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Negative electricity prices

7 January 2020 – In a few hours in the year the electricity price on the exchange is negative. This means that during that time electricity producers have to pay for the offtake of the electricity they generate. There is a strong incentive to consume and also not to generate this electricity. However, there are reasons why producers of both conventional and renewable electricity continue to run their generating installations even when the price is negative.

When do negative electricity prices occur?

Supply and demand determine the wholesale price of electricity. However, electricity is a special commodity with limited storability. Electricity always needs an offtaker to ensure that the grid remains stable. Storage providers therefore act on the electricity markets on the demand side (taking energy off the grid for storage) and on the supply side (releasing electricity into the grid from storage).

Negative electricity prices can occur on short-term electricity markets when high and inflexible electricity generation coincides with low demand. Negative electricity prices usually occur in periods when there is high wind and/or solar photovoltaic generation. Particularly low demand often occurs over public holiday periods such as Easter, Pentecost or Christmas.

For instance, electricity prices on the exchange were negative (averaging minus 52.75 euros per megawatt hour) between 10am and 6pm on Easter Monday, 22 April 2019. In other words, traders on the electricity exchange received money for buying electricity. On that day, consumption was low, which is typical for the Easter bank holidays, while at the same time photovoltaic installations were generating a lot of electricity. Despite moderate wind generation, renewables produced enough electricity to meet Germany's entire demand over a period of several hours. Although conventional generators reduced their output considerably, it was not sufficient to balance supply and demand.

The graph illustrates electricity generation and consumption and wholesale prices in Germany on Easter Monday, 22 April 2019.

On Pentecost Saturday, 8 June 2019, the auction prices for electricity on the EPEX Spot day-ahead market were also negative from midnight until 7pm (averaging minus 59.02 euros per megawatt hour). Weak consumption coincided with high levels of generation from renewables and inflexible conventional generation. In addition, IT problems on the electricity exchange led to a partial decoupling of the European trading markets: coordinated management under the market coupling scheme, which enables the cross-border integration of the central European electricity markets, was affected by IT problems and could therefore not be used for the export of the electricity generated in Germany. The prices in Germany were thus rather lower than they would have been if market coupling had been working properly. However, even without the technical problems, negative prices could have been expected in Germany because of the market situation. There were also negative prices over the Pentecost long weekend in 2018 – at that time for a total of eleven hours.

The graph illustrates electricity generation and consumption and wholesale prices in Germany on Pentecost Saturday, 8 June 2019.

Why do conventional power plants continue generating electricity?

There are various reasons why operators of conventional power plants keep their plants running when prices are negative. For operators of large fossil fuel or nuclear power plants, for example, shutting down and later re-starting their plants would be very costly. In light of these start-up and shutdown costs, it may make economic sense when prices are negative to ramp down a plant to its technical minimum but not shut down the plant completely. The operator of a power plant will make this calculation not only when prices fall below zero, but also when prices fall below the plant's marginal costs (including fuel and carbon emission costs). It is part of daily business for operators of conventional power plants to continue operation even during the hours when they cannot cover their costs. Industrial power plant operators also optimise the operation of their plants in conjunction with their electricity consumption. It may, for example, make economic sense to continue running a power plant to avoid a high grid load and thus high network charges. Nuclear power plants are also subject to technical and licensing restrictions.

The graph illustrates electricity generation by conventional power plants in Germany on Easter Monday, 22 April 2019.

Another reason for continuing operation is a plant operator's commitment to provide contractually agreed system services, such as balancing energy, to the network operator. This is referred to as conventional minimum generation. The Bundesnetzagentur investigated the reasons behind the generation of electricity by conventional power plants despite negative day-ahead exchange prices in its Minimum generation 2019 report.

Another reason that is more significant both in terms of scope and in economic terms, however, is what is known as the conventional generation base. This arises from the fact that conventional power plants earn revenue not only from the sale of electricity but also from various other sources. From the operators' perspective, it makes sense for combined heat and power (CHP) plants to continue producing electricity if they are responsible for supplying heat to an urban or industrial heating network and if it is not yet possible – or would be expensive – to separate the heat generation from the electricity generation process. The demand for heat can, however, only partially explain the behaviour, and the acceptance of operational losses, over the Easter and Pentecost periods. There are other financial incentives that encourage operators to continue generating electricity even when prices are negative, such as "avoided network charges" (payments to power plants for feeding in electricity below the extra-high voltage level) and "self-consumption privileges" (exemption from network charges and the renewable energy surcharge for power stations attached to industrial plants).

Nevertheless, negative prices and the associated costs create economic incentives for operators to increase the technical flexibility of lignite and black coal power plants, in particular, and thus be better able to adjust output at short notice. These power plants have thus continuously increased their flexibility in recent years. An example of how conventional power plants respond to peaks in generation from renewables is described here. The key step – an easier way to completely shut down and re-start the plants – is still missing, however.

Why do wind and solar photovoltaic installations continue generating electricity?

Renewable energy installations in Germany receive payments under the Renewable Energy Sources Act (EEG) because they cannot yet be fully refinanced through the market. Renewable energy generators receive a guaranteed payment for every kilowatt hour they produce. Since the entry into force of the revised EEG in 2014, installations with a capacity of more than 100 kW have to sell the electricity they generate directly on the wholesale market ("direct selling"). In 2017, this electricity accounted for up to 78% of the electricity receiving EEG payments.

Installation operators selling their electricity directly do not receive a feed-in tariff but a "sliding" monthly market premium that makes up the difference between the guaranteed payment and the average monthly revenue on the wholesale market. The level of the market premium is therefore largely independent of the applicable exchange price. The operator of a renewable energy installation will thus accept negative prices for as long as they are overcompensated by the market premium. Only when a negative price cancels out the market premium completely will the operator have negative revenues and switch off the installation. For many installations, given the current price level and corresponding average revenue at the beginning of 2020, it would be possible for the wholesale price to fall to minus 30 euros per megawatt hour without negative prices outweighing the guaranteed income from statutory payments. Only if the price were to fall even lower would there be an economic incentive for operators to switch off their generating installations. On account of other, individually varying costs, such as payments to maintenance companies, this price limit is not universally applicable, but differs between installations.

The revised EEG of 2014 also introduced the "six-hour rule", under which larger new installations receiving EEG payments and selling electricity directly will not receive payment if the day-ahead price on the electricity exchange is negative for a period of at least six consecutive hours. If this is the case, the installation operator will not receive the market premium as from the first hour in the period with negative prices.

In 2020-2021, innovation auctions will be held to test technical innovations and new auction procedures. One of the new features will be a fixed market premium. Renewable energy installation operators receiving payments under the innovation auction scheme will no longer receive the market premium when electricity prices are negative. The higher revenue risk associated with this might need to be taken into account when submitting bids on the electricity market.

How often do negative electricity prices occur?

Negative wholesale prices in Germany from 2015 to 2019







Number of hours with negative prices






Number of hours in a period of at least six consecutive hours with negative prices






Minimum [€/MWh]






Mean negative price [€/MWh]






Data basis: smard.de

In 2019, a total of 211 hours with negative prices were registered on the EPEX Spot day-ahead market, corresponding to around 2.4% of all traded hours in the year. Although the figure is higher than in the previous year, negative electricity prices still make up only a small proportion of total wholesale trade. It is also important to note that the two above-mentioned days at Easter and Pentecost alone accounted for 29 hours of negative price trading. The average negative wholesale price in 2019 was minus 17.27 euros per megawatt hour. The majority of the negative prices occurred in a period with at least six consecutive hours of negative pricing (a total of 123 out of 211 hours). Under the six-hour rule, the installation operators did not receive a market premium for these periods. There was a special beginning to the year 2020: for the first time since 2017 there were no negative prices at the new year.

Can negative electricity prices be avoided?

To reduce the frequency of negative electricity prices in future, both the supply side and the demand side need to be able to adapt even better to the fluctuations in renewable energy generation – for instance through more flexible conventional power plants or the separation of electricity and heat generation in CHP plants on the supply side, and through electricity-to-heat options and the use of storage on the demand side. Another important factor in avoiding negative electricity prices is eliminating sources of income beyond the electricity markets, such as self-consumption privileges. Extending electricity trading with neighbouring countries would also ease the situation.