Low demand and falling gas prices resulted in wholesale power prices declining to their lowest level in two years, a new report from a Teesside energy data analyst has revealed.
This was the standout highlight from a new report on the GB Q2 2023 electricity market from Stockton-on-Tees-headquartered EnAppSys.
Demand is typically lower at this time of year than in winter, but this quarter saw lower demand than any quarter since 2020 with a total demand of 51.6TWh, only 5% higher than the 49.0TWh in Q2 2020 when the COVID-19 pandemic was strongly dampening European demand. This was partly due to industries and consumers changing their electricity usage habits due to the high prices seen in recent quarters.
Alongside the reduction in conventional generation in Q2 2023, gas prices fell from April through to early June, dropping as low as £19.47/MWh. Across June, however, a sharp increase in gas prices was observed, peaking at £35.34/MWh. Carbon prices fell across the quarter with the UK ETS prices peaking at £74/te in early April and closing the quarter at a low of £50/te.
Against this backdrop, system prices dipped to their lowest level since the summer of 2021. System prices decreased by 34% on average compared to the previous quarter. The average system price of £87.58/MWh was the lowest for any quarter since Q2 2021, due mainly to more periods of negative pricing than would usually be expected; system prices dropped as low as -£155.20/MWh in May. Negative prices occur when the system operator pays for surplus energy to be consumed or not produced during these periods, rather than simply selling a surplus to balance the system.
Day-ahead prices also dropped beneath £0/MWh on several occasions during periods of high renewable generation. More extreme negative pricing was seen elsewhere in Europe, particularly in the Netherlands and Germany where prices dropped well beneath -€100/MWh at times.
Renewables generation (wind, biomass, solar and hydro) was the largest contributor to the GB power generation mix during the quarter, accounting for 38% of total output, although this was lower than usual due to falling demand. Gas-fired generation made up 35% of the total, with nuclear (15.2%), imports (11.7%) and coal (0.1%) accounting for the rest.
Paul Verrill, director of EnAppSys – which is part of the Montel Group – said: “Electricity prices during Q2 2023 followed the downward trend of wholesale gas prices, which fell throughout the quarter until early June as Europe emerged from the winter with record high gas stocks in storage at the end of the first quarter. As a consequence, market expectations were that the refilling of stocks through the summer season would be easier than had been anticipated ahead of the winter. This, coupled with expectations of weak economic growth, exerted a downward influence on market gas prices which fed through into the electricity market as a result of lower generation costs.
“However, from early June onwards gas, and consequently electricity prices, rose due to increased competition for LNG shipments between Europe and Asia, an extension of the maintenance period at Nyhamma gas processing plant in Norway, and the announcement that the Groningen gas field in the Netherlands would close in the autumn. As well as declining gas prices, increased French nuclear availability and low demand this quarter contributed to the GB power market continuing its recovery from the turbulent events of 2022. Wholesale power prices decreased to levels last seen in the summer of 2021 and the interconnectors returned to a position of net imports comparable to that seen before Russia’s invasion of Ukraine. However, it should be noted that prices in summer 2021 were still notably higher than historical averages, so prices currently remain high relative to these long-term averages.”