What "Price" means, and why cheaper generation does not always mean cheaper bills

What the "Price" figure actually is

Great Britain's wholesale electricity market works on a day-ahead and within-day basis: generators and suppliers trade power for delivery in specific half-hour periods. The price shown here tracks that wholesale/system price in £ per megawatt-hour (£/MWh) - it is not the retail price on a household bill, which bundles in network charges, policy costs, supplier operating costs and VAT (covered further down this page).

How the price is set: merit order and marginal pricing

GB's wholesale market is "pay as clear": generators bid the price they are willing to accept, cheapest first, and the market keeps accepting bids up the cost order - the merit order - until enough power is committed to meet demand. Crucially, every accepted generator gets paid the price of the last, most expensive bid needed to meet demand - the marginal price - not their own bid.

Wind and solar have near-zero marginal cost - once built, an extra unit of output costs them almost nothing - so they are accepted first. Gas-fired plant has to buy fuel and pay for its carbon, so it is very often the last, most expensive generator needed to balance the system. That means gas very often sets the wholesale price, even on days when gas supplies only a minority of actual generation. When gas is expensive (as during the 2021–2023 global gas crisis), it drags the price paid to every generator up with it, including wind and nuclear producing at near-zero cost.

This system exists because it is judged the cheapest way to run the market overall - generators do not need to guess competitors' costs to bid honestly, and it rewards low-cost, low-carbon plant with a margin that pays for further investment. But it does mean the headline price tracks gas even as gas's share of generation shrinks.

Contracts for Difference: decoupling renewables from the gas price

Most new large-scale wind, solar and other low-carbon projects in GB are built under a Contract for Difference (CfD) - a government-backed contract, administered by the Low Carbon Contracts Company (LCCC), that pays the generator a fixed strike price per MWh agreed at auction, regardless of what the wholesale market price does. It is the main mechanism the government uses to get new low-carbon generation built, because it gives developers and their lenders a predictable, bankable revenue stream instead of exposing a multi-billion-pound wind farm to volatile wholesale prices for 15–20 years.

How the mechanics actually work

A CfD generator still sells its power into the wholesale market as normal, and still receives the market price for it. Separately, every settlement period the LCCC compares that market outcome to the generator's strike price and pays - or charges - the difference:

• If the reference price is below the strike price, the LCCC tops the generator's income up to the strike price. This top-up is funded by the CfD Supplier Obligation, a levy charged to every electricity supplier in proportion to their share of the market, which suppliers pass through to customer bills - it is part of the "policy costs" slice of the bill breakdown below.
• If the reference price is above the strike price, the generator pays the difference back to the LCCC, which reduces the levy (or funds rebates) for everyone else.

Two details that often get missed: the comparison uses a reference price, not the real-time system price - for most technologies this is the GB day-ahead auction price (a separate, slightly different benchmark from the balancing-mechanism "system price" that spikes during shortages), averaged over the settlement period. And since 2015, most new CfDs have included a negative pricing rule: if the wholesale price stays negative for six or more consecutive hours, the generator's payments stop, so the scheme does not pay renewables to keep running when the grid does not want the power.

CfDs are awarded competitively by sealed-bid auction ("Allocation Rounds", AR1 through AR7 so far), split into technology "pots" - established technologies like onshore wind and solar compete in one pot, offshore wind has its own pot, and emerging technologies (floating offshore wind, tidal stream) compete in a separate pot so they are not priced out by cheaper mature technologies. Within each pot, cheapest bids win until the budget or capacity cap is used up.

Worked example: a contracted offshore wind farm

Say a wind farm cleared Allocation Round 6 (September 2024) at that round's offshore wind strike price of roughly £77.50/MWh (2024 prices). Here is what happens to its income in two different half-hour periods:

Worked example using a real AR6 strike price and a 500MW farm producing at full output for one half-hour (0.5h × 500MW = 250MWh); actual settlement uses metered output and the day-ahead reference price for the period, not full-capacity assumptions.

Either way, the generator's realised income per MWh converges on £77.50 regardless of what the wholesale price does that day - that is the entire point of the contract. Across a typical year the same farm will draw top-ups on calm, low-price days and pay clawbacks on tight, high-price days; developers bid a strike price low enough to win the auction but high enough that the blended result over 15–20 years covers their costs and financing.

What auction strike prices have actually done

Contrary to the assumption that renewables just keep getting cheaper, GB's CfD offshore wind strike prices rose sharply between the mid-2020s auctions after several years of decline: from about £37/MWh (2012 prices) in AR4 (2022) to about £59/MWh in AR6 (September 2024), and further to roughly £90/MWh in AR7 (results announced January 2026). This reflects higher interest rates, global supply-chain and turbine-cost inflation, and stronger competition for the same shipyards and cable factories from other countries' offshore wind programmes - not a change in the underlying economics of wind itself. See the 2030 plans page for the full history of auction rounds and capacity awarded.

Either way, CfDs only smooth the price paid to contracted generators; they do not change how the wholesale market sets its clearing price for everyone else, which is still driven by the marginal, usually gas-fired, plant on the grid at that moment.

Sources

• Low Carbon Contracts Company - CfD settlement mechanics and the Supplier Obligation levy.
• GOV.UK: CfD Allocation Round results (AR4–AR7) - official strike prices and capacity by round.
• Regen: CfD AR6 results analysis and Herbert Smith Freehills Kramer: AR6 results - AR4→AR6 strike-price comparison.
• Energy UK: AR7 offshore wind results explained - AR7 clearing prices.

So if renewables are cheaper, why is not electricity cheaper?

Two separate effects are at work, and both matter.

1. Marginal pricing means the wholesale price reflects the last unit, not the average

Even on a windy day when most electricity comes from near-zero-marginal-cost wind, the wholesale price is usually still set by the last, most expensive unit of gas needed - so the average cost of generation can fall while the price paid for every unit stays tied to gas. Cheaper renewables reduce how often and how much gas is needed, and via CfDs some of that saving does flow through, but it is not a direct pound-for-pound pass-through to the wholesale price.

2. Wholesale is a shrinking share of what is actually on a bill

A domestic bill under Ofgem's price cap is made up of far more than wholesale energy costs. For the 1 October to 31 December 2026 cap, wholesale costs (including Contracts for Difference) made up 47% of a typical direct-debit bill for gas and electricity together, up from 44% in July to September. Network charges, operating costs, policy costs and VAT make up most of the rest.

Crucially, network costs have been rising even as wholesale costs eased through 2026 - the House of Commons Library reports wholesale costs falling from around £690 to £652 (on an annualised typical-bill basis) between the January–March and April–June 2026 cap periods, while network costs rose from around £397 to £463 over the same change, driven by new grid investment (much of it needed to connect new renewables and reinforce the network for electrification). So a fall in wholesale costs can be, and recently has been, largely offset by rising network costs - which is a big part of why "renewables are cheap now" has not yet translated into noticeably lower bills.

There is a genuine, actively debated policy question behind this: advocates of "market reform" or splitting the GB price zone argue the current UK-wide marginal-pricing system overstates the benefit gas retains even as it is displaced, and that regional or reformed pricing could pass more renewable savings through faster. Others argue the current system's simplicity and investor certainty are themselves valuable, and that network costs - not the pricing mechanism - are the real driver of near-term bills. This page does not take a side on that debate; it is presented here so you can follow the reasoning either way.

Sources

• DESNZ: Electricity Generation Costs 2023 - Table 10, fuel, carbon and running costs per MWh for the merit order chart.
• Energy UK - industry explanation of why marginal pricing is used and its intended benefits.
• House of Commons Library: What costs make up an electricity bill? - wholesale/network/policy cost breakdown and trend figures.
• Ofgem: energy price cap update from 1 October 2026 (26 August 2026) - the bill breakdown and the wholesale share (47%).
• Ofgem: energy price cap unit rates and standing charges - current rates and the £1,723 typical bill.
• Low Carbon Contracts Company - the government-owned counterparty for Contracts for Difference.

What has changed on bills since 2021

Ofgem publishes what makes up the price cap each time it changes. Comparing the October 2021 cap with the October 2026 cap shows where the money goes now. A typical direct-debit bill for gas and electricity was £1,277 a year from 1 October 2021 and is £1,723 from 1 October 2026.

Wholesale costs are the biggest part of a bill and a bigger share than in 2021: 47% now, against 41%. Network charges have also grown, from 21% to 24%. Policy costs, which include support for renewables, have fallen from 12% to 6% of the bill.

Sources

• Ofgem: default tariff cap update from 1 October 2021 - Figure 1, breakdown of the cap in £.
• Ofgem: energy price cap update from 1 October 2026 - Annex 1, breakdown of the cap as a share of the bill.
• Ofgem: energy price cap and standing charges explained - what each cost covers.