The Southeast European day-ahead market tightened sharply for delivery on 16 July, but the headline rise in baseload prices conceals a more significant structural development: the region’s expensive hours have shifted decisively into the evening, while solar production continues to suppress the conventional daytime peak. Higher cooling demand, reduced net imports and limited flexibility during the sunset ramp pushed Serbia, Hungary and the southern Western Balkans into a scarcity-led price structure.
HUPX settled at €161.97/MWh, an increase of €10.90/MWh, while SEEPEX rose €21.00/MWh to €160.38/MWh. The Serbian market therefore traded only €1.59/MWh below Hungary, indicating strong price transmission across the central SEE corridor. Austria was similarly aligned at €161.01/MWh, Slovenia at €160.45/MWh and Germany at €159.86/MWh.
The most aggressive repricing occurred further south. ALPEX jumped €57.10/MWh to €169.58/MWh, a daily increase of more than 50 per cent, making Albania the most expensive SEE market and placing it €7.61/MWh above HUPX. North Macedonia advanced €33.00/MWh to €158.76/MWh, while Montenegro gained €28.10/MWh to €154.66/MWh.
These moves were not uniform across the region. Croatia eased slightly to €156.47/MWh, while Slovenia slipped to €160.45/MWh despite remaining close to the Hungarian benchmark. Romania increased by a more moderate €5.30/MWh to €155.30/MWh, Bulgaria by €4.30/MWh to €145.94/MWh, and Greece by €5.80/MWh to €142.24/MWh. Greece remained the cheapest market in the observed region, trading €19.74/MWh below Hungary, followed by Bulgaria at a €16.03/MWh discount.
Italy remained the highest large neighbouring market at €170.47/MWh, maintaining an €8.50/MWh premium over HUPX. The Italian premium continued to pull electricity westward, limiting the amount of surplus generation available to relieve the central and western Balkans.
Demand growth met weaker import support
Forecast regional consumption increased by 1,092 MW, or approximately 3.3 per cent, to an average 34,233 MW. The largest daily increase came from Romania and Bulgaria, where combined demand rose 657 MW to 9,919 MW. Greek consumption increased 390 MW to 7,776 MW, while Slovenia and Croatia added 133 MW, reaching 10,033 MW.
Hungarian consumption was the exception, declining 201 MW to 4,872 MW. This was insufficient to offset the wider regional increase, particularly as temperatures remained elevated. Greece was forecast at 29.2°C, while Albania and Montenegro were around 28.5°C and 30.2°C, respectively. Cooling demand therefore remained concentrated in the southern markets, where hydro availability and cross-border capacity could not fully moderate the evening price response.
Net regional imports fell from 871 MW to 710 MW, a reduction of 161 MW, even as consumption increased by more than 1 GW. Imports from the core market area through Austria and Slovakia declined by 306 MW to 1,593 MW. The combination of higher load and weaker external supply removed approximately 1.25 GW of effective system headroom compared with the previous day.
Hungary remained a net importer at an average 881 MW, Croatia at 1,112 MW, Romania at 597 MW, Serbia at 293 MW and the combined regional system at 710 MW. Bulgaria, by contrast, exported approximately 1,448 MW, while Greece exported around 1,016 MW. Bulgaria and Greece therefore acted as the principal regional supply anchors, explaining why their baseload prices remained materially below Hungary and the Western Balkans.
Commercial schedules reinforce this division. Bulgaria was exporting around 767 MW to Romania and more than 290 MW to Serbia, while Romania delivered approximately 239 MW in baseload and 442 MW during peak hours to Hungary. Hungary simultaneously exported approximately 564 MW in baseload and 713 MW during peak periods to Croatia. Electricity was consequently moving through a chain from Bulgaria and Romania into Hungary and then towards the structurally short Croatian market.
In the southern corridor, flow reversals point to Albania’s particularly tight position. Greece supplied Albania during both baseload and peak periods, while Albania also supplied Montenegro. North Macedonia relied on electricity moving from Greece but exported towards Serbia and Kosovo. These schedules are consistent with Albania’s exceptional day-on-day price increase and its elevated €169.58/MWh baseload settlement.
The evening ramp has replaced the conventional peak
The daily profile provides the clearest market signal. Across almost every SEE exchange, the reported off-peak average exceeded the peak average because the conventional peak block includes solar-rich daytime hours but excludes part of the late-evening scarcity period.
On HUPX, the peak average was €137.80/MWh, compared with an off-peak average of €186.10/MWh. The resulting inversion reached €48.30/MWh. Prices fell to a minimum of €96.10/MWh at hour 11, before rising to €303.30/MWh at hour 21. The full intraday range was therefore €207.20/MWh.
Serbia exhibited an even stronger evening ramp. SEEPEX recorded a minimum of €106.00/MWh at hour 12 and a maximum of €340.00/MWh at hour 21, producing a €234.00/MWh intraday range. Serbia’s off-peak average of €178.40/MWh was €36.10/MWh above its peak average of €142.30/MWh.
Albania recorded the most extreme volatility. Its daytime minimum fell to €64.10/MWh at hour 14, while the evening maximum reached €380.00/MWh at hour 21. The theoretical maximum-to-minimum spread was €315.90/MWh, with the off-peak block averaging €215.20/MWh, compared with only €124.00/MWh for the peak block.
Romania posted a €230.30/MWh intraday spread, ranging from €72.40/MWh to €302.70/MWh. Greece ranged from €11.90/MWh to €230.00/MWh, while Bulgaria moved between €70.20/MWh and €230.00/MWh. Montenegro was less volatile, with a minimum of €113.00/MWh and a maximum of €212.10/MWh, but its relatively high minimum indicates that the system was tight throughout the day rather than only during individual scarcity hours.
The simultaneous hour-21 maxima across Hungary, Germany, Romania, Slovenia, Greece, Bulgaria, Serbia, Montenegro and Albania demonstrate that the price event was regional rather than exchange-specific. Solar output reduced marginal prices during late morning and early afternoon, but flexible generation, storage and import capacity were insufficient to cover the evening demand ramp without activating expensive thermal units.
Forecast solar generation increased 577 MW to 7,742 MW, while wind rose 714 MW to 2,109 MW. Higher renewable output therefore did not prevent the price increase. It deepened the difference between the solar-rich midday period and the evening residual-load peak. The market is rewarding ramping capability and deliverability during hours 20–22, rather than undifferentiated daily renewable production.
For battery operators, the theoretical one-cycle gross spreads were particularly strong in Albania, Serbia and Romania. Actual captured revenue would be lower after efficiency losses, market fees, degradation and imperfect dispatch, but the profiles support the commercial case for storage located behind constrained southern and central SEE nodes. The data also explain the accelerating battery pipeline in Bulgaria, Greece and Romania: storage value is increasingly determined by the evening ramp rather than negative daytime pricing alone.
Gas remains the marginal fuel, while carbon offers little relief
Austrian CEGH gas increased €1.30/MWh to €55.72/MWh, while the Greek gas benchmark rose €0.40/MWh to €45.49/MWh. EU carbon allowances were broadly stable at €81.16/t, down only €0.20/t.
At a thermal efficiency of 50–55 per cent, CEGH gas implies a fuel cost of approximately €101–111/MWh of electricity. Adding carbon costs produces an indicative gas-fired marginal cost of around €130–145/MWh before variable operating costs. This broadly supports the baseload settlements in Greece, Bulgaria and Romania. Prices above €200/MWh, and particularly the hour-21 values between €300/MWh and €380/MWh, reflect scarcity, ramping and transmission constraints rather than fuel and carbon costs alone.
The Hungarian forward curve treated the daily spike as partly temporary. Week 30 remained unchanged at €120.00/MWh, almost €42/MWh below the day-ahead settlement. Week 31 increased only €0.50/MWh to €133.50/MWh. Longer-dated contracts strengthened more clearly: the August product rose €2.50/MWh to €141.00/MWh, while calendar 2026 gained €2.00/MWh to €123.50/MWh.
The forward market therefore has not extrapolated the €162/MWh spot price across the remaining summer period. It has, however, added risk premium to August and the broader annual strip. Hungarian premiums over Germany remain substantial at €10.00/MWh for week 30, €19.50/MWh for week 31, €21.00/MWh for August and €19.50/MWh for calendar 2026. That structure continues to price Hungary and the connected SEE markets as a constrained zone exposed to summer demand, evening flexibility shortages and limited north-to-south transmission capacity.
The central trading signal is no longer simply a high-price day. Serbia’s convergence with Hungary, Albania’s sharp premium and the simultaneous hour-21 spike across nearly every market reveal a regional flexibility deficit. Solar additions can continue to reduce midday prices, but without faster battery deployment, dispatchable capacity and stronger cross-border access, each additional hot-weather demand increase will concentrate value and volatility into a narrower evening window.
The 16 July generation totals are not yet included in the daily balance table, so renewable and thermal conclusions for the delivery day rely on forecasts and scheduled flows rather than settled production. The confirmed data nevertheless show the central imbalance clearly: regional demand increased by more than 1 GW, net imports declined, and price formation moved decisively towards the evening scarcity hours.
