Romania showed a pronounced shift in its day-ahead power pricing on 24 July, with OPCOM’s baseload settling at €129.98/MWh and traded volume reaching 39,454.3 MWh. The same session featured a quoted peak-load strip of €90.81/MWh, compared with €169.14/MWh for the off-peak product. The figures point to a separation between peak and off-peak levels in the market curve.
Intraday, prices in Romania dropped to about €13.25/MWh during the afternoon solar period before rising to €200.76/MWh at 22:00. The daily low-to-high gap therefore exceeded €187/MWh, producing one of the largest spreads reported across the regional set of markets.
Implications for solar capture and merchant revenue signals
The Romanian price pattern affects how renewable generation aligns with market clearing prices across the day. A solar plant may be associated with a baseload reference around €130/MWh, while a large share of output can occur during hours when prices clear at roughly €13–€30/MWh. In that context, using the arithmetic daily average as a proxy for solar capture prices can overstate merchant cash generation.
The distortion is described as most relevant where projects do not have support mechanisms that fix revenues, such as a contract for difference, a fixed-price PPA or colocated storage. Without such arrangements, the mismatch between physical generation timing and intraday pricing can change the implied value of merchant output.
Central European intraday spreads: Hungary and Slovenia
A similar structure appeared in Hungary and Slovenia during the same central European hours. Hungary’s price fell to €13.52/MWh at 14:00, then increased to €200.88/MWh at 21:00. Slovenia moved to about €13.62/MWh during the same hour and later reached a peak of €199.76/MWh in the evening.
Hungary’s intraday range reached €187.36/MWh, while Slovenia recorded an intraday spread of €186.14/MWh. In a simplified scenario, a battery buying at the daily minimum and selling at the maximum would face a gross spread close to €187/MWh. With an 85% round-trip efficiency, electricity purchased at €13.52/MWh would correspond to an approximate charging cost of €15.91/MWh per discharged megawatt-hour, leaving a theoretical energy margin near €185/MWh.
The calculation is framed as theoretical because the maximum spread was available only for a limited period and cannot be assumed for every battery cycle. As storage deployment increases, afternoon prices are expected to lift and evening scarcity to ease, but the 24 July curve is cited as providing a stronger signal for short-duration flexibility than an annual baseload forecast when aggregate demand declines while evening marginal prices remain close to €200/MWh.
Bulgaria and Greece show smaller midday discounts
Bulgaria and Greece displayed comparatively flatter daily price profiles than Romania, Hungary and Slovenia. Both markets fell to around €72.23/MWh near midday, while their daily highs were about €162.09/MWh. The solar-driven discount was therefore present but less severe than in the higher-spread markets.
Bulgaria’s afternoon trough depth was supported by its nuclear baseload, regional interconnection capacity and a growing battery fleet. Greece remained more dependent on gas-fired generation throughout the day, contributing to differences in how solar production translated into intraday volatility across the two systems.
