In 2025, renewable electricity producers in Southeast Europe transitioned from a protected segment to essential players in the regional power landscape. This shift has significantly influenced wholesale price dynamics, intraday pricing, and cross-border electricity flows. The assessment of operational performance now extends beyond mere capacity growth to include factors such as operating margins, realized prices, curtailment risks, and cash-flow stability.
Throughout the region, renewable electricity generation saw an impressive increase of approximately 9–12 percent year-on-year. This growth was primarily driven by wind energy expansions in Romania and Greece, alongside a notable rise in solar photovoltaic (PV) capacity across Bulgaria, Greece, and Croatia. Hydropower output remained stable compared to 2024, benefiting from favorable hydrological conditions in the western Balkans while facing challenges in parts of the lower Danube basin. The market’s ability to absorb this additional renewable output without significant state intervention indicates a maturing energy system.
Romania emerged as a pivotal market for renewable energy performance within Southeast Europe. The country’s wind sector operated over 3.1 GW of capacity, producing between 6.8–7.4 TWh annually based on location and turbine technology. Average capacity factors for wind farms ranged from 28–33 percent, with top-performing assets achieving higher rates. Notably, realized prices for wind energy improved in 2025 compared to the previous year, with long-term contracts yielding revenues of €80–95 per MWh, while merchant producers achieved market prices averaging €75–85 per MWh. With operating costs below €20 per MWh, EBITDA margins for Romanian wind projects frequently exceeded 60 percent, resulting in equity cash yields of 9–12 percent.
The solar sector faced its first major challenge in 2025 due to price cannibalization effects observed during peak generation periods. In Bulgaria, for instance, installed solar capacity surpassed ~4 GW, leading to midday wholesale prices dropping to between €30–45 per MWh. Despite strong irradiation and capacity factors of 18–21 percent, utility-scale solar plants selling on a fully merchant basis experienced revenue compression. However, those with fixed-price power purchase agreements maintained stable cash flows. Typical solar operating expenses ranged from €8–12 per MWh, allowing contracted projects to achieve EBITDA margins between 45–60 percent, while uncontracted assets displayed greater variability based on their hedging strategies.
Greece showcased advanced operational characteristics within its renewable energy market. Wind and solar collectively met between 45–55 percent of hourly electricity demand under favorable conditions throughout 2025. Producers benefitted from a dual performance profile; those under the Greek support framework realized effective prices ranging from €85–100 per MWh, ensuring robust cash flows. Conversely, merchant exposure became increasingly volatile, particularly for solar assets during periods of oversupply that resulted in negative or near-zero pricing. Wind projects exhibited higher resilience with capacity factors around 30–35 percent, leading to EBITDA margins typically between 55–65 percent.
The Western Balkans presented a different scenario where regulatory and grid constraints shaped renewable performance more than price dynamics. In Serbia, approximately 800 MW of wind capacity generated around 2.1–2.3 TWh, achieving average capacity factors near 30–34 percent. Most Serbian wind facilities operated under support schemes or long-term contracts that secured realized prices above €90 per MWh, even as regional spot prices averaged between €70–80 per MWh. With operating costs ranging from €18–22 per MWh, Serbian wind producers reported some of the most favorable financial profiles in the region, with EBITDA yields on invested capital reaching between 18–22 percent.
The solar sector in Serbia lagged behind its regional counterparts but demonstrated strong unit economics. Utility-scale and commercial rooftop installations achieved capacity factors of 18–22 percent. The combination of avoided retail prices and incentive mechanisms led to effective revenues often exceeding €100 per MWh, resulting in minimal cash-flow volatility and standard payback periods of around 7–10 years.
The hydropower sector experienced a relatively stable year in 2025, with overall output remaining flat but revenue outcomes improving due to the flexibility that allowed producers to capitalize on higher-priced evening and balancing markets. In Croatia and Bosnia and Herzegovina, hydro assets achieved average realized prices between €85–95 per MWh. Operating costs for large hydro plants typically remained below €15 per MWh, sustaining EBITDA margins above 70 percent. However, these returns increasingly served as stabilizers rather than growth drivers due to limited new hydro capacity entering the market.
A clear divide emerged across the region between contracted and merchant renewable producers in 2025. Assets with fixed or indexed revenue frameworks exhibited low volatility and predictable cash-flow characteristics akin to bond-like investments. In contrast, merchant-exposed producers faced greater revenue variability but benefited from significant intraday and cross-border price spreads when weather conditions diverged across Southeast European markets. The growing significance of regional interconnectors facilitated this effect by enabling renewable producers to exploit geographic price differences.
The financial landscape for renewable electricity producers confirmed that they can sustain equity returns within the high single-digit to low double-digit range despite increasing market penetration. Wind assets demonstrated resilience regarding price formation and cash-flow stability; however, solar assets increasingly required contractual safeguards or integration with storage solutions. Meanwhile, hydropower continued to underpin system economics with exceptional margins but limited growth potential.
This evolution signifies that Southeast Europe’s renewable energy sector has decisively transitioned beyond mere development narratives. By 2025, operational discipline, market integration, and strategic portfolio structuring have become more critical than access to subsidies. Producers leveraging combinations of wind, solar, and flexible assets across multiple markets are better positioned to stabilize revenues and protect returns—transforming the region into a structurally profitable renewable power market rather than viewing it solely as a peripheral zone in the energy transition.
