In 2025, renewable electricity producers in Southeast Europe (SEE) transitioned from a protected segment to central players in regional power markets, influencing wholesale pricing and system stability. This year marked a pivotal shift, with renewable sources such as wind, solar, and hydro becoming integral to the region’s energy landscape. The assessment of their performance now encompasses not only capacity growth but also crucial factors such as operating margins, realized prices, and cash-flow stability.
Renewable electricity production across SEE saw an increase of approximately 9–12 percent year-on-year, primarily driven by wind energy expansions in Romania and Greece alongside significant solar capacity growth in Bulgaria, Greece, and Croatia. Hydropower output remained stable compared to 2024, with varying hydrological conditions affecting different areas. Notably, the market absorbed much of this additional renewable output without heavy reliance on state interventions, indicating a maturing energy system.
Romania solidified its position as the leading market for renewable electricity performance within SEE. Wind farms exceeded 3.1 GW of installed capacity, generating between 6.8–7.4 TWh annually depending on site conditions. Average capacity factors for wind ranged from 28–33 percent, with top-performing assets in Dobrogea achieving higher rates. Despite increased market penetration, realized prices for wind improved; long-term contracts yielded stable revenues of €80–95 per MWh, while merchant producers achieved prices of €75–85 per MWh. With operating costs below €20 per MWh, EBITDA margins often surpassed 60 percent, resulting in equity cash yields between 9–12 percent.
Bulgaria’s solar sector faced challenges in 2025 due to price cannibalization during peak generation hours. Installed solar capacity surpassed ~4 GW, causing midday wholesale prices to drop to between €30–45 per MWh. While utility-scale solar plants experienced revenue compression despite favorable irradiation and capacity factors of 18–21 percent, those with fixed-price agreements maintained stable cash flows. Typical operational expenditures for solar were around €8–12 per MWh, allowing contracted projects to maintain EBITDA margins between 45–60 percent.
Greece showcased advanced renewable integration, with wind and solar covering 45–55 percent of hourly electricity demand. Producers under Greece’s support framework secured effective prices ranging from €85–100 per MWh. However, merchant exposure was more volatile due to extreme midday oversupply events resulting in negative or near-zero pricing. Wind projects typically achieved EBITDA margins between 55–65 percent, while solar margins varied from 40 to over 60 percent, depending on contract types.
The Western Balkans presented a different scenario where performance was less affected by price cannibalization but rather constrained by grid limitations and regulatory frameworks. In Serbia, approximately 800 MW of wind capacity generated around 2.1–2.3 TWh, with average capacity factors near 30–34 percent. Many Serbian wind assets benefitted from support schemes that ensured realized prices above €90 per MWh, significantly higher than the regional average of €70–80 per MWh. Operating costs ranged from €18–22 per MWh, leading to robust EBITDA yields often reaching between 18–22 percent.
The solar sector in Serbia lagged behind others in scale but excelled in unit economics; utility-scale systems achieved capacity factors of 18–22 percent. Effective revenues for behind-the-meter producers frequently exceeded €100 per MWh, with minimal cash-flow volatility and standard payback periods of around 7-10 years.
The hydropower sector across SEE experienced a neutral year overall; while aggregate production remained flat, revenue outcomes improved thanks to flexibility that allowed selling into higher-priced evening markets. In Croatia and Bosnia and Herzegovina, hydro facilities achieved average realized prices between €85-95 per MWh —considerably above long-term averages—with low operational costs sustaining EBITDA margins above 70 percent.
A stark divide emerged between contracted and merchant renewable producers throughout the region; those with fixed or indexed revenue models enjoyed low volatility and predictable cash flows akin to bond-like returns. Conversely, merchant-exposed producers faced greater revenue variability but capitalized on significant price spreads due to weather-related divergences across SEE markets. The importance of regional interconnectors further enhanced this dynamic by enabling indirect arbitrage opportunities.
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 penetration levels. Wind assets demonstrated resilience concerning pricing stability and cash flow consistency; however, solar assets increasingly require contractual safeguards or storage solutions for viability while hydropower continues to provide exceptional margins albeit with limited growth prospects.
This evolution signifies that renewables in Southeast Europe have transitioned beyond mere development narratives; by 2025, success hinges more on operational efficiency, market integration strategies, and diversified portfolios rather than dependency on subsidies alone. Producers adept at combining various renewable sources across multiple markets are better positioned to stabilize revenues and enhance returns, thereby establishing the region as a viable player in the global renewable energy market.
