Comparing France and England's Energy Markets

The French and GB energy markets: a case study

Across European energy, the biggest topic at the moment is negative prices. With 2023 being the year that this issue started to emerge, 2024 has picked up where we left off, already displaying a record number of hours where have observed negative prices. In France, 176 such hours were recorded (up to June 6) already beating the total 147 hours seen the previous year. But what is causing them, and how are market participants reacting? Read on to find out.

Our case study relates to May 12, a Sunday on which the French average Day-Ahead (DA) price dropped to 2 EUR/MWh, fluctuating between 62 EUR/MWh and -87EUR/MWh, with nine consecutive hours of negative prices from 09:00-17:00 CET.

French walk-outs: 2010 all over again

A large part of wind & solar farms in France operate under a Contracts for Difference (CfD) scheme. When DA prices are negative, the CfD scheme does not apply – meaning that subsidies are not paid to producers. As a consequence, portfolio managers disconnect the assets and they do not produce power. We estimate that on May 12, this led to the disconnection of 2 GW of wind and between 2-3GW for the solar. This accounts for around a quarter of the forecasted production, leaving a sizeable gap which needed to be filled by France's nuclear fleet.

Modulating French nuclear: pragmatism and adapation like Deschamp's winning era

When low-price periods are anticipated, nuclear power plants can be modulated using two strategies. The first strategy involves a full stop for the weekend, while the second strategy entails modulation during overnight and/or solar hours. On May 12, the second strategy was employed, as nuclear production significantly reduced during solar hours:

• Night Reduction: Nuclear production was reduced from 36GW to 33GW overnight.

• Solar Rise Reduction: As solar production increased, nuclear output was further reduced to 23GW.

• Solar Decline Recovery: When solar production began to decline, nuclear output was ramped back up from 23GW to 37GW.

So with sufficient generation to meet demand on the day, why was France importing via interconnectors?

Importing extra power: reflecting the 1998 squad

With such modulation – and renewable disconnection – it is clear that France was oversupplied. However, France found itself importing because the whole of Europe was also oversupplied during solar hours. This meant that the French fuel mix was flexible enough to absorb high levels of European solar production.

Intraday market impacts

Capacity was available between France, Belgium and Germany (none of which will stop France from winning the Euros) as these countries were coupled. As a consequence, intraday weighted average prices for these countries remained close. The ID market traded way below the day ahead with peak at -500EUR/MWh between 13:00-15:00 CET.

Balancing market impacts

Despite the imports, the market managed to maintain a relatively good balance during solar hours. We can observe some Replacement Reserve volumes (light blue colour on NIV analysis chart below). These volumes are mainly exports to Germany. When capacity is available, French grid operator RTE uses this scheme as it’s more flexible than reducing nuclear output.

Such volumes are transferred in Germany 40 minutes before delivery starts and they are sold by traders on the market. When this happens, the impact on German intraday markets can be huge - just as Kylian Mbappé's impact on Germany's defence will be should we meet our neighbours in the knockout rounds.

Making sense of it all

So, in the context of a low day ahead price, an absence of flexibility and an intraday market trading well bellow the day-ahead price, why is France importing so much? The purple line below shows the intraday import from GB to France. This still seems counterintuitive when we look at the intraday weighted average price always staying above the French price: why would people buy at the highest price to sell at low price? That's the kind of thing you see in the Premier League, not Ligue 1...

Power not coming home

Intraday imports from GB to France occurred despite higher intraday prices in GB than in FR. Already in the day-ahead auctions this price difference was quite stark, with British day-ahead prices remaining well above zero across the whole day on May 12 (min:18.50 EUR/MWh, average: 44.50 EUR/MWh, max:103.60 EUR/MWh).

All of Britain’s neighbours saw negative prices in the day-ahead auctions on May 12, except for I-SEM (Ireland and Northern Ireland). You can see in the graph below that whilst France hit its lowest period of day-ahead prices for the day at 2-3pm CET at -87 EUR/MWh, British power still cost 30 EUR/MWh.

Penalties going England's way for once

The oversupply situation across Central Western Europe did feed through to British power prices in intraday markets, with the Weighted Average Price (WAP) dipping to -36.82 EUR/MWh at 13:30 CET (shown below). France was facing far more significant oversupply issues than Britain at that point with the intraday WAP reaching -451.57 EUR/MWh. This means anyone producing or importing power into France would effectively face a penalty fee of almost 500 EUR/MWh – around fifteen times the ‘penalty fee’ faced by parties producing or importing into Britain, at a time where the interconnectors had been scheduled to run at full export into France.

Fitting the players to the system

To understand the driving factors behind reversing the interconnectors at that moment, it is important to understand the constraints faced by the British system. May 12 was a relatively warm Sunday: demand was low, solar generation was high, and wind was moderately high too as shown in figure 5 below. This lead to a very low level of system inertia (which National Grid aims to keep at a minimum of 120 GVA seconds in order to deliver a steady system frequency). Figure 6 shows British inertia plummeting at midday on Sunday, down to as low as 85 – although the forecast had been even lower at 74.5 GVAs.

So what did this mean for France? Britain needed extra spinning mass on the system, which is often achieved by turning down wind farms and replacing that with generation from gas power plants (CCGTs), as they provide inertia through their rotating mass. Overall it was a more extreme day for maintaining system stability, with some locational issues in the south east too. To manage this, Britain exported across the interconnectors with France in order to create additional demand, despite the highly negative price differential. Once the overall demand increased, this could then be filled by increasing the output from CCGTs to create headroom on the system.

The situation here highlights how beneficial the interconnection is between GB and its neighbours, not only for economic reasons but for the management of the overall system. It also provides opportunities for traders on the continent, who, on recognising Britain’s need to export power, could react accordingly.