The Southeast European day-ahead electricity market entered Tuesday with a familiar summer imbalance: strong solar generation during midday hours, constrained availability of thermal and nuclear capacity outside solar periods, weak hydrological conditions and an increasingly expensive evening ramp. The result was not a uniform regional price increase, but a fragmented market where Slovenia, Italy, Croatia and Romania recorded the highest baseload prices, while Greece, Bulgaria, Albania and Montenegro remained significantly cheaper.
The market structure reflected a growing challenge for the region’s power systems. Rising solar penetration is creating periods of abundant electricity supply during daylight hours, but limited dispatchable generation, insufficient storage capacity and reduced hydro flexibility are leaving markets exposed during the evening transition when solar output disappears.
Hungary’s HUPX baseload price increased by €8.30/MWh to €186.90/MWh, representing a daily rise of 4.6%. Romania settled slightly higher at €188.24/MWh, while Slovenia recorded the highest directly observed Southeast European price at €194.61/MWh. Croatia followed at €191.92/MWh, and Italy’s national day-ahead market reached €194.94/MWh.
Southern markets remained considerably cheaper. Greece traded at €155.03/MWh, Bulgaria at €157.03/MWh, Albania at €153.56/MWh and Montenegro at €159.55/MWh. North Macedonia increased to €165.43/MWh, while Serbia remained near the middle of the regional curve at €174.64/MWh.
The spread between the highest and lowest major SEE markets reached €41.05/MWh, measured between Slovenia and Albania. Including Germany and Italy, the difference widened to €45.15/MWh. This price separation is significant because it shows that available cross-border transmission capacity was not sufficient to fully balance regional electricity values during the evening scarcity period.
Daily baseload prices, however, do not fully capture the severity of the hourly imbalance. HUPX reached a minimum of €76.50/MWh at H14, when solar production was strongest, before rising sharply to €418.90/MWh at H20. Romania followed a similar pattern, reaching €433.90/MWh at H20, while Slovenia recorded the strongest evening increase with a peak of €507.60/MWh.
Croatia reached €478.80/MWh, while Serbia climbed to €496.80/MWh during the same evening scarcity window. By comparison, Germany peaked at €240/MWh, Austria at €245.40/MWh and Italy’s national market at €267.40/MWh. The difference demonstrates that the largest pressure was concentrated in the Hungary–Romania–Western Balkans corridor, where flexible supply was more limited.
The market event was therefore not a general shortage across all delivery hours, but a short-duration scarcity event concentrated around H20. It rewarded flexible resources capable of responding during the evening ramp, including gas-fired generation, pumped storage, batteries and demand-side flexibility, while making traditional baseload averages increasingly poor indicators of the actual costs faced by consumers with demand concentrated after sunset.
Regional electricity consumption was forecast at an average of 34,191 MW, an increase of 1,445 MW, or 4.4%, compared with Monday. Higher temperatures contributed to stronger demand, with regional temperatures increasing by almost 1°C, while Greece was expected to average 28.6°C.
Hungary’s consumption remained relatively stable at 5,023 MW, but demand increased across several larger SEE markets, including Romania at 5,923 MW, Greece at 7,251 MW, Serbia at 4,030 MW and Croatia at 2,589 MW. The combination of higher consumption, weak hydro conditions and limited flexible generation continued to increase pressure on regional electricity balances.
Estimated regional electricity generation increased to 32,604 MW, approximately 5.2% higher than Monday, allowing net imports to decline from 1,740 MW to 1,587 MW despite stronger consumption. Imports still covered around 4.6% of total regional demand, showing that the region remained dependent on external supply during periods of tighter system conditions.
The regional average deficit, however, concealed significant differences between individual markets. Hungary remained the largest structural importer, with average imports of 2,269 MW, equivalent to approximately 45% of domestic consumption. Croatia imported 1,197 MW, representing more than 46% of demand, while Serbia recorded a deficit of 496 MW. Romania imported 437 MW, Montenegro 305 MW, Slovenia 84 MW and Kosovo 142 MW.
Montenegro faced the largest relative supply gap, with imports covering almost 62% of forecast consumption. Domestic generation was estimated at only 187 MW, compared with demand of 492 MW. The decline in Montenegro’s BELEN day-ahead price by €36.60/MWh to €159.55/MWh therefore did not reflect stronger domestic supply conditions. Instead, prices were influenced by the availability and pricing of surrounding imports, particularly from Bosnia and Herzegovina, Serbia, Albania and the Italian interconnector.
On the export side, Bulgaria and Greece remained the main southeastern supply anchors. Bulgaria was expected to export 1,425 MW, equivalent to more than 36% of domestic consumption, while Greece’s net exports reached 1,506 MW, or approximately 21% of demand. Bosnia and Herzegovina exported 245 MW, North Macedonia 157 MW, and Albania recorded only a marginal export position of 10 MW.
Electricity flows created two main regional supply corridors. Northern imports from Austria and Slovakia into Hungary and Slovenia averaged 2,475 MW, around 7.4% lower than Monday. At the same time, Bulgaria supplied approximately 1,536 MW towards Romania and 366 MW towards Serbia.
Greece continued to support neighbouring markets, exporting 456 MW towards Bulgaria, 433 MW towards North Macedonia, 157 MW towards Albania and the full scheduled 500 MW towards Italy. These flows underline the increasing importance of regional interconnection as markets manage uneven generation conditions.
Romania operated as both a deficit market and a transit hub. While the country imported electricity from Bulgaria, it simultaneously exported 953 MW towards Hungary and 237 MW towards Moldova. Romania’s overall position was an average net import of 437 MW, but the direction of flows changed significantly throughout the day.
During peak hours, Romania moved into a 109 MW net export position, while during lower-demand periods it imported almost 984 MW. The changing direction of electricity flows reflected the interaction between Romanian solar production, Bulgarian exports and tighter conditions in Hungary.
The traditional distinction between peak and off-peak periods is becoming less useful in the current summer market structure. Hungary’s average import position was 2,269 MW, but imports increased to 3,096 MW during off-peak hours, compared with 1,441 MW during peak periods.
This reflects a major shift caused by solar generation. In today’s market, “off-peak” no longer necessarily means lower system pressure, because the hours after sunset often combine falling solar output with rising residential and commercial demand.
The generation mix explains the pricing pattern. Regional coal generation increased by 1,235 MW to 7,034 MW, while gas-fired generation rose by 766 MW to 5,408 MW. Hydropower output improved by 778 MW to 5,451 MW, but remained below levels needed to restore normal flexibility.
Solar production increased to 7,471 MW, while wind generation declined by 832 MW to only 1,747 MW. Nuclear generation remained weak at 3,348 MW, limiting the availability of stable low-carbon baseload capacity during the evening transition.
Hungary remained one of the markets most exposed to the evening scarcity period. Nuclear production averaged only 174 MW, while gas-fired generation increased to 942 MW. Solar generation contributed 1,422 MW, representing approximately half of domestic electricity production during daylight hours, but this capacity was unavailable when prices reached their highest levels after sunset.
As a result, Hungary relied heavily on imports from Slovakia, Austria and Romania while maintaining smaller export flows towards Croatia and neighbouring markets. The situation highlights the growing importance of flexibility resources as solar capacity expands faster than the ability of the system to replace lost evening generation.
For Tuesday, regional solar production was forecast at 8,700 MW, an increase of 1,229 MW, or 16.5%, while wind generation was expected to reach only 1,842 MW, just 95 MW higher than the previous day. Solar alone could cover approximately 25.4% of average regional consumption, but its concentration around midday explains why stronger renewable output did not prevent evening prices above €400/MWh.
The strong solar forecast supported the regional midday price minimum of approximately €76.50/MWh at H14 across Hungary, Romania, Slovenia, Croatia, Austria and Germany. However, the same synchronised solar output intensified the post-sunset ramp because multiple markets lost renewable generation at almost the same time.
Systems unable to bring sufficient hydro, nuclear, gas-fired generation or cross-border imports into the market during the H19-H21 period experienced the strongest price increases. This pattern confirms that future market value will increasingly depend not only on installed renewable capacity, but on the availability of technologies capable of shifting energy across hours.
Serbia provides a clear example of the difference between lower average prices and actual system security. The SEEPEX baseload price declined by €10.60/MWh to €174.64/MWh, placing Serbia at a €12.25/MWh discount compared with HUPX. However, the lower daily average did not eliminate exposure to extreme hourly volatility.
Serbia’s peak price remained almost unchanged at €158/MWh, while the maximum hourly price reached €496.80/MWh. Most of the daily price reduction came from the off-peak period, which declined from €210.90/MWh to €191.30/MWh.
The country remained a net importer of electricity, with an average deficit of 496 MW. During peak hours, the shortfall widened to 797 MW, with Bulgaria supplying an average of 366 MW and North Macedonia 358 MW. Serbia exported smaller volumes towards Romania, Montenegro and Croatia.
Domestic generation remained heavily dependent on coal. Serbian lignite-fired power plants produced 2,944 MW, representing approximately 79% of reported domestic generation. Hydropower recovered to 621 MW from 416 MW on Sunday, but remained far below the flexibility normally provided by the Drina and Danube hydro portfolio.
Wind production declined to only 110 MW, leaving Serbia increasingly dependent on lignite availability, imports and regional market conditions during the most expensive hours. The combination of low hydro output and high evening demand continues to expose the system to sharp price movements.
The SEEPEX discount should therefore be interpreted as a market-location effect rather than evidence of comfortable supply conditions. A market capable of reaching an average price of €174.64/MWh and an hourly maximum close to €500/MWh presents significant shape risk for utilities, industrial consumers and suppliers whose consumption profile does not match periods of lower solar-driven prices.
Croatia and Slovenia experienced an even stronger scarcity premium. CROPEX increased by €12.70/MWh to €191.92/MWh, while Slovenia’s BSP market rose by €14.30/MWh to €194.61/MWh.
Croatia imported 1,197 MW against domestic generation of 1,391 MW, relying mainly on electricity from Slovenia and Hungary. Average imports included approximately 672 MW from Slovenia and 424 MW from Hungary.
Slovenia maintained a relatively balanced daily position but still exported approximately 672 MW towards Croatia while importing around 720 MW from Austria. These transit flows contributed to the evening price pressure, with Slovenia reaching €507.60/MWh and Croatia €478.80/MWh during the peak scarcity period.
The high evening prices in Slovenia and Croatia reflected the broader regional shortage of flexible capacity rather than a simple lack of total electricity supply. Both countries remained connected to neighbouring markets, but available transmission capacity could not fully offset the simultaneous loss of solar generation and limited availability of flexible domestic resources.
Southern Southeast Europe avoided the same level of baseload pressure because Greece and Bulgaria maintained stronger export capability. Greece’s HENEX day-ahead price increased only slightly by €1.10/MWh to €155.03/MWh, while Bulgaria’s IBEX price declined by €1.10/MWh to €157.03/MWh. Both markets recorded evening maximum prices of approximately €278/MWh, significantly below the levels reached in Hungary, Romania, Serbia, Croatia and Slovenia.
Greece benefited from a more diversified generation mix, combining solar, wind, gas-fired generation and hydro resources. The country’s peak average price remained relatively low at €112.20/MWh, supported by strong renewable output and available thermal capacity.
Greek generation on Monday included approximately 2,778 MW from gas-fired plants, 3,031 MW from solar, 1,396 MW from wind and 792 MW from hydropower. This combination allowed Greece to maintain export capacity even during a period of regional market tightness.
Bulgaria continued to benefit from stable nuclear generation, with approximately 1,890 MW of nuclear capacity available, supported by coal-fired generation, solar production and cross-border exchanges. The country’s export position helped relieve pressure in neighbouring markets, particularly Romania and Serbia.
North Macedonia experienced a stronger price increase, with the MEMO day-ahead price rising by €27.40/MWh to €165.43/MWh. The increase was driven by a €34.90/MWh rise in the peak block and stronger export activity.
The country’s net export position increased from 43 MW to 157 MW, with electricity flows directed mainly towards Serbia and Kosovo. Albania also recorded a price increase, with the market rising by €17.50/MWh to €153.56/MWh, although it remained the cheapest market in Southeast Europe despite returning to a marginal export position.
Fuel markets provided limited relief. Although some energy commodities declined, they remained high enough to preserve a significant thermal generation premium across the region. The CEGH gas price decreased by €1.40/MWh to €58.92/MWh, while Greek gas prices increased to €53.99/MWh.
European carbon allowances eased slightly to €80.86/t, September coal declined to $118/t, and September gas traded at approximately €58.50/MWh. These levels continued to influence the operating economics of gas and coal-fired generation, particularly during periods when renewable output was insufficient.
Forward electricity markets showed signs that traders viewed the current tightness as a short-term event rather than a permanent structural repricing. Hungarian forward power prices declined across the curve, with Week 33 falling by €12/MWh to €182.50/MWh, Week 34 dropping to €159/MWh, September contracts declining to €167/MWh, and the 2026 calendar contract falling to €122.50/MWh.
The difference of €23.50/MWh between Week 33 and Week 34 indicates that the market continues to price the current pressure as an immediate summer scarcity event rather than a long-term change in the expected balance of supply and demand.
The HUPX premium over Germany narrowed by €13.40/MWh to €37.11/MWh, mainly because German baseload prices increased by €21.70/MWh to €149.79/MWh. Hungary’s premium over Greece widened to €31.86/MWh, reflecting stronger pressure in the northern part of the SEE market.
Forward Hungary–Germany spreads remained elevated, reaching €53.50/MWh for Week 33, €34.50/MWh for Week 34 and €34.50/MWh for September. These spreads continue to highlight the value of cross-border transmission capacity between Central Europe and Southeast Europe.
The immediate market signal remains concentrated in the hourly price profile rather than the average baseload direction. Strong solar forecasts continue to support lower midday prices, but limited nuclear availability, weak wind output and drought-sensitive hydro generation leave the evening period vulnerable to sudden price increases.
Flexible assets such as gas-fired plants, pumped-storage facilities, batteries and interruptible industrial demand are gaining increasing value because they can respond precisely during the hours when the market experiences the greatest imbalance.
For industrial consumers, hedging strategies based only on baseload contracts may no longer fully protect against short periods of extreme price volatility. During the latest market event, hourly prices approached €500/MWh in Serbia, Croatia and Slovenia, creating significant exposure for companies whose electricity consumption is concentrated after sunset.
At the same time, the price difference between the midday solar minimum and the evening peak created substantial opportunities for flexible technologies. The spread reached approximately €342/MWh in Hungary, €357/MWh in Romania, €431/MWh in Slovenia and €427/MWh in Serbia, demonstrating the growing economic value of storage and fast-response generation.