Power prices in Britain soared last year due to a colder than normal Q1 and low wind generation in the summer throughout Europe, according to an EnAppSys’ analysis of the industry.
These lower temperatures and reduced wind generation resulted in greater demand for gas-fired generation and corresponding upward pressure on prices at a time of increasing demand globally as the global economy recovered.
The EnAppSys study showed that day-ahead and within-day system prices increased dramatically in 2021 in on-peak and off-peak settlement periods. Day-ahead and system prices saw record high averages, and system prices peaked at a record £4,037.80/MWh – the highest imbalance price seen since the £5,003.33/MWh recorded in June 2001, shortly after the New Electricity Trading Arrangements (NETA) went live.
Meanwhile, demand for electricity rose last year as COVID restrictions were relaxed, with more people returning to work and businesses reopening their doors. However, the 247.8TWh of demand recorded in 2021 was still a 3% decrease from levels seen in the last “normal” year in 2019, indicating a continuing trend of lower demand and an increase in embedded generation.
The main single generation type meeting this demand was the CCGT fleet, with gas-fired generation totalling 107.5TWh across the year – the same level as the combined renewable fleet collectively (wind, solar, hydro and biomass). The gas-fired fleet saw a 13% increase from its record low levels of generation in 2020 (94.9TWh), when demand fell due to COVID lockdowns, but the 2021 level was 6% lower than in 2019.
The combined renewable total of 107.5TWh was lower than that in 2020, in which there were notably high levels of wind and solar generation. However, this was still higher than the 103.7TWh recorded in 2019, reflecting an increase in wind and solar installed capacity.
Overall, gas-fired plants contributed 37% to Britain’s generation mix in 2021, while wind accounted for 22%. Making up the rest of the generation mix was nuclear (15%), biomass (10%), imports (9%), solar (4%) and coal (2%).
Paul Verrill, director of EnAppSys, commented, “Last year was characterised by high commodity prices, which fed through into wholesale prices and then into higher bills for consumers. A cold winter from December 2020 to February 2021 reduced Europe’s gas reserves, which were then further depleted over the summer months by extended periods of low wind generation; this required more gas and coal generation across Europe.
“All of this has occurred against a background of increased demand for LNG and geopolitical issues around gas supply. The overall effect of these factors drove gas prices to extreme heights in the second half of 2021. These have continued in 2022 and the market indicates that they are set to stay high for some time.
“The electricity prices we have seen have, in part, been driven by the high gas (and carbon prices). However, there has also been a scarcity of generation supply brought about by issues at interconnectors and nuclear plants combined with some large generating assets leaving the market following poor revenue performance in previous years. The design of the GB capacity market, which aimed to keep a healthy generation margin in the market, has led to some of the problems.
“This ‘capacity crunch’ against a background of lower wind has led to generating assets seeking very high prices to assist in balancing the grid, leading to Ofgem expressing concern about market participant behaviour.”
Ofgem recently published an open letter highlighting its concerns about the extremely high balancing prices that had been submitted by some parties in the balancing mechanism (BM) across Q4 last year.
Paul Verrill continued: “In terms of generation, renewable output was lower than in 2020, due mainly to a reduction in windspeeds in the first three quarters. Wind output fell by 5.9TWh in 2021 – the largest year-on-year decrease in wind generation in history for GB. This highlights the challenges of creating a greener generation mix and meeting our net zero requirements.
“Total nuclear output also fell, from 47.2TWh in 2020 to 43.4TWh last year. This reduction is in part a consequence of Hunterston B7 going offline last November, plus Sizewell B1 and B2 seeing extended outages from May to August for repairs and Hartlepool 1 seeing an extended outage from September into 2022. This decrease in output had the effect of further increasing dependency on fossil fuel generation.”
