October 3, 2018 Read More →

IEEFA update: Time to reconsider the U.K.’s flagship scheme for avoiding blackouts

Capacity markets have proven to be an impediment to modernization

Overlapping forces spell further declines for coal-fired power

LONDON — Britain introduced a capacity market in 2014 to safeguard security of supply as the country transitioned to more variable, low-carbon electricity sources like wind and solar power, but it looks increasingly like a backward step that rewards ageing, large-scale incumbents while penalising newer, smaller competitors.

Power sector investment was a particular worry in Britain five years ago because much of the coal power fleet was ageing and nearing closure. It was considered important to boost investment in new generation.

However, capacity market prices have fallen sharply since then, to £8.40 per kilowatt earlier this year from £22.50 the year before, suggesting that supply capacity shortfalls were not as severe as first thought.

There are more efficient, market-led approaches to guaranteeing security of supply.

Since 2014, some 72% of capacity payments have gone to incumbent, large-scale coal, gas and nuclear power plants, while only 11% of the funds have been awarded to assets associated with a more modern grid, such as transmission interconnections, battery storage and demand response.

At IEEFA, we have argued that the capacity market is an overly complicated and interventionist tool to incentivise back-up generation and maintain supply security. So Denmark does not have a capacity market, and its renewable market share currently stands at 53%, far higher than the 29% of generation produced by renewables in the U.K. last year.

The concept behind capacity markets is sound—to provide supply security in an era of rapidly growing penetration of variable resources. Ensuring that the lights stay on during the winter if the wind stops blowing is not a misguided policy. However, as system operators have learned how to integrate variable generation, the need for the capacity market, which has cost almost £4 billion and almost exclusively benefited incumbent generators, may be diminishing. The U.K. government is now consulting on the scheme to find out whether the objectives were met—and whether they were valid.

As currently structured, the capacity market guarantees new, additional revenues for around three quarters of all eligible power plants in Britain, and especially coal, gas and nuclear power plants, most of which would have continued to operate even without the additional revenue. After all, the most favoured technology has been middle-aged, combined cycle gas turbines (CCGT) presently benefiting from Britain’s rapidly falling coal generation. Around 50 gigawatts of generation annually have been awarded capacity contracts in the four main auctions so far, out of a maximum eligible capacity of about 65GW.

In a report published in March 2017, IEEFA argued that the U.K. capacity market’s goal of assuring security of supply during a low-carbon transition could be met more efficiently through energy market reforms and through the build-out of electricity interconnections with the country’s neighbours.

One idea for energy market reform is to pass heavier penalties to electricity generators and suppliers that fail to match demand and supply, forcing the grid operator to scramble to avoid blackouts. In the case of suppliers, they may have failed to forecast how much power their customers needed. In the case of generators, a power plant may have suffered an unexpected outage.

In these events, the grid operator has to call up standby generation at very short notice, under a so-called balancing mechanism. As a result, National Grid, the system operator, incurs additional costs. Some of these costs are passed on to the responsible generators and suppliers. If higher imbalance charges were levied on the responsible suppliers and generators they likely would be incentivised to do the work of the capacity market, for example to invest in fast-response generation to cover unexpected power plant failures or to contract with customers to pay them to reduce demand at times of stress.

BRITAIN’S ENERGY REGULATOR, OFGEM, IS ALREADY CARRYING OUT SEVERAL REFORMS designed to boost incentives for companies to invest in back-up solutions. This year it increased the value it assumes that customers place on not being disconnected during a blackout (value of lost load), which has the effect of increasing charges to imbalanced suppliers and generators. This will reduce the need for a capacity market.

Another important reform is imminent, with National Grid about to expand participation in this balancing mechanism to very small providers with as little as 1 megawatt of capacity, including aggregators of demand response and very small-scale generation for the first time. This should increase the flexibility of the U.K. grid. This widening of access is part of a project to share balancing energy with Britain’s neighbours, another move that should increase flexibility.

At present, Britain is second bottom alongside Spain –above only Cyprus – among European Union countries for levels of cross-border interconnection. By building more subsea cables, Britain can benefit from a more diverse pool of demand and supply across multiple countries in multiple time zones. Britain is now actively building out its interconnection. As it completes these projects there should be a diminishing need for a capacity market.

Britain’s capacity market has achieved its goal to assure security of supply, but at a cumulative cost since 2014 of around £3.8 billion (excluding companies that withdrew from the scheme). The vast majority of these funds (83%) have gone to operators of existing power plants (see table below).

Use of capacity payment funds since 2014 (excluding withdrawals from the scheme)

Energy status £m awarded GW supported %
Existing generation 3,115.8 216.4 83.4%
New build interconnection 122.8 9.0 3.5%
Proven DSR 18.1 2.2 0.8%
Refurbishing 185.2 11.1 4.3%
Unproven DSR 2.5 0.2 0.1%
Pre-refurbishment 142.2 7.3 2.8%
New build generation 173.4 9.2 3.5%
Existing interconnection 68.1 4.1 1.6%
TOTAL 3,828.2 259.5 100.0%
Energy technology
CCGT 1,692.8 114.0 43.9%
CHP & autogeneration 339.3 23.0 8.9%
Coal 502.4 34.1 13.2%
DSR 71.0 4.4 1.7%
Hydro 52.0 3.4 1.3%
Nuclear 587.7 39.1 15.1%
OCGT and reciprocating engines 228.0 16.2 6.3%
Oil-fired steam generators 0.6 0.0 0.0%
Storage 213.4 14.0 5.4%
Interconnection 140.9 11.1 4.3%
TOTAL 3,828.2 259.5 100.0%

Source: BEIS

Most of those power plants would have remained available regardless of the scheme. Only 3.5% of the funds have been awarded to operators to build new generation.

We encourage Ofgem to continue its energy market reforms by increasing the incentives available for generators and suppliers to avoid market imbalances. We welcome National Grid’s work to expand access to this balancing mechanism. And we encourage the U.K. government to continue to drive new-build interconnection. These policies will diminish the need for a capacity market, and Britain can return to a more efficient, market-led approach to guaranteeing security of supply.

Gerard Wynn is a London-based IEEFA energy finance consultant. He can be reached at gwynn@ieefa.org.


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