Southeast European day-ahead power prices rose sharply for delivery on Monday, 24 August, as weekday demand returned after the weekend, with Hungary, Romania, Bulgaria, Slovenia and Croatia converging around €170/MWh while Montenegro and Albania detached sharply from the regional core.
Hungarian HUPX baseload settled at €170.26/MWh, up €61.0/MWh day on day. Romania cleared marginally higher at €170.37/MWh, Bulgaria at €169.70/MWh, Slovenia at €169.66/MWh and Croatia at €169.45/MWh. Greece followed at €167.55/MWh. The five-market Hungary-Romania-Bulgaria-Slovenia-Croatia cluster was therefore separated by less than €1/MWh.
Serbian SEEPEX remained softer at €159.90/MWh, a discount of €10.37/MWh to Hungary, while North Macedonia settled at €155.77/MWh and Albania at €144.15/MWh.
Montenegro moved the other way. BELEN averaged €186.69/MWh, around €16.4/MWh above HUPX, while Italy remained the highest major neighbouring market at €192.76/MWh. Germany stood at only €143.18/MWh, leaving Hungary at a premium of roughly €27/MWh to the German market.
Demand rebounds
The rise was driven principally by the return of weekday consumption.
Aggregate HU+SEE demand increased by 3.64 GW from Sunday to 32.72 GW, while generation recovered to about 30.52 GW. The region consequently remained net short and required approximately 2.19 GW of net imports.
Imports from the Austria-Slovakia direction stood near 2.91 GW, even as the region exported roughly 1.13 GW toward Italy, underscoring the continuing north-to-south and westward redistribution of electricity through SEE.
Solar availability rose by almost 2.4 GW day on day, while wind was broadly unchanged. The additional photovoltaic output helped suppress midday prices despite the large recovery in demand.
Evening ramp drives shape
The hourly structure was more striking than the baseload move.
HUPX fell to €85/MWh at H14 before rising to €257.5/MWh at H21. Hungarian peak power averaged only €146.9/MWh, compared with an off-peak average of €193.7/MWh.
The same pattern was visible across the coupled core. Romania ranged between €84.3/MWh and €259.6/MWh, Bulgaria between €84.4/MWh and €258.7/MWh, while Greece also reached €258.7/MWh. Croatia recorded a maximum of €242.8/MWh.
The profile points to increasingly pronounced solar-driven midday compression followed by a steep evening ramp once photovoltaic production declines.
For prompt trading, the H19-H22 period is therefore carrying substantially more scarcity risk than the conventional peak block would suggest.
Hungary remains import dependent
Hungarian demand reached 4.30 GW, against generation of 3.21 GW, leaving the country with average net imports of roughly 1.08 GW.
Slovakia remained the largest source of power into Hungary, while Austria also supplied the market. Hungary simultaneously exported toward Croatia, Serbia and other neighbouring systems, reflecting changing hourly flow patterns.
The country’s aggregate cross-border balance was almost neutral during the peak block, at around 12 MW net import, but widened to more than 2.15 GW of net imports in off-peak hours.
That helps explain why Hungarian off-peak power was significantly more expensive than the standard peak product.
Serbia stays below HUPX
Serbia remained at a meaningful discount despite being physically short.
Domestic demand averaged 3.79 GW, compared with generation of around 3.26 GW, leaving a net import requirement of roughly 522 MW.
Serbia imported predominantly from Bulgaria, North Macedonia, Hungary and Bosnia and Herzegovina, while exporting smaller volumes toward Montenegro and Romania.
The €10.37/MWh SEEPEX-HUPX discount showed that national deficits alone were not determining regional pricing. Border availability and neighbouring marginal costs continued to play a major role in setting the Serbian price.
Greece flips back to exports
Greece meanwhile returned to a net export position.
Demand rose to 7.50 GW, while domestic generation increased to around 8.06 GW, producing net exports of approximately 563 MW. Greece had been a 256 MW net importer on Sunday.
Exports were directed mainly toward Italy, North Macedonia and Albania, while Greece continued to receive some electricity from Bulgaria.
Peak-period Greek exports reached almost 1 GW, helping keep HENEX slightly below the tightly coupled Hungary-Romania-Bulgaria cluster despite high cooling demand.
Montenegro detaches
Montenegro was the major outlier.
BELEN’s baseload price of €186.69/MWh was already elevated relative to neighbouring SEE markets, but the hourly curve showed a much more severe dislocation.
Montenegrin peak power averaged €220.4/MWh, while a maximum of €450.2/MWh was recorded at H15. Off-peak power averaged only €153/MWh.
The spike was not replicated in surrounding markets, indicating a local basis event rather than broad regional scarcity.
Montenegro itself remained short, with consumption around 473 MW and generation of approximately 335 MW, equivalent to a deficit of about 138 MW.
Limited liquidity and available cross-border capacity can therefore create substantial deviations on BELEN even when the wider SEE region is relatively well coupled.
Albania remains cheap despite deficit
Albania provided the opposite signal.
ALPEX settled at only €144.15/MWh, more than €26/MWh below HUPX, even though domestic demand of approximately 1.15 GW exceeded generation of about 1.00 GW. The country was therefore a net importer of around 150 MW.
The divergence between Montenegro and Albania — both physically short, but at opposite ends of the regional price range — illustrates the importance of local liquidity, interconnection capacity and bidding structure in the western Balkans.
Forwards less bullish than spot
The forward curve offered a more cautious signal than the spot market.
Hungarian Week 35 power was assessed at €143.50/MWh, down 8.6% over the reported seven-day period, while Germany Week 35 stood at €120/MWh, down 7.34%. Italy moved in the opposite direction, with Week 35 up 6.55% to €179/MWh.
Week 36 was at €146.50/MWh for Hungary, €126.50/MWh for Germany and €179.50/MWh for Italy.
The Hungarian front-week contract therefore remained almost €27/MWh below Monday’s HUPX day-ahead settlement, suggesting the forward market was not pricing the spot tightness as a sustained condition.
Fuel prices were firmer. Austrian CEGH September gas had risen 8.94% over the displayed period and Q4 gas 8.06%, while API2 September coal gained 4.1% and Q4 coal 2.79%.
The divergence between higher fuel costs, weaker German and Hungarian front-week power and stronger Italian contracts points to regional fundamentals — particularly renewable production, transmission availability and hourly flexibility — remaining the dominant near-term price drivers.
Trading view
The Monday rebound should therefore be viewed less as the start of a broad SEE price rally and more as a return of weekday demand combined with increasingly volatile intraday shape.
The central markets remain tightly coupled at baseload, but the main trading opportunities are shifting toward hourly spreads and peripheral basis positions.
Key levels to watch are the H19-H22 evening ramp, Austria-Slovakia imports into Hungary, the persistent Germany-Hungary discount, Italy’s premium to SEE, Serbia’s import requirement and whether the exceptional Montenegro basis normalises.
Strong solar output can continue to depress midday values, but if dispatchable capacity and import availability tighten during the evening ramp, prompt volatility is likely to remain elevated even without a sustained rise in weekly baseload contracts.
