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, a fall of about 11%. Almost all of the deterioration came from wind.
Wind and solar diverge in weekly generation
Regional wind production fell 26.4% to 1.14 TWh from 1.55 TWh, while solar generation declined by only 0.9%. In Greece, wind production fell about 48%, while solar output increased.
The different operating patterns affect how each technology influences power prices over the day. Solar generation is concentrated in a relatively narrow daytime window, which can depress midday prices sharply but does little to cover demand after sunset. Wind production is less tied to daylight hours.
Broader replacement needs after concurrent wind weakness
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.
The price 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%.
Solar growth assumptions challenged by evening peak costs
The pattern complicates the assumption 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 output is weak at the same time.
In that scenario, the region can experience low solar-hour prices alongside expensive electricity later in the day. The combination increases price volatility and reduces the usefulness of conventional peak-versus-off-peak assumptions.
SEEPEX shows expensive hours after solar output falls
Serbia’s SEEPEX market has already shown periods where 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.
Implications for renewable investment and flexibility
The changing relationship has implications for renewable investment strategies. Solar developers increasingly need to assess capture prices rather than rely 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 shift electricity from oversupplied hours into periods when both solar and wind availability are weak.
Southeast Europe’s next stage of renewable integration is therefore less about headline renewable volumes than about hourly composition, with solar increasingly determining how cheap electricity becomes during the middle of the day and wind increasingly determining how often additional resources are needed.
