Authors: Andy Hackett, Senior Policy Adviser, and Andrew Schein, Director of Trials and Analysis

The Government’s highest priority is affordability, and reducing energy prices is central to that agenda. High energy prices hurt households, hurt UK industry, and are a drag on innovation and productivity.[i] A key debate concerns how network and policy costs – largely recovered through electricity bills – are funded, including the costs of new infrastructure, generation, and social schemes. If everything were on the table, there is a radical step worth considering for one policy in particular: ending the Capacity Market entirely.

If Ed Miliband were asked on BBC’s Question Time to explain the Capacity Market, it would make for uncomfortable viewing. The state takes a cut from your bill (via your supplier) to pay generators not for producing electricity, but for being available in case of a “system stress” event. More than a decade after the market opened, that event has never happened – but in 2024/25 alone the scheme cost consumers around £1.3bn.

In its defence, even without Capacity Market events, regular availability payments may have propped up plants that we needed in crises – plants that would otherwise have shuttered. But there are better ways to ensure capacity.

The original rationale: “missing money”

When we talk to policymakers and people inside the energy industry, our sense is that they assume economists generally endorse capacity markets as good policy. We don’t think that’s right, at all. Most economists’ ideal energy market has no additional market for capacity. An “energy-only” market should be sufficient to maintain capacity. Infrequently used plants can recover their fixed costs by cleaning up during a small number of scarcity hours each year. The prospect of these scarcity revenues should attract and retain capacity. Capacity markets shift risk from investors to consumers, providing revenue certainty but weakening incentives for efficiency, innovation and demand flexibility.[ii]

In practice, policymakers have been squeamish about energy-only markets. A popular theory developed that during wholesale cost spikes, there would inevitably be an imposition of price caps to blunt scarcity pricing. The result would be a “missing money” problem: prices too low – or too rarely high – for peaking and flexible assets to recover their costs. This problem, long recognised in liberalised markets, is intensified by low-marginal-cost renewables depressing wholesale prices. Capacity markets are designed to fill the gap by paying for availability rather than output.[iii]

The UK Capacity Market emerged when, in the early 2010s, policymakers feared a looming “capacity crunch” as coal retired, nuclear plants aged, and wholesale prices appeared too low and too volatile to support new investment. It was sold as a necessary measure to make up for weak scarcity signals and an insurance policy against blackouts – and, crucially, as temporary.

UK government explaining why we need a Capacity Market (UK Government, 2014)

But the UK did have an energy price spike during the lead-up and beginning of Russia’s invasion of Ukraine in 2022 – and, contrary to the missing money hypothesis, generators did avail themselves of high wholesale prices. The way the UK and most countries managed the energy crisis was to impose caps on retail prices, but leave wholesale markets alone, and then (eventually) reimburse the retailers for their losses. So in a real world example of scarcity, wholesale markets’ price signals and scarcity revenues did not prove to be in danger.

International cautionary tales

As the UK Government is at pains to say in the image above, capacity markets are not new. That is true. But their record is not great. International evidence suggests that they can stabilise revenues, but tend to perform poorly against decarbonisation and efficiency goals.[iv] That shouldn’t be a surprise, as their main role is to keep the most inefficient, expensive-to-run plants – i.e. old fossil plants – from shuttering.

Evidence from US markets suggests that capacity markets have served to lock in ageing fossil plants, undervaluing variable or flexible resources and suppressing the signals that reward storage or demand-side response (DSR).[v] Furthermore, traditional crediting rules tend to underestimate the reliability of wind and solar to distort investment and sustain overcapacity.[vi] Modelling also suggests that capacity markets mainly redistribute risk and cost from investors to consumers rather than improving efficiency, while energy-only markets can achieve similar reliability at lower cost.[vii]

A live example of strain in capacity market design is unfolding in PJM, the largest US electricity market. In its latest auction, prices hit the administrative cap of $333/MW-day for the third time in a row, setting another record-high price, but PJM still procured around 6.6 GW less than its reliability target. The cap itself followed a complaint to federal regulators by the Governor of Pennsylvania. Ironically, while capacity markets are justified as a solution to the missing money problem created by price caps in energy markets, in PJM costs have led to price caps binding the capacity market itself and failed to ensure adequacy.

The cost of PJM’s capacity auction over ten years (Ethan Howland/Utility Dive, 2025)

Other capacity markets offer lessons on market power and perverse incentives. A good example comes from home to the world’s longest-running incentive-based capacity market: Colombia. Launched in December 2006 – just like Shakira's reissued edition of her 2005 album featuring ‘Hips Don’t Lie’ – it has proven to be one of Colombia’s most influential exports, shaping reforms in New England, Ireland and Italy. Generators receive a regular reliability payment for selling a financial call option at an administratively set scarcity price, creating a strong financial incentive to generate whenever wholesale prices exceed that threshold.

Empirical work by Shaun McRae and Frank Wolak (2024) shows that large generators were often able to determine whether scarcity conditions were triggered at all.[viii] By adjusting bids and output, the largest firm unilaterally controlled the scarcity threshold in around 10% of hours. When creating scarcity was profitable, firms did so; when it was not, they avoided it – raising prices and distorting operational decisions, including water management (hydro dominates in Colombia) in ways that increased the risk of later shortages. During a 2015–16 El Niño event, which sharply reduced hydro inflows, wholesale prices exceeded the administratively set scarcity price in almost every hour for several months. The capacity payment mechanism had already encouraged greater forward contracting by hydro generators and lower reservoir storage, meaning the system entered this genuine scarcity shock with reduced resilience. The lesson for the UK is that once scarcity is defined administratively and made financially consequential, capacity mechanisms can create new and subtle forms of market power.

Colombia spot prices were below the scarcity price most of the time, except for a sustained period of high prices in 2015–16, during an El Niño event (McRae and Wolak, 2024)

This is unlikely to happen in exactly the same way in the UK. However, recent experience in its Balancing Mechanism – including cases revealed by the excellent Bloomberg investigation in 2023 – of generators withdrawing capacity ahead of tight periods only to re-offer it at higher prices, should make policymakers wary of market power risks. The general principle is that where markets are thin and operational discretion is high, perverse incentives arise.

Whose missing money?

In theory, the UK’s Capacity Market is technology-neutral. Anything that can reliably reduce net demand during system stress – generation, storage, interconnection, or DSR – should be able to compete and recover its costs. The mechanism was also presented as transitional. As DSR matured, interconnection expanded and wholesale markets deepened, capacity payments were expected to fall towards zero. Instead, the opposite happened: the scheme has disproportionately topped up revenues for gas-fired generation and underwrites its ongoing business case.

There has been some progress for newer forms of capacity. Battery storage has increased steadily in recent auctions. Electric vehicles, acting as virtual power plants in aggregate, are also part of the country’s capacity – a real success story for market innovation. But gas dominates. In particular, the sharp reduction in capital expenditure thresholds for multi-year contracts allowed refurbished Combined Cycle Gas Turbines to secure longer-term agreements, effectively treating life-extension investments as new-build capacity. This lowers financing risk for incumbent gas plants and strengthens their position not only in the Capacity Market but also in wholesale and balancing markets, where they can bid more aggressively. Despite repeated assurances that DSR would grow within the Capacity Market, participation has remained modest relative to system need and particularly at odds with a Clean Power Plan targeting a five-fold increase in demand flexibility by 2030.

UK Capacity Market prequalified and conditionally prequalified derated capacity by generation Type for T-4 CM auctions (Montel, 2025)

The recent proposal for a “Multiple Price Capacity Market” turns this implicit bias into an explicit policy choice, by simply paying some technologies more than others. While UK policymakers frame this as a response to security of supply concerns, the category most clearly positioned to benefit is new-build unabated gas. The result is a two-tier market in which firm thermal capacity is privileged over other forms of flexibility by administrative design, not a competitive market.

There is already a substantial pipeline of refurbished gas capacity seeking contracts, with more than 15 GW of projects prequalified in upcoming auctions. Paying a premium for new gas, without robust limits on running hours or a clear demonstration of system need, risks locking consumers into higher costs for decades. By undermining its own design principles, it also revives old legal and political risks: the last time the Capacity Market was seen to unduly favour incumbents it was successfully challenged by Tempus Energy, temporarily suspending the scheme.

A clean break

The UK Capacity Market is based on dubious economics and, after more than a decade in operation, is becoming harder to defend. In the next round of the seemingly permanent review of electricity markets, policymakers should seriously consider ripping the band-aid off and ending the scheme. That could save consumers money, stop subsidising fossil fuel generators, and improve system efficiency, all in one fell swoop - with no need to move these policy costs from bills to general taxation. There are a few coherent alternatives.

First, economists Shaun McRae and Frank Wolak - whose paper we have drawn on above – propose stronger supplier obligations: in particular, forcing suppliers to hedge a large share of future demand through standardised forward contracts. This idea could stop retailers from skimping on hedges, which ultimately felled many retailers during the energy price crisis – including, most famously, Bulb Energy – and is broadly in line with Ofgem’s post-crisis approach to supplier resilience. It can stabilise consumer prices, provide revenue streams for investment (i.e., for generators, in lieu of capacity payments), and mitigate the risk of supplier failure and political bailout, but without the heavy-handed market distortion of capacity markets.

Second, if policymakers remain nervous about leaving capacity adequacy to an energy-only market, there are ways to intervene to sharpen scarcity price signals. For example, they could follow a well-known example from Texas: ERCOT’s Operating Reserve Demand Curve embeds scarcity pricing directly into the energy market by valuing operating reserves against the probability and value of lost load. Rather than paying generators simply for being available, this sharpens price signals as reserves tighten, allowing scarcity revenues to emerge in a more continuous and predictable way.

Third, the UK could take a more interventionist approach and start setting up the “out-of-the-market mechanism”, hinted at in its Clean Power Plan, to manage a strategic reserve of capacity.11 Rather than meddling with markets to ensure that gas can be competitive in wholesale, balancing and capacity markets, policymakers could treat residual gas capacity not as a market good, but as a system asset. That could take the form of a regulated asset base, written up recently by the Stonehaven consultancy, or direct public ownership, with plants paid transparently for availability and dispatched centrally only when needed. Consumers would pay explicitly for an insurance scheme, rather than implicitly through distorted markets.

Which of these broad options to pursue is a big debate in itself. The first step is to treat the Capacity Market as a costly, temporary fix that has outlived its usefulness.

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[i] Castle, J.L., Hendry, D.F. and Martinez, A.B. (2023) ‘The historical role of energy in UK inflation and productivity with implications for price inflation’, Energy Economics, 126, 106947; Office for National Statistics (2024) The impact of higher energy costs on UK businesses: 2021 to 2024.

[ii] Newbery, D. (2015) Missing Money and Missing Markets: Reliability, Capacity Auctions and Interconnectors. Cambridge: Energy Policy Research Group; Cramton, P. and Stoft, S. (2006) ‘The convergence of market designs for adequate generating capacity’, White Paper, University of Maryland; Joskow, P.L. (2008) ‘Capacity payments in imperfect electricity markets: Need and design’, Utilities Policy, 16(3), pp. 159–170.

[iii] Cramton, P. and Stoft, S. (2006)

[iv] Bowring, J. (2013) ‘Capacity markets in PJM’, Economics of Energy & Environmental Policy, 2(2), pp. 47–64; Spees, K., Newell, S.A. and Pfeifenberger, J.P. (2013) ‘Capacity markets: Lessons learned from the first decade’, Economics of Energy & Environmental Policy, 2(2), pp. 1–26.

[v] U.S. Energy Information Administration (2022) Short-Term Energy Outlook Supplement: Sources of Price Volatility in the ERCOT Market. Washington, DC: U.S. Department of Energy. 6 Levin, T. and Botterud, A. (2015) ‘Electricity market design for generator revenue sufficiency with increased variable generation’, Energy Policy, 87, pp. 392–406; Spees, Newell and Pfeifenberger (2013); Bialek, S., Gundlach, J. and Pries, C. (2021), Energy-Only Markets Are Viable, Even with a High Share of Renewables. Institute for Policy Integrity.

[vi] Bothwell, C. and Hobbs, B.F. (2017) ‘Crediting wind and solar renewables in electricity capacity markets: The effects of alternative definitions upon market efficiency’, The Energy Journal, 38(S1), pp. 173–188.

[vii] Hohl, C. and Lo Prete, C. (2025) ‘Capacity markets vs. energy-only markets with improved scarcity pricing under increasing wind penetration’, Renewable Energy Focus, 55.; Petitet, M., Finon, D. and Janssen, T. (2017) ‘Capacity adequacy in power markets facing energy transition: A comparison of scarcity pricing and capacity mechanisms’, Energy Policy, 103, pp. 30–46.; Mou, Y., Papavasiliou, A., Hartz, K., Dusolt, A. and Redl, C. (2023) ‘An analysis of shortage pricing and capacity remuneration mechanisms on the pan-European electricity market’, Energy Policy, 183.

[viii] McRae, S.D. and Wolak, F.A. (2019) Market Power and Incentive-Based Capacity Payment Mechanisms. Stanford: Program on Energy and Sustainable Development.