The Southeast European day-ahead electricity market tightened significantly for delivery on 16 July, with higher baseload prices recorded across most exchanges. However, the headline increase reflects a deeper structural change in the region’s power system. The most expensive hours are increasingly moving into the evening period, while strong solar generation continues to suppress the traditional daytime peak. Higher cooling demand, weaker net imports and limited flexibility during the sunset ramp pushed Serbia, Hungary and parts of the Western Balkans into a market structure increasingly shaped by scarcity rather than fuel costs alone.
HUPX settled at €161.97/MWh, increasing by €10.90/MWh, while SEEPEX rose by €21.00/MWh to €160.38/MWh. The Serbian market therefore traded only €1.59/MWh below Hungary, confirming strong price convergence across the central Southeast European corridor. Austria followed at €161.01/MWh, Slovenia at €160.45/MWh and Germany at €159.86/MWh, showing that price pressure extended beyond Southeast Europe into the wider Central European market area.
The strongest repricing occurred further south. ALPEX increased by €57.10/MWh to €169.58/MWh, representing a daily increase of more than 50 per cent and making Albania the most expensive market in the region. The Albanian price was €7.61/MWh above HUPX. North Macedonia increased by €33.00/MWh to €158.76/MWh, while Montenegro gained €28.10/MWh to reach €154.66/MWh.
Other markets experienced more moderate movements. Croatia eased slightly to €156.47/MWh, while Romania increased by €5.30/MWh to €155.30/MWh. Bulgaria rose by €4.30/MWh to €145.94/MWh, and Greece increased by €5.80/MWh to €142.24/MWh. Greece remained the cheapest market among observed Southeast European exchanges, trading €19.74/MWh below Hungary, followed by Bulgaria with a €16.03/MWh discount. Meanwhile, Italy remained the highest-priced large neighbouring market at €170.47/MWh, maintaining an €8.50/MWh premium over HUPX.
Forecast regional electricity consumption increased by 1,092 MW, or approximately 3.3 per cent, reaching an average of 34,233 MW. The largest increase came from Romania and Bulgaria, where combined demand rose by 657 MW to 9,919 MW. Greek consumption increased by 390 MW to 7,776 MW, while Slovenia and Croatia added 133 MW, reaching 10,033 MW.
Hungary was the only major exception, with consumption declining by 201 MW to 4,872 MW. However, this reduction was insufficient to offset broader regional demand growth as temperatures remained elevated. Cooling demand remained concentrated in southern markets, with forecast temperatures reaching 29.2°C in Greece, around 28.5°C in Albania and 30.2°C in Montenegro.
Net regional imports declined from 871 MW to 710 MW, representing a reduction of 161 MW, even as consumption increased by more than 1 GW. Imports from the core European market area through Austria and Slovakia fell by 306 MW to 1,593 MW. The combination of stronger demand and weaker external supply removed approximately 1.25 GW of effective system flexibility compared with the previous day.
Hungary remained a net importer with average imports of 881 MW, followed by Croatia at 1,112 MW, Romania at 597 MW, and Serbia at 293 MW. In contrast, Bulgaria exported approximately 1,448 MW, while Greece exported around 1,016 MW. These two countries acted as the main regional supply anchors, helping explain why their baseload prices remained below Hungary and the Western Balkans.
Commercial schedules reinforced the regional supply imbalance. Bulgaria exported around 767 MW to Romania and more than 290 MW to Serbia, while Romania supplied Hungary with approximately 239 MW during baseload hours and 442 MW during peak periods. Hungary simultaneously exported around 564 MW during baseload hours and 713 MW during peak periods towards Croatia, creating an electricity flow chain from Bulgaria and Romania through Hungary and towards the tighter Croatian market.
In the southern corridor, electricity flows highlighted Albania’s particularly constrained position. Greece supplied Albania during both baseload and peak periods, while Albania also supplied Montenegro. North Macedonia relied on electricity flows from Greece but exported towards Serbia and Kosovo. These patterns correspond with Albania’s exceptional daily price increase and its high baseload settlement of €169.58/MWh.
The daily price profile provided the strongest signal of the changing market structure. Across most Southeast European exchanges, the average off-peak price exceeded the peak average because traditional peak periods now include solar-heavy daytime hours while excluding part of the late-evening scarcity window.
On HUPX, the peak average stood at €137.80/MWh, compared with an off-peak average of €186.10/MWh, creating an inversion of €48.30/MWh. Prices fell to a minimum of €96.10/MWh at hour 11 before rising sharply to €303.30/MWh at hour 21, producing a total intraday spread of €207.20/MWh.
Serbia experienced an even stronger evening ramp. SEEPEX recorded a minimum price of €106.00/MWh at hour 12 and a maximum of €340.00/MWh at hour 21, creating an intraday spread of €234.00/MWh. Serbia’s off-peak average of €178.40/MWh was €36.10/MWh higher than its peak average of €142.30/MWh.
Albania recorded the highest volatility. Prices dropped to €64.10/MWh at hour 14 before reaching €380.00/MWh at hour 21. The maximum spread reached €315.90/MWh, with the off-peak block averaging €215.20/MWh compared with only €124.00/MWh during peak hours.
Romania recorded an intraday spread of €230.30/MWh, moving between €72.40/MWh and €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 experienced lower volatility, with prices ranging from €113.00/MWh to €212.10/MWh, although the relatively high minimum price indicated that system tightness persisted throughout the day.
The simultaneous hour-21 price peaks across Hungary, Germany, Romania, Slovenia, Greece, Bulgaria, Serbia, Montenegro and Albania demonstrate that the event was regional rather than exchange-specific. Solar generation reduced marginal prices during late morning and early afternoon, but available flexibility from dispatchable generation, storage and imports was insufficient to cover the evening demand ramp without activating more expensive thermal units.
Forecast solar generation increased by 577 MW to 7,742 MW, while wind output increased by 714 MW to 2,109 MW. However, stronger renewable production did not prevent higher prices. Instead, it increased the difference between low-cost midday generation and the evening residual-load period when flexible resources are required. The market is increasingly rewarding ramping capability, storage availability and reliable evening delivery rather than renewable production volume alone.
For battery operators, theoretical one-cycle trading opportunities were particularly attractive in Albania, Serbia and Romania. Actual revenues would be lower after accounting for efficiency losses, market fees, degradation and imperfect dispatch, but the price profile strengthens the investment case for storage projects located at constrained nodes across central and southern Southeast Europe.
The data also explain the accelerating battery-storage pipeline in Bulgaria, Greece and Romania, where the value proposition is increasingly driven by evening flexibility rather than negative midday prices alone.
Gas remained the marginal fuel, but scarcity rather than fuel costs determined the most extreme price levels. Austrian CEGH gas increased by €1.30/MWh to €55.72/MWh, while the Greek gas benchmark rose by €0.40/MWh to €45.49/MWh. EU carbon allowances remained broadly stable at €81.16/t.
At thermal efficiency levels of 50–55 per cent, gas prices imply a fuel cost of approximately €101–111/MWh of electricity generation. Including carbon costs results in an indicative gas-fired marginal cost of around €130–145/MWh before variable operating expenses. Prices above €200/MWh, and particularly evening values between €300/MWh and €380/MWh, therefore reflect scarcity, ramping constraints and transmission limitations rather than fuel and carbon costs alone.
The Hungarian forward market treated the daily spike as partly temporary. Week 30 remained unchanged at €120.00/MWh, almost €42/MWh below the day-ahead settlement, while week 31 increased only slightly to €133.50/MWh. Longer-term contracts strengthened more clearly, with the August product rising to €141.00/MWh and calendar 2026 increasing to €123.50/MWh.
The forward curve has therefore not extrapolated the €162/MWh spot price across the rest of the summer, but it has added a risk premium to August and longer-term contracts. Hungarian premiums over Germany continue to reflect expectations of summer demand pressure, evening flexibility shortages and limited north-to-south transmission capacity.
The main market signal from 16 July is no longer simply that prices were high. The convergence between Serbia and Hungary, Albania’s sharp premium and simultaneous hour-21 price spikes across almost all markets reveal a regional shortage of flexibility.
Solar capacity will continue reducing daytime prices, but without faster deployment of battery storage, dispatchable generation and stronger cross-border transmission capacity, future periods of high temperatures and rising demand are likely to concentrate volatility into an increasingly narrow evening window.
The final generation totals for 16 July are not yet included in the daily balance table, meaning renewable and thermal conclusions remain based on forecasts and scheduled flows rather than confirmed production. Nevertheless, the underlying imbalance is clear: regional demand increased by more than 1 GW, net imports declined, and price formation shifted decisively towards evening scarcity hours.