Wind power is acquiring greater strategic value in Southeast Europe—not because it has become easier to develop, but because solar’s rapid expansion has made generation outside the midday photovoltaic window more valuable. July’s price movements demonstrate the commercial advantage of a more diversified renewable profile, while project announcements across Romania, Bulgaria, Greece and Türkiye show that investors are responding. The main constraint is no longer interest in wind. It is the speed at which projects can obtain permits, grid access and bankable support.
July’s power curve rewards renewable diversity
A regional market monitor estimated solar generation at 8,518 MW for July 20 delivery, compared with only 1,467 MW of wind, with wind output down 290 MW from the previous day. Solar reduced prices around midday, but weaker wind and the disappearance of photovoltaic generation contributed to evening prices of approximately €190/MWh in Romania, Bulgaria and Greece and €210/MWh in Serbia.
The preceding weekly balance pointed in the same direction. During Week 27, monitored Southeast European wind generation fell by 5.1%, while solar declined by 1.8% and hydropower by 3.4%. Net imports into the monitored region increased by 28.2%, with thermal plants filling more of the shortfall. These numbers are operational snapshots rather than proof of a permanent wind premium, but they show why low-wind periods become particularly expensive once solar disappears after sunset.
Wind does not always generate during peak hours, and windy conditions can eventually cannibalize wind prices as installed capacity rises. For now, however, Southeast Europe has substantially more solar concentration than wind concentration. The marginal wind project therefore offers buyers and power systems a production profile that is less correlated with the region’s most oversupplied hours.
Wind is capturing materially more value than solar
ENTSO-E’s market-value indicators provide a structural benchmark. For the period from June 1, 2025, to June 1, 2026, the calculated wind capture price was €108/MWh in Croatia, €107/MWh in Bulgaria, €105/MWh in Romania and €88/MWh in Greece. The equivalent photovoltaic values were €69/MWh, €57/MWh, €58/MWh and €43/MWh, respectively.
Wind’s profile value was consequently between €39/MWh and €50/MWh higher than solar’s across those four markets. ENTSO-E concluded that wind experienced less price cannibalization than photovoltaics during the measurement period. The indicators do not include annual wind yield, capital costs or site-specific resource quality, so they should not be interpreted as project returns. They nevertheless demonstrate that the regional market is currently paying more for the timing of wind generation.
This changes the investment conversation. Solar may remain faster and simpler to construct, but wind can provide a stronger capture profile, seasonal diversification and a natural hedge against a portfolio dominated by daytime photovoltaic output.
Romania is seeing capital rotate toward wind
Romania provides the clearest evidence of a shift in investor interest. Rapid improvements in solar permitting produced short development timelines and a growing supply of photovoltaic projects. Industry participants now describe the solar market as increasingly favorable to buyers, while competition for wind assets is intensifying. The Romanian government has also adjusted renewable-auction allocations to steer more support toward wind.
That rotation does not mean Romanian wind is easy to deliver. Wind projects generally face longer environmental, planning and grid-connection processes than solar. Grid congestion remains a central obstacle, and the transition to auction-based grid-capacity allocation will raise the importance of financial guarantees and project maturity.
Corporate procurement is nevertheless creating a route to market. In March, Rezolv Energy signed a ten-year virtual power purchase agreement under which a Bulgarian industrial consumer will procure power associated with the 461 MW Vifor wind farm in Romania. The buyer already had a Bulgarian solar PPA and added wind specifically to improve the balance of its renewable supply profile. The transaction was described as Bulgaria’s first publicly announced cross-border wind PPA.
One contract does not yet constitute a liquid regional market, but it validates a potentially important model: companies in solar-heavy markets can contract wind generation across national borders to reduce hourly concentration and improve renewable coverage.
Bulgaria has a large pipeline but a slow conversion rate
Bulgaria’s wind market shows the difference between development potential and deliverable capacity. The Bulgarian wind industry reports a pipeline of approximately 4 GW, with some projects reaching advanced development and financing stages. Its association expects around 200 MW to become operational by the end of 2027 and believes at least half of the pipeline could be completed by 2030.
At the same time, Bulgarian wind projects typically require four to five years to reach ready-to-build status. Industry representatives cite slow permitting reforms and limited institutional support and have called for contracts for difference to provide a predictable route to market.
The pipeline should therefore not be treated as imminent supply. Indeed, the slow conversion of announced projects into operating wind farms helps explain wind’s continuing scarcity value. The assets likely to attract the strongest investor demand are those that already possess environmental approvals, defensible land rights, grid capacity and a credible PPA or support contract.
Greece advances offshore wind—but transfers curtailment risk to investors
Greece delivered the region’s most important July offshore-wind policy development. A ministerial decree increased planned offshore capacity to 2.35 GW, compared with 1.9–2 GW in the national energy plan, and assigned capacity to individual zones. The plan includes 600 MW of pilot projects off Thrace, 250 MW near Crete, 500 MW around the Dodecanese, 500 MW around the Cyclades and Gulf of Euboea, and 200 MW in the Gulf of Patras. Grid-connection points were also identified.
Most projects are expected to compete for contracts for difference, while the 600 MW pilot tranche would receive feed-in tariffs. However, the government did not grant offshore projects protection against curtailment. They would be curtailed under the same general framework as other renewable generators.
The decree is a policy and market-design signal, not a near-term supply addition. Surveys, auction preparation, permitting, grid investment and construction remain ahead. The absence of curtailment protection is particularly significant for capital-intensive offshore projects: bidders will need to price that risk into their required returns, financing structures and auction offers.
Türkiye supplies the regional scale and financing benchmark
Türkiye remains the wider region’s scale market. In July, the government announced a 2.4 GW renewable-energy auction round, of which 1.5 GW is reserved for seven wind projects. Bids are scheduled for October 13. As of May, Türkiye had 15.1 GW of wind and 26.9 GW of photovoltaic capacity connected to the grid.
Financing activity indicates that auction-backed wind projects can still reach construction. FMO and Germany’s DEG agreed to provide Enerjisa Üretim with a $180 million package for three wind farms totaling 250 MW in Muğla. The projects are already under construction and scheduled to begin operating during 2026. The financing has an eight-year tenor and supports projects awarded under the YEKA state-support mechanism.
Türkiye’s model is not directly transferable to every Southeast European market, but it illustrates what smaller markets frequently lack: recurring auction volumes, predefined grid locations, an industrial-scale development pipeline and financing structures capable of moving awarded capacity into construction.
Western Balkan grid constraints reinforce the premium for mature projects
In the Western Balkans, wind growth remains closely tied to transmission policy. Serbia’s decision not to process connection-study applications for large new wind and solar projects until 2029 materially slows the next development cycle. Because wind already has longer lead times than photovoltaics, such delays are particularly consequential.
The likely commercial result is a widening valuation gap between early-stage pipelines and projects holding advanced permits or grid rights. Acquiring a nominal megawatt of planned wind capacity is not equivalent to acquiring a project capable of entering construction.
Wind will command value, but capacity additions will remain uneven
Southeast European wind is positioned to retain a profile advantage as long as solar capacity expands more quickly than wind and storage. Corporate buyers will increasingly combine the technologies rather than choose between them, using solar for low-cost daytime electricity and wind to broaden hourly and seasonal coverage.
Yet a strong capture price does not remove development risk. The near-term market will favor permitted and grid-secured onshore projects, assets supported by contracts for difference or long-term PPAs, and cross-border structures that connect wind-rich markets with industrial demand elsewhere in the region. Offshore wind offers substantial strategic potential, but remains a longer-duration option requiring policy stability, survey work and significant network investment.
July’s central wind-market message is therefore not that wind is replacing solar. It is that a solar-heavy electricity system places an increasing premium on renewable generation that arrives at a different time. In Southeast Europe, the commercial value of technological diversity is beginning to appear directly in capture prices, contracting strategies and investor demand.
