Southeast European electricity markets began the week with a sharp increase in day-ahead prices, as the return of weekday industrial and commercial demand coincided with weaker wind generation, historically low hydropower availability in Serbia and widening transmission congestion between Central Europe and Southeast Europe. The strongest price formation remained concentrated across the central and western part of the region. Italy cleared at €197.71/MWh, followed closely by Montenegro at €196.11/MWh, Serbia at €185.23/MWh and Slovenia at €180.30/MWh, confirming the emergence of a high-priced Adriatic and central Balkan trading corridor.
Hungary’s HUPX settled at €178.57/MWh, representing a daily increase of €56.40/MWh compared with Sunday. Romania’s OPCOM closely tracked the Hungarian market, clearing at €178.07/MWh, only €0.51/MWh lower, while Croatia reached €179.23/MWh. Together, Hungary, Romania, Croatia and Slovenia formed a tightly aligned regional price cluster between €178/MWh and €180/MWh, illustrating strong market coupling within the central part of Southeast Europe.
Despite this convergence, the broader European market remained highly fragmented. Germany cleared at only €128.09/MWh, leaving the Hungarian market trading at a premium of €50.48/MWh, almost €34/MWh higher than the previous day. This widening spread demonstrates that Monday’s price increase was driven by regional scarcity rather than a uniform continental trend. Although German prices rose by €22.60/MWh, Hungary advanced by more than twice that amount, highlighting the increasing value of cross-border transmission capacity into Hungary and the wider Southeast European market.
The strongest premiums were recorded in Serbia and Montenegro. SEEPEX surged by €73.10/MWh to €185.23/MWh, marking the largest absolute daily increase among the region’s electricity exchanges. Serbia traded €6.66/MWh above Hungary, while Montenegro’s BELEN price stood €17.54/MWh above HUPX and only €1.60/MWh below Italy. These pricing levels firmly positioned both markets within the expensive Adriatic and central Balkan trading zone rather than alongside the lower-priced southern Balkan markets.
Price developments in the southern part of the region painted a very different picture. Albania cleared at €136.03/MWh, North Macedonia at €138.07/MWh, Greece at €153.96/MWh, and Bulgaria at €158.08/MWh. Albania traded €42.54/MWh below Hungary, while North Macedonia remained €40.50/MWh lower. Greece recorded a discount of €24.61/MWh, with Bulgaria trading €20.49/MWh below HUPX.
The resulting regional price map was exceptionally fragmented. The spread between physically interconnected Montenegro and Albania widened to almost €60/MWh, while the difference between Italy and Albania approached €62/MWh. Serbia also traded approximately €47/MWh above neighbouring North Macedonia. Such significant price separations reflect transmission constraints, commercial allocation limits and differing national generation balances rather than a uniform shortage of electricity across the region.
The principal demand driver was the transition from the weekend into the working week. Forecast regional electricity consumption increased by 4,072 MW, or nearly 14 per cent, reaching an average of 33,440 MW. Hungary accounted for 673 MW of the increase as demand rose to 5,126 MW, while Greece added 541 MW, reaching 6,859 MW. Romania and Bulgaria together increased consumption by 1,476 MW to 9,516 MW, while Slovenia and Croatia contributed a further 1,305 MW, lifting combined demand to 10,211 MW.
Temperature alone does not explain the magnitude of the price movement. The regional average remained broadly unchanged at 27.1°C, with Greece reaching 28°C and Hungary forecast at 30.1°C. The sharp rise in electricity prices therefore reflected the return of weekday industrial demand and changing supply conditions rather than an abrupt increase in regional temperatures.
Renewable generation presented mixed fundamentals. Forecast solar output increased by 1,976 MW to 8,367 MW, benefiting from stronger daytime irradiation. By contrast, wind generation fell by 980 MW, or almost 39 per cent, leaving total wind production at only 1,561 MW. The decline in wind effectively offset much of the additional solar generation and left the evening demand peak increasingly dependent on thermal generation, electricity imports and limited hydropower flexibility.
Hourly market profiles clearly illustrate where the system came under the greatest pressure. Both HUPX and Romania’s OPCOM remained relatively moderate around midday before climbing sharply during the evening. Prices approached or exceeded €400/MWh during hours 20 and 21, while Slovenia’s BSP experienced an even steeper surge, reaching approximately €500/MWh during the evening peak. Greece also recorded an evening maximum approaching €280/MWh.
This hourly pattern is more revealing than the daily average itself. Strong solar generation successfully suppressed prices during midday hours, but once photovoltaic production declined after sunset, the combination of recovering industrial demand and weak wind generation forced the market to rely on significantly more expensive dispatchable generation. Traders therefore faced a classic steep evening ramp, characterised by relatively moderate midday prices followed by pronounced scarcity pricing during the evening peak.
Regional net electricity imports increased to an average of 1,981 MW, up by 440 MW from Sunday. Imports from Austria and Slovakia rose by 191 MW, reaching 2,852 MW, while the Italy-to-Southeast Europe net position remained at negative 876 MW, indicating that Southeast Europe continued to export electricity to Italy despite tightening domestic market conditions. Compared with Sunday, this represented a 459 MW shift that further reduced the benefits of increased imports from Central Europe.
This combination of stronger imports and persistent regional scarcity explains the widening spread between Hungary and Germany. Although additional electricity flowed south through Austria and Slovakia, available transmission capacity remained insufficient to fully transmit Germany’s considerably lower prices into Hungary. As a result, the Hungarian premium over Germany widened to €50.48/MWh, even with cross-border imports approaching 2.9 GW.
Commercial flow patterns observed over the previous week reinforce this interpretation. Significant scheduled electricity flows continued from Bulgaria to Romania, Romania to Hungary, and Hungary to Croatia, while Hungary also remained an important exporter toward Slovakia under commercial scheduling arrangements. Slovenia continued supplying both Croatia and Italy, while in the southern Balkans Albania and North Macedonia generally exported toward Greece. Montenegro simultaneously maintained commercial exports toward Albania, Serbia and Kosovo. These complex north-south and west-east trading patterns demonstrate that regional electricity prices cannot be explained solely by national production balances. Transmission allocations, loop flows and competing cross-border nominations continue to play a decisive role in determining marginal prices across the region.
The deeper structural concern remains hydrology. Serbian hydroelectric generation has fallen to historically low levels following prolonged drought, significantly reducing the availability of low-cost electricity and valuable system flexibility. Hydropower normally provides both energy production and rapid balancing capability during morning and evening demand ramps. With depleted reservoirs, Serbia has become increasingly dependent on lignite-fired generation, electricity imports and more expensive short-term balancing purchases.
Low Danube water levels introduce an additional source of uncertainty. River flow at the relevant monitoring point measured approximately 4,534 cubic metres per second, well below the long-term seasonal average. Bulgaria’s Kozloduy Nuclear Power Plant continued operating normally, but traders remain highly sensitive to the possibility of additional nuclear or hydrological constraints. Hungary’s Paks Nuclear Power Plant has already experienced operational pressure associated with exceptionally low Danube levels, while Romania’s Cernavoda and Bulgaria’s Kozloduy remain exposed to prolonged heat and cooling-water limitations.
Monday’s price increase therefore reflects not only actual supply tightness but also precautionary risk pricing. While nuclear facilities continue to operate, market participants must account for the disproportionate consequences of any further generation restrictions. Any nuclear derating during a period of weak hydrology would require replacement generation from gas-fired plants or additional imports precisely when cross-border transmission capacity is already carrying a substantial scarcity premium.
Current fuel market fundamentals provide little relief. Austrian CEGH natural gas traded at €60.27/MWh, with September contracts near €60/MWh and fourth-quarter deliveries at €59.50/MWh. Greek gas prices reached €53.09/MWh, increasing by €1.70/MWh, while EU Emissions Allowances (EUAs) remained elevated at €81.26/t. September API2 coal futures traded close to $123 per tonne.
At these fuel and carbon prices, gas-fired electricity generation remains expensive before accounting for start-up costs, balancing exposure and plant efficiency. Although coal generation continues to offer lower fuel costs for certain regional assets, carbon costs above €81/t significantly increase the delivered marginal cost of coal-fired production. Consequently, thermal generation establishes a relatively high price floor whenever renewable generation, hydropower and nuclear output are insufficient to satisfy demand.
The Hungarian forward market also indicates that traders do not view the current tightness as a one-day event. Week 32 contracts traded at €269/MWh, despite declining by €13/MWh during the latest session, remaining more than €90/MWh above Monday’s already elevated HUPX spot price. Week 33 increased by €10/MWh to €194.50/MWh, while September advanced to €174/MWh. By contrast, Calendar 2026 remained unchanged at €124.50/MWh.
The forward curve clearly concentrates risk in the near term. Hungarian contracts traded approximately €138/MWh above Germany for Week 32, €60/MWh above for Week 33 and €35.50/MWh above for September before narrowing to around €20.50/MWh for Calendar 2026. This pricing structure suggests that traders expect acute regional tightness during the coming weeks followed by a gradual normalisation rather than a permanent structural separation between Central European and Southeast European electricity markets.
From a short-term trading perspective, the principal risk remains concentrated during the evening peak. Strong solar forecasts continue to create attractive midday purchasing opportunities, but they provide little protection against the critical hours between 18:00 and 22:00. Weak wind generation, historically poor Serbian hydrology and continuing uncertainty surrounding Danube-dependent nuclear production leave the region vulnerable to another sharp evening price escalation. The hourly profiles observed on HUPX, OPCOM and BSP already demonstrate how quickly prices can move from moderate midday levels to €400–500/MWh scarcity intervals.
Serbia and Montenegro remain particularly exposed to further price increases because their markets are already trading above the Hungarian-Romanian price cluster and only marginally below Italy. Albania and North Macedonia continue to record considerably lower prices, but the magnitude of those discounts also indicates that available interconnection capacity is insufficient to fully exploit arbitrage opportunities. Greece and Bulgaria occupy an intermediate position, benefiting from lower average prices while remaining vulnerable to significant evening repricing as solar generation declines.
Weather forecasts suggest that hotter conditions will return during the middle of the week. Average regional temperatures excluding Greece are expected to increase from 27.1°C on 3 August to approximately 28.8°C by 5 August, while Hungary could reach 31.3°C. Greece is forecast to remain near 29.5°C, Serbia around 30°C, and Croatia between 28.5°C and 28.8°C. Rising cooling demand will therefore increase electricity consumption before hydrological conditions have any meaningful opportunity to recover.
Overall, the short-term market outlook remains firmly bullish for peak and evening delivery products, with considerably greater volatility than suggested by baseload averages. Midday prices retain downside potential thanks to forecast solar production of around 8.4 GW, but the regional electricity balance tightens rapidly once photovoltaic output declines. With wind generation limited to only 1.6 GW, net imports averaging around 2 GW, congestion premiums exceeding €50/MWh and thermal generation costs remaining elevated, Southeast Europe enters the new trading week with limited system flexibility, persistent supply tightness and a pronounced premium for reliable evening electricity deliveries.
