Developers in Romania, Bulgaria, Greece and Serbia are finding that the region’s renewable build-out is not delivering uniform returns across technologies. While solar and wind are both expanding quickly, their operating patterns are producing different market outcomes—especially around midday pricing, grid congestion and the way lenders underwrite revenue risk. As a result, engineering design, battery integration planning and EPC preparation are increasingly tied to where projects connect and how they will be dispatched.
Renewables pipeline accelerates, but solar dominates new capacity
Across Romania, Bulgaria, Greece and Serbia, combined solar and wind additions are expected to exceed 15–20 GW by 2030. Solar is projected to account for roughly 60–65% of new installations, supported by lower CAPEX and faster permitting cycles. Utility-scale solar projects are being delivered at €0.6–0.9 million per MW, while onshore wind sits at €1.2–1.6 million per MW depending on turbine specifications, logistics and grid connection requirements.
This cost-led build rate is now colliding with system-level constraints that affect how each technology earns revenue once it is online. For project teams, the implication is that early-stage feasibility studies must treat market capture and curtailment exposure as core inputs rather than secondary sensitivities.
Midday concentration pressures solar capture prices
Solar’s revenue profile is increasingly constrained by temporal concentration: generation clusters around midday as penetration rises and marginal prices decline. In Greece, midday prices during high irradiation periods frequently fall to €30–50/MWh, with extreme events approaching zero pricing. Similar dynamics are emerging in Bulgaria and Romania, particularly where solar pipelines are dense such as southern Bulgaria and Dobrogea.
These patterns translate into capture price discounts. While baseload market prices across the region may average €80–100/MWh, solar capture prices can fall to €60–75/MWh—an implied discount of €10–25/MWh depending on location and penetration levels. In saturated nodes in Greece and parts of Bulgaria, the discount can exceed €30/MWh, materially eroding expected cash flows for new builds.
Curtailment risk adds another layer of downside for solar
Grid constraints intensify the challenge during peak solar periods when transmission capacity lags generation growth in southern markets. Curtailment levels of 10–20% are increasingly common, with extreme scenarios reaching 25–30% in constrained zones. For a 100 MW solar plant, this can mean a loss of 15–40 GWh annually.
At prevailing prices, that curtailment exposure equates to €1.0–3.0 million in foregone revenue for a single project scale reference point. For engineering studies and grid interface planning, it elevates the importance of congestion analysis during site selection and of curtailment mitigation options during design.
Wind’s output profile supports higher capture prices and steadier delivery
Wind generation behaves differently across the same markets because output is less concentrated around midday. Capacity factors range between 30–45% for wind compared with 15–22% for solar, reflecting more consistent production across day and night. This alignment with demand patterns helps avoid the midday oversupply that depresses solar prices.
As a result, wind capture prices are typically €10–20/MWh higher than solar and often reach €75–95/MWh in markets where baseload prices fall in the €85–105/MWh band. Curtailment is also lower: in well-connected regions such as Romania’s Dobrogea or Serbia’s northern corridors it remains in the 3–8% range, rising to 10–15% only in more constrained zones.
From feasibility to financing: how operational differences flow into IRRs
The technology-driven divergence shows up directly in project economics used for investment committee decisions. 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. With operating costs of €1.0–1.5 million per year, EBITDA falls into the €7–10 million range.
Under debt financing at 65% leverage with interest margins of 300–400 bps, equity IRRs typically land between 7–10%, depending on price assumptions and mitigation measures included in the model. By contrast, a 100 MW wind project with CAPEX of €130–150 million can generate €18–25 million annually supported by higher capacity factors and capture prices; after operating costs of €3–4 million per year, EBITDA reaches €15–21 million.
With similar leverage assumptions, equity IRRs in the 11–13% range are achievable for wind projects. The underwriting logic reflects stronger resilience under downside scenarios due to lower exposure to price compression and curtailment—an effect that becomes especially relevant when lenders stress-test revenue volatility.
Lenders tighten terms for constrained solar while supporting wind leverage
Financing structures are increasingly technology- and location-sensitive as banks differentiate between revenue profiles shaped by dispatch outcomes. Solar projects in constrained zones face tighter debt sizing: leverage is 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 to reflect higher revenue volatility tied to capture discounts and curtailment risk.
Wind projects can sustain leverage of 65–75%, with DSCR thresholds of 1.25–1.35x reflecting more stable cash flows under prevailing market conditions. For developers preparing procurement packages and EPC scopes, this affects how early they must lock down grid studies outcomes and contract structures that improve bankability.
BESS hybridisation becomes a planning lever for solar competitiveness
Hybridisation is emerging as the primary response to solar’s structural limitations through co-located battery energy storage systems designed to shift output from low-price midday periods toward higher-value evening peaks. A reference configuration of a 100 MW solar plant paired with a 50 MW / 200 MWh battery can increase effective capture prices by €10–20/MWh by improving time alignment with market value windows.
At battery CAPEX levels of €400–600 per kWh, this implies an additional investment of €80–120 million for that scale pairing. The incremental revenue can lift project IRRs by 2–4 percentage points, helping restore competitiveness relative to wind when modeled against capture discounts.
Storage economics depend on intraday spreads and operational utilisation
The value case for BESS integration depends heavily on market structure and volatility rather than only on resource complementarity. In Greece, where intraday spreads can reach €60–100/MWh, storage integration is particularly attractive from an arbitrage perspective. In Romania and Bulgaria spreads of €30–70/MWh still provide sufficient arbitrage potential to justify investment.
However returns become more sensitive to utilisation rates and operational efficiency—factors that must be reflected in technical studies covering dispatch strategy assumptions, degradation considerations at an engineering level and performance guarantees during EPC preparation.
PPA design varies by technology profile
Industrial offtake adds another dimension through long-term PPAs intended to stabilise revenues for both solar and wind projects while reflecting underlying generation profiles in contract pricing. Wind projects’ more consistent output can support baseload or near-baseload PPAs at €75–95/MWh aligned with industrial demand patterns. Solar projects without storage are typically limited to profile-based PPAs at lower prices or require firming mechanisms to deliver consistent supply.
This distinction matters for procurement frameworks because contract terms influence how developers structure ancillary services participation assumptions, curtailment handling clauses and performance obligations tied to dispatchability.
Grid location remains decisive even as transmission plans progress
The interaction between technology performance and grid location continues to shape both curtailment outcomes and capture discounts during operations planning. In northern zones such as Vojvodina (Serbia) or western Romania, stronger interconnection and lower congestion reduce both curtailment exposure for solar economics improvement opportunities. In southern zones including Greece and southern Bulgaria, wind retains a structural advantage due to its generation profile reducing exposure to midday oversupply effects.
Transmission development is expected to moderate some differences: planned investments of €300–500 million per corridor aim to increase capacity and reduce congestion potentially lowering solar curtailment rates by 5–10 percentage points in key regions. Yet continued growth in solar capacity may offset part of those gains, meaning relative technology advantages may persist even after upgrades come online.
Implications for developers, EPC teams and investors
The divergence between wind and solar is reshaping portfolio strategies across South-East Europe beyond simple CAPEX comparisons or resource availability assessments. Developers increasingly evaluate projects using capture profiles, curtailment risk metrics and integration potential—especially when preparing engineering studies that feed into bankability models used by lenders during financing approvals.
EPC preparation also becomes more complex where BESS hybridisation is required: teams must coordinate grid interface design with storage dispatch requirements while ensuring procurement scopes align with performance expectations under volatile intraday conditions. Trading platforms such as Electricity.Trade play a role by providing data on capture prices, intraday spreads and congestion patterns used to refine revenue modelling beyond simplified assumptions.
Broader industry outlook: differentiated market outcomes likely intensify
The region’s renewable expansion is therefore not uniform; it is differentiated by technology choice, location constraints and system integration realities that determine outcomes once assets enter operation. Solar should continue leading installed capacity due to cost advantage and scalability, but its value proposition becomes increasingly dependent on mitigating midday price compression through storage or contractual structures that address firming needs.
Wind’s relative advantage appears likely to strengthen as penetration rises because its output profile better matches demand patterns while maintaining lower curtailment exposure in many corridors. Overall project selection across utilities, contractors and industrial stakeholders will increasingly reflect how engineering design decisions translate into euros earned—and ultimately returns delivered—within a more constrained but modernising grid system.