Day-ahead electricity prices in Southeast Europe rose sharply for delivery on Monday, 24 August, after demand returned to normal weekday levels following the weekend. In the tightly coupled core, Hungary, Romania, Bulgaria, Slovenia and Croatia converged around €170/MWh. Prices diverged in the periphery, with Montenegro and Albania moving in opposite directions.
Hungary’s HUPX baseload settled at €170.26/MWh, up 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 separated by less than €1/MWh, while Greece followed at €167.55/MWh.
Serbia remained cheaper than the regional core, with SEEPEX settling at €159.90/MWh, or €10.37/MWh below Hungary. North Macedonia cleared at €155.77/MWh and Albania at €144.15/MWh. Montenegro moved higher with BELEN averaging €186.69/MWh, while Italy was the highest major neighbouring market at €192.76/MWh.
Demand and generation shift the regional balance
The price rebound coincided with a return of weekday consumption across the HU+SEE area. Aggregate HU+SEE demand increased by 3.64 GW from Sunday to 32.72 GW, while generation recovered to approximately 30.52 GW. That left the region structurally short and requiring around 2.19 GW of net imports.
Imports from the Austria-Slovakia direction reached approximately 2.91 GW, while exports toward Italy were around 1.13 GW. Solar output increased by almost 2.4 GW day on day as wind output stayed broadly unchanged. The additional photovoltaic generation helped suppress prices during the middle of the day despite higher overall demand.
Hourly volatility widens as solar output declines
The hourly price pattern showed larger moves than baseload levels across the market area. On HUPX, prices fell to €85/MWh at H14 before rising to €257.5/MWh at H21. Hungarian peak power averaged €146.9/MWh versus an off-peak average of €193.7/MWh.
Coupled markets showed similar intraday dynamics, with Romania ranging between €84.3/MWh and €259.6/MWh and Bulgaria between €84.4/MWh and €258.7/MWh; Greece also reached €258.7/MWh. Croatia recorded a maximum of €242.8/MWh during the session.
The intraday structure reflected lower daytime prices linked to solar generation followed by steep increases as photovoltaic output declined and demand remained elevated . For short-term trading, the H19-H22 period was identified as a key window for managing scarcity and ramping risk .
Hungary’s import dependence and cross-border flows
Hungarian demand reached approximately 4.30 GW, while domestic generation stood at 3.21 GW. That left average net imports of around 1.08 GW. Slovakia remained the largest source of imports, with Austria also supplying electricity into Hungary.
At the same time, Hungary exported toward Croatia, Serbia and other neighbouring markets as hourly flow patterns changed . During peak hours, Hungary’s aggregate cross-border balance was close to neutral at around 12 MW net imports, while off-peak net imports exceeded 2.15 GW. This contributed to differences between peak and off-peak products relative to hourly flow conditions.
Serbia stays short below the central cluster
Serbia remained physically short while its wholesale price stayed below the central European cluster . Domestic demand averaged 3.79 GW, compared with 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.
Smaller export flows moved toward Montenegro and Romania . The spread between SEEPEX and HUPX was €10.37/MWh, indicating that national supply-demand balances alone did not determine regional pricing . Cross-border capacity constraints and neighbouring market conditions were cited as factors affecting Serbian price formation.
Greece returns to net exports; Montenegro diverges locally
Greece returned to a net export position on Monday after Sunday’s import position of around 256 MW. Demand increased to approximately 7.50 GW, while domestic generation reached around 8.06 GW, resulting in net exports of roughly 563 MW. Exports were directed mainly toward Italy, North Macedonia and Albania.
A portion of electricity continued to flow into Greece from Bulgaria . Peak-hour exports approached 1 GW, helping HENEX remain slightly below the tightly coupled Hungary-Romania-Bulgaria price cluster despite strong cooling-related demand .
Montenegro’s BELEN recorded a major local divergence from neighbouring markets . BELEN baseload averaged €186.69/MWh, while hourly prices showed a sharper split: Montenegrin peak power averaged €220.4/MWh and a maximum of €450.2/MWh occurred at H15; off-peak prices averaged just €153/MWh.
The spike was not mirrored across adjacent markets, consistent with a local basis event rather than a region-wide shortage . Montenegro remained short with consumption around 473 MW against generation of approximately 335 MW, leaving a deficit of about 138 MW. The episode highlighted how limited liquidity and cross-border capacity can produce significant deviations in BELEN even when wider Southeast Europe stays relatively well connected .
Albania remains cheap despite being short; forward curve lags spot tightness
Albania’s ALPEX settled at €144.15/MWh, more than €26/MWh below HUPX . Domestic demand was approximately 1.15 GW, exceeding generation of around 1.00 GW, implying roughly 150 MW of net imports . Despite physical shortness similar to Montenegro’s situation, Albania traded among the lowest prices in the region.
The forward market presented a less bullish picture than spot trading . Hungarian Week 35 power was assessed at €143.50/MWh (down 8.6% over the reported seven-day period), Germany Week 35 at €120/MWh (down 7.34%), while Italy Week 35 rose 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.
The Hungarian front-week contract level was therefore almost €27/MWh below Monday’s HUPX day-ahead price, indicating that forward pricing did not reflect current spot tightness as persistent . Fuel markets were firmer with Austrian CEGH September gas up 8.94% over the displayed period and Q4 gas up 8.06%, while API2 September coal increased 4.1% and Q4 coal gained 2.79% . Renewable output changes, transmission availability and flexible generation supply were described as key short-term drivers alongside these fuel moves .
