference is falling, but usage will rise as AI becomes cheaper, a phenomenon known as Jevon’s paradox. As people want fast responses, inference must happen close to users, so data centres will be needed across the UK, not concentrated overseas in countries with cheaper power.

European countries use 1–5% of their electricity powering data centres, and this will grow quickly as AI servers move onto home soil. Ireland already houses data centres for large technology companies like Apple and Google and uses nearly one-fifth of its electricity powering them. The Irish system operator has imposed a moratorium on new data centres in Dublin until 2028. With the UK’s compute capacity set to increase 20-fold by 2030, electricity demand will surge. Data centres require a 24/7 supply of electricity and so firm generation and spare grid capacity will be needed, and new capacity must be clean to ensure that AI does not drive up emissions.

Annual electricity consumption from data centres in Europe’s ten largest markets in 2022 (latest year available), and the share of each country’s total national demand.

After four consecutive quarters of wind being the largest source of electricity, gas took the top spot in the 4th quarter by the slimmest of margins, producing just 0.1% more electricity than wind farms.

Britain hit a milestone of 30 GW of installed wind capacity during December. Onshore wind farm developments took off during 2024 after the ban on their construction was lifted.

Gas bucked its longer-term decline by increasing output by 15% year-on-year during the 4th quarter. This was driven by lower wind output and higher demand, both caused by cold and calm weather conditions. Demand during the 4th quarter reached a three-year high.

The rise in Britain’s wind capacity over the last 20 years.

Britain’s electricity supply mix in the fourth quarter of 2024.

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.

Britain’s electricityy system set new records in 2024, marking yet more milestones in the country’s transition to clean power. Wind and solar generation hit all-time highs, supplying nearly 30% and 5% of the nation’s electricity over the course of the year. Cross-border electricity imports also hit a record high, accounting for 15.7% of the UK’s power supply in 2024.

Carbon emissions from electricity generation fell to a new record low, averaging 121 g/kWh over the year – down from 148 g/kWh in 2023. This was driven by fossil fuel use plummeting, supplying a new low of 27% of annual electricity demand, down from 33% in 2023. Although gas sank to its lowest output over the year, it also generated all-time high outputs on 12 December, during a dunkelflaute event.

The tables below look over the past fifteen years (2009 to 2024) 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 fourth quarter of 2024, or during the 2024 calendar year. 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.

The UK made headlines around the world as the first major economy to completely phase out coal power. This marks the end of over a century of industrial history and another step on the road to net zero. But eliminating coal power is only one part of the challenge. Coal is still used in other parts of the economy, and is burned abroad to produce the things we import. It is also not the only high-carbon fossil fuel: phasing down natural gas is the next big step for the power sector, but that will be much harder.

Achieving the country’s ambitions for a clean power system by 2030 will need immense investment in supporting infrastructure to cope with more supply from variable renewables and more demand from electric vehicles, heat pumps, data centres, and the like. This quarter saw the official launch of Eastern Green Link 2, a new interconnector between Scotland and England that will reduce stress on the transmission system. However, the chronic problem of delays in securing a grid connection remains a major obstacle.

Wholesale power prices rose 6% from the previous quarter, averaging £68/MWh between July and September. However, this is 27% lower than the same period last year. Balancing prices are moving in the opposite direction, up 21% year-on-year to nearly £12/MWh. Balancing now adds one-sixth to the cost of generating electricity, three times its share over the last decade. Although constraints caused by lack of transmission capacity form the majority of balancing costs, appearances can be deceiving. New rules around charging and setting fixed balancing prices have driven this rise.

The new government continued its string of energy sector announcements, pledging £22 billion towards carbon capture and storage (CCS) projects and approving several large solar farms. The National Energy System Operator (NESO) was launched to coordinate planning and operation across electricity and gas systems. With profound changes needed in the coming years, they will face interesting times.

62 countries have committed to phase out coal power by mid-century or have already stopped using it for electricity generation. Data from Xie et al.

On 30 September at 3 PM the UK’s last coal-fired power station, Ratcliffe-on-Soar, shut down for the last time. So ended 142 years of reliance on coal. This milestone makes the UK the first G7 nation to phase out coal power, and was reported around the world. We look at how the UK has phased out coal power, the impacts of its decline, and how soon other countries are expected to follow suit.

The end of coal power in the UK

Coal powered the industrial revolution. James Watts’ steam engine transformed the modern world, and London’s Holborn Viaduct became home to the world’s first coal power station in 1882. Since 1850, we have dug up and burned some 25 billion tonnes of coal, enough to cover the entire UK 3 inches deep. For more than a century, coal was the mainstay of the UK’s power system. But it was not until the Great Smog of 1952, which saw thousands killed by coal pollution, that we started to diversify the power mix. It took the next seventy years for coal to go from producing nearly 100% of electricity to zero.

The UK’s annual electricity production from coal over the past century.

Absolute demand for coal power did not peak until the 1980s, when production of North Sea gas started rapidly expanding. The ‘dash for gas’ meant that, for the first time, gas was not only cleaner but cheaper than coal, driving the first stage of coal’s decline. Progress stalled in the 2000s, but was kickstarted again in 2013, when the Energy Act blocked new coal plants from being built, and the carbon price floor rendered existing plants less competitive. Contracts for Differences (CfD) were introduced in 2014, increasing renewable capacity by 30 GW in the ten years since, and declining electricity demand reduced the need for generation, squeezing out coal further.

Cumulative CO2 emissions from the UK’s coal-fired power generation since 1920 stand at 9.8 GtCO2, a little under China’s total CO2 emissions last year. Retirement of coal plants is responsible for one-quarter of the reduction in UK power sector CO2 emissions since 2012. It also resulted in vast improvements in air quality. Compared with the Great Smog, sulphur dioxide and black smoke emissions in London are 100 times lower today. Fears of blackouts were commonplace when coal went into decline, yet the UK’s winter blackout risk is now the lowest in four years. Yet, coal phase-out also re-shaped communities, as jobs in mining towns and at local coal plants were lost to the incoming gas and renewable energy industries. While decarbonisation brings new and consistent job growth, retraining and restructuring are essential to ensure people are not ‘left behind’.

The coal phase-out league table

Among the world’s largest economies, the UK tops the league table for coal phase out. As of 2023, the UK had reduced coal-fired generation by 98% from its peak, compared to a 63% average across the G7 group of rich nations. The UK is now the 5th country in the world to have completely phased out coal power, and the first large country to do so.[1]

Some of Europe is close behind, seeing more than a 90% reduction in coal generation. The US has seen its coal generation fall by two-thirds since 2007. Even countries that are synonymous with coal, such as South Africa and Australia, are burning 25% less than at their peak.

The global coal phase-out league table: Electricity generation from coal in 2023 relative to peak in the 25 largest coal-consuming countries.

However, this progress is overshadowed by the six large countries still increasing their coal-fired generation. Coal’s share in the global electricity generation has dropped by just two percentage points over the past four decades. As global power demand continues to rise, total coal generation is higher than ever. China now produces more coal-fired electricity than the rest of the world combined, and was responsible for 95% of new coal power construction in 2023. Its coal generation stands at 5,754 TWh/yr, more than 20 times Britain’s total electricity demand. Similarly, coal power generation in India has doubled in the last 10 years, and is now three times that of the European Union.

Electricity generation from coal in China and the rest of the world combined, over the last forty years.

After 140 years, the UK becomes just the fifth nation to phase-out coal power, showing clearly how financial incentives and regulation can combine to drive rapid decarbonisation. While this is an important step forwards, the first global stocktake, the UN’s climate progress check, affirmed that the world is far off track from limiting warming to 1.5°C. At COP29, nations must build on the global pledge to ’phase-down’ coal power with a firm commitment and timeline for phasing-out coal power across the world.

[1] Austria, Belgium, Portugal, and Sweden have all phased out coal, but only produced at most 5-15 TWh of coal-fired electricity this century, much below the UK’s peak consumption.

The UK’s end to over a century of coal power is commendable; however, it cannot rest on its laurels. Its economy is still dependent on coal, which is used in industry and heavily embedded in the things we import. Coal is also not the only fossil fuel to worry about, for the power sector still relies heavily on gas to meet demand. So what is next for the UK? Not just in reducing its coal dependency, but in delivering a net-zero power sector.

Getting to zero coal

In 2023, UK industry consumed 3 million tonnes of coal. This was twice the amount used in power stations, but it has fallen more than 10-fold in a decade, and is just 1% of what was used in the 1950s. Around half of industry’s coal consumption is in coke ovens and blast furnaces to produce steel. UK steel has been in decline for decades. In 1970, the UK was the fifth largest steel producer, but now it has fallen to 28th (behind Belgium). Only two coal-consuming blast furnaces remain in the UK at Chinese-owned British Steel’s Scunthorpe mill, following the closure of Tata Steel’s Port Talbot mill in September, but these may too close down by the end of the year. Both Tata and British Steel plan to replace their blast furnaces with electric arc furnaces, as the remaining steel industry moves towards a greener future.

The government has not yet announced a firm deadline to eliminate coal from all sectors, but its Industrial Decarbonisation Strategy will work towards this by promoting hydrogen and electrification for industry. The writing may already be on the wall, as economy-wide coal consumption in the UK has fallen by 23% per year over the past decade.

The UK’s coal consumption and exports over the last hundred years, split by sector.

The UK has partly reduced its emissions by offshoring the most energy-intensive industries, instead relying on imports. Around one-third of the UK’s carbon emissions come from imported goods. Many imported products come with a heavy coal content, as they are produced with coal-rich Chinese electricity. Carbon pricing plays a key role in decarbonisation but does not yet apply to imported products. The Carbon Border Adjustment Mechanism (CBAM), due to be introduced by 2027, is designed to ensure that embodied carbon emissions in imports are charged at the same price as domestic production, incentivising cleaner production abroad. Yet, critics of the CBAM point to higher prices for consumers and argue that it is unfair, shifting climate responsibilities onto countries with lower historical responsibility.

The elephant in the room: getting rid of gas

The Government is aiming for 100% clean power by 2030 – the most ambitious target of any G7 nation – although the enormity of this challenge has led to questions over its feasibility. The new NESO currently defines clean power as being 95% from clean sources, with the remaining 5% from unabated gas. The UK needs to reduce its share of gas from around 25% to 5% in just six years. This means bulk energy generation must rapidly wind down, but provides some leeway for gas to provide essential balancing services via flexible gas turbines.

Share of the UK’s electricity demand from fossil fuels, with the trajectory from 2024 to 2030 needed to meet the Government’s expected definition of clean power.

Phasing down gas will be much more difficult than it was for coal. Coal was replaced partly by gas, which can operate flexibly according to demand. Now, however, gas is displaced largely by wind and solar which require other technologies, like long-duration energy storage and dispatchable thermal power, to maintain flexibility as they approach high shares. Connecting electricity generated by distant renewables to the regions that use it also requires vast grid upgrades. An alternative is to fit gas plants with carbon capture technology, allowing them to operate as before but with greatly reduced emissions. Both options require considerable investment, hence the Climate Change Committee note that the costs of decarbonisation escalate rapidly as you approach 100% clean power. The challenges are made more difficult still, as demand for electricity is expected to increase by 50% by 2035, requiring more capacity and greater flexibility to cope with bigger swings.

The target of 95% clean power by 2030 requires a rapid scale up of renewables. The Government’s CfD scheme is instrumental to this transition, with the September auction delivering a record 9.6 GW of capacity. Yet, only 3.4 GW of this was new offshore wind capacity, meaning the next auction must deliver five times more capacity (16.6 GW) to meet the Government’s target for 55 GW of offshore wind by 2030. The UK’s progress towards its net-zero targets should be applauded, as should the new Government’s ambitions to accelerate future progress. Major challenges lie ahead in delivering clean power and in decarbonising the wider economy, but the UK must lead by example as it encourages other nations to follow suit at COP29.

Investment in transmission infrastructure is key in reaching net zero. Grid congestion, mainly North-South between Scotland and England, has been on the rise in GB. The wasted energy due to bottlenecks is likely to reach 5 TWh in 2024, at a cost of almost £1bn per year, and set to more than triple until 2030, as Scotland is hosting the majority of the UK’s onshore wind and has a 40 GW pipeline of new offshore wind (up from just 3 GW today).

To address the issues, National Grid Electricity Transmission (NGET) will invest £30bn by 2030 in grid infrastructure. As part of this investment, NGET and Scottish & Southern Electricity Networks (SSEN) are developing the Eastern Green Link 2 (EGL2) national interconnector project between Peterhead in Aberdeenshire and Drax in North Yorkshire, which will transport energy southwards, reducing the amount of wind that is wasted, and allowing more capacity to be sensibly added.

So far, the project has signed major contracts in February 2024 for HVDC cables and converter stations, was approved by Ofgem in August 2024, and commenced construction in September 2024. The project is planned to be fully operational in 2029. The project is developed alongside its sister projects, EGL1 and EGL3&4, which are yet to reach final decisions.

EGL2 is a 2 GW, 505 km long project, including 436 km of high voltage direct current (HVDC) cable, the longest within the UK. At an expected cost of £4.3 billion [2], it is the single largest-ever investment in electricity transmission infrastructure in Great Britain, transporting power for two million homes.

EGL2 is mostly constructed as a subsea cable under the North Sea. This has the potential benefit of easier planning and construction, as it avoids lengthy planning disputes throughout Scotland and England, which have also blighted overland projects in other countries. Any delays in construction cost money (likely £100s of millions) in continuing to curtail wind farms, as well as additional financing and legal costs.

At £8.5m per kilometre, this project is 3.5 times more expensive than the £2.5m per kilometre cost of a 400 kV AC overhead line over land (the incumbent cabling solution). However, it is much cheaper than underground cabling at £18-25m per kilometre. While this sounds expensive (£1,000 gets you only 12 cm of the way), it is the same cost per kilometre as building a flat road in the UK, but only a fraction of the new motorway (the road equivalent to HVDC lines) between Cambridge and Milton Keynes, at £62m per kilometre, or HS2 at £290m per kilometre from London to Birmingham.

Major infrastructure costs in the UK.

EGL2 is the first of 26 projects to go through Ofgem’s new Accelerated System Transformation Incentive (ASTI) framework. ASTI allows 26 new transmission projects, worth £19.7bn, to accelerate investment timelines by “up to two years” (Ofgem), streamlining the old project-by-project approach for a more holistic process.

ASTI does not solve new power stations and storage needing to wait for new wires and pylons to be built; the so-called connection queue. The reported queue is now 701 GW, likely to rise to 800 GW by the end of 2024, with similar numbers in Spain (180 GW in August 2022), Italy (337 GW in March 2024), and the US (a whopping 2.6 TW in April 2024). It is clear that most of these power plants and storage units are unlikely to be actually built. In the UK, the electricity generation from 800 GW would be quadruple of what is required in 2050. The queue is traditionally operated on a ‘first come, first serve’ basis, leading to problems for power plants in advanced projects that joined the queue later having to wait for less advanced projects to be connected (or removed) first. Consequently, some customers are now being offered connection dates in the late 2030s (Ofgem), which is not a serviceable arrangement for reaching net zero power by 2030.

In 2023, the Connections Action Plan to set out actions to improve the connections processes and timescales, resulting in 17 GW being offered an earlier grid connection, implementing the NESO’s ‘First Ready, First Connected’ process (referred to as TMO41). There are also provisions in place to remove projects from the queue that do not meet their development milestones.

It is clear that the days of piecemeal infrastructure investments are numbered. The pace needed to reach net zero electricity requires a more holistic approach to grid construction, focussing on overall optimal outcomes, rather than project-by-project cost-benefit analysis. This holistic view is also expressed by the regulatory rules set by Ofgem, and can also be seen in the wider energy system, with the transition of NESO into public ownership, the implementation of Mission Control headed by Chris Stark, and incorporation of GB Energy. If successful, it is likely that other parts of the energy sector will also be governed by increasingly holistic approaches.

[2] In 2024 currency.

The cost of generating electricity has fallen two-thirds over the last two years, but the cost of keeping the grid stable has not followed suit. Balancing costs rose 30% over the same period, partly because lack of transmission increases congestion costs, but primarily because reforms have changed how consumers pay for balancing services.

Balancing costs were stable through the 2010s, averaging 5% of the wholesale power price. They rose gradually with the share of variable renewables, as these make balancing supply and demand more complex. However, while gas and electricity prices returned to pre-crisis levels in 2023, balancing costs continued climbing to new highs. NESO forecasts they will remain above £10/MWh until 2026, five times higher than their 2010s average.

Constraint payments have contributed to this rise. Wind farms are paid to reduce output when the grid cannot handle their generation due to congestion, while gas (and other) plants elsewhere in the country are paid to increase output to compensated. Constraints accounted for three-fifths of total balancing costs so far this year, and National Grid forecasts similar levels for next year. However, constraint costs have grown steadily since 2010, so they are not the cause of last year’s sharp rise.

Left graph: Balancing prices decoupled from wholesale prices after 2023, and National Grid forecasts see them remaining high for years.

Right graph: The share of total system balancing costs that come from constraint payments.

In April 2023, Ofgem made two reforms to the way balancing services are charged. First, all balancing costs are now paid by consumers, no longer split 50:50 between consumers and producers. This doubled the cost per MWh of energy as total costs are spread over a smaller group. However, as generators no longer pay for balancing, these savings could (in theory) be passed to consumers. Overall bills should remain unaffected, or may even fall as this change levels the playing field for smaller distributed and community generation projects.

The cost of balancing the electricity system as a share of wholesale electricity price (generation plus balancing).

Secondly, spot pricing was replaced with fixed charges across each half-year to increase transparency and reduce volatility on consumer bills. Charges are calculated 9 months in advance, based on a financial model forecasting wholesale prices 18 months ahead. This model expected wholesale prices hit record highs through to 2023, remaining above £150/MWh. In reality, prices fell sharply during 2023, reaching £64/MWh in 2024. As a result, NESO has overcharged for balancing services over the last year.

NESO estimated it held an £800m surplus as of April. This over-recovery of balancing charges will be returned to consumers over the coming years. NESO expects to return £270m during 2025/26, lowering balancing costs to £9/MWh. Ofgem will change how balancing costs are calculated from next year, shortening the notice period to reduce forecast errors.