Negative and zero prices in Europe’s power markets
Negative electricity prices are no longer unusual in Europe. What once appeared as an anomaly has become a recurring feature, particularly in markets with rapid renewable growth.
Germany illustrates how market design, subsidy structures and changing demand patterns are reshaping price behaviour.
This report examines why negative prices occur, how frequently they now appear across Europe, and why zero-price hours may become the next structural challenge.
Why negative prices occur
Negative prices emerge when supply significantly exceeds demand and flexibility is limited.
Key drivers include:
Low demand during holidays or weak industrial activity
High renewable feed-in from wind and solar
Subsidy structures that reduce price sensitivity
Renewable operators often receive fixed payments or market premiums, encouraging bidding even at negative prices.
Rising frequency across Europe
Recent figures show the scale of the issue:
France: up to 506 hours of negative prices
Spain: around 552 hours in 2025
Finland: roughly 725 hours in 2024
Poland: approximately 310 hours in 2025
Germany recorded over 570 hours of negative prices last year.
These figures suggest that surplus renewable generation is becoming structural rather than temporary.
The German case and regulatory reform
Under paragraph 51 of the EEG framework:
Renewable assets lose subsidy payments during negative price periods
The rule has shifted from six consecutive hours to a stricter one-hour threshold
While this reduces incentives to bid below zero, it encourages bidding at zero, meaning oversupply may shift from negative prices to zero-price hours.
Long-term outlook: fewer negative prices, more zero prices
Scenario analysis shows:
Without battery expansion, flexible demand and paragraph 51 incentives, Germany could experience more than 2,500 hours of negative prices by 2036.
When flexibility and subsidy reforms are included, negative price hours fall sharply by 2030 — but zero-priced hours increase.
The risk for unsubsidised generators
For unsubsidised assets:
Zero multiplied by output remains zero.
A growing share of zero-priced hours reduces merchant revenue and increases uncertainty for assets relying on market income.
Pro-rata allocation risk
When supply at zero exceeds demand, pro-rata allocation applies.
Example:
100 GWh offered at zero
80 GWh demand
Only 80% of bid volume is sold
This introduces:
Price dilution
Volume curtailment
As zero-price hours increase, pro-rata allocation may become more frequent and should be considered in renewable investment decisions.
Europe’s power markets are in transition. Renewable growth, limited flexibility and subsidy rules have created persistent oversupply conditions.
While negative prices may decline, zero-priced hours and pro-rata allocation risks are emerging as structural challenges.