Cold winter weather saw electricity demand in Britain return to pre-COVID levels in the first three months of 2021, a new study from electricity market analyst EnAppSys has revealed.

The study on Britain’s power market showed that total demand (at the transmission system level) across Q1 2021 was 56.0TWh, close to the 55.7TWh in Q1 last year despite lockdown measures still being in effect across the quarter.

The cold weather, combined with relatively low wind levels for a first quarter, meant that a greater proportion of fossil fuels were required than in Q1 2020. Fossil fuels contributed 41% of total demand in the latest quarter, versus 36% from renewables while nuclear had a 15% share. Of the fossil fuels, gas was by far the greatest contributor with 38% of total generation compared to just 3% from coal.

The return to high demand levels, coupled with relatively low wind generation across the quarter (19.3TWh versus 23.0TWh in Q1 2020), meant that the system was often tight. Average margin was 18% lower than that in Q1 last year and average spinning reserve was 7% lower. The CCGT fleet saw higher average utilisation at 51% compared to 38% in Q1 last year.

The periods of tight system resulting from the relatively high demand, lower renewables generation and more requirement for dispatchable fossil-fuel fired generation meant that there were several periods of high wholesale prices.

Paul Verrill, director of EnAppSys, said: “Although lockdown measures remained in force throughout the first quarter, the cold snap meant that transmission system demand was still relatively high and back close to pre-COVID levels for this time of year. This situation coincided with similar conditions across Europe, with the continent as a whole seeing around 10TWh more demand this quarter than in Q1 2020 as a result of colder temperatures.

“This high demand combined with low wind generation resulted in several tight periods in the quarter, with balancing needed to meet demand. This led to very high prices on several occasions. The average day-ahead auction price over the quarter was £64/MWh, the highest in any Q1 since 2014, with the next highest being an average of £52/MWh in Q1 2018. There were particularly high price spikes during cold snaps with day-ahead auction prices peaking at £1,500/MWh for the 5pm-6pm period on January 14 and at practically the same price level for the same period on the preceding day.

“The tight margins also led to high “cash-out” prices in industry processes – this being the price charged by the system operator, National Grid ESO, for meeting the demand of market participants who were short of power. On January 8, a cash-out price of £4,000/MWh occurred during the evening peak; this was the highest imbalance price seen for almost 20 years, albeit below the record of £5,000/MWh set in June 2001 shortly after the current market systems had been introduced.

“The reduction in renewable output (27.1TWh compared to 31.2TWh in Q1 2020) stems from a combination of high winds in the last Q1 and lower than usual winds this quarter.

“Coal generation has continued its Q1-on-Q1 decline, with Fiddlers Ferry having closed since Q1 last year, while the 28.4TWh produced from CCGT plants was materially higher than the 23.1TWh seen in Q1 2020. Since that time, Calon Energy units have withdrawn from the market and the increased output represents materially higher utilisation levels for the CCGT fleet than for the same period last year.

“As with coal, nuclear generation has also seen a Q1-on-Q1 decline since Q1 2017. This means there has been a steady reduction in low-carbon power from this source. The main reason for the reduction from last Q1 is that Heysham 2-8, Hinkley Point B7 and Hinkley Point B8 were offline for some of this Q1, having been online during Q1 2020.”