The UK Electricity System

The GB electricity transmission system is operated by the National Energy System Operator (NESO), the public corporation that took over the role from National Grid plc on 1 October 2024. NESO is responsible for balancing electricity supply and demand in real time, managing system security, and dispatching generators within the operating envelope of the physical network. It does not own wires. Those belong to three regulated Transmission Owners, covered on the Transmission Network page.

Generators sell their output into wholesale electricity markets, typically in the day-ahead and intraday auctions run by exchanges such as EPEX and N2EX. At the same time, every generator large enough to participate is also registered in the Balancing Mechanism, where NESO can issue real-time instructions to change output above or below what the generator had sold.

The Balancing Mechanism

The primary tool NESO uses to manage second-by-second system balance is the Balancing Mechanism (BM). Every half-hour settlement period, registered generators submit bids and offers to the BM. These are the prices, expressed in pounds per megawatt hour, at which the generator is willing to change its output from whatever it had sold in the wholesale market.

• Offers: the price to increase generation above the sold position
• Bids: the price to decrease generation below the sold position

When NESO accepts one of these bids or offers, the generator receives a Bid Offer Acceptance (BOA). The generator must comply, and payment follows based on the accepted price and the volume of energy moved. For curtailment of a wind farm, NESO is accepting a bid to reduce output, and the wind farm is paid for the generation it was contracted to deliver but is being instructed not to.

Why Curtailment Happens in the UK

Curtailment in the UK is primarily driven by transmission constraints. A large and growing share of GB wind generation sits in Scotland, while most of the electricity demand sits in England. When the wind is blowing hard, the transmission capacity between the two is not always sufficient to carry the Scottish output south to where it is needed.

NESO models the transmission network as a set of zones separated by notional boundaries, the engineering limits beyond which power cannot safely flow. The binding boundary for UK offshore wind is B6, the notional line across the Scotland-England border. B4, an internal Scottish boundary, adds a second layer of constraint for farms further north. When flows across B6 approach the transfer limit, NESO issues BOAs to generators north of the line to reduce output, and to generators south of it to increase output. That sequence, turn down one, turn up another, is the physical mechanism behind every curtailment event.

Around 98 percent of curtailed renewable generation in Great Britain originates in Scotland. Seagreen, Scotland's largest offshore wind farm at 1,075 MW, has seen curtailment rates exceeding 70 percent in some periods, with annual constraint payments in the tens of millions. Viking, Moray East, and Moray West show similar patterns.

Common causes of curtailment

• Transmission congestion, most commonly at B6 and B4 in Scotland
• High renewable output coinciding with low demand, typically overnight and in the shoulder seasons
• Grid stability requirements, including the need to maintain sufficient synchronous inertia and reactive support
• Maintenance outages on transmission lines, which temporarily reduce boundary capability further

The last point is underrated. Much of the ongoing transmission reinforcement work in Scotland actually reduces operational capability while it is under way, because lines have to be taken out of service to be upgraded. Analysis by UKERC shows that a 500 MW increase in B6 capability through 2024-2025 could have cut constraint costs by around 25 percent, which suggests that a meaningful share of the current bill is the cost of rebuilding the network we need.

Example Curtailment Event

To make the mechanics concrete, a simplified single-hour curtailment event for a 500 MW offshore wind farm:

That is only half the bill. To maintain supply to English demand, NESO also has to accept an offer from a gas plant south of B6 for the same 150 MWh. A typical gas plant offer price might be anywhere from £100 to £300 per MWh depending on wholesale conditions. At £150/MWh that adds another £22,500 to the same hour, a total system cost of £33,000 to deal with 150 MW of constrained wind for one hour.

How Curtailment Appears in Data

Curtailment events are visible through several public data signals:

• Balancing Mechanism dispatch data, published by Elexon and NESO, showing every BOA issued by unit and by settlement period
• Wind farm generation data, published through BM Reports at the BM Unit level
• System and wholesale prices, which react to constraint events

However, generation data alone does not explicitly label curtailment events. A turbine producing below its rated output might be curtailed, or it might be in a low-wind period, or it might be on a scheduled maintenance outage. None of those look different in the raw metered output stream.

Instead, analysts have to combine multiple datasets. A curtailment event is typically inferred by comparing expected generation (from wind speed, power curve, and assumed availability) against actual metered output, cross-referenced against BOA instructions for the same settlement period. If the farm is producing well below expected, and NESO issued a reducing BOA in the same half-hour, the difference is almost certainly curtailment. Public trackers such as the Wasted Wind project stitch these signals together to produce farm-level estimates.

Estimating Curtailment from Generation Data

Curtailment can be estimated by comparing expected wind generation with actual output, then attributing the shortfall when a BOA is present:

If this shortfall coincides with an accepted BOA to reduce output from the same BM Unit, the attribution is reasonably robust. Expected generation is the harder half of the calculation because it depends on choice of power curve, assumed availability, wake effects across the farm, and weather reanalysis accuracy. Different estimators produce different numbers for the same event, and any farm-level curtailment figure in the public domain should be read as an estimate with error bars rather than a measured quantity.

Support Schemes and Curtailment Payments

It is also important to separate curtailment compensation from the broader support scheme under which a wind farm operates. The two are distinct payment streams with different rules, and conflating them is the source of most of the misunderstanding in public commentary.

In the UK, offshore wind farms are supported under either the legacy Renewables Obligation (RO) regime, where eligible generation earns Renewable Obligation Certificates (ROCs) that obligated electricity suppliers must purchase, or under a Contract for Difference (CfD), where the generator is paid the difference between a strike price and a reference market price for the electricity it produces. The RO closed to new entrants in 2017 but supports most first-generation UK offshore wind, including Seagreen. The CfD is the current support mechanism for all new build.

Both schemes support renewable generation economics, but the payment associated with a curtailment event is not a support payment. It is a BM payment, made by NESO out of BSUoS charges levied on consumers. The BM bid price a wind farm offers reflects the revenue it would have earned had it generated, which includes its wholesale value plus its ROC or CfD value. In that sense, curtailment compensation is a make-whole, not a bonus.

For newer CfD-backed assets, an important interaction applies: from AR5 onwards, CfD contracts include a negative price rule that suspends CfD top-up payments during sustained periods of negative wholesale prices. This means newer farms like Moray West can submit more competitive BM bids because the lost revenue during negative-price curtailment periods is smaller. The effect is to reduce the turn-down cost NESO pays but not the underlying transmission problem. Support scheme design and curtailment incentives interact, but they are not the same thing.

Economic Impact of Curtailment

Curtailment has important financial implications for both wind farm operators and electricity consumers, but the flow of money is often misread. Wind farm operators receive make-whole BM compensation, which does not enrich them, it keeps them whole against the output they would have delivered. The larger cost, typically two to three times the curtailment payment in any given event, is the payment to the alternative generator that has to run in its place. In the UK, this is almost always a gas plant.

All of these costs are recovered through BSUoS (Balancing Services Use of System), a per-megawatt-hour charge applied to transmission system users, which in practice means every electricity consumer in Great Britain. Ofgem has estimated that constraint costs added approximately £15 to a typical household bill in late 2025. The charge is opaque to the end consumer, but it is real, and it is rising.

The honest framing, and the one political commentary rarely reaches, is that the curtailment bill is not primarily a subsidy problem or a renewables problem. It is a transmission problem. The fix is to build more cables between Scotland and England, and to rebuild the onshore corridors connecting Scottish wind to the rest of the country. Nothing about the economics of wind, the design of the CfD, or the operation of the BM changes this. The wires are the binding constraint, and until they are larger, the bill will be larger.

Future Curtailment Trends

Curtailment volumes in the UK are expected to increase in the near term as renewable capacity grows faster than transmission capability. NESO's own balancing cost forecasts suggest annual constraint costs could reach £4 to £8 billion by 2030 in the absence of significant network reinforcement. Several parallel developments may influence the trajectory.

• New offshore wind capacity: the CP30 pipeline adds gigawatts to the fleet over the next five years, most of it still north of B6. Without matching grid, each new project adds to the constrained volume.
• The Eastern Green Links: a programme of four to five subsea HVDC cables between Scotland and England, each around 2 GW. EGL2 was approved by Ofgem in 2025 at a capital cost of £4.3 billion, the largest single UK transmission investment ever approved. Most of the EGLs will not deliver until 2029 or later.
• Onshore reinforcement: reconductoring of 275 kV corridors to 400 kV, phase-shifting transformers at key nodes, and route upgrades across Scotland and northern England. Paradoxically, this work is currently reducing operational capability because lines are out of service while being upgraded.
• TMO4+ Connections Reform: the biggest overhaul of the connection queue in the system's history, moving from first-come-first-served to "first ready, first needed, first connect". Approved by Ofgem in April 2025 and implemented in June, with the new Gate 2 pipeline confirmed in December 2025.
• Energy storage deployment: battery storage cannot replace transmission capacity, but it can absorb some pre-constraint generation and reduce the curtailment peak. Commercial deployment is growing quickly.
• Market reform: the Review of Electricity Market Arrangements (REMA) includes zonal pricing as a live option. If adopted, it would change the siting signal so that new generation responds to local network capacity rather than ignoring it.

Improving visibility into curtailment events will become increasingly important for renewable asset owners, investors, and policymakers. EOS Omnia surfaces curtailment estimates, BOA data, and wind farm performance in a single view, so that the difference between expected and delivered generation can be tracked at farm, operator, and system level over time.

Glossary