The first two weeks of September have seen records shattered in the GB power market day after day, with day ahead prices clearing at £2,500/MWh on Nordpool for Wednesday 15th September, breaking the all-time record set just 24 hours before at £1,750/MWh.

In this blog, I take a look back at some of the numbers behind the (previously) record breaking events of Thursday 9th September and what it means for the approaching winter. Amidst a backdrop of already high prices due to rising global gas and carbon costs, GB saw day ahead prices hit £867/MWh. Within day, power was being traded at the market cap of £3,000/MWh on the EPEX platform for multiple hours (causing EPEX to increase this cap to £6,000/MWh on Friday), while the system price (cash-out) hit an all-time record of £4037.80/MWh as National Grid were forced to call upon units at very high prices to ensure supply met demand.

So why did this warm September day turn out to be the single most expensive day of balancing actions ever observed in GB, at a colossal cost of £38m?

Wind has been very low for this time of year

The first two weeks of September 2021 have seen unseasonably low wind. The chart below shows the cumulative distribution of wind load factors observed for the last six years. Here we define the load factor as the wind generation in each period divided by the maximum wind generation seen that year. The first two weeks of September 2021 are strikingly anomalous, with 50% of periods seeing wind generation at less than 15% of the annual maximum, and 92% of half hours seeing wind generation of less than 25% of the annual maximum. The impact on the GB power system is heightened compared to earlier years because the system is much more reliant on wind than previously seen, as the UK seeks to decarbonise the power sector. This trend is only set to grow as the UK targets 40GW of offshore wind capacity by 2030, and brings forward the debate on when longer duration storage will be needed to back up continuously long periods of low wind output in a system more reliant on wind.

There were a lot of units unavailable

Summer is usually a time when we see low demand and low prices, so plant that require maintenance take this opportunity to undergo any maintenance required to be ready for the winter period. These planned outages have taken over 17GW of capacity out of the market from a combination of coal, CCGT, biomass and nuclear units. This includes the mothballed Calon assets, which the market is still struggling to cover. Additionally, earlier in the week an outage occurred on the GB-France interconnector (IFA1), taking another 500MW out of the market. Extremely tight market conditions in Ireland meant that electricity trading on the Moyle interconnector was also suspended, preventing any exports to GB, while the Nemo interconnector from Belgium was also not fully importing. Finally, some flexible assets identified that the market would be very tight, and opted not to enter the wholesale market, instead chancing that they’d be needed at higher prices in the balancing mechanism.

National Grid were left with very few options, and the market knew it

Putting these pieces together, we see a difficult situation facing the control room at National Grid, whose primary role is to ensure there is enough power to meet demand. The chart below shows the demand that National Grid had to reach (over 33GW), the wholesale generation they knew was coming from each unit’s Final Physical Notification (FPN) at 30GW, and the remaining flexible assets they could call on (3.9GW) to meet the remaining 3GW needed. These assets knew that most, if not all, of them would be required so could get away with charging a significant premium on their offers, to the tune of the price cap of £4,000/MWh, a precedent first seen in January with similarly tight margins.  

What should we expect from the coming months?

At the time of writing, day ahead price records have already been broken again, with Wednesday 15th September peaking at £2,500/MWh, an all-time record. The system is struggling to cope with the swathe of plant on outage and the continual low wind period we find ourselves in, and the market is reacting accordingly. Going forwards, we expect a large number of plant to return from outage, and the go-live of the North Sea Link will add an additional 1.4GW to the GB power arsenal. Additionally, wind (usually) picks up over the winter months, so we expect to see a significant increase in generation here.

However, winter peak demand will be at least 10GW higher than we have seen in September, if not more. Low wind in GB usually means low wind in the interconnected countries, so we may find the interconnectors are not able to back up the system in these periods as we’ve already seen. There is also the risk of a unit tripping, taking precious MWs from the margin of comfort. Although the Loss of Load Expectation (LOLE) is only 0.1 hours this winter, any of these events will lead to a much tighter margin than hoped for, more high and volatile pricing in the market, significant opportunities for traders, and rising bills for consumers.

Listen to Rajiv discuss the topic further during an episode of our Investment Uncut podcast: Inside GB's power market with Rajiv Gogna