70 years ago, on 17^th October 1956, the late Queen Elizabeth II pulled the lever that unleashed the nuclear age. For the first time, homes received electricity from nuclear power. At Calder Hall, civil nuclear power was a reality. And it was delivering energy to homes and businesses across Great Britain.

Barely three years after Dwight Eisenhower had spoken of his desire for atomic energy to be harnessed for good as ‘atoms for peace’, British scientists and engineers had made it a reality.

Over the subsequent decades, nuclear power in Great Britain expanded. By the mid-1990s, nuclear power would make up a quarter of Britain’s electricity.

Now it’s 12%. We haven’t built any new reactors since 1995, and construction times have risen, and costs are astronomical.

But countries around the world are expanding their nuclear power capacity. A global nuclear revolution is underway, and Great Britain cannot be left behind.

When I was Minister for Nuclear during the last Conservative Government, I saw the excitement and potential within the industry at the new opportunities sweeping the world.

I was proud to put the first spade in the ground at Sizewell C, launch GB Nuclear, the Small Modular Reactor competition and secure Advanced Nuclear fuel production in the UK.

We were making huge strides. But the pace has slowed. If Britain is serious about embracing new nuclear power, we need to break down the barriers. Cost and delivery difficulties need to be addressed. Onward’s work gets to the heart of this challenge.

That means learning from our experiences here in Britain and looking overseas where nuclear is being delivered faster and cheaper. It means embracing the potential of SMRs alongside large-scale generation as part of a diverse nuclear fleet. And it means getting the incentives right so that developers, investors, and government are laser-focused on delivery.

The prize is enormous. Clean, reliable power. Our energy security strengthened. High-skilled jobs created and the UK a destination for investment and innovation.

Seventy years after Calder Hall, Britain should once again have the ambition to lead the world. We know how to build it; we just need to get better at delivering it.

Andrew Bowie MP

Shadow Secretary of State for Energy

Introduction

Brian George isn’t a household name, but Britain owes him a debt of gratitude. He was the project director of Sizewell B, the UK’s last completed nuclear power station.

Sizewell B was built for the Central Electricity Generating Board, a public corporation, and started generating power in 1995. Construction took less than seven years, and was delivered at a cost of £5300/kW in 2025 money, about 35% of the projected construction cost for Hinkley Point C.[1]

A 2025 interview with Brian George revealed the agency he was given to get things done.[2] In one instance, his controls and instrumentation supplier was unwilling to supply him before another client. Brian George sacked them, got on the Concorde, and flew to the USA to see Westinghouse to negotiate a new agreement. On a one-page contract, he struck a deal offering them a £10m bonus – £100,000 for meeting each of 100 key dates, with nothing if the installations were 8 weeks late. All of the deadlines were met.

The UK is facing a capacity crunch in terms of its ability to generate reliable electricity. Firm generation capacity (generation capacity excluding wind and solar) has fallen by 37% in the last fifteen years.[3] The country is leaning on an ageing group of gas, nuclear and biomass power stations in the winter months, and is increasingly reliant on interconnectors to neighbouring countries to provide power at times of scarcity.

Nuclear power can provide Britain with clean and reliable electricity generation at scale, but Britain and many other Western nations have been unable to deliver on time and budget. Hinkley Point C was originally scheduled to start delivering power at the end of 2025, but remains unfinished and significantly over budget.[4] Whilst the overspend has been borne by state owned enterprises in France and China, the follow-on project at Sizewell C places much more risk on the British government and billpayer. A project for small modular reactors has been proposed at Wylfa, and is likely to be highly reliant on state funding too.

The British state is starting to recognise the scale of the problem. The Nuclear Regulatory Review 2025, led by John Fingleton, proposed a radical reform of the regulatory landscape, and has support across the political spectrum. The Fingleton Review has opened the door to better delivery, but now the country needs a new generation of nuclear leadership, that is empowered and incentivised to deliver projects on time and budget.

This paper will:

• Explore the dynamics driving cost overruns in the UK and the West
• Make the case for small modular reactors as an important part of the nuclear capacity mix
• Recommend three deployment models for future UK nuclear projects, improving delivery incentives and the chances of successful project delivery

Brian George and Sizewell B

In 2025, thirty years after starting operations, Sizewell B ran at 99% of its maximum potential output, supplying 3.2% of the UK’s electricity.[5] This reliable source of power is now scheduled to continue running until 2055, helping power Britain with clean electricity for at least sixty years.[6]

Sizewell B has run at high load factors for thirty years

Figure 1: Sizewell B Annual Load Factor 1996-2025

Source: World Nuclear Association.[7]

Sizewell B was not preordained to be a successful project. The British nuclear industry had been weakened by very poor delivery of several advanced gas-cooled reactors (AGRs) from the 1960s to 1980s, and opted to build a new type of reactor. Whilst the Sizewell B design was based on existing reactor technology, built in Missouri and Kansas, it was the first pressurised water reactor (PWR) to be built in the UK, meaning the design was new to the UK supply chain. In addition, major modifications had to be made for the UK market, further increasing design novelty and construction risk. These included additional backup safety systems and a secondary containment structure to meet UK regulatory requirements.[8]

What had changed for the better was the delivery model and a much more active role from a publicly owned utility.[9] Most of Britain’s prior nuclear projects had been built by competing consortia of engineering firms, which joined together to supply different elements of a power station. Typically this consisted of a boiler maker, a turbine-alternator manufacturer, and a civil engineering firm, combining their skills and balance sheets. Once the project was complete, the power station would be handed over to the Central Electricity Generating Board (CEGB) or South of Scotland Electricity Board (SSEB) for operations.[10]

George recounted his earlier career, working as part of an engineering consortium that built the Wylfa A power station. He was unimpressed by the project management discipline and limited authority for the project manager under the consortium model.

Sizewell B was different.

Instead of outsourcing delivery, the CEGB would take a central role in designing the plant and managing its construction. In turn, George was given a huge amount of responsibility – claiming that “there had never been a project where the project director was given such power”.[11] George was able to pick much of his own team, and drew on his own experience as a welder to make the plant design easier to build. His team’s alterations increased the diameter of the containment vessel by ten feet, giving the construction teams more space to work.

The great tragedy of Sizewell B was that it remained a one-off. Having achieved a miraculous feat of cost-effective engineering, plans to replicate the design slowly crumbled away. In 1979, there had been government ambition for building ten such pressurised water reactors.[12] By the time the first concrete was poured at Sizewell B in 1988, there were plans for three more identical plants at Hinkley Point, Wylfa, and an additional plant at Sizewell. None of the three were built.[13]

The economic case for new nuclear capacity had been undermined by cheap North Sea gas and major improvements to the efficiency of gas power stations. The newly privatised electricity industry built out a large fleet of power stations in the 1990s ‘dash for gas’, leaving the industry with a saturated power market.[14]

Instead of building a fleet of new reactors, Britain underwent a long hiatus in nuclear construction, with a twenty three year gap between the commissioning of Sizewell B and first nuclear island concrete at Hinkley Point C.[15] Along a different branch of history, the UK would now have a sizeable fleet of reactors delivering clean, affordable electricity for decades ahead. This vision can be recovered, but only if the UK can re-learn how to build nuclear power stations on time and budget.

The need for firm power – and new nuclear power stations

Britain is facing a capacity crunch in terms of firm power generation capacity, defined as capacity that can meet peak demand with a high degree of reliability.  Whilst total generation capacity has increased by nearly 30 GW over the last twenty years, firm generation capacity has fallen by 24 GW, driven by the closure of Britain’s coal fleet and nuclear decommissioning.[16]

The UK has lost firm generation capacity

Figure 2: UK electricity generation capacity 1998 to 2025, by category (GW)

Source: Onward analysis. Department for Energy Security & Net Zero (DESNZ)[17]

Electricity supply and demand have to match in real time. Large mismatches can push the grid’s frequency outside of its safe operating range, risking the stability of the electricity system. Whilst wind and solar are valuable fuel saving technologies, incremental capacity contributes very little to reliable electricity supply.[18] Solar output declines precipitously in the winter months (when British electricity consumption is at its highest) and wind generation suffers from correlated lulls that can last for multiple days.

The National Energy System Operator provides de-rating factors for different technologies ahead of annual capacity market auctions, which ensure that Britain has enough firm capacity to meet demand. Each technology is ‘de-rated’ as a proportion of its maximum output, indicating how much it contributes to reliable supply. The contribution from incremental wind and solar capacity is minimal.

Some generation technologies are more reliable than others

Figure 3: Technology specific de-rating factors (%)

Source: National Energy System Operator (NESO)[19]

If the UK is to continue making progress on decarbonisation, it will need to electrify major emitting sectors such as transportation and heating buildings, which make up around half of territorial emissions.[20] The electrification of heating is a particular challenge for policy makers, as it is likely to exacerbate an existing winter skew to electricity consumption, with highly correlated demand during cold spells.

The recent Onward paper “Firm Foundations” argued for a diversified electricity mix of wind, nuclear, gas and solar to reduce the costs of the electricity system, and ensure that the UK has enough firm generation capacity to meet demand, without overreliance on interconnector flows from neighbouring countries.[21]

From a climate perspective, the UK will struggle to convince consumers to electrify their heating if its electricity system cannot reliably deliver when it is most urgently needed. The current government’s ‘Clean Power 2030’ policy requires 35 GW of unabated gas to remain on the system, but the requirement for firm capacity does not magically disappear after 2030. In 2040, the National Energy System Operator anticipates 51-63 GW of firm capacity, across a range of different generation technologies.[22]

Unfortunately, Britain faces significant headwinds to its firm power capacity, thanks to an ageing group of gas and nuclear power stations.

An ageing gas fleet

Gas generation became a major force in British electricity generation from the early 1990s. A combination of improved gas turbine technology, abundant North Sea gas and privatisation of electricity markets created the “dash for gas”, a major build out of efficient combined cycle gas power stations.

The concentrated build out of gas power stations in the 1990s and early 2000s has left the UK with a large cohort of older gas plants. Over 60% of the UK’s major gas power station capacity was commissioned over twenty years ago.[23]

The majority of UK gas generation capacity was commissioned over twenty years ago

Figure 4: UKgas power station capacity (MW) by commissioning year, 1990 to 2026

Source: Onward analysis. Department for Energy Security & Net Zero (DESNZ)[24]

The Department for Energy Security and Net Zero (DESNZ) assumes operating lives of 25 years for gas power stations, though life extensions should be possible. A 2025 paper published by DESNZ suggests that combined-cycle gas power stations can achieve five year life extensions at modest costs by replacing and refurbishing parts of the gas turbine, steam turbine and wider plant.[25] Repowering power stations for 10-25 years beyond the original design intent may be plausible in some instances. It is assumed to cost much more than a five year life extension (£545/kW at 2024 prices) requiring the replacement of all above ground equipment, leaving only the foundations in place.

Given the build times of recent nuclear projects, extending the life of the existing gas fleet and adding new gas capacity will be necessary, buying time for new nuclear capacity to come online.

An ageing nuclear fleet

Britain has five operational nuclear power stations, totalling 5.9 GW of capacity.

Four out of the five power stations (totalling 4.7 GW) are advanced gas-cooled reactors (AGRs) and are currently scheduled to end operations by March 2030.[26] Whilst small life extensions may be possible, these four stations have already exceeded their expected operating lives.[27]

Figure 5: Operational nuclear power stations in the UK

Source: World Nuclear Association.[28]

The UK’s only operational pressurised water reactor, Sizewell B, (1.2 GW) has negotiated a refurbishment and life extension that would keep the power station operating until 2055.[29] Two new power stations totalling 6.5GW (Hinkley Point C and Sizewell C) are under construction. The graph below assumes that each of their first reactors come online in 2030 and 2039 respectively.

UK nuclear capacity is expected to decline over the next ten years

Figure 6: Historic and expected nuclear power capacity in the UK (MWe, 1980 – 2040)

Source: Onward analysis, World Nuclear Association.[30]

The timing of the UK’s firm power capacity crunch is ominous. Just as the delivery of reliable electricity has become critical to AI and wider electrification, the UK is falling short.

Re-discovering the ability to build nuclear in a cost competitive fashion is critical for continued progress on decarbonisation and the resilience of the UK economy. Analyses of lifecycle emissions suggest that nuclear and wind power have the lowest emissions intensity of all major generation technologies.[31] Building a large nuclear fleet, alongside renewables, would also help diversify the UK’s energy mix away from gas, which continues to occupy a major role in electricity generation as well as in Britain’s heating systems.

If the country can start delivering nuclear projects on time and budget, then the UK can become a world leader in the delivery of affordable, reliable and clean electricity.

The nuclear cost problem

The cost problem in the nuclear industry is driven by the cost and time it takes to build new power stations. Overhead costs associated with running a nuclear power station are relatively low per MWh of generation, as are the variable costs of fuel.

The capital cost of building new nuclear projects is typically broken down into two components. Overnight construction costs refer to the cost of building the power station as if it were built ‘overnight’, which excludes the cost of finance during the build period. Financing costs then arise due to the time gap between the start of construction and the point at which the power station begins generating electricity. Rising interest rates make lengthy construction timelines particularly costly.

The charts below demonstrate how construction costs and delivery timelines in the UK have deteriorated since the success of Sizewell B. Hinkley C is yet to finish and Sizewell C has only recently taken its final investment decision (FID), thus the cost projections run the risk of further increases.

UK nuclear construction cost expectations have risen materially since Sizewell B

Figure 7: Construction cost estimates for three UK nuclear projects (2025 £/kW)

Source: Onward analysis, David Newbery, Department for BEIS, National Audit Office.[32]

UK nuclear construction schedules have lengthened since Sizewell B

Figure 8: Construction time estimates for three UK nuclear projects (years)

Source: Royal Academy of Engineering, Department for BEIS, National Audit Office.[33]

These cost and time overrun risks are becoming increasingly important to British billpayers, as they are taking on greater exposure to construction performance.

Hinkley Point C was financed under a thirty five year fixed-price Contract for Difference (CfD). This means that cost and time overruns are largely borne via lower returns to the project owners, rather than being incurred by billpayers. Ownership lies with Électricité de France (EDF) and China General Nuclear Power Group (CGN), companies owned by the French and Chinese states respectively.[34]

Sizewell C is being built under a Regulated Asset Base (RAB) model, where billpayers are exposed to more of the risk from rising construction costs. Moreover, the bulk of the capital for the project has been provided by the British State.[35]

The path to lower electricity costs from nuclear power lies not with financial engineering, but with better delivery incentives, lower build costs and faster construction timelines. If the UK can deliver nuclear projects within a lower and more predictable cost and time envelope, then the ‘nuclear premium’ for financing costs will also fall, and a lower cost electricity system will follow.[36]

Why have costs increased – and how can the UK improve?

The costs and duration of building nuclear power stations has increased throughout the West. The chart below compares nuclear construction times for three western countries (France, USA and the UK) to three East Asian countries. (China, Japan and South Korea)

China, Japan and the Republic of Korea have built nuclear projects at speed

Figure 9: Median nuclear reactor construction duration by completion year for six countries

Source: Power Reactor Information System Database (IAEA).[37]

France, the USA and the UK have all struggled with nuclear projects started in the 21st Century. The European Pressurised Reactor (EPR) at Flamanville (France) took seventeen years to build.[38] The twin AP1000s at Vogtle (Georgia, USA) took a decade, and the VC Summer plants in South Carolina halted construction in 2017, after Westinghouse (the primary contractor) went bankrupt.[39] Construction at Hinkley Point C in the UK is currently estimated to take about twelve years, around 80% longer than Sizewell B.[40]

By contrast, China’s last five completed reactors have an average construction time of less than six years.[41] The United Arab Emirates (UAE), a newcomer to nuclear power, was able to build four reactors at Barakah with an average build time of eight years, helped by the strength of the majority state-owned South Korean nuclear industry.[42] The UAE now has 90% of the UK’s nuclear capacity, despite Britain having a near sixty year head start.[43]

There are two major causal categories that have driven up build times and costs in the UK.

1. A scale problem, encompassing atrophied supply chains, lack of standardised designs and limited accrual of reactor building experience.
2. Poor incentives in the British nuclear industry.

Atrophied supply chains

First pour of nuclear island concrete at Hinkley Point C occurred in 2018. This represents a hiatus in new build projects of twenty three years since Sizewell B started commercial operations in 1995.[44] Such a lengthy time gap meant that the UK’s skills base in nuclear construction had eroded by the time it came to build Hinkley Point C.

By contrast, Sizewell B (first structural concrete in 1988) benefited from a supply chain that was still intact, after four reactors across Heysham B and Torness which were connected to the grid around the same time.[45] A 1985 report on the construction of Torness lamented that not all of the workforce could be recruited from local labour, with workers travelling “from as far as Edinburgh and Berwick-on-Tweed” suggesting a suitable labour force existed within only a 35 mile radius of the Torness site.[46]

Other countries have also suffered from major time gaps and supply chain erosion. Finland clocked up nearly twenty five years between the completion of Loviisa 2 and the start of Olkiluoto 3.[47] Even France, with its 63GW nuclear fleet, endured an eight year gap between the grid connection of Civaux 2 and the construction start of Flamanville 3.[48]

In 2010, The Royal Academy of Engineering published “Nuclear Lessons Learned”, an investigation designed to gather learnings from current and recent nuclear build projects. Learnings from the Olkiluoto 3 project in Finland noted the change in the supply chain environment since the 1970s. Reactor vendors had lost in-house design, project management and manufacturing expertise, with a much greater reliance on subcontractors.[49]

The ongoing construction of Hinkley Point C has helped revitalise the UK’s domestic nuclear supply chain, but manufacturing companies and subcontractors need visibility of future newbuild projects if they are to retain this skillset. This was recognised by the UK government, albeit in expensive fashion. The Department for Energy Security and Net Zero (DESNZ) ended up investing £5 billion into Sizewell C, before it reached Final Investment Decision (FID).[50] This allowed Sizewell C to start site enabling works in 2024, and make use of the skills, experience and supply chain accrued from Hinkley Point C.

Lack of standardised, repeated designs

Failure to commit to a standardised, repeated reactor design has been a consistent theme throughout the UK’s history of nuclear deployment. The civil Magnox programme built under the consortia model consisted of nine projects and eighteen reactors (1956-71) that were designed and built by five different consortium groups.[51] Consortium groups used different designs and planned reactor power output varied from 123MWe at Bradwell to 490 MWe at Wylfa, the final Magnox project.[52]

The AGR programme consisted of seven power stations and fourteen reactors (1965-1988) and initially fared little better when it came to repetition and standardisation of design. The first five power stations were built by three different consortium groups, each developing their own designs based on an earlier 33MW prototype reactor built by the UK Atomic Energy Authority.[53]

The final two stations (Heysham B and Torness) started construction in 1980 and were the fastest builds of the AGR programme.[54] The final two power stations were “largely repeat designs”, with changes for revised safety standards (particularly seismic tolerance) and site-specific requirements.[55]

UK nuclear construction timelines recovered after three very difficult AGR projects

Figure 10: UK nuclear power station construction duration (years) by start year

Source: Onward analysis, Power Reactor Information System Database (IAEA).[56]

The considerable design variation in past British nuclear projects contrasts sharply with French activities in the 1970s and 1980s. France built 34 pressurised water reactors of c. 900 MW each, across nine different sites, based on a similar design. The average construction time was just five and a half years.[57] There is good evidence that standardisation helps reduce costs as well as improve construction timelines. A 2012 analysis of French reactor cost data by Lina Escobar Rangel and François Lévêque found evidence of a learning curve within the same size and type of reactor.[58]

It is noteworthy that both the UK and France have struggled with the construction of EPRs, at Hinkley Point and Flamanville respectively, despite both countries’ previous reactors having been built reasonably effectively. Whilst the UK AGR programme suffered three very difficult AGR builds at Dungeness, Hartlepool and Heysham A, the final two AGR sites at Heysham B and Torness were built in around eight years, followed by the success of Sizewell B, built in less than seven.[59] The French finished the 1450 MW reactors at Civaux in nine years.[60] Whilst a large gap in nuclear construction might explain some of the difficulty, data from China suggests that building First of a Kind (FOAK) designs is inherently difficult, even with a strong domestic nuclear industry.

China built two EPRs at Taishan, and four AP1000s (a pressurised water reactor designed by Westinghouse) at Sanmen and Haiyang. Much of the AP1000’s content has since been localised under the CAP1000 which are now being deployed at scale. The graph below breaks out the EPR and AP1000 construction times (in red) vs. other reactors deployed in China.

Even China has struggled when it comes to building novel reactors for the first time

Figure 11: China nuclear reactor construction duration (years) by completion year

Source: Power Reactor Information System Database (IAEA) [61]

The six reactors in red (four AP1000s and two EPRs) took nearly nine years to complete on average. The rest of the Chinese nuclear builds have averaged about five and a half years.[62] Finland, France, China and the UK have all struggled to build the EPR at speed.

Finland, France, China and the UK have struggled to build the EPR quickly

Figure 12: Construction time (years) for nuclear projects building European Pressurised Reactors

Source: Power Reactor Information System Database (IAEA), National Audit Office.[63]

In theory, the UK might have benefitted from learnings in Finland and France. However, the EPR design was substantially modified for the UK market. The control and instrumentation protection systems used at Flamanville had to be enhanced, adding a further analogue backup control system to satisfy the UK regulator, increasing project costs by hundreds of millions of pounds.[64] In total, EPR design adaptations for the British market are argued to have required 7000 changes, requiring 35% more steel and 25% more concrete.[65]

The Sizewell C project should benefit from the repetition of the design at Hinkley Point C. Around 85% of the above ground design replicates Hinkley Point C, giving Sizewell C a high degree of cost certainty over nearly 60% of its total cost estimate.[66] The concern for the UK is that even if repetition and replication is the correct strategy, it may have been applied to an inherently difficult reactor design.

The UK is the only country to have started EPR builds at multiple sites. The French have declined to repeat Flamanville 3, and are instead planning to build a much-simplified version of the EPR design (the EPR 2), with plans to build six new reactors.[67] China has not built any more EPRs since Taishan 1 & 2, and a recent paper found that they were the most expensive per kW of any Chinese nuclear new build this century.[68]

Limited retention of construction experience

Constructing large nuclear power stations is a high-stakes test of engineering, construction and project management expertise. The ability of teams of humans to learn from experience and drive future productivity improvement is an important element of successful nuclear construction. Lessons can be learned and harnessed for the future, assuming there are similar projects to repeat in the pipeline, and there is an organisation that can create a ‘corporate memory’ to retain them.

The UK’s historic model of engineering consortia, responsible for the build out of the Magnox programme and most of the AGR fleet, wasn’t suited to accruing experience or learnings. Employees would be seconded from member companies to work for a consortium, and would have had more expertise in manufacturing processes rather than construction or project management.[69] On-site leadership could be diffuse, with supervision at the level of customer, consortium and individual contractor.[70]

Consolidation of the consortia into the National Nuclear Corporation (NNC) in 1973 marked a major change in the structure of the UK’s nuclear supply chain and approach to nuclear project management.

The contractual basis for the final two AGRs, Heysham B and Torness, differed from earlier AGR projects. The NNC focussed on managing the nuclear island, whilst the CEGB and SSEB respectively maintained overall project leadership and managed the remaining contracts.[71]

The construction of Heysham B and Torness in around eight years was impressive in the context of the AGR programme. The decision was taken to use the design of the AGRs with the better construction track records, Hinkley B and Hunterston B, which averaged around nine years for construction.

However, Heysham B and Torness had to contend with a decade of safety advancements since the earlier AGRs. They were built to withstand a one in ten-thousand year earthquake and incorporated secondary shutdown systems to improve safety.[72] The cable support steelwork at the earlier Hunterston project weighed 500 tonnes, but this had escalated to 3500 tonnes in the construction of Torness.[73]

The two power stations were largely able to rise to the extra challenges. There were significant innovations in management processes, with the introduction of a rigorous quality assurance programme, formal procedures to minimise design changes, and innovative contract structures. These featured bonus payments for meeting key deadlines as well as cash flow penalties that encouraged suppliers to raise problems early rather than relying on litigation further down the line.[74]

Innovation was not restricted to project management. Heysham B and Torness were the first to make use of off-site construction for large components of the build, taking inspiration from North Sea infrastructure, which recognised the advantages of moving construction work away from a constrained build site.[75] Major elements of the project, such as thousand tonne liner roof assemblies, were lifted into place.[76] The two power stations were by no means perfect, but they were delivered within about 10% of the original cost estimate, with the four reactors averaging about ten months behind schedule.[77]

The CEGB (and its successor, Nuclear Electric) took on even more responsibility for Sizewell B than it had for Heysham B and Torness. Originally a joint leadership group with the NNC was considered, but instead around a hundred key staff members of the NNC moved to direct employment under the CEGB.[78] The project group led by the CEGB compiled the safety case, decided the station layout and acted as architect-engineer, managing procurement, the construction site and commissioning.[79]

The key takeaway is that standardising the design isn’t enough, on its own, to improve construction productivity. The humans assembling nuclear power stations have to discover new ways of working and retain the learnings from one site to the next. Berthélemy & Rangel’s 2013 analysis of French and US nuclear builds noted that ‘learning by doing’ spillovers only take place when the same design of reactor is built by the same architect-engineer (the organisation that supervises the construction and manages different project suppliers).[80]

Vertically integrated utilities that take delivery responsibilities ‘in house’ are better placed to capture learning effects, and also have stronger incentives to do so, especially if they have a pipeline of multiple nuclear projects ahead. This may explain why large nuclear fleets often have a strong association with state owned companies. Few private utilities have the required scale to build a series of large scale reactors and thus have limited ability to retain learnings and apply them to future projects.

In Canada, Ontario Power Generation (OPG) leads the Darlington SMR project as the licence holder and operator while GE Hitachi Nuclear Energy supplies the technology.  The nuclear site licence, the corporate memory, the safety case, and the operator competence all reside in the same publicly owned entity that is spending the public money. The technology selection was made by OPG, who will bear the responsibility and consequences itself. OPG’s first unit is estimated at CAD 6.1 billion, with costs for the second, third and fourth units declining gradually to around CAD 4.1 billion for the fourth – roughly 33% cheaper than the first, with the plan to build one unit and learn lessons before building the next three as an overlapping programme.[81]

Incentives: the nature of risk

Britain’s historic nuclear projects have all entailed major capital commitments, with multi-year build timelines. The capital cost and duration of projects creates significant financial and development risk, which must be allocated properly to create the right alignment of incentives.

Under the Magnox programme, the five construction consortia were awarded turnkey projects to build power stations on behalf of their utility customers, the CEGB and SSEB. This involved the consortia taking on financial risk, as contracts were awarded on a fixed price basis, with adjustments for inflation and site-specific design changes.[82] Whilst this approach worked well for the relatively simple Magnox reactors, the AGR programme would highlight that the major financial risk that apparently lay with a consortium could be rapidly transferred to the utility customer.

The construction of the Dungeness B AGR was an engineering and financial disaster, with the two reactors averaging nearly nineteen years to build.[83] The reactors then ran at abysmal load factors, around 50% across their operating lives.[84] Construction started in 1965, but by 1969, the original consortium tasked with building the project had gone bust, incurring losses for its member companies and leaving the project completion to the CEGB and a different consortium.[85] This ultimately transferred risk onto the CEGB and the British taxpayer.

The decision for the SSEB and CEGB to take on a greater share of the delivery responsibility for Torness, Heysham B and Sizewell B was driven by the increased scale, complexity and financial risk associated with nuclear construction, alongside a supply chain that had been weakened by a decade long hiatus in new orders.[86] Larger reactor power outputs, fewer new build projects and greater capital intensity changed the structure of the UK nuclear industry.

The Magnox plants had been relatively simple, with much of the cost envelope reflecting conventional plant and equipment, making the turnkey fixed priced contract structure an appropriate balance of risk.[87] Two key changes altered the balance for the AGR programme.

Firstly, demands for the generating plant to work at high temperatures and thus higher thermal efficiencies increased the proportion of engineering at the technical frontier. Secondly, evolving safety requirements complicated the design of the plant. Evidence suggests that the NNC had been prepared to bid for Heysham B and Torness on a firm price turnkey basis, but the boards of the CEGB and SSEB recognised the risk mitigation of a fixed price contract was only theoretical in nature. NNC was poorly capitalised in relation to the contract values, and so offered no real insurance against a major cost overrun.[88]

The model for Hinkley Point C looks very different from a risk exposure perspective. The CfD contract is effectively a fixed power price agreement for 35 years. Construction and overrun risk has been left to EDF and CGN, but this in turn has reduced the incentives for arms of the British state to act as a good customer for the project. The Fingleton Review noted £700m of expenditure on fish protection systems, and hundreds of millions in additional costs due to the insistence on an additional analogue backup control system relative to the Flamanville reference design.[89] Repeated cost overruns have made the chances of signing an equivalent contract structure for large build projects very remote indeed.

The risk allocation for the follow-on project, Sizewell C has been structured very differently, with significantly greater risk exposure to the British taxpayer and billpayer. The government will provide 44.9% of the equity for the project, and 85.5% to 88% of the debt during construction.[90] Billpayers will also pay levies during the construction phase, before power is generated. In essence, much of the funding has come from the state and is secured by billpayers, but government control of the project has been intentionally limited. The rationale, according to the National Audit Office, is to benefit from shared ownership with other investors, “seeking to avoid governance weaknesses that have beset other mega-projects.”[91] The UK has abrogated itself of delivery responsibility whilst retaining the bulk of the financial risk.

Financial incentives for on-time and on-budget delivery do exist for Sizewell C but are relatively weak. The mechanism is a risk/reward sharing mechanism, with half of any savings below the Lower Regulatory Threshold being added to the Regulated Asset Base (RAB). Equally, only half of any overspend up to the Higher Regulatory Threshold is added to the RAB.[92] The National Audit Office has estimated that nominal rates of return for construction are 12-13% assuming a 9.5 year construction period, but only fall to a range of 10.8% – 11.4% at the Higher Regulatory Threshold, where construction is assumed to take over 13 years.[93] Private investors have the greatest risk exposure to ‘tail-end’ scenarios above the Higher Regulatory Threshold.  The National Audit Office have expressed scepticism over the incentive structure.

“The extent to which investors will be incentivised to control project costs in the way DESNZ assumes is unclear.” [94]

Incentives: the lack of competitive tension

The end position of the financial arrangements governing Sizewell C reflect the lack of competitive tension in the British nuclear industry. The failure of prospective large scale nuclear projects at Bradwell, Wylfa and Moorside limited the potential for alternative future nuclear deployment.[95] In addition, many of the UK’s potential nuclear sites remain under the ownership of EDF or the Nuclear Decommissioning Authority.[96]

Competitive tension has also been lost in the UK’s SMR technology selection process. The first steps of the SMR competition were taken in March 2016, to gather evidence and gauge market interest from prospective technology developers, utilities and investors.[97] The formal process launched in July 2023, with down-selection to six technologies by October 2023, reducing to just four providers by September 2024.[98] It was widely expected within the industry that two technologies would be selected by Great British Nuclear, and a public tender from 2025 confirms that the competition was looking to select “up to two technology providers for the Small Modular Reactor (SMR) programme”.[99] In June 2025, Rolls Royce SMR alone was selected as the preferred bidder to partner Great British Energy – Nuclear (GBE-N) in developing SMRs.[100] In November 2025, the Wylfa site on Anglesey was confirmed as the host site for the UK’s first SMRs.[101]

Selecting a single technology instead of two was a missed opportunity. Incentives would have been better aligned if two technologies had been selected for first of a kind deployment, with the technology proving itself as more cost effective and faster to deploy then winning the much larger market opportunity for fleet level deployment.

Incentives: The Fingleton Review

As well as the incentive problems created by different contract structures, the Nuclear Regulatory Review 2025, led by John Fingleton, highlighted a myriad of wider misaligned incentives within the UK nuclear industry.[102] Four key areas impacting the civil nuclear industry are highlighted below:

• Lack of challenge between dutyholders and the safety regulator: The Fingleton Review highlighted a culture of risk aversion in applying the ‘As Low As Reasonably Practicable’ (ALARP) principle to satisfy the requirements of the Health and Safety at Work etc. Act 1974. Whilst project developers can challenge the decisions of the Office for Nuclear Regulation (ONR), challenge is rare, as developers risk incurring delay or reputational damage.[103] The latter is of particular concern to new entrants to the nuclear sector. Over time, the lack of incentive to push back on further efforts to mitigate risk creates a ratchet effect, as precedent and regulatory expectations escalate towards ever increasing conservatism.
• The risk of judicial review: The Fingleton Review notes that Hinkley Point C and Sizewell C have been subject to seven different legal challenges, six of which related to planning or environmental questions.[104] The incentives to create legal challenges are strengthened by the UK’s application of the Aarhus Convention, which caps the cost liability for claimants at £5,000 for individuals and £10,000 for organisations.[105] As well as injecting the risk of delay and increasing uncertainty, widespread judicial review of environmental and planning decisions increases the incentives for developers to take an extremely risk averse approach to environmental and planning applications. This adds extra costs, as designs and applications become ‘gold-plated’ to reduce the risk of future legal challenge.
• The ONR’s revenue model: The ONR operates under a cost recovery model, with little in the way of core funding.[106] Operational and pass through costs are allocated back to the industry via direct work recording – or billing for each piece of work.[107] Not only does this create cost uncertainty for new entrants to the market, but also limits the scope for the ONR to invest in hiring and training ahead of demand growth. It is plausible that the revenue model also incentivises the creation of more regulatory engagement. The Fingleton Review also noted a wider tendency for wider regulatory assessment to be outsourced to consultants, by both dutyholders and regulators. The report argued that this has sustained a consultancy ecosystem that “thrives on complexity” and “weakens direct regulatory scrutiny”.[108]
• Public procurement rules: Wider government policy may also create poorly aligned incentives in the nuclear sector. The Fingleton Review noted that public procurement rules could constrain the weighting that can be allocated to selecting the best technology.[109]

In March 2026, the then Chancellor of the Exchequer, Rachel Reeves, wrote to the nuclear industry, stressing that nuclear power was a strategic priority for the United Kingdom.[110] The letter recognised the findings of the Fingleton Review, and asked companies to review “internal processes, incentives and performance management” approaches “to identify where complexity, delay or uncertainty can be reduced”.

The letter was a positive intervention, stressing the importance of delivery speed to the UK’s energy ambitions. However, the cultural implementation of Fingleton will require more than a report or a letter. The culture of the UK nuclear industry will only change when the individuals leading British nuclear projects see the risk of accepting disproportionate design changes as a bigger threat to their careers and pay packets than an awkward conversation with a regulatory body.

Why the focus on SMRs?

The UK’s Advanced Nuclear Framework describes SMRs as smaller versions of existing light water reactors, featuring a greater proportion of factory fabrication and up to 5% enriched uranium fuel.[111] The power cutoff is drawn at 500 MWe, which is a little larger than many global definitions that typically draw a line at 300 MWe per unit.[112]

The UK uses the term Advanced Modular Reactor (AMR) to cover reactors that use novel fuels and coolants, whether designed for electricity generation or industrial heat applications. The distinction between SMR and AMR is important in terms of operational risk and plant duration. Light water reactors make up the vast majority of the global nuclear fleet, and have thousands of cumulative reactor-years of operating experience. Light water reactors in the US are being licensed out to 80 years of operating life and the US nuclear fleet runs at a capacity factor of over 90%.[113]

Debates about SMRs mainly focus on the economics of constructing smaller reactor sizes, not the stability of the underlying light water reactor technology.

SMR scepticism and economies of scale

Enthusiasm for SMRs should be measured. The UK, alongside many western nations that have struggled with new build projects, should not use the promise of SMRs to gloss over the difficulties they have experienced with large nuclear projects.

As early as 1953, Admiral Hyman G. Rickover (the pioneer of nuclear propulsion for the US Navy) warned of the dangers of being lulled into a false sense of security by ‘paper reactors’ that promised features like simplicity, low costs, small sizes, and off-the-shelf components. By contrast, practical reactors that were actually being built were often behind schedule, complicated, expensive, large and heavy.[114]

The conventional industry view (and associated scepticism of SMRs) assumes that there are large scaling benefits to increasing the size of reactors, which explains the historic increase in reactor power output across the world.

Under the conventional worldview, costs for foundations and shielding do not fall proportionately with a smaller reactor size, leading to higher construction costs per kW of capacity. Similarly, largely fixed costs in operations and maintenance would be recovered over a smaller annual power output, driving up the unit cost of electricity.

SMR sceptics would point to the track record of SMRs that have already been built, such as the 150 MWe high temperature gas reactor at Shidao Bay in China, which took about eleven years between start of construction and commercial operations.[115] The most significant western project that has started construction is OPG’s Darlington project in Canada, which is looking to deploy four 300 MW boiling water reactors.

SMR optimism and economies of volume

The optimistic case for SMRs assumes that the economies of volume (benefits from repetition) can overcome the dis-economies of scale associated with smaller reactor sizes.

There is some debate about the extent of realised economies of scale in the nuclear industry. Tony Roulstone has argued that real-world scaling benefits may be overstated, as theoretical benefits from increases in size may be offset by longer build durations (due to increased reactor complexity) or additional safety requirements for larger reactors.[116]

French nuclear costs show evidence of learning within the same size and type of reactor

Figure 13: Overnight construction costs for French nuclear power stations (€ 2010/kW)

Source: Cour de Comptes data from Lina Escobar Rangel, François Lévêque (2012)[117]

Economies of volume are based on Wright’s Law, which derives from aircraft manufacturing. In 1936, Theodore Wright noted that the average labour cost per aircraft fell by about 20% for each doubling of aircraft production.[118] Under this worldview, nuclear costs could fall by building a greater number of smaller units, benefitting from repetition in manufacturing, assembly and construction.

The implicit bet being made by SMR developers is that the economies of volume can overcome the diseconomies of scale. For this approach to work, the entire production and assembly process must be changed to maximise volume benefits. Building a much smaller reactor in the traditional manner of large scale builds risks incurring the scaling headwind without maximising the tailwind from learning.

A recent interview from Tony Roulstone suggested three areas to maximise volume benefits:[119]

1. Radical standardisation: The design must be frozen, with all non-essential changes between builds removed. This reduces the costs of on-site design changes and regulatory approvals for subsequent builds.
2. Modularisation and off-site manufacturing: Manufacturing and assembly activity should be moved away from the construction site where possible. This increases the proportion of the plant that is built in a manufacturing environment and moves labour and quality assurance inspections away from a busy construction site.
3. Maximise production learning: Multiple sequential units should be built, with short time lags between repetitions, so the labour force can learn how to improve the assembly and installation process, without subsequently forgetting those learnings. Building many repeat units on a single site is likely to help, as would retaining the same contractors and workforce for subsequent projects.

As Tony Roulstone has argued, SMR technology providers will need an order book for their reactors to justify the up-front investment in factory production and supply chains. Order book momentum has occurred for two leading light water SMRs:

GE Vernova Hitachi BWRX 300 (300 MWe)

• Canada: One unit under construction, with plans to build three more units.[120]
• Potential projects include Poland, Tennessee and the UK.

Rolls Royce SMR (470MWe)

• UK: Commitments to deliver three initial units at Wylfa.[121]
• Czech Republic: Strategic partnership to deploy up to six units.[122]
• Sweden: Selected by Videberg Kraft as supplier for new nuclear. Planning underway for three reactors.[123]

If the arguments around the economies of standardisation, volume and modularisation work, then there are several further advantages to the SMR offering in the longer term. If the magnitude and variance of build costs and delivery timelines can be reduced, then the cost of financing projects should fall, both through lower interest rates and shorter periods of interest accrual.

Smaller project sizes would also open up nuclear to new customers that cannot afford to spend tens of billions on a capital project. This could make nuclear power financeable for large utilities, smaller countries or large technology firms, especially if global engineering firms can accrue experience building the same reactor design around the world. Smaller individual reactor sizes would also make the technology more feasible to incorporate in countries with smaller power grids.

The Rolls Royce SMR is particularly interesting, given its design output of 470 MWe, the largest SMR in the nuclear industry, and only about 25% below the power output of the fourteen AGRs built in the UK. Britain should view deploying the Rolls Royce SMR in this vein – learning how to build a fleet of domestic light water reactors cost effectively.

Simultaneously, the UK should make itself an attractive deployment location for the array of advanced modular reactors that are being developed in the United States. This is a fast-moving environment. Four microreactors achieved criticality by the 4th of July 2026, under the Reactor Pilot Programme set up by the US Department of Energy in 2025.[124] Britain’s higher electricity prices relative to the US could make the UK a more attractive place to deploy these nuclear innovations.

What would good look like?

A successful British nuclear programme is one in which power is delivered at affordable prices whilst meeting the required safety standards. Britain should be delivering ‘nth of a kind’ light water reactors at overnight construction costs of £7,500/kW or less. This must be achieved within a low variance of construction time and spending envelope (e.g. +/- 10%) so that uncertainty and cost of capital also reduce.

Three different features are proposed to help achieve the objective of affordable nuclear:

Multiple deployment pathways

The explore-exploit trade-off is a useful analogy for considering British nuclear deployment options. In a nuclear context, exploitation would be represented by committing to a large fleet build of a single design and benefitting from learning and economies of volume. Exploration would involve trying out lots of different designs and benefitting from experimentation.

Nuclear power is a difficult application of the trade-off, because high capital costs make experimentation expensive, and multiple simultaneous deployments will pressure the capacity of the UK supply chain and safety regulator. As well as the choice of reactor technologies, another variable for experimentation is the deployment and ownership model, relying on private sector deployment or a greater role for the state.

Britain should acknowledge the role of the state in large scale nuclear programmes. Britain’s own experience suggests that the construction of Torness, Heysham B and Sizewell B performed relatively well, and that publicly owned utilities (the CEGB and SSEB) played an important role. This may be because the vertically integrated utilities of the past had better in-house engineering capabilities, were better able to retain project learnings, or were better positioned to coordinate the construction of complex engineering projects.

Picking a monoculture delivery model is also risky. The later AGR builds at Torness and Heysham B benefitted from earlier experimentation, basing their design on the most successful of the first five AGR projects (Hinkley B and Hunterston) and avoiding repeating the disastrous Dungeness B. Britain should retain a commercial deployment pathway for private sector innovators, along much more competitive lines, as any successful deployment could then be copied and scaled.

This paper recommends three different deployment models.

1. A state led SMR fleet.
2. A commercial pathway for SMR/AMR projects.
3. A vendor selection process for future large scale nuclear projects.

Britain should pursue both a large scale nuclear build programme and SMRs, as the argument concerning economies of volume vs economies of scale remains contested. Gigawatt scale light water reactors also have a proven global track record of deployment and Great British Energy-Nuclear should not be tied to the SMR programme alone. In 2023, Simon Bowen (then Industry Adviser to Great British Nuclear) stressed the need for both large scale nuclear and SMRs, suggesting another two large scale sites beyond Sizewell C would be required in order to hit 24 GW of capacity by 2050.[125]

Improved delivery incentives and a cultural reset

Delivery incentives in the British nuclear industry need to improve. Not only do the financial incentives for project developers need to reward and encourage strong cost performance, but pro-growth incentives must extend throughout the wider ecosystem, encompassing the planning system, environmental regulation and nuclear regulation.

If GBE-N is to take on greater delivery responsibility, it must be able to attract the very best talent in the global industry.  The economics of nuclear power are dominated by construction and financing costs. If a project is executed cost-effectively, then there is plenty of financial room to remunerate the management teams and wider workforce.

The ONR needs the resources to invest ahead of demand, and a longer term revenue mechanism consistent with abundant and safe nuclear power. Developers and environmental regulators must have the confidence to approve projects without gold-plating applications.

Focus on fleet deployment

Learning curves do not happen automatically. Once the UK has decided upon some core reactor technologies, it needs to deploy a fleet of reactors, with minimal changes to the design and personnel involved in delivery.

The UK should consider a greater role for multiple reactor deployments at a single site, and give developers up front visibility of future build locations, so that the workforce and learnings from one project can transfer to the next as seamlessly as possible, without large time gaps that create the potential for loss of experience.

Recommendations

Recommendation 1: Ensure that eight reactors at Wylfa remains viable

The initial project at Wylfa is for three Rolls Royce SMRs, or c. 1.4 GW of power.[126] In November 2025, Lord Vallance (then Minister of State for Science, Innovation, Research and Nuclear) stated that the Wylfa site has the potential to host up to eight units.[127] Starting with three units is a logical step, given the existing transmission capacity on Anglesey is currently limited to 1.8 GW.[128]

It is vital that the option for a further five reactors on the same site is preserved. Should the initial deployment of three Rolls Royce SMR units show strong indicators of future ‘nth of a kind’ success, then the UK would welcome the potential to replicate the build over a further five units.

GBE-N should urgently clarify whether the seismic ratings of the Rolls Royce SMR will allow foundation blasting to be carried out for subsequent units if the first three reactors are already operational.

If operational SMRs would preclude further construction at the site, then blasting for all eight foundations should be carried out in advance. Wylfa is one of the best nuclear sites in Europe. It has hard bedrock, seawater cooling, and proximity to electricity demand centres in Liverpool and Manchester. The UK should ensure that it can maximise the long-term value of this important site.

Recommendation 2: Aim for a fleet of fifteen Rolls Royce SMRs, under GBE-N ownership and delivery accountability

The economics of SMRs rely on maximising the benefits of volume production. This requires repeating the same design, moving manufacturing into the factory, and minimising on-site construction activity. The cost of the first three units at Wylfa are likely to be high, with public contract disclosures indicating a c. £8.2bn forecast price for the supply stage of the technology partner contract.[129] Assuming this cost indication is consistent with three units, it implies costs of nearly £6000/kW for technology supply alone. In addition, the GBE-N commercial pipeline indicates substantial expenditure on a delivery partner for the project, early construction works and the main construction works.[130]

It is vital that GBE-N treats the deployment as a fleet programme and resists the urge to ‘stick build’ the first three reactors to demonstrate activity. Incremental units after the first three should be targeting capital costs of below £7,500/kW, and the programme must be designed in advance to achieve this.

The first three units are likely to require government funding, as the deployment has huge novelty risks. Not only is the design a first of a kind (and unfinalised), but the vendor is new to civil nuclear and the project involves novel construction methods. The British state should take on responsibility for project delivery and funding, recovering capital at project completion by selling down part of GBE-N’s ownership to external investors via a RAB structure. Recovered funding could then be recycled into subsequent units, crowding in private sector funding to a de-risked deployment model.

Delivery responsibility must lie with GBE-N, a publicly owned company, as it did for the CEGB and SSEB in the 1980s. Directly charging an arm of the British state with delivery responsibility will help drive cultural change in the nuclear industry, by forcing confrontation with disproportionate regulatory costs.

The Fingleton Review has support from across the political spectrum. Two of its key recommendations call for the Government to define the tolerability of risk in the nuclear sector and the meaning of ‘proportionality’ within the Health and Safety at Work Act.[131] The first three SMRs at Wylfa present a golden opportunity to break the ‘regulatory ratchet’ – the tendency for risk averse behavior between regulators and dutyholders that leads to higher cost over time.

If the first deployments meet success thresholds, GBE-N can also act as the ‘corporate memory’ to retain the project management learnings for subsequent units.  We suggest eleven ideas to improve the chances of a successful SMR fleet.

1. Clearly identify the individual responsible for leading the Wylfa project: GBE-N should clarify who is responsible for delivering the Wylfa project and wider programme. The project must avoid creating a diffusion of accountability between GBE-N, the SMR delivery partner and DESNZ.
2. Create a strong incentive structure for the project leadership team: The incentive structures for the Wylfa project need to motivate the leadership team to push back on unnecessary cost creep. If the project teams perform well, then they should be well remunerated. Every £1000/kW saved for the initial project is c. £1.4bn of cost savings for the UK. Establishing a collective bonus pool of £100m for strong delivery performance would be a rounding error in terms of project economics. Any incentive scheme should only pay out on project completion.
3. Ensure GBE-N has delivery accountability: Funding for the Wylfa project should only be released subject to a high level of design and contractual maturity, with HMT acting as a gatekeeper for reaching FID. From the point of FID, full funding and accountability for project delivery should sit with GBE-N, giving budget certainty for a project covering multiple spending review periods.  Poor cost and delivery performance should reduce all bonus schemes to zero, and require the project leadership to explain the overruns in person before the Public Accounts Committee.
4. Avoid rushing to final investment decision: A 2025 National Audit report on infrastructure mega-projects noted that there is often pressure on major projects to start quickly, so that progress can be announced.[132] This is a particular risk for nuclear projects, as starting a project before a design is completely finalised can lead to expensive re-work activity, driving delays and higher costs. The design must be finalised before a shovel goes into the ground.
5. Political accountability and support: The SMR programme should have clear political support from a senior government minister. A political sponsor, with a cross-government remit, would provide a clear point of escalation to help with regulation, planning or consenting issues.
6. Rapid spending authority for project leadership: The individual leading the Wylfa project will require the ability to take spending decisions quickly to allow early course correction when problems arise.A ring-fenced contingency budget should be established at the start of the project, allowing unanticipated costs to be dealt with immediately rather than waiting on central approval.
7. Pay flexibility for project leadership: GBE-N should be able to recruit the very best talent in global nuclear construction to lead the first three units at Wylfa. A derogation from public sector pay controls, agreed with HMT, would allow GBE-N to offer competitive remuneration packages to attract proven project leaders.
8. Make further deployment conditional on performance: The prospect of deploying multiple reactors after the first three units is a significant financial opportunity for the technology vendor and wider supply chain. Cost expectations should be established for the first three units, as well as ‘nth of a kind’ deployment, to ensure that deploying further units is conditional on strong execution relative to budget.
9. Remove local content requirements for the first three units: Delivering a new technology, from a new vendor, using new construction methods is already a difficult task. Removing local content requirements for the first three units would ease supply chain pressures and aid cost effective delivery. Local content requirements could be reintroduced for subsequent units if the first three are successful. This mirrors the Chinese approach to nuclear, which initially relied on western designs and construction expertise, but has gradually increased domestic content over time.[133]
10. Secure future sites in advance: GBE-N should secure the sites for the remaining SMR units in advance. If Wylfa has the capacity for eight units in total, it is likely that one or two additional sites would be required. These should be purchased in advance by GBE-N, so that site preparation work can start if the first three units are progressing to time and budget.
11. Designate the project as of Critical National Importance: The government has already made legislative changes to reduce the exposure of Nationally Significant Infrastructure Projects to judicial review.[134] A May 2026 policy paper proposed a parliamentary authorisation mechanism that would allow the Energy Secretary to determine a project as of Critical National Importance, subject to a House of Commons vote, protecting the project from judicial review.[135]

Recommendation 3: Enable private SMR and AMR deployment:

This paper has suggested that GBE-N take a much more active role as the launch partner for delivering the Rolls Royce SMR in the UK. However, the UK should also enable a pathway for private SMR deployment, with less active involvement from the state.

This approach recognises that there are major uncertainties with regards to the economics of different SMR technologies, and a more competitive deployment pathway may reveal lower cost solutions. Technological change is moving quickly, as evidenced by four microreactors in the US recently achieving criticality.[136]

The UK may have some advantages over the US in terms of securing deployment. The US has much lower cost electricity, thanks to lower gas prices and minimal carbon taxes, as well as abundant solar and onshore wind in many US states. This makes the deployment environment much more difficult for new US nuclear projects. If the UK can offer a credible deployment pathway, then many innovative firms may want to build their projects in Britain instead. Indeed, the UK may have a window to strike favourable long-term contracts with new technology providers. Innovative firms may prioritise the IP uplift from demonstrating their technology to the global market over maximising the economics of their first project.

The government has already established the Advanced Nuclear Framework to unlock privately-led nuclear projects. Subject to due diligence by DESNZ and GBE-N, eligible projects can apply to join the UK Advanced Nuclear Pipeline, which provides a statement of in-principle endorsement and unlocks engagement with DESNZ on potential revenue support, e.g. via a CfD style mechanism.[137]

Prospective applications must provide evidence of their technology and supply chain, developer capability, funding strategy, siting plans and operational plans.[138] The February 2026 report for the Advanced Nuclear Framework noted a circularity problem with respect to securing land rights. Prospective developers struggle to secure development rights to attractive sites without demonstrating to landowners they have a credible project – but access to land is a crucial part of demonstrating project credibility.[139]

To some extent nuclear sites are economically rivalrous, as they require a combination of community consent (typically highest in communities that have hosted nuclear before), suitable geology, access to cooling and existing grid infrastructure. The Fingleton Review noted that much of the nuclear estate remains under the ownership of the Nuclear Decommissioning Authority (NDA) and EDF, and recommended a process for releasing these sites.[140] GBE-N has recently completed a site report for Scotland and has been tasked with a study of land areas for deploying large-scale reactor technology, expected to report in Autumn 2026.[141]

GBE-N should be funded to acquire more legacy nuclear sites, as it did with the acquisition of land at Wylfa and Oldbury-on-Severn in 2024. NDA land would be the first priority for release, with compulsory purchase powers considered for further sites should they be required. Sites should be reserved for two future large scale nuclear projects and a fifteen unit SMR fleet, with the balance dedicated to the Advanced Nuclear Pipeline.

This would allow prospective developers to use these sites in their application to the UK Advanced Nuclear Pipeline. Sites could then be allocated to pipeline members via one of two approaches:

1. An auction process once the pipeline had reached sufficient maturity.
2. Allocated as part of a CfD negotiation or competitive allocation round, prioritising the best sites for projects which require the lowest level of subsidy.

Existing nuclear sites would be used to attract more potential developers to the pipeline, improving competitive tension in subsequent CfD negotiations. Site ownership would revert back to GBE-N if no final investment decision is taken within a set number of years. The government could also make the sites more attractive to prospective developers by reserving grid connection capacity, mirroring the prioritisation mechanisms that were proposed in March 2026 for strategic demand connections.[142] Prospective developers would remain free to source their own nuclear sites, making use of potential reforms to the Semi-Urban Population Density Criteria as suggested in the Fingleton Review.[143]

This pathway would be the competitive version of SMR and AMR deployment, using well prepared nuclear sites to help increase competitive tension and value for money for the billpayer. Projects would be privately financed, but with revenue visibility provided by a two-way CfD. The CfD mechanism is imperfect, but novel reactor technologies run the risk of operating at much lower output levels than anticipated, and it is vital that this uptime risk sits with developers and not billpayers.

The SMR and AMR pathway is Britain’s commitment to the ‘explore’ part of the ‘explore-exploit’ trade-off. It is up to developers to find ways of reducing capital costs and build times if they want to deploy successfully in the UK market and demonstrate their technology to the world.

Recommendation 4: Don’t neglect gigawatt scale reactors

The SMR hypothesis is that the economies of volume can overcome lost economies of scale. This hypothesis is unproven, and countries such as Korea and China are still able to build large light water reactors with proven track records on time and on budget.

GBE-N should run a technology selection process for large scale nuclear, seeking to mirror the down-selection process used at Barakah in the UAE. This would represent a move away from bilateral negotiations, in an effort to improve competitive tension for large reactor builds. This could be conducted after GBE-N has delivered its investigation into large scale nuclear sites, using the most promising two build sites as a reference point for vendor selection.

The focus should be on procuring the most cost effective and deliverable design, with emphasis on the construction track record of vendors and developers. There is only a short list of large light water reactor technologies that could be deployed in the UK.

• EPR or EPR2: This choice would represent a continuity bet with the UK’s existing large scale deployments, harnessing learnings from Hinkley Point C and Sizewell C. The French plan to build six EPR2 reactors, a simplified version of the original EPR design.[144]
• AP1000: Six Westinghouse AP1000 reactors have been completed in total across the USA and China, and are operating at strong load factors, averaging 89% in 2025.[145] Further units are contracted in Poland and Bulgaria.[146]
• APR1400: The APR1400 has been deployed very successfully in South Korea and the UAE. The reactor design has been subject to an IP dispute between Westinghouse and the South Korean nuclear industry in relation to export markets, which would need to be taken into consideration.[147]

Left-field candidates could include replicating the build at Sizewell B. Whilst the technology is older, it has been built before and has a strong operating track record.[148]

GBE-N should evaluate the technologies based on cost and delivery record. Particular weighting should be given to the track record of the delivery organisation that would manage the build programme, accepting that the UK would be best served by making use of teams with proven experience of large scale reactor delivery. In the case of building the AP1000 or APR1400, this would mean making use of international firms and supply chains with a proven track record of constructing those reactors.

Recommendation 5: Establish core funding for the ONR

The nuclear regulator needs to be able to invest ahead of demand, otherwise shortfalls in resources could act as a bottleneck in UK nuclear deployment. The regulator has a crucial role in assessing new designs, licensing new projects and assessing regulatory hold points on construction sites. The risks of creating a bottleneck in design assessment and construction could be solved for a relatively modest annual cost.

Annual design assessment costs are modest, but critical for UK nuclear delivery

Figure 14: Breakdown of historic fees and charges from the Office for Nuclear Regulation

Source: Onward analysis, Office for Nuclear Regulation annual reports.[149]

The current funding model limits the ability of the regulator to invest ahead of demand, risking an assessment bottleneck if key staff can’t be hired or trained ahead of time. The main problem is that most of the ONR’s funding is secured on a cost-recovery model, billing for specific engagements with limited core funding.[150] The 2025/26 Annual Report for the ONR reveals that grant funding from the Department for Work and Pensions was less than 5% of the budget for the year ahead.[151]

Administrative sponsorship of the ONR has recently moved to DESNZ, and the department should allocate a much larger core funding package.[152] This would give the regulator the necessary resources to meet growing demand, helping the ONR complete design assessments within two years and licensing decisions within a year, as per the Fingleton Review.[153] The ONR should also have the ability to carry reserves forward to future years, again helping it scale up ahead of demand.

Conclusion

Nuclear power holds enormous potential for the UK.

It can deliver national energy security, drive economic competitiveness and help fight climate change. However, this potential will not be realised if the next series of nuclear projects falls prey to another round of cost and time overruns. Billions of pounds of public money is at stake, and public appetite for nuclear technology will be sorely tested by another high profile cost overrun.

There are reasons for optimism.

The British nuclear industry has been in a difficult position before, suffering from a number of troubled projects in the 1960s and 1970s. The industry was able to respond. The delivery model evolved, with greater responsibility placed with publicly owned utilities. Project execution improved and the UK built three new power stations at Heysham B, Torness and Sizewell B, delivered effectively in terms of both construction time and cost.

The Fingleton Review has highlighted the risk aversion, procedural complexity and poor incentives within the nuclear industry. The Review provides a blueprint for regulatory simplification and improved delivery, and the UK must adopt its recommendations in full. The next step is to ensure that a new generation of project leaders are able to take advantage of a new regulatory landscape and are rewarded for driving down costs and delivering on schedule.

Many of the UK’s difficulties are shared by other Western nations, as nuclear supply chains and delivery experience have eroded, due to a hiatus in new projects. If the UK can deliver a successful SMR project and replicate the same design time and time again, then Britain can once again lead the way in delivering clean and reliable power.

[1] Sizewell B costs sourced from Newbery, D. The Cost of Finance and the Cost of Carbon: A Case Study of Britain’s only PWR (2021) Hinkley C cost estimate from National Audit Office, Sizewell C (2026) Both values adjusted to £ 2025 using UK CPI (ONS)

[2] Delivering Sizewell B: “No Project Director was given such power” – Nuclear Industry Association (July 2025)

[3] DESNZ, Digest of UK Energy Statistics, table 5.7. Calculation refers to the capacity change between 2010 and 2025 for all generation other than for wind, solar and pumped hydro.

[4] 2025 anticipated commissioning date taken from the 2018 Annual Report for NNB Generation Company (HPC) Limited. Project cost increases are documented in multiple annual reports from 2019 to 2025.

[5] 99% refers to 2025 annual load factor for Sizewell B, World Nuclear Association Reactor Database. The same source has 10.4 TWh of electricity supplied by Sizewell B in 2025, which is compared to c. 323.3 TWh of total UK electricity supply from DESNZ, Digest of UK Energy Statistics, table 5.1.

[6] Gov.uk press release: Sizewell B power plant given lifetime extension to 2055 (8th July 2025)

[7] World Nuclear Association, Nuclear Reactor Database, Sizewell B.

[8] Pages 17-18, Nuclear Lessons Learned, published by the Royal Academy of Engineering, October 2010.

[9] The Sizewell B project was started by the Central Electricity Generating Board and completed under the ownership of Nuclear Electric.

[10] Wearne, S. H., & Bird, R. H. (2016). UK Experience of Consortia Engineering for Nuclear Power Stations.

[11] Delivering Sizewell B: “No Project Director was given such power” – Nuclear Industry Association.

[12] Taylor, S. (2007). Privatisation and Financial Collapse in the Nuclear Industry (page 37)

[13] Taylor, S. (2007). Privatisation and Financial Collapse in the Nuclear Industry (page 39)

[14] Page 15, Nuclear Lessons Learned, published by the Royal Academy of Engineering, October 2010.

[15] Power Reactor Information System Database (IAEA), entries for Sizewell B and Hinkley Point C.

[16] DESNZ, Digest of UK Energy Statistics, table 5.7. Firm generation capacity change relates to all generation capacity excluding solar, wind and pumped hydro. Total generation capacity calculation re-rates wind and solar to reverse the de-rating factors applied within the table.

[17] DESNZ, Digest of UK Energy Statistics, table 5.7. Firm generation capacity change relates to all generation capacity excluding solar, wind and pumped hydro. Total generation capacity calculation re-rates wind and solar to reverse the de-rating factors applied within the table.

[18] Onward, Firm Foundations: The case for cheap and reliable power (August 2026)

[19] NESO, Electricity Capacity Report 2026 (May 2026)

[20] DESNZ, 2025 UK greenhouse gas emissions: provisional figures.

[21] Onward, Firm Foundations: The case for cheap and reliable power (August 2026)

[22] The National Energy System Operator, Future Energy Scenarios 2025 Data Workbook, Tab F11. Range refers to the sum of Base Load and Dispatchable capacity in 2040 across three scenarios.

[23] Onward analysis of gas generation capacity from DUKES table 5.11 (DESNZ).

[24] Onward analysis of gas generation capacity from DUKES table 5.11 (DESNZ).

[25] DESNZ, Electricity Generation Cost Study – Extending the Life of Existing Generation Assets (May 2025)

[26] World Nuclear Association, Nuclear Power in the United Kingdom (accessed 22/09/2026)

[27] EDF, UK Nuclear Fleet Stakeholder Update, January 2026

[28] World Nuclear Association, Nuclear Power in the United Kingdom (accessed 22/09/2026)

[29] Gov.uk press release: Sizewell B power plant given lifetime extension to 2055 (8th July 2025)

[30] World Nuclear Association, Nuclear Power in the United Kingdom (accessed 22/09/2026) Future year assumptions are for all four AGRs to cease operations at the end of 2029 and the first units at Hinkley Point C and Sizewell C start generating power in 2030 and 2039 respectively, with the second units following a year later.

[31] Our World in Data, What are the safest and cleanest sources of energy? (accessed 22/09/2026)

[32] Onward analysis, all values inflation adjusted to 2025 using UK CPI (ONS) Sizewell B costs sourced from Newbery, D. The Cost of Finance and the Cost of Carbon: A Case Study of Britain’s only PWR (2021) 2016 BEIS estimates use medium scenario for FOAK PWR. Hinkley C original estimate from National Audit Office, Hinkley Point C (2017) Hinkley C (Latest estimate) and Sizewell C estimates from National Audit Office, Sizewell C (2026)

[33] Sizewell B data from Nuclear Lessons Learned, Royal Academy of Engineering, October 2010. 2016 BEIS estimate from BEIS Electricity Generation Costs, November 2016. Hinkley C and Sizewell C estimates from National Audit Office, Sizewell C (2026) Hinkley C estimate uses average of higher and lower scenarios, Sizewell C assumes Lower Regulatory Threshold.

[34] EDF, Agreement for construction of HPC nuclear power station, October 2015.

[35] National Audit Office, Sizewell C, May 2026 (Page 40)

[36] National Audit Office, Sizewell C, May 2026 (Page 11)

[37] Power Reactor Information System Database (IAEA). US data for 2016 removed due to a long construction pause at Watts Bar 2.

[38] Power Reactor Information System Database (IAEA), entry for Flamanville 3.

[39] Power Reactor Information System Database (IAEA), entry for Vogtle 3 and World Nuclear News (May 2026)

[40] Hinkley Point C construction time taken from higher scenario, National Audit Office, Sizewell C, May 2026 (Page 28) Sizewell B construction time from Power Reactor Information System Database (IAEA), Sizewell B.

[41] Onward analysis of Power Reactor Information System Database (IAEA), entry for China.

[42] Onward analysis of Power Reactor Information System Database (IAEA), entry for the United Arab Emirates.

[43] World Nuclear Association. Assumes 5.9 GW of nuclear capacity in the UK vs. 5.3 GW in the UAE.

[44] Power Reactor Information System Database (IAEA), entry for Hinkley Point C and Sizewell B.

[45] Power Reactor Information System Database (IAEA), entry for Heysham B  and Torness.

[46] Kershaw, P.J. & Weatherseed, D.C. & Polin, J. Torness Nuclear power station: civil engineering construction, Proceedings of the Institution of Civil Engineers, Volume 78, 1985.

[47] World Nuclear Association, Nuclear Power in Finland (accessed 22/09/2026)

[48] World Nuclear Association, Nuclear Reactors in France (accessed 22/09/2026)

[49] Page 39, Nuclear Lessons Learned, published by the Royal Academy of Engineering, October 2010.

[50] National Audit Office, Sizewell C, May 2026 (Page 22)

[51] Wearne, S. H. (2015). Evolution of UK Contract Structure for Nuclear Power New Build.

[52] World Nuclear Association, Nuclear Reactors in the United Kingdom (accessed 22/09/2026)

[53] Wearne, S. H. (2015). Evolution of UK Contract Structure for Nuclear Power New Build.

[54] Power Reactor Information System Database (IAEA), entry for Heysham B  and Torness.

[55] Wearne, S. H., & Bird, R. H. (2016). UK Experience of Consortia Engineering for Nuclear Power Stations.

[56] Onward analysis of Power Reactor Information System Database (IAEA), entry for the United Kingdom. Excludes experimental reactors. Power station construction duration has been calculated using the average for each constituent reactor.

[57] Onward analysis of Power Reactor Information System Database (IAEA), entry for France.

[58] Lina Escobar Rangel, François Lévêque. Revisiting the cost escalation curse of nuclear power: New lessons from the French experience. (2012)

[59] Power Reactor Information System Database (IAEA), entry for the United Kingdom.

[60] Power Reactor Information System Database (IAEA), entry for France.

[61] Power Reactor Information System Database (IAEA), entry for China.

[62] Onward analysis of Power Reactor Information System Database (IAEA), entry for China.

[63] Power Reactor Information System Database (IAEA) for Olkiluoto 3, Flamanville 3 and Taishan (calculated using an average of the two reactors) Hinkley Point C data uses the average of higher and lower scenarios from National Audit Office, Sizewell C (2026)

[64] Nuclear Regulatory Review 2025 (Page 121)

[65] World nuclear news, EDF announces Hinkley Point C delay and rise in project cost (January 2024)

[66] National Audit Office, Sizewell C, May 2026 (Pages 4 and 29)

[67] World nuclear news, EDF estimates EPR2 programme cost at EUR72.8 billion (December 2025)

[68] Liu, He, Qiu, and Kammen, 2025, Can China break the ‘cost curse’ of nuclear power? (Page 2)

[69] Wearne, S. H., & Bird, R. H. (2016). UK Experience of Consortia Engineering for Nuclear Power Stations.

[70] Wearne, S. H., & Bird, R. H. (2016). UK Experience of Consortia Engineering for Nuclear Power Stations.

[71] Nuclear power station project management, British Nuclear Energy Society, London (1989), Paper 1.

[72] Nuclear power station project management, British Nuclear Energy Society, London (1989), Paper 6.

[73] Nuclear power station project management, British Nuclear Energy Society, London (1989), Paper 23.

[74] Nuclear power station project management, British Nuclear Energy Society, London (1989), Paper 1.

[75] Nuclear power station project management, British Nuclear Energy Society, London (1989), Paper 12.

[76] Nuclear power station project management, British Nuclear Energy Society, London (1989), Paper 12.

[77] Nuclear power station project management, British Nuclear Energy Society, London (1989), Papers 1 and 22.

[78] Nuclear Lessons Learned, published by the Royal Academy of Engineering, October 2010, Page 21.

[79] Nuclear Lessons Learned, published by the Royal Academy of Engineering, October 2010, Page 21.

[80] Michel Berthélemy, Lina Escobar Rangel. Nuclear reactors’ construction costs: The role of lead-time, standardization and technological progress. 2013.

[81] World Nuclear News, Canada’s first SMR project: How is CAD20.9 billion cost calculated? (May 2025)

[82] Wearne, S. H. (2015). Evolution of UK Contract Structure for Nuclear Power New Build, Page 2.

[83] Power Reactor Information System Database (IAEA), entry for the United Kingdom.

[84] World Nuclear Association, Dungeness B1 and Dungeness B2 (accessed 23/09/2026)

[85] Wearne, S. H. (2015). Evolution of UK Contract Structure for Nuclear Power New Build, Page 5.

[86] Nuclear power station project management, British Nuclear Energy Society, London (1989), Paper 22.

[87] Nuclear power station project management, British Nuclear Energy Society, London (1989), Paper 22.

[88] Nuclear power station project management, British Nuclear Energy Society, London (1989), Paper 22.

[89] Nuclear Regulatory Review 2025 (Pages 68 and 121)

[90] National Audit Office, Sizewell C, May 2026 (Page 40)

[91] National Audit Office, Sizewell C, May 2026 (Page 13)

[92] Centrica, Sizewell C: Regulated investment with predictable returns, July 2025, Page 9.

[93] Quoted construction internal rates of return are post-tax nominal. National Audit Office, Sizewell C, May 2026 (Page 48)

[94] National Audit Office, Sizewell C, May 2026 (Page 13)

[95] National Audit Office, Sizewell C, May 2026 (Page 17)

[96] Nuclear Regulatory Review 2025 (Page 134)

[97] DESNZ, Small Modular Reactors competition: phase one, March 2016.

[98] Great British Nuclear, Small Modular Reactors: technology selection process, July 2023.

[99] Find a tender, Great British Nuclear: Lead Financing and Structuring Advisory Services.

[100] DESNZ press release, Rolls-Royce SMR selected to build small modular nuclear reactors, 10th June 2025.

[101] DESNZ press release, North Wales to pioneer UK’s first small modular reactors, 13th November 2025.

[102] Nuclear Regulatory Review 2025 (Page 2)

[103] Nuclear Regulatory Review 2025 (Page 34)

[104] Nuclear Regulatory Review 2025 (Page 81)

[105] Nuclear Regulatory Review 2025 (Page 83)

[106] Nuclear Regulatory Review 2025 (Page 130)

[107] Office for Nuclear Regulation, Our Regulatory Charges (accessed 24/09/2026)

[108] Nuclear Regulatory Review 2025 (Page 40)

[109] Nuclear Regulatory Review 2025 (Page 32)

[110] HMT, Chancellor letter to nuclear regulators and industry (13th March 2026)

[111] DESNZ, Advanced Nuclear Framework, Glossary. (February 2026)

[112] IAEA, What are Small Modular Reactors (SMRs)?, (Accessed 24/09/2026)

[113] World Nuclear Association, Nuclear Power in the USA and EIA, Electric Power Monthly (Accessed 24/09/2026)

[114] H. G. Rickover, Memo from the 5th of June 1953.

[115] World Nuclear Association, Shidaowan HTR-PM 1, accessed 24/09/2026.

[116] Nuclear Engineering International, Economies of scale vs. economies of volume (August 2015)

[117] Cour de Comptes overnight construction cost from Appendix A: Lina Escobar Rangel, François Lévêque. Revisiting the cost escalation curse of nuclear power: New lessons from the French experience. 2012.

[118] Wright, T.P., Factors affecting the cost of airplanes, Journal of Aeronautical Sciences (1936)

[119] Notes taken from Green Giants Podcast – Episode 117: Can Nuclear Energy Scale? Tony Roulstone on SMRs, Cost & Repeatability (August 2026)

[120] OPG, Darlington SMR (Accessed 24/09/2026)

[121] Rolls Royce SMR, Rolls-Royce SMR secures contractual certainty to build Europe’s first SMR fleet (April 2026)

[122] Rolls Royce SMR, Rolls-Royce SMR secures Czech contract to deliver Small Modular Reactor Programme (April 2026)

[123] Vattenfall, Videberg Kraft selects Rolls-Royce SMR as supplier for new nuclear power in Sweden (June 2026)

[124] Reuters, Four US microreactors hit criticality milestone (July 2026)

[125] House of Commons Science and Technology Committee, Delivering Nuclear Power (18th January 2023)

[126] Great British Energy – Nuclear, UK SMR programme at Wylfa hitting target for British contracts (June 2026)

[127] UK Parliament, Small Modular Reactor Programme and Site Allocation (13th November 2025)

[128] NESO, Electricity Ten Year Statement 2025, Boundary NW1 – Ynys Mon (Page 32)

[129] Gov.uk Contract Award Notice, Small Modular Reactor Technology Partner, published 8th May 2026.

[130] Great British Energy – Nuclear Commercial Pipeline, August 2026.

[131] Nuclear Regulatory Review 2025 (Pages 57 and 62)

[132] National Audit Office, Lessons learned: Governance and decision-making on mega-projects (Page 16)

[133] Liu, He, Qiu, and Kammen, 2025, Can China break the ‘cost curse’ of nuclear power? (Pages 3-4)

[134] HM Treasury, Getting Britain Building: Reforming Judicial Review for Infrastructure (May 2026)

[135] HM Treasury, Getting Britain Building: Reforming Judicial Review for Infrastructure (May 2026)

[136] Reuters, Four US microreactors hit criticality milestone (July 2026)

[137] DESNZ, Advanced Nuclear Framework, Page 5 (February 2026)

[138] DESNZ, United Kingdom Advanced Nuclear Pipeline – Guidance and expectations for project proposers, Page 10 (March 2026)

[139] DESNZ, Advanced Nuclear Framework, Page 31 (February 2026)

[140] Nuclear Regulatory Review 2025 (Page 134)

[141] Great British Energy – Nuclear, Potential future nuclear power plant siting in Scotland (June 2026)

[142] DESNZ, Accelerating electricity network connections for strategic demand (March 2026)

[143] Nuclear Regulatory Review 2025 (Page 99)

[144] World nuclear news, EDF estimates EPR2 programme cost at EUR72.8 billion (December 2025)

[145] Onward analysis of Power Reactor Information System Database (IAEA)

[146] Westinghouse, AP1000 Pressurized Water Reactor (Accessed 24/09/2026)

[147] World Nuclear News, Westinghouse reaches agreement on IP with Korean companies (January 2025)

[148] The prospect of repeating the Sizewell B design was raised by Simon Bowen (then Industry Adviser to Great British Nuclear) at a House of Commons Science and Technology Committee on ‘Delivering nuclear power’ in January 2023.

[149] Onward analysis of Office for Nuclear Regulation Annual Reports 2017/18 to 2025/26.

[150] Nuclear Regulatory Review 2025 (Page 130)

[151] Office for Nuclear Regulation, Annual Report and Accounts 2025/26 (Page 49)

[152] Office for Nuclear Regulation, New administrative sponsorship change for ONR (July 2026)

[153] Nuclear Regulatory Review 2025 (Page 126)

The post Up and Atom: Unlocking SMRs and Large Nuclear appeared first on Onward.

Foreword

In 1977, John Hoskyns wrote the Stepping Stones report for Thatcher’s Opposition which set out the steps needed to reboot Britain’s economy. It was famous for showing that there was one fundamental problem underpinning all others: the power of the trade unions.

If a similar exercise was carried out today, the consistent stumbling block to Britain’s challenges would be our sky-high energy costs. Britain has the highest electricity prices in the developed world. This is not the result of bad luck, but a series of deliberate policy choices to prioritise an electricity grid dominated by wind and solar at any cost.

Britain faces many challenges today. We need to have a growing economy, better living standards, globally competitive manufacturing, and we want to be a power base in the industries of the future like AI and biotech. For all of these things, cheap electricity is the holy grail.

Most people accept this. However, a truth much less acknowledged is that cheap electricity is better for the environment too.

Only a tenth of the UK’s emissions come from our electricity grid. The remaining 90% come from transport, heating, and the rest of our economy. If we want those emissions to fall, then we need people to want to use electric cars and electric heating – then our priority should be to make electricity cheap.

Instead, our Net Zero legislation has forced us towards the opposite target. The Labour Government’s priority is to squeeze out every last drop of carbon from our electricity, making it even more expensive and deterring electrification. This is bad climate policy. Sending our industry overseas to more polluting countries and creating a barrier for consumers to adopt electricity at home is worse for global emissions. The simple truth is this: there is no point in having the cleanest electricity in the world, if nobody can afford to use it.

That’s why the detailed analysis in this report by Onward, Firm Foundations, comparing an electricity system dominated by wind and solar to one which prioritises cheaper power, matters.

When I became Energy Secretary in 2023, I was astonished to find that the Government had not done this work. The energy policy I had inherited was based on the promise that renewables are cheap, but when I combed through the spreadsheets that officials put in front of me to ‘prove’ this, I realised they did not have the evidence to back it up. The hidden costs that weather-dependent power creates – backup, balancing, and building extra grid – were not being properly accounted for. What the Department was missing was a full system cost.

I promptly commissioned that analysis because our energy policy should be based on facts, not ideology. However, my successor, Ed Miliband, cancelled it when he came into power.

Two years on, Onward has finished the work that I started. This is the most detailed analysis of the cost of our electricity system ever produced in British politics, whether by a think tank or the British Government. I am tremendously grateful to Ed Hezlet and Marlon Dey at Transira Energy for carrying out such important and expert work.

The findings are remarkable. The cheap power pathway saves consumers over £320 billion by 2050 – equivalent to around £540 per household per year. It would make the cost of our electricity a fifth cheaper by 2035, and almost a third cheaper by 2050 – which would be a boon for our economy and the cost of living. Our power in 2050 would still be nearly 80% clean – but the lower cost would make electrification a much more attractive choice for many more consumers.

This is not about turning our back on our duty to provide the next generation with a better environment. The Burkean contract between the living and those yet to be born is a core Conservative principle which we should never abandon. This is the case for an energy policy that works for the climate and our economy.

This much-needed report demonstrates that we can have both economic prosperity and a better environment if we make electricity cheap, let the economy grow, and make consumer choice king.

The Rt Hon Claire Coutinho MP
Shadow Secretary of State for Energy

Executive Summary

The UK’s expensive electricity is weighing on the nation. Rising bills are repressing the discretionary income of British households and high industrial electricity prices are discouraging inbound investment. This paper quantifies the logical failures that have led to high prices and how they are defeating the very reason why the costs were incurred in the first place: to meet environmental objectives. Expensive electricity is hampering the electrification of heating, transport and industrial activity, pushing progress in reducing greenhouse gas emissions ever further away.

Government policy has started to recognise that there is an electricity cost problem, but efforts to redistribute costs are mere symptom management. Instead, policymakers must engage with a major cause of high prices – an expensive power system, driven by the wider costs that come with intermittent generation sources.

Onward have commissioned an independent study to quantify the full system costs of continuing with the current policy direction, versus cost savings that can be achieved by taking a new approach. It models a power system that prioritises firm generation capacity, responding to demand, rather than forcing consumers to react to the vagaries of the British weather. This plan includes a diversified mix of nuclear, renewables and gas generation, which builds a much cheaper power system that can be used to electrify and decarbonise more of the economy.

The savings are substantial. The alternative policy pathway saves £320 billion between 2030 and 2050, and reduces system costs by 20% in 2040 versus “business as usual”. Savings are made across four major areas:

• £137 billion in network spending, thanks to a higher utilisation firm power system with supply located closer to demand
• £94 billion from lower wholesale prices, thanks to the removal of carbon taxes
• £67 billion in lower spend on balancing and ancillary services
• £22 billion across generation subsidies and the Capacity Market

Realising savings of this scale requires a shift away from the current central planning model, to a system that allocates the costs of intermittent generation to the causative generators, rather than sending a bill to the end consumer. This paper sets out an alternative policy pathway, to build a power system that allows consumers to access affordable electricity when they need it, cutting bills and increasing economic growth. In turn, cheap electricity can drive the adoption of electric vehicles and heat pumps, via consumer preference, and not state mandates. This is a win-win, for growth and the climate.

Introduction

A cruel paradox sits at the heart of Britain’s energy and climate policy.

The UK has expensive electricity, higher than its developed nation peers. In 2024, Britain had the highest industrial electricity prices of International Energy Agency member countries, and the second highest domestic prices, just behind Germany.^[1] Having made electricity some of the most expensive in the world, policy now tries to push consumers to use more of the UK’s expensive power – as electrification is the main lever to drive the decarbonisation of heating and transport.

Two logical flaws have driven the country into this position.

Firstly, the wider system costs that come with building a power system centred on intermittent generation have been overlooked. Building new transmission lines, balancing the grid and retaining a backup power system to deal with still, dark winter days all add to system costs. Those costs are charged to consumer bills, rather than being properly internalised by the generators that cause them.

Secondly, 95% decarbonisation of the power sector has been prioritised ahead of electrification. This has driven up electricity costs, making electrification more costly and less attractive than it should be.

The UK can get out of this mess by building the electricity system around a core of reliable generation capacity. The opportunity is material, with the potential for £320 billion of system cost savings from 2030 to 2050.

This approach is not compatible with a dash for Net Zero by 2050, as it retains a 23% role for gas in the electricity system of 2050. But it would reduce emissions in a way that the British public could actually get behind, rather than have forced upon them. An electric vehicle or heat pump powered by such a generation mix will reduce emissions by over 80% relative to a combustion engine or gas boiler.^[2] Cut electricity prices, and those technologies will become the rational choices for consumers.

The proposition is simple. Fix the electrical foundations first. Build a diverse generation mix around nuclear, renewables and gas that allows consumers to access affordable electricity when they need it. Cut systems costs and let consumers adopt electrification technologies on their own terms.

Electricity Costs: Escaping a doom loop

UK electricity consumption has fallen by 21% since the 2005 peak, with declines across domestic, commercial and industrial use.^[3] In other markets, weak consumption volumes might lead to lower prices and a self-correcting system. This is not the case in the UK electricity market.

Fixed costs have become more dominant, as a greater proportion of the system is financed by inflation-linked contracts, secured against consumer bills. This has been true for electricity networks since privatisation but now extends to generation assets too. As contracted costs grew faster than electricity volumes, unit prices rose. In turn, higher prices discouraged electricity use, leaving fixed costs to be recovered over fewer units of consumption. This is an inflationary feedback loop that must be broken.

Electricity prices have risen and consumption has fallen

Figure 1: UK electricity final consumption (GWh) & costs per MWh (2025 prices) 1988- 2025

Source: Onward analysis. Department for Energy Security & Net Zero (DESNZ), ONS.^[4]

Electricity Costs: Treating symptoms rather than fixing the problem

Government policy has started to recognise that there is an electricity cost problem, but the responses have treated the symptoms, not the underlying cause. Costs have been re-allocated between different groups, but the expensive underlying system has not been addressed.

• In June 2025, the Government announced the expansion of the Warm Home Discount (WHD) to a further 2.7 million households.^[5] The WHD is a £150 energy bill discount for households in receipt of means-tested benefits and is funded by a levy of around £40 on a typical dual fuel customer’s household bills, including those in receipt of the discount.^[6]
• The November 2025 Budget scrapped the Energy Company Obligation scheme (ECO) and moved 75% of domestic Renewable Obligation (RO) costs into general taxation for three years. This helped reduce the price cap just before the 2026 local elections.^[7]
• The expanded British Industry Supercharger (BIS) and the new British Industrial Competitiveness Scheme (BICS) have increased support for energy intensive businesses. Funding for the BIS is recovered via non-eligible consumer bills.^[8]
• The January 2026 Warm Homes Plan promised bill reductions via the installation of rooftop solar, heat pumps, insulation and batteries. It is funded by £15 billion of public spending.
• In July 2026, the new Prime Minister announced the removal of VAT from domestic electricity bills from the 1st of October 2026.^[9] Funding this measure will require spending cuts, higher borrowing or offsetting tax rises elsewhere.

Rather than fixing the underlying causes of the UK’s expensive electricity, policymakers are engaging in elaborate shell games. Industrial electricity costs are shifted onto households, low income households have their costs alleviated at the expense of their neighbours, and eventually costs have to be shifted on to the billpayer of last resort – the taxation system.

Similarly, encouraging consumers to adopt rooftop solar to cut their bills is partly financial engineering, allowing households to avoid electricity levies that are then left with their neighbours. It is akin to standing up in a football stadium to get a better view – the strategy will not scale effectively. If rooftop solar is pursued at significant scale, it is likely that suppliers or policymakers will respond, by cutting export tariff rates, or increasing standing charges on bills. The UK must end its approach of managing symptoms, and start to fix the underlying cause.

Electricity Costs: An expensive electricity system

The real cause is that the UK is building an expensive electricity system. One that requires massive investment in not just generation assets, but transmission, storage and interconnectors too.

Much has occurred to disguise this reality.  Expensive subsidy schemes for early renewable generators, alongside carbon taxes, drove cost increases in the 2010s. Extreme gas price spikes were responsible for rising bills in 2022 and 2023. But a new set of inflationary pressures are just starting to reveal themselves: rising costs to pay for transmission, balancing and underutilised gas power stations. This final group of costs can be largely attributed to a system built around intermittent generation.

Electricity bills have been driven higher by carbon taxes, generation levies and network costs – as well as high gas prices

Figure 2: GB household electricity costs (£ p.a. nominal) assuming 3.1 MWh of consumption.

Source: Onward analysis of data from electricitybills.uk^[10]

These inflationary pressures could be downplayed when the costs of new intermittent generation appeared to be declining, inexorably, year after year. Contract-for-difference (CfD) strike prices awarded for offshore wind fell by 72% between 2014 and 2019, but have since risen materially.^[11]

Offshore wind CfD strike prices have started to rise

Figure 3: Historic CfD strike prices for fixed bottom offshore wind (£2025/MWh)

Source: Onward analysis. Department for Energy Security & Net Zero (DESNZ), ONS.^[12]

At the start of the 21^st century, the UK had 76 GW of generation capacity that fulfilled average consumption of 38 GW and met winter peak load of about 58 GW.^[16] This was a system of firm generation capacity that could supply electricity on demand, composed of coal, gas and nuclear power. The system was built with a sensible buffer of spare capacity to reliably meet peak load in winter, allowing for station outages and the risk of particularly cold winters.

Policymakers must adapt to the inescapable reality that the bet on becoming the “Saudi Arabia of wind” has not paid off as once hoped.^[13] The signs of a reaction to new information are mixed. In January 2026,  the Department for Energy Security and Net Zero (DESNZ) increased their 2040 levelised cost forecasts for offshore wind from £51/MWh (2025) to £96/MWh.^[14] However, the Climate Change Committee assumes costs of just £37/MWh for the same technology.^[15]

Availability: Power when consumers need it

By 2025, UK generation capacity had risen materially, to around 108 GW, but average final consumption and peak demand had fallen by 16% and 12% respectively. A huge amount of extra generation capacity had been connected but was less able to do useful work.

Generation capacity has increased, but consumption and peak load have fallen

Figure 4: UK generation capacity, average final consumption & peak load, 1998-2025 (GW)

Source: Onward analysis. Department for Energy Security & Net Zero (DESNZ) ^[17]

The type of generation capacity has changed materially. Firm capacity is defined as power stations that can meet peak demand with a high degree of reliability and where output is controllable by a plant operator. By contrast, the output of intermittent generation (such as wind and solar) is driven by weather conditions, over which the operator has little control.

The UK’s firm capacity, including coal, gas, nuclear, hydro and biomass, has fallen by nearly 40% since the 2010 peak. It is unlikely that this trend will reverse anytime soon. 80% of the UK’s existing nuclear capacity is scheduled to close by March 2030.^[18] 63% of the UK’s combined cycle gas power station capacity was commissioned over 20 years ago.^[19]

The UK has lost firm generation capacity

Figure 5: UK electricity generation capacity 1998 to 2024, by category (GW)

Source: Onward analysis. Department for Energy Security & Net Zero (DESNZ) ^[20]

The loss of firm generation capacity creates two major risks.

Availability: Turning away investment

Firstly, it turns away inbound investment, because the UK lacks the generation capacity or grid connections to power new projects. Whilst some new industries may be able to flex their power demand up and down with the weather, most are looking to invest millions in capital equipment and will want to get full utilisation of their investment. The UK can neither deliver initial grid connections in a timely fashion nor ensure stable long term supply, so international investors look to countries that can, like the USA or China.

It is unclear whether the Department for Energy Security and Net Zero even want this investment. Adding a firm source of demand that seeks to run on a consistent basis will imperil a 95% clean power target. The head of ‘Mission Control’ for the UK’s Clean Power 2030 ambition recently stated:

“I want that increase in electricity demand, but I also want it to be of a particular type” – matching the profile of wind and solar generation as much as possible.^[21] While demand flexibility is an important technology and offers major opportunities to improve the utilisation of network infrastructure, that is not the same as shaping demand to suit intermittent generation patterns. It is undesirable to build an economy that is dictated by the vagaries of the weather. Britain had such a society three hundred years ago and it was much poorer. 

If factories or data centres want firm power and the UK cannot provide it, investment will take place overseas. GDP per capita has risen by just 0.4% per annum since 2007.^[22] The UK cannot afford to forgo the investment opportunities of the 21^st century.

Availability: Hampering electrification

The second risk is to consumer acceptance of electrification, and thus, to long-term progress on decarbonisation. The requirement for reliable electricity has increased over the last fifty years. An energy vector that used to power our lighting and domestic appliances now powers the internet, access to financial services, and AI.

Consumers are being pressured to go further than ever, by electrifying their transport and heating systems too. That proposition will meet resistance if households are unable, or cannot afford to turn on their heating on cold, still, dark winter days.

British electricity consumption already peaks in the winter months, before the arrival of widespread electrified heating. But solar power delivers most of its output in summer, and wind generation suffers from multi-day lulls. The country must retain firm generation capacity to keep the lights on and its homes warm, even as demand from electric cars and new uses like datacentres rises.

Britain’s electricity consumption peaks in winter

Figure 6: 2025 GB daily average electricity consumption, wind and solar generation (GW)

Source: Onward analysis. National Energy System Operator (NESO) ^[23]

Two logical failures

There are two major logical failures at the heart of Britain’s electricity policy malaise. The first has been to treat the direct production costs of intermittent renewables as reflective of the costs they impose on the wider electricity system. The second has been to prioritise the near-complete decarbonisation of the electricity system as a precursor to wider electrification.

Logical failure 1: Generation versus system costs

The true cost of intermittent generation is poorly understood. Political debate often compares levelised costs: a metric that captures the average cost of generating electricity over the lifetime of a generation asset. This ignores the cost of intermittency, and treats each MWh of electricity as if it were a jar of marmalade, that can easily be stored in a cupboard for consumption later in the year. In reality, the value of electricity is not fungible through time and space.

The physical reality of the electricity system is much more constrained. Supply and demand must be in constant balance, and the potential for storage, on current technology, is limited. Britain currently has enough storage capacity for around one hour of electricity demand.^[24] Even if all 16 of Ofgem’s shortlisted long duration storage projects get built, the total would increase to around five and a half hours.^[25] This is not enough to make it through a winter spell of low wind and sun.

Adding intermittent renewable capacity does not displace the need for reliable generation to ensure security of supply. In the end, this means that two generation systems are required, not one. Clean Power 2030 is only 95% clean for a reason – a reliable gas backbone is still needed to step in at times of scarce wind and solar. The 95% Clean Power 2030 target still requires 35 GW of unabated gas capacity to stay online, and assumes those power stations run at a capacity factor of just 5%.^[26] Gas power stations still need to recover their fixed costs, meaning higher prices via the Capacity Market or through scarcity pricing in periods of tight supply.

The National Energy System Operator (NESO) calculates the extent to which different generation technologies contribute to reliable supply. For conventional generation, this is based on historic availability during winter peak demand periods.^[27] For wind and solar, NESO uses an incremental equivalent firm capacity model.^[28] Hydro and gas turbines sit above 90%, whereas wind and solar are rated below 10%.

Some generation technologies are more reliable than others

Figure 7: Technology specific de-rating factors (%)

Source: National Energy System Operator (NESO) ^[29]

The costs of an intermittent-first, low carbon electricity system are material and are discussed in turn:

• Overbuilding capacity relative to demand: 95% Clean Power 2030 assumes building 115 to 126 GW of wind and solar capacity.^[30] This is to meet average electricity demand of around 36 GW.^[31] The overbuild is needed in the plan to restrain unabated gas to 5% of electricity generation, because wind and solar have low capacity factors and volatile generation profiles.
• Transmission costs and losses: The best wind resources are located far away from demand centres, requiring extensive transmission buildout across Scotland and the East of England. Firm generation capacity still needs to remain connected to the grid, so very little is ‘freed up’ by the new wind projects. Generation located far away from demand also means greater electricity losses through the UK’s network infrastructure.
• More storage: Volatile renewables need to be buffered by a storage system to reduce unabated gas use. Long duration electricity storage projects are being financed by ‘cap and floor’ subsidy support and hydrogen projects are very heavily subsidised.
• Firming costs: Intermittent-led electricity systems still need firm generation capacity to cover periods of high demand and low renewable output. This means that firm generation stations will run at low utilisation levels. These costs will be paid for one way or another; either via subsidies for new build firm power projects, via the Capacity Market to keep existing gas plants online, or by extreme prices at moments of scarce supply.
• Balancing costs: Intermittent renewables tend to have greater uncertainty over their short term output than firm technologies. This means that more has to be spent on short term balancing services to match supply and demand.Gas and nuclear power stations also provide inertia to the grid, thanks to the large rotating mass of their turbines and alternators, which are synchronised with the frequency of the electricity system. This helps stabilise the grid if a large power source drops, giving the system operator time to react. Wind and solar generators provide little effective inertia, meaning that new investment must be made to compensate for this loss, for example, by building synchronous condensers.

The list above is not a tirade against intermittent renewables, but the country has to face reality. If the UK builds an intermittent-first electricity system, then a lot of genera tion, storage and interconnection infrastructure will be needed, whilst maintaining a core of firm generation capacity. This can be observed via the utilisation rate of the UK’s electricity generation, transfer and storage infrastructure, which has fallen materially since 1998.

Utilisation of the UK’s electricity system has fallen

Figure 8: Utilisation of UK generation, storage and interconnector assets, 1998-2025 (%)

Source: Onward analysis. Department for Energy Security & Net Zero (DESNZ) ^[32]

The costs of building out the transmission network are a good example of rising infrastructure costs. NESO’s latest update on transmission spending recommends £64 billion of investment by 2030, and a further £89 billion into the 2030’s.^[33] On a combined basis, over £150 billion is being spent on assets that do not generate any power.

Solar power in particular will change the world, but less so Britain than brighter countries. The technology has collapsed in cost, and countries close to the equator have more consistent sunlight throughout the year. Those countries will often have high electricity demand on the sunniest days, due to air conditioning use, a helpful alignment between supply and demand.

The UK sits much further north and was ranked by the World Bank as the second worst country in the world for solar potential.^[34] The British priority is to build an electricity system that provides reliable power in winter. Solar may save gas use in summer but does little to alleviate the need for firm capacity in the winter months. Wind and solar generators are valuable to the extent that they save variable costs in our electricity system – the value of displaced gas and carbon.

UK winters are very poor for solar generation

Figure 9: Estimated monthly solar capacity factor for London and Madrid (2018-2024) (%)

Source: Onward analysis. Convexity power system modelling from Bayesian.energy ^[35]

Intermittent renewables are more than welcome in the UK market. But they should not be built under CfDs that treat each MWh as equally valuable. They should internalise the system costs that they create, and then compete in the wholesale and capacity markets, or secure their own power purchase agreements with corporate customers.

The distinction between the costs of generating individual megawatt hours of electricity, and the cost of delivering an electricity service that can reliably power the country are not new. Ten years ago, the Department for Energy and Climate Change (DECC) commissioned Frontier Economics to build a theoretical framework that encompassed the full system costs of different technologies.^[36]

In 2017, Dieter Helm’s Cost of Energy Review noted that neither wind or solar paid the full cost of their intermittency.^[37] The Review recommended the adoption of an ‘equivalent firm power’ capacity auction, so that the costs of intermittency would rest with those who caused them.^[38]

In August 2020, the Department for Business, Energy and Industrial Strategy (BEIS) published the 2020 edition of the electricity generation costs publication. It included ‘enhanced levelised costs’ that tried to capture some of the system impact of adding a marginal unit of a given generation technology.^[39]

Under the previous government, the now Shadow Secretary of State for Energy, Claire Coutinho, started a full systems cost review of generation technologies.^[40] There is no evidence of this analysis ever emerging from DESNZ.

It is clear that UK energy policy was starting to engage with a system level cost analysis, but it appears that this foray into rationality has since been sidelined. Politicians promising lower electricity bills on the basis of low levelised cost forecasts for wind and solar are either unaware of this prior analysis, or deliberately avoiding bringing the true costs to light, knowing that it will conflict with their preferred public narrative.

Logical failure 2: 95% decarbonisation of the electricity sector ahead of electrification

Territorial emissions are a flawed metric for a global emissions problem. The 2050 Net Zero target encourages the offshoring of any economic activity that comes with a local footprint – from growing food to refining crude oil. If the UK’s targets were in keeping with a concern for global climate change, they would be based on consumption rather than territorial emissions, recognising the trends in the graph below.

UK per capita emissions have declined, as China’s have risen

Figure 10: Greenhouse gas emissions per capita (tonnes) for UK and China (1980-2024)

Source: Jones et al. (2025), processing by Our World in Data.^[41]

In the interests of brevity, let us accept the territorial framework, in line with data published by DESNZ.

In 1990, the electricity supply sector was the single largest contributor to UK territorial emissions, responsible for over a quarter of the total. By 2025, absolute emissions from the electricity sector had fallen by 82%, and made up just 10% of the total.^[42]

UK electricity has made significant progress in reducing emissions

Figure 11: UK territorial emissions by sector: 1990 vs. 2025 (million tonnes of CO2e)

Source: Onward analysis. Department for Energy Security & Net Zero (DESNZ) ^[43]

Driving the last 10% out of the electricity supply sector is no longer the lowest hanging fruit. If driving gas use down to 5% to hit a 2030 target increases electricity costs, it then makes it more difficult to electrify (and decarbonise) domestic transport and heating buildings. These two sectors make up around half of the UK’s remaining territorial emissions.^[44]

Policies focussed on rapidly decarbonising the electricity system and inflating electricity costs, are damaging the cause of electrification. The policy problem can be observed through the lens of heat pumps, which offer a promising opportunity to decarbonise the heating of buildings, which makes up around 18% of UK territorial emissions.^[45]

An electric heat pump is an amazing piece of technology. A real-world study from 2020-2022, based on British homes, recorded a median seasonal performance factor of 2.8, which means that heat pumps in the study transformed one unit of electricity into 2.8 units of useful heat.^[46] This would make a heat pump 3.3x as efficient as an 85% efficient gas boiler.

Even if the UK’s grid was 100% powered by gas, heating via a heat pump would reduce carbon emissions by around a third relative to a gas boiler. Using the carbon intensity of British generation in 2025, the emissions reduction would be nearly 80%.^[47]

But the economics of buying an air-to-water heat pump system do not stack up for ordinary families. The capital costs are around £10,000 higher than a gas boiler, or an extra £2,500 after a £7,500 government grant.^[48] But even without the capital cost headwind, UK electricity prices are currently 3.6x to 4.1x those of gas.^[49] This ratio of electricity to gas prices is known as the ‘spark gap’ – and the UK is a major outlier relative to Europe.^[50]

A technology that is 3.3x as efficient as a gas boiler is up against an electricity price around four times as expensive as gas. The result is low heat pump uptake, despite a grant value equivalent to nearly 8 years of free domestic heating.^[51]

Electrified heating makes sense in France, but not in the UK

Figure 12: Domestic electricity to gas price ratio (spark gap), UK and France (1990-2024)

Source: Onward analysis. Department for Energy Security & Net Zero (DESNZ) ^[52]

The logic is borne out in the data. Alongside a high spark gap, the UK had the lowest stock and sales rates of heat pumps per household out of 15 major European countries. UK consumers are responding rationally to an expensive electricity system.

The UK has expensive electricity relative to gas – and low heat pump uptake

Figure 13: Heat pump market share vs. electricity-to-gas price ratios for 15 European countries (2024)

Source: The Climate Change Committee. ^[53]

Adoption should be consumer driven, if it is to maintain broad political consent. Lower electricity costs and a greater range of technology options (including the benefits of cooling) will be far more powerful in the long term than a hectoring state mandate.

Cheap electricity will allow continued progress on decarbonising transport and heating, without the political backlash or economic damage. It is the pro-consumer response to the challenge of decarbonisation, that can sustain political support over the decades ahead.

Full system costs modelling

Onward commissioned a system cost analysis to bring much needed clarity to the real costs of the British electricity system. Transira Energy, an independent energy advisory practice, have modelled the system cost of two different power systems and explained the differences between them. The two scenarios are named “Business as Usual” and the “Alternative Policy Pathway”. Each scenario is introduced in turn, with further details available in the Transira Energy report.^[54]

Business as Usual (BAU)

BAU has been produced by Transira, to reflect the likely evolution of the power system under the current policy framework, taking account of real-world delivery constraints. Key assumptions and results include:

• Decarbonisation:
  • Emissions in the power sector continue on trend to hit zero in 2045, but the wider economy falls short of the 2050 net zero target
  • Removal of the Carbon Price Support from April 2028, but electricity generators remain covered by the UK Emissions Trading Scheme (UK ETS)
• Generation technologies:
  • Continued policy support for the expansion of wind and solar generation under CfDs
  • Deployment of flexible low carbon technologies such as gas and bioenergy, both fitted with carbon capture and storage (CCS) technology. (Hereafter Gas CCS and BECCS)
  • Continued policy support for storage, interconnectors and hydrogen
  • 13.3 GW of nuclear by 2050 (2.2x current capacity) financed under the Regulated Asset Base (RAB) model
• Electrification:
  • Support and mandates for wider electrification continue – such as the ban on internal combustion engine cars by 2030, and support for heat pump deployment via the Boiler Upgrade Scheme and the Clean Heat Market Mechanism.

Alternative Policy Pathway (APP)

APP has been developed by Onward. It assumes that a new government wins a general election in 2029, and shifts policy to focus on reducing costs in the electricity system. Cheap and reliable electricity is prioritised, with further decarbonisation of the electricity system relegated to third place in the energy trilemma. It assumes:

• Decarbonisation:
  • The Climate Change Act 2008 is repealed, removing the need to hit carbon budgets.
  • The Carbon Price Support ends in April 2028 and electricity generators are removed from the UK Emissions Trading Scheme (UK ETS) from 2031.
  • There is no coal present on the system. Emissions intensity in the power generation sector remains similar to 2027 levels, and remains just below 100g CO2/kWh in 2050, with unabated gas providing 23% of the generation mix.
• Generation Technologies:
  • Renewable Obligation payments for existing wind and solar cease from 2033.
  • Policy support for new renewable, carbon capture, hydrogen, energy storage and interconnector projects ceases from 2030.
  • No changes are made to pre-existing CfD contracts.
  • 20 GW of nuclear capacity by 2050 (3.4x current capacity) financed under the RAB model. Reducing nuclear construction costs and timelines becomes the core energy priority of the UK government, with measures to improve the availability of sites and grid connections.
  • 45 GW of gas capacity remains on the system in 2050. New build capacity market contracts are extended to 20 years to support new gas-fired technologies.
• Electrification:
  • Subsidies and mandates for electrification cease, with adoption being driven by lower electricity prices and greater range of consumer choice, for example, encouraging air-to-air heat pumps with cooling functionality.
  • Electricity use from data centres grows faster than in BAU, thanks to improved connection availability and lower electricity prices.

APP has a balanced mix of nuclear, renewable and gas generation

Figure 14: Alternative Policy Pathway: Generation mix from 2027 to 2050 (TWh)

Source: Transira Energy. ^[55]

The central premise behind the APP system is a greater proportion of firm generation capacity, located closer to demand and existing transmission infrastructure. This saves billions of expenditure on network expansion and balancing costs.

APP doesn’t need to connect as much generation capacity as BAU

Figure 15: Generation capacity under APP and BAU (2027-2050, GW)

Source: Transira Energy. ^[56]

System Costs: APP vs. BAU

System costs refer to the total cost of the electricity system, excluding the costs and profit margins of electricity suppliers.^[57] The APP scenario reduces system costs substantially relative to BAU, saving a cumulative total of £320 billion over 2030-2050, adjusted for lower electricity generation under APP.^[58]  This results in APP system costs falling 17% below BAU by 2035 and 20% below BAU by 2040.

Relative to 2027 system costs, APP saves 21% by 2035 and 31% by 2050.

APP has lower system costs than BAU, with a 17% saving by 2035

Figure 16: Electricity system cost index under BAU and APP (£ per MWh, 2027 =100)

Source: Transira Energy. ^[59]

For a household with average electricity consumption, Onward estimates that APP would drive a real term electricity system cost reduction of c. £200 between 2027 and 2035.^[60]

Savings could be increased by a further £90, via a series of further policy measures:

• Warm Home Discount: Moving the costs of the Warm Home Discount out of the energy sector and into general taxation would reduce electricity costs by c. £20 p.a. for an average use household.
• Addressing debt related costs: A domestic customer with average electricity consumption pays around £32 p.a. in debt related costs. Halving the cost of debt by improving the home moving process and enabling utilities to remotely move non-paying customers to smart prepayment meters, could save £16 p.a. ^[61]
• Feed-in-tariff: Moving the remaining costs of the Feed-in-tariff into general taxation in 2035 would reduce electricity bills by about £10 p.a.^[62]
• VAT: Zero rating VAT on domestic electricity in 2035 would cut costs by a further £44 p.a.

Why are APP system costs lower?

There are four major drivers of the £320 billion cumulative saving that APP enjoys relative to BAU from 2030 to 2050. Each driver is discussed in turn.

APP saves £320bn in cumulative system costs between 2030 and 2050

Figure 17: Categorised system cost savings from 2030 to 2050 under APP vs. BAU (2025 £bn)

Source: Transira Energy. ^[63]

1.      Networks: £137 billion of savings (43% of the total)

The total network savings figure is driven by lower transmission costs, making up the vast majority of cumulative network savings. There are also small savings on the lower voltage distribution network, as domestic electrification of transport and heating proceeds more slowly in APP than under BAU.

APP makes material savings on network spending vs. BAU

Figure 18: Annual allowed network revenues under BAU and APP (2025 £bn)

Source: Transira Energy. ^[64]

The higher costs in BAU are driven by the investment that is needed to connect geographically dispersed generation assets (e.g. wind farms). By contrast, APP benefits from a more centralised generation system that connects up firm power stations located near existing transmission infrastructure.

Put differently, APP avoids the need to connect 78 GW of generation, storage and interconnector assets relative to BAU, thanks to its higher proportion of firm generation capacity.^[65]

2.     Wholesale prices: £94 billion of savings (29% of the total)

There are two major drivers of wholesale price differences between the two scenarios. BAU benefits from greater renewable capacity, which has a depressing effect on wholesale prices. However APP benefits from taking electricity generators out of the UK ETS (a carbon pricing mechanism) from 2031, which reduces the marginal costs of gas generation. This in turn reduces the wholesale price whenever gas is the marginal price setting technology.

Removing carbon taxes reduces wholesale costs for APP

Figure 19: Baseload wholesale power prices under BAU and APP (£ per MWh, 2025)

Source: Transira Energy. ^[66]

In the early years, the removal of electricity generators from the UK ETS outweighs the price depressing effects of greater renewable capacity, leading to lower wholesale prices under APP.

APP retains a large proportion of existing renewable capacity but extends no further policy support to new projects. This is a pragmatic stance that recognises that the capex has been sunk, and the renewable generation will displace gas costs and reduce carbon emissions.

In the outer years, APP is assumed to maintain a wholesale cost advantage over BAU. APP has greater firm capacity, meaning fewer periods of very tight supply relative to demand, and also enjoys the advantage of lower marginal cost flexible generation, driven by greater unabated gas capacity rather than using hydrogen, Gas CCS or BECCs.

Real carbon prices in the BAU scenario are assumed to increase by 6.1% per annum from 2030 to 2050, reaching a level of £164/tonne by 2050. This is appreciably lower than the DESNZ net zero aligned strategy forward curve, which reaches a level of £235/tonne in 2050.^[67] In APP, the cost of carbon is reduced to zero from the start of 2031, as generators no longer pay the UK ETS.

Carbon price assumptions for BAU and APP

Figure 20: Carbon price assumptions for BAU and APP (£ per tonne, 2025)

Source: Transira Energy. ^[68]

Both scenarios use the same gas price assumptions, with prices starting at c. £35 per MWh (th) in 2027, falling to c. £23/MWh by 2050. The forward looking price assumptions are based on a blend of futures pricing and DESNZ forecasts out to 2030, and then uses the DESNZ central gas price scenario out to 2050.^[69]

Gas price history and forward looking assumptions

Figure 21: Gas price history and forward looking assumptions (£ per MWh thermal, 2025)

Source: Onward analysis, Transira Energy, Ofgem, DESNZ, ONS. ^[70]

APP would be more exposed to a future gas price shock than BAU. However, the impact on consumer electricity prices would be significantly smaller than the events surrounding the Russian invasion of Ukraine. In 2022, virtually all of Britain’s electricity generation was linked to the wholesale market. CfD generation made up just 20 TWh, or around 8% of British electricity demand.^[71] Under APP, greater consumer price stability relative to 2022 comes from two sources.

Firstly, pre-existing CfDs contracts will be honoured, which will provide a meaningful price hedge out to 2040 and beyond. Secondly, all nuclear power projects from Sizewell C onwards are assumed to be built under the RAB model, where revenues are dictated by a pre-agreed return on capital, rather than being driven by wholesale electricity prices. Nuclear power is anticipated to deliver a third of the APP generation mix in 2050.^[72]

For context, Onward estimates that a 250% increase in gas prices in 2040 (akin to 2022 prices in real terms) would increase fuel costs for APP by about £6 billion relative to BAU.^[73] Policymakers would then have to decide the extent to which inframarginal returns for merchant generators are recovered by windfall taxes such as the Electricity Generator Levy.

3.     Balancing and ancillary services: £67 billion of savings (21% of the total)

Balancing costs represent the cost of real-time actions taken by NESO to manage network congestion, demand and supply fluctuations, as well as other critical conditions such as frequency and voltage. Ancillary services are costs paid for ahead of time, for services such as frequency response, which help manage the stability of the electricity system. Of the £67 billion of total category savings, £59 billion are from lower balancing costs and £8 billion are from savings on ancillary services.^[74]

In the BAU scenario, balancing costs continue to rise out to 2040, as upgrades to the transmission network are assumed to take longer than the buildout of new wind generation capacity. This is in keeping with the findings of the Winser review, which noted that strategic transmission projects can take twelve to fourteen years, between identification and final commissioning.^[75] Balancing costs in both scenarios start to decline once transmission upgrades catch up with wind capacity buildout. This occurs earlier for APP, due to lower future wind capacity.

APP makes material savings on balancing and ancillary services vs. BAU

Figure 22: Annual system cost expenditure on balancing & ancillary services under APP and BAU (2025 £bn)

Source: Transira Energy. ^[76]

Balancing costs under APP also benefit from the removal of the UK ETS. This is because the gas ‘turn up’ required to replace wind generation that is curtailed behind transmission bottlenecks, is achieved at a lower price, thanks to the removal of carbon costs.The APP generation mix is also more predictable, thanks to a greater proportion of firm generation capacity, reducing the need for last-minute balancing actions from the NESO control room.

The savings in ancillary services are much smaller, but still significant, totalling £8 billion from 2030 to 2050. BAU requires a greater level of spend to manage system voltage, inertia and frequency, due to a greater generation share from non-synchronous and intermittent renewable technologies.

By contrast, APP has a higher share of generation from gas and nuclear, both of which provide inertia to the electricity system and can be controlled. This reduces the need to procure standalone services to manage the stability of the electricity system.

4.     Generation subsidies and Capacity Market costs: £22 billion of savings (7% of the total)

The final cost category consists of subsidies for low carbon generation, as well as Capacity Market costs that are required to keep varying amounts of gas capacity online.

The first graph presents traditional subsidies, excluding the costs of the Capacity Market. APP has lower generation subsidy costs, saving £43 billion by 2050. APP benefits from the early retirement of the Renewable Obligation scheme for wind and solar projects from 2033, and from ending support for new low carbon generation (other than nuclear) from 2030. Nuclear subsidy costs are higher for APP in the later years, due to greater nuclear generation capacity.

In an ideal world, large scale nuclear projects would be built under competitive markets. But the scale of up-front investment required, operating lives of at least sixty years, and the risk from changes to political attitudes in future make this an unrealistic expectation.^[77]

APP spends less on generation subsidies

Figure 23: Annual system cost spending on generation subsidies for APP & BAU (2025 £bn)

Source: Transira Energy. ^[78]

Whilst APP spends less on low carbon generation subsidies, it ends up spending more in the Capacity Market, as the pathway assumes a greater build out of new combined cycle gas power stations.

But APP spends more in the Capacity Market

Figure 24: ​​Annual Capacity Market costs under APP and BAU (2025 £bn)

Source: Transira Energy. ^[79]

Capacity Market agreements for new build gas are assumed to extend to 20 years in APP, rather than the 15 years under BAU. This is to incentivise the construction of new gas-fired capacity and to overcome the political risk associated with future net zero targets. BAU has a greater reliance on life extensions for unabated gas, and procures more firm capacity via direct subsidies for Gas CCS, hydrogen power stations and BECCS.

The allocation of system costs

Models and forecasts of the future are not policy prescriptions, but they can provide valuable learnings. In this case, building a power system that retains a larger role for firm generation capacity (nuclear and gas) drives large cost reductions, via lower transmission build-out and lower balancing costs.

If the incremental costs of network investment, balancing and ancillary services are allocated to the increased wind and solar generation under BAU, then the marginal system integration costs of those technologies are revealed to be much higher than their individual levelised costs.

Intermittent generation is expensive to integrate into the electricity system

Figure 25: ​​Marginal system integration costs attributed to wind and solar generation vs. levelised cost assumptions (£ per MWh 2025)

Source: Transira Energy. ^[80]

These system integration costs are not being properly revealed in CfD auctions, or captured in levelised cost estimates, for three major reasons.

• Transmission cost recovery: The costs of paying for the onshore transmission system are largely recovered from demand customers. Wider transmission charges on generation (in aggregate) are restricted to the limiting regulation of 2.50 EUR per MWh.^[81]
• Curtailment protection: In May 2009, Ofgem introduced an interim ‘connect and manage’ regime, which allowed generators to connect to the network ahead of the transmission investment that would be required to accommodate the new power flows.^[82] Connection gives firm access rights, which means generators are compensated for electricity flows that the grid can’t handle. This policy socialised the costs of curtailment through balancing charges, rather than billing the causative generator, which would occur under a ‘polluter pays’ principle.
• Balancing cost recovery: Prior to April 2023, balancing cost recovery was split evenly between generators and consumers. Balancing costs are now recovered from the demand side only, removing any scope for generators to internalise the costs that they create.

Market design has significant potential to improve cost outcomes for consumers. If prospective generators are forced to internalise the integration costs that they impose upon the wider electricity system, then behaviour will change. New generation projects might be built in areas with lower network constraints, or built alongside battery storage to allow greater control over dispatch.

Driving further improvement for APP:

APP is not an idealised view of the world. The pathway faces significant cost headwinds from expensive nuclear capacity, with incremental large scale nuclear power stations built in the 2040’s costing £122-£138/MWh in 2025 terms.^[83]

For a scenario like APP to succeed to its full potential, and reduce system costs by more than the assumed 31% between 2027 and 2050, nuclear construction costs must fall. The recommendations of the Fingleton Review must be implemented in full, and the incentives to deliver new projects on time and budget must be improved.

In 1995, Sizewell B (the UK’s first and only operating pressurised water reactor) was completed on time and on budget.^[84] Brian George, the project manager at Sizewell B, delivered an incredible piece of infrastructure that will supply clean electricity for at least sixty years.^[85] This excellence in nuclear construction must be rediscovered.

Reducing the cost of nuclear delivery is not just critical to economic growth. If costs can be cut faster, then heat pumps and electric vehicles will become a much more attractive proposition for consumers, helping decarbonise more of the economy, without the political friction of today. Furthermore, speeding up the rate of nuclear delivery would displace gas generation faster than assumed under APP, driving down the remaining emissions in the electricity sector.

Carbon emissions: APP vs. BAU

The APP scenario has a higher emissions intensity than BAU. Under APP, unabated gas retains a 23% role in the generation mix of 2050, versus under 3% for BAU. APP also precludes any investment in BECCS, foregoing the ‘benefits’ of negative emissions accounting.

APP is not a highly carbon intensive electricity system. Emissions intensity increases only very marginally vs the 2027 start point, and remains below 100g/CO2/kWh in 2050.^[86]

Power sector carbon intensity (2027-2050)

Figure 26: ​​Power sector carbon intensity under BAU and APP (g of CO2 per kWh)

Source: Transira Energy. ^[87]

On a cumulative basis, APP generates 524 million tonnes of increased emissions relative to BAU, but saves £320 billion between 2030 and 2050. Put differently, driving the last 23% of unabated gas off the system comes at a cost of over £600 per tonne of CO2. This is more than twice the highest value that DESNZ models for carbon prices by 2050.^[88]

Even though emissions from the power sector rise in aggregate, driven mainly by growth in electricity consumption, APP is building a robust and affordable electricity system that will allow emissions reductions in other areas of the economy.

Power sector emissions remain low under both scenarios

Figure 27: ​​Historic and forecast emissions from the electricity sector (Mt CO2e)

Source: Onward analysis. DESNZ and Transira Energy. ^[89]

Mandating net zero territorial emissions by 2050, via the Climate Change Act 2008 (2050 Target Amendment) Order 2019, was not a measured policy decision. It was rushed through at the end of Theresa May’s premiership after ninety minutes of debate in the House of Commons.^[90] No government impact assessment was laid before Parliament.^[91]

The level of parliamentary scrutiny applied was not in keeping with legislation that would not only constrain the UK’s economy, but mark a radical curtailment in the free choices of its citizens.Efforts to meet the target have involved effectively dictating how peopleshould travel, warm their homes and what foods they should eat.^[92]

The metrics against which the UK has measured climate progress are also flawed, as the Climate Change Act 2008 uses territorial accounting, covering emissions that occur within the UK’s borders.^[93] Consumption emissions (sometimes referred to as a ‘carbon footprint’) covers the emissions associated with the consumption of goods and services in the UK.

2023 is the most recent year for which we have data covering both territorial and consumption measures. From 1990 to 2023, territorial emissions are estimated to have declined by 51%. On a consumption basis, the decline was a more limited 24%.

UK consumption emissions have fallen more slowly than territorial emissions

Figure 28: ​​UK consumption and territorial emissions since 1990 (Indexed to 1990 = 100)

Source: Onward analysis. DESNZ, DEFRA. ^[94]

The promise of electrification, via carrots, not sticks

There are major aspects of the decarbonisation agenda, which can make sense for the UK economy, its citizens and the global climate. Electrification sits at the top of this list. APP is designed to provide a stable, affordable and relatively clean power sector that enables long term electrification of heating and transport.

A heat pump, if powered by the APP grid of 2050, would reduce carbon emissions by about 85% relative to a gas boiler.^[95] An electric vehicle would have around 88% lower emissions per incremental mile driven.^[96] These dramatic improvements are driven by a combination of the high energy efficiency of many electrified technologies, and a largely clean power sector.

Reducing the cost of electricity relative to gas or petrol will make these technologies more attractive. By way of example, Onward have modelled the annual running cost savings a household could expect from switching from a gas boiler to a heat pump under BAU and APP.

Heat pumps save households more money under APP

Figure 29: ​​Estimated annual savings from heat pump adoption under BAU and APP (£ p.a.)

Source: Onward analysis. Ofgem, NESO, Transira Energy. ^[97]

Whilst BAU assumes faster growth in the adoption of electric vehicles and heating, this is driven by large subsidies and state mandates, not free choice. APP prioritises cheap electricity, consumer choice and long term political consent.

Demand for electrolysis (hydrogen production) under APP is assumed to fall to zero, due to the removal of subsidies. Demand from data centres rises materially, attracted by the UK’s more competitive electricity prices and greater availability.

Growth in electricity use under APP is driven by affordable prices, not mandates

Figure 30: ​​Forecast increase in electricity use between 2027 and 2050 (TWh)

Source: Transira Energy. ^[98]

The forecast electrification of transport and heating are still very substantial under APP. Onward estimate that the 48.3 TWh of EV demand growth by 2050 is the equivalent to electrifying nearly 23 million cars, or over 60% of the UK’s existing car fleet.^[99] 23.7 TWh of demand growth for electrified heating would be equivalent to displacing 6.7m gas boilers, or nearly 30% of the UK’s existing domestic gas heating.^[100]

Those two initiatives alone would reduce territorial carbon emissions by nearly 51 million tonnes, or c. 14% of 2025 levels.^[101] Further improvements would also be captured via lower emissions in the fuel supply chain.

Building electrification from a firm foundation

The APP scenario quantifies the scale of savings that could be made if electrification is built from firm foundations. A robust electricity system will give British businesses and the British public confidence that electricity will be available when they need it, with a long term commitment to affordable prices. It is up to the manufacturers and retailers in the heating and transportation industries to take advantage of this foundation.

Technology providers will compete to provide products that consumers want. Perhaps cars with greater range and faster charging, or new electric heating systems with lower installation costs and embedded cooling. Innovators and entrepreneurs must rise to the challenge and create products and services that are better than the fossil fuel incumbents.

If future governments want to accelerate the adoption of electrification technologies, and move faster on climate targets, they can reintroduce subsidy support further down the line, perhaps according to a standardised carbon value across technologies. The sums required to encourage adoption will be much lower if power is affordable and technology providers have made their products more attractive to consumers, via real competition.

Electrification has much wider potential than just helping decarbonise cars, vans and space heating. With the right innovation, heavy goods vehicles and medium temperature industrial processes will have the potential to electrify too, driving further emission reductions. If the UK can make its electricity affordable and available, those innovations can be pioneered in Britain, and exported to the rest of the world.

Conclusion

The Government’s approach to the electricity sector is incoherent. It is rushing to decarbonise the power sector with intermittent renewables, whilst ignoring many of the extra system costs that this entails, particularly the costs of building extra transmission and balancing the grid.

This approach is driving up electricity prices. The government is simultaneously pushing consumers and businesses to adopt electrification technologies, whilst making the electrical input more expensive.

Instead of addressing a major cause of expensive electricity (rising system costs) the Government is engaging in shell games – subsidising selected groups of businesses and consumers, and moving electricity costs into general taxation. In a fiscally constrained environment, this is fraught with risk. Consumers will not welcome a cocktail of high prices, state electrification mandates and rising taxation.

The UK must change course

The APP scenario from Transira’s report has a balanced mix of generation of nuclear, wind, solar and gas. It can reduce the cost of Britain’s electricity system by over 20% by 3035 and by over 30% by 2050.

It assumes nuclear capacity is rebuilt under the RAB model and is run as a baseload power source. The rest of the electricity generation sector is left to fight it out in the market. Renewables will be awarded no more CfDs, and will have to compete directly with gas power stations, newly unencumbered by carbon taxes.

If the UK can drive down electricity costs over the course of a parliament, and signal long term intent to continue doing so, two important flywheels can start to kick in.

Firstly, electricity consumption will return to robust growth – from domestic consumers, the existing commercial base and new inbound investment. This will unleash a positive flywheel, where the UK starts improving the utilisation of its electricity system, and drives down average costs. In the long run, the economics of the cheap power system win out, and take market share from oil and gas.

Secondly, the UK becomes a more credible international investment proposition. Inflation falls, growth picks up and investors become more confident that the UK is an attractive long term bet. In turn, this reduces the cost of financing future generation assets, whether renewables, nuclear or gas. This in turn drives down the cost, and drives up the availability of the electricity system, powering the British economy through the 21^st century.

Future research

The Alternative Policy Pathway is not a blueprint or mandate for the UK’s future generation mix. Using it as such would simply replace one form of central planning with another. However, the research exercise has highlighted three policy areas that will guide Onward’s future analysis.

1. Electricity market reform: Intermittent renewables impose significant system costs that aren’t internalised by the causative generators. Transmission charging reform, via removing the Limiting Regulation, would expose generators to their true grid build-out costs. Nodal pricing or changes to the Balancing Mechanism could similarly expose generators to the balancing costs that they create. It is vital that these costs are internalised and the system costs of different generation technologies are revealed up front, rather than being hidden in consumer levies.

2. Reducing infrastructure costs: The UK is set to spend extortionate sums of money on the build out of the transmission system. As well as casting a critical eye on the planned levels of transmission investment, there are major opportunities to achieve greater value for money. This could be achieved by improving the incentives on cost effective infrastructure delivery, or incentivising network companies to use new technologies (such as batteries and dynamic line rating) to improve the utilisation of their assets. Equally, the build costs and timelines for new nuclear projects are too high in the UK. Britain must rediscover the ability to build nuclear power on time and budget, if it is serious about delivering affordable power and deep decarbonisation of its energy system.

3. Encouraging electrification: Cheaper electricity will be a formidable driver of electrification and decarbonisation, but there are ways to encourage adoption without relying on large subsidies and mandates. As an example, UK demand for one type of heat pump (portable air conditioning) overwhelmed supply this summer.^[102] A cost effective policy to decarbonise heating should tap into this existing demand, and encourage the installation of air-to-air heat pumps that can provide both summer cooling and winter heating.

^[1] Comparisons sourced from Department for Energy Security & Net Zero (DESNZ) – Industrial electricity prices in the IEA including taxes and Domestic electricity prices in the IEA including taxes. The UK ranked 25th out of 25 countries for industrial prices and 26th out of 27 countries for domestic prices in 2024.

^[2] Assumes average electricity system carbon intensity of 92g CO2/kWh from Transira Energy – Powering Britain: A comparison of policy pathways to 2050 (July 2026). Onward analysis includes technology assumptions of 8% losses in transmission and distribution, 40 miles per gallon for a petrol vehicle using normal biofuel blend (2.069 kg of CO2e/litre – DESNZ, Greenhouse gas reporting: conversion factors 2025) vs. 3.5 miles per kWh for an EV, heat pump seasonal performance of 3.0 vs. gas boiler efficiency of 85%.

^[3] DESNZ, DUKES table 5.1. 21% decline refers to the change in final electricity consumption from 2005 to 2025.

^[4] Onward Analysis. DESNZ. Electricity consumption from Historical electricity data: 1920 to 2025. Electricity expenditure from DUKES table 1.1.6. Prices adjusted to 2025 values using UK CPI (ONS)

^[5] UK Government press release, 19th June 2025. Millions more families to get £150 off energy bills this winter.

^[6] Levy calculation from Ofgem policy cost allowance methodology Annex 4 (July to September 2026). Calculation based on Ofgem typical domestic consumption values of 2,700 kWh electricity and 11,500 kWh of gas.

^[7] Ofgem, Summary of changes to energy price cap 1 April to 30 June 2026 (announced 25th February 2026)

^[8] The BIS scheme is funded via the Network Charging Compensation Scheme levy. The BICS scheme is being funded by a combination of changes to the indexation for generators under the RO and FIT schemes, the removal of the Carbon Price Support from April 2028 and Exchequer funding.

^[9] UK Government press release, 21st July 2026. New PM cuts tax on household electricity bills to give breathing space on cost of living.

^[10] Onward analysis of data from electricitybills.uk, data and methodology section.

^[11] 72% reduction refers to the difference between the weighted average strike price for the FIDER round in 2014 and the weighted average strike price for AR5, awarded in 2019 (National Audit Office and DESNZ)

^[12] Onward analysis. FIDER round data from the National Audit Office and CfD rounds 1-7 from the respective DESNZ allocation round results. Calculations are weighted average strike prices and adjusted to 2025 values using UK CPI (ONS). Upward price adjustment to AR7 is based on DESNZ, link.

^[13] Prime Minister Boris Johnson’s speech at the Global Investment Summit 2021 in the Science Museum, link.

^[14] DESNZ, Electricity generation costs 2023 and Electricity generation costs 2025. Levelised costs reflect offshore wind projects commissioning in 2040 have been adjusted to 2025 values using UK CPI (ONS)

^[15] The Climate Change Committee, The Seventh Carbon Budget: Advice for the UK Government, February 2025, page 208. 2040 levelised costs adjusted to 2025 values using UK CPI (ONS)

^[16] Onward analysis. Generation capacity for the year 2000 sourced from DESNZ, DUKES table 5.7 and excludes pumped hydro storage capacity. Average electricity consumption and maximum load met are calculated from DESNZ, DUKES,  Historical electricity data: 1920 to 2025, and refer to the year 2000.

^[17] Onward analysis, DESNZ. Generation capacity sourced from DUKES table 5.7. Calculation excludes pumped hydro storage and re-rates wind and solar to reverse the applied de-rating factors. Average final consumption from DUKES 5.1, maximum load from DUKES Historical electricity data 1920 to 2025.

^[18] World Nuclear Association, Nuclear power in the United Kingdom. The UK has 5.9 GW of existing nuclear capacity and the calculation assumes that only Sizewell B (1.2 GW) operates past March 2030.

^[19] Onward analysis. DESNZ, DUKES table 5.11. Calculation refers to combined cycle gas turbine (CCGT) station capacity commissioned before 2006.

^[20] Onward analysis, data from DESNZ, DUKES table 5.7. Firm generation capacity excludes pumped hydro storage and groups hydrocarbon based generation, nuclear, hydro, bioenergy and waste. Intermittent generation calculations re-rate wind and solar to reverse the de-rating factors within the table.

^[21] Youtube, The Carbon Brief Interview: Head of UK “mission” for clean power. Relevant quote from 7 minutes 48 seconds.

^[22] ONS, Gross domestic product per head. Cumulative increase from 2007 to 2025 expressed as a compounded annual growth rate.

^[23] Onward analysis. Wind and solar generation from NESO, Historic GB Generation Mix. Consumption data sourced from NESO, Historic Demand Data 2025, and is calculated by the sum of national demand and embedded wind and solar generation.

^[24] Battery data sourced from Modo Energy GB BESS buildout Q1 2026, with a total of 11.8 GWh. UK pumped hydro storage capacity assumed to total 24.5 GWh across four sites. Combined total of 36.3 GWh.

^[25] Refers to projects listed under Ofgem Window 1: Minded-to decisions – long duration electricity storage published 26th June 2026. 16 projects assumed to total an additional 137 GWh of storage.

^[26] NESO, Clean Power 2030 Data Workbook. 35 GW of gas capacity is referenced on tab CP.17 and tab CP.06 references a generation range of 14.5 to 15.1 TWh p.a. – which implies a capacity factor of c. 5%.

^[27] NESO, Electricity Capacity Report 2026 (May 2026)

^[28] Energy System Operator, Storage & Renewables De-Rating Factors (2023)

^[29] NESO, Electricity Capacity Report 2026 (May 2026)

^[30] DESNZ, Clean Power 2030: Action Plan: A new era of clean electricity, December 2024 (page 32)

^[31] Onward analysis. Data sourced from NESO, Clean Power 2030 Data Workbook, tab CP. 28. 36 GW of average consumption is based on customer load plus network losses.

^[32] Onward analysis, DESNZ. Utilisation calculated by: (electricity supplied) / (sum of generation, storage and interconnector capacity multiplied by 8,760 hours per year) Generation capacity from DUKES table 5.7 and re-rates wind and solar to reverse the applied de-rating factors. Grid scale battery storage capacity from DUKES table 5.16. Interconnector capacity from DUKES table 5.13 and excludes Moyle (Northern Ireland to Scotland) Electricity supply from DUKES table 5.1.

^[33] NESO, Beyond 2030 – Electricity Transmission Update June 2026.

^[34] World Bank, Energy Sector Management Assistance Program, Global photovoltaic power potential by country (June 2020)

^[35] Convexity power system modelling from Bayesian.energy. Data collecting using Renewables Vision feature, assuming generic solar, for London and Madrid, 2018-2024. Data aggregated into monthly averages by Onward.

^[36] Frontier Economics, Whole power system impacts of electricity generation technologies – a report prepared for the Department of Energy and Climate Change (February 2016)

^[37] Dieter Helm, Cost of Energy Review, 25th October 2017, page 109.

^[38] Dieter Helm, Cost of Energy Review, 25th October 2017, page viii.

^[39] Department for Business, Energy and Industrial Strategy, Electricity Generation Costs 2020, (August 2020)

^[40] Hansard, Offshore Wind, Volume 778: debated on Wednesday 14 January 2026.

^[41] Jones et al. (2025); Population based on various sources (2024) – with major processing by Our World in Data.

^[42] DESNZ, Provisional UK greenhouse gas emissions statistics 2025, data tables, Table 1a: Territorial greenhouse gas emissions by source sector, in million tonnes carbon dioxide equivalent (MtCO2e), UK 1990-2025.

^[43] Onward analysis. DESNZ, Provisional UK greenhouse gas emissions statistics 2025, data tables, Table 1a: Territorial greenhouse gas emissions by source sector, in million tonnes carbon dioxide equivalent (MtCO2e), UK 1990-2025.

^[44] Onward analysis. DESNZ, Provisional UK greenhouse gas emissions statistics 2025, data tables, Table 1a. Domestic transport comprised 30.8% of territorial emissions in 2025. Residential, commercial and public sector buildings collectively account for 20.6% of territorial emissions and are largely driven by space and water heating.

^[45] Onward analysis. Breakdown estimated from 2023 greenhouse gas emissions data from the UK National Atmospheric Emissions Inventory.

^[46] DESNZ & Energy Systems Catapult, Electrification of Heat Demonstration Project, Interim Insights from Heat Pump Performance Data.

^[47] Onward analysis. Assumes carbon intensity of 130g/CO2/kWh based on the weighted average 2025 data from NESO Historic GB Generation Mix. Onward technology assumptions are for a heat pump seasonal performance factor of 3.0 versus 85% gas boiler efficiency and 8% power losses in transmission and distribution.

^[48] Assumes £3300 for a new gas boiler plus installation (Checkatrade cost guide, updated March 2026) Air-to-water heat pump cost assumed at £13,300 (MCS data dashboard 2025 average installation cost for an air source heat pump) £7500 grant relates to the Boiler Upgrade Scheme.

^[49] Onward analysis, Ofgem. 3.6x spark gap refers to the unit price difference between electricity and gas under the Ofgem energy price cap from 1st July to 30th September 2026. 4.1x refers to the price difference when both unit rates and standing charges are taken into account.

^[50] European Heat Pump Association, 2025 European heat pump market report (The UK had the highest electricity to gas price ratio of 18 European countries)

^[51] £7500 BUS grant compared to Q3 2026 Ofgem price cap. Assumes 11,500 kWh of annual gas consumption at 7.33 p/kWh and a daily standing charge of 29.04p, which equates to 7.9 years of gas bills.

^[52] Onward analysis. DESNZ, International domestic energy prices. Spark gap is calculated from Table 5.5.1 (Domestic electricity prices in the IEA including taxes) and Table 5.9.1 (Domestic gas prices in the IEA including taxes)

^[53] The Climate Change Committee, Progress in reducing emissions, 2026 report to Parliament (June 2026) Data taken from Charts and Data, tab ES4. Bubble size represents the stock of heat pumps per 1000 households.

^[54] Transira Energy – Powering Britain: A comparison of policy pathways to 2050 (July 2026)

^[55] Transira Energy – Powering Britain: A comparison of policy pathways to 2050 (July 2026)

^[56] Transira Energy – Powering Britain: A comparison of policy pathways to 2050 (July 2026)

^[57] Suppliers costs and margin typically encompass around 15% of a household bill – electricitybills.uk

^[58] Transira Energy – Powering Britain: A comparison of policy pathways to 2050 (July 2026). £320bn of cumulative system cost savings are expressed in 2025 real values and have been pro-rated for 7% lower cumulative electricity consumption under APP.

^[59] Transira Energy – Powering Britain: A comparison of policy pathways to 2050 (July 2026).

^[60] Onward analysis. Real system cost saving in 2035 is relative to a 2027 base cost assumption. 2027 base cost is assumed to be the Q3 2026 Ofgem price cap assuming 3.3MWh of UK average domestic consumption, with two upward adjustments. 2027 base costs are adjusted upwards by £14 to account for increased transmission cost in 2027 vs. 2026 and by £81 to account for RO costs that are paid for out of taxation. A 20.7% system cost reduction is then applied to all bill cost components excluding supplier costs, debt related costs and supplier profit. Applying the same analysis to BAU would result in a system cost saving of around £50 by 2035.

^[61] Ofgem, Ofgem Interim Chief Executive Tim Jarvis’ keynote speech at Utility Week Live on 20 May 2026. Debt cost estimates derived from Ofgem price cap (Annex 9): 1 July to 30 September 2026.

^[62] Onward analysis. Assumes £1.0bn scheme cost (24/25 prices) in 2035/6 based on DESNZ, Feed-In Tariffs analytical annex: Impact of indexation options (Option 1, CPI) Total scheme costs assumed to be one third recovered from domestic consumption and recovered over 29 million households.

^[63] Transira Energy – Powering Britain: A comparison of policy pathways to 2050 (July 2026) Cumulative system cost savings have been pro-rated for 7% lower cumulative electricity consumption under APP.

^[64] Transira Energy – Powering Britain: A comparison of policy pathways to 2050 (July 2026)

^[65] Transira Energy – Powering Britain: A comparison of policy pathways to 2050 (July 2026). 78 GW refers to the capacity difference for generation, storage and interconnector assets between BAU and APP in 2050.

^[66] Transira Energy – Powering Britain: A comparison of policy pathways to 2050 (July 2026)

^[67] DESNZ, Traded carbon values used for modelling purposes, 2025.

^[68] Transira Energy – Powering Britain: A comparison of policy pathways to 2050 (July 2026) and DESNZ – Traded carbon values used for modelling purposes, 2025.

^[69] Forward looking assumptions from Transira Energy – Powering Britain: A comparison of policy pathways to 2050 (July 2026) and are based on a blend of market futures (as of May 2026) and DESNZ – Fossil fuel price assumptions: 2025 (Scenario B) – adjusted to 2025 values using UK CPI (ONS)

^[70] Onward analysis. Gas price history from 2010-2025 derived from Ofgem monthly wholesale market indicators and adjusted to 2025 values using UK CPI (ONS) 2026 data covers January to July 2026 and is sourced from ONS, System Average Price (SAP) of gas. Forward looking assumptions from Transira Energy – Powering Britain: A comparison of policy pathways to 2050 (July 2026) based on a blend of market futures (as of May 2026) and DESNZ – Fossil fuel price assumptions: 2025 (Scenario B), adjusted to 2025 values using UK CPI (ONS)

^[71] Onward analysis. 2022 CfD generation sourced from Low Carbon Contracts Company, CfD Historical Data dashboard. British electricity demand sourced from NESO, Historic Demand Data 2022.

^[72] Transira Energy, Powering Britain: A comparison of policy pathways to 2050 (July 2026)

^[73] Onward analysis. Calculation estimates gas consumption difference between APP and BAU in 2040 based on unabated gas and CCUS electricity generation for both scenarios in 2040. Gas price spike relative to 2040 forecast price is based on average gas price for 2022 (ONS System Average Price of Gas) adjusted to 2025 values using UK CPI (ONS).

^[74] Transira Energy, Powering Britain: A comparison of policy pathways to 2050 (July 2026)

^[75] DESNZ, Accelerating electricity transmission network deployment: Electricity Networks Commissioner’s recommendations, principal areas of recommendation.

^[76] Transira Energy, Powering Britain: A comparison of policy pathways to 2050 (July 2026)

^[77] Dieter Helm, Cost of Energy Review, 25th October 2017, page 47.

^[78] Transira Energy – Powering Britain: A comparison of policy pathways to 2050 (July 2026) Annual cost differences have not been pro-rated for 7% lower cumulative electricity consumption under APP.

^[79] Transira Energy – Powering Britain: A comparison of policy pathways to 2050 (July 2026) Annual cost differences have not been pro-rated for 7% lower cumulative electricity consumption under APP.

^[80] Transira Energy – Powering Britain: A comparison of policy pathways to 2050 (July 2026) Marginal system integration costs calculated as the difference in cumulative network, balancing and ancillary services system costs between BAU and APP, divided by the difference in cumulative wind and solar generation between the two scenarios. System cost categories have been pro-rated for 7% lower cumulative electricity consumption under APP. Levelised cost assumptions are based on DESNZ – Electricity generation costs 2025 and refer to averages from 2030 to 2050. Offshore wind levelised costs assume an 85% / 15% mix of fixed-bottom and floating offshore wind.

^[81] NESO, Calculation of the Generator TNUoS Adjustment Tariff for the purposes of the Limiting Regulation (May 2026)

^[82] Ofgem, Derogations to facilitate earlier connection of generation – decision on interim approach (8th May 2009)

^[83] Transira Energy, Powering Britain: A comparison of policy pathways to 2050 (July 2026)

^[84] The Royal Academy of Engineering, Nuclear Lessons Learned (October 2010), page 13.

^[85] DESNZ, Press release, Sizewell B power plant given lifetime extension to 2055 (8th July 2026)

^[86] Transira Energy, Powering Britain: A comparison of policy pathways to 2050 (July 2026)

^[87] Transira Energy, Powering Britain: A comparison of policy pathways to 2050 (July 2026)

^[88] DESNZ, Traded carbon values used for modelling purposes, 2025.

^[89] Onward analysis. Historic data (1990-2025) from DESNZ, Provisional UK greenhouse gas emissions statistics 2025 – data tables – Table 1a. Forecast emissions under BAU and APP from Transira Energy – Powering Britain: A comparison of policy pathways to 2050 (July 2026) 2025 to 2027 data based on linear extrapolation from Onward.

^[90] Hansard, Climate Change, Volume 662 debated on Monday 24 June 2019.

^[91] The Climate Change Act 2008 (2050 Target Amendment) Order 2019 – Explanatory Note

^[92] The Climate Change Committee, The Seventh Carbon Budget, Advice for the UK Government (February 2025). Page 300 assumes that 25% of meat and 20% of dairy is replaced by lower carbon foods by 2040. It is stated that “This reduction in meat and dairy goes beyond the existing long-term consumption trend”

^[93] Section 29 of the Climate Change Act 2008 defines UK emissions on a territorial basis – as emissions of a greenhouse gas “from sources in the United Kingdom”

^[94] Onward analysis. Territorial emissions sourced from DESNZ, Provisional UK greenhouse gas emissions statistics 2025 – data tables – Table 1a. Consumption emissions sourced from the Department for Environment, Food & Rural Affairs (DEFRA), Carbon footprint for the UK dataset, 1990 to 2023. Both datasets are indexed so that 1990 levels equate to 100.

^[95] Onward analysis. Assumes average electricity system carbon intensity of 92g CO2/kWh in 2050 (Transira Energy – Powering Britain: A comparison of policy pathways to 2050) and Onward technology assumptions of 8% losses in transmission and distribution, heat pump seasonal performance of 3.0 vs. gas boiler efficiency of 85%.

^[96] Onward analysis. Assumes average electricity system carbon intensity of 92g CO2/kWh in 2050 (Transira Energy – Powering Britain: A comparison of policy pathways to 2050) Onward technology assumptions of 8% losses in transmission and distribution, 40 miles per gallon for a petrol vehicle using normal biofuel blend (2.069 kg of CO2e/litre – DESNZ, Greenhouse gas reporting: conversion factors 2025) and EV efficiency of 3.5 miles per kWh.

^[97] Onward modelling. 2027 base system costs are established for electricity and gas based on the Q3 2026 Ofgem price cap. Electricity 2027 base system costs reflect the price cap, with £14 of transmission cost increases and the full cost of the Renewable Obligation added back. Gas bills are modelled to decline by applying the Transira modelled gas price curve (Transira Energy – Powering Britain: A comparison of policy pathways to 2050) to the direct fuel cost proportion of the Ofgem price cap. Electricity bill forecasts apply the Transira system cost index for BAU and APP to 2027 base system costs, with no impact assumed on supplier costs, supplier profit or debt related costs. Heat pump savings assume 85% gas boiler efficiency, heat pump seasonal performance factor of 3.0 in 2027, rising to 3.5 by 2050. Electricity standing charge is assumed at 75p/day in real terms and savings assume disconnection from the gas system. Charging VAT at 0% for domestic electricity is not a policy assumption and is shown for illustration purposes only.

^[98] Transira Energy – Powering Britain: A comparison of policy pathways to 2050

^[99] Onward analysis. Onward assumes 8% power losses in transmission and distribution, 3.5 miles per kWh for an EV and 6900 average annual mileage per ICE car, assuming 35:65 diesel to petrol ICE fleet mix. (2024 National Travel Survey, Department for Transport statistics, table NTS0901a) Existing base assumed to be 36.7m registered UK cars (SMMT data)

^[100] Onward analysis. Assumes 9.8 MWh of thermal heating demand per household, derived from 85% efficient gas boiler and 11.5 MWh of gas consumption (Ofgem typical consumption values prior to July 2026). Heat pump seasonal performance factor of 3.0 and 8% power losses in transmission and distribution and 23 million gas boilers in the UK (Uswitch, UK boiler statistics 2023)

^[101] Onward analysis. Assumes 2.069 kg of CO2e per litre of petrol and 0.18296 kg of CO2e per kWh of natural gas (DESNZ, Greenhouse gas reporting: conversion factors 2025) 2025 territorial greenhouse gas emissions of 366.6 million tonnes of CO2e (DESNZ, 2025 UK greenhouse gas emissions: provisional figures – data tables, Table 1a)

^[102] The Times, Rush to buy portable air conditioner units in heatwave empties shelves (10th July 2026)

The post Firm Foundations: The case for cheap and reliable power appeared first on Onward.

Onward is developing an implementable energy strategy for a future incoming government with the goal of achieving UK energy abundance, prioritising affordability, security and a market-led approach towards energy supply.

The first report in this series examines the suite of policy costs imposed by the state at various stages of the supply chain. This includes taxes, levies and regulations applying to UK energy producers, which constrain overall supply. It also includes policy costs that apply at the supplier stage, including network costs, subsidy mechanisms for renewables investors and social schemes, which end up passed through to consumers through bills. Finally, it includes taxes and carbon pricing that increase the cost of energy for consumers, particularly industrial users of energy.

Britain has among the highest industrial energy costs in the world, and household bills are driving inflation, harming living standards and contributing to poverty. Meanwhile UK terrestrial decarbonisation has been extremely rapid and, on its own terms, successful, with emissions halving since 1990.¹ Unfortunately this has been achieved at least in part by industrial offshoring, and “austerity” – that is, households using less energy² and businesses engaging in less economic activity. This is not the right way to achieve net zero and, in the case of emissions that are simply moved offshore, does nothing to benefit the planet.

Energy consumption per capita is one of the strongest correlates of per capita growth and of living standards available in historic global data.³ It is simply not possible for an economy to flourish without energy abundance, and demand from future technologies will only require more energy, not less. By pursuing unilateral energy disarmament, the UK risks consigning itself to falling behind for limited environmental gain.

This is a policy choice. But an alternative approach is possible – and necessary. This first report in Onward’s series reveals where the state adds unnecessarily to energy costs for households and businesses, and identifies where policy-driven costs could be stripped back immediately.

Foreword

There is no such thing as a high-growth low-energy country. Cheap, reliable, abundant energy is why the United Kingdom has prospered for two centuries. The Industrial Revolution was fuelled by our plentiful supply of coal and Mrs Thatcher’s boom years from our oil and gas resources in the North Sea.

We now stand a quarter through a new century, living with the consequences of a dangerous experiment. One which has waged a crusade against necessary parts of our energy system, which has chosen a system that needs to build ever more capacity for less productivity and which has distorted the market to benefit energy developers over consumers. As the energy-hungry growth opportunities of AI and an increasingly dangerous world zooms into closer focus, it is time for us to bring energy realism back to the debate.

This is seen most clearly in our electricity policy which has led to Britain having the most expensive industrial electricity in the developed world. Whilst this has been done in the name of climate change, it is in fact hindering not helping the situation. Moving people on to electricity to heat their homes or run their cars is one of the key planks of decarbonisation, and yet pursuing the cleanest electricity in the world no matter the cost is precisely what is driving up bills. There could be no better achievement for decarbonisation than to make electricity significantly cheaper, even if it wasn’t 100% clean. This is a clear and indisputable truth but one which net zero ideologues refuse to engage with.

The Labour Government blames soaring energy costs on wholesale prices, but this is not borne out by the facts. This report from Onward makes clear that taxes, levies and renewables subsidies imposed by the state now make up a third of consumer bills. Stripping out carbon taxes on gas power alone – which have soared under Labour and are due to rise even further – would cut families’ electricity bills by 10% tomorrow.

There is a wider question at hand. The UK is responsible for just 1% of global emissions. If a fanatical approach to net zero leaves us poorer, more reliant on imports, with higher energy costs and fewer jobs, which of the countries that make up the 99% of emissions – still rising around the world – will want to follow our lead? The UK has done more than any other major economy to cut emissions, but we have become a warning rather than an example to the rest of the world. For the UK to have any impact at all, ministers must prioritise the cheap electricity and energy resilience we need for industry to succeed and to improve living standards.

Axing the Carbon Tax, backing the North Sea, streamlining nuclear regulations that put the needs of newts over our need for reliable, land-dense energy, and being honest about the true cost of renewables would be a start.

I welcome Onward’s work on this brand new energy commission to bring energy realism back into the debate. This first report illustrates where the state adds unnecessary costs onto bills. That is a welcome first step towards an energy system which puts cheap, reliable energy first.

~ Rt Hon Claire Coutinho MP

Shadow Secretary of State for Energy Security & Net Zero

Executive Summary

The cost of energy is one of the most important factors holding back the British economy. It has been the main driver of the rising cost of living, majorly accelerated UK deindustrialisation and is generating a major political backlash.⁴ Attitudes towards net zero among voters are hardening, with a widening appreciation of how rapidly Britain has unilaterally decarbonised, in contrast with big polluters like China. Britain has been left with among the highest industrial electricity costs in the world.

While decarbonisation to tackle climate change may have had laudable intentions, it has been achieved in highly damaging ways. Britain has eradicated coal as a dispatchable source of energy, and reduced its domestic supply of gas by punishing North Sea production, before it has either the renewable energy infrastructure or the grid capacity to complete full energy transition. In fact, wind and solar generators are currently paid to take power off the grid in periods of excess capacity. Britain has failed to invest in adequate nuclear power, lagging far behind France, where nuclear energy provides for three-quarters of electricity demand. Britain’s overall energy supply has been reduced without a plan to replace it.

Cutting domestic emissions has been achieved to a large degree by deindustrialisation, which has resulted in emissions-generating economic activity being moved offshore. Net zero has therefore been pursued on the basis of cutting energy use, rather than achieving an abundant renewable supply. The process of “carbon leakage”, where emissions are simply moved overseas, damages Britain’s economy while doing nothing to lower emissions globally. This not only gets the balance wrong between environmentalism and economic security; it is actively irrational.

Britain is highly gas dependent. Advocates of a full and swift transition are unrealistic: 85% of British households still rely on gas for home heating, it remains vital for industrial processes, and the grid relies on gas-generated electricity as a firm, dispatchable energy source 97% of the time. Failure to produce enough gas domestically has left Britain highly import-exposed, with half of demand met by expensive and carbon-intensive imports of liquid natural gas (LNG). North Sea Production has been penalised, even as the UK continues to import gas from the same sites from Norway.

As well as driving gas scarcity, UK policy choices actually make bills higher directly, too. Onward analysis shows that through taxes, levies and subsidy costs passed through to billpayers alone, the state adds 30% – or £285 – to a typical household.⁵ And the state imposes costly carbon taxes and VAT on gas generators. These taxes add around 40% to the wholesale cost of gas, and 15% to the average family’s bill.⁶ These taxes on electricity generation could be cut almost immediately. This would make gas power cheaper – a vital first step in making electrification and decarbonisation of the wider economy affordable.

Finally, as well as taxing energy producers and imposing levies on suppliers, the state taxes the consumption of energy by businesses through carbon pricing and the Climate Change Levy. These policies are designed to incentivise industrial decarbonisation, but the reality is that they drive up electricity costs for businesses to unsustainable levels, leading to offshoring and industrial collapse.

The UK needs a radically different approach to energy policy, prioritising security of domestic supply and affordability for businesses and families. This will require more nuclear power, an economically sustainable and competitive renewables sector, and more abundant gas for the foreseeable future. It will also require reform of energy procurement, pricing and the auction system. Onward’s energy commission will address all these problems in turn.

This first report focuses on fiscal policy choices that add to energy costs. None of the recommendations require new infrastructure, new investment by government or by the private sector, or any other physical change. Rather, they target additional, imposed costs in the energy system that a future government seeking to prioritise affordability and security could remove or radically reform.

1) How the state increases costs for energy producers

Energy affordability is a function of supply

In a well-functioning, abundant energy market, greater supply should enable lower energy prices. This is the basic logic of supply and demand, which underpins the efficient functioning of markets.

Some have suggested that the solution to energy scarcity and affordability is reducing demand. And demand has been falling: since 2020, the National Energy System Operator’s (NESO) Future Energy Scenarios (FES) have constantly projected sharp and sustained rises in demand for energy, but in reality demand has continued to stagnate or fall in every year those projections were made.⁷

This should, however, be seen as a problem rather than something to be welcomed. Falling demand for energy is a sign of reduced economic dynamism, investment and output. It is also a sign of deindustrialisation. Falling demand is itself a function of the limits on supply, which is the primary cause of unaffordable energy.⁸

Britain is experiencing energy scarcity

The UK has reduced overall energy use per person and electricity production more than any other G20 country. UK electricity production per head is likely to fall below the world average.⁹ This leaves the UK below Iran, Libya, Bulgaria and Belarus.¹⁰

Energy consumption per capita is affected by a range of factors, not only the cost and scarcity of energy. Overall economic performance also affects industrial activity and output levels, for example, and deindustrialisation due to factors other than energy prices will cause overall energy consumption to fall.

However, when compared to other members of the G20, including economies with a similar profile to the UK, it is clear that the UK has reduced its per capita energy consumption more than its peers, including France, Italy, Germany, Japan, Canada, and the United States.¹¹

Figure 1: Change in per capita energy use (%) in G20 economies, 2003-2023

Source: Our World In Data¹²

Figure 2: UK energy consumption per capita (kWh), 1965 – 2025

Source: World Bank¹³

Gas scarcity and grid limitations both drive lack of supply

Given the constraints on Britain’s grid capacity, increasing overall supply is not completely straightforward. How energy supply feeds through into consumer and industrial prices is also determined in part by Britain’s energy auction system.

In this system – the “merit order” – the most expensive energy source on a per unit basis (usually gas) sets the marginal price of electricity, after the less expensive forms (usually nuclear and renewables) have supplied what they can. If Britain had a much larger nuclear component in the energy mix, UK electricity prices would be much lower.¹⁴ But due to the lack of sufficient nuclear, wind and solar power to meet demand, gas is still needed and sets the marginal wholesale electricity price 97% of the time.¹⁵ Britain is therefore more beholden to gas prices than France, where nuclear generation sets relatively stable prices, or Germany, which historically has a mix of coal, gas, and hydro setting prices.

Worse still, the government makes wholesale gas more expensive by imposing taxes and carbon pricing on gas generators, even though gas remains an essential part of the electricity generation system.¹⁶

Limitations on grid capacity are another factor increasing the price of energy. Curtailment payments are currently made to renewable energy generators to reduce their output as the network cannot physically transmit the power they are producing.¹⁷ This is a function of the inherent limitations on grid capacity and the fact that wind and solar power require significant additional transmission infrastructure. And policy costs such as renewables levies and Contracts for Difference add to bills on top of the wholesale price, supplier costs, the cost of grid upgrade and transmission and supplier margins.

Britain is highly dependent on imports

The UK spent the best part of 25 years as a net exporter of energy, from the 1980s through to 2004.¹⁸ Throughout this period UK energy prices steadily declined in real terms.¹⁹ This was due at least in part to policy-led optimisation of exploitation of the North Sea, and also to a greater supply of reliable, dispatchable power. The North Sea output supplied well over half of the UK fossil fuel demand for much of this period.²⁰ Production peaked in 1999 marking the high point of the basin’s contribution to national energy supply.

However, the UK moved to being a net importer in 2004. Gas and oil comprise 90% of energy imports. This was due in large part to reductions in the output of the North Sea, and the switch from domestically mined coal to natural gas dominating within the UK energy system. The switch to gas meant the surge in consumption outpaced domestic production, and the phase out of old nuclear power stations and of all coal power reduced overall baseload capacity. Prices went on to double from the early to the late 2000s.²¹ And separately from gas, the UK once again became a net importer of electricity in 2023, after a brief period as a net exporter.²²

Extraction costs in the North Sea had risen due to natural geological depletion and it being a mature basin. However, the fiscal and policy environment also changed. The Supplementary Charge on North Sea profits was introduced by Labour in 2002 and increased to 20% in 2006, together with tighter environmental rules and mandatory public reviews of the impact of new site licensing.²³

Figure 3: UK energy net exports, 2000-2024

Source: International Energy Agency²⁴

The UK once benefited from a plethora of energy sources. North Sea oil and gas, a robust fleet of nuclear power stations, and dispatchable power sources including coal all contributed to greater supply and competitive energy prices.²⁵ But today the UK is a net importer of energy and faces higher energy costs than our international comparators.²⁶

Figure 4: UK generation capacity, 2000-2024

Source: International Energy Agency²⁷

Climate policies have targeted producers as revenue sources

Climate objectives have now been enshrined into almost every component of energy policy. These measures were in part intended to internalise the externalities of carbon emissions. The UK has already made large reductions in onshore emissions, which are down 54% on 1990 levels.²⁸

Britain has completely eliminated its coal production capacity, unlike Germany or China, but has not followed countries like France in developing a comprehensive nuclear or renewable replacement energy mix.²⁹ Nuclear power provides for more than 70% of France’s energy needs.³⁰

But the cumulative effect of these climate policies has been to disincentivise energy production and consumption by adding costs, reducing domestic supply, and increasing reliance on imported energy, while claiming tax revenues from domestic production. The fiscal targeting of North Sea oil and gas companies through windfall taxes like the Energy Profits Levy has been motivated partly by the drive towards decarbonisation and partly by a goal of raising additional revenue – a “cash cow” – for the state.³¹

Eliminating coal without a ready alternative has left the UK particularly reliant on gas, yet successive governments have consistently sought to disincentivise oil and gas production, consumption of gas and gas power generation through taxes and carbon pricing.³²

Figure 5: Carbon emission intensity by country

Source: Ember, Electricity Data Explorer³³

Britain was hit harder by the gas shock due to policy choices

The 2021-22 shock to gas prices arising from the Ukraine war hit the UK disproportionately because policy had removed alternative energy sources. The UK’s last coal plant closed in September 2024, removing a flexible, dispatchable source of electricity.

In contrast, China’s coal output reached record levels in 2025, hitting 4.83 billion tonnes, even as it has acted as a major renewables investor and manufacturer.³⁴ Coal accounts for 23% of German electricity production.³⁵ Meanwhile the UK has eliminated coal without a secure, reliable and affordable alternative of baseload power. And this trend is not isolated, as the UK has also reduced its nuclear capacity.

Figure 6: Coal-based generation of electricity in the UK, 2000-2024

Source: DESNZ, 2025³⁶

Figure 7: Coal production, 1990 – 2025

Source: DESNZ, 2025³⁷

Figure 8: Total operable nuclear capacity, 1970-2025

Source: World Nuclear Association³⁸

The UK’s domestic capability to produce its own gas is rapidly diminishing; North Sea output is declining despite ongoing demand.³⁹

As a result, the UK has become increasingly reliant on imported liquefied natural gas (LNG) rather than expanding domestic production. The North Sea Transition Authority anticipates that there will be an annual 11% decline in domestic production of offshore gas, despite natural gas still being used to 2050 for electricity and hydrogen production.⁴⁰

This reliance on imports and exposure to international gas prices is the reason the UK was especially exposed to the gas price shocks resulting from Russia’s invasion of Ukraine.

Figure 9: Pipeline imports, LNG imports and pipeline exports of natural gas, 2000-2024

Source: DESNZ⁴¹

Figure 10: Natural gas exports to the UK by country, 2000-2024

Source: DESNZ⁴²

Figure 11: UK industrial electricity prices and comparator countries, 2021-2022

Source: DESNZ⁴³

An overall reduction in energy supply has been exacerbated by the reduction in the share of dispatchable power within the overall energy mix.

Figure 12: Electricity generated by fuel type, 2000-2024

Source: DESNZ⁴⁴

Government policies have penalised investment the North Sea

Historically the North Sea has produced volumes of oil and gas equivalent to well over half of UK fossil fuel demand, and this remained broadly true up until 2024.⁴⁵ But these reserves are rapidly depleting, alongside production, and as a consequence expenditure on decommissioning installations has hit a record high. In 2024 decommissioning expenditure reached £2.4 billion and £27 billion is estimated to be spent on decommissioning in the North Sea between 2023 and 2032.⁴⁶

However, policy more than geology is reducing North Sea investment and exploitation. The North Sea is a mature basin, but the current rate of depletion is exacerbated by the UK’s domestic net zero agenda. There are around 280 active oil and gas fields today, but 180 of these are expected to cease production by 2030.⁴⁷ This reflects regulated decline exceeding natural decline, as policy is determining output, rather than resources. A study by Offshore Energies UK estimated that 7.5 billion barrels of oil and gas could be extracted from the North Sea, 3.2 billion more than recent Government estimates, meeting half the UK’s oil and gas needs.⁴⁸

Fiscal disincentives to further North Sea production, together with refusal to grant licenses for new site exploration (discussed further below) have exacerbated extensive decommissioning. Decommissioning costs are subject to a tax rebate, which can make decommissioning more financially attractive than investing in more capacity.⁴⁹ However, as the process is still expensive enough, it tends to become irreversible.

Historically the North Sea fiscal regime in the form of Petroleum Revenue Tax (PRT) was designed to capture revenues rather than disincentivise exploitation, applying to fields approved before 16th March 1993 before being zero-rated in 2016.⁵⁰ Oil allowances and safeguard provisions would ensure less profitable sites would pay almost none of the tax, and capital allowances allowed companies to deduct more than 100% of their investment costs from taxable PRT profits.⁵¹

By contrast, the current North Sea fiscal regime, composed of Ring-Fenced Corporation Tax, the Supplementary Charge and the Energy Profits Levy, is designed around net zero objectives, with the exception of the latter originally being to capture windfall profits, and now taxes ordinary profits at headline rates of 78%.⁵²

The two regimes differ not only in structure but in purpose: PRT aimed to collect revenue from production profits by capturing resource rents; the current regime is reducing the rents and profit incentives of production in the North Sea as a whole.

The fiscal impact to reduced domestic North Sea production then compounds: the decommissioning rebates themselves imply a fiscal cost to the Treasury, and once completed further tax revenues from profits then stop.

The North Sea still has significant potential

North Sea output is in serious decline

Since 1999, output has fallen by more than 65%.⁵⁹ Some of this is an inevitability of a mature basin, but the pace of contraction reflects policy choices. Today, North Sea oil and gas accounts for less than 15% of UK electricity generation (once gas-fired generation is considered).⁶⁰

While UK exploitation is in decline, Norwegian oil and gas companies such as Equinor actively exploit North Sea sites on the UK side of the border.⁶¹ The UK also relies on importing gas from Norway that has been extracted from Norwegian territory sites. This compounds UK import dependency while actually increasing consumed emissions, since gas imports are more carbon intensive.

And this shrinkage will only continue; in 2024, for the first time since 1964, no new oil wells were drilled in the UK’s North Sea territories.⁶² This is a result of the regulatory and fiscal framework that has progressively undermined the commercial viability of domestic production. Meanwhile, the UK retains its gas intensive infrastructure despite declining supply. In direct contrast, Norway completed 49 exploration wells and made 21 discoveries on the Norwegian continental shelf in 2025 alone, up from 42 exploration wells in 2024.⁶³

Punishing producers – the Energy Profits Levy (EPL)

Introduced in 2022 to capture genuine windfall profits arising from exceptional price spikes, the EPL now targets windfalls that no longer exist. The levy has instead become a standing penalty on production. From 1 November 2024, the EPL rate increased from 35% to 38%, alongside the removal of its principal investment allowance.⁶⁴ The abolition of the 29% investment allowance for qualifying expenditure has significantly weakened incentives to invest in new developments or life-extension projects.

The impact on investment of these policy decisions is material. Offshore Energies UK forecasts that the combined effect of a 78% headline tax rate and the removal of EPL investment allowances will reduce viable capital investment from £14.1 billion to just £2.3 billion between 2025 and 2029.⁶⁵

By comparison, Norway’s fiscal regime allows companies to recover up to £78 for every £100 of qualifying expenditure, delivering total relief of around £46.25 under comparable assumptions.⁶⁶ The contrast highlights the extent to which the UK regime has become internationally uncompetitive and has intentionally undermined production.

Ring-Fenced Corporation Tax and the Supplementary Charge

The structure of these two taxes further elevates the tax burden on North Sea operators. Ring-Fenced Corporation Tax applies a 30% rate to offshore profits and prevents companies from offsetting losses from other UK business activities. The Supplementary Charge adds a further 10% on adjusted profits while disallowing deductions for finance (borrowing) costs.

Together these measures operate as structurally higher and less flexible versions of standard corporation tax, ensuring that offshore extraction is consistently taxed more heavily than most other forms of economic activity, even after capital allowances are taken into account.

Figure 13: Tax rates on oil and gas producers, 1973-2025

Source: Institute for Fiscal Studies⁶⁷

The cumulative effect of this regime means that investment is discouraged, production declines faster than geology requires, and domestic energy supply is progressively replaced with imports.

Bans on new North Sea exploration

The current government’s licensing regime is fundamentally misaligned with its tax and regulatory framework. The government has introduced Transitional Energy Certificates (TECs) to facilitate the continuity of the UK’s existing offshore oil and gas sector. Under this framework, TECs are effectively a licensing regime that will enable limited production on or near existing fields, provided activity does not involve new exploration, is part of or links back to existing fields and infrastructure, and is necessary to sustain production through the natural decline of the basin.⁶⁸

Although this approach aligns with the government’s commitment not to award new exploration licences, reflecting climate goals, it perpetuates reliance on more polluting gas imports. The result is a contradictory policy environment: companies are encouraged to maintain output in theory, but face tax rates and general bans on new exploration that make doing so increasingly uneconomical in practice. This inconsistency further suppresses investment and accelerates decline beyond what geology alone would dictate.

An even more extreme approach has been taken towards onshore fracking, which has been completely banned in the UK since 2019. This has for the foreseeable future cut off any possibility of expanding land-based domestic shale gas supply, regardless of technological developments or potential investment appetite.⁶⁹ This will be explored further in a later report.

North Sea viability is now in question

Oil and gas revenues fell from £6.1 billion to £4.5 billion in 2024–25, despite the continuity of the Energy Profits Levy (EPL); evidence that the Levy is accelerating decline in the sector and costing the Treasury billions rather than raising additional revenue.⁷⁰

Projections indicate that decommissioning spending will exceed commercial capital investment by North Sea oil and gas companies by 2028. The EPL has been responsible in part for the cessation of production decisions being brought forward, resulting in higher decommissioning expenditure in the short term.⁷¹

Carbon taxes and pricing add to the cost of gas

In addition to the taxes and regulatory restrictions on new oil and gas supply, the UK also imposes additional carbon taxes which add to the wholesale cost of gas, including gas generation of electricity.

These additional taxes are Carbon Price Support (CPS) and the UK Emissions Trading System (ETS). Originally intended to disincentivise the use of coal to cut domestic carbon emissions, these taxes now remain an additional burden on gas supply – despite the UK’s high degree of exposure to gas.

Gas-fired generation remains essential for system balancing, meeting peak demand, compensating for renewables intermittency and ensuring resilience, but it is simultaneously penalised through additional taxes and carbon pricing.

Carbon Price Support (CPS) – an obsolete tax

The objective of CPS has largely been achieved: coal has been eliminated from the grid. Ratcliffe on Soar, the UK’s last coal fired power station, closed in September 2024.⁷² But CPS remains in place and now functions primarily as a tax on gas-fired generation. Because gas is the UK’s marginal generator, CPS feeds directly into the wholesale marginal price in the day-ahead market.

This means the tax now raises the cost of every unit of electricity produced, including electricity from sources that pay no CPS at all, namely the renewables intending to lower energy costs, by increasing the price set by gas.

The Centre for British Progress estimates that CPS adds approximately £6.60 per MWh to the cost of gas-fired electricity.⁷³ This raises costs for industry, households and the public sector indirectly through the wholesale market. As coal no longer burns in the UK, CPS no longer drives fuel-switching; instead, it increases the cost of dispatchable generation, making the UK more exposed to volatility in global gas markets and raising the overall price floor of the system.

The UK Emissions Trading System (ETS) – a high and rising burden

This system was designed to use market forces to incentivise lower-carbon technologies for energy production by gradually limiting permitted emissions and subsequently increasing costs. In theory, the ETS should reward efficient producers and discourage high-carbon alternatives.

In practice, it interacts with CPS to create a double carbon-pricing burden on gas producers. The scheme now plays a more explicit role in delivering the Government’s net zero trajectory than in ensuring energy security or maintaining adequate domestic supply.⁷⁴

The Government has announced its intention to align the UK ETS more closely with the EU scheme, a move that is expected to push carbon prices higher.⁷⁵ The EU emissions trading scheme has been trading approximately 50% higher than the UK’s comparative scheme for the last two fiscal years.⁷⁶

Equalisation with the EU scheme may achieve marginal emissions reductions on paper, but it risks higher costs for British industry; increased dependency on imported energy; carbon leakage as domestic production falls; and ultimately higher global emissions as the UK displaces relatively efficient domestic gas with higher-carbon LNG imports. EU ETS linkage would also make scrapping UK ETS “difficult if not impossible,” according to the Centre for Policy Studies, as both sides must maintain emissions trading systems.⁷⁷

Data from 2022 shows imported emissions were at their highest level since 2007.⁷⁸ Given that the UK will rely on gas for decades even as the grid decarbonises, an ETS that suppresses domestic production without credible substitutes may simply raise costs and undermine energy security without delivering meaningful global emissions reductions.

The cost of carbon taxes on household bills

CPS and UK ETS cost the average UK household, assuming that that household consumes 3,100 kWh of electricity annually, around £94 per year comprising 10% of its annual energy bill.⁷⁹ Carbon taxes therefore increase wholesale prices by around 40% relative to the underlying pre-carbon fuel cost.⁸⁰ Of this £96 uplift, around a fifth of the cost is due to CPS with the rest a result of UK ETS, meaning that the cost of each is approximately £22 and £72 per household respectively.⁸¹

Figure 14: Average Annual 3,100 kWh Household Electricity Bill by Component (£), 2025 Financial Year

Source: Onward analysis, Electricity Bills UK⁸² & Scrap Carbon Taxes⁸³

Figure 15: Average Annual 3,100 kWh Household Electricity Bill by Component (%), 2025 Financial Year

Source: Onward analysis, Electricity Bills UK,⁸⁴ Scrap Carbon Taxes⁸⁵

Impact of the Carbon Border Adjustment Mechanism (CBAM) on refineries

The UK’s downstream energy infrastructure is also under strain. Since 2024, the number of operational refineries has fallen from six to four, following the closure of Grangemouth in Scotland and the Prax refinery at Lindsey. These refineries are critical national assets, producing most of the fuels required for transport and heating, including petrol, diesel, jet fuel, fuel oil, and heating oil. The remaining facilities have over one million barrels per day of refining capacity.⁸⁶

The exclusion of refining from the UK’s Carbon Border Adjustment Mechanism (CBAM) compounds this problem. CBAM is intended to prevent carbon leakage by imposing charges on imports produced under weaker environmental standards.⁸⁷ The most important input for refineries is gas, which emits carbon and is therefore subject to the UK ETS. Not only must refineries pay for energy, but also their carbon costs. Without the protection against carbon leakage through offshoring provided by CBAM, UK refineries face structurally higher costs than international competitors, increasing the risk of further closures and deeper import dependence for refined fuels.

Pursuing energy diversification by punishing domestic producers

The UK’s strategy to diversify its energy mix is grounded in legitimate objectives: reducing carbon emissions, hedging against fossil fuel price volatility, improving energy security, and transitioning away from finite resources. These goals are not inherently in conflict with maintaining domestic energy production.

But a successful transition does not require the accelerated decline of domestic supply. On the contrary, domestic production can reduce global emissions by displacing imported LNG, which typically has higher lifecycle emissions. A balanced energy system, combining gas, nuclear, renewables, storage, and dispatchable capacity, depends on domestic producers remaining commercially viable throughout the transition.

Instead the UK has constructed an energy policy framework centred on reducing domestic emissions, suppressing energy use, and increasing prices to change behaviour, while assuming other countries will follow a similar path. The outcome has been a system in which abundance has been replaced by scarcity, firm capacity by intermittency, and stable investment by accelerating decline.

Prices have risen while capital investment has collapsed. Consumers bear higher costs, energy security has weakened, and domestic producers face growing disincentives to invest or remain in the UK market. The result is not a smooth transition, but a more fragile, more expensive, and more import-dependent energy system.

Recommendations

Abolish the Energy Profits Levy (EPL). Fiscal policy for oil and gas producers should be a single, stable regime. Windfall taxes reduce domestic supply and increase import dependence while generating uncertainty for investors.

Normalise corporate tax for energy producers. Align the corporation tax regime for oil and gas producers with that for the rest of the UK by abolishing Ring-Fenced Corporation Tax.

Abolish the Supplementary Charge. Overlapping taxes create complexity and perverse incentives. Corporation Tax is already charged on profits not revenues.

Commit to a minimum fiscal stability period. Arbitrariness and uncertainty are ruinous for investment decisions that are by definition multi-year and involve commercial risk. While no parliament can bind its successors, a stable fiscal framework should be enshrined in current law, ruling out retrospective tax changes and one-off windfall levies.

Resume regular, predictable licensing rounds. End the ban on further oil and gas exploration and remove approvals from short-term political decision-making, treating licensing as an administrative decision based on safety and mainstream compliance requirements, not climate targets.

Remove climate targets from decisions over domestic supply. Targets currently written into law should not affect domestic producers. Restricting production does not reduce UK demand or UK carbon consumption, but it does constrict supply and increase costs.

Abolish Carbon Price Support tax on gas generators. This tax was designed to disincentivise coal and has performed its role. An additional carbon tax on the power source that sets the marginal wholesale rate more than 90% is irrational and should be ended.

Abolish carbon pricing via the Emissions Trading System (ETS) entirely for gas generators. This represents a form of double taxation on gas, and feeds directly through into wholesale electricity prices. Gas-based electricity generation is a small percentage of UK overall emissions.

Apply equal regulatory and compliance costs to imports. Where domestic oil and gas producers face environmental or adjustment mechanisms such as environmental offset obligations, these should apply equally to those exporting carbon-emitting energy to the UK so there is a level playing field. UK refineries should be protected by CBAM.

Designate North Sea oil and gas as Critical National Infrastructure within the National Security and Investment Act 2021. Energy producers provide a vital role in the UK energy supply chain and in UK energy security. They should be designated as security assets within the Government’s national Industrial Strategy and feature in overall supply chain resilience planning.

Remaining sector-specific taxes should have fixed sunset clauses. All taxes and regulations that specifically target oil and gas producers should be sunsetted so they expire unless Parliament explicitly renews them.

“Full expensing” should apply for oil and gas producers, replacing more limited sector-specific allowances. The commercial risks associated with capital investment are considerable for investors and oil and gas producers should benefit from being able to deduct 100% of qualifying capital expenditure against corporation tax in year 1.

2) How state-imposed costs on energy suppliers affect bills

In addition to taxing production the state imposes various taxes and levies on energy suppliers, which are the companies that buy energy and then sell to consumers through household and commercial bills.

These levies are passed on to households. Wholesale costs only represent 34% of a typical bill. Businesses are largely protected from levies, but their energy consumption is taxed in other ways, through carbon pricing and the Climate Change Levy, explained in Chapter 3. Carbon pricing and taxes are also levied on gas generators, which is reflected in the wholesale price of gas generated electricity when sold to energy suppliers.

Onward analysis shows that the combined effect of taxes on generators, policy levies and renewable subsidy mechanisms like Contracts for Difference (CfDs) is to add 30% – or £285 – to the average household’s energy bill.⁸⁸ Some of these charges, including for the Capacity Market, network charges and balancing costs, cover the cost of transmission, grid upgrade and maintenance and balancing capacity on the grid to ensure a continuous energy supply. Some of these – such as curtailment payments, when renewable generators are paid to switch off – are the result of long-term policy failure but are not a direct levy. Some are system requirements. Others are levies passed directly onto billpayers.

How policy costs affect the supplier stage

Supplier-side costs are additional energy costs administered by suppliers such as British Gas, Octopus Energy, and OVO Energy. While these are charged to and administered by energy suppliers, they are almost entirely paid for by consumers, as suppliers recover nearly all policy-related obligations from billpayers.

These costs therefore comprise a major component of household energy bills. These layers of levies and charges include network costs, subsidies for renewable technologies, charges for smart meters, home-efficiency schemes, and levies to fund major infrastructure projects such as the Sizewell C and Hinckley nuclear power stations.

Households are exposed to these costs but industries are better insulated. Energy-intensive industries (EIIs) are almost completely exempt in order to maintain global competitiveness and prevent carbon leakage, And from 2027 many small and medium manufacturers will also receive relief as part of the British Industrial Competitiveness Scheme (BICS). Small businesses are however often liable to pay these levies.⁸⁹

The exemptions will ensure that around 7,000 electricity-intensive businesses in manufacturing sectors like automotive, aerospace and chemicals will be exempt from levies such as the Renewables Obligation, Feed-in Tariffs, and Capacity Market charges (explained below), reducing their costs by up to £40 per MWh.⁹⁰

Additional costs have risen even as wholesale prices fall

While wholesale costs have been falling over the past few years, with the exception of 2022 and 2023 when they rose significantly as a result of the war in Ukraine and consequent gas crisis, supplier-side costs have risen significantly. This has led to household bills increasing rather than benefiting from falling wholesale costs. It is projected that generation subsidies, carbon taxes, and levies will cost the average household £285 in 2026-27, comprising nearly a third of the average household bill.⁹¹

Of these, three components, VAT, UK ETS, and Carbon Pricing Support — which together cost the average household £140, or about 15% of an average household bill – could be removed quickly from gas generators without significant domestic legal complications, though carbon pricing is linked to international climate agreements.⁹²

In spite of the Chancellor, Rachel Reeves, scrapping the Energy Company Obligation (ECO) from the end of this year and slashing the cost of the Renewables Obligation (RO), which is passed on to households, the non-wholesale, supplier-side costs are still projected to rise from £644 to £776 by 2030 for the average UK household.⁹³  Scrapping the Renewables Obligation completely along with Contracts for Difference and Feed- in-Tariffs would save the average household in 2030-31 £113 a year.⁹⁴

Figure 16: Non-wholesale costs and projections for the average 3.1 MWh UK household

Source: Electricity Bills UK⁹⁵

This is partially because of a projected increase in other renewables subsidies, including Contracts for Difference (CfDs). But it is also due to the introduction of new levies such as the Regulated Asset Base (RAB) model, which is used to fund the construction of Sizewell C, Carbon Capture Storage projects such as net zero Teesside, and new costs related to the British Industrial Competitiveness Scheme (BICS).

Full breakdown of costs passed on to consumers

The Renewables Obligation (RO)

The Renewables Obligation is the UK’s older subsidy for large-scale renewable energy projects, which the Chancellor announced in the November 2025 Budget would be re-indexed from the Retail Price Index (RPI) to the Consumer Price Index (CPI) and have around 75% of its cost moved into general taxation.⁹⁶ Although no new projects have been accredited since 2017, when the scheme began to be phased out, RO accreditations are valid for 20 years and so the levy continues to have an effect on consumer bills.

The RO requires electricity suppliers to purchase a certain share of supply from renewable technologies. To do this, renewable obligation certificates (ROCs) are issued to renewable energy producers, and suppliers must purchase these from the renewable generators in order to prove that a certain amount of electricity has been generated from a renewable source. If a supplier cannot provide enough ROCs, it must pay a “buyout” price for each ROC it is short.

As RO support arrangements expire, their impact on consumer bills will steadily decline. By 2037, all RO support will have ended, removing their effect on bills entirely. For the average 2025 household, ROs cost £102 and comprise 11% of the average household bill.⁹⁷ In 5 years, the cost was projected to fall to £68 and will comprise 6% of the average household bill. However, between 2026 and 2029 the Chancellor has said that the Exchequer will refund 75% of domestic RO costs. Therefore the cost will instead fall to £17 and 2% of the average household bill.⁹⁸

• Cost to Average 2025 Household: £102 (11% of household energy bill)
• Projected (Real Terms) Cost to Average Household 2030: £17 (2% of household energy bill)

Figure 17: Impact of Renewables Obligation on electricity bills for an average 3.1 MWh domestic household, 2019–2031.

Source: Electricity Bills UK⁹⁹

Feed-in-Tariffs (FiTs)

Feed-in-Tariffs (FiTs) are a legacy subsidy for small-scale renewables which pay people for generating their own renewable electricity through solar panels, wind turbines, and other small-scale renewable technologies. The FiT gives two payments: one for each unit of electricity generated, and another for any surplus exported to the grid. Energy suppliers make these payments and the cost is recovered through consumer bills.

The scheme has been closed to new installations since 2019, but as FiT contracts typically run for 20-25 years, existing participants will continue to receive payments until their contract expires. For the average 2025 household, FiTs cost £23 and comprise 2% of the average household bill. In 5 years, the cost is projected to rise to £26 and will comprise 2% of the average household bill.¹⁰⁰

• Cost to Average 2025 Household: £23 (2% of household energy bill)
• Projected (Real Terms) Cost to Average Household 2030: £26 (2% of household energy bill)

Figure 18: Impact of Feed in Tariffs on electricity bills for an average 3.1 MWh domestic household, 2019–2031.

Source: Electricity Bills UK¹⁰¹

The Supplier Obligation and Contracts for Difference (CfDs)

CfDs are the current subsidy mechanisms for large-scale renewable energy projects. CfDs were introduced in 2014, with projects and funding being allocated in allocation rounds held every few years. The latest – “AR7” – is the seventh round, which is taking place currently. The cost of financing CfDs is applied to energy suppliers and is called the Supplier Obligation.¹⁰²

During each CfD allocation round, the government sets an administrative strike price cap for each technology, which developers bid below. Each round has “pots” for different technologies: offshore wind, solar, and tidal, and contracts are awarded in order of lowest cost until the budget is used up. All winning projects in this pot receive the same strike price, which is determined by the highest-priced project needed to clear the auction.

Once set, this strike price is the guaranteed price per MWh for 15 years, adjusted each year for inflation from the 2012 benchmark. Once the contract is signed with the Low Carbon Contracts Company (LCCC), the government-owned arm’s-length body responsible for administering CfDs, the generator starts producing, the strike price is compared to a reference market price.

If the market price is higher, the generator pays the LCCC the difference, and if the market price is lower, the LCCC pays the generator the difference. The LCCC funds payments through a levy on electricity suppliers which are then transferred onto the consumers through bills.

As a result, CfDs and wholesale prices have an inverse relationship. When wholesale prices rise above the strike price, generators pay back the difference, reducing costs for consumers and resulting in “negative CfD” costs. This happened in 2022-23 when wholesale prices skyrocketed due to the Ukraine war.

The most recent CfD round – “AR7” – will increase electricity prices

For the next round of allocations, AR7, the maximum strike price is £113 per MWh – well above the average wholesale electricity price.¹⁰³ This higher strike price reflects rising supply chain and financing costs in the offshore wind sector, which makes up the majority of projects in AR7.

This will consequently lead to higher consumer bills as the LCCC, and subsequently the consumer, will have to pay more in order to top up to the strike price. Also, as more CfD-backed generation comes online and more contracts are signed, more electricity is paid for at these higher guaranteed prices so the combined overall cost of CfDs will increase.

The cost to households of CfDs

For the average 2025 household, CfDs cost £33 and comprise 3% of the average household bill. In 2030, the annual cost is projected to rise to £70 and will comprise 6% of the average bill. By 2030, the impact of CfDs on the average household’s bills is projected to rise by 176% compared to 2019.¹⁰⁴

Hinkley Point C is funded as part of the CfD scheme and is expected to add £1bn to Britain’s energy bills annually.¹⁰⁵ The nuclear power plant, which is being built in Somerset and scheduled for completion in 2030, is projected to cost the average household around £20¹⁰⁶ (£2025) in 2030. This means Hinkley is expected to comprise 2% of the average household energy bill in 2030, and makes up close to a third of the costs borne by CfDs. 

It is argued by supporters of the CfD-funded renewables model, such as the current Energy Secretary, that they help to protect households from volatile gas markets, as when the wholesale price of electricity (which is usually set by the price of gas) rises above the CfD strike price, the generator in receipt of the CfD will pay back the difference to the LCCC, and the surplus is passed on to consumers as a credit.

However, when the wholesale price of electricity falls (due to lower gas prices, for example), consumers remain locked in to the CfD strike price, meaning they cannot benefit from advantageous conditions. Furthermore, the more renewables facilities come online, the more CfDs are issued and the higher the pass-through cost via the Supplier Obligation.¹⁰⁷

Finally, the credit to the LCCC, passed through to households via the Ofgem price cap, is not experienced by consumers immediately, and may not compensate fully for the spike in wholesale energy prices, since gas sets the marginal price – electricity generated by CfD price mechanisms only represent around one-third of overall energy generation.¹⁰⁸

• Cost to Average 2025 Household: £33 (3% of household energy bill)
• Projected (Real Terms) Cost to Average Household 2030: £70 (7% of household energy bill)

Figure 19: Impact of Contracts for Difference on electricity bills for an average 3.1 MWh domestic household, 2019–2031.

Source: Electricity Bills UK¹⁰⁹

The UK Capacity Market (CM)

This is a scheme that pays generators to guarantee that they can supply power at times of high demand. The CM allows these generators, mostly gas and nuclear plants, to earn payments at a fixed kWh rate for supplying electricity at times when demand is high. If these generators fail to deliver when called on then they face penalties.

During times of high demand, known as System Stress Events, NESO – the public corporation responsible for managing the gas and electricity networks – issues generators with a Capacity Market Notice (CMN) to alert generators to potential shortfalls. CM contracts are allocated through annual auctions where generators bid to provide capacity, with those offering the lowest-priced bids winning.

The scheme is funded through charges on electricity suppliers, which are passed on to consumers via their bills. CM prices look set to increase dramatically over the next few years.¹¹⁰

For the average 2025 household, the CM costs £28 and comprise 3% of the average household bill. In 5 years, the cost is projected to rise to £45 and will comprise 4% of the average household bill.

• Cost to Average 2025 Household: £28 (3% of household energy bill)
• Projected (Real Terms) Cost to Average Household 2030: £45 (4% of household energy bill)

Figure 20: Impact of the Capacity Market on electricity bills for an average 3.1 MWh domestic household, 2019–2031.

Source: Electricity Bills UK¹¹¹

Energy Company Obligation (ECO)

There are several smaller policy costs that contribute to household bills. The Energy Company Obligation (ECO), a charge that obliged energy companies to fund for home installations resulting in reduced energy usage for low-income households, currently costs the average household £27 per year and was due to be scrapped after April 2026 as per the government’s Autumn budget. However, it has since been extended to December 2026 as the government has not been able to fully design a successor scheme yet.¹¹²

• Cost to Average 2025 Household: £27 (3% of household energy bill)
• Projected (Real Terms) Cost to Average Household 2030: £0 (0% of household energy bill)

Figure 21:  Impact of Energy Company Obligation on electricity bills for an average 3.1 MWh domestic household, 2019–2031.

Source: Electricity Bills UK¹¹³

The Warm Home Discount

The Warm Home Discount (WHD) provides support to customers in receipt of certain low income benefits in the form of a rebate. This rebate, along with the costs of operating and administering the scheme, is funded through a levy on energy suppliers, which is ultimately passed on to consumers through energy bills.

Recent changes to the WHD have broadened eligibility to all households on Universal Credit, rather than just those with larger, older or otherwise energy inefficient homes, and the rebate has been increased from £140 to £150, alongside an Industry Initiatives element which provides additional support. As the cost of funding the scheme is recovered through a levy on consumer bills, this expansion has actually increased costs for all households. This means that someone who was already receiving the WHD now receives less support once levy costs are factored in.

• Cost to Average 2025 Household: £15 (2% of household energy bill)
• Projected (Real Terms) Cost to Average Household 2030: £20 (2% of household energy bill)

Figure 22: Impact of Warm Home Discount on electricity bills for an average 3.1 MWh domestic household, 2019–2031.

Source: Electricity Bills UK¹¹⁴

Smart Meter Charge

The Smart Meter Net Cost Charge helps to fund the installation of smart meters across the country. It cost the average household £20 in 2025, and this cost is anticipated to remain broadly stable through to 2030.

• Cost to Average 2025 Household: £20 (2% of household energy bill)
• Projected (Real Terms) Cost to Average Household 2030: £20 (2% of household energy bill)

Figure 23: Impact of Smart Meter Charges on electricity bills for an average 3.1 MWh domestic household, 2019–2031.

Source: Electricity Bills UK¹¹⁵

Supplier margin and costs

This is the cost suppliers levy on households to recover their operating costs, such as customer service, billing, and other administrative activities. These costs are partly recovered through the standing charge and have increased in real terms over the past five years.

• Cost to Average 2025 Household: £133 (14% of household energy bill)
• Projected (Real Terms) Cost to Average Household 2030: £147 (14% of household energy bill)

Figure 24: Impact of supplier operating costs and profit margins on electricity bills on an average 3.1 MWh domestic household, 2019–2031.

Source: Electricity Bills UK¹¹⁶

Green Gas Levy

This places an obligation on all licensed fossil fuel gas suppliers to pay a quarterly levy which is calculated based on the number of meter points they serve. It funds the injection of biomethane into the gas grid, the Green Gas Support Scheme. Exemptions are available for suppliers who can prove their total gas supply is 95% biomethane or more.

This is a separate levy from the electricity market and applies to suppliers’ provision of gas directly to households and businesses for heating, gas cooking and in various industrial processes. It is a more recent levy, introduced only in 2021.¹¹⁷ While it currently funds and incentivises carbon-neutral gas it also adds to household bills by imposing a levy on suppliers that is directly passed on.¹¹⁸ It would in legislative terms be relatively straightforward to remove, though the government would need to find a way out of existing funding commitments to investors in green gas projects.

Sizewell C levy

Sizewell C, the nuclear power station being built in Suffolk, is being funded using the Regulated Asset Base (RAB) model, through which investors recover costs through a charge on consumer bills during the construction phase, reducing the need for high-interest loans and lowering the long-term cost of the project. This has an impact on households: the Sizewell C RAB levy costs the average 2025 household £4 per year, but this cost is projected to increase to £19 per year by 2030.¹¹⁹

• Cost to Average 2025 Household: £4 (1% of household energy bill)
• Projected (Real Terms) Cost to Average Household 2030: £19 (2% of household energy bill)

Figure 25: Projected cost of Sizewell C levy  on electricity bills for an average 3.1 MWh domestic household, 2025-2031

Source: Electricity Bills UK¹²⁰

Assistance for Areas of High Electricity Distribution Costs (AAHEDC)

This levy subsidises the high costs of distributing electricity in Northern Scotland, has minimal impact on households, costing the average household only £1 per year.¹²¹

• Cost to Average 2025 Household: £1 (<1% of household energy bill)
• Projected (Real Terms) Cost to Average Household 2030: £1 (<1% of household energy bill)

Figure 26:  Impact of Areas with High Electricity Distribution Costs (AAHEDC) on electricity bills for an average 3.1 MWh domestic household, 2019–2031.

Source: Electricity Bills UK¹²²

Network Charging Compensation (NCC) Scheme and the Energy Intensive Industry (EII) Support Levy

The Network Charging Compensation Scheme helps to relieve levy costs on Energy Intensive Industries. This costs the average 2025 household £3 and is projected to rise to £7 by 2030.¹²³ This scheme specifically offsets the high costs of maintaining the physical electricity grid, protecting heavy manufacturers like steel and chemical plants from international price competition by shifting a portion of their network fees onto the wider consumer base.

• Cost to Average 2025 Household: £3 (<1% of household energy bill)
• Projected (Real Terms) Cost to Average Household 2030: £7 (1% of household energy bill)

Figure 27: Projected cost on electricity bills for an average 3.1 MWh domestic household of Network Charging Compensation Scheme / Energy Intensive Industry (EII) Support Levy, 2025-2031

Source: Electricity Bills UK¹²⁴

Extra levy share to support heavy industry

This is a levy designed to reduce costs on heavy industry as part of the British Industry Competitiveness Scheme (BICS), which will come into force in 2027. The cost to households is estimated to be £5.¹²⁵

• Projected (Real Terms) Cost to Average Household 2030: £5 (1% of household energy bill)

Figure 28:  Projected cost of BICS levy on electricity bills for an average 3.1 MWh domestic household, 2027-2031

Source: Electricity Bills UK¹²⁶

Carbon Capture Storage projects (CCS)

This subsidises innovation and investment in carbon capture and storage technology. The per household cost is estimated to be £4 by 2030 for those projects that have already been allocated funding, including one in Teesside that is due to open in 2028.¹²⁷

Around two-thirds of Department for Energy, Sustainability, and Net Zero (DESNZ) CCS funding remains unallocated. Any future projects are likely to come online post-2030, as they would first need to secure planning consent and financing before becoming operational. The annual estimated cost to the average household is £3.¹²⁸

• Projected (Real Terms) Cost to Average Household 2030: £7 (1% of household energy bill)

Figure 29:  Projected cost of Carbon Capture Storage projects (CCS) on electricity bills for an average 3.1 MWh domestic household, 2028-2031

Source: Electricity Bills UK¹²⁹

VAT

Household electricity and gas bills are subject to VAT at 5%, applied to the total bill after all costs have been included.

• Cost to Average 2025 Household: £46 (5% of household energy bill)
• Projected (Real Terms) Cost to Average Household 2030: £50 (5% of household energy bill)

Figure 30: Impact of VAT on electricity bills for an average 3.1 MWh domestic household, 2019–2031.

Source: Electricity Bills UK¹³⁰

Network charges

These are the fees for using and maintaining the grid infrastructure that transports gas and electricity across the country, and for ensuring that supply meets demand at any given time.

The main charges are Transmission Costs, Distribution Costs, and Balancing Costs.

Transmission Costs (TNUoS)

This is the cost to move electricity across long distances, moving power from generators to regional distribution systems. TNUoS charges are also used to fund the maintenance costs of high-voltage transmission infrastructure, such as pylons, substations, and other major infrastructure.

• Cost to Average 2025 Household: £52 (5% of household energy bill)
• Projected (Real Terms) Cost to Average Household 2030: £105 (10% of household energy bill)

Figure 31: Cost to households of Transmission Costs (TNUoS) through bills, 2019-2031

Source: Electricity Bills UK¹³¹

Distribution Costs (DUoS)

DUoS is used to fund the maintenance and operation of the local electricity network, including wires, poles, transformers, and other essential infrastructure. This ensures electricity is safely stepped down from the high-voltage transmission network and safely delivered to homes and businesses across the country.

• Cost to Average 2025 Household: £114 (12% of household energy bill)
• Projected (Real Terms) Cost to Average Household 2030: £146 (14% of household energy bill)

Figure 32: Cost to households of Distribution Costs (DUoS) through bills, 2019-2031

Source: Electricity Bills UK¹³²

Balancing Costs (BSUoS) – consumers pay suppliers to switch off

Electricity system balancing costs are levied by the Energy Systems Operator (ESO) for balancing supply and demand on a second by second basis. Costs are used to ensure that the grid has enough power at all times and does not get overloaded. This is because electricity cannot yet be stored economically and at sufficient scale, so the system must be “balanced” to maintain a stable frequency.

Balancing costs are essentially the cost of energy intermittency, as energy sources are turned on and off. This is subsidised by the taxpayer and British industries.

• Cost to Average 2025 Household: £41 (4% of household energy bill)
• Projected (Real Terms) Cost to Average Household 2030: £91 (9% of household energy bill)

Figure 33: Cost to households of Balancing Costs (BSUoS) through bills, 2019-2031

Source: Electricity Bills UK¹³³

Curtailment payments

There are two types of constraint costs: Curtailment costs (turn-off), and replacement costs (turn-on). Curtailment costs involve cases where generators – usually wind farms – are paid to turn off because the grid cannot physically transmit the amount of power they are producing. Replacement costs, meanwhile, are costs involved with turning generators on – usually Combined Cycle Gas Turbines (CCGTs) – during times when the grid does not have enough power. These costs are part of the wider balancing (BSUoS) costs administered by suppliers and passed onto consumers through bills.

NESO uses forecasting models to estimate future constraints and balancing costs. Forecasts are turned into fixed BSUoS tariffs, which are passed onto suppliers who then pass the costs onto consumers. Paid to turn on gas, paid to turn off wind.

Wind farms are turned off at times when the grid has lots of electricity, and the transmission cables cannot physically transmit the amount of power being produced.

Therefore, as transmission costs are higher in Scotland (these are further away from the demand for power) it tends to be the big Scottish wind farms that are paid to turn off.

Producers under the CfD and RO schemes are paid strike price regardless, even if they stop producing because they tell NESO they will only stop production if they are compensated to the amount they would have received had they kept generating. So BSUoS costs are essentially spent on topping them up to the strike price when they are not generating as the grid would be overloaded if they did.

This means there is no incentive for wind farms to buy batteries and store lost power. It just gets wasted.

Turn-on costs

BSUoS turn-on costs slightly different to the Capacity Market. The CM is a cost paid to generators to ensure they are available to provide power when called upon. BSUoS turn-on costs are the funds they are paid by unit of power provided when called upon.

An alternative model is the Firm Power Auction, first proposed by Professor Dieter Helm in his 2017 Cost of Energy Review.¹³⁴ This system would scrap CfDs and the Capacity Market in favour of a single unified auction. Instead of being paid for generating electricity when the wind blows, all types of generators, renewables, nuclear, and fossil fuels, would bid to supply firm power.

Firm power, electricity that can be delivered reliably whenever it is needed, would require generators to guarantee their output incentivising renewable generators to invest in battery storage or demand-side response technology, ensuring that they bear the costs of intermittency and not consumers.¹³⁵

Figure 34: Estimated 2025 constraint costs by month

Source: GB Renewables Map¹³⁶

Seagreen offshore wind farm, which lies off the coast of Dundee and is one of the biggest wind farms in the UK, had 64% of its potential power curtailed over the past two years.¹³⁷ Viking wind farm in the Shetlands also had 64% of potential power curtailed.¹³⁸

In December 2024, 81% of potential power from Seagreen was curtailed, amounting to approximately 407,000MWh of power wasted.

The total curtailment and turn-up cost so far in 2025 has been £1.36 billion, or 9,034 GWh.¹³⁹

Recommendations

End the Renewables Obligation and Feed-in-Tariffs. These are due to be wound down but should immediately be removed as levies on suppliers that are passed on to households.

No further Contracts for Difference auction rounds for wind and solar should be held. AR7 should be the last round of CfDs. After this, renewables generators should operate by selling electricity into the wholesale market. The Hinkley Point CfD should remain.

The RAB for Sizewell C should be retained unless and until an alternative funding mechanism can be found. Nuclear will become an increasingly important share of the UK energy mix and the current funding mechanism is important for project financing and delivery.

CfD contracts should be renegotiated or ended on a structured run-off basis. Investors losing out as a result would be able to recover a percentage of their loss, depending on the length of the contract, with a firm cap as a percentage of original project capital expenditure. Indexed gilts could be used as a compensation mechanism instead of up-front cash.

Contracts for Difference and the Capacity Market should ultimately be replaced with a Firm Power Auction system. This proposal, supported by Professor Dieter Helm in his Cost of Energy Review, would end the socialisation of investment risk and the cost of intermittency being passed on to consumers. This will be explored in a further Onward report.

3) How policy costs affect consumers of energy

Climate policies target industrial energy users

Policies to incentivise the shift to net zero through decarbonisation have targeted industrial users of energy particularly, both through direct taxation and through carbon pricing mechanisms. These policies are intended to reduce emissions production and incentivise efficiency, but they also increase production costs, disproportionately harm industries that are by definition carbon-intensive, weaken industrial competitiveness and reduce overall economic output.¹⁴⁰

Examples of industries that are necessarily carbon-intensive, including iron and steel, process chemistry and the wider chemicals sector, cement, glass and ceramics manufacturing and oil refining.¹⁴¹ These industries are emitting by nature, not as a matter of discretion. And frontier technology sectors of the future such as AI data centres, quantum computing, life sciences research and pharmaceutical production are all energy-intensive, something that was not envisaged when climate change policies were first adopted.

Yet despite the energy-intensive nature of innovation frontier industries, and the inherently carbon-intensive nature of various important production sector industries, the UK policy framework has made industrial electricity more expensive, and deliberately targets carbon-intensive industries with carbon pricing and the Climate Change Levy.

Figure 35: Projected Data Centre energy consumption

Source: NESO¹⁴²

The industrial unit cost of UK energy is frequently ranked the highest in the EU or G7, and historically have ranged between 17% and 49% above the International Energy Area median.¹⁴³ This punishes existing industries while providing a powerful deterrent to investment.

This is a function of high unit costs as a result of constrained supply and of direct taxes on energy use.

Figure 36: 2024 Industrial gas and electric prices in pence per kWh (including taxes)

Source: DESNZ¹⁴⁴

Figure 37: UK Industrial gas and electric prices in pence per kWh (including taxes)

Source: DESNZ¹⁴⁴

The Climate Change Levy targets industrial energy users

This tax is charged to non-household users of energy, primarily industrial users. This includes manufacturing businesses and heavy industries but also the wider commercial sector, including the public sector.

It is charged on a per-kWh basis and is explicitly designed to make commercial energy use more expensive to incentivise energy efficiency and reduce emissions.¹⁴⁶ This tax is a good example of the bad underlying philosophy behind UK energy policy: rather than achieving an economically sustainable energy transition through innovation and technology, it explicitly aims to reduce economic activity.

It has been assumed so far that reductions in energy use can be achieved while reducing overall energy consumption. However, international comparisons of GDP per capita growth and per capita energy consumption suggest otherwise. Rather, per capita growth and energy use track each other very closely.¹⁴⁷

Figure 38: World per capita energy consumption and world GDP per capita

Source: World Bank¹⁴⁸ and Our World In Data¹⁴⁹

Impact of the Levy on industry

Energy demand in heavy industry, and in energy-intensive frontier industries such as data centres, is generally inelastic, limiting the scope for energy use-limiting behavioural change. It also applies to both electricity and gas, so electrification does not provide an escape. This is perverse since incentivising a shift to cleaner energy was the original goal, not killing off industrial output.

Figure 39: Impact of Climate Change Levy (CCL) on industrial electricity prices

Source: Onward Analysis and ONS¹⁵⁰

High energy prices are the number one cause of factory closures and industrial job losses in the UK, where energy-intensive industry (EII) output fell by a third between 2021 and 2025, hitting a 35-year low.¹⁵¹

Accrued receipts from the Levy skyrocketed first from 1999 and then 2012, but have flatlined since 2019, most likely because economic activity has stalled.¹⁵²

Figure 40: Climate Change Levy Receipts

Source: ONS¹⁵³

The pace of UK deindustrialisation has been alarming, with manufacturing output, gross value added (GVA) and share of GDP collapsing.¹⁵⁴ Manufacturing’s share of national income is now below 9%, well below other European and G7 comparators.¹⁵⁵

This is particularly alarming given the outsized contribution of production sector jobs, including manufacturing, mining and extraction, to national gross value added. These sectors employed 445,000 people in 2023, accounting for just 1.4% of total employment. But they had a collective gross-value added (GVA) of £57bn, 2.5% of national GVA. This makes the average production sector job 77% more productive than average employment.¹⁵⁶

Figure 41: Energy-intensive manufacturing industries gross value added (GVA), 1990-2025, Index 2015 = 100

Source: ONS¹⁵⁷

Figure 42:  Industrial electricity prices (per kWh) and the Net Rate of Return for Manufacturers (%), 2024 prices, 2008-2024

Source: ONS¹⁵⁸ and DESNZ¹⁵⁹

*Electricity prices (p / kWh) have been adjusted for inflation

The energy sector is also the worst-performing in the UK over the past six years. While Gross Value Add (GVA) per hour worked has increased by 2.8% across the whole UK economy, it has dramatically declined when it comes to the energy sector, falling by 53%.

Figure 43: UK productivity change by sector – 2019 to 2025 (Output per hour worked calculated as GVA per hour worked)

Source: Economics Observatory¹⁶⁰

Reliefs for EIIs – partial and temporary

Some qualifying EIIs benefit from exemptions from the Levy if they comply with Climate Change Agreements (CCAs).¹⁶¹ However, even with CCAs electricity is taxed at 10% of the headline Levy rate and gas at 35%, and relief is conditional on meeting efficiency targets and is time-limited. Industries outside the CCA framework pay the full Levy.

These reliefs are welcome, but they are conditional and partial exemptions from an unnecessary tax. Even at the lower relief rate, the Levy still disincentivises industrial energy consumption by increasing costs. Furthermore, temporary policy relief mechanisms do not provide certainty for businesses and their investors to make long-term investment decisions. For many industries, any loss of the reliefs would be devastating in terms of marginal costs.

UK Emissions Trading System (ETS) – an EU hangover

The other major state-imposed policy driving up the cost of energy is the Emissions Trading System (ETS), largely carried over from Britain’s membership of the EU ETS. This is another policy designed to drive up the cost of energy by forcing carbon emitters to surrender allowances for every tonne of CO₂ emitted, or to purchase additional allowances under a trading mechanism at a cost, either at auction or on the secondary market.

The UK price is £57 per tonne compared to £69 per tonne in the EU.¹⁶² The UK is obliged to operate an effective carbon pricing system under the terms of the EU-UK Trade and Co-operation Agreement (TCA).¹⁶³

The ETS applies to oil and gas producers, electricity generators and heavy industry, plus carbon-intensive sectors like aviation. Industrial users eligible to pay ETS are therefore liable for their own carbon costs and also for the passed through costs of carbon pricing that applies to producers.¹⁶⁴

Even households and industrial energy users who are not eligible to pay ETS themselves therefore experienced the pass-through costs, meaning energy inflation from ETS is built in through the supply chain.

ETS reliefs are limited

As with the Climate Change Levy, the government provides compensation mechanisms for qualifying industrial users for costs arising from ETS. This compensation is paid for out of general taxation. Some energy-intensive industrial users also receive a certain portion of their allowances for free, with the aim of preserving competitiveness and preventing “carbon leakage”, the process by which carbon-emitting production is simply moved offshore for no environmental gain.¹⁶⁵

Once again, the problem with the relief schemes is that they are limited to certain qualifying industries, partial and temporary. The same disincentives to long-term investment therefore still apply, and UK industry is made less competitive as a matter of policy compared to jurisdictions that do not operate a similar carbon pricing system.

Recommendations

Phase out the Climate Change Levy. This should be immediate and permanent for electricity, where carbon is already priced further up the supply chain, and should be removed for gas until there is an economically sustainable alternative energy mix.

Establish permanent CCL exemptions immediately for EIIs and trade-exposed sectors to prevent carbon leakage. The offshoring of industrial production and therefore of emissions places domestic net zero targets over economic rationality. This must be stopped instantly, even if the CCL is phased out more gradually.

Alternatively, apply the CCL only to industries with genuine options for greater energy efficiency. Identify sectors where energy efficiencies are possible and desirable, rather than applying the CCL to sectors where large scale energy consumption is non-discretionary.

Establish a permanent, wide-sweeping ETS exemption and compensation mechanism for all EIIs. These sectors are strategically important and should never pay ETS, and should be given relief for pass-through ETS costs affecting electricity generators.

Implement a phased removal of the ETS. There is no domestic legal necessity in operating a state-based carbon pricing mechanism. Rather, decarbonisation efforts should be market-led, and policies to incentivise it should be based on investment reliefs like full-expensing, not deterrents. The UK should seek to renegotiate its carbon pricing commitments under the EU TAC.

Appendix 1

Calculations using data from UK Electricity Bills 2030¹⁶⁶ and Scrap Carbon Taxes¹⁶⁷

Key Assumptions:

• Gas sets the marginal price 97% of the time (demand-weighted share)

Source: Zakeri et al (2023)¹⁶⁸

• CfD volumes are not netted off in our calculations, as CfD generation is concentrated in high-renewable hours when gas is less often marginal, and a simple volumetric net-off would overstate the offset from carbon-price effects.

• UK ETS price is approx £60 / tCO₂

Source: Onward Analysis of ICAP Auction Results.¹⁶⁹

• CCGT emissions intensity is 0.4 tCO₂ / MWhₑ. This is calculated by taking the 0.2 tCO₂ / MWh value and assuming a 50% efficiency so multiplying it by 2 to get 0.4 tCO₂ / MWhₑ.

Source: UNFCCC¹⁷⁰

• The average UK Household uses 3100 kWh (3.1 MWh) of energy / year.

Source: Ofgem / Ben James¹⁷¹

Calculation

CPS cost = £7.20 / MWh

UK ETS Cost = £24.00 / MWh
 (£60.00 £ / tCO₂ auction cost × 0.4 tCO₂ / MWhₑ CCGT emissions intensity)

Total carbon tax cost = £31.20 / MWh

£31.20 / MWh = £0.03120 / kWh

0.03120 × 3100 (benchmark annual consumption) × 0.97 (97% gas sets price assumption)

= £93.82 / year

Appendix 2

Calculations using data from UK Electricity Bills 2030¹⁷² and Scrap Carbon Taxes¹⁷³

Cost of wholesale to average household = £324.05
Cost of Carbon Taxes to average household = £93.82

£324.05 – £93.82 = £230.23

£93.82 ÷ £230.23 = 0.41

= 41%

Appendix 3

Calculations using data from UK Electricity Bills 2030¹⁷⁴ and Scrap Carbon Taxes¹⁷⁵

CPS cost = £7.20 / MWh

£7.20 / MWh = £0.0072 / kWh

0.0072 × 3100 × 0.97 = £21.65 / year

UK ETS Cost = £24.00 / MWh

£24.00 / MWh = £0.024 / kWh

0.024 × 3100 × 0.97 = £72.17 / year

Appendix 4

Calculations using data from UK Electricity Bills 2030¹⁷⁶ and Scrap Carbon Taxes¹⁷⁷

Ben James FY26-27 projections estimate that the average 3100 kWh household will spend £939.44 per year on energy.

His projected costs for Renewables Obligation + Feed in Tariffs + Contracts for Difference + Capacity Market + Sizewell C + Extra levy share post-NCC + VAT (5%) = £190.72.

£190.72 + £93.82 (our 24/25 estimates for Carbon Tax costs) = £284.54

£284.54 ÷ £939.44 = 30%

Appendix 5

Calculations using data from UK Electricity Bills 2030¹⁷⁸ and Scrap Carbon Taxes¹⁷⁹

Carbon Taxes cost = £93.82 per year

VAT cost for 2025 = £46.08

£93.82 + £46.08 = £139.90

£139.90 ÷ £967.77 (2025 total cost) = 15%

Endnotes

1.  Climate Change Committee, link

2.  A study by the Centre for Climate Change and Social Transformations, commissioned by the Climate Change Committee, revealed that “substantial change” in household behaviour would be needed for the UK to reach its net zero by 2050 target, with 60% of reductions in consumption needing to come from households, see CAST, link

3.  Our World in Data, Energy Use per Person vs GDP per Capita, link

4.  It should be noted that energy policy is largely devolved in Northern Ireland, but for ease the term “UK” has been used throughout this report.

5.  Projected figure for 2026-27, Onward analysis

6.  Onward Analysis (see Appendix 1), and Electricity Bills UK, link

7.  Kilowatts, GB Electricity Demand: Two Lost Decades, LinkedIn analysis link

8.  Office for National Statistics, Impact of Higher Energy Costs on UK Businesses 2021–2024, link 

9.  O’Brien, N., British Energy Policy Part 1: Unilateralism, link

10.  Our World in Data, Per Capita Electricity Generation, link 

11.  Our World in Data, Energy Production and Consumption, link

12.  Our World in Data, Energy Production and Consumption, link

13.  Our World in Data, Per Capita Energy Use, link

14.  Open Access Government, Nuclear Power: The Safer and Cheaper Alternative to Fossil Fuels, link

15.  Next Kraftwerke, What Does Merit Order Mean?, link

16.  Scrap Carbon Taxes Campaign, link

17.  National Energy System Operator, Constraint Payments Explained, link

18.  House of Commons Library, Energy Prices and Bills, SN04046 Briefing Paper, link

19.  Littlechild, S., Electricity Market Reform, Cambridge Judge Business School Energy Policy Research Group, link

20.  Office for Budget Responsibility, A History of Natural Gas in the UK, link

21.  Littlechild, S., Electricity Market Reform, Cambridge Judge Business School Energy Policy Research Group, link

22.  Office for National Statistics, Energy and emissions in the UK, link

23.  See House of Commons Library, Energy Policy: An overview, link

24.  International Energy Agency, United Kingdom Energy Mix link

25.  Definition of dispatchable power generation sources capable of rapid ramp-up or shutdown to meet demand fluctuations.

26.  Deloitte, Why Britain Pays More for Electricity, Deloitte UK link

27.  International Energy Agency, United Kingdom Energy Mix, link

28.  Carbon Brief, UK Emissions Fall 3.6% in 2024, link

29.  Carbon Brief, UK Coal Phase-Out Interactive Analysis, link

30.  World Nuclear Association, France Country Profile, link

31.  Aberdeen & Grampian Chamber of Commerce; BBC News, North Sea Tax Policy Coverage, link

32.  British Progress, Cut Bills, Boost Electrification by Removing Carbon Costs, link

33.  Ember, Electricity Data Explorer, link

34.  Mining.com, China Coal Output Hits Record in 2025, link

35.  Clean Energy Wire, German Fossil Electricity Production Increase 2025, link

36.  Department for Energy Security and Net Zero, UK Energy in Brief 2025, link

37.  Department for Energy Security and Net Zero, UK Energy in Brief 2025, link

38.  World Nuclear Association, UK Reactor Database, link 

39.  UK Parliament Scottish Affairs Committee, Energy Transition Report, link

40.  National Energy System Operator, Future Energy Scenarios: ESO Pathways to Net Zero, link; Department for Energy Security and Net Zero, Statutory Security of Supply Report 2024, link

41.  Department for Energy Security and Net Zero, Digest of UK Energy Statistics: 4.5, link

42.  Department for Energy Security and Net Zero, Digest of UK Energy Statistics: natural gas, link

43.  Department for Energy Security and Net Zero, International non-domestic energy prices, link

44.  Department for Energy Security and Net Zero, UK Energy in Brief 2025, link

45.  UK Parliament Committees, Energy System Evidence, link

46.  North Sea Transition Authority, Decommissioning Cost Estimates, link

47.  Offshore Energies UK, Policy Versus Geology, link

48.  Ibid.

49.  The Telegraph, North Sea Investment Coverage, link

50. Mommer, B., Fiscal Regimes and Oil Revenues, Oxford Institute for Energy Studies, link

51.  CW Energy, United Kingdom Oil and Gas Taxation link

52.  HM Government, Energy (Oil and Gas) Profits Levy Changes, July Statement 2024, link

53.  The Independent, North Sea Policy Coverage, link

54.  Ibid.

55.  Offshore Energies UK, Policy Versus Geology, link

56.  Westwood Global Energy Group analysis cited in Offshore Energies UK.

57.  Offshore Energies UK, World class expertise underpins resilient performance in decommissioning sector, link

58.  Westwood Global Energy Group analysis cited in Offshore Energies UK: The report utilises geological data to estimate the remaining recoverable oil and gas volumes, focusing especially on areas located 25 to 50 kilometres from existing infrastructure. Its findings reveal that the majority of viable resources lie within 50 kilometres of established hubs, allowing for faster and more efficient development.

59.  RenewableUK, Can North Sea Oil and Gas Power Britain’s Future?, link

60.  Ibid.

61.  OGV Energy, Norway Restarts North Sea Licensing, link

62.  The Telegraph, No New North Sea Oil Wells Coverage, link

63.  Norwegian Petroleum Directorate, Exploration Activity, link

64.  HM Government, Energy (Oil and Gas) Profits Levy Changes, July Statement 2024, link

65.  Offshore Energies UK, Impact of Oil and Gas Tax Changes, link

66.  Ibid.

67.  Institute for Fiscal Studies, Corporation Tax Explained, link

68.  HM Government, North Sea Future Plan, link

69.  HM Government, Government Ends Support for Fracking, link

70.  Aberdeen & Grampian Chamber of Commerce, Windfall Levy Revenue Analysis, link

71.  Offshore Energies UK, Decommissioning Sector Performance, link

72.  BBC News, Demolition of UK’s last coal-fired power station approved link

73.  British Progress, Cut Bills, Boost Electrification by Removing Carbon Costs, link

74.  HM Government, UK Emissions Trading Scheme Policy Overview, link

75.  Ibid.

76.  Institute for Energy Economics and Financial Analysis, Low UK Carbon Pricing Causes £29bn Lost Revenues, link

77.  Centre for Policy Studies, Power to the Markets, link

78.  BBC News, Energy Policy Coverage, link

79.  Onward Analysis (see Appendix 1) and Electricity Bills UK,link and Scrap Carbon Taxes, link

80.  Onward Analysis (see Appendix 2) and Electricity Bills UK, link and Scrap Carbon Taxes,link

81.  Onward Analysis (see Appendix 3) and Electricity Bills UK, link and Scrap Carbon Taxes, link

82.  Electricity Bills UK, 2030 Electricity Bill Projections, link

83.   Scrap Carbon Taxes Campaign, link

84.  Onward analysis; Electricity Bills UK, 2030 Electricity Bill Projections, link; Scrap Carbon Taxes Campaign, link

85.  Scrap Carbon Taxes, link

86.  Prosperity Institute, Destroying the Foundations, link

87.  Bloomberg News, UK Oil Refineries and Carbon Cost Risks, link

88.  Onward Analysis; Electricity Bills UK projections, link

89.  Ibid.

90.  HM Government, Powering Britain’s Future Electricity Bills Reform, link

91.  Onward analysis; Electricity Bills UK projections, link

92.  Onward analysis (see Appendix 5); Electricity Bills UK projections, link

93.  Onward analysis; Electricity Bills UK projections, link

94.  Ibid.

95.  Electricity Bills UK, 2030 Electricity Bill Projections, link

96.  Reuters, Most Britons energy bills to fall after regulator cuts cap, link

97.  Electricity Bills UK, 2030 Electricity Bill Projections, link

98.  Ibid.

99.  Ibid.

100.  Electricity Bills UK, 2030 Electricity Bill Projections, link

101.  Ibid.

102.  DESNZ, Electricity Market Reform, link

103.  BBC News, Government raises maximum price for wind energy, link

104.  Onward analysis; Electricity Bills UK projections, link

105.  The Telegraph, Hinkley Point C Cost Coverage, link

106.  HM Government, Hinkley Point C Value for Money Assessment, link

107.  DESNZ, Electricity Market Reform, link

108.  Onward analysis; MyGridGB, Last 12 months link

109.  Electricity Bills UK, 2030 Electricity Bill Projections, link

110.  James, B., Electricity Price Trajectory Analysis, LinkedIn post, link

111.  Electricity Bills UK, 2030 Electricity Bill Projections, link

112.  HM Government, ECO4 Extension Government Response, link

113.  Electricity Bills UK, 2030 Electricity Bill Projections, link

114.  Electricity Bills UK, 2030 Electricity Bill Projections, link

115.  Ibid.

116.  Electricity Bills UK, 2030 Electricity Bill Projections, link

117.  HM Government, Green Gas Levy Rates and Exemptions, link

118.  Ibid.

119.  Electricity Bills UK, 2030 Electricity Bill Projections, link

120.  Ibid.

121.  Ibid.

122.  Electricity Bills UK, 2030 Electricity Bill Projections, link

123.  Ibid.

124.  Electricity Bills UK, 2030 Electricity Bill Projections, link

125.  Ibid.

126.  Ibid.

127.  Electricity Bills UK, 2030 Electricity Bill Projections, link

128.  Ibid.

129.  Ibid.

130.  Electricity Bills UK, 2030 Electricity Bill Projections, link

131.  Electricity Bills UK, 2030 Electricity Bill Projections, link

132.  Electricity Bills UK, 2030 Electricity Bill Projections, link

133.  Electricity Bills UK, 2030 Electricity Bill Projections, link

134.  Helm, D., Cost of Energy Review, HM Government, link

135.  Hawkes, R.; GB Renewables Map | Curtailment, link

136.  Ibid.

137.  Windtable, Seagreen Wind Farm Data, link 

138.  Windtable, Viking Wind Farm Data, link

139.  Windtable, Seagreen Wind Farm Data, link

140.  Prosperity Institute, It’s Broke, Fix It, link

141.  HM Government, Energy and Trade Intensive Industries List, link

142.  National Energy Systems Operator, Future Energy Scenarios 2025, link

143.  Office for National Statistics, Impact of Higher Energy Costs on UK Businesses link

144.  DESNZ, International non-domestic energy prices, link

145.  Ibid.

146.  DESNZ, Climate Change Levy Rates, link ; DESNZ, Environmental taxes, reliefs and schemes for businesses, link

147.  Our World in Data, Energy Use per Person vs GDP per Capita, link

148.  World Bank, GDP per capita (current US$), link

149.  Our World in Data, Energy use per person, link

150.  Office for National Statistics, Impact of Higher Energy Costs on UK Businesses, link; Jobs Foundation, Jobs and Energy: The impact of high energy costs on the UK jobs market, link

151.  Ibid.

152.  Office for National Statistics, Public Spending Time Series, link

153.  Office for National Statistics, Public Spending Time Series, link

154.  Office for National Statistics, Impact of Higher Energy Costs on UK Businesses, link

155.  World Bank, Manufacturing Value Added (% of GDP), link

156.  Prosperity Institute, Destroying the Foundations, link 

157.  Office for National Statistics, Impact of Higher Energy Costs on UK Businesses, link

158.  Office For National Statistics, Profitability of UK companies time series, link

159.  DESNZ, International non-domestic energy prices, link  

160.  Economics Observatory, UK Productivity Change by Sector, link

161.  HM Government, Climate Change Agreements Guidance, link

162.  Centre for British Progress, Cut Bills, Boost Electrification by Removing Carbon Costs, link

163.  HM Government, UK–EU Trade and Cooperation Agreement, link

164.  HM Government, UK Emissions Trading Scheme Policy Overview, link

165.  HM Government, UK Emissions Trading Scheme Policy Overview, link

166.  Electricity Bills UK, 2030 Electricity Bill Projections, link

167.  Scrap Carbon Taxes Campaign, link

168.  Zakeri et al, The role of natural gas in setting electricity prices in Europe, WU Vienna, link

169.  Argus Media, European Emissions Markets, link

170.  UNFCCC, Mechanism Methodology, link

171.  Ofgem, Benchmark Maximum Charges, link ; Electricity Bills UK, 2030 Electricity Bill Projections, link

172.  Electricity Bills UK, 2030 Electricity Bill Projections, link

173.  Scrap Carbon Taxes Campaign, link

174.  Electricity Bills UK, 2030 Electricity Bill Projections, link

175.  Scrap Carbon Taxes Campaign, link

176.  Electricity Bills UK, 2030 Electricity Bill Projections, link

177.  Scrap Carbon Taxes Campaign, link

178.  Electricity Bills UK, 2030 Electricity Bill Projections, link

179.  Scrap Carbon Taxes Campaign, link

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The Party has an opportunity to be the sensible voice on climate and the environment that sits between the Government’s too much too soon method, and Reform’s more sceptical approach. The Conservative approach can be one that appeals to their base and target voters who, as evidenced in the report, care about climate change but worry about the personal costs of action. The Conservatives should champion a pragmatic, pro-market strategy for tackling climate that is cognisant of costs to the consumer.”

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