Do households get paid to use electricity when prices are negative?

Almost never. Retail tariffs are fixed or averaged, and network charges and taxes stay positive. Only customers on contracts that pass through the hourly wholesale price see any of it, and even then the other charges usually keep the total above zero.

Are negative prices a sign that something has gone wrong?

Not exactly. They are a sign that the system has more inflexible supply than it can use in that hour, which is a real and useful signal. Persistent negative prices point to a need for more storage, more flexible demand or better connections.

When are negative prices most likely?

Mild, sunny and windy days with low demand: spring and autumn weekends, and public holidays, when consumption is low but renewable output is high.

Why Electricity Prices Go Negative

Wholesale electricity prices go below zero when generators would rather pay to keep producing than stop. That sounds irrational, and it is not: some plants face large costs if they shut down and restart, and some are paid a subsidy for every unit they generate, so they will accept a small loss on the energy itself to avoid a bigger loss elsewhere. Add a windy sunny day with little demand, and the price can spend hours underwater.

What a negative price means

In a wholesale auction, sellers submit the lowest price at which they are willing to produce. Most of the time that number is positive, because producing costs money. But the auction permits negative offers, and markets set an explicit floor several hundred units below zero.

When enough sellers offer below zero and demand is small, the crossing point between supply and demand falls below zero too. Under uniform pricing, everyone accepted in that hour trades at the negative price: the buyers are paid to take the electricity, and the sellers pay for the privilege of delivering it. The mechanism is the ordinary one described in merit order and marginal pricing, simply carried below the axis.

Reason one: plants that cannot easily stop

Not every generator can be switched off for a few hours and switched back on.

A nuclear reactor can reduce output, but deep cycling is slow, costly and constrained by the physics of the fuel. A large coal or lignite unit takes many hours to restart and burns expensive fuel doing it, and repeated cycling wears the plant. A combined heat and power plant may be producing steam for a district heating network or an industrial process, so its electricity is a by-product of an obligation it cannot drop.

For all of these, the choice in a low price hour is not between earning money and earning nothing. It is between a modest loss for a few hours and a much larger loss from shutting down and starting again. So they offer at a negative number that reflects that trade off, and keep running.

Reason two: payment per unit generated

Many renewable plants are supported by schemes that pay a fixed amount for each megawatt hour produced, on top of whatever the market pays, or that guarantee a total price per unit. Others earn certificates or tax credits tied to output.

A plant earning a support payment of, say, 50 per megawatt hour is still better off generating at a market price of minus 20 than not generating at all, because it nets 30. Its rational offer is therefore not zero but roughly minus the value of the support. When a lot of capacity is in that position, the bottom of the supply stack sits well below zero and stays there.

This is why negative prices appear first and most often in systems that combine a large amount of subsidised renewable capacity with plants that are slow to shut down.

Reason three: too much wind and sun, too little demand

The first two reasons set the floor. The third decides when it is reached.

Demand for electricity has a strong weekly and seasonal shape. It is lowest on mild weekends and public holidays, when factories and offices are closed and neither heating nor cooling is working hard. Renewable output has a different shape entirely, driven by the weather. When a bright, breezy Sunday in spring lands on a system with a large fleet of wind turbines and solar panels, the two curves pull apart.

The scale of the potential mismatch is easy to see in the annual statistics. Ember’s figures for 2025 show wind and solar together producing about 45% of all electricity generated in Germany across the whole year. In individual hours on a good day, the combined output is far above that average, while demand is far below its own.

Two further conditions decide whether that surplus crashes the price or escapes. If the neighbouring markets have room and the interconnectors are not full, the excess is exported and the price is held up. If the borders are congested, the surplus is trapped and the price falls. The same applies to storage: batteries and pumped hydro absorb cheap energy until they are full, and then stop helping.

What happens as a result

Negative prices are a signal, and the system responds to them.

Flexible consumers move load into those hours where they can. Batteries charge, since buying at a negative price and selling later at a positive one is the most profitable trade available. Electrolysers, water pumping, heating and cooling stores and industrial processes with some freedom over timing do the same.

Generators that can stop, do. Wind and solar output is curtailed, either by the operator for network reasons or by the owner choosing not to produce at a loss, which is covered in our explainer on curtailment.

And policy adjusts. Support schemes have increasingly been redesigned so that payments stop during extended periods of negative prices, precisely to remove the incentive that made some of those hours negative in the first place. Newer contracts in several European countries include such clauses as standard.

Where negative prices show up

The pattern differs by cause. In markets with high midday solar output, the negative hours cluster around the middle of the day, in spring and autumn, which is the shape described in the duck curve. California’s grid is the most studied example, and the daily shape of its generation is visible on our CAISO grid page.

In markets with a lot of wind concentrated far from demand, the negative hours arrive overnight and in the small hours, when wind output is strong and consumption is at its lowest. West Texas has produced this pattern for years, and the wind share of the ERCOT grid can be seen on its page.

In Europe, the spread of negative hours has followed the build out of solar capacity closely, and the count of such hours has risen across many countries. Our Europe page carries the annual and monthly generation statistics behind that build out.

One honest caveat: World Power Monitor does not publish European wholesale prices yet. What we publish today is annual and monthly statistics compiled by Ember, and hourly operator data for United States grids, which shows the generation and demand patterns that cause negative prices rather than the prices themselves.