Part One: Understanding the Capacity Market: why it exists and what it aims to achieve

This is the first of a two-part blog exploring the Capacity Market - the mechanism designed to ensure security of electricity supply in Great Britain. In Part One, we introduce the purpose of the Capacity Market, its origins, and the key policy decisions behind its creation. We explained why it was needed, how it fits into the wider electricity market, and the problems it aims to solve. We also looked at the overarching objectives of the scheme and how it supports long-term energy security. In Part Two, we’ll dive into the practical operation of the Capacity Market: how demand is forecast, how the auctions work, who can participate, and what obligations are placed on successful bidders.

Let’s start with a simple quote from the Department of Energy and Climate Change (DECC), taken from their 2013 consultation paper on electricity market reform:

“The Capacity Market will deliver security of supply by providing generators with a steady retainer payment to be available to provide additional capacity when needed.”

In short, the Capacity Market exists to ensure there’s enough electricity supply available, not just during normal conditions, but especially when demand spikes or other sources fall short.

Why Do Generators Need a Retainer Payment?

It might seem odd. Don’t generators already get paid for producing electricity?

Yes, they do. But here's the catch: electricity can’t easily be stored. Unlike gas or water, you can’t just stockpile it for later. Most storage options (like batteries or pumped hydro) are expensive and limited. Even advanced technologies like superconducting magnetic storage are still in development and not widely deployed.

This means we must produce electricity exactly when it’s needed, every second of the day. If supply falls short of demand, the grid destabilises and that can quickly lead to power cuts.

The Nature of Demand

Electricity demand isn’t constant. It varies throughout the day and across the seasons. For example, people use more electricity in winter evenings than on a summer afternoon. 

Take a look at a 2024 demand duration curve for Great Britain:

• For 99% of the time, demand is around 4,000 MW below peak.
• For 95% of the time, it’s 7,500 MW below peak.

This shows that there is a requirement for several thousand MW of generation that only runs for a few hours every year. 

In recent years, we've added more intermittent renewable energy sources, like wind and solar. These are great for decarbonisation, but they don’t generate consistently, especially when the sun isn’t shining, or the wind isn’t blowing.

As a result, we still need reliable, dispatchable generation (such as gas) to back them up. However, those backup generators now run less often, which makes them less profitable, unless there’s another way to support them financially.

That’s Where the Capacity Market Comes In

The Capacity Market ensures that enough reliable capacity remains available, even if it only runs occasionally. It gives generators a financial incentive to stay ready, not just to produce power when it’s profitable.

This was highlighted by NESO in their Clean Power report last year: dispatchable power will still be required, but it will operate for significantly shorter periods.

For example, around 35 GW of unabated gas capacity, broadly aligned with the current fleet will need to remain available as standby to ensure security of supply. This requirement will remain throughout the early 2030s until greater volumes of low-carbon dispatchable power and other flexible resources are able to replace it.

However, for this standby generation to remain viable, it must recover its fixed costs (capital and operational) as well as any running costs incurred during its limited operation. How can this be managed?

1. Spiky Prices

One option is to allow very high prices during peak demand periods. These prices must be high enough during just a few peak hours to allow the final few percentiles of capacity that only runs in those hours to recover all their annual costs. This creates volatility that’s hard for suppliers and consumers to manage. Are you exposed to those prices or not? And if such high prices don’t occur for a year or two (e.g. due to mild weather or low demand), marginal generators go out of business, leaving a gap just when they’re needed next.

2. Strategic Reserve

A Strategic Reserve involves keeping specific generation assets outside the normal market, only to be dispatched in emergencies (e.g. to prevent blackouts). While it can provide security, it also has drawbacks:

• Capacity in the reserve is excluded from earning market revenues, so the value of capacity isn’t priced in across the system.
• Generators sitting at the edge of viability (between reserve and market) may shut down, as they aren't compensated for their role in providing security.
• Large reserves may reduce liquidity in wholesale and balancing markets, distorting pricing and investment signals.

3. Capacity Payments

Most active generators receive payments to ensure they are available to supply electricity when needed. Importantly, the term generators here also include demand-side participants, that is, consumers who are willing to reduce their electricity usage when required, helping to balance the system.

A Brief History of Capacity Payments in Great Britain

When the electricity market in Great Britain was first privatised, capacity payments were built in. Generators dispatched to run were paid the Pool Purchase Price (PPP). Generators despatched out with-that were paid their bid price plus the availability payment LOLP × VOLL. 

• SMP (System Marginal Price): Price of the most expensive unit dispatched
• LOLP (Loss of Load Probability): Risk of a capacity shortfall
• VOLL (Value of Lost Load): £2,000/MWh in 1990/91, inflation-linked

Generators that were available but not dispatched still earned an Availability Payment:

Availability = LOLP × VOLL

This system was simple but vulnerable to abuse, as “available” units were not always properly verified. In 2001, the NETA reforms ended these payments, moving to bilateral trading. From 2005–2012, free EU ETS allowances indirectly supported fossil fuel generators, acting as an unintended capacity subsidy.

Today’s System

Under the modern Capacity Market, most active generators (Generators with Low Carbon support e.g. FiT, RO or CfD are not eligible to take part in the CM) are paid to ensure they're available when needed supporting grid reliability in a more structured and transparent way.

In Part Two, we’ll explore how the Capacity Market operates in practice, from demand forecasting and the auction process to capacity agreements and settlement arrangements. We’ll look at who can participate, how the auctions are run, what obligations are placed on successful bidders, and how payments and penalties are handled. We'll also touch on how the scheme has evolved, including changes to emissions rules, treatment of storage technologies, and the inclusion of intermittent renewables.