Stock code
300693
Picture this: the power grid faces a real shortage for only ten hours in an entire year. Would you build a brand new power plant just to cover those ten hours? As an investment, it sounds absurd. Yet for a grid operator, those ten hours are exactly the problem they cannot afford to ignore. Capacity Markets exist to solve this problem.
In the first two parts of this series, we looked at how energy storage earns money from ancillary services and wholesale arbitrage. Both follow a simple logic: you get paid for the energy or grid service you actually deliver. A capacity market works on a different principle. Here, you get paid mostly for a promise: whenever the grid needs me, I will be ready.
This guide explains what a capacity market is, why it exists, how the auctions work, which countries run one, and why battery energy storage is becoming one of its most important participants.
A capacity market is a mechanism that pays electricity providers to be available during periods of peak demand or system stress, rather than only for the power they generate day to day. In energy policy, it is generally classified as a type of capacity remuneration mechanism (CRM).
The product being traded is not electricity itself, but reliability: the guaranteed readiness to deliver power when the system needs it most. Providers commit years in advance to stay on standby, and in return, they receive a predictable capacity payment. If a shortage arrives and they fail to perform, they face penalties. This combination of upfront payments and performance obligations lies at the core of every capacity market.
For most of the year, existing generation is sufficient. The real challenge comes during extreme events, such as heatwaves or cold snaps, when demand spikes sharply within a few hours.
As more wind and solar are added, this challenge becomes harder to manage. Their output is not always available during peak demand, especially under unfavorable weather conditions.
The cost of getting this wrong can be severe. During Winter Storm Uri in February 2021, Texas lost a large share of its generation within hours as gas infrastructure froze and plants tripped offline. According to the U.S. Federal Energy Regulatory Commission, more than 4.5 million people lost power, some for as long as four days. Texas runs an isolated grid with no formal capacity market, which left it with fewer dedicated reserve resources when the crisis hit.
The lesson is hard to ignore. Every grid eventually faces the same question: when demand spikes and supply falters, who guarantees the lights stay on? Economists call the underlying challenge the missing money problem, where an energy-only market alone may not reward enough reliable capacity to stay online. Capacity markets provide an additional layer of insurance designed to address this challenge.
It's like a reservation made years in advance. Take Great Britain as an example, home to one of the world's most established capacity markets, run by the National Energy System Operator (NESO).
The system holds two main auctions for each delivery year:
T-4 auction: held roughly four years ahead of delivery. Most volume is secured here, as much as 95% of expected capacity, giving developers time to build anything new.
T-1 auction: a top-up held one year ahead, allowing the system to adjust once demand forecasts are clearer.
First, the system operator estimates how much reliable capacity the grid will need in a future delivery year. Then it holds a competitive auction. Generators, battery storage systems, demand-side response providers, and interconnectors can all participate. The lowest-cost resources are selected until the target is met.
Successful bidders receive capacity contracts and ongoing payments. In some markets, new-build projects can win long-term agreements of up to 15 years to help support project financing.
But capacity payments come with obligations. When the system enters a stress event, contracted providers must deliver power or reduce demand as agreed. If they fail to perform, they may face financial penalties.
While market designs vary, capacity mechanisms have become an increasingly important tool for ensuring resource adequacy across Europe. Besides Great Britain, established or growing schemes include:
Italy, where transmission operator Terna runs both a traditional capacity market and a new storage-specific mechanism.
Poland, whose capacity market held its first auction in 2018 with deliveries starting in 2021, is operated by grid operator PSE.
France, which has run a capacity mechanism for years as part of its security-of-supply toolkit.
The designs differ in detail, but the goal is shared: technology-neutral competition to keep enough reliable capacity on the system as the energy mix shifts toward renewables.
Battery energy storage systems (BESS) are becoming increasingly competitive in capacity markets. A battery can respond within milliseconds, making it well suited for situations where the grid needs immediate support.
In Britain, batteries already bid alongside gas plants and interconnectors for capacity contracts. Some markets have gone further and built mechanisms designed specifically for storage. Italy's MACSE scheme (Electricity Storage Capacity Procurement Mechanism), run by Terna, is the clearest example. Its first auction in late September 2025 secured 10 GWh of battery capacity on 15-year contracts, with bids oversubscribed by more than four times and roughly €1 billion of investment behind it.
Capacity markets also reward duration, not just power. In that first MACSE auction, the winning projects averaged around 6.6 hours of storage. This reflects how grids use de-rating factors, which discount each technology by its expected availability during a stress event. Longer-duration systems of four hours and above generally deliver more capacity value and more resilience than one- or two-hour systems, so they tend to be valued more highly.
Across this series, we have covered three major ways energy storage projects earn revenue:
Ancillary services: providing fast-response grid support such as frequency regulation.
Wholesale arbitrage: charging when electricity prices are low and discharging when prices are high.
Capacity markets: being paid to stay available for future system stress events.
These are not the only revenue sources for storage, but they are among the most important in many markets. In practice, the best projects rarely rely on just one. They stack multiple revenue streams and balance stability against upside, combining the certainty of a capacity contract with the higher, more volatile returns of merchant markets. As renewable penetration continues to rise, the need for flexible and reliable capacity will only become more critical, further strengthening the role of energy storage in future power systems.
A capacity market pays providers for being available during peak demand or system stress, not just for energy delivered. It buys reliability and commitment.
It exists because grids face their biggest risk in just a few extreme hours a year, a risk that grows as variable renewables replace firm conventional plants. The unsolved version of this is the missing money problem.
Capacity remuneration mechanism (CRM) is the umbrella term; capacity markets are the most common form.
Capacity is procured years ahead through auctions. In Britain, the T-4 auction (four years ahead) secures most volume, and the T-1 auction (one year ahead) tops it up. New-build projects can win contracts of up to 15 years.
Take the payment, keep the promise. Underperformance during a stress event triggers penalties.
Countries with capacity mechanisms include Great Britain, Italy, Poland, and France, etc.
Energy storage is increasingly competitive because it responds instantly. Italy's MACSE auction awarded 10 GWh of batteries on 15-year contracts in 2025, oversubscribed fourfold.
Smart projects practice revenue stacking, combining capacity, arbitrage, and ancillary services rather than depending on one.
This is Part 3 of our energy storage revenue series. If you missed them, start with Part 1 on ancillary services and Part 2 on wholesale arbitrage.
