Europe's Heatwave Summer Drives Gas-Fired Generation 6.59 GW Above Recent Norms
Repeated heatwaves have forced western Europe into a gas-intensive power mix this summer, squeezing nuclear and hydro output and pushing up TTF prices.
Gas-fired power generation across five western European countries — Italy, Spain, France, Britain and Belgium — ran 6.59 GW above average summer levels recorded in 2024 and 2025, Montel Analytics assessed, as repeated heatwaves this season hammered both nuclear output and hydropower resources. The increase represents roughly a third above recent-year averages.5
Italy and Spain led the surge, each posting gas-fired generation up 28% compared to recent summers, accounting for 3.1 GW of that combined uplift, per Montel's analysis. France, despite being Europe's largest nuclear producer, contributed significantly after river temperatures limited cooling capacity at several reactors.5
The French nuclear constraint has been severe. During the week of July 13 (2026-07-13), France's nuclear fleet shed 6.4 GW of output — roughly 14% of the country's total daily power demand — as the heatwave drove river temperatures above regulatory discharge limits. That shortfall fed directly into continental gas burn.3
ICE Endex TTF front-month gas traded at €63.41/MWh on August 19 (2026-08-19), down 0.33% on that session, while summer power prices in France hit record highs on Thursday, May 28 (2026-05-28), Montel reported, with power prices in Germany reaching their highest since March as markets priced in mounting outage risk from water shortages.1
The river system has become a second constraint working alongside high temperatures. Water at the Kaub chokepoint on the Rhine fell to its lowest level in decades for mid-July, driving freight costs for diesel shipments from Rotterdam to southern Germany up more than 50% in a single week, according to reporting from the week of July 13 (2026-07-13). The comparison to 2018 is instructive but sobering: the Kiel Institute for the World Economy calculated that November 2018's low Rhine levels cut German industrial production by 1.5% and shaved 0.4% from GDP.3
This year, the damage has landed earlier and harder. An exclusive analysis by economic research firm Prognos, published in Handelsblatt during the week of July 13 (2026-07-13), put the cost of Germany's end-June heatwave alone at more than €6 billion ($6.8 billion).3 Prognos has estimated that Germany could lose €1 billion on each day temperatures exceed 35°C — a figure that implies cumulative losses of a different scale if the frequency projections for three or four intense heatwaves per summer prove accurate.3
Wildfires have compounded the broader European toll. Across the five hardest-hit countries, the fires have already cost more than $3 billion, according to an analysis by the Financial Times cited by Foreign Policy, while the June heatwave alone is estimated to have trimmed more than $2 billion from European economic output.4
The labor productivity channel adds another dimension. Research cited in Chartbook 467 by Adam Tooze on August 16 (2026-08-16) found that output per hour falls by approximately $1.30 in constant PPP terms for every degree across the 30–35°C range, or roughly 3% of mean hourly output in the 2014–2024 sample. At sustained temperatures well above that band — which Italy, France and Spain have seen repeatedly this summer — the drag compounds quickly.6
Hydro storage entered the summer in an ambiguous position. ENTSO-E's Summer Outlook, published June 3 (2026-06-03), showed total European hydro storage 19% above June 2024 levels but 18% below June 2025, meaning the buffer was neither flush nor critically depleted when the heatwaves intensified. That mixed starting point likely explains some of the regional variation in how quickly gas generation had to fill the gap.2
ENTSO-E also projected European electricity demand 2.5% higher than the previous year, a baseline that left limited slack once nuclear deratings and hydro drawdowns began accumulating.2
The cross-sector link running from French nuclear output to TTF has been the dominant pricing mechanism this summer. Nuclear outages have reduced French baseload, lifting power prices across the region, which in turn pulled gas-fired plant into the merit order and sustained TTF demand at a point when storage injections typically wind down. How quickly this mechanism eases into autumn depends on river temperature trends and whether deferred nuclear maintenance units return on schedule — two variables that French grid operators have not yet publicly resolved.5,3