Britain’s Contract for Difference (CfD) has become one of the world’s most influential renewable support mechanisms. It gives developers a predictable, inflation-linked strike price and shields them from much of the volatility of the wholesale market. In return, consumers benefit when market prices rise above that strike price. The model has helped turn offshore wind from a niche technology into a major national industry. It gave investors certainty.
Its elegance is also its limitation. The standard CfD is primarily designed to procure low-carbon megawatt-hours at a competitive price. It does not, by itself, fully express the value of generating in a particular place, producing at a particular time or reducing pressure on a constrained network. As the renewable fleet grows, those system differences matter more.
This is sometimes described as a ‘build it anywhere’ model. That is a little too simple: projects still face planning rules, network charges, connection offers and physical geography. But the central CfD payment is largely national rather than locational. A megawatt-hour receives the contracted strike price whether it arrives in a region hungry for power or behind a boundary where the grid is already saturated.
A successful mechanism meets a changing system
Under the current scheme, generators are paid against their actual metered output, subject to rules including the withdrawal of difference payments during negative-price periods for contracts from Allocation Round 4 onwards. That output link gives investors confidence: produce eligible electricity and the contract stabilises revenue. It has been highly effective for financing capital-intensive projects.
Yet the same protection can weaken operational signals. DESNZ’s April 2026 Reformed National Pricing delivery planacknowledges distortions in day-ahead, intraday and balancing markets. It also shows the scale of the physical problem. Wind generators were paid £370 million to turn down in 2024/25, while turning up replacement gas cost £910 million. Without mitigation, the government’s cited modelling suggests constraint costs could peak at around £7 billion in 2030/31, although the outcome depends heavily on network and generation build.
Those figures do not mean that wind is the problem. They mean that generation, networks, demand and market design are arriving on different timetables. Building more clean power is essential. Building it without enough transmission, storage, flexible demand or locational coordination can be expensive.
Why DESNZ ruled out a deemed CfD
One proposed answer was the deemed CfD. Instead of paying according to actual output, it would pay according to what a plant could theoretically have generated. The attraction is clear: decouple support from physical production and a renewable generator may have less incentive to produce into oversupply or submit very negative bids simply to preserve subsidy income. It’s a model considered in other European countries.
On 21 April, DESNZ ruled that option out. Its judgement focused on four risks: gaming estimates of deemed generation, cross-portfolio manipulation, over-protection from market risk and consumers paying for hypothetical output during curtailment. It also highlighted the complexity and administrative cost of creating robust generation estimates for different technologies. The department concluded that the value-for-money and deliverability risks outweighed the benefits.
That judgement is understandable but disappointed key players such as SSE. A market design that depends on measuring an unobservable counterfactual creates fertile ground for argument and optimisation. If the calculation is generous, consumers overpay. If it is too tight, investment suffers. The April decision therefore keeps actual output at the heart of the CfD for now.
Capacity-based CfDs remain on the table
DESNZ has not closed the reform discussion. It says it will continue considering a capacity-based CfD and how future support can align with the Strategic Spatial Energy Plan and other siting and investment levers. A capacity-based approach would shift some emphasis from paying each unit of output towards paying for supported capacity, potentially leaving generators more exposed to operational market signals.
That could improve dispatch incentives, but it raises its own design questions. How much energy availability should be required? How should degradation, outages and technology differences be treated? Would investors demand a higher return for taking more volume and price risk? And would the mechanism genuinely lower whole-system costs once financing costs are included?
Wholesale CfDs answer a different question
The same April package introduced another idea: voluntary Wholesale Contracts for Difference for eligible existing generators that are not already contracted under a CfD. The initial concept is aimed particularly at exchanging an eligible generator’s forward wholesale revenues for a fixed power price, while existing Renewables Obligation (RO) support would continue separately. Government intends to consult and would only offer contracts where it believes they provide value for consumers.
This is important, but it is not a direct substitute for the deemed CfD. The policy problem is different. A Wholesale CfD is intended to reduce the exposure of existing renewable output – and consumers – to volatile gas-linked wholesale prices. It does not automatically solve locational constraints or reward generation at the most useful hour.
Location: move beyond a national average
The cheapest project at the point of auction may not be the cheapest project for the system. A wind farm behind a congested boundary can require new transmission or repeated constraint actions. A slightly more expensive project closer to demand, storage or available network capacity may create greater whole-system value.
That does not necessarily mean turning the CfD auction into a full locational market. Locational signals can come from several places: network charging, connection reform, spatial planning, zonal auction parameters, differentiated budgets or separate incentives for strategic areas. The important point is consistency. Developers need a credible long-term view of where the country wants capacity, what network will be available and which risks they are expected to carry.
Timing: not every clean megawatt-hour is equal
A unit of electricity produced during a tight winter evening is more valuable to the system than one produced during a period of national oversupply. As storage and flexible demand grow, some of that difference can be managed. But future support should still avoid rewarding output that repeatedly arrives when the system cannot use it.
Timing could be reflected through stronger exposure to market prices, availability requirements, technology-specific design or complementary flexibility markets. The challenge is to preserve the bankability that made the CfD successful while allowing more operational information to reach the asset. Too little exposure produces distortions; too much can raise financing costs and slow deployment.
Evolution, not demolition
My instinct is not to tear up the CfD. Its greatest achievement is lower-cost capital, and Britain will need a great deal more capital to build the generation required for 2030 and beyond. Reform that undermines investability could save money in one part of the system and lose more elsewhere.
The better route is disciplined evolution. Keep a dependable route to market for new low-carbon generation. Use the Strategic Spatial Energy Plan, connections reform and network investment to give stronger locational direction. Let operational markets communicate scarcity and flexibility. Test whether capacity-based support can reduce distortions without making projects unfinanceable. And treat Wholesale CfDs as a separate consumer-price intervention whose costs and benefits must be demonstrated transparently.
The first generation of CfDs asked: how cheaply can we build renewable electricity? The next generation must add three questions: where should it connect, when will its output be valuable, and what does it contribute to the wider system? That is not an argument against more renewables. It is the argument for making the next wave easier to use.
