Western Europe Gas-Fired Output Up 6.59 GW This Summer as Heatwaves Erode Nuclear and Hydro
Repeated curtailments at French nuclear plants and falling hydropower reserves have driven gas generation sharply higher across five countries, lifting power prices and gas demand simultaneously.
Gas-fired power generation across five western European countries has risen by a combined 6.59 GW this summer compared with 2024 and 2025 summer averages, Montel Analytics data published on Wednesday (2026-08-12) show, as a sequence of heatwaves forces nuclear plant curtailments and depletes hydropower reserves. The week of 2026-08-10 brought at least the fifth extreme heat episode of the season, sustaining a demand and supply pressure that has now run across the entire summer.3,2
The increase feeds directly into European gas demand at an awkward moment. ICE Endex TTF front-month touched €60.29/MWh in Thursday (2026-08-13) evening trading, down 1.22% on the session, yet gas-fired generators across France, Italy, Spain, Britain and Belgium are absorbing more fuel to fill the gap left by curtailed nuclear and hydro capacity. Higher gas burn for power in summer runs against the injection timeline that utilities need before the October heating season begins.3
France has been the most visible stress point. EDF data showed France's nuclear output was cut by 7.3 GW on Wednesday (2026-08-05) — equivalent to 12% of total installed capacity — as river temperatures rose and environmental discharge limits tightened. Nuclear accounts for roughly 70% of France's electricity mix in normal conditions, so curtailments of that scale move spot markets quickly.2
The day-ahead market responded on Tuesday (2026-08-11). French day-ahead power prices surged by as much as 21.8% to €142.5/MWh, per LSEG data cited by Reuters, driven by expectations of nuclear output cuts at the mid-day peak. A parallel episode in mid-July 2026 had already forced EDF to cut generation by 6.4 GW as river temperatures hit cooling discharge limits. Two curtailments of that magnitude within two months, triggered by the same physical constraint, underscore that this is not a one-off.2
Italy and Spain show comparable generation shifts. Montel Analytics placed gas-fired output in each country up 28% this summer against the 2024-2025 baseline, contributing roughly 3.1 GW apiece to the 6.59 GW aggregate gain. Britain and Belgium account for the balance, though Montel did not publish individual figures for those two markets.3
Italy's gas dependency in the power sector puts it in a distinct position. Ember data show gas plants set the Italian day-ahead power price in 89% of hours so far in 2026, compared with 15% in Spain — a gap that reflects Italy's heavier reliance on thermal generation and Spain's larger renewable fleet. Italy's average power price stood at €142/MWh in March 2026, per Ember, against €59/MWh in Spain over the same period. As gas output climbs further, the spread between the two markets looks set to widen.1
The nuclear cooling constraint is a physical one, not a market mechanism. When river temperatures exceed regulatory thresholds — as they have at least twice this summer — French nuclear operators must curtail output regardless of power demand. The 7.3 GW cut recorded in the week of 2026-08-05 followed the same logic as the 6.4 GW reduction in mid-July 2026, and with the fifth major heat episode of the season arriving in the week of 2026-08-10, the pattern now looks seasonal rather than episodic.2
How far into late August and September the current heat pattern extends will shape the gas demand picture heading into winter. German power settled at €134.41/MWh in Thursday (2026-08-13) trade, a signal that the French curtailment pressure has spread north across European power markets. The next EDF cooling assessment and any revision to late-August meteorological forecasts will tell traders whether the 7.3 GW curtailment sequence recorded in early August (2026-08-05) marks a high point or merely a mid-summer plateau.2,3