In Week 25, TTF futures averaged €41.76/MWh, down 14.8% on the week. Electricity prices in most Southeast European markets moved higher despite the gas benchmark decline. Serbia increased by 9.6%, Hungary by 10.6%, Croatia by 11.2%, Romania by 7.7%, and Italy by 3.7%.
Gas and electricity price divergence in Week 25
The gap between gas and electricity pricing was most visible across the region’s wholesale markets. Gas continued to play a role as a marginal fuel in systems where gas-fired generation sets the price. However, it was not the main driver of short-term power price changes during the week.
Hourly balancing dynamics contributed to the disconnect between fuel costs and electricity outcomes. The pattern coincided with higher overall demand and weaker output from several non-dispatchable sources. Electricity demand rose by 3.1% to 16.34 TWh.
Demand, renewables output, and thermal dispatch
Generation from hydro fell by 4.7% and wind output declined by 4.4% in Week 25. Thermal generation increased by 19.4%, reflecting a higher need for dispatchable capacity. These changes occurred alongside lower TTF prices.
Gas-fired generation rose by 32.3%, adding approximately 771 GWh versus the previous week. While lower gas prices reduced marginal generation costs, wholesale electricity prices remained elevated across the region.
The increase in thermal dispatch was particularly linked to evening peak hours, according to the week’s market pattern. With more generation required during those periods, price levels stayed supported even as fuel input costs eased.
Implications for procurement and generator operations
For industrial buyers, the week highlighted limits in procurement approaches that rely primarily on gas price signals. Electricity price formation was shaped by factors beyond the gas benchmark, including hydro availability and renewable generation profiles.
Other elements included temperature-driven demand changes, cross-border flows, and the timing of evening ramps. As a result, a declining gas benchmark could coincide with rising electricity prices when system flexibility is constrained.
For generators, Week 25 improved conditions for flexible thermal assets. Gas-fired plants gained from both fuel economics and increased dispatch opportunities during periods of system tightness.
The commercial value increasingly depended on availability during scarcity hours rather than fuel spread alone. This aligned with the observed need for additional dispatchable capacity during peak periods.
Policy focus on gas market stability versus power affordability
From a policy perspective, Week 25 separated gas market stability from electricity market affordability outcomes. Changes that improve LNG supply, storage levels, and hub pricing can reduce upstream fuel risk.
Those measures do not directly address structural electricity challenges such as grid congestion, ramping requirements, renewable intermittency, and hydrological variability. The week therefore reflected how system constraints can override fuel-price signals.
Overall, Week 25 reinforced that fuel prices explain part of regional power market movements while system shape, flexibility needs, and timing increasingly account for the rest.