European TTF futures averaged €49.00/MWh in Week 24, up 0.9% week-on-week, while most Southeast Europe day-ahead power markets moved lower. Stronger renewable generation and improved regional supply conditions dominated price formation during the period.
Natural gas benchmarks remain volatile
TTF prices fluctuated through the week, reaching a high of €49.99/MWh before easing to €46.77/MWh by Friday. The one-month forward contract was assessed at €41.180/MWh.
Other gas benchmarks included Henry Hub at $3.24/MMBtu and JKM at $15.940/MMBtu. Despite sensitivity to LNG competition, storage refill needs, and geopolitical risk, near-term fundamentals did not support a sustained gas-driven rally.
Wind and solar output drive regional price direction
Electricity markets were shaped more by renewables than by gas during Week 24. Regional wind and solar output rose by 518.6 GWh (+16.6%) to 3.64 TWh.
Wind generation increased by 28.1%, while solar output climbed by 10.4%. Demand also rose during the week, increasing by 4.6%, alongside the higher renewable supply.
Lower power prices across multiple SEE markets
The additional renewable generation contributed to price declines across several markets, including Serbia, Bulgaria, Croatia, Romania, Hungary, and Italy. The impact was sufficient to offset upward pressure that would typically be associated with gas market moves.
Thermal generation also did not transmit gas volatility into power pricing. Gas-fired output fell by 58.0 GWh (-2.4%) to 2.38 TWh, indicating gas was less frequently on the margin.
Coal and lignite replace gas as hydropower falls
Coal and lignite increased by 420.6 GWh (+24.4%) to 2.14 TWh during the same period. This largely compensated for a 7.5% decline in hydropower.
With coal increasingly setting the marginal unit in several hours, gas signals were partially displaced from short-term price discovery across the region.
Week 24 market structure shifts toward dispatch mix
Week 24 reflected a changing structure in Southeast Europe power markets, where renewables output and hydro variability interacted with coal dispatch in determining day-ahead outcomes. Gas remained a macro risk driver, but its volatility did not translate into higher electricity prices across the region.
