From negative prices to zero hours: the new challenge for energy investors in Germany

However, a closer look at future developments shows a more differentiated picture. While instances of negative prices have increased sharply in the past, it can be assumed that their number will decline again over the long term as more battery storage is deployed, power grids receive further investment, electrolysers are further build-out and stated subsidy support regulation try to avoid negative prices. At the same time, however, another category of price signals will increase significantly, namely hours with an electricity price of €0/MWh, known as “zero hours”.

This development does not mean that the structural problem of oversupply from renewable energies will disappear. Put simply, the way in which this oversupply is reflected in the market price is changing.

Drivers of negative electricity prices in Germany

The main driver of negative electricity prices is the increasing supply of renewable energy combined with limited demand flexibility. Particularly during periods with high wind or strong solar production, as well as low electricity demand (e.g., weekends, holidays, or economically driven scenarios).

When this happens, electricity supply can significantly exceed demand. Since electricity can only be stored to a limited extent, conventional power plants cannot always be shut down at short notice and many subsidised plants are willing to bid at negative prices (as there has so far been little economic incentive to shut down during negative prices). This oversupply leads to falling power prices and, in extreme cases, pushes them into negative prices.

With the strong expansion of wind and solar capacities, this phenomenon has intensified significantly in recent years. As early as 2020, 298 hours with negative electricity prices were observed in Germany. The reason was a “good” weather year with high renewable generation and low electricity demand due to the COVID-19 pandemic.

After the number of negative hours declined significantly during the energy price crisis, due to the very high price level at the time in 2021 and 2022, 2023 again brought a high number of negative hours. Here as well, high renewable generation and low electricity demand, this time due to Germany’s economic situation, were the decisive factors.

2024 and 2025 saw 459 and 573 hours respectively, setting new records each time. In particular, most of the negative hours were observed during the summer months in the mid-day, whenever high solar generation prevailed.

Structural reasons for fewer negative prices in the future

Even though the supply of renewable energy will continue to grow, several structural developments could reduce negative prices in the future.

§ 51 EEG and the suspension of support during negative prices

Paragraph 51 of the German Renewable Energy Act (EEG) stipulates that new installations under the EEG lose their support if the exchange price is negative for several hours, or now even for one[1] hour.

This regulation creates a strong economic incentive to reduce feed-in during strongly negative prices and leads to EEG plants under the new regulation no longer bidding at negative prices (as they would not receive their subsidy payments if the price is negative) but instead being incentivised to offer their electricity on the exchange at prices of “zero”.

As a result, the amount of electricity that continues to be pushed into the market at negative prices is likely to decrease in the future.

More flexibility in the power system

At the same time, increasing flexibility is emerging in the power system:

• Battery storage systems (BESS)

• Electrolyzers

• Demand response

• Sector coupling (e.g. e-mobility)

These technologies can deliberately absorb electricity and act as a kind of “artificial consumer” when a large amount of renewable energy is available in the system. This helps to both stabilise prices and prevent negative prices.

A detailed quantitative and qualitative analysis of how exactly these factors can reduce the number of negative hours can be found in our negative prices whitepaper.

The new market reality: more “zero hours” in the future?

While negative prices could decline in the long term, as our whitepaper from September 2025 shows, this leads to another clear signal: the number of hours with prices close to or exactly at zero will increase significantly.

The reason is simple: the structural oversupply of renewable energy is not disappearing. Instead of slightly negative prices, the market will more frequently reach situations where a price of €0/MWh occurs, taking into account rational bidding behaviour by newly installed EEG-supported plants.

This price signal still indicates that we are operating in a system with structural oversupply and that the challenge is shifting rather than disappearing.

For installations under the EEG, this development may initially appear positive, because when the electricity price is €0/MWh, the market premium continues to be paid in full, unlike in the case of negative prices, when § 51 EEG would apply. This means that operators continue to receive their support even if the exchange price is zero. However, this seemingly good news brings with it a new challenge. 

The Pro-Rata Rule: Volume allocation for identical bids

When a large number of producers offer electricity at the same time, another market mechanism can become relevant: the pro-rata rule.

This rule comes into effect when more electricity is offered on the exchange at the same price than is actually demanded. In this case, the market cannot accept the entire offered volume. Instead, the accepted volume is distributed proportionally among all suppliers with the same willingness to accept that price.

But what does the pro-rata rule mean in practice? Suppose the following market conditions occur on the exchange:

• High electricity supply (particularly due to high renewable generation) at a price of €0/MWh totalling 100 GWh

• Lower electricity demand of 80 GWh

• The market price settles at €0/MWh

This means that the market requires only 80 GWh of electricity, while 100 GWh is offered at the same price. As a result, not all bids can be fully accepted in the auction. Instead, under the pro-rata rule, each offered volume is reduced proportionally. In this case, the accepted share amounts to: 80 GWh / 100 GWh = 80%

In this example, this specifically means:

• Each supplier can now market only 80% of their offered volume in the day-ahead auction.

• 20% of the energy remains unsold in the day-ahead auction and is therefore not remunerated under the EEG payment scheme.

As the share of renewable energy increases and more bids are submitted close to €0/MWh, this mechanism could become increasingly relevant in the future.

How will the Pro-Rata factor develop in the future?

The following pro-rata factor considers the limitation of marketable electricity volumes in hours with positive and zero prices (i.e., in all hours except those with negative prices) and therefore refers to all affected hours, not exclusively to hours with exactly €0/MWh.

It thus represents the share of production that cannot be fully sold on the market due to oversupply.

In general, the “Central” scenario of Montel’s European power price scenarios shows that the number of hours with prices of zero will increase significantly in the coming years. Until 2029, a clear rise in these hours can be observed, which intensifies further after 2030 and follows a steeper trajectory. A key driver of this development is the strong expansion of renewable generation capacities in Germany, which gains significant momentum from 2027 onward. After 2031, the expansion of solar capacity slows somewhat but continues to increase overall. At the same time, installed battery storage capacity grows substantially: it expands very dynamically until 2029, flattens briefly until around 2031, and then increases markedly again. Meanwhile, electricity demand continues to rise steadily, which can absorb part of the additional supply.

These developments are reflected in the trajectory of the pro-rata factor. Until 2028, the factor initially declines, meaning that a smaller share of the generated electricity can be sold on the market. Afterward, the factor increases again until around 2031, as growing flexibility options, particularly storage as well as increasing demand, can absorb a larger share of production. After 2031, the factor declines once more, as the continued expansion of renewable capacities again leads to greater supply surpluses.

The importance of the Pro-Rata rule for investment decisions

The pro-rata rule has an impact on the expected revenues of renewable energy projects, particularly for subsidized installations.

In general, for installations receiving support under the current market premium scheme, it is a positive development when electricity prices are not negative but instead settle at “zero,” since in those hours they remain eligible for government remuneration.

The market premium payment for installations that do not fall under § 51 EEG is generally composed of the produced and grid-fed electricity volume and the market premium:

If negative electricity prices occur, the determination of the market premium payments must take into account that § 51 EEG applies to specific power plants. Therefore, it must be considered that no payment will be made during hours with negative prices (6h to 1h rule of the § 51 EEG). The calculation for an installation that falls under the 1-hour rule, for example, must therefore be adjusted as follows:

Where:

If the number of negative hours decreases in the coming years, the influence of this regulation on market premium payments will also decline. In this example, the calculation component (1 − 1h share) would in the future equal 1 and therefore disappear from the calculation. At the same time, however, the increasing number of zero-price hours would cause the pro-rata rule to become more important.

However, if only part of the energy is sold due to the pro-rata rule, the volume for which a market premium is paid is reduced, since only the volume under the pro-rata factor can be sold. Accordingly, the market premium payment must be adjusted:

Where:

This means that if the pro-rata case occurs more frequently in the future, this reference parameter should be considered in revenue calculations for all installations, regardless of which hourly rule of § 51 EEG they fall. Accordingly, a reduction in the volumes that can potentially be sold on the market must be assumed. In this case, the pro-rata factor refers to the share that cannot be sold for all hours (except those with negative prices) and is not limited only to hours when the electricity price is “zero.”

Another relevant case arises when a plant initially falls under the 1-hour rule and experiences negative price hours in its early years of operation, while in later years it is additionally affected by the pro-rata rule. In this case, a combined calculation logic must be applied:

Here as well, the factor (1 − 1h share) represents the reduction of the market premium payment due to negative prices, while the PR factor represents the reduction due to excess supply, for example at prices of €0/MWh.

However, it is important not to apply the calculation logic presented above indiscriminately to all project valuations, since depending on the design of direct contracts with the direct marketer, individual contractual arrangements may apply. These must of course be considered when calculating the economic viability of a plant.

For unsubsidised installations, the pro-rata issue is less relevant, as they are not entitled to the market premium. Therefore, they cannot generate revenues during hours with zero prices. For these installations, the key factor is primarily how the total number of zero-price hours in the market develops. Deviations may also occur here depending on whether and which direct marketing contracts are concluded. In addition, the question arises as to what optimisation potential results from this. How sensible is it to sell at “zero prices” in the long term when considering wear, tear, and maintenance costs for the installations?

From a price to a volume problem in the electricity market

Developments in the electricity market suggest that negative prices in Germany may occur less frequently in the future. This is mainly due to regulatory adjustments such as § 51 EEG and the increasing expansion of flexibility options.

However, the underlying problem does not disappear. Instead of negative prices, the market will increasingly be characterised by zero-price hours. These hours still reflect a structural oversupply of renewable energy.

At the same time, the pro-rata rule is bringing a new market mechanism into stronger focus. When too many producers offer electricity simultaneously at very low prices, part of the energy can simply no longer be sold.

The key question for the coming years will therefore not only be how negative prices can be reduced, but above all how the number of zero-price hours will develop. 

Sources:

SDAC (2023), SDAC measures in cases of short supply Curtailment management, Second auction, and Peak Load Capacity in SDAC, Online: Curtailment-to-publish24012023.pdf

NEMO (2019), EUPHEMIA Public Description Single Price Coupling Algorithm, Online: epexspot.com/sites/default/files/2020-02/Euphemia_Public Description_Single Price Coupling Algorithm_190410.pdf

Clearingstelle EEG (2026), Wird die Vergütung meiner Anlage wegen negativen Preisen reduziert?, Online: Wird die Vergütung meiner Anlage wegen negativen Preisen reduziert? | Clearingstelle EEG|KWKG

EEG

[1] With the transition to electricity quarter-hour contracts, a calendar hour is considered an hour with a negative price if the arithmetic mean of the four spot market prices of the respective quarter-hours within that hour is negative (Source: Clearingstelle EEG (2026)).

[2] In Germany known as „anzulegender Wert”