European winter power prices: Has the market priced in too much risk?

Key takeaways

• Gas remains the dominant price driver. Gas is expected to set marginal prices in more than 65% of French winter hours and 70% of German hours, leaving both markets exposed to TTF volatility and geopolitical supply risks.
• Coal is benefiting from higher gas prices, but capacity is constrained. European coal generation has increased by around 12 TWh since 1 March, and profitable plants are expected to run near baseload this winter despite lower year-on-year availability.
• Hydro deficits and weak nuclear availability remain bullish risks. Nordic reservoirs are around 10 TWh below their 10-year average, while French nuclear availability is expected to fall 5 GW year on year in Q4 before recovering in Q1.
• Kpler sees growing downside risk to Q1-27 power prices in France and Germany. Forward contracts have doubled in recent months, but mild weather, recovering nuclear availability and lower gas burn could challenge current valuations. A renewed gas shock or weak wind generation remains the key upside risk. A warm skew cuts expected French Q1-27 demand growth from 5.5% to 0.3% year on year.

Gas remains the dominant driver of winter power prices

Europe enters winter facing elevated gas prices, depleted hydro reservoirs and constrained nuclear availability. Gas remains the dominant driver of power prices, leaving markets highly exposed to TTF volatility. TTF, the Dutch gas benchmark, accounts for well over 80% of daily price movement in French winter power products and over 90% in German products. Power prices have risen and fallen with TTF, which has been driven by the wider Middle East conflict.

Exposure differs by market. Gas sets the price in over 95% of hours in Italy, and in over 70% of hours in Great Britain, Belgium, the Netherlands and Germany. Spain is shielded by high renewable penetration and strong hydro stocks. France and Poland are partly protected by nuclear availability and strong coal generation respectively.

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Higher gas prices revive coal generation, but capacity remains constrained

Coal generation was weak in Q1 2026, with declines across all major markets. Since the start of the Middle East crisis it has recovered sharply. European coal generation is up about 12 TWh y/y since 1 March, led by Poland, the Netherlands, Germany and Czechia. Higher TTF prices have restored coal's competitiveness against gas. Forward prices suggest coal generation will remain profitable through spring 2028, while gas-fired plants face much tighter margins, with spark spreads potentially turning negative this winter.

Policy has not added capacity. Germany discussed moving some coal assets from grid reserve back into the market, and Italy discussed bringing two coal assets back if gas exceeded €70/MWh. Neither proposal has advanced beyond discussion. Kpler expects coal availability to be about 1 GW lower than in winter 2025/26. Operators could skip maintenance and run plants harder, but Kpler expects availability to be flat to down overall. Plants that are in the money should run near baseload all winter.

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Hydro deficits and nuclear outages tighten European supply

Drought and high temperatures have drained reservoirs across most major bidding zones. The Nordics hold the largest deficit, about 10 TWh against the 10-year average. Southern Norway (NO2, NO5 and NO1) is in strong deficit, and NO2 is increasingly pulled towards continental prices. NO4 holds a relative surplus and remains shielded from high TTF prices. In the Alps, reservoirs in northern Italy, Switzerland and France are also in strong deficit. Some outlooks point to wetter weather, but Kpler expects conditions to stay well below seasonal averages over the coming months.

Iberia is the exception. Spring rains kept Spanish hydro in surplus through summer, and seasonal forecasts point to strong precipitation. Kpler expects Spanish hydro to stay strong and keep prices dampened this winter.

Nuclear availability is also poor. Drought has cut output from the European fleet through October. Reactors in northern France are only now returning, and Romania's main nuclear plant may stay offline until later in November. Finland, Sweden and Belgium also face heavy maintenance. In France, Kpler expects availability to be about 5 GW lower year on year in Q4, then to recover gradually through Q1-27 as plants return from refuelling outages.

Environmental outages have resulted in Europe losing 27 TWh in generation capacity year to date, with over 70% of that on the nuclear fleet and France hit hardest. Removing low-cost nuclear baseload pushed prices up across Europe in August and September. 

Kpler expects nuclear availability to recover in 2027 but does not see these outages as a one-off. Weak hydro, high temperatures and El Niño, which Kpler expects to last until spring, raise the risk of more extreme events such as heatwaves next summer. Kpler meteorologists see no direct El Niño impact on European weather, but could raise global temperatures. Q2 nuclear availability is already low, so Q2 contracts need to price weak hydro stocks and constrained nuclear fairly.

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Mild weather could significantly reduce Q1 power demand

Initial signals from the European Centre for Medium-Range Weather Forecasts point to significantly higher than normal temperatures across continental Europe in Q1. The UK and the Nordics are 0.5℃ to 1℃ above the long-term average. Precipitation is broadly positive across continental Europe, while parts of the Nordics look neutral to drier. A warm, wet winter points to a thinner Alpine and Nordic snowpack. That could lift run-of-river output and storage in Q1 but reduce snowmelt in spring, with a smaller effect in Q2 and Q3.

Weather shapes demand. The Kpler model shows French Q1-27 demand rising 5.5% year on year under a mean weather scenario but only 0.3% with a warm skew. Germany and Great Britain show similar effects. France is the most temperature-sensitive market, with load changing by 2 GW or more for each 1℃. Kpler expects about 1% growth in most major markets in 2027 from data centres, heat pumps and electric vehicles, and 2.1% in the Netherlands.

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Renewables are reshaping European power price dynamics

Kpler estimates that Europe will install 48 GW of solar and 21 GW of wind this year. A neutral wind signal for Q1 is mildly supportive for Germany, which had poor wind years in Q1 2025 and Q1 2026. Solar is flipping peak-base spreads, a trend once confined to summer that now reaches shoulder months such as October and March. Reforms in France, Germany and the Netherlands, including the Dutch net metering phase-out, are reducing deeply negative bids from renewable assets. Kpler expects these reforms to cut negative-price hours structurally in 2027.

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Why Kpler sees downside to French and German Q1-27 prices

French and German Q1-27 power contracts have doubled in recent months, with French Q1-27 now trading around 190 €/MWh. Kpler sees downside at these levels, as current prices appear to overstate gas-fired generation requirements and understate the potential demand impact of a mild winter.

In France, gas sets the price in 80% to 84% of hours under a medium weather scenario. Under the Kpler base case of mild weather, that share falls sharply. Nuclear availability in Q1-27 is slightly higher year on year, and high prices give operators an incentive to raise utilisation. The Kpler's gas outlook points to improving European supply conditions in 2027, supported by additional US LNG capacity and an assumed gradual resumption of Qatari exports. Further supply growth is expected later in the year, including pipeline gas from Romania's Neptune Deep project. Weak hydro is the main offset, with French reservoirs projected to start Q2 at a record low.

In Germany, the Kpler base case has coal burn rising 4 TWh year on year and gas burn falling 16 TWh, or 30%. Wind is the key swing factor. Wind output 10% above average removes 3 TWh of gas burn, and wind displaces about 2.5 times more gas than imports do. With load 5% lower, residual demand falls in all neighbouring markets, helped by more nuclear in Switzerland and Czechia. German gas storage is low and LNG arrivals have stopped in recent days, which adds pressure in coming weeks. Kpler holds slightly bearish views on coal and TTF into Q1, while Alpine hydro and NO2 remain bullish factors.

On the French calendar 2027 contract, Kpler was bullish in its previous three monthly reports because of weak hydro and rallying gas. It is now slightly bearish, because the rally has fairly repriced those risks. Renewables set the price in 6% to 7% of hours at about zero, and nuclear sets it in about 30%. The market implies that other fuels price the remaining hours at €150/MWh to €160/MWh. That looks fair given weak hydro and strong gas, but it is already priced. Offshore wind delays could support Q4-27 prices, since those farms play a baseload role.

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Key watchpoints

• TTF direction, which can override any fundamental view. A gas shock would make the bearish case redundant.
• Q1 wind output. The neutral signal means forecasts differ, and low wind would lift prices from an already high base.
• French hydro withdrawals and environmental outages heading into Q2 and summer 2027.

French and German Q1-27 power prices have rallied sharply, but Kpler's outlook for milder weather, lower gas burn and recovering nuclear availability points to growing downside risk. Elevated TTF prices and weak hydro remain important bullish factors, while a renewed gas shock or prolonged low wind generation could quickly reverse the outlook.

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