The U.K. this week holds its biggest auction ever for electricity generating capacity under a multi-billion-pound scheme whose stated aim is to increase investment in new, flexible generation. The intent is to help balance the growth in variable wind and solar power while ensuring there are enough power plants to cover demand.
Under the so-called capacity market, the system operator National Grid pays owners of conventional power plants (mostly gas, coal and nuclear) to promise that they will make capacity available in any given delivery year.
At tomorrow’s auction, National Grid will tender for the delivery of some 54 gigawatts (GW) of capacity (the vast majority of the country’s present conventional generation fleet) one year ahead, for delivery in 2017/18.
Last month, National Grid completed its third, four-year-ahead (T4) auction, in that case for 2020/21. To date, these T4 auctions have allocated about £1 billion a year (£2.97 billion in total) from ratepayers for power plants simply to continue to be available in the future, something most were already planning on doing. Sound like value for money? Four-fifths of these funds will go to existing capacity, and nearly one third to coal and nuclear. Allocating so much to existing units, including relatively inflexible capacity, seems to conflict with the stated goal of driving new capacity to help integrate variable renewables.
While there appear to be some clear opportunities here to make the market more efficient, the question is whether Britain really needs a capacity market.
Capacity auctions have created a fourth, major market for delivery of electricity in Britain alongside the wholesale power market, the balancing services market, and auctions for low-carbon electricity. This is probably over-kill.
The role of the wholesale power market is obvious enough: to allow utilities and generators to trade electricity across various timescales. Auctions for renewable power are meant to boost low-carbon generation in line with public support for climate action. The balancing market allows National Grid to balance demand and supply in real time by paying generators to fire up or shut down supply. Capacity markets, intended to balance demand and supply, work one to four years out.
BUT DOES THE U.K. EVEN NEED BOTH BALANCING AND CAPACITY MARKETS? Capacity markets pay conventional generators, no matter the weather, to be available down the road, including when wind and solar power aren’t there. The argument is that such baseload needs this extra reward because electricity markets don’t pay for constant availability. And that they need this extra support because growth in renewables has pushed conventional power plants off the grid, making them less profitable.
There are a couple of big holes in these arguments.
First, baseload is required under only a certain set of circumstances, such as when the system is already rather short, for example, and/or there is a very high penetration of variable renewables. While U.K. supply is rather tight, this could be rectified in more targeted ways than delivering a windfall to the majority of conventional generating assets. Investment in electricity interconnection, for example, to Denmark, France, Germany, Iceland and Norway would be one way to boost supply. A corresponding investment in efficiency, including in digital metering, or batteries, would smooth peaks in demand.
Second, balancing markets can already do the job of relieving system stress if the system operator pays generators and consumers enough to change their output or demand in real time. That job becomes easier if you throw in some basic market design reforms, such as allowing renewables to participate in balancing markets, and reducing scheduling periods (when the operator fine tunes last-minute demand and supply) from 30 minutes (in Britain) to 15 minutes (as in Germany), or even 5 minutes. This would reduce errors in demand or wind and solar forecasting, for instance, that National Grid has to correct.
Through the balancing market, National Grid rewards power plant operators for covering shortfalls or surpluses in supply in near real time. These costs are added up and passed on to the market participants responsible for causing an imbalance through a so-called imbalance charge.
In the balancing market, power plant operators can submit offers to increase generation, say, up to a limit of £10,000/ MWh. This winter, such offer prices have increased higher than average, to £1,990/ MWh on Nov. 8, for exampled, compared with average wholesale power prices of about £50/MWh. Generators can also participate through bilateral arrangements with the National Grid, through the so-called short-term operating reserve (STOR), and supplemental balancing reserve (SBR). In the latter case, imbalance charges for that half-hour period are automatically set at the official value the energy regulator Ofgem places on avoiding a blackout. That so-called value of loss load (VoLL) value is presently set at £3,000/ MWh. Where National Grid calls upon the STOR reserve, it pays according to how short the system is, applying a probability of VoLL to a certain pre-agreed fee.
The balancing and settlement code company Elexon tots up National Grid’s resulting costs, and calculates the imbalance charge for that settlement period. In this way, balancing costs are passed on to market participants and regular power markets, incentivising generators and utilities to be more careful in calculating their own demand and supply—and to be in balance in real time. In other words, the balancing market can force participants to perform the same tasks as the capacity market, but voluntarily, rather than being funded by ratepayers at a cost of £1 billion a year.
There are signs that the balancing market is becoming more effective at passing on the true cost of correcting system stresses under two key reforms to be implemented in November 2018.
First, as we have seen, some of National Grid’s costs are based on the value to energy consumers of avoiding a blackout, or VoLL. This value of VoLL is planned to double to £6,000 per megawatt hour (MWh), from £3,000.
Second, the calculation of imbalance charges at present doesn’t take account of bids and offers below a certain reference size of 50MWh (the Price Average Reference (PAR) Volume), which may exclude some of the most expensive offers. The reforms will see the PAR volume cut to 1MWh, from 50MWh, which itself was cut from 500MWh last year.
These changes may not be enough to make the capacity market redundant, but they show what is possible. They beg the question of why the energy regulator, Ofgem, cannot introduce more ambitious action sooner, and find other alternatives to the present capacity market giveaway to existing gas, coal and nuclear.
Gerard Wynn in an IEEFA energy finance consultant.
RELATED POSTS:
IEEFA Update: A Rush to Subsidies as Power Plants in Europe Face an Existential Threat
IEEFA Europe: Can Coal Power Hang On?
IEEFA Europe: Seeds of an Industrial Alternative to Germany’s Regional Lignite Economies
