Southeast Europe’s renewable investment market is shifting its focus from how much electricity a project can generate to when it can sell that power and what it is worth at the time. The change could have significant implications for developers, lenders and investors.
Solar growth is increasing the value of flexibility
Solar remains one of the fastest ways to add generating capacity across the region. BloombergNEF expects about 93 GW of additional solar capacity between 2026 and 2036 across the six Central and Southeast European markets covered by its regional outlook. It also points to falling realised renewable prices and grid constraints as factors increasing the value of storage, transmission, PPAs and other forms of flexibility.
AleaSoft Energy Forecasting illustrates the difference between average wholesale prices and the prices received by renewable generators with data from Spain. From January to September 2026, the country’s average wholesale price rose to €74.10/MWh from €63.39/MWh a year earlier. Over the solar-heavy period from 10:00 to 18:00, however, the average price fell to €23.87/MWh from €30.92/MWh.
Spain recorded 747 negative-price hours in the first nine months of 2026, up from 535 in the same period of 2025. The implication for Southeast Europe is not that Spanish market conditions will be replicated exactly, but that annual baseload prices can increasingly mask the economics of individual technologies. A market can remain relatively expensive even as the value captured by photovoltaic generators declines.
Project economics depend on hourly delivery
This distinction matters across Southeast Europe, where renewable project pipelines are growing rapidly while grids were not designed for highly concentrated variable generation. As a result, the investment equation is widening. A project’s future value may depend on its hourly production profile, the corresponding captured electricity price, grid availability, curtailment, balancing exposure and the contractual route used to sell power.
These factors cannot be assessed in isolation. Heavy solar generation can depress prices during the hours when photovoltaic plants produce most, while grid congestion can prevent a plant from exporting all its available output. Forecasting errors can add balancing costs, and a PPA can mitigate some risks while transferring others back to the generator.
Storage can change a project’s production profile, but it also adds capital expenditure and operational risk. The shift is changing what makes an electricity asset valuable: when scarcity dominates a system, additional generation normally has substantial value. Where renewable surpluses occur periodically, more value increasingly accrues to flexibility—the ability to shift, control, store or contract electricity so that production reaches the market when it is worth more.
Financing must reflect future market conditions
This shift does not weaken the long-term case for renewable generation, but it changes how renewable assets need to be financed. AleaSoft says photovoltaic plants should now be assessed using captured prices, hourly production, curtailment and alternative market scenarios, rather than relying on an average wholesale-price forecast. That 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 be based solely on today’s generation mix. They must account for the electricity system that the plants will operate in as they mature.
Competition is shifting to deliverable megawatt-hours
As renewable penetration rises, the strongest assets may not necessarily be those with the lowest headline generation cost. Grid position, production profile, flexibility, contractual structure and the ability to preserve captured value could increasingly determine which projects deliver reliable cash flows. The investment case is therefore extending beyond the cost of building generation.
Southeast Europe’s first renewable investment cycle was largely a race to secure land, permits, connection capacity and installed megawatts. The next is increasingly set to be a competition over economically deliverable megawatt-hours.
