The UK’s Energy Woes Can’t Be Blamed on Gas
The pursuit of net zero has inexorably raised the cost of UK electricity—for which, naturally, fossil-fuel price spikes are getting all the blame.
In response to discontent over the UK’s punishingly high electricity prices—with domestic rates being near the highest in Europe and industrial rates being the highest—Energy Secretary Miatta Fahnbulleh has been making the media rounds, asserting that rates are overwhelmingly “being driven by global fossil-fuel markets,” and that as a consequence of a national dependence on hydrocarbons, “we are price takers.” Writing on August 26, the London Times’ Emma Powell echoed Fahnbulleh, saying that one of the main contributors to the problem is the UK’s continued reliance on natural gas for electricity production and the fact that, under the marginal pricing system, gas sets the wholesale price for “all electricity sold” in the country, even that produced by other means (wind, solar, biomass, etc.).
In 2024, 30 percent of UK electricity was produced using natural gas. But if we take the International Energy Agency’s most recent numbers (from that year) and compare them on a country-by-country basis with current EU electricity prices, we see instantly that natural-gas usage is hardly determinative of electricity prices. It’s true that Ireland, which now has the most expensive electricity in Europe, produced 48 percent of its electricity using gas. But it’s just as true that Germany, which has the second-most expensive electricity in Europe, produced only 18 percent of it using gas (a number helped along by the foreign saboteurs who blew up Germany’s Nord Stream pipeline four years ago). The numbers don’t lend themselves to a simple conclusion. The Netherlands got 36 percent of its electricity by burning gas, but it sits at number 16 on the list of EU electricity prices. Belgium got 18 percent from natural gas but sits at number 3 on that list. Other factors are clearly at play.
The truth is that, despite the rhetoric surrounding it, and though it’s certainly been volatile in recent years owing to geopolitical factors, the price of natural gas has surprisingly little effect on UK electricity bills overall. For instance, in 2024 the UK got 41 percent of its electricity from wind and biomass sources, which are not paid the wholesale price for electricity but are instead paid according to what is called a contract for difference (CfD). Simply put, these sources are paid a contractual set price (called a strike price) for the electricity they produce—never more than the strike price, and never less, over the duration of the contract (typically 15 years, recently raised to 20). If the wholesale price of electricity is lower than the strike price (which it nearly always is), those producers are paid an additional sum to meet the strike price; the wholesale price is merely a point of reference from which to calculate the balance they will receive on top of the wholesale price. If the wholesale price is greater than the strike price (which it almost never is), the producers pay back the difference to consumers—the wholesale price again serving merely as a point of reference. And in that year, 2024, when the UK got 41 percent of its electricity from wind and biomass, the CfD payments (on top of the wholesale price) were as follows: £1.9 billion for offshore wind, and more than £388 million for biomass.
In the 10 years that the CfD scheme has been in place, the wholesale price of electricity has been higher than the strike price in only a few quarters coinciding roughly with the Ukraine-related gas crisis. This means that but for those brief exceptions, wind and biomass producers have been raking in CfD premiums on top of the wholesale price, sometimes significant premiums. In fact, the lower the wholesale price of electricity, the greater the CfD premium. In Q4 2025, when UK natural-gas prices were about equivalent to those of September 2018 (and the wholesale price of electricity was therefore correspondingly low), UK offshore wind enjoyed CfD payments upward of £736 million (again, that’s in addition to the wholesale price), while biomass producers settled for a more modest premium exceeding £138 million. Even thus far in Q3 2026, when the effects of the Middle East conflict are being seen clearly in European gas prices and therefore in wholesale electricity prices in the UK, and when Fahnbulleh and others are asserting that rising natural-gas prices are the reason for high UK electricity bills, offshore wind has taken in more than £142 million in CfD payments and biomass more than £38 million. (That’s as of this writing. The numbers are still moving.)
Despite the oft-repeated claim, renewables-based electricity production is rarely if ever cheaper than thermal-based production. More damningly, when the strike prices for wind and biomass were cheaper than the wholesale price of electricity in 2022 (with volatility continuing into 2023), and when it therefore would have financially benefitted rate payers were the UK to avoid burning costly gas for electricity production, we saw total CfD production, measured in terawatt hours (TWh), actually decline. But by 2024–25, when gas prices had largely settled down, and coincidentally when CfD payments no longer risked running in an adverse direction (with producers possibly having to pay back the difference), wind and biomass rediscovered their vigor, with their combined output in TWh roughly doubling.
It’s certainly true that via the marginal pricing system, the cost of gas affects the wholesale price of electricity. But the wholesale price of electricity applies mostly to . . . electricity produced by natural gas, or roughly 30 percent of UK electricity (actually, now 27 percent). But a greater part, 41 percent, is produced by wind and biomass operators that are paid a strike price that is almost always higher (sometimes significantly so) than the wholesale price, and connecting these prices/costs is something of a category error. The price of natural gas (and therefore the price of electricity produced from it) is subject to market forces, whereas the price of electricity produced by wind and biomass is set at government auction and fixed over a contractual term. Over the roughly five years from 2017 to 2022 and the beginning of the first gas crisis (a timespan coinciding with the first five years of the CfD scheme), we even observe gas prices dropping noticeably and electricity prices rising just as noticeably, a divergence that calls into serious question the assertion that UK electricity bills are driven by the cost of natural gas.
A similar divergence caught the attention of the UK’s own Office for National Statistics. In 2023, when gas prices were still volatile in the wake of Russia’s invasion of Ukraine, the United Kingdom, as might be expected based on the prevailing narrative, had the highest industrial electricity rates in the International Energy Agency, 46 percent above the IEA median. Yet industrial gas prices in the UK that same year were 7 percent below the IEA median. The UK was down at number 15 on the list of industrial gas prices.
The narrative needs work.
Since 2000, over years in which the country has committed to net-zero goals and the increased electrification of everything, UK domestic electricity production has dropped by 24 percent, and electricity imports have risen considerably, from a low of 2.16 TWh in 2003 to 43.7 TWh in 2024. According to the National Energy System Operator, UK electricity imports topped 15 percent in 2025, which was up from about 12 percent the year before. Put another way, that’s roughly a 25 percent increase in electricity imports just from 2024 to 2025.
In 2000, nearly all UK electricity was produced by dispatchable sources of power: natural gas, nuclear, and coal generators that could run day and night, in any season, and in any kind of weather. And that year their load factors—aka capacity factors—were 75 percent for natural gas, 70.5 percent for nuclear, and 50.8 percent for coal. (Load/capacity factor measures the average amount of electricity produced by a power source relative to that source’s installed, or nameplate, capacity.) But coal-based electricity production has now ceased entirely, natural-gas usage for electricity generation as of 2024 was half of its 2008 peak, and nuclear electricity generation in 2024 was less than half of what it was in 2000.
Over that same quarter of a century, the use of biofuels for electricity production has increased more than elevenfold, the use of solar more than fourteenfold, and the use of wind eighty-eightfold. But there are financial and even (in one clear case) environmental ramifications to these changes. First, the environmental matter: From an emissions standpoint, biomass—though a dispatchable energy source, with a load/capacity factor of nearly 67 percent in 2024—is about the worst fuel there is for producing electricity at scale, being slightly cleaner only than lignite, the dirtiest of coals. For carbon-accounting purposes within UK and EU regulatory schemes, biomass has enjoyed the spurious status of being carbon-neutral, but its use in pursuit of net-zero goals is more than a little ironic. Where stack emissions are concerned, burning most coals would be significantly cleaner than burning biomass. But again, at least biomass is a dispatchable power source, providing a much needed degree of energy reliability. The same cannot be said of wind and solar.
According to a report by the UK Department for Energy Security & Net Zero (the department Fahnbulleh now leads), the load/capacity factor for UK onshore wind in 2024 was 25.7 percent. For offshore wind it was 38.7 percent, and for solar it was a paltry 9.8 percent. That these low-energy-density forms of production are replacing such high-density sources as coal and natural gas goes some way toward explaining both that 24 percent drop in domestic electricity production from 2000 to 2024 and the concomitant rise in imports, and it certainly explains in large part the rise in electricity costs in recent years.
As the Centre for British Progress notes, the combined capacity factor of the UK electrical grid has declined from 43.4 percent in 2011 to 30.5 percent in 2024. The more wind and solar penetration into any grid, the lower the grid’s capacity factor. For one thing, these renewables require overbuilding. If your technology’s capacity factor is 50 percent, you need to install twice as much to get nameplate capacity (e.g., you need to install 20 megawatts to get 10 megawatts). If it’s 25 percent, you need to install four times as much to achieve nameplate capacity (e.g., 40 megawatts to get 10 megawatts). And because these renewables are intermittent (with wind turbines at whatever scale not producing during calms, and solar not producing in cloudy or nighttime conditions), there’s the need for dispatchable backup, chiefly natural-gas turbines. But using gas turbines not as baseload producers but primarily as “peaker” plants that backstop wind and solar, as is increasingly their function, reduces gas’s capacity factor too—electively and as a matter of policy but not (as with wind and solar) because of inherent technological limitations.
Among other things, this leads to (or indicates) increasing underutilization. From 2000 to 2024, the UK installed 65 gigawatts’ worth of new generation on the grid—a time, once again, when domestic electricity production dropped by 24 percent. What’s more, according to the Centre for British Progress, UK electricity consumption has fallen by 22 percent since 2005. All of which means that more and more fixed costs (in the form of installed gigawatts’ worth of overbuilding and backstopping) are being recovered by relatively fewer and fewer hours of electricity produced and sold. And this, far more than volatile natural-gas prices, explains the punishing cost of UK electricity. As some wag once put it: Wind and solar are the cheapest forms of electricity production—30 percent of the time. The other 70 percent of the time they’re extremely expensive.
Furthermore, to cite the Centre for British Progress once more, not only have we added many gigawatts’ worth of underutilized assets to the grid, but we’ve done so in smaller and smaller increments—so many little generators, widely dispersed, each requiring new connectors to the grid plus whatever number of attendant inverters, transformers, and substations. The increase in grid costs is significant. For comparison, in the years 1965–69, the UK added 19.5 gigawatts to the grid, and the average size of the generators that were connected was 974 megawatts. In the years 2010–14, the UK added 22 gigawatts to the grid, but the average size of the generators connected was 32 megawatts.
Finally, it’s not just the costs related to overinstalled, underutilized assets. Nor is it just the costs required to radically expand and maintain the grid. Load balancing and managing the capacity market in such an immensely complicated system bring their own toll. Decades ago, when the generators were relatively few, impressively large, dispatchable, and adjustable in their output, and all of them were connected to the high-voltage transmission network, load balancing was much simpler. But in 2025, according to the National Energy System Operator, 36 percent of UK electricity was produced by intermittent power sources, some of them connected to the high-voltage transmission network and some of them connected to low-voltage distribution networks. Having to manage the load, on an hour-by-hour basis, on a grid that is more than a third weather-dependent, with producers jumping in (or dropping out) upstream here and downstream there, is no small task. And that task comes with its own costs.
Quoting findings by the think tank Nesta, Powell of the Times admirably notes that the wholesale price of electricity—on which Fahnbulleh and others pin the blame for high UK electricity rates—made up a little more than a third of the average UK electricity bill in 2025, whereas the combined costs of renewables subsidies and grid maintenance and upgrades (themselves made more costly and complicated by renewables penetration) exceeded more than 40 percent of the average bill.
True, the Middle East conflict will have altered those proportions somewhat, raising the wholesale-price component on current bills. But that’s partly just the cost of reliability on a grid that is increasingly subject to intermittent, unreliable power sources, a grid that in the past quarter century has seen its combined capacity factor drop from roughly 65 percent to 30.5 percent. Blaming reliability for the costs of a system forced expensively to accommodate unreliability may be a political winner for some. (Invoking the dread specter of fossil fuels has such magic in certain circles.) But it won’t keep the lights on or the house warm come winter. And it won’t make electricity bills any smaller.
If one has a need (and certainly unless and until that need can be overcome), it’s best to anticipate and manage it. For the UK, this would mean lifting the moratorium on North Sea gas exploration and entering into long-term contracts with developers of those fields, rather than paying spot prices on the import market—often for Norwegian natural gas extracted from the very same North Sea, and sometimes for liquefied natural gas, which is the most expensive and carbon-intensive form of natural gas (owing to the energy expended liquefying, shipping, and regasifying it). This would have a modest if real effect on the wholesale price of electricity, but it would have a dramatic effect on energy security and a beneficial effect on UK tax revenues and on the market for high-skilled, high-paid labor. It would also—if not immediately—allow the country to replenish its gas reserves, at a time when storage is at worrisome lows.
Avoiding such steps toward managing a national need and instead making a public show of resenting that need is simply ineffectual.
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