What are capacity markets? How countries pay to keep the lights on

A capacity market pays power stations, batteries and even large consumers for being available, whether or not they end up producing any energy. It is a payment for readiness rather than for energy. 

Countries run them because the energy market alone does not reliably fund the capacity needed for the handful of hours each year when the system is genuinely tight - and those are precisely the hours when losing supply matters most. 

Why capacity markets exist alongside wholesale power markets 

In theory, an energy-only market handles scarcity on its own. When capacity is tight, prices spike, and those spikes fund the plants that run only occasionally. 

In practice, that mechanism is fragile. Revenue depends on a few very high-priced hours, which might not happen every year. A peaking plant could earn nothing for two years and then cover its costs in just one January week. As a result, investors and lenders naturally hesitate to fund such an asset. 

Regulators compound the problem, for good reason. Most markets impose price caps to protect consumers from extreme outcomes, but a cap set below the true value of lost load cuts exactly the revenue that scarcity pricing was intended to deliver. The result is what the industry calls the missing money problem: the gap between what a plant needs to earn to remain viable and what the energy market will actually pay it. 

Several forces have widened that gap over the past decade: 

• Falling thermal running hours, as wind and solar displace gas and coal, forcing the same fixed costs to be recovered across less output 

• Price caps and political intervention, which truncate the scarcity revenue that peaking plant depends on 

• Ageing fleets reaching retirement, where continued operation requires capital spend that merchant revenues alone will not justify 

• Renewed demand growth, driven by electrification and data centre load, after a long period of flat or declining consumption. 

This is balanced by a reliability standard, typically defined as expected unserved energy or a loss-of-load expectation, like three hours annually. Governments consider this standard non-negotiable, so if the market fails to meet it, a mechanism is put in place to ensure compliance. 

It is worth being clear about what a capacity market is not. It does not set the energy price, nor does it pay for electricity produced. A plant with a capacity agreement still sells its output into the wholesale market on exactly the same terms as everyone else. The capacity payment sits alongside that revenue, covering the cost of existing rather than the cost of generation. 

How capacity auctions work 

A capacity market is essentially a procurement exercise. The system operator determines how much capacity is needed to meet the reliability standard, then purchases it. 

Five design decisions shape the outcome: 

1. The demand curve, set administratively rather than emerging from the market. Regulators generally use a sloped curve rather than a vertical line at a fixed volume, so slightly more capacity clears when it is cheap and slightly less when it is expensive, which dampens price volatility between auctions 

2. Lead time, with auctions run several years ahead of delivery — typically four — to give new projects time to secure planning, connection and finance 

3. Derating factors, which scale each participant’s nameplate capacity to reflect what it can actually be relied upon to deliver during a stress event 

4. The clearing price, paid to every successful participant regardless of what they bid, in the same pay-as-cleared structure used in energy markets 

5. Contract length, which varies by asset type and is the single most important term for anyone financing new build. 

Derating is the step that makes the whole thing comparable. A gas turbine might be derated modestly to account for outage risk. A wind farm is derated heavily, since its output on a still winter evening cannot be relied upon. Batteries are derated by duration, because a one-hour unit contributes far less to a multi-hour stress event than a four-hour one. 

These factors are recalculated periodically and can shift materially between auctions, introducing a genuine revenue risk for storage in particular. A change in methodology can alter a project’s capacity income even when nothing about the asset itself has changed. 

Contract length is where the mechanism does its real work. Existing plant typically receives a one-year agreement, effectively a payment to defer closure. New build can secure fifteen years, converting an uncertain merchant revenue stream into something a lender will underwrite. Most markets also run a supplementary auction closer to delivery, which fine-tunes the volume procured and captures units that were not ready to bid four years earlier. 

Who gets paid, and for what 

Capacity markets are technology-neutral in design, and the range of participants has broadened considerably: 

• Thermal generation, still the largest block, particularly gas plant that would otherwise struggle to justify staying open 

• Battery storage, now a significant share of new capacity in several markets, though constrained by duration derating 

• Interconnectors, which contribute the capacity expected to flow inward during a stress event 

• Demand-side response, where industrial and commercial consumers commit to reduce load on instruction 

• Existing nuclear and hydro, which participate alongside everything else. 

Payment carries commitments. A capacity agreement obligates the holder to deliver energy during a system stress event, and failing to do so leads to penalties that may surpass the received payment. This difference makes a capacity market distinct from a subsidy: it guarantees a firm commitment, validated when it counts. 

Providers must also prequalify, demonstrating that the capacity physically exists and can respond as claimed. For new builds, milestones must be met, or the agreement is forfeited. This is intended to stop speculative projects from blocking capacity that others could have delivered. 

Which countries run capacity markets today 

Great Britain operates the most established mechanism in Europe, running four-year-ahead and one-year-ahead auctions since 2014. It has become a substantial route to market for battery storage, and clearing prices have risen markedly as the thermal fleet has aged and demand growth has resumed. 

France has operated a decentralised model based on tradable capacity certificates, under which suppliers must hold certificates matching their customers’ contribution to peak demand. It has been moving towards a more centralised design, closer to the British model. 

Italy runs centralised auctions that have secured both new gas capacity and storage. Poland introduced a capacity market largely to manage the retirement of its coal fleet while maintaining adequacy. Belgium’s mechanism was designed around the planned nuclear phase-out and has underwritten new gas capacity. Ireland runs auctions within the all-island market amid acute adequacy pressure from data centre demand growth. 

European rules constrain what these mechanisms can fund. An emissions performance limit prevents the highest-emitting plant from receiving new capacity agreements, effectively closing the door on new coal and pushing the mechanisms towards gas, storage and demand response. 

The variation between countries is not accidental. A market’s design usually reflects the specific adequacy problem it was built to solve - managing a nuclear phase-out, retiring coal, or accommodating rapid demand growth - which is why mechanisms that look superficially similar can behave quite differently. 

Criticisms and alternatives to the capacity market model 

The objections are substantial and worth taking seriously: 

• Consumer cost, since capacity payments are recovered through bills and in some markets add materially to them 

• Prolonging fossil generation, because even with emissions limits the mechanisms overwhelmingly reward firm thermal capacity 

• Systematic over-procurement, as regulators setting the demand curve face a political cost of blackouts that vastly exceeds the political cost of a slightly higher bill 

• Barriers to smaller participants, where prequalification and milestone requirements favour established operators over demand-side aggregators. 

The main alternative in use is the strategic reserve, where the system operator contracts a small block of capacity held entirely outside the market and dispatched only in emergency. Germany has favoured this approach. It is cheaper and less distorting, but it provides no investment signal, so it maintains existing plant rather than bringing forward new capacity. 

The purist alternative is to remove price caps and let scarcity pricing do the work. This is theoretically elegant but politically very difficult, as it requires accepting occasional extreme prices as the intended outcome rather than a market failure. The mechanics of that approach are set out in What is the merit order, and how are power prices set? 

A third option gaining interest is to focus more on flexibility. If sufficient demand can be diverted from peak stress periods and enough storage can channel energy into those times, the need for large amounts of firm capacity decreases. Some system operators are now purchasing flexibility services directly, although not on a scale that fully addresses the adequacy issue. 

Conclusion 

Capacity markets exist because reliability is a public expectation, while generation investment is a private decision, and the energy market alone does not always bridge the two. 

Three things are worth watching in the auctions ahead. Clearing prices have been climbing across several markets as thermal retirements accelerate and demand growth returns, indicating that the mechanisms are working but that adequacy is tightening. Emissions conditions are becoming stricter, steadily narrowing what qualifies. And the storage share of cleared capacity keeps rising, with the debate shifting towards whether derating rules properly reflect what longer-duration batteries actually deliver in a stress event. 

That last question matters more than it sounds. Derating methodology determines how much a battery earns, which in turn determines what gets built - shaping how much firm capacity the system needs to buy in the first place.