New report: The true affordability of net zero

This evening my latest report: The true affordability of net zero, was launched at an event hosted by The Lord Offord of Garvel, Shadow Minister for Energy Security and Net Zero in the House of Lords. The event was attended by MPs, Peers and members of the energy community as well as the press. It’s the first time a report of mine has received quite so much attention. Ahead of the launch it was covered by UnHerd and the Telegraph.

My report reviews in depth the costs of renewable generation and their impact on our bills, driving British industrial electricity costs to the highest in the developed world, and our domestic costs to fourth highest. We’re told this is due to the cost of gas, yet our gas bills are only 15^th highest in the world. According to international energy price statistics published  by the UK Government, as of June 2024 (the last month included in the dataset), large British firms were paying 27.91 p /kWh for electricity while those in the EU paid just 10.80 p /kWh. But this was not always the case. Back in July 2011 there was almost no difference between the price paid by industrial consumers in the UK versus those in the €7.48 p /kWh compared with 7.04 p /kWh.

“It is a sad fact that the UK’s industry electricity prices are amongst the highest in developed economies – higher than in the EU and around four times the prices in the US. The result is that UK energy-intensive industries are uncompetitive,”
– Professor Sir Dieter Helm

My report sets out all of the additional costs applied to bills as a result of net zero policies which in 2023-24 amounted to over £17 billion, and are projected to increase to over £20 billion per year in 2029-30. My analysis indicates that had Britain continued with its legacy gas-based power system in the period since 2006, consumers would have been almost £220 billion better off (2025 money) even taking into account the impact of the gas crisis.

Other countries have fewer costs and levies – the UK chooses to not only subsidise renewables but also impose other levies and taxes which are designed to encourage a move away from carbon intensive energy. Unfortunately this is often impractical, meaning that households and businesses effectively pay additional taxes on their energy without being able to receive any associated benefits. These are clear policy choices, in part driven by the Government’s determination to “lead the world” on climate.

In the meantime, the UK wastes large amounts of money through a failure to properly manage net zero investment. Windfarms have been deliberately built behind grid constraints in the knowledge that the electricity they produce cannot all be used. In 2024 the Seagreen windfarm which opened in October 2023 was constrained off (ie paid not to export its electricity to the grid) twice as often as it actually sold its electricity to the grid. When this happens, consumers must pay a gas power station to generate the electricity they actually use, and pay windfarms not to generate the same amount of electricity. Consumers pay twice because investments in the power grid have failed to keep pace with the construction of subsidised windfarms.

Nor is there any sign of relief. Despite the Government’s claims that a move to renewables will result in cost savings, the Climate Change Committee (“CCC”) in its recently published 7th Carbon Budget says that savings from net zero are only expected during the 7th budget period which runs from 2038 to 2043. The cost assumptions contained within this report are unrealistically optimistic, anticipating reductions in the costs of windfarms that are not substantiated by the evidence. The chances or realising such savings in the 2040s or at any time, are remote.

Gas is not to blame for high electricity prices

It is frequently stated by policymakers and green lobbyists that renewables are “cheap” and indeed, cheaper than the alternatives provided primarily by gas. The high gas prices of 2022 are cited as being a particular problem with the use of gas, despite the very low gas prices that endured in the first twenty years of this century.

While gas accounts for 93% of wholesale electricity prices, those wholesale prices are only around 40% of bills. Ofgem’s breakdown of bills includes the costs of the Capacity Market (“CM”) and Contracts for Difference (“CfD”) within wholesale costs and not policy costs. Policy costs include the Renewables Obligation (“RO”), Feed in Tariffs (“FiT”), Energy Company Obligation (“ECO”), Warm Homes Discount (“WHD”), Green Gas Levy (“GGL”), Network Charging Compensation Scheme (“NCCS”) and Assistance for Areas with High Electricity Distribution Costs (“AAHEDC”). Moving CM and CfD costs from wholesale to policy costs would reduce the share of wholesale costs in the final bill to 42% and increase policy costs to 14%.

While wholesale gas prices explain a large portion of wholesale electricity prices, it is a different story when it comes to the amounts paid by homes and businesses (known as the retail price). The following chart shows wholesale gas and electricity prices and retail electricity prices in current money terms (ie the money of the day for each year), from 1994 to 2024 (household spend data for 2024 are not yet available).

It can clearly be seen that from 2006 retail electricity prices begin to diverge from wholesale prices – while wholesale gas and electricity prices are broadly stable until 2021, yet retail electricity prices experience consistent increases.

Prior to 2006, the margin between retail and wholesale electricity prices was broadly stable at 3.88 – 4.79 p/kWh with an average of 4.23 p/kWh (2006 money). Had this margin been maintained in the subsequent years ie the costs of the energy transition not been added to bills, households would have saved £130 billion in 2006 money (£218 billion in today’s money). In contrast, some estimates suggest that the UK spent an additional £75 billion as a result of the 2021-23 gas crisis.

So despite what people say about high gas prices being responsible for high electricity prices, this was only true for late 2021-23 – for most of the past 25 years, something other than gas prices has been driving electricity prices higher.

Policymakers are also fond of blaming “high international gas prices” on the UK’s high energy costs. However, this claim also does not survive closer scrutiny. Firstly, there is no single “international gas price” – there is not even a single British gas price! However, what policymakers mean by this expression is that, as net gas importers, we must pay whatever prices are demanded by the international gas markets.

But this is true for all net gas importers, many of whom, like the UK, use gas as the fuel in their marginal electricity generating plant. So while “international gas prices” may explain periods of higher energy prices in the UK, they do not explain why the UK has relatively expensive energy compared with other countries. This additional expense undermines the UK’s international competitiveness and is driving de-industrialisation.

The impact of renewable energy on bills

Renewables impact electricity bills both directly through subsidies, and indirectly through network charges. The UK has been subsidising renewables in 1990 with the Non-Fossil Fuel Obligation, so it seems extra-ordinary that subsidies that were intended to “prime the pump” and enable immature technologies are still required 35 years later. Not only that, but, far from tapering, the subsidies are increasing.

According to the Office for Budget Responsibility, the UK spent £9.9 billion on environmental levies in 2023-24, however this figure excludes the Feed-in Tariff which subsidises small-scale renewables, the Climate Change Levy and the Energy Generators Levy , all of which are ultimately paid for by consumers. A more complete assessment of these levies indicates that in fact in 2023-24 the total cost was £17.2 billion:

These levies can be simplified into three main categories: renewables enablers (subsidies and the Capacity Market), heat-related levies (the Renewables Heat Incentive, Green Gas Levy and Warm Homes Discount) and everything else (the CRC Energy Efficiency Scheme and the Energy Generators Levy which was a windfall tax on generators which benefited from high electricity prices during the gas crisis but that did not incur gas-related fuel costs).

The reduction in subsidies in 2021-22 and 2022-23 was largely due to the Contracts for Difference scheme which saw a significant reduction in payments and even some payments back from generators as market prices, driven by the gas crisis, exceeded the strike prices. Despite this, overall levies still exceeded £12 billion!

According to the OBR,  environmental levies are set to rise from the current £17 billion per year to over £20 billion in 2030, and its forecast may well be an under-estimate when higher CfD strike prices and new levies such as the proposed Carbon Capture & Storage levy are added.

The next big cost element attributable to renewables is the cost of backup. Since wind has an average capacity factor of just 35% and just 10% for solar significant amounts of backup are needed to ensure security of supply. This is delivered through the Capacity Market whose costs are currently £1.3 billion and expected to reach £4 billion by the end of the decade. This is likely to be an under-estimate since significantly more money will be needed to replace gas plant that is set to retire in the coming years.

Then we have constraint costs. The priority has been to connect renewables to the grid with little thought to whether their electricity can be moved to consumers. For example the Seagreen windfarm located off the coast of Angus in the North Sea, was curtailed twice as much as it generated in 2024 since it is located behind a grid constraint. Overall constraint costs in 2024-25 amounted to some £2.3 billion according to data from system operator, NESO.

Curtailment costs are expected to rise significantly over the next few years.

Network costs are impacted by weather-based renewables in other ways. Wind and solar have very low energy density, meaning a lot more wires are needed for the same amount of energy. An 800 MW CCGT needs one grid connection while an 800 MW wind farm may have 60 turbines all of which need to be connected. Given the 35% capacity factor of wind, 2-3 times as many turbines are needed to achieve the equivalent energy of the CCGT. All of this is added to the network component of bills.

The costs of managing the real-time intermittency of weather-based renewables are also added to network costs. Balancing costs have increased significantly with the growth in renewables, and in some scenarios, could almost double by the early years of the 2030s.

Will renewables get cheaper?

In a nutshell, no. All the signs indicate that not only are the costs of renewables and their subsidies rising, they are likely to rise still further.

The CCC assumes offshore wind costs of £51 /MWh in 2025, falling to £31 /MWh in 2050 and solar PV costs of £46 /MWh in 2025, falling to £27 /MWh in 2050. These figures for 2030 onwards are lower even than the Government’s 2023 Electricity Generation Cost Report which was itself considered to be highly optimistic as it assumed the costs of renewables would continue to fall despite rising supply chain and inflation.

In AR4, 28 projects secured contracts amounting to 7.1 GW of capacity. Of these eight have been terminated (1.7 GW) including Norfolk Boreas which defaulted on its contracts, four are yet to meet their Milestone Delivery Date (0.3 GW) including the 200 MW Stornoway Wind Farm. The Milestone Delivery Date (“MDD”) is the deadline by which generators awarded a CfD must demonstrate delivery progress, by providing evidence either of (i) spend of 10% of total pre-commissioning costs, or (ii) project commitments.

The Government extended the MDD for all technologies from 12 months to 18 months in AR4 . The remaining 16 projects (5.1 GW) have progressed to the “pre-start” phase, which is means certain milestones still need to be met before commissioning can begin. This includes the 2.1 GW Hornsea 3 project which took its Final Investment Decision in December 2023.

In AR5, 25 projects secured contracts amounting to 3.6 GW of capacity. There were 2.7 GW of these are in the pre-MDD phase and the remainder in the pre-start phase. The following year saw 9.6 GW of capacity being procured as prices increased significantly from previous rounds. All but five projects are currently in the pre-MDD phase. AR5 attracted no bids at all from offshore wind projects. At the same time there were failed wind tenders in Germany, the Netherlands and the US . More recently there was a major tender failure in Denmark, where its largest ever wind tender failed to attract a single bid.

“There is a common misconception that bid prices in the UK Government Contracts for Difference (CfD) auction are indicative of offshore wind costs, but this is wrong. Rather, winning bids reflect the minimum price offshore wind developers are willing to receive for a 15-year contract period to gain access to the grid, on the expectation of higher revenues in the future. However, recent weakening of UK Government climate policy ambition has lowered future expectations for carbon prices and, therefore, future power prices,”
– Paul Butterworth, CRU International

Historic auction prices give a mis-leading account of true costs due to the effects of the “Permitted Reduction Mechanism”. Under these rules, projects are allowed to withdraw up to 25% of their original capacity and rebid that capacity in a future CfD round. In AR6, several projects that had won contracts in AR4 took advantage of this mechanism, withdrawing a portion of their capacity and re-bidding it, including Ørsted’s Hornsea 3 project, which had won a CfD in AR4 at £37.35 /MWh (2012 money) and rebid a portion of its capacity in AR6 securing a higher strike price of £54.23 /MWh. Other projects that rebid and secured contracts in AR6 include East Anglia 3, Inch Cape A & B, and Moray West, in fact all of the offshore wind projects with contracts under AR4 rebid in AR6 apart from the defaulting Norfolk Boreas.

Worryingly there are signs that the next subsidy round, AR7 will be significantly more expensive than its predecessors. Last year, analysis by global commodities consultancy CRU International suggested that increased cost pressures and lower future power price expectations mean CfD prices would need to be £65–70 /MWh (real 2012, or £92-99 /MWh in 2025 money) for project viability. And that “further out, bid prices will need to be higher still to account for higher Crown Estate leasing costs”.

CRU’s analysis suggests that the business cases for UK offshore wind projects is predicated on receiving higher revenues in the future, after the 15-year CfD period expires, when power prices are expected to be higher, as a result of high carbon prices. An expectation of higher prices is interesting since one of the main “benefits” of renewables according to policymakers is that they will reduce costs to consumers, so the idea that they are only viable if costs are higher rather undermines these claims. CRU argued that three factors undermine the windfarm business case.

Firstly, many argued that the failure of AR5 was due to the rising cost of raw materials, but CRU demonstrated that these costs peaked at the time of AR4 and therefore by AR5 were declining. However, general supply chain inflation, over and above material costs, has increased build costs (some estimates suggest by as much as 40%), as have higher financing costs, and these increases do imply higher required revenues will be needed to maintain returns. Secondly, Crown Estate, which leases seabed rights, has changed its leasing mechanism adding up to ~£40 /MWh to the cost of offshore wind.

Thirdly, and most importantly in CRU’s view with respect to AR5, expectations for higher carbon prices in the UK diminished following government actions to increase availability of emission allowances which saw the UK carbon price fall by 60% relative to the EU price, or ~£50 /tCO2. At the time of CRU’s report there was an expectation of lower carbon prices. In fact, UK carbon prices rose sharply in late January 2025 after the Prime Minister announced an intention to re-connect the UK carbon market with the higher-priced European market. The UK market has consistently traded below its European equivalent as de-industrialisation has resulted in a surplus of allowances. Artificially increasing carbon pricing is clearly price negative for consumers. Currently, UK carbon allowances are trading at £46 /t vs £59 /t for EU carbon allowances, and compared with £35 /t in January before the announcement. Harmonisation would increase end user bills by around £120 million per year based on current UK and EU carbon prices and exchange rates.

The expectation of higher prices is reflected in a consultation launched by the UK Government into changes it wants to make to the CfD auction process in AR7. The timing of this consultation is odd – it ran until 21 March and the auction will not open until Summer 2025. However, for AR6, the Administrative Strike Prices were published in the November preceding the auction, and the Budget Notice was published in early March 2024 with the auction process beginning later that same month. This new consultation pushes back the entire process, from publication of the Administrative Strike Prices through to the auction itself.

The subject matter of the consultation covers various proposed reforms to the operation of the CfDs. Arguably the most significant proposal is a change in contract term from 15 to 20 years – which would materially cover the lifespan of a windfarm (typically 20-25 years). This would mean projects would receive subsidies for a longer period, and is likely being proposed as a means of reducing the headline strike price figures by spreading payments over a longer period. This very much suggests that the Government has received feedback from the industry that much higher payments will be needed to meet the targets set out in the Clean Power 2030 Plan.

The Government is also proposing changes (subsequently adopted) to the way the budget for the CfD is set: instead of being determined before the auction begins, the Budget Notice would not be published until after sealed bids had been received. The Government says this would allow auction budgets for fixed offshore wind “to be set to maximise capacity” and could “enable the Government to procure more fixed-bottom offshore wind, subject to value for money considerations, to deliver clean power by 2030.” This sounds as if the Government intends to prioritise volume over cost, which would likely result in higher costs being passed on to consumers.

A final point to note is that during the period that CfD strike prices were falling, turbine manufactures began to lose large amounts of money. While this has sometimes been attributed to covid and the gas crisis, the losses actually began to appear in 2018, before either began.

Back in 2022, market participants observed that the trend of turbine manufacturers selling at a loss would (self-evidently) threaten renewable generation targets, and indeed this was borne out in the various failed tenders subsequently.

Turbine manufactures are for the most part repairing their finances and returning to profitability (although problems remain at Siemens), but they have achieved this in part by pushing the financial challenges down the supply chain to project developers, who have started to see losses of their own. Most notably, wind project developer Ørsted posted a loss of about £2.2 billion in 2023 and wrote off £3.3 billion from its windfarm business. Vestas has imposed significant price increases, selling turbines at an average price of €1.21 million /MW in the second quarter of 2024 – up both from €1.04 million /MW in the same period in 2023, and from €970,000 /MW in the first quarter of 2024. Against this backdrop it is unsurprising that developers are seeking higher levels of subsidies.

Since writing the report, Ørsted announced the cancellation of its Hornsea 4 project on the basis that it was uneconomic. Hornsea 4 had a CfD awarded in AR6 at a strike of £83 /MWh in £2025. By comparison, the average day ahead power price in 2024 was £73 /MWh – in other words, Hornsea 4 was not economic even with a 13% premium over the “expensive” gas-based wholesale power price. So much for renewables being cheap!

Renewables are not and never will be cheap

The public has been seduced by narratives that renewables are cheap, believing them because the wind and the sun are “free”, and ignoring the fact that the machines necessary to convert their energy to electricity are very far from being free, and for the most part are actually very expensive. That renewables are not cheap should be clear, based both on the evidence that after 35 years of subsidies, we are yet to see any benefits through lower bills.

Indeed, the evidence suggests that consumers would have been almost £220 billion better off financially (in £2025) had the energy transition not been attempted. The UK’s progress in reducing emissions in its power sector were largely achieved coincidentally as a result of declining coal production at a time when North Sea gas began to be exploited. Even the Climate Change Committee recognises that financial savings may not materialise until the 7th Carbon Budget period which runs from 2038 to 2040 – half a century after we first started to subsidise renewable generation!

The UK’s international competitiveness is being harmed by its comparatively high electricity prices. Despite the mantras of policymakers about “high international gas prices”, the UK’s high electricity costs are a result of policy choices: the UK has the highest industrial electricity prices in the developed world and the forth highest domestic electricity prices, but only the 15th highest gas prices. In a world where all gas importing countries must pay “international gas prices” and many of these countries use gas as the marginal fuel for power generation, gas prices alone cannot explain why UK electricity prices are as high as they are.

In fact the reason for this is the choices made by successive governments, which have added £ billions in costs to bills. Some countries seek to recover similar costs through taxation, while other countries have simply not created many of the additional levies which apply in the `UK.

The result has been some reduction in UK emissions beyond that achieved incidentally through the switch away from coal to gas in the power sector, but not a reduction in global emissions, since manufacturing has simply moved to countries with cheaper (and dirtier) energy, with additional emissions being incurred through the transportation of goods to the UK, often from places as far away as China. The UK increasingly imports heavy bulk items such as steel, which incur considerable transportation emissions – ideally such items should be produced as locally as possible. But the UK’s comparatively high energy prices make this uneconomic. And since the UK accounts for just 0.8% of global carbon dioxide emissions, little is gained from the economic self-harm these punitive energy policies are creating.

It seems impossible that net zero targets can be met without significant sacrifices by the public. Sooner or later the public will understand the full extent of the requirement, and it is by no means clear that it will be willing to go along with it. Voters in both the US and Europe have begun to turn away from the net zero project – voters in the UK may well do the same. They should be provided with the full information on which to make their choices: continuing to gaslight the public about the costs of net zero is unacceptable.

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