Variable renewable generation across a group of regional markets declined to 3.50 TWh in the week of Aug. 17-23, down from 3.93 TWh in Week 30 in late July. The fall amounts to about 11%. Almost all of the deterioration came from wind.
Wind and solar diverge across regional markets
Regional wind production fell 26.4% to 1.14 TWh from 1.55 TWh over the comparison period. Solar generation declined by only 0.9%. In Greece, wind production fell about 48%, while solar output increased.
The different generation patterns affect market pricing in distinct ways. Solar output is concentrated in a relatively narrow daytime window, which can depress midday prices sharply. It does little to cover electricity demand after sunset.
Wind production is less tied to daylight hours. When wind generation declines across several interconnected countries at the same time, the lost supply has to be replaced during a much broader portion of the day. That replacement increasingly comes from hydroelectric plants, thermal generation or imports.
Price increases despite weaker consumption
The pricing impact was visible during Aug. 17-23, when wholesale electricity prices rose in most Southeast European markets despite weaker aggregate consumption. Greece’s weekly average increased 41.2%, Bulgaria’s rose 16.9%, and Hungary’s climbed 7.2%.
The shift also complicates assumptions that rapid solar deployment will steadily reduce average power prices. Additional photovoltaic capacity can continue pushing midday prices lower while doing comparatively little to reduce the cost of the evening peak.
If wind production is weak at the same time, the region can see low solar-hour prices alongside expensive electricity later in the day. This combination increases price volatility and reduces the usefulness of conventional peak-versus-off-peak assumptions.
Implications for market products and renewable economics
Serbia’s SEEPEX market has already shown periods when conventional daytime peak prices were lower than the baseload average because the most expensive hours occurred after solar generation had fallen. In July, SEEPEX baseload averaged €109.43/MWh, while the conventional peak product averaged only €86.38/MWh.
The changing relationship affects how renewable projects are evaluated for revenue potential. Solar developers increasingly need to assess capture prices rather than relying on annual average electricity prices alone.
Wind farms may retain greater value where their output is less correlated with the growing solar fleet, although they remain exposed to periods of regional wind correlation . The same trend strengthens the economics of batteries and flexible hydro because they can move electricity from oversupplied hours into periods when both solar and wind availability are weak .
For Southeast Europe, renewable integration is therefore shaped by hourly composition rather than headline renewable volume alone . Solar increasingly determines how cheap electricity becomes during the middle of the day, while wind increasingly determines how often additional resources are required during other parts of the day .
