On 7 August 2026, the Southeast European electricity market entered a period of growing divergence between lower average day-ahead prices and increasing dependence on physical electricity imports. Prices declined across most interconnected markets as stronger solar generation reduced daytime scarcity, but Serbia moved against the regional trend, with the SEEPEX price rising to EUR 179.51/MWh, creating a significant premium compared with neighbouring markets.
The wider Southeast European power system is forecast to record average electricity consumption of 35,033 MW, an increase of 311 MW compared with the previous day. At the same time, regional generation reaches only 32,008 MW, resulting in a supply deficit of 3,025 MW. Imports therefore cover approximately 8.6% of total demand, compared with 6.6% one day earlier.
The region’s daily import requirement increased by 725 MW, or almost 32%, despite slightly lower temperatures. Electricity inflows from Austria and Slovakia towards Hungary and Slovenia increased to 4,065 MW, while Southeast Europe continued exporting around 853 MW towards Italy. The market is therefore absorbing additional electricity from Central Europe while maintaining exports towards the higher-priced Italian market.
This market structure shows that declining average spot prices should not be interpreted as an improvement in the regional supply-demand balance. The system remains physically short, but the timing of scarcity has shifted, mainly due to stronger solar generation during daylight hours. Forecast solar production increased to 8,333 MW, up by 1,492 MW compared with the previous day. However, wind generation declined by 554 MW to only 1,924 MW, limiting renewable support outside the central daytime production window.
Electricity prices in Hungary declined by EUR 24.50/MWh to EUR 157.93/MWh, while Romania, Slovenia and Croatia settled within a very narrow range between EUR 158.31/MWh and EUR 158.66/MWh. These four markets effectively formed a common regional price zone with a difference of less than EUR 0.75/MWh. Bulgaria, at EUR 156.47/MWh, and Montenegro, at EUR 158.20/MWh, also remained close to this regional average.
Austria declined to EUR 152.02/MWh, leaving HUPX with a premium of EUR 5.91/MWh compared with the Austrian market. Germany moved in the opposite direction, increasing by EUR 22.60/MWh to EUR 122.08/MWh, although it remained EUR 35.85/MWh below Hungary. The reduction in the Hungary-Germany spread, from EUR 82.90/MWh one day earlier, reflects both the recovery of German prices and the decline in Hungarian day-ahead averages.
Nevertheless, the remaining EUR 35.85/MWh price gap between Germany and Hungary continues to create a strong commercial incentive for electricity flows towards Eastern and Southeastern Europe. The main limitation to further market convergence is not the lack of cheaper generation in Central Europe, but the availability of cross-border transmission capacity.
Italy remained the most expensive market in the broader interconnected region, with a price of EUR 184.23/MWh, despite a daily decline of EUR 14.10/MWh. Its premium compared with Hungary reached EUR 26.30/MWh, preserving the economic incentive for electricity exports across the Adriatic. Italy’s relatively flat hourly profile is particularly important, with average peak prices at EUR 180.90/MWh and off-peak prices at EUR 187.50/MWh.
The strongest deviation from regional price convergence came from Serbia, where SEEPEX increased by EUR 4.10/MWh to EUR 179.51/MWh. Serbia was therefore EUR 21.59/MWh more expensive than Hungary, EUR 21.13/MWh above Croatia, EUR 23.04/MWh above Bulgaria and almost EUR 27/MWh above North Macedonia. At the same time, Serbian electricity prices were only EUR 4.72/MWh below the Italian market level.
The Serbian premium reflects a tightening domestic supply-demand balance. Electricity consumption is forecast at 4,105 MW, while generation reaches approximately 3,487 MW, leaving the country dependent on average net imports of 619 MW. Imports therefore cover around 15% of Serbian electricity demand, compared with 564 MW the previous day.
The imbalance becomes significantly more pronounced during peak hours, when Serbia’s net import requirement rises to 976 MW. This represents almost one-quarter of average daily consumption and explains why the SEEPEX peak electricity price reached EUR 170.90/MWh, significantly above the Hungarian peak price of EUR 141.10/MWh and the Bulgarian peak price of EUR 138.30/MWh.
Serbia’s hourly price curve also reveals a strong evening scarcity effect. The minimum price remained unusually high at EUR 113.10/MWh, while the maximum reached EUR 290/MWh during hour 21. By comparison, HUPX peaked at EUR 245.50/MWh, while Greece and Bulgaria reached EUR 249.80/MWh. The Serbian market therefore reflects both tight baseload availability and an additional evening scarcity premium caused by limited flexibility.
Cross-border flows confirm this situation. Serbia imports an average of 356 MW from Bulgaria and 315 MW from North Macedonia, with peak flows increasing to 400 MW and 419 MW respectively. Romania contributes an average of 59 MW, rising to 197 MW during peak periods. At the same time, Serbia exports around 70 MW towards Montenegro, leaving its balance dependent on electricity availability from southeastern neighbouring markets.
Domestic Serbian generation remains heavily dependent on lignite-based power production. The latest generation structure shows coal accounting for around 74%, hydropower 22%, gas 2% and wind only 2%. Thermal generation declined to an average of 2,426 MW on 6 August, compared with 2,838 MW previously, while wind production fell to only 53 MW. Hydropower remained relatively stable at 722 MW but was insufficient to compensate for lower thermal and wind output.
This generation structure creates particular vulnerability during evening hours. Solar production across the region can reduce prices during midday, but Serbia has significantly less photovoltaic capacity available to reshape its net-load curve compared with Hungary, Greece, Bulgaria and Romania. Once solar output declines after sunset, Serbia must compete for imported electricity while domestic wind production remains limited and thermal plants carry most of the remaining demand.
Hungary represents a different type of market exposure. Forecast consumption declines by 169 MW to 5,229 MW, but domestic generation falls sharply to only 2,549 MW, leaving the country dependent on net imports of 2,680 MW. Imported electricity therefore covers more than 51% of Hungarian demand, highlighting the country’s strong reliance on regional flows.
Hungary receives the majority of imports from Slovakia (1,656 MW) and Austria (1,255 MW), while Romania contributes only 48 MW under baseload conditions because the direction of Romanian-Hungarian flows reverses during off-peak hours. At the same time, Hungary exports around 413 MW towards Croatia, confirming its role as both a major importing market and a key electricity transit hub for the Western Balkans.
The Hungarian price curve remains highly unusual. Peak electricity on the HUPX market averages EUR 141.10/MWh, while off-peak electricity trades at EUR 174.80/MWh. The minimum price of EUR 96/MWh occurs during hour 13, while the maximum of EUR 245.50/MWh appears during hour 21. The almost EUR 150/MWh intraday spread demonstrates the growing separation between solar-supported daytime hours and the evening period dependent on thermal generation and imports.
Germany shows an even stronger version of the same structural trend. Peak electricity prices average only EUR 89/MWh, while off-peak prices rise to EUR 155.20/MWh. The minimum price falls to just EUR 13/MWh during hour 14, when solar generation reaches its highest output. However, this low-cost daytime electricity cannot fully reach Hungary and Southeast Europe because of cross-border transmission limitations, leaving southeastern consumers exposed to higher evening prices.
Romania’s daily balance is also deteriorating. Consumption rises to 6,150 MW, while generation reaches 5,395 MW, creating a net import requirement of 755 MW. Romania imports more than 1,000 MW from Bulgaria on average, although it can export electricity towards Hungary and Serbia during peak hours. This indicates that Romania remains structurally short over the full day but can temporarily become a regional supplier during selected high-value periods.
Bulgaria continues to represent the most important conventional export buffer in the Eastern Balkans. Generation reaches 5,256 MW, compared with consumption of 4,046 MW, allowing average exports of 1,211 MW. Electricity flows towards Romania reach 1,033 MW, including 1,626 MW during peak hours, while exports towards Serbia average 356 MW. Stable nuclear generation from the Kozloduy plant, at almost 1,886 MW, combined with coal, hydropower and solar production, gives Bulgaria a crucial role in regional electricity security.
Greece also remains a net exporter, with generation of 8,620 MW and demand of 7,469 MW. Its export surplus of 1,151 MW is directed towards Bulgaria, North Macedonia, Albania and Italy. However, the HENEX price increased by EUR 11.30/MWh to EUR 152.94/MWh, reflecting lower wind availability and greater reliance on gas-fired generation. Gas plants produced an average of 3,306 MW on the previous day, representing around 36% of Greece’s electricity mix.
Albania recorded the lowest regional electricity price at EUR 144.12/MWh, down by EUR 32.80/MWh. Generation of 1,093 MW almost fully covered consumption of 1,104 MW, leaving a negligible deficit of only 12 MW. Albania received around 169 MW from Greece while exporting 195 MW towards Montenegro, effectively operating as a transit market. Its lower price compared with Hungary and Serbia reflects favourable hydrological conditions and limited short-term system pressure.
Montenegro remained close to the regional price level at EUR 158.20/MWh, following the return of the Pljevlja Thermal Power Plant after a short outage. Domestic generation increased to 363 MW, but consumption reached 494 MW, leaving the country with a net import requirement of 130 MW. Montenegro receives electricity from Bosnia and Herzegovina, Serbia, Albania and Kosovo while exporting approximately 415 MW towards Italy.
The return of the Pljevlja plant reduced Montenegro’s domestic deficit, but the country continues to benefit from its position as a transit route towards the higher-priced Italian market. BELEN peak prices averaged EUR 136/MWh, while off-peak prices increased to EUR 180.40/MWh, confirming the wider regional trend of stronger dependence on evening and overnight electricity.
Fuel and carbon markets continue to support elevated forward electricity prices. Austrian CEGH gas increased to EUR 56.36/MWh, while September and fourth-quarter gas contracts traded around EUR 57/MWh. EU ETS carbon allowances increased to EUR 81.82/tCO₂, while September coal reached USD 115/t. These input costs limit the possibility of sustained electricity price declines once solar generation decreases.
The Hungarian forward curve confirms continued market risks. Week 33 electricity trades at EUR 174.50/MWh, Week 34 at EUR 161.50/MWh and September contracts at EUR 163.50/MWh. The September contract increased by EUR 6.50/MWh in a single session, while the Calendar 2026 contract reached EUR 122.50/MWh.
The decline in spot prices has therefore not translated into lower long-term risk expectations. European gas storage levels stood at only 57% full on 5 August, the lowest early-August level in fifteen years. At the same time, low Danube water levels continue affecting nuclear generation and fuel logistics. The Danube reference flow of approximately 4,385 cubic metres per second remains an important operational factor for the region.
Slovenia’s decision to keep the Krško nuclear power plant operating at minimum output until mid-August reduces the immediate risk of a complete nuclear outage, but its contribution has already weakened. Slovenia currently imports an average of 323 MW, receiving around 1,154 MW from Austria while exporting 682 MW towards Croatia.
The defining characteristic of the electricity market on 7 August is the simultaneous presence of lower average day-ahead prices and increased physical import dependence. Solar generation reduces prices during midday hours, but it does not eliminate the regional energy deficit. The imbalance returns during the evening period, when Serbia represents the clearest scarcity market, Hungary remains structurally dependent on northern imports, and Italy continues attracting electricity because of its persistent price premium.
For battery energy storage operators, flexible gas generators and demand-response providers, the greatest commercial opportunity remains concentrated in the transition between solar production hours and evening demand peaks. Industrial demand-shifting programmes in Romania demonstrate the same economic principle: moving electricity consumption from evening hours into periods of strong solar production can capture the widening price difference between renewable-rich and residual-load periods.
Serbia’s maximum price of EUR 290/MWh during hour 21, combined with a daily minimum of EUR 113.10/MWh, represents the clearest regional example of this emerging market structure. As renewable generation expands, the value of flexibility – through batteries, storage, demand management and flexible generation – is becoming as important as electricity production itself.