The renewable energy landscape in South-East Europe is undergoing significant transformation, marked by a pronounced divergence between wind and solar power technologies. While both are pivotal to the region’s decarbonization efforts, they exhibit distinct operational behaviors and financial outcomes that are reshaping investment strategies and market dynamics.
Installed renewable capacity is projected to expand sharply across Romania, Bulgaria, Greece, and Serbia, with total additions expected to surpass 15–20 GW by 2030. Solar energy is anticipated to account for approximately 60–65% of these new installations, driven by lower capital expenditure (CAPEX) and expedited permitting processes. Current costs for solar utility-scale projects range from €0.6–0.9 million per MW, while onshore wind projects incur costs between €1.2–1.6 million per MW, influenced by turbine specifications and logistical considerations.
Despite the favorable CAPEX associated with solar installations, their revenue potential is increasingly constrained due to generation patterns concentrated around midday. In Greece, where solar capacity has surged, midday market prices during peak irradiation often dip to €30–50/MWh, with extreme instances approaching zero pricing. Similar trends are evident in Bulgaria and Romania, particularly in areas with significant solar development like southern Bulgaria and Dobrogea.
This temporal concentration results in capture price discounts for solar energy. Although average baseload market prices across the region hover around €80–100/MWh, solar capture prices can drop to between €60–75/MWh, leading to discounts that can reach €30/MWh in oversaturated markets such as parts of Greece and Bulgaria. This situation significantly impacts project revenues as curtailment becomes a common issue due to grid constraints that limit output during peak production times.
Curtailment levels for solar projects are increasingly reported at 10–20%, with extreme cases hitting 25–30%. For a typical 100 MW solar installation, this translates into annual losses of 15–40 GWh, equating to foregone revenues of approximately €1.0–3.0 million.
In contrast, wind generation exhibits a more stable output profile with capacity factors ranging from 30–45%, compared to only 15–22% for solar. Wind production aligns more closely with demand trends and avoids the oversupply issues faced by solar energy during midday hours. Consequently, wind capture prices generally exceed those of solar by about €10–20/MWh, frequently reaching between €75–95/MWh.
Curtailment rates for wind are comparatively lower; in well-connected areas like Romania’s Dobrogea or northern Serbia, curtailment remains within the 3–8% range. This advantage translates into greater revenue stability for wind projects compared to their solar counterparts.
The financial implications of these operational differences are stark. A typical 100 MW solar project, situated in a moderately constrained area and requiring an investment of around €70–80 million, could yield annual revenues between €8–12 million. After accounting for operating costs estimated at €1.0–1.5 million annually, EBITDA would likely fall within the range of €7–10 million. This scenario typically results in equity internal rates of return (IRRs) between 7–10%.
A similar-sized wind project, however, with a CAPEX of approximately €130–150 million, may achieve annual revenues ranging from €18–25 million. Following operating expenses estimated at around €3–4 million, EBITDA could reach between €15-21 million . Under comparable financing conditions, equity IRRs can be expected in the range of 11-13%, illustrating stronger resilience against market volatility.
Lending practices are evolving as financial institutions increasingly differentiate between these energy technologies. Solar projects located in constrained regions often face stricter debt sizing limits, typically capping leverage at around 50-60%, unless bolstered by storage solutions or long-term contracts. Conversely, wind projects can sustain higher leverage ratios of 65-75%, reflecting their more stable cash flow profiles.
The integration of hybrid systems featuring co-located battery storage is emerging as a strategic solution to address the limitations faced by solar power. By enabling the shifting of energy generation from low-value midday periods to higher-value evening peaks, such systems can enhance effective capture prices by an estimated €10-20/MWh. However, this requires significant additional investment—between €80-120 million—potentially improving project IRRs by 2-4 percentage points.
The economic viability of hybrid systems is highly contingent on regional market structures and volatility levels. In Greece, where intraday price spreads can soar up to €60-100/MWh, integrating storage technology appears particularly advantageous. Meanwhile, Romania and Bulgaria present spreads ranging from €30-70/MWh that still offer sufficient arbitrage opportunities but may be more sensitive to operational efficiencies.
The role of long-term power purchase agreements (PPAs) with industrial consumers further influences revenue stability for both technologies; however, contract pricing varies based on output consistency. Wind projects typically support baseload PPAs priced at €75-95/MWh due to their reliable output patterns while solar projects often rely on profile-based PPAs that yield lower prices unless paired with firming mechanisms.
The geographical interplay between technology type and grid infrastructure plays a critical role in determining economic outcomes across the region. In northern areas like Vojvodina (Serbia) or western Romania, improved interconnections reduce curtailment risks and capture price discounts for solar installations compared to southern regions where wind maintains its competitive edge due to its favorable generation profile.
Aiming to alleviate some disparities through infrastructure investments ranging from €300-500 million per corridor will likely enhance transmission capacity and mitigate congestion challenges; however, these advancements may not fully offset ongoing increases in solar capacity growth that continue to shape relative technology performance.
The evolving landscape necessitates that investors reassess portfolio strategies beyond mere capital allocation based on resource availability or CAPEX alone; they must now consider factors such as capture profiles and curtailment risks when evaluating prospective projects within this differentiated market environment.
This shift underscores a broader trend wherein renewable expansion across South-East Europe does not follow a monolithic path but rather reflects diverse technological choices influenced heavily by location and system integration capabilities—ultimately impacting financial returns derived from each energy source.
