The renewable energy landscape in Southeast Europe is witnessing a significant transformation as the region’s installed capacity for solar and wind continues to expand. By 2030, the combined capacity of solar and wind installations across Romania, Bulgaria, Greece, and Serbia is projected to exceed 15–20 GW, with solar expected to account for approximately 60–65% of these new additions. This trend is largely driven by lower capital expenditures (CAPEX) and expedited permitting processes for solar projects, which are being realized at costs between €0.6–0.9 million per MW, compared to onshore wind installations that range from €1.2–1.6 million per MW.
Despite the cost advantages associated with solar technology, its revenue potential is increasingly hampered by its generation profile. Solar production tends to peak around midday, coinciding with a decline in market prices as supply outstrips demand. In Greece, for instance, midday prices during high irradiation periods can plummet to between €30–50/MWh, with extreme cases nearing zero pricing. Similar trends are emerging in Bulgaria and Romania, particularly in areas with significant solar development such as southern Bulgaria and Dobrogea.
This temporal concentration results in capture price discounts for solar energy. While average baseload market prices across the region hover between €80–100/MWh, solar capture prices can dip to €60–75/MWh, reflecting discounts that vary by location and penetration levels. In saturated markets, particularly in parts of Greece and Bulgaria, these discounts can exceed €30/MWh, leading to substantial revenue losses for solar projects.
Curtailment further exacerbates these challenges. In regions where grid infrastructure has not kept pace with rapid generation growth, system operators are often forced to restrict output during peak solar generation periods. Curtailment rates of 10–20% are becoming commonplace, with extreme scenarios reaching up to 25–30%. For a typical 100 MW solar facility, this could result in an annual loss of 15–40 GWh, equating to a revenue shortfall of €1.0–3.0 million.
In contrast, wind energy exhibits a more favorable operational profile. Capacity factors in the region range from 30–45% for wind compared to just 15–22% for solar, indicating more consistent output throughout the day. Wind generation aligns better with demand patterns and avoids the midday oversupply that depresses solar prices, resulting in wind capture prices that are typically higher—often between €75–95/MWh, compared to solar.
Curtailment rates for wind are also significantly lower. In well-connected areas such as Romania’s Dobrogea or northern Serbia, curtailment remains at around 3–8%, increasing to about 10–15% in more congested regions. This combination of higher capture prices and reduced curtailment contributes to greater revenue stability for wind projects.
The financial implications of these operational differences are stark. A 100 MW solar project located in a moderately constrained area may yield annual revenues between €8–12 million, factoring in capture discounts and curtailment losses. With operating costs estimated at €1.0–1.5 million, this leads to an EBITDA range of €7–10 million. Assuming a debt financing structure at 65% leverage, equity internal rates of return (IRRs) typically fall between 7–10%.
A similar-sized wind project, however, can generate annual revenues ranging from €18–25 million, bolstered by higher capacity factors and capture prices. After accounting for operating costs between €3–4 million, EBITDA can reach between €15–21 million. With comparable leverage ratios, equity IRRs can achieve levels between 11–13%, reflecting a stronger resilience against adverse market conditions due to lower exposure to price volatility.
Lending practices are evolving in response to these diverging profiles. Solar projects situated in constrained areas face stricter debt sizing limits, often capped at 50–60%, unless supplemented by energy storage solutions or long-term contracts. Debt service coverage ratios (DSCR) are generally set at around 1.40–1.60x. Conversely, wind projects can maintain leverage ratios of up to 65–75%, with DSCR thresholds ranging from 1.25–1.35x.
The integration of hybrid systems is emerging as a strategic response to the limitations faced by solar technologies. By incorporating battery storage alongside solar installations, operators can shift generation from low-price midday periods to higher-value evening demand peaks. For example, pairing a 100 MW solar plant with a 50 MW / 200 MWh battery could enhance effective capture prices by approximately €10–20/MWh. Although this entails additional investments estimated between €80–120 million, it could improve project IRRs by about 2–4 percentage points.
The economic viability of hybrid systems is heavily influenced by market dynamics and price volatility. In Greece, where intraday price spreads may reach as high as €60–100/MWh, integrating storage becomes particularly appealing. Romania and Bulgaria also present opportunities with spreads ranging from €30–70/MWh, although returns here depend more critically on operational efficiency.
The role of industrial consumers is another factor influencing revenue stability through long-term power purchase agreements (PPAs). Wind projects tend to support baseload or near-baseload PPAs priced around €75–95/MWh, closely aligning with industrial demand patterns. In contrast, solar projects without storage often rely on profile-based PPAs at lower prices or require additional mechanisms for supply consistency.
The interaction between technology types and their geographical locations plays a pivotal role in shaping financial outcomes. In northern regions like Vojvodina (Serbia) or western Romania, enhanced interconnection reduces both curtailment rates and capture price discounts, thereby improving the economics of solar projects. Conversely, southern regions such as Greece and southern Bulgaria continue to favor wind due to its generation profile that mitigates exposure to midday oversupply.
The anticipated development of grid infrastructure aims to alleviate some disparities between technologies; planned transmission investments ranging from €300–500 million per corridor could enhance capacity and diminish congestion effects on solar curtailment rates by approximately 5–10 percentage points. However, ongoing growth in solar capacity may offset these improvements, suggesting persistent differences between operational models.
This divergence between wind and solar technologies is prompting investors to reevaluate their strategies within the renewable sector. Decision-making now extends beyond simple CAPEX considerations; investors increasingly assess projects based on their capture profiles, curtailment risks, and potential for integration into broader energy systems. Wind assets are typically viewed as core investments providing stable returns while supporting higher leverage financing structures; conversely, solar projects are perceived as more complex investments requiring active management strategies.
The emergence of trading platforms such as Electricity.Trade enhances market transparency by offering critical data on capture prices and congestion patterns, enabling developers to refine their revenue modeling approaches effectively.
The renewable energy expansion narrative across Southeast Europe is nuanced rather than uniform; it reflects varying outcomes influenced by technology selection, geographic positioning, and system integration capabilities. While solar may dominate installed capacity due to its cost-effectiveness and scalability advantages, wind retains significant value owing to its superior alignment with demand dynamics and reduced vulnerability to infrastructural constraints.
This evolving landscape suggests that as renewable penetration increases within the region, the disparities will likely intensify further—resulting in distinct economic niches for each technology rather than direct competition on equal footing.
The strategic decision-making process regarding whether to invest in solar or wind technologies now encompasses considerations related not only to resource availability but also how best to navigate an increasingly constrained and volatile grid environment.
