The expansion of renewable capacity across South-East Europe is often presented as a unified transition story, with solar and wind treated as interchangeable building blocks of decarbonisation. In practice, the two technologies are diverging in both operational behaviour and financial outcomes. The divergence is not marginal; it is structural, shaping capture prices, curtailment exposure, financing conditions and ultimately the allocation of capital across the region.
Installed capacity is growing rapidly. Across Romania, Bulgaria, Greece and Serbia, combined solar and wind additions are expected to exceed 15–20 GW by 2030, with solar accounting for roughly 60–65% of new installations due to lower CAPEX and faster permitting cycles. Solar utility-scale projects are being delivered at €0.6–0.9 million per MW, while onshore wind ranges between €1.2–1.6 million per MW, depending on turbine specifications, logistics and grid connection requirements.
Despite this CAPEX advantage, solar’s revenue profile is increasingly constrained by its temporal concentration. Generation is clustered around midday, coinciding with declining marginal prices as penetration increases. In Greece, where solar additions have accelerated, midday prices during high irradiation periods frequently fall to €30–50/MWh, with extreme events approaching zero pricing. In Bulgaria and Romania, similar dynamics are emerging, particularly in regions with dense solar pipelines such as southern Bulgaria and Dobrogea.
This concentration leads to capture price discounts. While baseload market prices across the region may average €80–100/MWh, solar capture prices can fall to €60–75/MWh, implying a discount of €10–25/MWh depending on location and penetration levels. In saturated nodes, particularly in Greece and parts of Bulgaria, the discount can exceed €30/MWh, significantly eroding project revenues.
Curtailment compounds this effect. Grid constraints, particularly in southern markets where transmission capacity lags generation growth, force system operators to limit output during peak solar periods. Curtailment levels of 10–20% are increasingly common, with extreme scenarios reaching 25–30% in constrained zones. For a 100 MW solar plant, this translates into a loss of 15–40 GWh annually, equivalent to €1.0–3.0 million in foregone revenue at prevailing prices.
Wind generation follows a different profile. Capacity factors across the region range between 30–45%, compared to 15–22% for solar, reflecting more consistent output across day and night. Wind production is less concentrated, aligning better with demand patterns and avoiding the midday oversupply that depresses solar prices. As a result, wind capture prices are typically €10–20/MWh higher than solar, often reaching €75–95/MWh in markets where baseload prices are in the €85–105/MWh range.
Curtailment for wind is also lower. In well-connected regions such as Romania’s Dobrogea or Serbia’s northern corridors, curtailment remains in the 3–8% range, rising to 10–15% in more constrained zones. The combination of higher capture prices and lower curtailment results in significantly stronger revenue stability.
These operational differences translate directly into financial outcomes. A 100 MW solar project in a moderately constrained node, with CAPEX of €70–80 million, may generate annual revenues of €8–12 million after accounting for capture discounts and curtailment. Assuming operating costs of €1.0–1.5 million per year, EBITDA falls in the €7–10 million range. With debt financing at 65% leverage and interest margins of 300–400 bps, equity IRRs typically fall between 7–10%, depending on price assumptions and mitigation measures.
By contrast, a 100 MW wind project with CAPEX of €130–150 million can generate €18–25 million in annual revenues, supported by higher capacity factors and capture prices. After operating costs of €3–4 million, EBITDA reaches €15–21 million. With similar leverage, equity IRRs in the 11–13% range are achievable, with stronger resilience under downside scenarios due to lower exposure to price compression and curtailment.
Lenders are increasingly differentiating between these profiles. Solar projects in constrained zones face tighter debt sizing, with leverage often capped at 50–60% unless supported by storage or long-term contracts. Debt service coverage ratios are typically set at 1.40–1.60x, reflecting higher revenue volatility. Wind projects, by contrast, can sustain leverage of 65–75% with DSCR thresholds of 1.25–1.35x, reflecting more stable cash flows.
Hybridisation is emerging as the primary response to solar’s structural limitations. Co-located battery storage systems enable solar projects to shift generation from low-price midday periods to higher-value evening peaks. A 100 MW solar plant paired with a 50 MW / 200 MWh battery can increase effective capture prices by €10–20/MWh, offsetting a significant portion of the discount. At battery CAPEX levels of €400–600 per kWh, this implies an additional investment of €80–120 million, but the incremental revenue can lift project IRRs by 2–4 percentage points, restoring competitiveness with wind.
The economics of hybrid systems depend heavily on market structure and volatility. In Greece, where intraday spreads can reach €60–100/MWh, storage integration is particularly attractive. In Romania and Bulgaria, spreads of €30–70/MWh still provide sufficient arbitrage potential to justify investment, though returns are more sensitive to utilisation rates and operational efficiency.
Industrial offtake introduces another dimension. Long-term PPAs with industrial consumers can stabilise revenues for both solar and wind projects, but the underlying profiles influence contract pricing. Wind projects, with more consistent output, can support baseload or near-baseload PPAs at €75–95/MWh, aligning closely with industrial demand patterns. Solar projects, particularly without storage, are typically limited to profile-based PPAs at lower prices or require firming mechanisms to deliver consistent supply.
The interaction between technology and grid location is critical. In northern zones such as Vojvodina (Serbia) or western Romania, stronger interconnection and lower congestion reduce both curtailment and capture discounts, improving solar economics. In southern zones, particularly in Greece and southern Bulgaria, wind retains a structural advantage due to its generation profile and reduced exposure to midday oversupply.
Grid development is expected to moderate some of these differences. Transmission investments of €300–500 million per corridor are planned to increase capacity and reduce congestion, potentially lowering solar curtailment rates by 5–10 percentage points in key regions. However, these improvements will be offset by continued growth in solar capacity, meaning that relative differences between technologies are likely to persist.
From an investor perspective, the divergence between wind and solar is reshaping portfolio strategies. Rather than allocating capital based purely on CAPEX or resource availability, investors are increasingly evaluating projects based on capture profiles, curtailment risk and integration potential. Wind projects are often positioned as core assets, providing stable returns and supporting debt-heavy financing structures. Solar projects are treated as higher-risk, higher-complexity assets, requiring active management and integration with storage or trading strategies to achieve target returns.
Trading platforms such as Electricity.Trade play a central role in this environment, providing data on capture prices, intraday spreads and congestion patterns. This information allows developers to model revenue streams with greater precision, aligning project design with market realities rather than simplified assumptions.
The broader implication is that renewable expansion in South-East Europe is not a uniform process. It is a differentiated market where technology choice, location and system integration determine outcomes. Solar will continue to dominate in terms of installed capacity due to its cost advantage and scalability. Wind, however, will retain a disproportionate share of value due to its alignment with demand patterns and lower exposure to system constraints.
As the region moves toward higher levels of renewable penetration, these dynamics will intensify. Capture discounts for solar are likely to increase in the absence of sufficient storage and grid expansion, while wind’s relative advantage may strengthen. The resulting system will not be one where technologies compete on equal terms, but one where each occupies a distinct economic niche.
In this context, the decision to build solar or wind is no longer purely a question of resource or CAPEX. It is a strategic choice about how to position within a grid that is becoming more constrained, more volatile and more differentiated. The outcome of that choice is reflected not only in megawatts installed, but in euros earned and returns delivered.
