Greece is providing Southeast Europe with clear evidence that rapid growth in photovoltaic capacity can weaken renewable revenues even as solar generation remains strategically valuable to the electricity system. The issue is not solar production itself, but the growing concentration of generation in the same hours. Greece’s experience also shows how this can affect the economics of photovoltaic assets.
More curtailment and lower solar capture rates
Renewable curtailment in Greece reached 1,601.4 GWh in the first half of 2026. The volume was higher than the 1,327.1 GWh recorded in the same period of 2025 and the 513.5 GWh reported two years earlier.
Greece also registered 788 hours of near-zero or negative wholesale prices in H1 2026, compared with 168 hours in H1 2025 and 135 hours in H1 2024. By August, the total for the first eight months of 2026 had reached 949 hours, around three times the figure for the corresponding period of 2025.
The average Greek solar capture rate declined from 71.9% in H1 2024 to 61.6% in H1 2025 and 44.0% in H1 2026. In May 2026, solar generation was valued at just 28.3% of the average wholesale price.
Effects on photovoltaic project economics
A photovoltaic plant can generate electricity exactly as its technical model projected and still fall substantially short of its original revenue assumptions. When many solar installations generate at the same time, additional daytime supply pushes down the market price. As installed capacity grows, each new project can also reduce the value captured by the existing fleet.
Insufficient grid capacity to carry all available generation adds curtailment to the problem. Each curtailed MWh is technically available production that cannot be monetised unless contractual or regulatory compensation applies. The underlying market signal is that electricity’s economic value increasingly depends on when it is generated.
The consequences reach beyond new projects, and operating assets financed under older assumptions may need reassessment. Lower expected captured prices can reduce merchant-project cash flow even when annual wholesale prices remain relatively strong. Assets bought on the basis of historical capture rates may also be valued differently when future revenue models account for stronger cannibalisation.
Refinancing is another consideration: lower expected cash flows can reduce the debt an asset can support, even if the plant remains technically sound and operationally profitable. AleaSoft distinguishes asset profitability from compliance with financing requirements. A project may still be able to meet scheduled debt payments while falling below the coverage levels set out in its financing agreements.
Responses for operating assets and regional markets
For operating Greek assets, the response does not necessarily mean abandoning solar, but reconsidering how the asset earns revenue. Potential measures include renegotiating route-to-market arrangements, changing hedging structures, refinancing debt, adding flexibility or adjusting operating strategies. None removes the underlying effect of generation timing on market value.
Greece is therefore relevant to investors in neighbouring markets, including Serbia, Bulgaria, Romania, Croatia and Montenegro. These countries and other regional systems will not necessarily follow the same trajectory or timetable, because their generation mixes, interconnection capacity, support mechanisms and market structures differ. Greece offers an early view of the consequences when renewable deployment moves faster than transmission investment, storage, flexible consumption and other sources of system flexibility.
The Greek experience demonstrates the risk of assessing renewable expansion only in MW. Once solar reaches sufficient scale, investors also need to consider the share of the market’s headline electricity price that photovoltaic generators actually capture. In Southeast Europe, Greece has made this a market phenomenon that can be observed, rather than only a theoretical project-finance issue.