Winter 2020 was a bumpy ride in the GB electricity market. Electricity Margin Notices (“EMN”) (the new name for a “NISM” – Notice of Insufficient System Margin) were issued six times, there were two Capacity Market Notices (“CMN”) (following one on 15 September just before the start of winter) and on a further five occasions National Grid ESO tweeted about possible system tightness. As expected, prices were spiky and volatile across all near-term time periods, and generators were able to capture significant upside in the Balancing Mechanism (“BM”).
In just 3 days this year, EDF was paid more in the BM than in the whole of Q3 last year, at one point earning £4,000 /MWh – 70x the average winter 2020 day ahead power price of £55 /MWh. According to analysis by Hartree Solutions, the six biggest earning power stations in the BM in January were all CCGTs with EDF’s West Burton B plant earning £8 million on 8 January when both an EMN and a CMN were issued.
Market participants with imbalances faced significant price risk with Imbalance Prices also seeing significant spikes, reaching £4,000 /MWh on 8 January which was the tightest day of the past winter. This exposed particularly smaller firms which can struggle to hedge their full shape risk in the forward markets.
Why was the market so tight in winter 2020 and was it a one-off or part of a wider trend?
There are two opposing schools of thought on this. One view is that NG ESO wants to make EMNs less rare: if market participants are to be encouraged to develop necessary capacity, then there need to be signals to suggest it is needed. If ESMs are only issued rarely, then the market might conclude there is ample capacity.
The other perspective, which I favour, is that we are heading into a period of structural under-capacity. The market is responding to the Government’s deadline of October 2024 for the closure of all remaining coal plant, and the aging nuclear fleet is seeing declining reliability even where lifetime extensions have been granted. The beleaguered next generation nuclear facility at Hinkley Point C has had it’s opening date pushed back again, this time to June 2026 (and another hike in the costs), means that the nuclear replacement programme will not be available to fill the gap.
There were also some more specific events last winter which may not be part of the wider trend. Last year the bankruptcy of Calon Energy forced its two large CCGTs (2.3 GW in total) into mothballs, although recent developments suggest they could be brought back into use ahead of next winter, and there was an extended outage from 8 December until 9 February on the BritNed interconnector which added to the capacity shortage.
“For one week in mid-February, wind farms generated nearly 40% of Great Britain’s electricity, keeping electricity prices low and reducing carbon emissions. However, two weeks later wind power had almost disappeared, providing just 7% of weekly generation and leading to higher prices,” – Ed Birkett, Senior Research Fellow, Energy and Environment, Policy Exchange
Of course, the weather did not help – January and February in particular saw the weather alternating between cold and still periods with low wind output and high demand for heating, and storms where the temperature was notionally higher but still felt cold, driving heating demand.
What does last winter’s tightness means for the market?
The next few years will see less coal and nuclear running, and while more renewable generation continues to be built, solar makes a minimal contribution in the winter, and high pressure weather systems with low temperatures and little wind are actually quite common at that time of year.
But while lower capacity margins increase the chances of blackouts it does not make them likely as NG ESO has plenty of reserves to call on in addition to the capacity market. That in itself does not mean all is well – my sense is that for the next few years, we will see periods of significant market tightness in winter, with corresponding price spikes and volatility.
At the same time, there will be low system demand in the summer, due to the increasing contribution of solar power, with more periods of negative prices. And across the year, I expect balancing costs to rise sharply, as was seen last summer when low system demand saw balancing costs rise sharply.
The other important trend is that of electrification. The Government is pushing hard for electric vehicles to replace petrol and diesel cars and vans, and is looking at ways to encourage the uptake of heat pumps as an alternative to gas heating. Either of these in isolation would have a major impact on electricity system demand, with electric heating driving higher use of electricity in winter – some 78% of British homes are currently heated with gas, so the potential impact on the electricity system of electricifation could be very material.
Although some of the capacity issues last winter might have been one-offs, the reality is that dispatchable generation is being increasingly replaced with intermittent renewable capacity, while demand is set to grow significantly. This means that although the specific drivers may differ in future, the overall outcomes may be remarkably similar, and winter 2020 may indeed provide an insight into a new market paradigm.
If this is the case, then market participants will need to find ways to manage these very different winter and summer dynamics.