Increasing French power exports reducing negative price hours

Normally, we pay money to buy goods. But in today’s power markets, the situation is sometimes reversed and producers can actually pay consumers to take electricity off their hands.

Imagine walking into a car dealership, driving away with a brand-new car, and finding that your bank account has more money than before. Sounds absurd, right?

This is because the power system is about balance. Either too much power supply without enough demand, or insufficient power supply to meet demand, can cause problems. Therefore, payments can flow in what appears to be reverse, depending on who is taking the actions to help keep the system in balance.

This is exactly what happens in power markets during negative price hours - and it’s becoming more common. The record number of negative price hours in France (set in 2024) was broken by June 24th 2025, just halfway through the season. At that point the trend looked almost exponential.

But then, July broke the rhythm. Only 7 negative hours were recorded during the whole month, and from mid-August onwards, the number of negative price hours remained low.

At first glance, these numbers seem counter-intuitive. July usually marks the start of the summer lull where demand is low and solar production is still strong. Nuclear output even increased from 38 GW to around 40-42 GW. That would normally lead to more negative price hours too.

This year, however, demand was unusually high during the first week of July due to a heatwave. Load peaked at 50 GW, a level more typical of March. And yet, in March, negative prices were present every day.

So if demand wasn’t the key driver, what was?

The first suspect is hydro. France faced a dry summer, with run-of-river production dropping from 4.7 GW in June to just under 3.2 GW in July. However, this can’t offer the full explanation as both March and April had similar hydro production levels and more negative prices.

Wind output dropped sharply after mid-May, as usual when temperatures increase, and negative prices were observed on a daily basis in June, so that is unlikely to be a key driver either.

We know that negative prices are mostly solar-driven too. That said, solar production was broadly stable between June and early July, which doesn’t explain the sudden change in trend. Even in late July, when solar output fell slightly, it remained close to the levels we saw in early June, which was a period where negative prices occurred on a daily basis.

Exports and interconnections changing the negative prices game

From early July, France consistently exported more than 10 GW per hour and that is where the story changes.

Some might think exporting power is just a matter of “pushing” electricity to neighbors. In reality, three conditions must be met:

1. France must have enough production to generate a surplus

2. Export capacity must be available on the interconnectors

3. Neighbouring countries must be willing to buy the power

Negative prices occur when there is too much power on the grid. This first condition is usually met by design during sunny, low-demand days.

But July brought two key developments that unlocked the second condition. Firstly, IFA1 interconnector capacity returned to 2 GW on July 1st, reopening a major route to the UK. Secondly, CORE region export limits were raised by 4 GW starting July 12th, creating additional room for France to send power into Europe.

This meant France could suddenly export much more of its surplus production.

And our neighbors were ready to buy. The UK, which prefers cheap imports over burning expensive gas, quickly filled its interconnection capacity. That helped ease some of the oversupply pressure, but the real breakthrough came from the north as Germany and Belgium reversed their trade flows.

In June, Germany and Belgium were net exporters to France, making French oversupply even worse. From early July, they flipped and became large net importers, taking as much French power as the grid could carry.

Changing solar dynamics

In June, German solar production frequently exceeded 25 GW. By July, it was rarely below 30 GW and the same pattern held in Belgium and the Netherlands. Counterintuitively, this helped France. High German solar meant that German thermal units (gas, coal) were running at minimum, freeing up interconnection capacity and creating room for imports. France could finally push out its surplus power instead of being stuck with it, reducing negative price hours dramatically.

What this shows is that solar has been driving negative prices, one way or another.

This summer’s price dynamics show that negative prices are not just a story of solar overproduction but of interconnection capacity and cross-border flows. When France can export freely and neighbors are willing to take its surplus, the pressure on the grid eases and negative hours almost disappear, even with high solar output and low demand.

For market participants, this underlines the importance of monitoring not only domestic fuel mix forecasts but also European flow dynamics and interconnector availability, as they are now key drivers of French Day-Ahead price formation and volatility.