Britain introduced a capacity market in 2014 to safeguard security of supply as the country transitioned to more variable, low-carbon sources like wind and solar power, but it looks increasingly like a backward step, away from a more democratic energy system including local, small-scale generation, to a centralised, sclerotic scheme rewarding the biggest incumbents.

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

Since the inception of the scheme, three quarters of capacity payments have gone to existing, large-scale coal, gas and nuclear power plants, and one tenth to assets which might be associated with a modern grid, such as interconnection, battery storage and demand-response.

At IEEFA, we have argued that the capacity market is an overly complicated and interventionist tool to crack the problem of incentivising back-up generation and avoiding black-outs, in a UK grid which today has a moderately high level of renewable power, at 29% of generation last year, but far below Denmark, for example, which has 53% renewables and no capacity market.

The idea of capacity markets is to counter the economic threat renewable energy poses to large, existing gas, coal and nuclear power plants, to make sure the lights stay on when renewables are scarce and demand is high, for example on cold winter nights when the wind isn’t blowing. As renewable energy capacity grows, large, on-demand power plants may increasingly depend on such events to make serious money.

Given that it is difficult to predict months and years ahead how often these “scarcity events” might occur, the capacity market is intended to guarantee operators of on-demand power plants additional revenues, to drive investment. The UK government is now consulting on the scheme, to find out whether the objectives were met, and whether they were valid.

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 exist without these new windfalls. 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 65 GW.

In a report published in March 2017, IEEFA argued that the UK capacity market’s goal of assuring security of supply during a low-carbon transition could be met more efficiently through energy market reform, and build-out of electricity interconnection 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, when the grid operator has 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 fault.

In these events, the grid operator has to call up alternative generation at very short notice, under a so-called balancing mechanism. As a result, the National Grid incurs costs some of which are passed to the generators and suppliers responsible. By passing higher imbalance charges more directly to those responsible, suppliers and generators may 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 contract with customers to pay these to reduce demand at times of stress.

Britain’s energy regulator, Ofgem, is already carrying out such “cash out” reforms, to sharpen incentives to invest in back-up solutions. It can go further, by raising these charges. This will reduce the need for a capacity market.

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

At present, Britain is second bottom alongside Spain– only above 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 achieves this, again 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 withdrawals from the scheme). The vast majority of these funds (83%) have gone to operators of existing power plants (see Table below). Most of those power plants would have remained available regardless of the scheme. Only 3.5% have been awarded to operators to build new generation.

At IEEFA, we encourage Ofgem to continue its “cash out” energy market reforms, to increase the incentives available for generators and suppliers to avoid market imbalances. We welcome the National Grid’s work to expand access to this balancing mechanism. And we encourage the UK government to continue to drive new-build interconnection. In this way, the need for a capacity market will fall, and Britain can return to a more efficient, market-led approach to guaranteeing security of supply.

Table 1. Use of capacity payment funds since 2014 (excluding withdrawals from the scheme)

Source: National Grid

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