Southeast European day-ahead power prices rose sharply for delivery on Monday, 24 August, as electricity demand returned to normal weekday levels following the weekend. Hungary, Romania, Bulgaria, Slovenia and Croatia converged around €170/MWh, while Montenegro and Albania moved in opposite directions, highlighting growing differences between tightly coupled central markets and less liquid peripheral markets.
Hungary’s HUPX baseload settled at €170.26/MWh, increasing by €61/MWh day on day. Romania cleared at €170.37/MWh, Bulgaria at €169.70/MWh, Slovenia at €169.66/MWh and Croatia at €169.45/MWh. The five-market cluster was therefore separated by less than €1/MWh. Greece followed at €167.55/MWh.
Serbia remained cheaper, with SEEPEX settling at €159.90/MWh, €10.37/MWh below Hungary. North Macedonia cleared at €155.77/MWh and Albania at €144.15/MWh. Montenegro moved in the opposite direction, with BELEN averaging €186.69/MWh, while Italy remained the highest major neighbouring market at €192.76/MWh. Germany stood at €143.18/MWh, leaving Hungary at a premium of roughly €27/MWh.
Weekday demand drives the rebound
The main driver behind Monday’s price increase was the return of weekday electricity consumption. Aggregate HU+SEE demand increased by 3.64 GW from Sunday to 32.72 GW, while generation recovered to approximately 30.52 GW. The region therefore remained structurally short and required around 2.19 GW of net imports.
Imports from the Austria-Slovakia direction reached approximately 2.91 GW, while the region simultaneously exported around 1.13 GW toward Italy. The flows illustrate the continuing redistribution of electricity across Southeast Europe, with northern and western markets supplying deficit areas while surplus generation moves toward Italy.
Solar generation increased by almost 2.4 GW day on day, while wind output remained broadly unchanged. The additional photovoltaic production helped suppress prices during the middle of the day despite the significant recovery in overall demand.
Evening ramp becomes the key trading window
The hourly price structure was considerably more significant than the movement in baseload prices. HUPX fell to €85/MWh at H14 before climbing to €257.5/MWh at H21.
Hungarian peak power averaged €146.9/MWh, compared with an off-peak average of €193.7/MWh, demonstrating how conventional peak and off-peak products are becoming less representative of the actual intraday price structure.
Similar dynamics were visible across the coupled markets. Romania moved 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 pattern reflects the growing impact of solar generation on daytime prices, followed by a steep increase in prices as photovoltaic output declines and demand remains elevated. For short-term traders, the H19-H22 period is therefore becoming a particularly important window for managing scarcity and ramping risk.
Hungary remains dependent on imports
Hungarian demand reached approximately 4.30 GW, while domestic generation stood at 3.21 GW, leaving the country with average net imports of around 1.08 GW.
Slovakia remained the largest source of imports, with Austria also supplying electricity to the Hungarian market. At the same time, Hungary exported toward Croatia, Serbia and other neighbouring markets as hourly flow patterns changed.
Interestingly, Hungary’s aggregate cross-border balance was almost neutral during the peak period, at around 12 MW of net imports, while off-peak net imports exceeded 2.15 GW. This helps explain the unusual relationship between the peak and off-peak products and highlights the importance of analysing hourly flows rather than relying solely on standard block prices.
Serbia remains below the regional core
Serbia also remained physically short, although its wholesale price stayed below the central European cluster. Domestic demand averaged 3.79 GW against generation of around 3.26 GW, creating a net import requirement of approximately 522 MW.
Serbia imported primarily from Bulgaria, North Macedonia, Hungary and Bosnia and Herzegovina, while smaller export flows moved toward Montenegro and Romania.
The €10.37/MWh discount between SEEPEX and HUPX demonstrates that national supply-demand balances alone do not determine regional prices. Cross-border capacity, neighbouring market conditions and the marginal cost of available electricity continue to play an important role in Serbian price formation.
Greece returns to a net export position
Greece moved back into a net export position on Monday. Demand increased to approximately 7.50 GW, while domestic generation reached around 8.06 GW, resulting in net exports of roughly 563 MW.
This represented a clear reversal from Sunday, when Greece had been a net importer of around 256 MW.
Exports were directed mainly toward Italy, North Macedonia and Albania, while some electricity continued to flow into Greece from Bulgaria. Greek exports during peak hours approached 1 GW, helping HENEX remain slightly below the tightly coupled Hungary-Romania-Bulgaria price cluster despite strong cooling-related demand.
Montenegro records a major local price divergence
Montenegro was the clearest outlier in the region. BELEN’s baseload price reached €186.69/MWh, already well above most neighbouring markets, but the hourly profile showed an even more pronounced divergence.
Montenegrin peak power averaged €220.4/MWh, while the market recorded a maximum of €450.2/MWh at H15. Off-peak prices averaged just €153/MWh.
The spike was not reflected across neighbouring markets, pointing to a local basis event rather than a region-wide shortage. Montenegro itself remained short, with consumption of around 473 MW against generation of approximately 335 MW, leaving a deficit of about 138 MW.
The episode demonstrates how limited liquidity and cross-border capacity can produce significant price deviations in BELEN even when the wider Southeast European market remains relatively well connected.
Albania sends the opposite signal
Albania provided a contrasting example. ALPEX settled at only €144.15/MWh, more than €26/MWh below HUPX, despite domestic demand of approximately 1.15 GW exceeding generation of around 1.00 GW.
The country therefore required roughly 150 MW of net imports, yet remained one of the cheapest markets in the region.
The contrasting situations in Montenegro and Albania are particularly significant because both markets were physically short. Their very different prices demonstrate the importance of market liquidity, interconnection availability and local bidding structures in determining wholesale prices across the Western Balkans.
Forward market remains more cautious
The forward curve presented a considerably less bullish picture 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 rising 6.55% to €179/MWh.
For Week 36, Hungary was assessed at €146.50/MWh, Germany at €126.50/MWh and Italy at €179.50/MWh.
Hungarian front-week power was therefore almost €27/MWh below Monday’s HUPX day-ahead price, suggesting that forward traders were not pricing the current spot tightness as a persistent market condition.
Fuel markets were firmer. Austrian CEGH September gas had risen 8.94% over the displayed period, while Q4 gas gained 8.06%. API2 September coal increased 4.1% and Q4 coal 2.79%.
The combination of higher fuel prices, weaker German and Hungarian front-week power and stronger Italian contracts suggests that regional electricity fundamentals remain more influential than fuel costs alone. Renewable output, transmission availability and the supply of flexible generation are likely to remain the key short-term drivers.
Trading outlook
Monday’s price rebound should therefore be viewed less as the beginning of a broad Southeast European power rally and more as a return of weekday demand combined with increasingly volatile intraday price formation.
The central markets remain closely coupled at the baseload level, but trading opportunities are increasingly shifting toward hourly spreads and peripheral basis positions. The evening ramp is particularly important as solar output falls and flexible generation and imports become more valuable.
Traders will need to monitor the H19-H22 ramp, Austria-Slovakia flows into Hungary, the Germany-Hungary price differential, Italy’s persistent premium over Southeast Europe, Serbia’s import requirement and the evolution of the exceptional Montenegro basis.
Strong solar generation can continue to suppress midday prices, but tightening dispatchable capacity or reduced import availability during the evening could keep prompt volatility elevated even if weekly baseload forward contracts remain comparatively subdued.