Across Southeast Europe, 2025 has marked the first full year in which renewable electricity producers have operated not as a protected transition segment, but as core contributors to regional power systems and wholesale price formation. Wind, solar and hydro assets are no longer marginal add-ons; they are now shaping intraday price curves, cross-border flows and balance-of-system economics. Performance in 2025 therefore needs to be assessed not only in terms of installed capacity growth, but through operating margins, realized prices, curtailment exposure and cash-flow stability.
At a regional level, renewable electricity production across SEE expanded by roughly 9–12 percent year-on-year, driven primarily by wind additions in Romania and Greece and by a surge of solar PV capacity in Bulgaria, Greece and Croatia. Hydropower volumes were broadly stable versus 2024, with some positive hydrology in the western Balkans offset by weaker inflows in parts of the lower Danube basin. What differentiates 2025 from prior years is that most of this incremental renewable output was absorbed by the market without heavy reliance on emergency state intervention, signalling a maturing system.
Romania remained the anchor market for renewable electricity performance in SEE. Wind producers operated a fleet exceeding 3.1 GW, generating approximately 6.8–7.4 TWh over the year, depending on location and turbine vintage. Average wind capacity factors clustered around 28–33 percent, with well-sited Dobrogea assets at the upper end of the range. Importantly, realized prices for wind producers improved in 2025 compared to 2024 despite higher penetration. Long-term contracted projects under legacy support schemes delivered stable revenues equivalent to €80–95 per MWh, while 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 percent, translating into equity cash yields of 9–12 percent for seasoned projects.
Solar producers across SEE experienced their first real stress test in 2025 as daytime price cannibalization became visible in high-penetration zones. Bulgaria is the clearest example. Installed solar capacity crossed ~4 GW, pushing midday wholesale prices in summer months down to €30–45 per MWh during peak generation hours. For utility-scale solar plants selling fully merchant power, this compressed revenues despite strong irradiation and capacity factors of 18–21 percent. However, producers with fixed-price power purchase agreements or feed-in premium coverage maintained stable cash flows. Even under lower spot prices, typical solar OPEX of €8–12 per MWh allowed EBITDA margins of 45–60 percent for contracted projects, while uncontracted assets saw materially wider dispersion depending on hedging strategy.
Greece continued to demonstrate the most advanced renewable system behavior in SEE. Wind and solar together frequently covered 45–55 percent of hourly electricity demand during favorable conditions in 2025. For producers, this translated into a bifurcated performance profile. Assets under the Greek support framework realized effective prices of €85–100 per MWh, maintaining strong and predictable cash flows. Merchant exposure, however, became more volatile, particularly for solar, as negative or near-zero prices appeared during extreme midday oversupply events. Wind producers performed more robustly, with capacity factors around 30–35 percent and less price cannibalization due to temporal diversification. On a full-year basis, Greek wind projects typically delivered EBITDA margins of 55–65 percent, while solar margins ranged from 40 to over 60 percent depending on contract structure.
In the Western Balkans, renewable producer performance in 2025 was shaped less by price cannibalization and more by grid and regulatory constraints. Serbia illustrates this dynamic clearly. Wind capacity of roughly 800 MW generated around 2.1–2.3 TWh, with average capacity factors near 30–34 percent. Most Serbian wind assets remained under support schemes or long-term offtake arrangements, securing realized prices above €90 per MWh at a time when regional spot prices averaged €70–80 per MWh. With operating costs in the €18–22 per MWh range, wind producers in Serbia delivered some of the cleanest financial profiles in the region, with EBITDA yields on invested capital commonly reaching 18–22 percent.
Solar performance in Serbia lagged peers in absolute scale but stood out in terms of unit economics. Utility-scale and commercial rooftop systems achieved capacity factors of 18–22 percent, and the combination of avoided retail prices and incentive mechanisms resulted in effective revenues often exceeding €100 per MWh for behind-the-meter producers. Cash-flow volatility was minimal, and payback periods of 7–10 years became standard for commercial and industrial solar investors.
Hydropower producers across SEE experienced a relatively neutral year in 2025. Aggregate output was broadly flat, but revenue outcomes improved because hydro flexibility allowed producers to sell into higher-priced evening and balancing windows. In Croatia and Bosnia and Herzegovina, hydro assets captured average realized prices of €85–95 per MWh, well above long-term averages. Operating costs for large hydro remain structurally low, typically below €15 per MWh, sustaining EBITDA margins above 70 percent for legacy assets. However, these returns increasingly function as system stabilizers rather than growth drivers, with limited new hydro capacity entering the market.
Across the region, a clear performance divide emerged in 2025 between contracted and merchant renewable producers. Assets with fixed or indexed revenue frameworks displayed bond-like cash-flow characteristics, with low volatility and predictable dividend capacity. Merchant-exposed producers faced higher revenue dispersion but also benefited from strong intraday and cross-border price spreads when weather patterns diverged across SEE markets. The growing importance of regional interconnectors amplified this effect, allowing renewable producers to indirectly arbitrage geographic price differences.
From a financial perspective, 2025 confirmed that renewable electricity producers in SEE can sustain equity returns in the high single-digit to low double-digit range, even as penetration increases. Wind assets remain the most resilient in terms of price formation and cash-flow stability, solar assets increasingly require contractual protection or co-location with storage, and hydro continues to anchor system economics with exceptional margins but limited growth.
The broader implication is that renewables in Southeast Europe have moved decisively beyond the development story. By 2025, performance is dictated less by subsidy access and more by operational discipline, market integration and portfolio structuring. Producers that combine wind, solar and flexible assets across multiple SEE markets are increasingly able to smooth revenues and protect returns, positioning the region not as a peripheral energy transition zone, but as a structurally profitable renewable power market in its own right.
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