European heatwave placing power grids under strain

As much of Europe swelters, power demand is rising sharply and the strain on energy systems is unfolding in real time. From surging evening prices to overstretched ancillary services and reduced nuclear output, every part of the system is designed for a specific role – a particular “shape.” But soaring temperatures are disrupting demand patterns and renewable output, leaving those pieces no longer fitting neatly into place.

The result? A grid under mounting pressure. 

France, Spain and Germany are among the hardest hit, facing not only extreme heat but also the cascading effects on electricity demand, generation mix and market dynamics. This is not just about higher consumption: it’s a growing mismatch between renewable generation and peak demand – and the economic signals this clash is sending. 

Solar power remains abundant during daylight hours but fades quickly in the evening – just as households ramp up usage with cooling and appliances. This daily shift is pushing up prices precisely when conventional fossil fuel plants need to ramp up. Behind the scenes, ancillary and balancing markets are under mounting pressure, and even nuclear is feeling the heat, literally. 

The result is a growing paradox: negative daytime prices, extreme evening prices and a grid caught in between. 

The heat is on 

Temperatures have been hovering 5–10C above seasonal norms in much of southern and western Europe. In parts of Spain and southern France, daytime highs over 35C are now common. But the meteorological reality is only half the story. 

Air conditioning and cooling appliances are driving up power demand, particularly in the late afternoon and evening. In countries such as Spain and Italy, where residential air conditioning is widespread, demand spikes sharply between 16:00 and 21:00. In Germany and France, the pattern differs slightly, driven more by industrial and commercial load, alongside rising household demand. 

The shape of the daily load curve is changing: earlier morning ramp-ups, higher midday plateaus and longer, sharper evening peaks. This evolution is clashing with renewable generation limitations – presenting challenges for grid operations and market dynamics. 

Solar cliffs and price spikes 

In markets with high solar penetration, midday generation dominates. This has two notable effects: 

• Daytime prices often turn negative. 

• A steep “solar cliff” emerges in the early evening, as generation plummets just as demand remains high. 

This causes a significant spread between midday and evening prices. In recent weeks, day-ahead prices in Germany and France dipped into negative territory during solar hours, especially on weekends. Prices close to EUR -100/MWh have been recorded between 12:00-15:00, only to exceed EUR 300/MWh by 20:00. 

This paradox is one of the most defining features of Europe’s current power market. Abundance is followed by scarcity, with daily spreads of EUR 300–400 increasingly common.

The economic impact is significant: 

• Daily average prices are volatile but moderate and may still average EUR 100/MWh despite extreme swings. 

• Matching consumption with generation matters more than ever. Savvy consumers can save significantly by cooling homes or charging EVs during solar hours. 

• Storage assets benefit from price spreads, charging at low prices and discharging during expensive peaks. 

• Intraday trading becomes critical, with high premiums for early evening delivery. 

• Generators and storage operators face rising risk and volatility. 

Fossil ramps, grid strain, market friction 

To meet evening demand, fossil fuel plants – mainly gas and coal – must ramp up rapidly. Meanwhile, nuclear declines during solar hours. But such flexibility comes at a cost: 

• Stop-start cycling increases wear and reduces plant efficiency. 

• Many units were designed for baseload operation, not aggressive ramping. 

• Opportunity costs grow for plants idling during the day. 

• French nuclear assets like Civaux and Chooz are under scrutiny for corrosion issues that experts tentatively link to daytime modulation. 

So fossil-fuelled plants face a key decision: run during the day at low prices, or stay offline and capitalise on evening peaks? This decision affects not only energy markets but also reserve markets, where availability is critical. 

Ancillary services under strain 

While spot markets draw headlines, it’s ancillary services that offer the clearest stress signals. 

During solar hours, conventional generation is largely offline, leaving fewer units to provide frequency regulation, spinning reserves or fast ramping. In the evening, those same units are needed for generation, making reserve capacity costly. 

Prices for ancillary services are surging. 

In Germany, balancing auctions have cleared at double typical summer levels and in Italy, fast reserve procurement is fetching record premiums. TSOs across Europe are paying significantly more to secure flexible capacity in a shrinking pool.

This poses a dilemma: offer capacity to energy markets or to reserve services? During tight evening hours, the energy market often wins – leaving flexibility gaps that prices alone can’t always fix. 

When the river runs hot 

Another emerging concern is nuclear plant cooling. France’s EDF issued a public notice almost two weeks ago that output at its Bugey plant may be reduced due to elevated Rhone River temperatures. Environmental regulations limit the temperature of discharged cooling water, and those thresholds are nearing. 

With air temperatures forecast to hit 38°C, other plants – including Cruas and Saint-Alban – are also under watch. 

This isn’t new: similar constraints occurred in 2019 and 2022. But the pattern is clear – climate extremes are reducing the operating window of what was once Europe’s most dependable baseload power. 

What is the market telling us? 

At a structural level, this reveals Europe’s growing reliance on a narrow band of flexible resources – both technically and economically. 

Battery storage helps, but most systems are sized for 1-2 hour discharges – not enough to cover 4-5 hour evening peaks. Flexible thermal plants are bearing the brunt, but at high cost and with growing fatigue. Demand-side response remains underutilised. Industrial flexibility exists, but price signals are not always passed on quickly. 

Meanwhile, the price paradox continues.  

If Europe sees more heatwaves – and climate models suggest it will – system stress will increase. Blackouts remain unlikely in well-interconnected markets, but the cost of reliability is rising. Operators may turn to strategic reserves, curtail trade flows or issue scarcity alerts – all with market consequences. From a policy perspective, the takeaway is clear.  

Europe needs greater flexibility, year-round. Reserve products must evolve to reflect the scarcity of fast-responding capacity. Market signals are working, but investment frameworks are lagging due to policy uncertainty, geopolitics, and technological inertia. 

Europe’s power system is now shaped as much by climate as by technology. Heatwaves are no longer rare disruptions but regular, systemic stress tests. Each year, the margin for error narrows. 

The paradox of abundant solar energy by day and high-cost scarcity by night is becoming structural. The system must evolve to match supply and demand in real time, pairing each shape with the right slot. The price signals are clear. The challenge is putting the right tools to the right tasks – before the toy breaks.

This article originally appeared as a column on www.montelnews.com