Southeast Europe’s renewable investment activity is shifting focus from how much electricity a project can generate to when its output reaches the market and what it earns in each hour. The change could have significant implications for developers, lenders and investors.
Solar remains one of the fastest routes to new generating capacity in the region. BloombergNEF (BNEF) expects around 93 GW of additional solar capacity between 2026 and 2036 across the six Central and Southeast European markets in its regional outlook. BNEF also says falling realised renewable prices and grid constraints are increasing the value of storage, transmission, power purchase agreements (PPAs) and other forms of flexibility.
AleaSoft Energy Forecasting’s figures for Spain illustrate the growing gap between wholesale prices and the prices captured by solar generation. Between January and September 2026, the Spanish average wholesale price rose to €74.10/MWh, from €63.39/MWh a year earlier. Over the same periods, the average price from 10:00 to 18:00, covering much of the solar production period, dropped from €30.92/MWh to €23.87/MWh.
Spain also recorded 747 negative-price hours in the first nine months of 2026, compared with 535 in the corresponding period of 2025. The relevance for Southeast Europe is not that Spanish market conditions will be replicated exactly. Rather, annual baseload prices can increasingly mask the economics of individual technologies, with a market remaining relatively expensive even as the value captured by photovoltaic generators declines.
Project economics increasingly depend on hourly conditions
This distinction matters across Southeast Europe, where renewable project pipelines are growing rapidly while grids were not designed for highly concentrated variable generation. A renewable project’s future value may depend on six interconnected factors: its hourly production profile, the corresponding captured electricity price, grid availability, curtailment, balancing exposure and the contractual route used to sell its electricity. These elements cannot be assessed separately.
High solar output can push prices down during the hours when photovoltaic plants generate most heavily, while grid congestion can prevent plants from exporting all available production. Forecasting errors can lead to balancing costs, and a PPA can mitigate some risks while transferring others back to the generator. Storage can change a plant’s production profile, but it also brings additional capital expenditure and operational risk.
The transition is changing what makes an electricity asset valuable. In a system dominated by scarcity, additional generation normally has substantial value; where renewable surpluses occur periodically, more value increasingly attaches to flexibility. This includes the ability to shift, control, store or contract electricity so that it reaches the market when it is valuable.
Financing requires analysis beyond average wholesale prices
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 valued using analysis of captured prices, hourly production, curtailment and alternative market scenarios, rather than relying on an average wholesale-price forecast. The principle 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 only on today’s generation mix and must reflect the electricity system into which the plants will mature. As renewable penetration increases, the assets with the lowest headline generation costs may not necessarily be the strongest.
Grid position, production profile, flexibility, contractual structure and the ability to preserve captured value could increasingly determine which projects generate 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 increasingly a competition over economically deliverable megawatt-hours.