Southeast Europe’s renewables investment landscape is shifting its focus from how much electricity projects can produce to when that power reaches the market and its value at that hour. The change has potentially significant consequences for developers, lenders and investors. Solar remains one of the region’s fastest routes to new generating capacity.
BloombergNEF expects around 93 GW of additional solar capacity across the six Central and Southeast European markets in its regional outlook between 2026 and 2036. At the same time, falling realised renewable prices and grid constraints are increasing the value of storage, transmission, power purchase agreements (PPAs) and other forms of flexibility. The gap between average electricity prices and renewable captured prices is becoming increasingly important.
AleaSoft Energy Forecasting illustrates the difference with data from Spain. From January to September 2026, the Spanish average wholesale price rose to €74.10/MWh from €63.39/MWh in the same period a year earlier. However, the average price from 10:00 to 18:00, covering much of the solar production period, fell to €23.87/MWh from €30.92/MWh.
Spain also recorded 747 negative-price hours in the first nine months of 2026, up from 535 in the corresponding period of 2025. These figures do not mean that Spanish market conditions will be replicated across Southeast Europe. They show how annual baseload prices can conceal the economics of individual technologies, with a market remaining relatively expensive even as the value captured by photovoltaic generators declines.
Grid and hourly prices shape project revenues
The distinction is relevant across Southeast Europe, where renewable project pipelines are growing rapidly while grids were not designed for highly concentrated variable generation. A project’s future value may increasingly depend on six connected factors: its hourly production profile, the corresponding captured electricity price, grid availability, curtailment, balancing exposure and the contractual route used to sell its power. These factors need to be assessed together.
Heavy solar generation can push prices down during the hours when photovoltaic plants produce most, while grid congestion can prevent them from exporting all available output. Forecasting errors can add balancing costs, and a PPA may reduce some risks while transferring others back to the generator. Storage can reshape a plant’s production profile, but it also brings additional capital expenditure and operational risk.
The shift is changing what makes an electricity asset valuable. In a system dominated by scarcity, additional generation normally has substantial value; when renewable surpluses occur periodically, more value goes to flexibility. That means being able to shift, control or store electricity, or contract it so that production reaches the market when it is valuable.
Financing increasingly depends on captured value
The change does not weaken the long-term case for renewable generation, but it alters how renewable assets need to be financed. AleaSoft says photovoltaic plant valuations now require analysis of captured prices, hourly production, curtailment and alternative market scenarios, rather than relying on an average wholesale-price forecast. This approach is becoming directly relevant to Southeast Europe.
Regional projects reaching financial close in 2026-2028 may remain exposed to wholesale markets into the 2040s. Their debt cases therefore cannot rely solely on today’s generation mix; they must account for the electricity system into which the plants will mature. As renewable penetration grows, the projects with the lowest headline generation costs may not necessarily be the strongest assets.
Grid position, production profile, flexibility, contractual structure and the ability to preserve captured value could increasingly determine which projects deliver reliable cash flows. Southeast Europe’s first renewable investment cycle was largely a race to secure land, permits, connection capacity and installed megawatts. The next is set to focus increasingly on economically deliverable megawatt-hours.