Southeast Europe’s next phase of wind investment will be assessed increasingly by the market value of the electricity produced, not just by the number of megawatts built. The shift comes as Europe accelerates wind deployment: it added 8.8 GW of new capacity in the first half of 2026, with onshore wind accounting for 74%. Installed capacity surpassed 311 GW, and WindEurope expects a further 148 GW to be added from 2026 to 2030, according to WindEurope’s latest figures.
Southeast Europe will enter this expansion from a different starting point. The region has substantial undeveloped wind potential, relatively high electricity-price volatility, strong seasonal interactions with hydropower and growing cross-border trading in several markets. But additional wind farms will not necessarily capture the same economic value.
Production profile and market value
For the first generation of wind investments, the key questions were whether the wind resource was adequate, turbines could be connected, expected annual output was sufficient and the tariff or PPA could support debt. Those considerations remain essential, but they describe only part of an asset’s value. Wind farms generate electricity according to weather rather than market demand, so they may produce most when several neighbouring projects are also operating at high output.
When plants are exposed to the same weather system, regional wind generation can rise at the same time and push wholesale prices down during high-wind periods. This creates a wind-specific form of renewable cannibalisation: annual output can match forecasts while the average price earned for those MWh declines. The captured price is therefore becoming a more important measure.
An AleaSoft analysis that prompted this discussion examines photovoltaics, but its broader point also applies to variable generation: average market prices alone cannot establish a renewable asset’s value. Production must be assessed against the hourly prices available when the plant is generating. For wind, however, timing is only part of the challenge.
Forecasting also matters. Solar output follows a relatively stable daily pattern, although cloud cover affects generation; wind output can rise or fall rapidly as weather systems move across a region. This creates greater exposure to deviations between nominated production and actual delivery.
Forecasting, connections and portfolios
A wind farm’s economics depend on three related factors: how much electricity it generates, the value of electricity during those production hours and the cost of correcting differences between forecast and actual output. Grid geography adds another consideration. Wind resources tend to cluster, leading developers to target similar locations and often rely on the same transmission corridors.
A location with the strongest wind resource may therefore become less attractive when multiple projects compete for limited network capacity. A project with somewhat weaker wind conditions, but better connection infrastructure and a production profile less correlated with other plants, may ultimately generate more stable revenues. This also affects the composition of regional portfolios.
Ten wind farms do not necessarily provide meaningful diversification if all respond to the same weather system. The key measure is meteorological correlation, not simply the distance between projects. A portfolio spanning genuinely different wind regimes may have a smoother combined production profile and potentially lower balancing costs than a larger group concentrated in one wind corridor.
Cross-border markets make those correlations more significant. Strong winds across Romania, Bulgaria, Croatia, Serbia or neighbouring Central European markets can change regional electricity flows and prices at the same time. Interconnectors can carry surplus power to other markets, but congestion may also isolate an area when its generation is at its highest.
Risk assessment for new projects
Wind project bankability increasingly depends on the combination of resource quality, market profile and grid position. The challenge differs from that of solar: solar cannibalisation is closely linked to predictable midday output, while wind exposure is more stochastic. Some periods of high wind may coincide with valuable winter demand and high prices; others may align with widespread regional oversupply.
Wind can therefore complement solar economically while retaining its own captured-price risk. The next generation of due diligence will need to account for this distinction. Lenders will continue to require P50 and P90 production forecasts, turbine availability assumptions and grid studies, but those inputs increasingly need to be linked to hourly market scenarios, regional wind correlation and balancing costs.
The task is no longer only to estimate how much electricity turbines can produce, but also how much economic value a project can retain from that output. WindEurope’s latest outlook indicates that Europe remains on track for substantial wind expansion and identifies grids and permitting as major constraints on further growth.
For Southeast Europe, this presents an opportunity as well as a warning. Wind remains one of the region’s strongest options for adding domestic generation, reducing fuel exposure and complementing solar and hydropower. As the region builds more variable renewable capacity, projects will command greater value when their production profiles, grid positions and commercial structures help preserve the value of the MWh produced by each megawatt.
