In 2025, renewable electricity producers across Southeast Europe operated as core contributors to regional power systems and wholesale price formation. Wind, solar and hydro output influenced intraday price curves, cross-border flows and balance-of-system economics. Performance was assessed through operating margins, realized prices, curtailment exposure and cash-flow stability rather than only installed capacity growth.
Renewable electricity production across the region increased by roughly 9–12% year-on-year. The expansion was driven by wind additions in Romania and Greece, alongside a surge in solar PV capacity in Bulgaria, Greece and Croatia. Hydropower volumes were broadly flat versus 2024, with improved hydrology in parts of the western Balkans offset by weaker inflows in sections of the lower Danube basin. Most of the incremental renewable output was absorbed by the market without heavy reliance on emergency state intervention.
Wind generation and pricing outcomes in Romania and Greece
Romania remained a key market for renewable performance in 2025. Wind producers operated a fleet exceeding 3.1 GW, generating about 6.8–7.4 TWh annually depending on location and turbine vintage. Average capacity factors were in the 28–33% range, with Dobrogea assets at the upper end.
Realized prices for Romanian wind improved versus 2024 despite higher penetration. Long-term contracted projects under legacy support schemes delivered stable revenues equivalent to €80–95 per MWh. Merchant or semi-merchant producers captured weighted average market prices of €75–85 per MWh. With operating costs below €20 per MWh, EBITDA margins for Romanian wind assets commonly exceeded 60%, translating into equity cash yields of 9–12% for seasoned projects.
In Greece, wind and solar together frequently covered 45–55% of hourly electricity demand during favorable conditions in 2025. Under the Greek support framework, realized effective prices were €85–100 per MWh, supporting strong and predictable cash flows. Merchant exposure became more volatile, particularly for solar, as negative or near-zero prices appeared during extreme midday oversupply events.
Greek wind performance was described as more robust, with capacity factors around 30–35%. Less price cannibalization was attributed to temporal diversification. On a full-year basis, Greek wind projects typically delivered EBITDA margins of 55–65%, while solar margins ranged from 40% to over 60%, depending on contract structure.
Solar PV revenue dispersion in Bulgaria and contract protection effects
Solar producers across Southeast Europe faced their first real stress test in 2025 as daytime price cannibalization became visible in high-penetration zones. Bulgaria provided the clearest example of the effect on wholesale pricing during peak generation hours. Installed solar capacity crossed approximately 4 GW, pushing midday wholesale prices in summer months down to €30–45 per MWh.
For utility-scale solar plants selling fully merchant power, revenue compression occurred despite strong irradiation and capacity factors of 18–21%. Producers with fixed-price power purchase agreements or feed-in premium coverage maintained stable cash flows. Even when spot prices were lower, typical solar OPEX of €8–12 per MWh supported EBITDA margins of 45–60% for contracted projects.
The same period also showed wider dispersion for uncontracted assets based on hedging strategy. The source data linked this dispersion to how revenue outcomes responded to daytime oversupply conditions.
Western Balkans constraints and Serbia’s wind and solar economics
The Western Balkans showed a different pattern in 2025, with renewable producer performance shaped less by price cannibalization than by grid and regulatory constraints. Serbia illustrated this dynamic for both wind and solar markets.
Serbian wind capacity was roughly 800 MW, producing around 2.1–2.3 TWh. Average capacity factors were near 30–34%. Most Serbian wind assets remained under support schemes or long-term offtake arrangements, securing realized prices above €90 per MWh, while regional spot prices averaged €70–80 per MWh.
With operating costs in the range of €18–22 per MWh, Serbian wind delivered EBITDA yields on invested capital commonly reaching 18–22%. Solar output in Serbia was smaller than peers elsewhere but unit economics were highlighted as a differentiator.
Utility-scale and commercial rooftop systems achieved capacity factors of 18–22%. For behind-the-meter producers, avoided retail prices combined with incentive mechanisms resulted in effective revenues often exceeding €100 per MWh. Cash-flow volatility was described as minimal, with payback periods of 7–10 years standard for commercial and industrial solar investors.
Hydropower stability and system role across Croatia and Bosnia and Herzegovina
Hydropower producers across Southeast Europe experienced a relatively neutral year in 2025. Aggregate output was broadly flat compared with 2024, but revenue outcomes improved because hydro flexibility enabled sales into higher-priced evening and balancing windows.
In Croatia and Bosnia and Herzegovina, hydro assets captured average realized prices of €85–95 per MWh, above long-term averages cited in the source material. Operating costs for large hydro were structurally low, typically below €15 per MWh. This supported EBITDA margins above
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