Southeast European day-ahead electricity prices moved sharply lower across most interconnected markets for Tuesday delivery, reversing part of Monday’s rally as stronger solar availability, cooler temperatures and lower import requirements outweighed an increase in aggregate regional consumption. The key feature of the session was not only the decline in outright prices, but also the strong convergence across Hungary and central European-linked markets, while Serbia, North Macedonia and parts of the southern Balkans continued to trade at significant discounts.
Hungary’s HUPX day-ahead baseload settled at €164.47/MWh, down €19.4/MWh, or around 10.6%, from Monday. Romania’s OPCOM cleared at €164.17/MWh, Croatia at €164.23/MWh, Germany at €163.93/MWh, Slovenia at €165.68/MWh and Austria at €166.08/MWh. The six markets therefore averaged approximately €164.76/MWh, with only €2.15/MWh separating the lowest and highest prices.
The degree of convergence was particularly clear in Hungary’s cross-border spreads. HUPX traded just €0.54/MWh above Germany, €0.30/MWh above Romania and €0.24/MWh above Croatia, while Slovenia carried a premium of slightly more than €1.20/MWh over Hungary. The narrow spreads indicate that Tuesday’s market behaved increasingly like an integrated central European power system, rather than a group of separately priced national markets.
Further south, however, the price picture remained markedly different. Serbia’s SEEPEX recorded the lowest regional baseload price at €133.02/MWh, despite rising €4.8/MWh from Monday. North Macedonia followed at €135.38/MWh, down almost €16/MWh. Albania rose €8.3/MWh to €152.60/MWh, Greece edged up €0.3/MWh to €153.72/MWh, while Montenegro declined €13.6/MWh to €154.65/MWh. Italy remained the regional premium market at around €172.64/MWh, leaving a €39.6/MWh gap between Italy and Serbia.
The result was a clear two-tier regional structure. Hungary, Romania, Croatia, Slovenia, Austria and Germany formed a closely clustered group around €164–166/MWh, while Serbia and North Macedonia remained heavily discounted. HUPX traded approximately €31.45/MWh above Serbia and €29.08/MWh above North Macedonia, compared with premiums of €10.75/MWh over Greece and €11.87/MWh over Albania. Italy maintained an €8.17/MWh premium over Hungary.
Hourly profiles provided an even stronger indication of the market’s underlying dynamics. Conventional peak and off-peak relationships remained inverted across several markets, reflecting the impact of solar generation during daytime hours. In Hungary, the peak block averaged €153.8/MWh against €175.1/MWh for off-peak hours. Germany showed a similar pattern at €153.8/MWh and €174.1/MWh, respectively, while Romania recorded €153.9/MWh for peak and €174.4/MWh for off-peak.
The inversion became even more pronounced in southern markets. Greece recorded a €133.1/MWh peak average compared with €174.3/MWh off-peak, producing a spread of more than €41/MWh. Serbia averaged €115/MWh during peak hours against €151.1/MWh off-peak, while North Macedonia stood at €122.5/MWh and €148.3/MWh. Italy recorded €159.1/MWh for peak and €188.2/MWh for off-peak.
The hourly curves underline the growing separation between solar-heavy afternoon hours and the evening ramp. HUPX reached a low of €131.3/MWh in hour 14 before climbing to €208.6/MWh in hour 21. Romania recorded the same €208.6/MWh maximum, while Greece fell as low as €66.3/MWh in hour 15 before reaching €208.6/MWh in hour 21. Italy showed the strongest evening scarcity signal, with its national price peaking at €251.7/MWh in hour 21.
Serbia provided a particularly clear example of why a low daily average does not necessarily indicate a lack of scarcity. SEEPEX dropped to just €56.9/MWh at its minimum, but surged to €224.3/MWh in hour 21, exceeding the Hungarian maximum. North Macedonia ranged between €70/MWh and €200/MWh, while Montenegro moved from €130/MWh to €217.1/MWh. The data show that the regional market’s risk is increasingly concentrated in specific evening hours rather than reflected in the daily baseload average.
Fundamentals were mixed rather than uniformly bearish. Average regional consumption was forecast at 31.495 GW, up 708 MW from Monday, even as the regional temperature indicator declined 1.2°C to 23.3°C. Hungarian demand fell by 259 MW to 4.48 GW, while Greece added 345 MW and Romania and Bulgaria together increased demand by approximately 920 MW.
Renewable availability provided the stronger bearish influence. The regional solar forecast increased by 918 MW to around 7.895 GW, while wind availability declined by 179 MW to 1.248 GW. Tuesday’s price correction was therefore not driven by weaker demand alone. Instead, higher solar output and changing physical flows helped absorb stronger weekday consumption and pushed daytime prices lower.
Net regional imports fell to only 436 MW, down 555 MW from the previous session. Imports from the Austria-Slovakia core declined by 462 MW to 948 MW, while exports towards Italy increased to around 513 MW from 403 MW. The stronger convergence between HUPX and Germany therefore occurred despite lower overall imports from the western core, suggesting that Tuesday’s price alignment was not simply the result of heavy west-to-east power flows.
Country-level balances revealed a pronounced northbound flow pattern. Bulgaria remained one of the region’s strongest surplus systems, with forecast generation of approximately 5.37 GW against consumption of 3.90 GW, leaving net exports of around 1.47 GW. The Bulgaria-Romania base flow was approximately 1.15 GW, while around 385 MW moved towards Serbia and another 160 MW towards North Macedonia.
Romania was almost balanced at system level, with generation of around 5.59 GW versus consumption of 5.60 GW, but continued to function as an important transit market. Average base flows from Romania into Hungary reached approximately 1.19 GW and increased to 2.27 GW during peak hours. The combination of Bulgarian surplus and Romanian northbound flows helped keep the central SEE markets closely aligned even as imports from Austria and Slovakia declined.
Hungary remained structurally short, with consumption forecast at 4.48 GW against generation of approximately 2.89 GW, implying net imports of around 1.59 GW. That deficit was nevertheless smaller than Monday’s estimated 2.09 GW. Slovakia remained an important source with approximately 796 MW on a base basis, while Hungary also exported electricity towards Croatia and Slovenia during parts of the day. The highly variable Austria-Hungary flow profile, which switched between imports and exports, showed that the almost negligible daily HUPX-Germany spread concealed significant intraday congestion and flow reversals.
Bulgaria’s strong surplus contrasted with Serbia’s relatively balanced system. Serbian generation was forecast at around 3.48 GW, compared with consumption of 3.53 GW, leaving an average net import requirement of only about 59 MW. Despite this near balance, Serbian electricity traded more than €31/MWh below Hungary. Strong imports from Bulgaria and North Macedonia combined with exports on other borders created a complex hourly flow pattern that kept the daily average depressed even though Serbia recorded an evening price above HUPX.
Greece remained a significant exporter despite trading below the northern European cluster. Generation was forecast at 7.42 GW against consumption of around 6.50 GW, leaving exports of approximately 919 MW. Although that was substantially below Monday’s 1.55 GW, Greek electricity continued flowing towards Bulgaria, Albania, North Macedonia and Italy during significant parts of the day. The move from a €66.3/MWh afternoon low to a €208.6/MWh evening high demonstrates how strongly hourly renewable availability is shaping the Greek market.
The prompt power correction was also reflected in Hungary’s forward curve. Week 35 fell €10/MWh to €150.50/MWh, while Week 36 declined €13.50/MWh to €147/MWh. September 2026 dropped €4/MWh to €157.50/MWh, while Calendar 2026 remained unchanged at €126.50/MWh. The concentration of losses at the front of the curve suggests that traders were primarily unwinding part of the short-term risk premium accumulated during Monday’s price spike rather than materially repricing the longer-term Hungarian power balance.
Hungarian-German forward spreads narrowed accordingly. The Week 35 premium contracted by €9/MWh to €22.50/MWh, Week 36 narrowed €4.50/MWh to €25.50/MWh, and September decreased €1/MWh to €25.50/MWh. The Calendar 2026 spread remained at €20/MWh. Hungary’s front-end power prices therefore weakened both in absolute terms and relative to Germany.
Fuel markets provided a less bearish signal. CEGH gas increased €1/MWh to €63.16/MWh, while the Greek gas indicator rose €0.60/MWh to €55.58/MWh. EU allowances edged down €0.20/t to €81.58/t. September gas forwards were unchanged at €63/MWh, while Q4 increased €0.50/MWh to €63.50/MWh. The divergence between firmer gas prices and weaker prompt electricity indicates that Tuesday’s correction was driven primarily by regional power fundamentals, renewable generation and cross-border positioning, rather than a broad decline in thermal fuel costs.
The weather outlook suggests that the bearish pressure may not persist uniformly. The regional temperature forecast excluding Greece rises from 23.3°C on Tuesday to 23.9°C on Wednesday, then accelerates to 26.7°C on Thursday and 27.6°C on Friday. Hungary is forecast to warm from 21.1°C to around 26.4–26.5°C later in the week, while Romania, Serbia, Greece and Montenegro are also expected to experience significantly higher temperatures.
The warming trend points towards renewed cooling demand just as the market is demonstrating that its most expensive periods are increasingly concentrated after the solar ramp-down. Tuesday’s decline in baseload prices has removed part of the premium built into the Hungarian front end, but the underlying hourly structure remains tight. Prices above €200/MWh appeared across much of the region, Italy exceeded €250/MWh and even discounted Serbia reached more than €224/MWh. The next sessions are therefore likely to be shaped less by the daily baseload average and more by the interaction between daytime renewable price compression, evening thermal flexibility and cross-border transmission capacity.