Last week, Britain held its biggest auction yet for electricity generating capacity, under a multi-billion-pound scheme whose stated aim is to increase investment in new, flexible generation, and so help balance the growth in variable wind and solar power, and make sure there are enough power plants to cover demand.
Under this capacity market, the system operator the National Grid pays operators of conventional power plants (mostly gas, coal and nuclear) to guarantee that they will make capacity available, in future, in any given delivery year.
This week, the National Grid will tender for the delivery of some 54 gigawatts (GW) of capacity (that’s the vast majority of the country’s entire, present conventional generation fleet) one year ahead, for delivery in 2017/18.
Last month, the 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), provided by ratepayers, for power plants to continue to be available in future, something most were already planning on. 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 (coal and nuclear), seems to conflict with the aim to motivate new capacity to help integrate variable renewables.
There are clear opportunities to make this capacity market more efficient – to avoid pure economic rents, or windfalls, to existing generation including coal. But does Britain need a capacity market at all?
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 may be 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 the National Grid to balance demand and supply, in real time, by paying generators to fire up or shut down supply. Capacity markets are also intended to balance demand and supply, but this time one to four years ahead.
Do we need both balancing and capacity markets?
Capacity markets pay conventional generation, which can run all the time, no matter the weather, to be available in future, including when wind and solar power aren’t available. The argument is that such baseload needs this extra reward, because electricity markets at present don’t pay for firm availability. And conventional generation needs this extra support – the argument goes – because growth in renewables has pushed conventional power plants off the grid, making them less profitable.
For me, there are two big problems with these arguments.
First, there is only a certain set of circumstances when we may need this baseload: for example, if the system is already short, and/ or there is a very high penetration of variable renewables. While UK supply is tight, this could be rectified in more targeted ways than delivering a windfall to the majority of conventional generating assets. For example, investment in electricity interconnection to Norway, France, Germany, Denmark and Iceland would be one way to boost supply, while corresponding investment in efficiency, including digital metering, 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 balance demand and supply in real time. That job becomes easier if you throw in some basic market design reforms, such as encouraging renewables to participate in balancing markets, and reducing settlement periods (when the operator fine tunes real-time demand and supply) from 30 minutes (in Britain) to 15 minutes (as in Germany), or even 5 minutes. Shortening settlement periods in this way would reduce the errors, for example in actual demand at any moment, and in wind and solar forecasting, that the National Grid has to correct.
Through the balancing market, the 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.
For example, in the balancing market, power plant operators can submit offers to increase generation, up to a limit of £10,000/ MWh. This winter, such offer prices have crept higher, for example to £1,990/ MWh on November 8. That’s 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). If the National Grid calls upon capacity participating in the SBR, this offer price is 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 the National Grid calls upon the STOR reserve, it pays according either to how short the system is, applying a probability of VoLL, or a certain pre-agreed fee.
The balancing and settlement code company, Elexon, tots up these balancing 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 to calculate 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 tasks of the capacity market, but voluntarily, rather than 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 due to be implemented in November 2018, under a rather obscure rule-change called P305.
First, the value of VoLL will double to £6,000 per megawatt hour (MWh), from £3,000. Second, the calculation of imbalance charges will be set by the most expensive 1MWh (called the Price Average Reference (PAR) Volume), after netting out bids and offers in any given settlement period. At present, the PAR volume is 50MWh, effectively diluting more expensive offers over shorter time periods.
These changes may not be enough to make the capacity market redundant, but they show what is possible. They raise the question 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. They also question the wisdom of abandoning SBR arrangements, effectively a fleet of reserve power plants, to make way for the capacity market. Why not keep the SBR, and do without the capacity market, instead?