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As DESNZ proposes tighter delivery assurance requirements, our consultation response asks whether a Capacity Market designed around traditional winter peaks fits the electricity system of the 2030s, or whether consumers risk paying more for security of supply while undermining the flexibility needed to deliver it. This insight explores these questions in more detail.
Every year, Great Britain's Capacity Market (CM) follows a familiar cycle of consultation, regulatory changes, prequalification and auctions, to secure the capacity needed to keep the lights on.
Underpinning this process is a substantial body of modelling and analysis, set out in the Electricity Capacity Report. From auction procurement targets to technology-specific de-rating factors, this evidence informs how much capacity we secure and how we assess its contribution to security of supply.
The principle is straightforward: consumers effectively pay an insurance premium to ensure capacity is available when the electricity system needs it most. In return, capacity providers must demonstrate their ability to deliver through testing and performance requirements, with penalties and potential termination fees if they fail to meet their obligations.
This year's proposed reforms focus on how capacity providers demonstrate their ability to deliver, with DESNZ proposing tighter testing requirements intended to provide greater assurance during system stress events. In particular, the proposals would restrict Satisfactory Performance Days (SPDs) to winter working days between 4pm and 7pm, alongside a requirement to demonstrate responsiveness during the core winter period.
As the electricity system evolves, we need to ask whether we're insuring against the right risks, securing the right cover and, crucially, paying the right premium. This is particularly important for Demand Side Response (DSR), where more prescriptive testing requirements could increase participation costs and undermine the business case for the flexibility the government wants to encourage.
Security of electricity supply has traditionally been associated with cold winter evenings, when demand is high and generation margins are tight.
Yet Electricity Margin Notices (EMNs) have also been issued during summer periods, illustrating that operational challenges can arise outside traditional winter peaks. While EMNs are distinct from Capacity Market Notices (CMNs), this raises a wider question about whether increasingly prescriptive winter testing requirements adequately reflect the range of conditions in which capacity may be needed.
As we move towards a more renewables-led electricity system, the timing and characteristics of system stress are changing. This raises questions about the mix of generation, storage and consumer-led flexibility needed to maintain security of supply.
"As such, it is the government’s view that testing requirements should be brought more in line with the conditions under which a System Stress Event (SSE) is likely to occur. This would provide greater assurance that committed capacity can deliver in similarly challenging circumstances." – DESNZ consultation on changes for Prequalification 2027
DESNZ's consultation proposes restricting Satisfactory Performance Days (SPDs) to a winter testing period from 1 October to 30 April, between 4pm and 7pm on working days. It also proposes that participants demonstrate their ability to respond to an instruction at least once during the core winter period, from 1 December to the end of February.
The intention is to align testing more closely with the conditions DESNZ considers most likely to arise during a system stress event.
As the generation mix changes, testing requirements must reflect the evolving nature of system stress, rather than focusing narrowly on traditional winter peaks. This raises a wider question about what the Capacity Market should value. The scheme is solely designed to secure capacity adequacy, while the system will increasingly depend on responsiveness and flexibility.
A more fundamental and comprehensive overhaul of the Capacity Market is long overdue. Neither the Review of Electricity Market Arrangements (REMA) nor the light-touch 10-year review adequately addressed fundamental questions about the future role of unabated gas, how to maintain security of supply while reducing reliance on fossil fuel generation, or how to provide long-term investment signals for low-carbon flexible capacity. Revising testing requirements alone cannot resolve these wider questions about the capacity mix the market should procure, how different technologies are rewarded and whether the mechanism remains aligned with the government’s focus on affordability or longer-term decarbonisation objectives.
Narrowing the testing window may make compliance more prescriptive, but does it actually provide greater confidence that capacity will be available when consumers need it?
Given the difficulty of replicating genuine system stress conditions, Regen is calling on DESNZ to publish a comprehensive cost-benefit analysis of the proposed requirements, including whether more flexible, technology-specific testing arrangements could provide equivalent assurance at lower cost. DESNZ has already recognised the need for such flexibility in its proposed exemptions for interconnectors but has not extended similar consideration to other technology types, particularly DSR, where operational characteristics and baselining requirements present distinct challenges.
Regen recognises the need for robust delivery assurance. Consumers pay capacity providers to be available during system stress and should expect them to demonstrate that they can meet their obligations. If we increase the risks faced by capacity providers, we need to understand how those risks might ultimately be reflected in the price consumers pay for security of supply.
For a scheme as data-rich as the Capacity Market, the published evidence supporting testing reforms appears limited. Industry would reasonably expect a cost-benefit analysis demonstrating why existing testing arrangements are insufficient, how the proposed changes would materially improve delivery assurance during genuine system stress, and whether those benefits would outweigh the additional costs to consumers.
The question is not simply whether tighter testing provides greater assurance, but whether the additional assurance justifies the potential costs and consequences for participation.
Additional testing requirements and tighter availability windows can increase the risks and costs of participation. Those costs will be reflected in higher auction bids, while some providers may decide that participation is no longer commercially viable.
Even small changes in clearing prices can have significant consequences. Regen’s sensitivity analysis of the T-1 and T-4 auctions held between 2024 and 2026 suggests that a hypothetical £5/kW/year increase in clearing prices across all six auctions would have added approximately £114 million from the T-1 auctions and £1.1 billion from the T-4 auctions, equivalent to £1.22 billion in additional nominal payments over the lifetime of the agreements.
This is an illustrative scenario, not a forecast of the proposed reforms. It assumes that procured capacity volumes and agreement durations remain unchanged, showing how relatively modest changes in clearing prices can affect the total cost to consumers.
One potential consequence of the proposed testing requirements is their impact on Demand Side Response (DSR). Whether this is unintended or otherwise is open to debate.
DSR and the Capacity Market have a chequered history. In 2018, following a challenge brought by Tempus Energy, the General Court of the EU annulled the European Commission's State aid approval for the scheme, leading to its temporary suspension. The challenge raised concerns about the treatment of demand-side resources.
Today, the government's Clean Power 2030 Action Plan places demand flexibility at the heart of a cleaner and more affordable electricity system. But making flexibility commercially viable often depends on combining revenues from several markets. The Capacity Market is particularly valuable because its contracted payments can help underpin investment.
The proposed testing requirements could create a practical problem for DSR providers.
Under baselining arrangements, providers must demonstrate that they have reduced demand compared with what they would otherwise have consumed.
Restricting testing to winter weekday peaks could therefore create a perverse incentive. Some DSR providers may need to maintain or increase electricity consumption during peak periods to establish a sufficient baseline, only to turn it down again to demonstrate their ability to respond. In other words, we could end up encouraging electricity consumption at precisely the times we are trying to reduce it.
If these requirements make participation more difficult, costly or risky, some DSR providers may withdraw from the Capacity Market altogether. That would reduce competition in auctions and increase costs for consumers. It could also weaken the business case for demand flexibility at the very time government wants to see more of it.
Can other flexibility markets provide the revenue certainty needed to unlock investment? Or are we risking the business case for demand flexibility at precisely the point when government's own Clean Power 2030 Action Plan envisages 10 to 12 GW of consumer-led flexibility by the end of the decade?
Reduced DSR participation could also weaken competition in capacity auctions, increasing clearing prices and costs to consumers. There is a wider policy tension here. The government wants more flexibility to support a cleaner and more affordable electricity system, yet reforms intended to strengthen security of supply could inadvertently discourage those same resources.
DESNZ should use its detailed auction data to assess the potential impact. Re-running historical auctions with lower levels of DSR participation would not provide a definitive forecast, but it could help quantify the consequences for competition and consumer costs.
Of course, DSR must demonstrate that it can deliver. But different technologies have different operating characteristics and equivalent confidence in delivery does not necessarily require identical testing arrangements.
DESNZ recognises this principle for interconnectors, proposing exceptions to certain testing requirements to reflect their operational constraints. Why should DSR not receive similar consideration, particularly where the proposed testing window creates challenges for existing baselining arrangements?
The challenge should be to strengthen delivery assurance without unnecessarily excluding resources that contribute to system security.
DESNZ needs to strike the right balance.
Too little assurance risks consumers paying for capacity that cannot deliver. Too much prescription risks increasing costs, reducing competition and weakening the investment case for demand flexibility.
As we approach prequalification in 2027, there is a wider conversation to be had about the role and value of demand flexibility within the Capacity Market. If the government expects flexibility to make a growing contribution to the electricity system, markets should recognise that contribution and provide proportionate routes to participation.
Before proceeding DESNZ should publish a clearer assessment of the expected benefits and costs of the proposed testing requirements, consider their cumulative impact on DSR participation and work with industry to develop proportionate approaches that reflect the different ways capacity providers contribute to security of supply.
Ultimately, the Capacity Market is an insurance policy for our electricity system. But as we lock in capacity payments for 2031 and beyond, we must ensure we're not paying higher premiums for cover designed around yesterday's risks.
If you're interested in our work around the Capacity Market, please contact Georgina Morris-Rowbottom. If your organisation aligns with our mission, perhaps membership is for you. To discuss the options, reach out to Hannah Stanley.
