Their enduring popularity

The UK’s capacity market has returned this year, following its lengthy suspension while the European Commission investigated a legal challenge from Tempus Energy. Although the March auction for delivery of capacity in 2023/24 saw a resurgence of the clearing price to £15.97/kW-year, it remains well below the levels thought necessary to achieve the government’s aim of attracting new, efficient combined cycle gas turbine (CCGT) plants. Despite this, SSE’s Keadby 2 – an 840 MW CCGT plant already under construction – accepted the price and was awarded a 15-year contract available for new plant, having clearly decided to take what it could get under the prevailing conditions.

The development is something of a positive sign for a scheme that has had underwhelming results during its initial run from 2014 to 2018, plagued by unexpectedly low prices, a fleet of undesirable diesel generators and open cycle peaking plants, and unpopular payments to ageing coal plant.

Intended to encourage investment in adequate new generating capacity where the wholesale energy market might fail, capacity markets have spread from the USA to Europe in recent years, spurred by the rapid rise in intermittent renewables and thermal power plant retirements. For some, a form of compensation for ‘firm capacity’ is essential for providing back-up to less dependable wind and solar, while for their critics, capacity markets represent an unnecessary subsidy to fossil generation or a misguided weakening of free-market signals. Recent legal challenges to their status in both the US and Europe have increasingly cast the schemes as a totem of the old order in the conflict between new and established energy sources.

The UK mechanism largely follows a model set by the PJM Interconnection – a major US power pool stretching from Virginia to Illinois – which established its capacity market in 2007. Both regions run reverse auctions in which generators, energy storage, and demand response bid to supply enough capacity to meet projected peak demand a few years ahead (three years in PJM, four for the UK). In contrast to the UK, the PJM system has arguably been too successful, with a boom in CCGT contributing to an excessive reserve margin of over 28% last year. The growth has been linked to the ‘cost of new entry’ parameter used in the auction, which seems to have significantly underestimated the actual cost of new gas plant – helped by the region’s share of the shale gas boom. Experiences in both PJM and the UK make clear that capacity markets are highly sensitive to their input parameters, and can be difficult to steer towards policy targets such as a particular generating mix or reserve margin.

The alternative position is exemplified by the ERCOT market covering Texas, which has held true to an ‘energy-only’ market approach, even as capacity compensation mechanisms have proliferated around the US. This is all the more noteworthy given that Texas is also a champion of wind power, which provided around 20% of the state’s power supply in 2019. However, a calm day in a hot summer can test the nerves of the system operator, as reserve margins in the state fell to an alarming 8.1% last year, and customers were asked to restrict consumption on two occasions in August (13.75% is the recommended margin in the US). Investors in new capacity are encouraged by a wholesale market ‘price adder’ which can offer huge profits in times of scarcity, but so far, sufficient growth in gas generation has not materialised; all while the state bucks the national trend by showing growing demand.

The EU is disapprovingly tolerant of the new wave of capacity schemes – also implemented in some form in Poland, France, Italy, and potentially Greece – seeing them as a barrier to a more unified electricity market, while recognising its members’ fears over future supply. As part of the recent ‘Winter Package’ of energy legislation, the Commission moved to prevent existing coal plant receiving capacity payments beyond 2025, as well as proposing a centralised ‘adequacy assessment’ and greater sharing of capacity. Meanwhile, Germany has ostensibly adhered to energy-only principles, but covered its bases by contracting various out-of-market reserves of coal and gas plants.

Capacity market critics often point to the rise of smarter electricity systems, which allow consumers to participate directly in the market through greater use of demand-side response. This could help alleviate a fundamental problem at the heart of electricity markets, in that even when wholesale prices are left unfettered, they rarely adequately express the value of electricity to society. On the other hand, the envisaged model may require consumers to be able to accurately assess and purchase the level of reliability they require.

For now, the enduring popularity of capacity markets is testament to their appeal with policy makers, who would often prefer not to deal with the price spikes and scarcity events inherent to a working energy-only market.

These concerns are likely to loom even larger in developing economies as they face the challenge of liberalising energy markets while expanding renewable generation and meeting growing demand.

Author: Toby Lockwood, IEA Clean Coal Centre, UK