European TTF futures averaged €49.00/MWh, up 0.9% week-on-week, but most Southeast Europe day-ahead power markets declined. Stronger renewable generation and improved regional supply conditions were cited as the main drivers of price formation. Over the same period, gas volatility did not result in higher electricity prices across the region.
TTF prices stayed volatile during the week, rising to a high of €49.99/MWh before falling to €46.77/MWh by Friday. The one-month forward was assessed at €41.180/MWh. In related benchmarks, Henry Hub traded at $3.24/MMBtu, while JKM stood at $15.940/MMBtu.
Despite continued sensitivity to LNG competition, storage refill needs, and geopolitical risk, near-term fundamentals did not support a sustained gas-led rally. Against that backdrop, electricity trading patterns in Southeast Europe were shaped more by renewables than by gas-linked signals. Demand also increased during the week.
Renewables output rose as demand climbed
Regional wind and solar output increased by 518.6 GWh (+16.6%), reaching 3.64 TWh. Wind generation rose by 28.1%, while solar increased by 10.4%. The additional renewable supply coincided with rising electricity demand of 4.6%.
The higher renewable contribution supported lower prices across multiple markets, including Serbia, Bulgaria, Croatia, Romania, Hungary, and Italy. The price impact from renewables was described as strong enough to offset upward pressure that would typically be associated with gas market movements. This shift kept gas volatility from translating into day-ahead price increases.
Thermal generation mix changed alongside hydropower declines
Thermal generation also did not pass through gas volatility into power pricing during Week 24. Gas-fired output fell by 58.0 GWh (-2.4%) to 2.38 TWh. As a result, gas was less frequently positioned as the marginal source of supply.
Coal and lignite replaced gas in marginal hours
The decline in gas generation was met by higher coal and lignite output, which rose by 420.6 GWh (+24.4%) to 2.14 TWh. This increase largely compensated for a 7.5% drop in hydropower. With coal increasingly setting the marginal unit in several hours, gas signals were partially displaced from short-term price discovery.
This substitution effect further weakened the link between commodity price swings and electricity price formation across the region during Week 24. Gas volatility remained present in the background, but it did not determine day-ahead outcomes where renewables and coal dispatch played a larger role.