Wholesale gas in 2024–25 was broadly comparable with the prices Britain experienced in 2008–13 once inflation is taken into account. Yet household electricity remains expensive, grid-management costs have risen sharply, and in July the National Energy System Operator had to instruct additional, predominantly gas-fired generators to run during record solar output simply to provide voltage support. If gas alone is the explanation, the numbers no longer fit the story.
By Shane Oxer — Campaigner for fairer and affordable energy
Today, 1 October 2026, households move into autumn with another increase in energy costs. The public explanation will again centre heavily on wholesale gas. But a single quarterly price-cap explanation does not answer the more important question: why has Britain’s electricity system become so expensive to operate when the underlying wholesale gas commodity, outside crisis spikes, has not risen anything like the total cost of the system around it?
The evidence from this summer points to a much deeper problem. Wind output weakened. Gas remained the largest contributor to NESO’s July generation mix. Interconnectors remained heavily used. Thermal constraints rose sharply. Most strikingly, record solar reduced daytime transmission demand sufficiently that fewer synchronous generators were commercially running, forcing NESO to procure additional, predominantly gas-fired units for voltage support. That is not a theory about what might happen in 2035. It happened in Britain this July.
START WITH THE GAS PRICE
In 2008, UK NBP day-ahead wholesale gas averaged about 58p per therm. By 2013 the annual average was around 68p per therm. These historical figures were supplied to the former Department of Energy and Climate Change from the wholesale market and are recorded in the Parliamentary record.
Those nominal prices cannot be compared directly with 2026 because inflation matters. The Office for National Statistics CPI series stood at 84.7 in 2008 and 143.6 by August 2026. On that basis, the 58p wholesale gas price of 2008 is equivalent to roughly 98p per therm in 2026 money. The 68p average from 2013 is also close to 99p in today’s money.
Now compare that with the more recent market. BP’s published UK NBP marker averaged about 83.57p per therm in 2024 and 88.77p in 2025. In simple inflation-adjusted terms, wholesale gas in both years was below the 2008 equivalent. That does not erase the genuine international gas shocks of 2021–22 or the shorter geopolitical spikes that still occur, but it does undermine the idea that a permanently and relentlessly rising underlying gas commodity can explain the whole increase in Britain’s electricity-system costs.
The question therefore changes. If the gas itself was broadly comparable with 2008–13 in real terms, what else has become more expensive?
JULY 2026 GAVE US AN ANSWER
The NESO July 2026 Monthly Balancing Cost Report should be required reading for anyone trying to understand Britain’s electricity bills. July was exceptionally sunny, yet wind generation fell from 4.6 TWh in June to 4.0 TWh in July. Gas remained the largest contributor in NESO’s generation mix at 30%, with wind at 23.9% and interconnectors at 20.7%. There were also two days during the month when gas supplied more than half of the generation mix.
That matters because it exposes the first weakness in the simplistic “cheap renewables replace expensive gas” narrative. Renewable capacity can be large, but the system still has to respond to what wind and solar actually produce at the time demand exists. When wind output falls, other sources must replace it. In Britain today that frequently means gas, imports, storage and other dispatchable generation.
Yet the most revealing part of July was not the weak wind. It was what happened when solar output became extremely high.
THE £40.8 MILLION SOLAR PARADOX
In July 2025, NESO’s system synchronisation cost for voltage control was £11.0 million. In July 2026 it was £40.8 million. That is a rise of £29.8 million in a single year. The physical volume of voltage-control actions also increased, from 517 GWh in June to 690 GWh in July.
NESO’s explanation is the crucial part. Record sunshine produced very high levels of embedded solar generation. That reduced the amount of electricity households and businesses were drawing through the high-voltage transmission system during daylight hours. Fewer large synchronous generators therefore found it economic to run commercially.
But the electricity network still required the services those machines provide. A power system needs more than megawatt-hours. It requires voltage support, frequency stability, inertia and reactive power, and those services have to be available in the right location at the right time. NESO records that low transmission demand and high embedded solar output reduced the number of synchronous generators self-dispatching, so it had to instruct additional, predominantly gas-fired generating units through the Balancing Mechanism to provide location-specific voltage support.
Britain experienced record solar output, yet still had to pay predominantly gas-fired generators to run because the electricity system needed the services those machines provided.
This does not mean solar produces no useful electricity. It plainly does. The significance is that the cost of generating renewable electricity is not the same as the cost of operating a secure electricity system around it. July exposed that difference in a way the headline price of a solar megawatt-hour never can.
CHEAP GENERATION IS NOT THE SAME AS A CHEAP SYSTEM
Britain does not buy isolated units of electricity disconnected from time, location and network conditions. It needs a functioning electricity system every second of the day. Electricity has to arrive when it is needed, at the places where it is needed, while voltage and frequency remain within safe limits and sufficient reserve exists to respond when generators fail or weather changes.
That means generation prices alone can never provide a complete comparison between technologies. The system around the generator matters: transmission, distribution, balancing, reserve, voltage, inertia, storage, interconnection and backup. July’s £40.8 million voltage-control bill demonstrates how costs can appear elsewhere in the system even during record renewable output.
THEN CAME THE CONSTRAINT BILL
Voltage control was only one part of July’s problem. Thermal constraint costs rose from £92.2 million in July 2025 to £167.8 million in July 2026, an increase of £75.6 million. A thermal constraint occurs when the transmission network cannot safely carry all the electricity trying to flow through part of it. NESO then has to intervene, reducing generation in one area and increasing it elsewhere.
The wider structural problem is now acknowledged by Government. In its Reformed National Pricing Delivery Plan, DESNZ says that generation build has outpaced network build in many parts of the country and that this misalignment has imposed additional costs on consumers and investors. That is a significant admission because it confirms that Britain expanded generation faster than the network required to transport it efficiently.
The consequence is a system that can pay one generator to reduce output and another generator elsewhere to increase it. Those costs are not imaginary bookkeeping entries. They are part of the cost of operating the electricity system and are recovered through the charging arrangements that ultimately feed through to consumers.
£370 MILLION TO TURN WIND DOWN, £910 MILLION TO TURN GAS UP
DESNZ’s own 2024/25 figures show the scale of the problem. Wind generators were paid about £370 million to turn down because of network constraints. Demand still had to be met, so generation elsewhere had to increase. DESNZ records approximately £910 million of gas turn-up costs, around two-thirds of the total network-constraint costs in that year.
The sequence matters. The gas generator did not create the transmission bottleneck. It was being used to solve it. Yet once gas is dispatched behind a constraint, its cost becomes visible while the underlying system failure can disappear into technical categories such as balancing and constraint management.
This is why it is misleading to treat every expensive gas action as evidence that gas itself is the root cause of expensive electricity. Sometimes gas is expensive because it is being asked to perform a role the rest of the system cannot perform at that location and moment.
THE GOVERNMENT’S OWN FORECAST POINTS TO THE GRID
The same DESNZ plan says that, without sufficient mitigation, constraint costs could peak at around £7 billion a year in 2030/31. The exact outcome depends on how quickly new transmission projects are delivered and how generation develops, but the direction is clear enough.
More importantly, DESNZ says that while gas prices affect the cost of replacement generation, the primary near-term driver of projected constraint expenditure is the growing volume of thermal constraint actions until major network reinforcements are operational. That is a far more revealing description of the problem than the public shorthand that expensive electricity is simply the result of expensive gas.
GAS FELL, BUT ELECTRICITY DID NOT FOLLOW
Summer 2026 also provided direct evidence that gas and electricity prices do not always move together. Towards the end of July, international gas markets began to soften, yet British day-ahead electricity prices remained elevated. NESO identified weaker wind generation and continuing generation constraints among the reasons.
Independent market reporting then showed an even clearer divergence. On 3 August, Catalyst Commercial described the situation as “Gas and power have parted company”: UK NBP gas softened across most of the curve while UK baseload electricity strengthened. That does not make gas irrelevant. It proves that Britain’s electricity price is driven by more than the commodity price of gas alone.
Wind availability matters. Nuclear availability matters. Imports matter. Network congestion matters. The location of generation matters. Voltage and inertia matter. Once those factors are recognised, the simple gas narrative starts to look less like a complete explanation and more like one part of a much larger system problem.
JULY’S BALANCING BILL WAS ABOUT £300 MILLION
NESO’s initial July balancing-cost report came to approximately £302 million, against a benchmark of around £257 million. The eventual reconciled figure moves through the normal settlement process, but the scale is what matters: roughly £300 million was spent balancing the system in one summer month.
NESO’s benchmark already incorporated movements in wind generation and wholesale electricity prices. The additional pressure reflected restricted network boundaries, summer outage arrangements and substantially elevated voltage and inertia requirements. These are costs produced by the operation of the electricity system itself.
THEN CARBON POLICY MAKES THE GAS WE STILL NEED MORE EXPENSIVE
Britain’s system still relies on gas for dispatchable generation, low-wind periods, constraint redispatch and some synchronous services. Yet government policy then adds carbon costs to that generation through the UK Emissions Trading Scheme and Carbon Price Support.
We do not need to guess whether those policies affect electricity prices. The Government’s own compensation guidance for energy-intensive industries explicitly recognises the electricity-price impact. Its current methodology uses an assumed combined UK ETS and Carbon Price Support impact of £32.04 per MWh in real 2025 prices.
That figure is not a simple amount that can be subtracted from every domestic bill. But it establishes the principle beyond argument: carbon policy deliberately increases the cost of carbon-emitting electricity. So when gas is required to cover weak wind, solve a constraint or provide system services, it is not carrying only the cost of the underlying fuel. It is also carrying policy-imposed carbon costs.
THE COST DOES NOT DISAPPEAR BECAUSE IT SITS IN A DIFFERENT BOX
Ofgem divides the household bill into categories such as wholesale, networks, policy and operating costs. That may be necessary for regulation, but the physical system does not operate in neat accounting boxes. Carbon policy affects wholesale electricity. Network weaknesses create balancing costs. Balancing actions require generation. Renewable deployment drives transmission requirements. New transmission appears later in network charges.
The consumer pays the combined result. Whether a cost is labelled “wholesale”, “network”, “policy” or “balancing” does not alter the amount leaving the household budget. That is why Britain needs to stop comparing technologies only through isolated generation prices and start publishing the complete cost of the electricity system required around them.
DESNZ HAS ALREADY ACKNOWLEDGED THE PLANNING GAP
The Government’s own pricing reform documents recognise that Britain historically lacked a single overarching plan determining what generation and network assets should be built, where they should be built and when. Generation expanded faster than parts of the network, and consumers are now paying for the resulting mismatch while still financing the enormous transmission programme intended to correct it.
That creates costs on both sides. If the grid is not reinforced quickly enough, constraints rise. If it is reinforced, consumers ultimately finance new substations, transformers, overhead lines, cables and associated infrastructure. New grid investment may reduce future constraint expenditure, but that makes whole-system accounting more important, not less. The public should be shown both sides of the calculation: what the infrastructure costs and what it is expected to save.
THE CLIMATE CHANGE ACT SET THE DESTINATION — BUT WHERE IS THE COMPLETE ACCOUNT?
Behind this transformation sits the statutory framework established by the Climate Change Act 2008. In 2019, Parliament changed the 2050 target from an 80% reduction in greenhouse-gas emissions to 100% — Net Zero. The 2019 amendment order contains a sentence that deserves renewed attention in light of today’s infrastructure and system costs: “A full impact assessment has not been produced for this instrument.”
Individual measures have of course been assessed since then. Wind schemes have assessments. Solar schemes have assessments. Grid projects, carbon pricing, transport, heating and storage have their own documents. But that is not the same as one national assessment examining what happens when all those costs, dependencies and infrastructure requirements are combined into a single system.
What is the total network requirement? How much dispatchable generation must remain? How much storage is needed, and for what duration? What happens when transmission projects are delayed? What are the cumulative balancing and constraint costs? What do carbon pricing and financing add? What is the impact on industry, fuel poverty and household bills? Those questions belong together.
THE FIGURES TO REMEMBER
July 2026 gives us a remarkably concise picture of why that national assessment matters. Voltage-control costs went from £11.0 million to £40.8 million in a year. Thermal constraints went from £92.2 million to £167.8 million. Wind output fell from 4.6 TWh to 4.0 TWh. Gas remained NESO’s largest generation source. Interconnectors supplied around a fifth of the mix. And during record solar output NESO still had to instruct additional, predominantly gas-fired units to provide voltage support.
These figures describe three problems inside the same electricity system. When weather-dependent output is low, firm generation is required. When large amounts of electricity are produced behind grid bottlenecks, constraint intervention is required. When high inverter-connected generation suppresses synchronous plant, additional system services may have to be procured. Scarcity can cost money, abundance can cost money, moving electricity can cost money and stabilising the system can cost money.
STOP BLAMING ONE FUEL FOR THE COST OF AN ENTIRE SYSTEM
The historical gas comparison should change how this debate is conducted. Wholesale gas in 2024 and 2025 was below the inflation-adjusted equivalent of the 2008 price, yet Britain’s electricity system is carrying constraint-management, redispatch, voltage, inertia, carbon-pricing and network-expansion costs on a scale that barely existed when the Climate Change Act was passed.
Gas cannot explain all of those costs. In many cases gas is the technology being called upon to solve a problem elsewhere in the electricity system. A gas station replacing wind trapped behind a transmission bottleneck did not create the bottleneck. A gas station instructed to provide voltage support during record solar conditions did not create the fall in synchronous generation. Yet the cost of that gas action can appear at the end of both processes.
The question consumers should therefore ask is not simply, “What did gas cost?” It is: why did the system need that gas, what created the cost before the gas station was dispatched, and what other charges were added around it?
MAKE THEM SHOW THE EVIDENCE
This summer’s figures are exactly why Britain needs one comprehensive assessment of the costs and physical requirements of its statutory climate targets. Parliamentary Petition 780321 — “Suspend Climate Change Act targets & undertake a full national impact assessment” calls for an independent national assessment of the public and private costs, effects on energy bills, fuel poverty, industry, food and energy security, and the land and infrastructure required for wind, solar, networks, substations and storage.
The petition remains open until 21 March 2027. You can read and sign Parliamentary Petition 780321 here.
The issue is larger than another quarterly bill increase. Britain is rebuilding an electricity system around legally binding targets while the operational evidence is already showing the cost of constraints, balancing, stability services and network mismatch. If that programme is economically and technically sound, a complete national assessment should be able to demonstrate it.
The public should not be asked to judge the programme from one wind-farm price, one solar price or one quarter’s gas market. It should be shown the entire system.
MAKE THEM SHOW THE EVIDENCE.
Shane Oxer — Campaigner for fairer and affordable energy
Evidence note: Historical gas figures cited above use DECC annual averages of ICIS Heren NBP day-ahead prices; the recent comparison uses published UK NBP market-marker data, so the series are not methodologically identical but are suitable for illustrating the broad long-run wholesale comparison. Inflation adjustment uses the ONS CPI index. July voltage, generation, balancing and constraint figures are taken from NESO’s July 2026 Monthly Balancing Cost Report. The 2024/25 constraint figures and the 2030/31 projection come from DESNZ’s Reformed National Pricing Delivery Plan.
Leave a Reply