Table of Contents
Summary
The UK is not on track to meet the target of decarbonised electricity production by 2030 or Net Zero by 2050. The UK’s relative success in switching to renewable sources has been aided by the switch from coal to gas, the offshoring of industry and reduced electricity demand. These levers cannot be pulled a second time.
Electricity in the UK costs more than in the US, East Asia and many European countries. This discourages businesses from investing in manufacturing and industry, and will crimp growth in both high-tech sectors such as AI and traditional energy-intensive industries.
This will also make the transition to Net Zero harder by discouraging electrification. A part of this is due to significant market failures in the pricing model for intermittent renewables.
Existing projections for hitting net zero by 2050, such as those from the National Grid and the Climate Change Committee, assume low (c. 1.5%) economic growth. This assumption is unlikely to hold, but even on the current pathway, meeting this demand primarily through building additional wind farms will incur high costs due to transmission, storage, distribution and grid balancing costs.
The solution is firm power. This will reduce the cost of electricity and ensure reliable, continuous supply, while supporting the green transition.
A new government should develop a firm power strategy for the UK. This should include:
Large Nuclear: the Government should aim to have built or begun constructing 8-10 additional gigawatt-scale nuclear plants, with a total capacity of over 200 TWh/year, between now and 2040. To achieve this, the Government should empower GB Nuclear, fast-track reactor design approval, begin multi-plant construction programmes with standardised reactors based on existing designs, and exempt nuclear plant construction on existing or former nuclear sites from as many environmental impact assessment requirements as possible, as Spain has recently done for renewable energy projects.
In its first term, the Government should take the final investment decision for Sizewell C, agree a contract for the development of Wylfa, and make a plan for two new large reactors.
The Challenge
One of the biggest constraints on growth and productivity in the UK is a lack of affordable, reliable, green sources of energy. This has contributed to industrial stagnation. In the last two decades, electricity prices have grown by 210%, outpacing wages and general inflation. Energy costs in the UK are higher than in the US, East Asia, and many European countries.
Combined with obstructive planning laws and an already degraded industrial base, these high prices are an effective veto on any industrial strategy, constraining the UK’s economic options. High electricity prices have reduced investment in the UK. Evidence shows that electricity prices matter for foreign direct investment (FDI), and over time, the UK’s energy-intensive industries have seen depressed production. The poor performance of Britain’s manufacturing can be traced back to the high cost of electricity, a historically unfavourable tax regime, and, more recently, the negative effects of planning bottlenecks.
The UK was the first major economy to halve its emissions (between 1990 and 2022), but it has been playing the emissions reduction game on easy mode. Reduction has resulted in large part from the replacement of coal by natural gas, and increasingly renewables, in the electricity generation mix, and also electricity demand reduction - including as a result of offshoring manufacturing. Demand has fallen since 2008, and peak demand has likewise declined from 406.46TW to 2005 to just 309.98TW in 2023. This has made the integration of intermittent renewable energy sources easier, since falling peak demand lowers the risk of grid failure.
Even this limited progress, however, has come at a high and growing economic cost. In 1997 UK industrial electricity costs averaged 7.93 pence per kilowatt-hour (in 2022 prices). By 2022 prices were 18.95 p/kwh (£189.50/MWh), a 138% increase in real terms. Much of this cost growth occurred before the war in Ukraine: by 2019, prices were 12.59 p/kwh (in 2022 prices), a 58% increase on the 1997 level.
After taxes, the UK has the third highest energy prices in the set of 25 countries that report their data to the International Energy Agency (2022), almost 30% above the average European price. In 2019, prices were over 66% above the European median.
The era of playing on easy mode is over. To achieve further progress on decarbonisation, households will switch to electric vehicles and heat pumps and industry will switch from natural gas to electricity – these changes will lead to an increase in electricity demand.
An incoming Government will want to improve the UK’s sluggish growth rate. A quickly growing UK economy will add a substantial load to the grid, even if progress on decarbonisation is weak.
Industries of the future, such as AI, will further increase electricity demand, as will any reshoring of traditional energy-intensive industries. Data centres plus Bitcoin mining consumed 460TWh globally in 2022: the IEA predicts that this will more than double, to 1000TWh, by 2026, with nearly all new demand coming from data centres, especially those dedicated to AI, which is more computationally intensive than traditional computing.
In Ireland, data centres are forecast to take up one-third of national electricity demand by 2026. In 2022 in the US, grid planners forecast load growth at a modest 2.6% annual growth rate for the next 5 years. By 2023, an $630 billion investment explosion in data centres and manufacturing had increased the forecast annual growth rate to 4.7%.
In the UK, the National Grid Electric System Operator (ESO) estimates that data centres could represent up to 6 per cent of UK electricity demand by 2030, up from around 1 per cent today – an increase in energy demand from 4.8 terawatt hours (TWh) in 2023 to 19.6k TWh in 2030. These forecasts are pessimistic about potential load growth, in the light of what other grid operators are now projecting.
To sum up, in the last 14 years the Government has overseen decarbonisation in the context of:
Falling electricity demand
A weak economy characterised by growing manufacturing imports, low investment, and a negative current account balance.
The option to switch from one form of high-emission fossil fuel (coal) to another (lower-emission natural gas).
Whereas the next Government will be aiming to progress towards to Net Zero in the context of:
Rising electricity demand
A strong economy, high investment, and improved industrial competitiveness
A near-completed coal-to-gas switch.
The Opportunity
The UK could address the above challenges with firm power. Firm power refers to a reliable, available-at-all times energy supply. Clean firm power takes longer to build than wind and solar, but is cheaper on a full-system basis, and the power it generates is more economically valuable due to not suffering from intermittency. Recent modelling by Carbon Free Europe shows that the most cost-effective path to net zero for the UK involves building 61GW of nuclear by 2050, due to reduced requirements for grid balancing and lower transmission costs.
Firm power would lead to significant economic benefits for the UK, including:
Powering the AI revolution: data centres for cloud compute, as well as supercomputers, require large amounts of reliable energy, for training and running AI models. Currently, the UK is heavily dependent on the Big 3 compute providers (all American companies), and the cost of compute is likely to rise as AI demand rises. The UK is already investing in sovereign compute capacity, and new supercomputers, but not being able to meet energy demands will hinder AI development and growth.
Powering green industry: if the UK hopes to build green technologies, this will require an investment in UK manufacturing capacity not seen for many decades. Many forms of heavy industry, including factories, benefit from firm power, and businesses are more likely to invest if electricity is cheap and continuous energy supply is guaranteed. Many industrial processes ideally operate 24/7 and face high opportunity costs even if paid to temporarily consume less by the grid operator at times of low renewable production at peak hours. Advanced modular reactors (AMRs) are potentially well placed to support industrial decarbonisation, due to their smaller size and potential for lower construction cost. In addition to this, the production of key future energy fuels like hydrogen or sustainable aviation fuel benefits from a reliable source of energy for secure supply and to be economically viable.
Providing cheaper household energy: since 2022, British households have felt the impact of higher energy costs. Reducing the cost of living is likely to be a key priority for the new government. Many households face higher energy demand than before, due to an increase in working from home, this could rise further if UK households buy more electric vehicles and air conditioning units. Furthermore, consumers are conscious of the high cost of climate-friendly options, such as installing heat pumps, and may expect state financial support for these options. Firm power can help address this in the longer term, though the benefits will take time to filter through to ordinary households.
Wind and solar come with significant economic downsides. Their outputs are uncontrollable and weather-dependent, which drives up grid balancing costs and increases the need for backup power such as batteries or gas peaker plants. Since the same weather conditions typically prevail at most wind farms in a region, the marginal value of wind production rapidly goes to zero or below when the wind is blowing. Lastly, the best wind speeds are available offshore, but farms’ distance from major population centres increases transmission costs.
Firm power, by contrast, is reliably available on demand. France and Norway, which both export significant firm power in the form of nuclear and hydro, are typically able to command much higher prices for their electricity exports than countries with high intermittent renewable penetration such as Germany, Denmark and the UK. UK firm power could allow the UK to benefit, rather than lose out from, European energy trading.
Plan of Action
The new government should aim to have built, or begun building, 8-10 additional gigawatt-scale nuclear plants, with a total capacity of over 200 TWh/year, between now and 2040. This will supply around 50% of the UK’s electricity demand and would allow for a rapid phase-out of gas. In 2023, electricity demand was 310 TWh, but we expect demand to increase for the reasons outlined earlier.
Currently, nuclear power provides just 48 TWh annual electricity in the UK, about 15% of electricity consumption. Building 10 large nuclear power stations would 5x this capacity, which could be further supplemented by private investment in small modular reactors (SMRs), subject to technological advances and regulatory approval of SMRs.
To deliver on this vision for Great British Nuclear, the Secretary of State for Energy Security & Net Zero should, in the first 1-3 months:
Empower GB Nuclear.
GBN should have a high degree of autonomy, similar to that of ARIA, including control over the funds required to buy sites, exemption from Freedom of Information requests, and exemption from the civil service pay framework.
Allocate an approximate annual budget of £300-500 million, with multi-year budget flexibility (to account for the lumpy nature of site procurement).
Work with Ofgem and other bodies to:
Fast-track the reactor design approval process, to accommodate GW-scale proven designs, such as the APR-1400, and new SMRs coming to market. This could include automatic approval of nuclear reactor designs which are approved in jurisdictions with similar regulatory systems, such as the EU and US.
Rapidly review from which regulations nuclear plant construction should be exempt. Alongside this, the government should review how the Office for Nuclear Regulation should be reorganised and decision-making strengthened to ensure the mistakes of Hinkley C and Sizewell B are not repeated
Take the final investment decision for Sizewell C, agree to a contract for the development of Wylfa, and make a plan for two new large reactors.
Work with the Department for Levelling Up, Housing & Communities, and relevant regulatory agencies, to reduce approval timelines to 2 years (compared to Sizewell’s 10 year process):
Introduce a fast-track planning approval process for nuclear power stations.
Introduce a waiver and/or change to the environmental impact assessment requirements for new nuclear power stations, particularly those built on existing sites, where grid connections are already available.
Allow reactor design approval and planning applications to take place in parallel.
In the following 3-6 months, GB Nuclear, should:
Identify industrial partners for new nuclear fleets.
One option could be to begin negotiations with French state-owned EDF to build a fleet of EPR2 reactors. These are simpler versions of the original EPR reactor designed for Hinkley C and planned for Sizewell. EDF has now abandoned this original EPR design and all their projects in France—such as at Penly, Normandy—will use the EPR2.
Another option is to begin negotiations with KEPCO in South Korea, to build a fleet of APR-1400 reactors, beginning at Wylfa on Anglesey. This would be a good site for KEPCO’s simple reactor design. KEPCO has a strong record of rapid construction, and proven ability to build a highly reliable fleet with very high capacity factors and minimal maintenance downtime.
Work with industry and other parts of government to solve potential bottlenecks in:
Talent: ensure that foreign designers, engineering teams, and their families can access required visa pathways, and train UK civil servants, regulators and builders with the relevant skills.
Supply chain: bring together the nuclear industry and defence industry to identify supply chain bottlenecks for nuclear components and opportunities for domestic advanced manufacturing.
Political opposition: work with councils and civil society to communicate the benefits of nuclear, particularly in terms of energy costs and carbon emissions.
Commit to funding a fleet (at least 4x units) of the winner of the SMR design competition. This is likely to be the Rolls-Royce “UK SMR”. In the medium-long term, SMRs are likely to be privately financed and built largely for the exclusive needs of the most energy-intensive industries. At least one final investment decision for SMRs should be taken in the first term.
Create the conditions for new Advanced Modular Reactors to be developed within the UK by:
Developing a market shaping mechanism for Advanced Modular Reactors
Review private wiring arrangements to enable low-cost PPAs for onsite SMR or AMR power production.
Figure 1: Civil Nuclear Sites in the UK
Budget
The cost of building nuclear reactors varies, but power plant construction is very expensive and often exceeds budget estimates. The UK, in particular, has a history of projects significantly surpassing their original budgets. For instance, the UK’s Hinkley Point C costs 4.8x more than South Korea’s nuclear programme per unit of energy production.
A single large nuclear reactor can cost around £10-15 billion (Hinkley C, which is at the more expensive end of the scale, includes two reactors and is projected to cost over £30 billion). If the UK can capitalise on the efficiencies of South Korea’s Kepco and associated construction firms, it might be able to bring the cost down to around £10 billion per reactor.
A rough estimate for the cost of building 10x large nuclear power plants, each with 2 large nuclear reactors, is around £200 billion at today's prices. If the reactors are built between 2024-2040, this works out at around £10-15 billion per year. The majority of the costs are in construction, which happen at a later stage in the process.
For context, the CCC estimates that the cumulative investments for reaching Net Zero from 2020 to 2050 would be £1.3 trillion. The CCC estimate (balanced pathway) related to power generation between 2020 and 2050 is £331 billion. When factoring in the long average lifespan of nuclear power plants, and assistance from private investors, the procurement of 10 reactors can be justified on financial grounds.
FAQs
Gigawhatts?
This briefing uses two similar but different measures which are commonly used without clear definitions in academic papers. A watt measures power, like the flow rate of water from a tap, while a watt-hour measures total energy, akin to the amount of water dispensed over time. Power peaks are measured in watts as they represent instantaneous moments of electricity supply.
Although generators are described in terms of watts, their actual energy output varies. For instance, a 1.6GW wind farm typically produces only 5.6 terawatt-hours (TWh) of electricity yearly at a 40% capacity factor, because the wind doesn’t blow all the time, compared to a nuclear plant with the same capacity that might produce 12.6 TWh at a 90% capacity factor. For context, the UK used 266 TWh of electricity and had a total electricity demand of 310 TWh in 2023.
How does firm power affect electricity markets?
The benefits of firm power are evident in modern electricity markets, where electricity trades in half-hourly segments. Lower-cost generation sources like wind and solar, which have nearly zero marginal costs, are prioritised to save money for consumers. This ordering, called the merit order, places thermal plants at a disadvantage because they require fuel to operate.
This system makes firm and intermittent power sources competitive rather than complementary. Firm power is often misunderstood in media as either consistently running "baseload" power or as backup for unreliable wind and solar, yet both descriptions cannot simultaneously be true.
From an investor's perspective, particularly for gas or nuclear plants, large initial investments and, in the case of gas plants, ongoing fuel costs must be recouped through electricity sales. However, the prevalence of intermittent sources reduces their operation time due to their lower position in the merit order, threatening their economic viability. This is particularly critical for nuclear plants with high upfront costs. The merit order fails to account for the differing contributions of each generation type to grid stability.
Electricity is most valuable when it is demanded. Excess supply can lead to negative or zero value. Half-hourly trading segments reflect real-time electricity market values, which differ greatly from end-user prices that include transmission, distribution, and subsidy costs. Negative wholesale prices indicate surplus production, often due to the unpredictable output of wind and solar. This has led to an increase in subsidies as these sources often generate power when demand is low, leading to more frequent negative pricing and a widening gap between market prices and the prices renewable producers receive.
Why have electricity prices gone up?
The long-term rise in electricity prices is an international trend that predates the turmoil in global gas markets caused by Russia’s war in Ukraine. In comparative terms, the UK’s competitiveness challenge is somewhat specific to electricity. In 2022, UK industrial gas costs were the fourth lowest in the IEA’s collected data from 25 member countries, but industrial electricity costs were the third highest. For households, the same picture emerges: UK domestic consumers pay a relatively low price for gas, but high prices for electricity. Industrial electricity prices rose steadily from 2008 to 2020 despite flat industrial gas costs over the same time period.
The long-term trend of rising electricity costs is in part due to the policy choice to subsidise intermittent renewable generators, rather than trends in our regional gas market. Direct subsidies primarily consist of levies under the Renewable Obligation and Contracts for Difference frameworks. Indirect subsidies consist of the growth in grid balancing and transmission costs, plus some fraction of the increase in per megawatt-hour costs at firm power plants where capacity factors have decreased due to the arrival of subsidised intermittent renewables on the grid, plus the costs of the Capacity Market, where the government procures backup capacity to see the country through supply crunches. While subsidies for renewables help to decarbonise the grid, they can also lead to higher electricity costs for consumers, due to the intermittency problem.
The problem of large indirect subsidies was recognized in Professor Dieter Helm’s 2017 government-commissioned Cost of Energy Review, which proposed “equivalent firm power” auction as a replacement for the traditional merit order basis of electricity auctions. This framework would have forced wind power generators to internalise the externalities they currently inflict on bill-payers, and provoked a lobbyist backlash. It was subsequently dropped.
Taken together, the OBR forecasts £11.1 billion of direct environmental levy costs for 2023/24, across renewables obligation, contracts for difference, the capacity market, and the green gas levy. This does not include grid balancing (£2.85 billion in 2023), nor the additional transmission costs linked to the growth of generation offshore or in remote areas (at least another £3 billion), nor the increases in firm power costs due to lowered capacity factors. Even the direct environmental levy costs, however, sum to £82.2 per MWh generated in 2023, assuming that the OBR’s forecast for the year is correct. Total TNUOS revenue was £4.1 billion in 2023/24, up from £2.1 billion in 2013. The cost of subsidy per MWh has fluctuated but generally risen over time, alongside the growth in intermittent renewable generation.
All this comes before an additional estimated £100-140 billion in spending on grid upgrades out to 2050. Network costs (transmission and distribution, plus balancing) on bills have already risen by 51% in just three years since April 2021, and now constitute almost 25% of household electricity bills.
What is wrong with existing projections?
Existing projections, such as those from the Electric System Operator (ESO) and Climate Change Committee (CCC), are based on unrealistic assumptions about UK population growth, GDP growth and changes in electricity demand. The ESO’s “Consumer Transformation” scenario, for instance, envisages electricity supply of 910 TWh in 2050, out of 1239 TWh of total energy – a near 30% reduction in total energy supply. This 910 TWh of electricity supply services just 550 TWh of total electricity consumption.
In other words, the ESO envisages that after 26 years of economic and population growth, plus the complete electrification of road transport, residential heating, and industrial processes, electricity consumption increases by just 100% from today’s levels. Offshore and onshore wind, in this scenario, supplies 665 TWh of this electricity, up from around 80 TWh today.
Figure 2: A Visual Summary of the ESO’s “Consumer Transformation” Scenario.
As seen in figure 2, electricity supply levels are very high, almost 3x current supply. Wind contributes almost 7x more electricity than nuclear power.
The future path of prices is inherently uncertain. Certain key technologies, such as large-scale multi-year energy storage, simply do not yet not exist and their eventual costs remain unknown. For instance, The ESO envisions, hydrogen storage in salt caverns or depleted oil fields as a key technology, but its modelling of the quantity of storage required is a huge underestimate that does not take into account the possibility of multiple years of below-average wind speeds, followed by a dunkelflaute in a period of high demand. A recent Royal Society report highlights that the storage required is likely to be closer to 123 TWh, compared to the ESO’s estimate of just 12TWh.
The apparent contradiction of higher electricity demand alongside lower total energy consumption rests partly on the higher efficiency of electric vehicles and heat pumps, which produce far less waste heat compared to ICE cars and gas boilers. The modelling assumes that the higher conversion efficiency (up to 3x) of these electricity-powered products should enable large reductions in final energy demand.
This assumption is perfectly reasonable on the face of it, but may potentially be undermined by the lower useful-energy-return-on-useful-energy-invested of the future system. If more energy is required simply to produce the wind, e-fuel, and storage-based system of the future, as at least some modelling suggests, some or all of this apparent efficiency gain will be illusory. While this energy consumed in system production will largely take place abroad (since the U.K is a substantial net importer of wind turbines and solar panels), this energy cost will inevitably reflect itself in the cost of the products themselves, absent massive producer state subsidies.
Another flaw in the assumption of higher efficiency reducing demand is the existence of rebound effects, which are well documented in the academic literature. UK household data indicates that insulation increases household welfare but does not, after four years, reduce energy demand at all: households simply use the savings to buy more heating and run their houses hotter. For this reason, therefore, we should not necessarily expect large demand reductions even if heat pumps become cost-effective and widely adopted through deep retrofits, or if the government successfully incentivizes the installation of triple glazing and more insulation.
Nor is the ESO’s analysis of the growth of high-electricity demand sources credible. It forecasts that data centre demand could reach as much as 30 TWh by 2050, up from around 3-5 TWh today, with a wide credible interval: data quality for data centre electricity consumption is notoriously poor in many countries. Even at the top end of the ESO’s forecast range, however, data centre consumption is still only around 5-7% of the 550-670 TWh of projected 2050 electricity demand that most models project.
In countries with more robust data collection, however, forecast growth is much higher. EirGrid, for instance, who collect higher-quality data on current data centre electricity usage, forecasts that data centre consumption will constitute 23% of Ireland’s entire electricity demand by 2029 in their central case. Between 2015 and 2020 Irish data centre electricity demand grew up by 144%. The Danish Grid forecasts similar demand levels.
Why not just build SMRs?
There is huge medium-term potential for SMRs, but the sector is still relatively immature and the first few SMRs the UK builds will almost inevitably be very expensive per MWh with delayed construction timescales. Large cost reductions and improvements in SMR build times may not be felt until the mid-2040s. If the UK is to make a success of SMRs, this will require a commitment to build fleets of at least eight per SMR design. Meanwhile, China and South Korea have demonstrated that it is possible to build fleets of large (GW-scale) nuclear reactors at coal-competitive costs today. The Government should support investment in SMR development while pursuing a radical plan for traditional nuclear.
Rian Chad Whitton is a writer and analyst for the U.S. political risk company Bismarck Analysis, and a former market analyst at ABI Research. He writes primarily about energy, manufacturing, and automation. You can find him on X and Linkedin, and his personal writing at Doctor Syn.
Tone Langengen is a senior policy advisor at the Toby Blair Institute. She is an expert in net-zero policy and strategy. Her work highlights the importance of practical policy solutions that address climate change. Prior to joining TBI, Tone worked in the UK civil service on various net-zero policy areas such as heat-and-transport decarbonisation and green growth. In addition, she worked in the Cabinet Office where she helped deliver the response to the Covid-19 pandemic.