Weather shifts and renewables drive market volatility

European energy markets in April embarked on a roller-coaster ride, primarily driven by abrupt weather changes. Unseasonably warm weather during the first half of the month weighed on already anaemic power demand. Coupled with persistently high renewable power generation, this led to the first-ever negative hourly prices on the Spanish day-ahead market. By month’s end the Spanish market had recorded more than 100 hourly instances of negative prices, with similar reports in many other European markets. This trend highlights the ongoing erosion of daytime value created by the expansion of solar capacity. This will only reverse when more flexible battery storage enters the market to capitalise on profitable intraday price volatility. Notably, last year Italy achieved its highest-ever battery deployment, nearly doubling its battery capacity, with most installations integrated with solar energy projects.

Meanwhile, both the Spanish and French nuclear fleets had to significantly reduce output during periods of low residual load. French nuclear output plunged by 17 GW within a single day, providing flexibility not only for France but all Western Europe. Such instances of nuclear flexing are expected to become more frequent and intense as intermittent renewable capacity is increasingly integrated into the grid. Despite the intraday flexing of nuclear reactors, significant economic curtailment of renewables occurred during periods of negative hourly prices. For instance, Germany reduced 13 GW of wind production within a single hour, while Great Britain curtailed 6 GW of wind output for economic reasons, experiencing its most negative day-ahead price since last July. Flexibility in Central Europe was further constrained by cross-border capacity limitations on France’s eastern borders. This was implemented from mid-March for grid security reasons, signalling upside risks to geographic spreads. Additionally, French grid operator RTE highlighted potential security issues between August and October, which could further elevate the upside risk to Italian prices.

During the second half of April, a cold spell prompted a surge in gas and power demand, leading to record late storage draws across Europe. These draws were also required by weak supply, due to losses in Russian supply, Dutch production, the onset of Norwegian spring maintenance, and tightening LNG supply driven by strong Asian demand and a lack of new supply growth. Although low LNG supply is not problematic in the short-term, thanks to high inventories, it poses a risk of summer prices rising too quickly. This could potentially bring an excess of LNG to Europe when storage space is limited, thereby introducing a wider contango. While EUA prices followed a similarly upward trend, their momentum was primarily driven by speculative short positions.

Now that we are in May, with several national holidays across Europe, we expect surging solar production to introduce more low-priced hours. Conversely, potential future upside risks include high cooling demand, low hydro availability, and higher river temperatures, which may pose challenges beyond the solar production peak. Notably, following the shutdown of thermal plants in Italy in recent years due to a lack of cooling water, the Italian regulator recently approved amendments to the capacity market, requesting thermal plants to modify their cooling systems to reduce water dependence. We continue to monitor all the above risks and assess the impact of conflicts in Ukraine and the Middle East, as the market prices in gas risks arising from these factors.