January trading across South-East Europe cleared as a single, stress-tested power system in which hydro flexibility, nuclear baseload, variable wind and solar, gas availability and cross-border constraints interacted hour by hour. The month’s defining feature was not persistently high prices, but repeated regime shifts between energy-long and flexibility-short conditions. A small number of constrained evening hours drove a disproportionate share of cost and value transfer.
Nuclear baseload and regional export flows
Nuclear provided the anchor at the base of the supply stack, with Bulgaria and Romania’s nuclear fleets supplying a continuous, predictable output. Bulgaria’s nuclear generation enabled sustained exports into neighbouring systems, with northbound flows from Bulgaria into Romania exceeding 400 GWh over the month. The effect was less visible in headline spikes than in the absence of prolonged fuel-driven scarcity or a gas-led spiral. In systems without direct nuclear access, including Montenegro and Serbia, the anchor arrived only via imports, increasing exposure to congestion risk.
Hydropower dispatch during evening scarcity
Reservoir and cascade hydro across Serbia, Croatia, Romania, Bosnia and Herzegovina, and Montenegro acted as the region’s primary flexibility asset. January hydrology did not overwhelm the system with volume, but it supplied timing for dispatch decisions. Hydro was used selectively into evening ramps where power exchanges priced scarcity. Price patterns included soft baseload days near €60–70/MWh alongside peak extremes approaching €300/MWh on SEEPEX.
Other exchange references showed peak averages of €165–180/MWh on CROPEX and OPCOM, with extreme dispersion on MEPX. Hydro reduced the duration of scarcity while preserving its value through selective release into tight periods. Water carried option value across weeks, with operators withholding in energy-long hours and releasing during ramps. This approach monetised the shape of demand rather than suppressing prices.
Wind variability and solar-shaped intraday profiles
January wind production rebounded sharply in several weeks across the region, particularly in Romania and parts of the eastern Balkans. At times it compressed off-peak prices by flooding systems with low-marginal-cost energy. Wind’s contribution remained episodic, with lulls coinciding with cold spells and evening demand peaks when flexibility was most valuable.
Those swings reinforced the month’s regime-switching pattern: when wind output rose, prices softened quickly; when it fell, the system relied more on hydro dispatch, imports and residual thermal capacity. Markets with deeper liquidity and stronger interconnection absorbed these changes more smoothly than thinner systems.
Solar was structurally secondary in winter conditions due to limited absolute output. It still affected intraday profiles by depressing midday prices and steepening evening ramps. That dynamic increased the premium for flexibility assets able to shift from midday softness into evening stress. In January, solar did not drive volumes but sharpened the curve through its effect on timing.
Gas supply stability amid price spikes
Regional gas supply remained stable in January, with adequate storage and pricing that tracked European hubs without shock. Serbia’s long-term supply structure insulated gas-to-power from spot volatility. Romania’s domestic production further reduced exposure, while Croatia’s LNG access provided security at a higher but controlled cost.
As a result, gas acted as a ceiling rather than a trigger for price formation. Power prices spiked without a corresponding gas spike, indicating that flexibility and grid constraints were the marginal drivers during January. The relationship pointed to system conditions rather than fuel scarcity as the source of tight-hour pricing.
Cross-border constraints and local price separation
Interconnectors determined whether scarcity was shared or isolated across markets during constrained periods. The Romania–Bulgaria corridor showed strongly asymmetric flows favouring Bulgaria-to-Romania during large parts of the month. The Romania–Hungary interface flipped direction repeatedly, indicating alternating price leadership and intermittent convergence between areas.
Bulgaria’s high throughput on IBEX included record daily volumes showing aggressive coupling during unconstrained hours. During critical ramps, saturation left residual scarcity to be priced locally rather than fully shared across borders. In smaller markets such as Montenegro, thin liquidity amplified these effects, producing days as low as €18.79/MWh alongside peaks above €180/MWh within the same month.
Price dispersion tied to flexibility access
The combined system behaviour translated into distributional outcomes across participants with different flexibility exposure. Primary winners included holders of controllable flexibility and optionality: hydro operators, nuclear-anchored exporters, portfolio traders with cross-border access, and assets able to shift energy from off-peak to peak periods.
The repeated spread between off-peak levels near €120–125/MWh in Romania and peak averages above €170/MWh was monetisable during tight hours. Similar dispersion appeared between Serbian minima near €67/MWh and peak extremes near €294/MWh. The clearest losers were inflexible buyers and suppliers structurally short during evening ramps.
This included industrial loads without demand response, district heating systems, and portfolios hedged flat rather than by shape. Those positions paid for a small number of hours that dominated monthly costs due to constrained ramp conditions.