TTF futures averaged €41.76/MWh in Week 25, down 14.8% on the week. Despite the gas benchmark decline, several Southeast European electricity markets recorded higher prices. Serbia increased by 9.6%, Hungary by 10.6%, Croatia by 11.2%, Romania by 7.7%, and Italy by 3.7%. The pattern points to a disconnect between gas and power price movements during the period.
Hourly balancing shifts alongside weaker gas pricing
The divergence was linked to hourly balancing dynamics rather than fuel fundamentals alone. Gas remained an important marginal fuel, including in systems where gas-fired generation sets the price. However, it was not the dominant driver of short-term power price changes during Week 25.
Demand and generation availability moved against each other over the week. Electricity demand rose by 3.1% to 16.34 TWh, while hydro generation fell by 4.7%. Wind output declined by 4.4%, and thermal generation increased by 19.4%. These changes required more dispatchable capacity even as fuel input costs decreased.
Gas-fired output increases as thermal dispatch expands
Gas-fired generation rose by 32.3%, adding about 771 GWh versus the previous week. The increase indicated that gas plants were not only relevant but increasingly needed to cover system requirements. Falling TTF prices supported lower marginal generation costs, but wholesale electricity prices remained elevated across the region.
The higher level of thermal dispatch was especially visible during evening peak hours. With more gas units running to meet tight conditions, the timing of supply and demand contributed to price levels despite cheaper gas benchmarks. In this setup, power prices reflected system constraints more than changes in fuel spreads alone.
Implications for procurement, generators and market design
The Week 25 pattern affected industrial procurement approaches that rely primarily on gas price signals. Electricity price formation was described as shaped by multiple inputs, including hydro availability, renewable generation profiles, temperature-driven demand shifts, cross-border flows, and the timing of evening ramps. As a result, a declining gas benchmark could coexist with rising electricity prices when flexibility is constrained.
For generators, the week supported flexible thermal assets through increased dispatch opportunities during periods of system tightness. Gas-fired plants benefited from both fuel economics and higher utilization during scarcity hours. In that context, value was tied more to availability during tight periods than to fuel spread alone.
From a policy standpoint, Week 25 highlighted differences between gas market stability and electricity market affordability. Changes such as improved LNG supply, higher storage levels and hub pricing can reduce upstream fuel risk, but they do not directly address structural electricity issues including grid congestion, ramping needs, renewable intermittency and hydrological variability.
