Romania provided the clearest illustration of the region’s distorted daily price curve. OPCOM’s day-ahead baseload price settled at €129.98/MWh on 24 July, with traded volume reaching 39,454.3 MWh. However, its quoted peak-load strip was only €90.81/MWh, compared with €169.14/MWh for the off-peak product, highlighting the extent to which strong solar generation reshaped the conventional relationship between peak and off-peak prices.
Prices in Romania fell to approximately €13.25/MWh during the afternoon solar period before climbing to €200.76/MWh at 22:00. The gap between the daily low and high therefore exceeded €187/MWh, creating one of the most pronounced intraday spreads in the regional market.
This price inversion has direct consequences for renewable project valuations. A Romanian solar plant may appear to be operating in a €130/MWh baseload market, yet much of its physical generation is delivered during hours when prices clear at only €13–€30/MWh. Using the arithmetic daily average as a proxy for solar capture prices can therefore significantly overstate merchant cash generation, unless the project is supported by a contract for difference, a fixed-price PPA or colocated storage.
A similar pattern emerged further west. Hungary’s electricity price fell to €13.52/MWh at 14:00 before reaching €200.88/MWh at 21:00. Slovenia dropped to €13.62/MWh during the same central European hour and later peaked at €199.76/MWh in the evening.
Hungary’s intraday range reached €187.36/MWh, while Slovenia recorded a spread of €186.14/MWh. In theory, a battery buying electricity at the daily minimum and selling at the maximum would face a gross spread approaching €187/MWh. At an 85 per cent round-trip efficiency, electricity purchased at €13.52/MWh would translate into a charging cost of approximately €15.91/MWh per discharged megawatt-hour, leaving a theoretical energy margin of nearly €185/MWh before accounting for degradation, connection charges, trading fees and imbalance exposure.
The maximum spread, however, was available only for a limited period and cannot be extrapolated across every battery cycle. As storage deployment increases, it will also tend to lift afternoon prices and reduce evening scarcity. Nevertheless, the 24 July price curve provides a stronger commercial signal for short-duration flexibility than a conventional annual baseload forecast. The value of storage becomes particularly evident when aggregate demand declines but the evening marginal price still approaches €200/MWh.
Bulgaria and Greece displayed a flatter price profile. Both markets fell to approximately €72.23/MWh around midday and reached daily highs of about €162.09/MWh during the morning. Their solar-driven price discount was therefore significant but considerably less severe than in Romania, Hungary and Slovenia.
Bulgaria’s nuclear baseload, regional interconnection capacity and growing battery fleet helped limit the depth of its afternoon price trough, while Greece remained more dependent on gas-fired generation throughout the day. The contrast underlined the importance of generation mix, storage capacity and interconnection availability in determining how strongly solar production translates into intraday price volatility.
