The renewable energy landscape in South-East Europe is undergoing significant transformation, marked by a pronounced divergence between solar and wind technologies. As countries like Romania, Bulgaria, Greece, and Serbia ramp up their renewable capacity, the total installed capacity of solar and wind is projected to exceed 15–20 GW by 2030. Solar energy is anticipated to dominate this growth, accounting for approximately 60–65% of new installations, driven by lower capital expenditures (CAPEX) and expedited permitting processes.
Utility-scale solar projects are being developed at costs ranging from €0.6–0.9 million per MW, while onshore wind projects typically incur costs between €1.2–1.6 million per MW. Despite solar’s cost advantage, its revenue potential is increasingly limited due to the temporal concentration of generation. In regions with high solar penetration, such as Greece, midday electricity prices can plummet to €30–50/MWh, with extreme cases nearing zero pricing during peak irradiation periods.
This phenomenon leads to significant capture price discounts for solar energy. While average baseload prices in the region hover around €80–100/MWh, solar capture prices often fall to €60–75/MWh, reflecting discounts of €10–25/MWh. In saturated nodes within Greece and Bulgaria, these discounts can exceed €30/MWh, adversely affecting project revenues.
Curtailment exacerbates these challenges, particularly in southern markets where grid constraints limit 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 plant, 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 favorable operational profile. Capacity factors for wind range from 30–45%, compared to just 15–22% for solar. This results in more consistent output that aligns better with demand patterns, mitigating the midday oversupply that depresses solar prices. Consequently, wind capture prices are generally higher—by about €10–20/MWh—often reaching between €75–95/MWh.
Curtailment rates for wind are also notably lower; in well-connected areas like Dobrogea in Romania or northern Serbia, curtailment remains between 3–8%, increasing to 10–15% in more constrained regions. The 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 situated in a moderately constrained area may generate annual revenues of around €8–12 million, resulting in EBITDA figures between €7–10 million. With debt financing at approximately 65% leverage, equity internal rates of return (IRRs) typically fall within the range of 7–10%.
A comparable 100 MW wind project, however, can achieve annual revenues of between €18–25 million, driven by its higher capacity factors and capture prices. After accounting for operating costs estimated at €3–4 million, EBITDA can reach between €15–21 million. Under similar financing conditions, equity IRRs can be expected in the range of 11–13%, showcasing greater resilience against price volatility and curtailment risks.
Lending practices are adapting to these emerging dynamics. Solar projects located in constrained areas face stricter debt sizing criteria, often limiting leverage to between 50-60%. Conversely, wind projects can sustain leverage levels of up to 65-75%, reflecting their more stable cash flow profiles.
The integration of hybrid systems is gaining traction as a strategic response to the limitations faced by solar technologies. Co-located battery storage systems allow for the shifting of generation from low-price midday hours to higher-value evening peaks. A hybrid setup involving a 100 MW solar plant coupled with a 50 MW / 200 MWh battery could enhance effective capture prices by an estimated €10-20/MWh, thereby improving competitiveness with wind.
The economic viability of such hybrid systems is contingent on market structures and volatility. In Greece, where intraday price spreads can reach up to €60-100/MWh, integrating storage becomes particularly appealing. Meanwhile, Romania and Bulgaria present spreads between €30-70/MWh, which still offer sufficient arbitrage opportunities but require careful management of operational efficiency.
The role of industrial off-takers further complicates the revenue landscape for both technologies. Long-term power purchase agreements (PPAs) with industrial consumers can stabilize revenues; however, the differing output profiles affect contract pricing dynamics. Wind projects are better positioned for baseload PPAs priced at around €75-95/MWh, while solar projects often necessitate profile-based PPAs at lower rates unless paired with storage solutions.
The geographical interplay between technology and grid infrastructure is crucial. In northern areas like Vojvodina (Serbia) or western Romania, improved interconnections reduce both curtailment and capture price discounts for solar projects. Conversely, southern regions such as Greece and Bulgaria maintain a structural advantage for wind due to its generation characteristics.
The anticipated investments in grid development—estimated at between €300-500 million per corridor—aim to enhance transmission capacity and alleviate congestion issues. While these improvements may reduce curtailment rates by approximately 5-10 percentage points, they will likely be counterbalanced by the ongoing increase in solar capacity across the region.
This evolving landscape necessitates a reevaluation of investment strategies within the renewable sector. Decision-makers are increasingly assessing projects based on their capture profiles, curtailment risks, and integration capabilities rather than solely on CAPEX or resource availability. Wind projects are increasingly viewed as core assets due to their stable returns and favorable financing conditions, while solar projects require more active management approaches to meet targeted returns amidst growing complexity.
The implications extend beyond individual project economics; they reshape portfolio strategies across the region’s energy landscape. As market participants adapt to these dynamics, platforms providing data on capture prices and congestion patterns become essential tools for aligning project designs with real market conditions.
The renewable expansion narrative in South-East Europe is thus far from uniform; it reflects a complex interplay where technology selection, geographic positioning, and system integration critically influence outcomes. While solar will likely lead in terms of installed capacity due to its cost efficiency and scalability, wind will continue to command a significant share of market value owing to its compatibility with demand patterns and reduced exposure to systemic constraints.
The trajectory toward increased renewable penetration will further accentuate these trends. Without adequate storage solutions or grid enhancements, capture discounts for solar may intensify while wind’s advantages could solidify further. Ultimately, stakeholders must recognize that decisions regarding investments in either technology represent strategic choices shaped by an increasingly constrained and differentiated grid environment.
