On a windy night in Scotland in early 2026, National Grid ESO paid wind farm operators in the north of England and Scotland to turn off their turbines. The constraint payments that night ran to millions of pounds. The wind farms themselves were generating electricity that the grid simply couldn’t move south fast enough to meet demand in the areas where it was needed. The turbines stopped spinning. The payments went out. And the gas-fired plant in the midlands kept running to fill the gap.

This is curtailment — and it’s becoming one of the central cost problems in the UK’s transition to a renewable energy-dominated grid.

How Curtailment Happens

The UK grid has a physical constraint: electricity generated in Scotland and the north of England has to travel south through a network of transmission lines with limited capacity. When generation in the north exceeds what the interconnectors can carry, the system operator has two options — tell northern generators to reduce output, or find a way to store or divert the excess.

Storage at scale is still being built. So the practical answer, most of the time, is curtailment. National Grid ESO, operating the balancing mechanism, offers a price to generators who are willing to reduce or stop generating. Generators who accept the offer are paid their bid price, which is typically based on what they would have received by selling the electricity in the market. For wind farms with low operating costs and no fuel bills, this means being paid roughly market rate for electricity they didn’t generate.

In theory this should resolve the imbalance. In practice the costs are borne by electricity consumers through network charges, and the total curtailment bill has grown substantially as UK renewable capacity has expanded without commensurate transmission reinforcement.

The Numbers in 2026

Curtailment costs for wind in Great Britain crossed £1 billion annually for the first time in 2025 and have continued to rise in 2026 as new offshore capacity in the North Sea came online ahead of the transmission upgrades needed to absorb it. Ofgem has published preliminary assessments suggesting that without accelerated transmission investment, curtailment costs could reach £3-4 billion annually by 2030.

For context: these costs appear in consumer bills as part of network charges. The money is not wasted in an absolute sense — it maintains system stability and pays for electricity that generators could have sold. But it represents a significant inefficiency in the energy system, paying twice for the same electricity unit (once as curtailment payment to a northern generator, once as running cost for a southern dispatchable generator that runs instead).

The geographic concentration of curtailment is notable. The B6 boundary — the electrical bottleneck between Scotland and England — accounts for a disproportionate share of constraint costs. Individual wind farms in Scotland with high curtailment exposure have reported effective load factors significantly below their technical capacity because of the frequency with which they’re asked to reduce output.

The Balancing Mechanism and BM Pricing

For generators large enough to be directly dispatched in the balancing mechanism (above 1MW is the technical threshold, though in practice BM participation requires investment in infrastructure and trading capability), curtailment happens through bid/offer pairs submitted to National Grid ESO. A wind farm submits a bid — the price at which it is willing to reduce generation — and the system operator accepts bids from the cheapest offer up to the volume needed to resolve the constraint.

The bid price is typically set at or close to the market reference price, ensuring generators aren’t substantially worse off from curtailment than from generating and selling. But the calculation interacts with subsidy contracts — generators with Contracts for Difference receive top-up payments based on generation volumes, and curtailment reduces the generation volume against which the CfD settlement is calculated. The interaction between CfD payments and constraint payments has been a contested regulatory area, with generators arguing that the current settlement framework creates uncertainty in curtailment-exposed locations.

Locational Pricing: The Policy Debate

The UK’s current wholesale electricity market uses a single national price — meaning generators in Scotland receive the same market price as generators in the south, regardless of whether their electricity can actually be delivered to where it’s needed. This is the fundamental driver of curtailment costs: there is no price signal discouraging new renewable build in the most constrained locations.

Locational marginal pricing (LMP) — the system used in US electricity markets, where the market clearing price varies by grid location based on transmission constraints — would theoretically provide exactly this signal. Wind farms in highly constrained locations would receive lower prices, reflecting the reduced value of their output to the system.

The UK government and Ofgem have been consulting on locational pricing since the early 2020s. The Review of Electricity Market Arrangements (REMA) process, which concluded its assessment phase in 2025, found significant support for a move toward locational pricing among network operators and large industrial users, but substantial opposition from renewable developers concerned about the impact on project economics in constrained regions. A policy decision remains outstanding as of mid-2026.

In the interim, National Grid ESO has implemented targeted charges — TNUoS zonal tariffs that vary by location — that go some way toward the same effect, charging generators in constrained zones more for their transmission access. These charges have modestly slowed new build in the most constrained zones but have not resolved the fundamental infrastructure gap.

What Developers Can Do

For project developers working with renewable sites in constrained areas, curtailment risk has become a standard input to project finance modelling. Lenders increasingly require curtailment assessments as part of due diligence, and the assumptions used — particularly around future transmission investment timescales — significantly affect project valuations.

Battery storage co-location has become a standard risk mitigation tool for large wind farms in constrained locations. A co-located battery can absorb generation that would otherwise be curtailed and export it when constraint conditions ease, improving the effective capture rate. The economics depend heavily on the spread between constrained-on and unconstrained market prices, which varies significantly by year and grid location.

Power purchase agreements that specifically address curtailment risk — sharing the exposure between generator and offtaker, or with floor price provisions that activate under high-curtailment conditions — are increasingly negotiated into corporate PPA contracts, particularly for buyers committed to 24/7 matching of their renewable procurement with their actual consumption.

The underlying infrastructure problem — transmission capacity that can move renewable power from where it’s generated to where it’s consumed — requires long lead times and significant capital. The National Grid’s Holistic Network Design for offshore wind, and the various onshore transmission reinforcement projects under the Accelerated Strategic Transmission Investment programme, are expected to reduce the constraint severity over the next decade. For developers making investment decisions on projects that will operate through that period, the trajectory matters more than the current position.