Southeast European renewable electricity generation rose 30.1% to 3,597.48 GWh in Week 42, led by a sharp increase in wind output. Wholesale electricity prices nevertheless rose in every market covered. The figures were provided by Virtu.Energy.
Regional wind generation climbed 86.6% to 2,133.35 GWh, while solar output fell 9.7% to 1,464.13 GWh. The increase in total variable renewable generation did not prevent weekly prices from rising across the region.
Serbia’s weekly electricity price increased 28.53%, followed by gains of 12.60% in Bulgaria, 11% in Croatia, 9.72% in Romania, 8.99% in Hungary and 6.70% in Greece. The contrasting movements reflect the complex structure of the regional electricity market.
Renewable output and market conditions varied by country
Renewable generation was uneven across both geography and time. Türkiye contributed a large share of the regional increase, while Italy also added substantial production. Romania and Greece recorded strong wind gains, but Bulgaria’s combined wind and solar generation declined 21.5%.
Hungary also saw weaker variable renewable output, meaning the regional total concealed significant differences between national markets. Prices depend on conditions during individual marginal hours, not only on average weekly renewable production. A system may generate abundant wind power overnight but still face expensive evening peaks if renewable output falls as consumption rises.
Transmission constraints can also prevent lower-cost renewable electricity from moving from a surplus bidding zone to a deficit market, allowing large wholesale price spreads to persist even as regional renewable generation increases. In Week 42, Greece recorded stronger renewable generation and larger electricity exports alongside comparatively low prices. Serbia increased wind and solar generation but shifted further into net imports as demand rose and hydropower output declined.
Flexibility and hourly generation profiles shape project economics
The investment debate in Southeast Europe is moving beyond installed renewable capacity. The next stage requires storage, transmission, demand response and better portfolio management. Batteries can store surplus wind and solar generation during lower-priced periods and release it during evening peaks, while cross-border interconnectors can transfer renewable surpluses between markets.
Flexible hydro and thermal plants can offset fluctuations in renewable output, and industrial demand response can ease system pressure during expensive hours. For renewable developers, future project revenues will increasingly depend on the hourly generation profile rather than simply the annual number of megawatt-hours produced.
Two solar projects with identical annual production can have different economics if one is in a congested market with midday price compression, while the other has access to storage or stronger cross-border capacity. The same issue applies to corporate PPAs: buyers seeking predictable energy costs need to distinguish between purchasing annual renewable volumes and securing electricity during the hours their facilities consume it.
Week 42 showed why renewable expansion alone cannot be treated as a single-variable solution to wholesale electricity prices: Southeast Europe generated substantially more wind and solar power, yet several markets became significantly more expensive. The missing link was the system’s ability to move, store and reshape renewable electricity for the hours and locations where it had the highest value. Courtesy of Virtu.Energy.