A steep decline in wind generation has emerged as a major factor behind recent electricity-price strength in Southeast Europe, highlighting the different market effects of wind and rapidly expanding solar capacity.
Variable renewable generation across a group of regional markets fell to 3.50 TWh in the week of Aug. 17-23 from 3.93 TWh in Week 30 in late July, a decline of about 11%.
Almost all of that deterioration came from wind.
Regional wind production fell 26.4% to 1.14 TWh from 1.55 TWh over the comparison period, while solar generation declined by only 0.9%. In Greece, wind production fell about 48%, while solar output increased.
The difference matters because the technologies affect prices differently.
Solar generation is concentrated in a relatively narrow daytime window. Strong output can depress midday prices sharply, but 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.
The effect 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 16.9% and Hungary’s 7.2%.
The trend 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 production is weak at the same time, the region can simultaneously experience low solar-hour prices and expensive electricity later in the day.
That combination increases price volatility and reduces the usefulness of conventional peak-versus-off-peak assumptions.
Serbia’s SEEPEX market has already shown periods in which 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 has implications for renewable investment.
Solar developers increasingly need to assess capture prices rather than simply annual average electricity prices. Wind farms, by contrast, 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, the next stage of renewable integration is therefore less about the headline volume of renewable generation than its hourly composition.
Solar is increasingly determining how cheap electricity becomes during the middle of the day.
Wind is increasingly determining how often the region needs something else.
