UK offshore wind and the grid: what it means for bills

How much UK electricity comes from wind now

Renewables generated a record 53.1% of UK electricity in the first quarter of 2026, according to DESNZ Energy Trends published in June 2026. That figure covers all renewable sources and marks the highest share recorded for any quarter. Within that total, wind generated 35.6% of UK electricity, or 29.3 TWh, up from 28.5% in the same quarter a year earlier. Offshore wind alone generated 20.5% of UK electricity, or 16.9 TWh, up from 16% and 12.9 TWh in Q1 2025. The year-on-year increase in offshore wind output reflects both new capacity coming online and favourable wind conditions during the quarter. Onshore wind makes up the remainder of the wind total. The combined wind share of 35.6% means more than a third of the electricity used in the UK during the quarter came from wind farms, with offshore installations contributing the majority of that growth. These figures are official statistics from the Department for Energy Security and Net Zero, not projections or estimates. They show the current position of renewables in the generation mix and provide the baseline against which future quarters will be compared. The record renewable share also reflects lower overall electricity demand and reduced output from fossil fuel plants during the period.

The quarterly data matters because it shows how quickly the generation mix is changing. Offshore wind has moved from a marginal contributor to providing more than a fifth of UK electricity in a single quarter. That shift has implications for the grid, for the auction system that supports new projects, and for household bills. Each of those areas is covered in the sections below. The 53.1% renewable figure is a snapshot of one quarter and will vary with weather and demand, but it establishes the scale of the transition already under way. The DESNZ data also confirms that wind, both onshore and offshore, is the largest single source of renewable electricity in the UK. Gas remains the largest single source overall in many periods, but its share continues to fall as renewable capacity expands. The Q1 2026 figures are the most recent official statistics available at the time of writing.

What the latest offshore wind auction bought

Contracts for Difference Allocation Round 7, known as AR7, awarded 8,437.5 MW of capacity, or about 8.4 GW, almost all of it offshore wind. The results were published by GOV.UK in January 2026. Of that total, 6,865 MW of offshore wind in England and Wales was awarded at a strike price of £91.20 per MWh in 2024 prices, equivalent to £65.45 in 2012 prices. A further 1,380 MW of offshore wind in Scotland was awarded at £89.49 per MWh in 2024 prices, or £64.23 in 2012 prices. The auction also awarded 192.5 MW of floating offshore wind at £216.49 per MWh in 2024 prices, which is more than twice the fixed-bottom offshore price. The floating wind premium reflects the earlier stage of that technology and the higher costs of installing turbines on floating platforms in deeper water. The AR7 offshore wind projects are due to deliver between 2028/29 and 2030/31. That delivery window means the capacity bought in this auction will not affect generation figures for several years. The strike prices are set in 2024 prices and are indexed over time, so the nominal payments will be higher when the projects begin generating. The auction results show the prices at which developers agreed to build, and they provide the basis for the CfD payments described in the next section. The split between England and Wales and Scotland reflects the different offshore sites and the separate administrative arrangements for each region.

The AR7 outcome is significant because it contracted more offshore wind capacity than any previous round. The 8.4 GW total is roughly equivalent to the output of several large gas-fired power stations, though it will generate only when the wind blows. The strike prices awarded in AR7 are lower in real terms than those in earlier auctions, which reduces the expected cost to consumers per unit of electricity generated. The floating wind allocation, while small in capacity terms, establishes a price benchmark for a technology that could be deployed in deeper waters around the UK coast in future rounds. The delivery dates between 2028/29 and 2030/31 mean the projects will connect to the grid during a period when the connection queue is being reformed, as described below. The auction is one part of the system that brings new renewable capacity forward, and its results feed directly into the CfD mechanism that determines how generators are paid.

How a Contract for Difference works

A Contract for Difference, or CfD, is a two-way payment agreement between a generator and a government-backed counterparty. Under the scheme, the generator receives a strike price for each unit of electricity it produces. When the wholesale price of electricity is below the strike price, the gap is topped up through a levy on electricity suppliers, and that levy is passed to household bills. When the wholesale price is above the strike price, the generator pays the difference back, which reduces the cost to suppliers and ultimately to bills. The mechanism is designed to stabilise revenue for generators and to protect consumers from paying above-market prices when wholesale costs are high. The strike price is set in the auction, so the AR7 prices of £91.20 per MWh in England and Wales and £89.49 per MWh in Scotland in 2024 prices are the reference points for those projects. The payments are calculated against a reference wholesale price, and the difference flows in one direction or the other depending on market conditions. The CfD scheme design is set out by GOV.UK and applies to the projects awarded in each allocation round. The levy that funds top-up payments is collected from electricity suppliers, and suppliers recover those costs through the prices they charge customers. The net effect on bills depends on the relationship between wholesale prices and strike prices over the life of the contract.

In plain English, a CfD is a bet shared between generators and bill payers on the future price of electricity. If wholesale prices turn out low, bill payers make up the difference to the generator. If wholesale prices turn out high, the generator returns the difference, and that money offsets what suppliers would otherwise charge. The scheme therefore smooths the cost of new renewable capacity rather than exposing generators to volatile wholesale markets. The AR7 strike prices are fixed in 2024 prices and indexed, so the actual payments will rise with inflation. The floating offshore wind projects awarded at £216.49 per MWh will receive a higher top-up per unit when wholesale prices are below that level, reflecting their higher costs. The CfD mechanism is separate from the network costs described in the next section, but both ultimately reach household bills through supplier charges and the price cap. The two-way nature of the contract means that periods of high wholesale prices can produce payments back to suppliers, which may reduce the net cost of the scheme to consumers.

The grid is the bottleneck

Before connections reform, around 722 GW of projects were waiting in the grid connection queue, roughly four times what the government's clean power targets need, according to NESO in December 2025. That queue included projects that had secured connection dates far in the future, often many years ahead, and it did not reflect the projects most likely to be built. NESO's connections reform results, published on 8 December 2025, gave 132 GW of renewable projects a connection date before 2030 under Gate 2 Phase 1. The reform cut the queue from 722 GW to 132 GW by removing projects that did not meet the new criteria and by prioritising those that could connect sooner. The 132 GW figure represents projects with dates before 2030, which is a much smaller and more deliverable set than the original queue. The bottleneck is not only the number of projects waiting but also the physical capacity of the transmission network. Offshore wind farms are built at sea, often far from the cities and industrial areas that use the most electricity. New transmission lines, substations and cables are needed to move that power from the coast to demand centres. Building that infrastructure takes time, requires planning consent, and often faces local opposition. The grid queue reform addresses the administrative backlog, but the physical build-out of the network remains a constraint on how quickly new offshore wind capacity can be connected and used.

The connection queue is a bottleneck because a project cannot generate and sell electricity until it has a grid connection. Even if an offshore wind farm is built and ready, it needs a cable and a connection point to deliver power to the network. The 722 GW queue was far larger than the capacity needed to meet clean power targets, which meant many projects were holding places in line without a realistic prospect of connecting soon. NESO's reform reduced the queue to 132 GW with pre-2030 dates, which aligns the pipeline more closely with what the network can actually accommodate. The reform also changes the way connection dates are allocated, moving away from a first-come, first-served system towards one that prioritises projects that are ready and that support the government's targets. For offshore wind, the connection challenge is particularly acute because the best sites are often in the North Sea and Irish Sea, while the largest demand is in London, the South East and other urban areas. New high-voltage transmission links are required to bridge that distance. The grid is therefore the bottleneck not because of a lack of projects but because of the time and cost of building the infrastructure to connect them.

What it means for your energy bill

Two separate cost streams from the electricity system reach household bills. The first is the CfD levy. When wholesale prices are below the strike price, the gap is topped up through a levy on electricity suppliers, and suppliers pass that cost to customers. When wholesale prices are above the strike price, the generator pays the difference back, which reduces the cost to suppliers. The net effect on bills therefore depends on the relationship between wholesale gas prices and the strike prices of the projects in the scheme. The second stream is network costs. Building and running the grid is one of the components of the Ofgem price cap, so grid expansion feeds into household bills over time alongside wholesale and policy costs. As the network is expanded to connect offshore wind and to reinforce the transmission system, those costs are recovered through charges that appear in the price cap. The price cap itself is set by Ofgem and reflects a range of costs, including wholesale energy, network charges, policy costs and supplier operating costs. The CfD levy and network costs are two of the policy and network components within that cap. The overall effect on any household bill depends on the balance of these components and on wholesale market conditions, which vary over time. No forecast numbers are given here because the net effect depends on future wholesale prices and on how quickly network costs are incurred.

The CfD mechanism is designed so that consumers pay the strike price rather than the wholesale price for the output of contracted projects. When wholesale prices are high, the generator pays back the difference, which can offset some of the cost. When wholesale prices are low, consumers pay the top-up. Over the life of a contract, the aim is to provide stable revenue for generators and stable costs for consumers. The AR7 strike prices of around £91 per MWh in 2024 prices are the reference points for the projects awarded in that round. The floating offshore wind projects at £216.49 per MWh will require larger top-ups when wholesale prices are below that level. Network costs are separate from the CfD levy and are recovered through the price cap. Grid expansion to connect offshore wind and to reinforce the network adds to those costs over time. The net effect on bills is therefore the sum of the CfD levy, network costs and other components of the price cap, and it varies with wholesale prices and with the pace of network investment. No prediction is made here about the direction or size of that net effect.

Where capacity is heading

Market analyst GlobalData forecasts UK installed power capacity to almost double between 2025 and 2035, with renewables making up 73% of capacity by 2035. That forecast was published on 15 October 2026 and is a commercial forecast, not an official projection. It is attributed here as a single data point and should be read alongside the official statistics and auction results described above. The GlobalData forecast covers installed capacity, which is the maximum output a plant can produce, rather than actual generation, which depends on weather and demand. The 73% renewable share of capacity by 2035 is a projection of how the mix could evolve if current trends continue. It is not a government target and it is not a statement of what will happen. The official figures for Q1 2026 show renewables at 53.1% of generation, which is a different measure from capacity share. The AR7 auction results show 8.4 GW of offshore wind contracted for delivery between 2028/29 and 2030/31. The NESO connections reform shows 132 GW of renewable projects with connection dates before 2030. These official figures provide the factual basis for understanding the direction of travel. The GlobalData forecast is included once, clearly labelled, and no other predictions are made in this article.

The distinction between capacity and generation matters when interpreting forecasts. A system can have a high share of renewable capacity but a lower share of renewable generation if the wind does not blow or the sun does not shine. The Q1 2026 figures show that renewables generated 53.1% of electricity, with wind at 35.6% and offshore wind at 20.5%. Those generation shares reflect actual output during the quarter. The GlobalData forecast of 73% renewable capacity by 2035 is a projection of installed capacity, not of generation. It is a commercial forecast and is attributed as such. The official data and the auction results provide the confirmed figures, while the forecast provides one view of how the system might develop. No other forecasts or predictions are made in this article. The facts set out above are drawn from GOV.UK, NESO, DESNZ, Ofgem and GlobalData, and each is attributed to its source.

Source: GOV.UK: CfD Allocation Round 7 results.

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Frequently asked questions

What is a Contract for Difference in simple terms?

A Contract for Difference is a two-way payment agreement. The generator receives a strike price for each unit of electricity. When the wholesale price is below the strike price, the gap is topped up through a levy on electricity suppliers, which is passed to bills. When the wholesale price is above the strike price, the generator pays the difference back.

How much of UK electricity came from renewables in Q1 2026?

Renewables generated a record 53.1% of UK electricity in the first quarter of 2026, according to DESNZ Energy Trends published in June 2026. Wind generated 35.6% and offshore wind alone generated 20.5%.

What did the AR7 auction award?

AR7 awarded 8,437.5 MW, or about 8.4 GW, almost all offshore wind. This included 6,865 MW in England and Wales at £91.20 per MWh in 2024 prices and 1,380 MW in Scotland at £89.49 per MWh in 2024 prices. It also awarded 192.5 MW of floating offshore wind at £216.49 per MWh in 2024 prices. Projects are due to deliver between 2028/29 and 2030/31.

Why is the grid connection queue a problem?

Before reform, around 722 GW of projects were waiting in the queue, roughly four times what clean power targets need. NESO's reform on 8 December 2025 gave 132 GW of renewable projects a connection date before 2030. The queue is a bottleneck because projects cannot generate and sell electricity until they have a grid connection, and offshore wind farms need new transmission from the coast to cities.

How do CfD payments and network costs affect household bills?

CfD payments are funded through a levy on electricity suppliers, which is passed to bills. When wholesale prices are above the strike price, generators pay back the difference, which can reduce costs. Network costs are one of the components of the Ofgem price cap, so grid expansion feeds into bills over time. The net effect depends on wholesale prices and on the pace of network investment.