European heatwave pushes power prices to multi-year highs across markets

A heatwave stretching across western Europe has driven wholesale electricity prices to their highest levels in more than a year, exposing the fragility of power systems that are simultaneously managing surging cooling demand and temperature-related generation losses.

In Great Britain, the National Energy System Operator paid £470 per megawatt-hour to secure imports from continental Europe during the Tuesday evening peak between 5pm and 7pm. That price is more than six times the June 2024 average of £71/MWh and nearly four times the £123/MWh seen just 24 hours earlier. The operator also activated demand flexibility services that reduced household consumption by roughly 115 MW during the same window.

Gas plants and wind farms falter in the heat

The immediate trigger for the price spike was a combination of higher demand for air conditioning and a sudden drop in domestic generation. Five British gas-fired power stations reported they would need to curtail output because of "ambient" conditions, removing approximately 2.5 gigawatts from the grid, enough to supply 2.5 million homes. According to Shivam Malhotra, head of power trading at consultancy LCP Delta, such unplanned outages are "not unusual" in extreme temperatures, but the scale this week is notable: the loss of capacity is about 40% higher than before the heatwave began.

Wind output collapsed as the high-pressure system responsible for the heat also stilled the air. Wind farms provided only 13% to 15% of Britain's electricity on Tuesday, compared with a June average of roughly 30%. Solar farms, meanwhile, held steady at around 14 GW, meeting about 35% of total demand. Clear skies offset the efficiency loss that photovoltaic panels normally suffer in extreme heat.

Continental markets under parallel pressure

Britain was not alone. On the Epex Spot exchange, German day-ahead prices for Tuesday evening were forecast above €545/MWh, the highest level since June 2024. French prices climbed above €268/MWh, a peak not seen since August 2023. Both markets are grappling with the same meteorological drivers: temperatures approaching 43°C in parts of France, depressed wind speeds across the North Sea and northern Europe, and thermal constraints on conventional generation.

French nuclear output has been curtailed because river water temperatures have risen above the thresholds that permit safe reactor cooling. EDF typically reduces output at several plants each summer when water temperatures exceed regulatory limits, but the current heatwave has arrived earlier and with greater intensity than in recent years. The French grid operator RTE has warned of further reductions if temperatures remain elevated through the week.

Interdependence exposed

The episode illustrates how tightly coupled European power markets have become. Britain's ability to import 1.5 GW of additional capacity from the continent, secured at the £470/MWh peak, depended on spare generation in France, Belgium and the Netherlands. But those same markets were tightening simultaneously, limiting the volume available for export and pushing prices higher for everyone.

Malhotra noted that the system operator's scramble for imports is "likely to come from the continent, which is having its own problems due to the heatwave." The result is a feedback loop: higher continental prices make imports more expensive for Britain, while British bidding pulls power away from continental consumers, reinforcing the price signal across borders.

Demand response proves its worth but remains small

The 115 MW reduction achieved through Britain's demand flexibility service, which pays households and businesses to cut consumption during peak periods, is a fraction of the 2.5 GW lost from gas plants and the 1.5 GW of imports secured. Yet it demonstrates that distributed demand-side response can be activated quickly and at a lower cost than emergency generation. National Grid ESO has said it expects such services to grow to several gigawatts by 2030, but the current fleet remains modest compared with the scale of weather-driven swings.

Industry analysts argue that the economic case for wider participation is strengthening. At £470/MWh, the value of avoided consumption is roughly £470,000 per gigawatt-hour, a price signal that could justify significant investment in smart thermostats, battery storage and industrial load shifting if it becomes a recurring feature of summer markets.

Nuclear and hydro constraints deepen the squeeze

Beyond gas and wind, the heatwave is testing other low-carbon sources. French nuclear availability, which normally provides the backbone of winter and summer baseload, has been reduced by an estimated 5-8 GW across the fleet due to cooling water restrictions. In Spain and Portugal, hydroelectric reservoirs are below seasonal averages after a dry spring, limiting the ability to ramp up output when wind falls. Italy, a net importer, faces similar pressure as its gas-fired plants also contend with ambient temperature derating.

These compounding constraints mean that the marginal price-setting unit across much of western Europe is increasingly a gas plant operating at reduced efficiency, burning more fuel per megawatt-hour produced, while carbon costs under the EU ETS add a further €70-80 per tonne of CO2. The combined effect pushes short-run marginal costs well above levels seen in previous summers.

Price signals and policy responses

The £470/MWh peak is a market signal, not a retail price. Most British households are on fixed tariffs or protected by the energy price cap, which limits the pass-through to bills. Industrial consumers on half-hourly metering, however, face direct exposure. Some energy-intensive users have already curtailed production voluntarily, calculating that the cost of lost output is lower than the cost of power at current levels.

Policymakers are watching closely. The European Commission's upcoming electricity market design reform, agreed in principle earlier this year, aims to decouple consumer prices from short-term gas-driven spikes through long-term contracts for difference and expanded two-way contracts for flexibility. But those mechanisms will not be fully operational before 2026 at the earliest. In the meantime, national governments may face pressure to intervene, as Spain and France did in 2022, if the heatwave persists and prices remain elevated.