The previous posts:

• European power reserves: part 2 - aFRR (and how solar is impacting it)

• The German aFRR capacity market - a deeper look on prices

• An intro to the European balancing world

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Heatmaps for 2025 and 2026

To present the capacity prices, I created several heatmaps. The columns on the left show the upward direction, while those on the right display the downward direction. It’s important to note that, unlike in countries such as France, the aFRR capacity auction in Germany operates on a pay-as-bid basis. This means that capacity providers are paid the price they bid, rather than a single clearing price. For each auction, both an average price and a marginal price are determined.

These results pertain specifically to Germany, even though Germany participates in ALPACA, which facilitates capacity sharing with Austria and the Czech Republic. Additionally, the auction is structured into daily blocks of four hours, resulting in six separate auctions per day for each direction.

Monthly average of the average

Below is the average of the monthly average price per block. It is clear that, in the upward direction, capacity prices are mainly influenced by demand: prices are higher during peak load hours. In contrast, prices in the downward direction are heavily affected by solar generation, with noticeably higher prices during daylight hours with high solar output. Additionally, we observe slightly elevated prices at night in winter, when wind generation tends to be stronger.

Although the difference may not yet be statistically significant, it appears that capacity prices in 2026 have been slightly lower compared to 2025. This could be at least partly attributed to the increased penetration of large-scale batteries in the aFRR segment.

Maximal value of the average

The heatmaps below now show the maximum values of the averages. As we can see, there are several days where average prices are significantly higher than on typical days.

Maximal value of the marginal value

Next, we can examine the maximum marginal value, which indicates the highest bid that was selected—and thus received the largest remuneration—for each month and block. For example, in the chart below, we see a bid that received €3,784 per MW per hour on September 16, 2025.

Although these bid levels are quite extreme, similar occurrences can be found in other countries as well. For example, as shown below, there was an aFRR up bid in the Netherlands priced at €1,789 per MW per hour for a four-hour block.

A normal day vs an extreme day

Below are screenshots from the small app (link provided). The first screenshot represents a typical day, where the average price is close to the marginal price. In these situations, the difference between marginal pricing and pay-as-bid is relatively minor.

In contrast, during peak price events—such as on April 24, 2026, shown below—the marginal price often differs significantly from the average price. This means that some selected bidders could have earned substantially more if they had been able to better predict the cleared price. However, accurately forecasting such peak price events is very challenging. During these periods, the merit order also tends to become much more convex, with prices rising sharply towards the end. It’s important to note that in Germany, only the bids that are actually selected are made public.

Link to the app

The small app, accessible via the paywall link below, includes the heatmaps, daily prices, and merit order visuals as shown above. All data are from this source.

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Previous posts on balancing

You might be interested by the previous posts that I have already written on balancing. Each of them is exploring a different aspect of the balancing world:

• Focus on European power reserves: part 1 - FCR.

• European power reserves: part 2 - aFRR (and how solar is impacting it).

• The German aFRR capacity market - a deeper look on prices.

• On Imbalance Prices.

• PICASSO: insights and data.

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Capacity overview

Generally, there are three key balancing products in Europe: FCR (Frequency Containment Reserve), aFRR (automatic Frequency Restoration Reserve), and mFRR (manual Frequency Restoration Reserve). Some countries also use a slower reserve called RR (Replacement Reserve). The key idea is that FCR responds first, acting within 30 seconds to quickly halt frequency deviations. Afterward, the other reserves step in to gradually restore overall system balance.

In general, a minimum amount of capacity for each type of reserve is procured, with most countries using capacity auctions to ensure sufficient volumes are secured. Below, you’ll find the procured volumes for a typical day in Germany. Notice that aFRR and mFRR are each represented by separate lines for upward and downward capacity, while FCR is shown as a single line, reflecting its symmetrical nature.

The proportion of procured capacity can vary significantly between countries. As shown above, aFRR capacity is predominant in Germany. In contrast, the graph below for the Netherlands highlights that mFRR capacity plays a much larger role there proportionnally. You’ll also notice four lines representing aFRR capacities. This is because TenneT procures aFRR across two time horizons: one on a daily basis and another in four-hour blocks.

From capacity to energy offered

As mentioned earlier, the main objective of capacity auctions is to ensure that there are enough energy bids available to maintain system reliability. All market participants selected in the capacity auction are required to submit energy bids that at least match the volume they were awarded. However, so-called "free bids" are also permitted, allowing additional bids to be submitted beyond the contracted volume. This explains why, as shown below, the quantity of offered energy bids can fluctuate from one quarter-hour to the next.

It’s worth noting that in certain cases and in some countries, the volume of free energy bids can far exceed the amount of procured capacity. For example, as shown below for the Netherlands, the available aFRR down energy bids are significantly higher than the contracted capacity (as illustrated by the dashed rectangle compared to the solid line).

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FCR - only capacity, no energy

FCR is somewhat different from the other reserve products, as it is considered solely a “power” product. In most countries, FCR is procured through capacity auctions only—there is no associated energy delivery. Currently, a group of nine countries organizes a joint auction for FCR capacity, allowing cross-border exchanges. This approach ensures that the most cost-effective bids are selected across the region, while also respecting specific rules, such as maintaining a minimum amount of capacity in each participating country.

Below, you can see the average FCR capacity procured in Belgium from 2023 onward, broken down by month and by four-hour blocks. The data shows that in 2023 and 2024, Belgium relied heavily on foreign FCR bids to meet its requirements, with the average volume procured domestically just around or slightly above the mandatory minimum. From 2025 onward, the proportion of FCR procured within Belgium rises steadily—a reflection of increasing competitiveness of Belgian FCR providers.

FRR balancing capacity auctions

The market for FRR (both aFRR and mFRR) balancing capacity remains largely national, with limited harmonization across European countries regarding how procurement is organized. Differences exist not only in the volumes procured—which can vary significantly from country to country—but also in several key elements of the auction process:

• The duration of the product (e.g., whether capacity is contracted for one hour, four hours, or a full day).

• The settlement mechanism, such as pay-as-bid versus pay-as-clear pricing.

• The complexity of allowable bids (single or multipart bids, technical details).

• The timing and frequency of the auctions.

• Other specific rules tailored by each national market.

Below, you’ll find an example of the merit order from an aFRR capacity auction in Belgium for a four-hour block, illustrating how bids are ranked according to price.

The results of these auctions can fluctuate significantly from day to day, and within the day. This is the case in Germany, where prices for balancing capacity often drop close to zero when there is ample availability—such as during nighttime hours for both upward and downward capacity. In contrast, prices tend to rise for upward capacity in the evening, and for downward capacity during daylight hours when solar generation is high. These price patterns generally reflect the opportunity costs faced by balancing capacity providers, who adjust their bids based on factors like renewable generation, anticipated demand, and potential earnings from alternative market activities.

It’s important to note that price dynamics for balancing capacity are not uniform across all countries. For example, in Spain, downward capacity prices tend to be very low during periods when day-ahead electricity prices are also low—such as midday in June—because renewables, particularly solar energy, contribute significantly to the available balancing capacity. In contrast, in Germany, the integration of renewables into balancing capacity markets is not yet as widespread, especially for solar. This highlights how differences in the generation mix, especially the penetration of renewables, can shape the balancing market in each country.

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TSO demand

Without going into the technical complexities of how demand is determined—a topic that is complicated in itself—here’s a simplified explanation. As its name suggests, mFRR (manual Frequency Restoration Reserve) is activated manually: the TSO must explicitly trigger a specific volume, typically for a 15-minute quarter-hour period. In contrast, aFRR (automatic Frequency Restoration Reserve) is automatic, with activation following a signal that updates every four seconds based on a controller. As a result, aFRR demand is automatically adjusted in real time, without direct intervention from the TSO.

Each TSO has its own way of activating mFRR (or even RR) and depends on the chosen balancing “philosophy” and the activation strategy. Comparing the two largest European countries, we can note:

• France utilizes a centralized and proactive balancing model managed by its single transmission system operator, RTE. The French philosophy emphasizes early TSO intervention. It is also backed by strict dual-pricing imbalance which penalize deviations leading market participants to balance their portfolios early. In such a context, France is using much more mFRR and even RR for balancing.

• Germany relies on a decentralized and reactive market-driven philosophy split across four regional TSOs. The German model pushes intraday gate closures much closer to real-time, allowing continuous commercial trading to solve discrepancies and leaving the TSOs to react only to remaining deviations. In this context, Germany relies mostly on aFRR, with very few mFRR activations.

So, each country will have at all times a particular demand for aFRR and mFRR. Let’s now explore how this demand is translated into activated energy.

aFRR - energy

Below is a graph showing the quarter-hourly aFRR energy demand (dashed lines) for both upward and downward directions. The solid lines indicate the actual activated aFRR volumes, which often diverge from the demand. This discrepancy represents the exchange of aFRR energy through the European platform PICASSO. PICASSO essentially acts as “a controller above national systems”: if a balancing demand in one country can be satisfied more cost-effectively by an energy bid from another country, the platform selects that bid, allowing the TSO to import lower-priced reserve energy from abroad. This setup promotes cross-border efficiency and helps ensure that balancing services are delivered at the lowest possible cost across participating countries.

As mentioned earlier, aFRR is managed with adjustments every 4 seconds. This means both the demand and, ultimately, the prices can fluctuate at this high frequency. Below is an example showing how aFRR prices vary in Belgium over time.

Based on these 4-second prices, TSOs calculate 15-minute average prices. The methods used to determine these averages can vary and, in some cases, are harmonized across countries. The two main approaches are a simple arithmetic average and a weighted average, typically based on the demand or the fulfilled demand during each interval.

After the paywall, I will continue the overview with a closer look at mFRR energy, the influence on imbalance prices, and other key details about the balancing market.

Thank you for reading and for your support.

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In summary, a look at historical values suggests two simultaneous trends:

• First, day-ahead market prices are becoming more volatile, largely driven by the recent surge in solar energy.

• Second, the distribution of short-term prices—particularly imbalance prices—is improving, becoming more stable and increasingly resembling the pattern seen in day-ahead markets.

However, the two trends are not developing at the same pace. Let’s have a look.

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Evolution of the day-ahead market

The graphs below display histograms of day-ahead prices for 2019 and 2024. As we can see, prices are significantly more dispersed than they were in 2019. Additionally, the pronounced peak around zero—which typically indicates a grid dominated by high renewable energy production—is almost invisible in 2019. This suggests that renewables have a much more pronounced role recently than 5 years ago1.

Recent evolution of the imbalance price in Germany

Looking now at the imbalance prices, I noticed that the trend is evolving much faster. and this is why I prefer to look at recent data. Therefore, I present below the evolution of the imbalance price for the period of January to April for the last three years (2024 to 2026).

As we can see in the histograms below, the distribution has shifted with a much clearer dual peak distributions, something that looks closer to the day-ahead distribution.

Looking at the difference

We can also examine the difference between the day-ahead price and the imbalance price. The first graph illustrates the rolling averages for the 5th–95th percentiles (light blue), 25th–75th percentiles (darker blue), and the median (red line) since the start of 2023. Two key trends emerge:

• A noticeable reduction and narrowing in the spread between percentiles, particularly evident in 2025.

• A slight seasonal volatility, with moderately increased levels during the spring months, which is especially apparent in 2024.

So, what is driving this shift, and what are the implications?
In the sections below, under paywall, I’ll share more statistics on day-ahead prices, imbalance prices, and their differences, including a graph on Belgium. I’ll also discuss the main factors behind these trends and explore the potential consequences for market participants.
Thank you for reading, and thank you in advance if you choose to upgrade your subscription.

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For more insights on PICASSO, see my previous posts:

• PICASSO insights.

• The impact of aFRR on imbalance prices: how a small, high-priced bid can have a large effect.

Imbalance price in Austria

First, the imbalance price in Austria on 18 March 2026 spiked at 3257 €/MWh at 10:15 AM during a quite uneventful day. The previous quarter-hour the price was also very high at 2623 €/MWh.

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In this post, I will introduce another interesting contradiction: Europe, despite having significantly lower solar irradiation, could—and perhaps should—export solar-generated electricity to the southern Mediterranean region, even though that region enjoys far greater solar potential.

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The initial idea

The idea is quite straightforward: the southern Mediterranean region offers some of the highest levels of solar irradiation in the world. It makes perfect sense, then, to consider installing solar panels there and importing the resulting electricity to Europe.

This idea is even more powerfully illustrated by visual representations showing that a small red square could, in theory, supply Germany’s energy needs; a slightly larger one could supply the entire European Union; and, remarkably, it would take only a modest area in the Algerian desert to generate enough power for the whole world.

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The Interconnection projects

In addition to ideas/projects like Desertec, there are several initiatives and efforts aimed at increasing interconnections between the two regions. Interestingly, when looking at how these projects have been presented—particularly in earlier years—there has been a strong emphasis on importing clean energy from the South to the North. Here is a brief review.

Regarding the planned additional interconnection between Spain and Morocco, here is a statement from a 2019 press release by the Spanish TSO:

The construction of this third link between Spain and Morocco is the natural system reinforcement that the energy transition is demanding in order to connect Europe with Africa, as it will enable the integration of renewable energy into the European system, mainly photovoltaic, derived from the ambitious solar energy development plan that Morocco has in place, which in turn will result in the reduction of the marginal price of electricity in the Spanish market.

Regarding another interconnection project, linking Greece to Egypt, it is officially stated that the cable will be bidirectional. However, the primary focus in this official communication is on importing green electricity from Egypt to Europe.

GREGY will allow 100% Renewable Energy System (RES) energy exports, contractually ensured by bespoke Power Purchasing Agreements, from Egypt to Greece and Europe, at times of high-RES generation, contributing to a significant increase of RES participation in the energy mix and reduction of CO2 emissions of the power sector.

A similar tone is taken with regards to the project of interconnection between Italy and Tunisia, from a speech of Von der Leyen:

Tunisia is looking to harness its tremendous potential for renewable energy. And the European Union needs reliable energy suppliers of clean energy as we are electrifying our entire economy. Thus, we need to invest in our infrastructure so that Tunisia can export clean energy to Europe.

Although Italy may be seen as somewhat behind other Southern European countries like Greece and Spain, it's important to recognize that the Italian grid faces significant congestion between the north and south. The southern region produces a much larger share of renewable energy relative to its electricity demand, while the more populated and industrialized north has higher consumption.

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The game changer: European solar oversupply

Because these projects require significant time to move from conception to completion, substantial changes can occur in the interim. In Europe, the most notable change of the past four years has been the rapid surge in solar energy—outpacing substantially solar in North Africa.

There are several ways to illustrate how deeply solar is already integrated into the energy mix. One clear example is shown by the average electricity prices in Germany and France for the month of April. As the data below demonstrates, average prices were negative in both countries during the middle of the afternoon, highlighting the significant dominance of solar generation during these hours.

With such widespread solar dominance, we are also witnessing a surge in negative electricity prices across virtually all European countries. These negative prices are then a signal for renewable curtailment, as producers must pay to produce.

In its December report, SolarPower Europe continues to project a very high rate of solar installations. Despite an anticipated dip in new additions for 2026 and 2027, the organization expects annual installations to remain at or above 60 GW. Therefore, this solar oversupply is likely to remain and probably intensify.

What’s the situation in the Southern Mediterranean region?

Although solar capacity is also growing in this region, the situation remains very different from the rest of Europe. Below is a snapshot of emissions on 14 May 2026 at noon. The most striking feature is the sharp contrast between the green areas of Southern European countries (such as the Iberian Peninsula, France, southern Italy, Albania, and Greece) and the brown areas of North Africa, where fossil fuel generation clearly dominates—even in the middle of a spring day.

Examining Egypt’s generation mix up to 2023, it is clear that natural gas remains by far the dominant source of electricity generation—and its share is still increasing. In contrast, solar and wind make up only a minimal portion of the mix, barely registering at the bottom of the graph.

Another example is Algeria, where nearly all electricity is generated from natural gas.

The positive news is that these countries are steadily increasing their share of renewables, particularly solar energy. This trend is evident in the growing imports of Chinese solar products. However, the volume of Chinese solar panel imports remains significantly lower than in certain European countries such as Greece and Spain, as shown below.2.

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Going North-South is not great for solar

Europe and Africa share a close north-south alignment that places them in similar time zones, resulting in a high correlation for solar generation across both continents. This correlation is not absolute, however, as seasonal variations create significant regional differences. During Europe's winter, for instance, solar production remains much higher in North Africa due to its geographic position closer to the equator. Despite these complementary seasonal shifts, a north-south interconnection is certainly less effective than an east-west interconnection, with regards to solar.

The reasons to pursue interconnection projects

Yet, these interconnection projects still make sense in my opinion. Here are two simple reasons to pursue them.

1. Efficient for reducing global emissions

One of the main reasons for installing renewables in Europe is to reduce emissions3. Since climate change is a global challenge, it simply makes sense to export Europe’s solar surplus if it can contribute to lowering emissions elsewhere. As highlighted earlier, countries in this region still rely heavily on fossil fuels for electricity generation. Exporting Europe’s solar surplus could therefore help decrease the rising levels of renewable curtailment Europe is facing, while also supporting a reduction in fossil fuel use abroad.

2. Increased export of natural gas

By reducing their local electricity generation from natural gas, these countries could free up more natural gas for export, potentially boosting their revenues4. Additionally, Europe could increase its imports of natural gas from these regions via pipeline, which is a less expensive method than importing liquefied natural gas (LNG).

In conclusion

These interconnections remain valuable, but their original purpose may have shifted over time—particularly now, as Europe sometimes experiences significant solar surpluses. In reality, countries in the Southern Mediterranean region still rely heavily on fossil fuels, while many European nations are dealing with increasing negative electricity prices, and solar curtailment.

Given this context, could North Africa become an importer of Europe’s surplus solar power?

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Here for the first part of the presentation.

2026 May Trends In European Electricity Markets Part 1

1.35MB ∙ PDF file

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The full presentation is under a paywall (32 slides in total).

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Before jumping into the topic of the post, here is a brief recap on the start of the solar season as of end April.

Part 1: day-ahead prices

With spring having started a month ago, we are now well into the solar season. As the figure below shows, solar generation in the European Union has clearly transitioned out of winter, with March production already seeing a significant increase. In fact, output in March more than doubled compared to February, marking a strong start to the season.

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Focusing on Germany, this trend becomes even more evident. Below is a chart showing solar injection in Germany, categorized by different price brackets. Several observations are noteworthy:

Although total generation did not increase significantly from March to April (with four days of data still missing), the share of solar generation injected at zero or negative prices in April is much higher than it was in March. This highlights a non-linear relationship between solar production and market prices. In particular, while large negative prices (below -10 €/MWh) were almost nonexistent in March, they account for nearly a quarter of the generation in April.

Looking at it from a different perspective, here is the combined solar value for each month. While the net value exceeded 400 million euros in March, it dropped to just 160 million euros in April (with four days still unrecorded), primarily due to the significant share of negative values.

Part 2: short-term markets

Short-term markets, including intraday and balancing, can also experience episodes of extreme negative prices. For example, during Easter Monday, we observed particularly low prices in these markets. I explained this event in this post.

In summary, we are seeing regular periods of very low prices, and these periods can sometimes last quite a while. Batteries can help absorb surplus energy during these hours, but what happens when they reach full charge? In this post, I will explore why collocating them with heat storage might be interesting.

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This is a post without paywall. Do not hesitate to share it with friends and colleagues, and potentially subscribe to support my work.

As articulated in one of the core principles described by Gregory Mankiw in the economics textbook Principles of Economics, rational decision‑making is inherently marginal in nature.

A rational decision maker takes an action if and only if the marginal benefit of the action exceeds the marginal cost.

In practice, this means that we should, as individuals or policymakers, evaluate decisions by comparing the incremental gains and incremental costs of a specific action. An action is therefore pursued only when the additional benefit it generates outweighs the additional cost it imposes.

Let’s take this principle and apply it to the question: should we add solar in the European grid?

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How will we assess that?

Two elements must be considered: first, the cost of installing solar capacity, and second, the benefits it generates. From an economic perspective, the rational decision is to stop adding incremental solar capacity once the cost of an additional megawatt exceeds the total benefits expected over the project’s lifetime.

Considering benefits, we can identify the following elements:

• Economical benefits on energy only: by how much do we reduce the overall cost of electricity generation by adding an additional MW of solar?

• Ecological benefits: how much CO₂ do we avoid emitting by adding an extra MW of solar1? One should also include the avoided cost of other pollutants, which is particularly relevant in countries still heavily reliant on coal, for example.

• Geopolitical benefit: by producing more energy domestically, we reduce dependence on foreign suppliers, which is certainly highly valuable in the current context.

One could also cite other benefits, such as employment creation. Furthermore, a few remarks:

• In Europe, ecological benefits—at least regarding emissions reduction—have been largely internalized through the CO₂ emission trading system. There is an explicit additional cost associated with producing electricity from fossil fuels.

• Both ecological and geopolitical considerations can be summarized as a “preference premium” that society may be willing to pay to favor solar over importing and burning fossil fuels.

Will the cost continue to decline?

I have discussed this question in a post two years ago. Basically, my conclusion was:

Solar has experienced one of the most incredible price declines of any physical goods. We are now at a high level of maturity in the manufacturing of modules as well as in solar project developments, resulting in most probably only incremental changes. This will translate into a one-third reduction of LCOE for large solar projects in one decade, a good achievement but not as impressive as the last decade.

Looking at the latest Lazard review of LCOE, we can clearly see that the LCOE of solar is not necessarily going down in the recent years. It is safe to say that we are at a point where solar projects will not continue to decrease significantly, mainly due to the fact that there are a variety of costs beyond the solar cells that are much less compressible.

Let’s now look at the other side of the coin: the value of solar.

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The (fast) declining value

As most readers of this post are already aware, the value of solar generation has been declining rapidly in recent years. In particular, solar capture rates are converging toward 50% in several European countries2. The figure below, from Lion Hirth, illustrates the evolution of the solar capture rate in Germany, with the most recent observation for 2025 standing at around 50%. I also refer to my previous post on an update of solar capture rate.

To be clear, that trend is present in almost all European countries as we can see in the graph below.

Another way to illustrate the declining value of solar is to examine the price levels at which solar generation occurs. The figure below shows solar injections into the grid distributed across price categories. It highlights the growing share of solar generation occurring during low‑price—and increasingly negative‑price—periods, reflecting the correlation between solar output and periods of system-wide surplus. This shift further underlines the erosion of the market value of solar as penetration levels increase.

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A simple model

These figures are informative at the level of the overall solar fleet. However, they do not answer the key question: what is the marginal value of adding one additional megawatt of solar capacity?

In practice, adding capacity does not only generate revenue for the new unit itself; it can also depress prices and thereby reduce the value of electricity produced by the existing solar fleet. As a result, the economic value of an additional megawatt cannot be approximated by the capture rate observed at the current level of installed capacity.

To formalise this idea, suppose that the solar capture rate Cr​ declines as a function of the solar market share x (x-axis of Hirth’s graph). If we assume a roughly linear relationship—an approximation broadly consistent with the stylized relationship shown in Hirth’s analysis—we can write:

Assuming that the total economic value (Ev) is simply the capture rate multiplied by the solar market share (in %), the total generation (P) and the baseload price (π), we obtained that:

Now, replacing that in the first formula, we have the following formula.

If you remember your math course from high school, you will directly notice that this equation will attain a maximum value equal to:

As an example only, and taking numbers from here, we can consider A to be 1.2 and B to be 3.9. In such a case, the maximal value is reached for 15.4%, which is still above of the European Union in 2025 (about 11.2%), but below some individual European countries. It also shows why the maximal theoretical value is much large for wind3.

Of course, this is way too simplistic, but yet, it is interesting in order to illustrate the phenomena4. In any case, it would also look a bit theoretical, so, hereunder I will make it a bit more concrete.

A simple calculation

In 2024, total solar generation in Germany amounted to 59.7 TWh, corresponding to a total economic value of €2,756 million. This implies a solar capture price of €46.1/MWh and a capture rate of 59%, given an average wholesale price of €78.4/MWh. In 2025, solar generation increased to 70.4 TWh, with a total economic value of €3,246 million. The capture price remained broadly unchanged at €46/MWh, but the capture rate declined to 51.6%, as the average market price rose to €89.3/MWh.

At first glance, one might conclude that the increase in installed solar capacity translated into a higher economic value in 2025. However, this interpretation can be misleading. A large share of the increase in total value is driven by the rise in average wholesale prices rather than by an improvement in the intrinsic value of solar generation.

To illustrate this, assume counterfactually that the capture rate in 2025 remained unchanged but the average market price had stayed at its 2024 level of €78.4/MWh. Under this assumption, the total economic value of solar generation in 2025 would have been approximately €2,850 million—only marginally higher than in 2024. Given an estimated increase in installed capacity of 12 GW, this implies an added economic value of roughly €8.3 million per additional gigawatt per year, or about €0.0083 per watt and per year. This figure approximates the marginal economic benefit of additional solar capacity under these conditions.

The marginal economic benefit of adding new solar capacity therefore appears to be low. Looking ahead, it is conceivable that total solar value could reach a maximum, beyond which additional installations would actually reduce the aggregate economic value of all solar generation by further depressing prices during peak production hours.

That said, the relationship between installed capacity and capture rate is unlikely to be strictly linear. The decline in capture rates could eventually slow or plateau, in which case total economic value might stabilise rather than peak and decline5. Even under such a scenario, however, the core conclusion remains unchanged: the marginal value of additional solar capacity is already low, reflecting the fact that power systems in several countries are now at a relatively advanced stage of solar penetration.

Marginal cost > marginal economic benefit

Although the methodology used above is deliberately simple—a back‑of‑the‑envelope calculation—it is nonetheless informative for understanding orders of magnitude. Turning now to the cost side, we can form a rough estimate of the marginal cost of adding solar capacity.

Assuming an installed CAPEX of around €1/W and annualizing this investment in a very simplistic and imprecise way, this corresponds to an annual cost on the order of €0.1/W per year6. This figure can be interpreted as the marginal cost of adding one additional watt of solar capacity.

Strikingly, this rough marginal cost estimate is an order of magnitude higher than the marginal economic benefit estimated above. While highly simplified, this comparison strongly suggests that, at current penetration levels, additional solar capacity delivers limited incremental economic value relative to its cost.

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Not the end of the story for solar

Although adding solar capacity is unlikely to make much economic sense when assessed solely through its value in the day‑ahead wholesale market, this does not imply that further solar deployment is necessarily unjustified. There remain compelling reasons to continue expanding solar capacity, depending on the perspective adopted.

From the viewpoint of individual consumers, solar can still be economically attractive. This is largely because retail electricity prices include cost components—such as network tariffs, levies, and taxes—that are not reflected in wholesale market prices. By self‑consuming solar generation, households or businesses can avoid part of these charges, allowing solar investments to remain privately profitable even when their system‑wide economic value is low.

From a societal perspective, there are also strong arguments in favor of continued solar expansion. As discussed earlier, solar contributes to decarbonization objectives, reduces exposure to fossil fuel price volatility, and improves energy security by lowering dependence on imported fuels. These ecological and geopolitical benefits are not fully captured by market prices, yet they remain central to public policy considerations.

The consumer view

For consumers who face fixed network charges, levies, or taxes—often calculated on a per‑kilowatt‑hour basis—there is almost always a strong incentive to maximise self‑consumption of locally generated solar electricity, at least up to the level of their own demand. By consuming their own production, these consumers avoid paying grid‑related charges on electricity drawn from the network, thereby reducing their total energy bill7.

Once self‑consumption reaches the level of the consumer’s typical load profile and generation exceeds on‑site demand, the situation changes. Excess electricity must either be stored—most commonly via home batteries—or exported to the grid. Both options entail additional costs and constraints. Battery storage requires further capital investment and comes with efficiency losses, while grid injection is often remunerated at low prices and may be subject to fees or regulatory limitations.

As a result, the marginal financial benefit to the consumer declines sharply beyond their own consumption needs, making investments in additional solar capacity, batteries, or systematic grid injection significantly less attractive from a private business‑case perspective.

The societal view: lowering energy dependance

For policymakers, there are compelling reasons to continue promoting the expansion of solar energy, foremost among them the reduction of dependence on fossil fuels. This consideration is particularly important for European countries, which import a large share of their fossil energy needs—more than 80% of oil consumption and roughly 60% of natural gas, according to recent estimates. Reducing this reliance not only supports climate objectives but also enhances energy security, limits exposure to volatile global commodity markets, and mitigates the geopolitical risks associated with energy imports.

However, these benefits must be weighed against a growing system‑level challenge. As solar penetration increases, periods of very low or even negative electricity prices become more frequent. During such episodes, the power system increasingly requires the curtailment of other generation sources, including assets that may be more flexible or system‑relevant. As a result, additional solar capacity does not necessarily translate one‑for‑one into lower fossil fuel generation.

If curtailment becomes widespread, the marginal contribution of new solar capacity to emissions reductions may diminish sharply and, in extreme cases, approach zero. This highlights a fundamental policy trade‑off: while solar remains essential to the energy transition, its system value increasingly depends on complementary investments in flexibility, storage, grid reinforcement, and market design. Ensuring that further solar deployment continues to deliver genuine decarbonization and energy‑security benefits therefore requires careful calibration of incentives, grid integration strategies, and market mechanisms.

Will solar + batteries make the difference ?

Finally, one could wonder if batteries will not be the game changer. Indeed, batteries can increase significantly the economical benefits of solar. By shifting generation from low‑price to higher‑price periods, storage can increase the marginal benefit of solar by improving capture rates and reducing curtailment. However, this comes with an increased marginal cost, as batteries require additional capital investment, incur efficiency losses, and have finite lifetimes. The net effect therefore depends on the balance between these two forces, balance that is highly location‑specific: countries with a more even distribution of solar production throughout the year and limited seasonal concentration are generally better suited for battery deployment, as storage assets can cycle more frequently—often daily—thereby improving their economics relative to systems with strong seasonal solar variability.

Potentially, solar can increasingly be dispatchable or “baseload” as Ember indicated in a recent study.

In conclusion

In Europe—and in several other regions of the world—solar deployment has now reached a level at which it is no longer obvious that the economic value added by new solar capacity keeps pace with the marginal cost of adding solar. While the cost of solar is unlikely to continue falling substantially, its marginal benefits are likely to decline further as penetration increases, capture rates fall, and curtailment becomes more widespread.

Battery storage may partially restore the value of additional solar capacity by shifting generation toward higher‑value hours and reducing curtailment. However, this comes at the cost of higher marginal system costs. Where the equilibrium ultimately lies remains uncertain and is likely to be highly location‑specific.

In any case, it is important to remind that beyond pure market value, solar continues to deliver other benefits, notably in terms of emissions reductions and enhanced energy independence—considerations that remain central to public policy.

Finally, it should be noted that, in a context of declining marginal benefits, keeping costs as low as possible becomes critical, which strongly argues in favor of prioritizing utility‑scale solar deployment, over rooftop solar, but this debate is potentially for another post!

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Given that daytime electricity demand across Europe sometimes still stays below 250 GW, adding several tens of gigawatts of new solar each year is far from insignificant. Solar oversupply has become a persistent feature of the energy landscape, and all signs point to its continued presence in the years ahead.

However, in this post, I am not focusing on the issue of general “solar oversupply.” Instead, I want to explore the specific challenges that arise when an oversupply is not accurately predicted—when several gigawatts of unexpected solar generation exceed the day-ahead forecasts, and lead to extreme price drops, sometimes plunging into four-digit negative territory in the intraday and balancing markets.

A clear example of this occurred in several countries on Easter Monday, as I described in my previous post.

For this post, I have identified six key risks that, in my view, play an important role when assessing the likelihood of encountering these extreme oversupply situations. It’s important to highlight that the effects are not linear—once certain thresholds are crossed, the system can experience dramatic drops in prices, as witnessed during Easter. This illustrates the presence of tail risk: while such events might seem rare, their impact can be disproportionately severe when multiple risk factors align.

These tail risks could create substantial challenges—and opportunities—that market participants should be prepared to hedge against or potentially capitalize on.

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I will start by examining the major negative price event that occurred in Belgium, Austria, and Germany. Afterwards, I will discuss the positive price spike seen in France. For each case, I’ll explore the underlying root causes that drove these market phenomena1.

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A quick view of the day-ahead prices

Before looking at the imbalance prices, let’s first take a look at the day-ahead prices. As anticipated, these were exceptionally low, driven by reduced demand over the Easter period and mild temperatures. On top of that, both solar and wind generation were strong throughout the weekend, further pushing day-ahead prices down.

Below, you can see the level of “clean” generation—solar, wind, hydro, and nuclear—that was available on Sunday, 5 April and Monday, 6 April across the European Union. At certain points, the combined output from these sources nearly matched total electricity demand.

As a direct consequence, power prices dropped significantly, as illustrated by the two maps showing the average day-ahead prices. Notably, several countries—including France and Germany—experienced average prices that were negative throughout Sunday.

If we look at the most dramatic moment, on 5 April at 2 PM, we got negative prices of -114.5 €/MWh in Germany and even -210.5 €/MWh in Poland.

Sunnier than expected

At these price levels, a significant share of downward flexibility—such as the ability to absorb additional power when solar generation is underestimated—had already been utilized in the day-ahead markets. This situation is reflected in the balancing capacity prices, which reached 66 €/MW/h for both aFRR and mFRR Down in Germany during the afternoon block from 12 PM to 4 PM (source). Additionally, FCR prices stood at 61 €/MW/h for the same period.

With limited downward flexibility available, any new downward need in the balancing timeframe is met with sharply negative prices, a trend that also extends to the intraday markets.

In Belgium, solar production exceeded expectations, further intensifying this effect. On April 6th, for example, actual solar generation was up to 1.5 GW higher than the day-ahead forecast, as shown by the gap between the orange (measured) and grey (forecasted in day-ahead) curves in the graph below.

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Extreme negative imbalance price in Belgium

Let’s now turn to the extreme downward prices observed. The most pronounced situation occurred in Belgium, where the imbalance price plummeted to the minimum possible value of -15,000 €/MWh for five consecutive quarter-hours. This is unprecedented in Belgium and likely rare across other countries as well.

This event did not occur in isolation—other countries in the region, including Germany, Austria, and the Netherlands, also experienced similar, though less extreme, episodes of exceptionally low prices. These extreme price drops were primarily the result of mFRR down activations. Additionally, as we’ll explore later, aFRR activation also led to extremely low prices, although this effect was brief in comparison.

By contrast, on the day before, France recorded a quarter-hour with a very high positive imbalance price.

I’ll discuss the causes and implications of these events in the following section, available behind the paywall.

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Before reviewing mFRR capacity, here below is a link to previous posts on balancing capacity markets:

• The German aFRR capacity market - a deeper look on prices

• Updates on FCR prices

• European power reserves: part 2 - aFRR (and how solar is impacting it)

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A gradual reduction of mFRR capacity

It is interesting to note that the quantity of mFRR capacity in Germany has declined significantly over the past 15 years. In the chart below, the tendered volumes for mFRR downward (in yellow) and upward (in orange) are presented. Up until 2016/2017, mFRR capacity was roughly on par with aFRR capacity. However, today, mFRR capacity represents only a little more than a quarter of the upward aFRR capacity and about a fifth of the downward aFRR capacity, highlighting a clear shift towards aFRR in the German balancing market.

The chart below displays the volumes procured during a recent 24-hour period: aFRR volumes are shown in green, while mFRR volumes appear in blue. As we can see, aFRR volumes are considerably higher than those for mFRR. Additionally, the procurement volumes change in 4-hour blocks.

This strong preference for aFRR capacity over mFRR capacity is not observed in all countries. In fact, some countries prefer to procure significantly more mFRR capacity, or even opt for Replacement Reserve (RR). The variations in balancing capacity approaches across Europe will be explored in an upcoming post.

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The current market in 2025

In 2025, the total market value reached €60.9 million, with €35.6 million allocated to negative mFRR capacity and €25.3 million to positive mFRR capacity. The distribution, shown below, highlights a distinct seasonal pattern that differs between upward and downward capacity.

Downward capacity

During the winter months (November to February), downward capacity prices were extremely low, indicating ample availability for downward balancing. It’s not uncommon for the average cost of mFRR down capacity to be around 1 €/MW/h during this period.

As spring approaches, downward balancing becomes more expensive; there are often only limited options to further reduce generation since many conventional providers are already operating at minimum output or may not be running at all. In some situations, it can make economic sense for generators to accept losses from producing energy—by not fully recovering their costs—but offset these losses with higher revenues from offering balancing capacity. As a result, prices for downward balancing capacity rise.

Interestingly, the graph shows that July had lower downward capacity prices compared to other sunny months. This aligns with the observation that solar capture rates were unusually high in July.

Upward capacity

For upward capacity, the distribution remains relatively stable throughout the year. Typically, upward capacity prices increase during periods with high generation prices (peak periods), reflecting the fact that most generators are already operating and there is less available capacity for upward balancing. While the monthly distribution appears stable, there are still significant variations at the hourly level.

After the paywall, we will take a closer look at how prices are distributed throughout the day and across different months. We will also examine examples of merit order curves for these capacity auctions, with a focus on the extreme days, when prices were significantly higher.

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• From ENTSOE.

• From a former post.

• From next-kraftwerke.

In this post, I will focus on recent developments in the FCR market across the nine countries that participate in the common market. It’s worth noting that, with a demand of 1,700 MW in 2026 for these countries and an assumed average price of €60 per MW per four-hour block, the annual market size is estimated to be around €220 million.

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The demand

Let’s start by looking at demand. Each country has a specific FCR requirement—the total quantity that must be fulfilled. Below, you’ll find the projected demand for 2026. The demand remains relatively consistent across the different blocks, each representing a four-hour segment of the day.

In the table below, the first column shows each country’s FCR demand, alongside the core share—the minimum volume that must be covered by local bids—and the export limits, which indicate the maximum portion of local bids that can be exported to other countries. As you can see, France and Germany are the major players in the FCR market, together accounting for more than 70% of the total demand.

For reference, the figures below present the same information for 2025. Both the overall demand and its distribution have increased from 2025 to 2026. Notably, France’s demand rose from 486 MW in 2025 to 610 MW in 2026. Additionally, the export limit increased from 145 MW to 183 MW, meaning that up to 793 MW of local French bids could potentially be procured in 2026, compared to only 631 MW in 2025.

General overview of the results

Looking at the overall results, we observe the following trends. The first graph presents the average yearly volumes selected locally, while the second graph shows the average prices. Notably, France has seen an increase in selected volumes from 2022 to 2025, whereas Germany’s volumes have decreased during the same period.

In terms of prices, France has experienced lower FCR prices over the past three years, particularly in 2024. In contrast, Belgium saw elevated prices in both 2023 and 2024, while the Netherlands experienced high prices in 2023 and again in 2025. For the Netherlands, it’s worth noting that the average was influenced by a few instances of exceptionally high prices, which will be discussed later in this post.

Below is the rolling average for the selected countries (the Netherlands has been excluded due to a few extreme price spikes, as well as Denmark and Slovenia, given their low demand). The data shows periods where prices converge across countries and others where significant differences persist, particularly for Czechia and Belgium. Additionally, it is clear that France has consistently maintained lower prices over a relatively long period.

Focusing on France and Germany, we can clearly observe that prices often converged in 2022, but began to diverge significantly from 2023 through the end of 2025. In 2026, prices appear to be converging again, likely due to the increased demand in France and higher export limits, which allow more French local bids to be selected. Other contributing factors may include changes in neighboring countries, which will be discussed further in the following sections.

After the paywall, I’ll provide a more detailed analysis of prices and selected volumes for each country—Germany, France, Belgium, Switzerland, and the Netherlands. Additionally, I’ll showcase examples of the merit order on specific days, highlighting instances of inelasticity that occasionally occur in the FCR market.

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On 11 March, France saw several quarter-hours with low imbalance prices, including three periods—at 10:00 AM, 10:30 AM, and 10:45 AM—when prices dropped below -200 €/MWh.

When examining the volumes, we observe rising imbalances during these periods, indicating an increased need for downward regulation.

As I described in my previous posts, on Picasso and on imbalance prices, there is a strong link between aFRR prices and the resulting imbalance prices. In this post, I will illustrate how a single (rather small) aFRR energy bid can significantly influence aFRR activation prices—and by extension, imbalance prices. Understanding this dynamic is important, as it highlights how large imbalance prices can arise and potentially have an influence on trading strategies, whether for hedging against imbalance risk or for taking advantage of price movements.

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Special note: for this post, I used extensively screenshots from balancing.services. It is a great resource for having a clear overview of the European balancing world.

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This year is no exception, as can already be seen in the data from a week in March: each day, solar generation in Germany exceeded 40 GW, while midday residual load fluctuated between 7 and 20 GW. These low residual load levels exert considerable downward pressure on prices, and showing the characteristic “duck curve” pattern.

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In this post, I use normalized prices to enable better year-on-year comparisons. Prices are normalized by dividing each value by the average price of the period under consideration, so that the mean of the normalized prices equals one.

Germany by season

I have divided the curves by season, as the differences between them are significant. Each season spans three months: fall covers September to November, spring is from March to May, summer runs from June to August, and winter extends from December of the previous year through February. For example, Winter 2026 refers to the period from December 2025 to February 2026. The four seasonal curves are shown below.

• For fall, there has been almost no change over the past three years.

• For winter, there is very little variation, and the lowest prices occur during the night. This contrasts with fall, where low prices are observed both at night and around midday.

• In spring, the changes have been significant each year, with the average in 2025 approaching zero at midday.

• In summer, the dip becomes more pronounced—shaped more like a U than a V for the low-price hours. The change between 2024 and 2025 was relatively minor, partly due to lower-than-usual solar irradiation in July.

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What about Sundays?

Sundays are the most challenging days because overall electricity demand is much lower, making the impact of solar generation proportionally much greater. In Germany, Sunday load levels are typically 10 to 15 GW lower than on weekdays. The data shows the following:

• Unlike the curves for all days, the duck curve is already clearly visible in fall.

• In winter, the influence of solar on Sundays is very limited.

• In spring, the impact of solar is significant, with average prices often turning negative, and the effect has increased each year.

• In summer, the general pattern has remained similar from year to year, although extreme negative prices—such as the record low of -500 €/MWh on July 2, 2023—can have a disproportionate effect on the averages.

Behind the paywall, I will present duck curves for five additional countries, along with heatmaps of average day-ahead prices across several European nations.

Thank you for reading. If you enjoyed this post, please consider subscribing or upgrading to a paid subscription to access all articles in full.

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On the first of March, we observe a large negative imbalance price of -1474 €/MWh for one quarter-hour. Even though the impact is probably limited as it only lasted one quarter-hour, it is interesting to show the underlying reasons behind this price.

This is the imbalance price in question.

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Generally, we observe increased activity in the continuous intraday market as participants try to avoid such events. However, this was not the case at that particular moment, suggesting that the spike in the imbalance price was both sudden and relatively unexpected.

So, what were the reasons for such low imbalance prices during that quarter-hour? Let’s find out.

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In this post, I will unpack some principles behind imbalance prices and highlighting how they are calculated in Germany and Belgium. Although many of these mechanisms share common roots, practices are far from harmonized.

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Why do we need an imbalance price? What’s the objective of the imbalance price?

In simple terms, the imbalance price is the financial bridge between the planned energy market and the physical reality of the power grid. Practically speaking, the imbalance price is designed to be a corrective signal. It must be expensive enough that market participants prefer to balance themselves rather than rely on the TSO.

Now, let’s consider three different situations and check how the imbalance price can actually influence the market actor behaviors.

• First, let’s consider that the imbalance price is set at the Day-Ahead market price. In such case, the financial incentive for a BRP to maintain a balanced portfolio effectively disappears. In this scenario, the power grid is treated like a risk-free storage unit. Because there is no penalty for deviating from a schedule, market participants have little reason to invest in forecasting tools or flexible assets. This leads to “moral hazard,” where BRPs allow their imbalances to grow. Ultimately, the actual costs of balancing the system are not reflected in the price, leading to a loss of market efficiency and increased socialized costs for the end consumer.

• Secondly, let’s now consider that the imbalance price is set at a very punitive level. In such as case, it creates a climate of extreme risk aversion that can distort market behavior. BRPs, fearing astronomical penalties, will likely “over-hedge” their positions or procure excessive reserves to ensure they never fall short. While this might seem beneficial for grid security, it drives up operational costs significantly. These high risk premiums are eventually passed down to consumers, making electricity unnecessarily expensive. Furthermore, a hyper-punitive environment can reduce competition by creating a high barrier to entry for smaller players or renewable energy companies that naturally face higher volatility in their production schedules.

• Thirdly, we consider an imbalance price that is advantageous in only one direction—for instance, being cheap when a BRP is short. In such as case, the imbalance price triggers strategic gaming of the system. If the cost of being short is lower than the price of buying energy on the spot market, BRPs will intentionally under-buy energy to capitalize on the price difference. This creates an asymmetric incentive where participants prioritize their own profit over the physical stability of the grid.

These examples illustrate how the imbalance price can shape market behavior. Ultimately, it comes down to striking the right balance between competing trade-offs in order to create effective incentives.

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Single or dual price?

In general, a balancing market can operate under either a single‑price system or a dual‑price system. Under a single‑price system, the imbalance price is the same whether the BRP has a negative imbalance (i.e., it is short and needs energy, resulting in a payment from the BRP to the TSO) or a positive imbalance (i.e., it has a surplus of energy, resulting in a payment from the TSO to the BRP).

Countries typically fall into one of three categories:

• Single‑price systems,

• Full dual‑price systems,

• Hybrid systems, where the market switches between single and dual pricing depending on system conditions, such as the Netherlands.

For example, here below, you can see the evolution of the imbalance prices for a day in several countries: Germany, Spain, and Switzerland (before 2026)1.

Single-price

Dual-price

Interestingly, for BRPs, the difference between the two pricing systems is significant. The wider the gap between the two imbalance prices, the more potentially punitive the system becomes. Consider the Swiss example shown above: for most of the daytime period (roughly 9 AM to 6 PM), the positive imbalance price was negative, while the negative imbalance price hovered around 150 €/MWh. In practice, this means:

• A BRP with a positive imbalance (surplus) would have received a negative amount—in other words, it would pay the TSO for injecting extra energy into the system.

• A BRP with a negative imbalance (shortage) would also pay the TSO to cover its missing energy.

Such a price difference for positive and negative imbalance prices incentivizes the creation of larger BRPs or portfolios: two small BRPs with opposite imbalance positions would benefit by netting their imbalances internally and avoiding these penalties. This portfolio effect largely disappears in a single‑price system, where positive and negative imbalances are valued equally.

The various elements that might exist

As mentioned above, the imbalance price should incentivize the BRP to act to restore their imbalance (and in some countries2, go even beyond, and create an opposite imbalance if it can help the system). Therefore, in general, there is a connection between the balancing energy prices (the prices that TSO pay to activate and restore the balance) and the imbalance price. Nevertheless, this is only a general principle and in practice, we have as many declinations as there are countries in Europe. The principal questions are:

• Balancing activation prices: Is the imbalance price directly linked to the prices of activated bids? And if yes, how do we consider them (average, weighted average, marginal)? Are both upward and downward activation prices included, or only the marginal activation in the direction of system need?

• Scarcity pricing: Are there uplift components that increase the imbalance price when the system is tight?

• Is there a dual‑price or single‑price framework? Are positive and negative imbalances settled at the same price or at two different prices ?

• Cross-border effect: In countries participating in international balancing platforms (MARI, PICASSO), do foreign activations influence the domestic imbalance price?

• Volume-based component: Does the magnitude of system imbalance influence the price (e.g., non-linear ramps, penalties, or volume thresholds)?

• Intraday price: is there a link with the intraday market?

After the paywall, I will go into more details about the German and Belgian imbalance prices, especially how they are calculated and how they compared to day-ahead prices in 2025.

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What are TBs?

The hourly TB spread is defined as the difference between the single highest and single lowest hourly electricity prices within a 24-hour period. This metric can be used to quantify the maximum theoretical revenue a one-hour duration battery can generate by "buying low" (charging during the cheapest hour) and "selling high" (discharging during the most expensive hour).

Here in this post, I am defining TB1, as the difference between the highest and the lowest price, then TB2, as the difference between the second highest and second lowest, etc. It should be noted that this could differ from another definition of TB2, being the difference between the two highest hours - the two lowest hours (actually the sum of my definition of TB1 and TB2). As always, Modo has great content for explaining what are TBs.

Also, in this post, I am using 30-days rolling averages as I believe that they can capture best the seasonal behavior while not being impact too much by peaks at some days that make the plots unreadable.

1. Germany

Let’s start with Germany. First, we show the graph of the rolling average of the cheapest price per day (blue curve) and the highest price per day (red curve). In-between, it is the spread.

We can clearly see that the best spreads were attained during the energy crisis, up to 300 €/MWh supported by very high prices, up to 600 €/MWh.

The second graph shows the the different TB (as defined earlier in the text). As we can see, they are closely linked together.

Below is the annual average of the TBs for each year. The year 2022 was particularly strong in this regard. In the more recent years, TB1 has remained above 100 €/MWh, with TB2 not far behind. As mentioned earlier, such spreads—excluding grid costs—could be an indicator for battery energy storage systems (BESS). For example, an ideal 2-hour storage system could theoretically achieve 350 cycles at spreads of 120 €/MWh and 100 €/MWh, resulting in an annual revenue of around €77,0001. Of course, adding losses, battery degradation, and especially grid costs2, this revenue can significantly be reduced.

Since 2023, we have observed a rise in spreads on the day-ahead markets, largely driven by the growth in solar generation. As more solar capacity is still being added3, it is likely that these spreads will continue to increase through 2026 and probably into 2027. However, over time, I expect that the expansion of storage solutions, greater flexibility—including demand-side measures—and a potential slowdown in new solar installations will eventually reverse this trend. Additionally, the evolution of spreads will be strongly influenced by natural gas prices and CO2 emission costs.

Under the paywall, I will present similar plots for 6 other European countries4 (Belgium, France, Spain, Finland, Greece, and Hungary), as well a comparison between countries.

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Let’s have a look.

France as a superpower for electricity export

In 2025, France acted as a major exporter for Europe. Although it occasionally imported electricity on certain borders, it remained a net exporter nearly 99% of the time2.

France’s exports do not only benefit its immediate neighbors. In 2025, 15% of French electricity exports supplied non‑bordering countries3.

Looking at Europe as a whole, the scale of French exports becomes striking: France exported 92.5 TWh out of 547 TWh produced in 2025—meaning that 17% of all electricity generated was exported. This volume exceeds the entire annual electricity consumption of Belgium or Switzerland, and France exported almost as much electricity as all other European exporters combined. Unsurprisingly, such abundant low‑carbon supply, coupled with relatively modest domestic demand, results in French wholesale prices being among the lowest in Europe, surpassed only by some regions of the Nordic countries.

How is electricity produced in France?

In 2025, France generated roughly 547 TWh of electricity with an exceptionally clean mix dominated by low‑carbon sources. Nuclear power remained the backbone of the system, providing about 70% of total output and returning to near pre‑crisis production levels. Hydropower accounted for around 11%, reverting to its long‑term average after an unusually high year in 2024. Wind contributed roughly 9%, though performance was constrained by the lowest capacity factor in a decade due to weak wind conditions. Solar reached about 6% and delivered the strongest growth thanks to continued capacity expansion and favorable sunlight conditions. Fossil fuels supplied less than 5% of total electricity, underscoring France’s status as one of Europe’s cleanest and most reliable power producers in 2025.

The exceptional French mix can also be seen in the emission map here below. Only Nordics country, Switzerland and Albania have a carbon intensity below 100 gCO2eq/kwh, according to electricity maps.

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How were the day-ahead prices?

Before examining prices, it’s essential to understand the demand side. In 2025, electricity consumption in France remained broadly stable relative to the previous year, reaching 451 TWh (+0.4% vs. 2024). After the sharp declines triggered by the 2022–2023 energy crisis, the downward trend halted in 2024. Nevertheless, demand in 2025 remains roughly 6% below pre‑crisis levels (2014–2019).

In this context of persistently subdued demand and abundant low‑marginal‑cost generation (nuclear, hydro, wind, and solar), wholesale electricity prices have stayed depressed—indeed, lower than in any neighboring country.

Of course, these figures reflect an annual average, and the monthly pattern reveals substantial volatility. The contrast between winter and spring is particularly striking: prices fell sharply from over 120 €/MWh in February to around 20 €/MWh in May. As we will discuss later, this abrupt drop has significant implications for the capture prices of all generation technologies.

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Nuclear in 2025

Nuclear generation rose to 373 TWh in 2025, recovering to near‑2019 levels due to better reactor availability. At the same time, operating patterns shifted: reactors now reduce output more often during midday in spring and summer, instead of mainly at night or on weekends as in the past.

Hereunder, we can see the production levels of nuclear, as well as the corresponding economic value. First graph is hour by hour.

The second graph presents the same information but aggregated on a monthly basis. As expected, the economic value—expressed in k€ per hour—is significantly higher in February than in the months from April to June or in September. This pattern directly reflects the decline in average day‑ahead prices shown earlier, with winter months benefiting from much stronger price signals than the rest of the year.

We can also look at average hourly nuclear generation by season. While the data clearly shows that modulation occurs, its impact appears much more modest when viewed through seasonal averages. Here is the EDF report on modulation in case you have missed it.

Finally, we examine the relationship between nuclear generation and day‑ahead prices using a scatter plot. The y‑axis shows the hourly average day‑ahead price in France, while the x‑axis represents nuclear output. The points are color‑coded by solar generation to indicate the level of solar production at each interval. As expected, nuclear output is reduced primarily during low‑price periods—precisely those hours that coincide with high solar generation.

After the paywall, I will present detailed data on solar and wind generation in France for 2025, explore a bit forward price projections, examine the rise of negative prices, and discuss several aspects of balancing operations in the French power system.

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In this one, I will present some of the latest data on the occurrence of negative-price hours, explain the key factors behind the trend, and outline why I believe negative prices will continue to appear—though likely to be more moderate in values.

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The leaderboard

Below is the number of hours with negative prices in the day‑ahead market for selected countries. Since 1 October 2025, the day-ahead market has switched to quarter‑hourly intervals, so each quarter hour is counted as 0.25 hours.

As shown in the data, negative prices were almost nonexistent in 2022 during the energy crisis. They began to appear more frequently in 2023, with Finland leading all European bidding zones. The trend accelerated significantly in 2024: several countries, such as France, saw a doubling of negative-price hours, while others—like Greece—experienced them for the first time. In fact, 2024 recorded the highest number of negative hours ever observed, with more than 700 hours, representing over 8% of the year.

The trend continued in 2025, although it moderated somewhat in the Nordic countries. Spain, for example, reached a similar level of negative-price hours (6.3% of the time) than Germany. Even Poland and Greece saw further increases, confirming that this has become truly a continent‑wide phenomenon.

Focus on Spain

Let’s now turn to a country that entered the world of negative prices somewhat later. In 2023, Spain recorded no negative‑price hours, yet by 2025 it had reached levels comparable to many other European markets. Moreover, at the time of writing, the Iberian Peninsula (Spain and Portugal) is actually leading the pack in terms of negative‑price occurrence.

It is also insightful to look not only at the number of negative‑price hours, but at their value. The chart below shows the cumulative value in €/MWh—meaning that instead of simply counting occurrences, we sum all negative prices together. Dividing this total by the number of negative‑price hours gives an average value of –2.1 €/MWh in 2025, which, as we will see later, is significantly lower than in many other countries.

As we can see, negative‑price hours appeared very early this year. This was driven by a combination of persistently strong wind conditions and an exceptionally favorable hydrological year.

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This situation has led to a sharp drop in day‑ahead prices, with extended periods hovering close to zero. For example, during the week of 9–15 February, the average day‑ahead price was just 6.2 €/MWh (and 2.2 €/MWh in Portugal). With wind generation running at very high levels and hydro plants obliged to produce (as further water retention is limited), prices dropped accordingly, resulting in extremely low price levels.

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Focus on Finland

Turning to Finland—the country that recorded the highest number of negative‑price hours in 2024—we observe a very different pattern. In many European markets, negative prices are heavily concentrated in the spring months, when solar output is strong and demand is seasonally low (as is the case in Spain, where spring effectively begins earlier). By contrast, Finland experienced negative prices throughout the entire year in 2024, with particularly notable occurrences even in October, well outside the typical seasonal window.

Looking at a particular week in October 2024, we can see that the load was mostly met by wind, nuclear and hydro. At the start of the week, wind was absent, and we can see a broad range of other power plants compensating, from increased hydro and biomass to gas and even peat, with prices jumping much higher. Furthermore, solar had virtually no impact in such a week. In terms of average value per negative hours, it has been -1.8 and -1.3 €/MWh respectively for 2024 and 2025, which are really moderate compared to Germany, for example.

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Focus on Germany

As we can clearly see, most of the negative hours are gained in spring, starting early April and being strong afterwards until fall. In 2025, interestingly, 47% of all hours with negative prices happened in May and June only. That means that 18.4% of all hours of these two months exhibit a negative price, truly a remarkable feature.

Going to the value, we can observe that the value is going much lower than in Spain and in the Nordics for example. The average negative price has been -12.9 €/MWh in 2023, and has reduced after, to -11.5 €/MWh in 2024 and -10.9 €/MWh in 2025.

These values are generally due to specific large events, such as this one on Sunday 11 May 2025.

So, why do we see very deep negative prices in Germany, while Spain generally avoids them? And what does the future hold for negative‑price hours? Should we perhaps pay more attention not only to negative prices, but also to the growing prevalence of near‑zero prices?

Behind the paywall, I’ll share my perspective on these questions. In short, I believe that extreme negative‑price events will likely become less frequent, yet the overall trend toward an increasing number of negative—or very low—price hours is far from reversing. Let’s have a look together.

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Forecasts may tell you a great deal about the forecaster; they tell you nothing about the future. — Warren Buffett

If there is one topic dominating today’s energy discussions, it is the rapid emergence of batteries in our power system. This surge is driven largely by the attractive revenues seen since the energy crisis—higher energy prices, greater needs and spreads fueled by solar generation, and steadily declining battery costs.

Given that batteries typically have an operational lifespan of around 20 years, it is natural to try to estimate what long‑term revenues might look like. This is especially relevant because current remuneration levels in Europe, which remain relatively high, are likely to decrease sooner rather than later.

What makes this even more challenging is that large‑scale storage is still a relatively new asset class, making long‑term revenue forecasting inherently uncertain. But despite the uncertainty, let’s give it a try.

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Are forecasts sometimes completely off?

Before turning to batteries, it’s helpful to look at another technology that has grown at an extraordinary pace: solar. Forecasting solar remuneration has been particularly difficult, with capture rates1 repeatedly overestimated. In 2022, solar capture rates were still close to 100%, but by 2025 they had fallen to around 50%. Such a sharp decline was, in my view, largely unforeseen.

A review of the official EEG projections—used to determine the level of support required for renewables in Germany—reveals a consistent pattern: estimated solar capture rates have systematically exceeded what ultimately materialized2. Each year, new analyses update expectations for the coming years (see the graph below). The scenario made in 2022 projected a solar capture rate higher than 80% until 2026. In contrast, actual outcomes (black dashed line) deteriorated much faster, with capture rates reaching only 59% in 2024 and 52% in 2025.

It is now clear that the true impact of solar on energy markets has been difficult to anticipate, largely because its deployment followed an exponential trajectory. Today, the situation is evolving. Solar capacity is still expanding at an impressive pace, but it is no longer in the same exponential growth3. Instead, storage is emerging as the technology entering its own exponential growth cycle, with deployment accelerating rapidly.

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Revenues with infinite capacity

I particularly appreciate thought experiments—situations where we can postulate new assumptions, even if they may never be fully true or technically feasible. Here, I will assume an extreme case: an electricity system with infinite BESS capacity, effectively removing any storage constraint.

In such a scenario, competition among battery operators would push revenues down toward the marginal cost of using storage. In my view, this marginal cost consists mainly of three components4:

1. Energy losses,

2. Battery degradation, particularly the cost of repowering once the battery becomes too degraded, evaluated at future expected cell prices (important when costs are declining),

3. Network charges, which can impact significantly the cost of operating storage5 .

To simplify the reasoning, let’s temporarily assume no network charges and zero losses. In this stylized world, the average spread captured by the battery should converge to its degradation cost.

If we assume that only the battery cells need replacement, with a future cell cost of €100/kWh and a cycle life of 10,000 cycles, each cycle must generate at least €10 to cover the degradation cost. With an annual utilisation of 500 cycles, the battery operates for 20 years. Under these assumptions, annual revenues would be: €5k per MWh of installed capacity, or €10k per MW for a 2‑hour system (again, assuming no losses and no network fees).

Of course, this is a very simplified framework, but it helps illustrate the basic principle: in the long-run, storage revenues tend to toward the marginal cost of storage, driven by degradation, losses, and grid charges6. In most European countries, this marginal cost remains well below today’s revenue opportunities. Furthermore, it is very likely that we will never get to this marginal cost, because such low level would probably impede the development of new projects, except if substantial other revenues are generated from other markets, such as capacity markets7.

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Current revenues

Let’s have a tour of current revenues from other markets. The first one is in Texas (ERCOT). As Modo8 shows, the revenues for 2025 have cratered from 193$ per kW in 2023 to less than 30 $/kW only 2 years after.

Across the Channel—where battery deployment has progressed further than in continental Europe9—we have observed revenues fluctuating between £50,000 and £100,000 per MW per year over recent months.

So, how doe it compare with Continental Europe?

Well, we find quite large differences potentially, ranging from very high values such as these ones for the Baltics from Clean Horizon (For a 2h battery, yearly revenues ranged between €700k/MW/year and €3,500k/MW/year) or this one stating a performance of more than 500 k€/MW in one year in 2024. More moderate estimates are often closer to 200 k€/MW/year (see Modo) or even 148 k€/MW/year (source). The latter source even produces a forecast for 2026 (Germany):

Overall, revenues decline by approximately €3.7 thousand per megawatt, corresponding to a reduction of around 2.5%. Higher spreads in the day-ahead market are partially offset by lower balancing power prices in the new scenario, resulting in a slightly lower overall revenue level.

The forecast revenues for 2026 amount to €145,900 per megawatt per year, slightly below the average achievable revenues of the past twelve months, but still within a comparable range.

Interestingly, this remains considerably higher than the levels seen in the UK, and far above the revenues observed in Texas. It is also notable that the source expects lower balancing revenues but higher day‑ahead spreads—very much in line with what I would anticipate as well.

In any case, I do not claim to have a crystal ball, but I will try to outline how one might frame potential future storage revenues, based on four key points.

Let’s explore these below.

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