Southeast European day-ahead electricity prices increased sharply on Wednesday, 26 August, with the main Hungary-Romania-Bulgaria-Greece cluster settling between €184/MWh and €187/MWh. Hungary’s HUPX baseload day-ahead price closed at €184.04/MWh, up €8.70/MWh from the previous day. Romania was the most expensive market in the central SEE group at €186.50/MWh, followed by Bulgaria at €185.33/MWh and Greece at €184.47/MWh. Croatia rose to €182.56/MWh and Slovenia reached €181.82/MWh.
The six markets stayed within a narrow spread of less than €5/MWh, indicating strong convergence across the central Hungary-SEE trading area. The higher level was not linked primarily to demand growth, as forecast consumption across Hungary and SEE rose by only 100 MW day on day to an average of 33.755 GW. Regional temperatures were expected to ease slightly.
Cross-border flows tighten as Italy demand stays expensive
Instead, the regional cross-border balance tightened, with total net imports falling by 182 MW to 2.521 GW. Inflows from the Austria-Slovakia core increased by 354 MW to 3.235 GW, while exports towards Italy rose by about 446 MW to 1.097 GW. This meant more power entered northern parts of the SEE system from Central Europe while a larger volume was simultaneously directed to Italy.
Italy cleared at €198.08/MWh, around €14/MWh above HUPX, supporting continued westbound and south-westbound flows where transmission capacity allowed. Germany remained much cheaper at €153.65/MWh, leaving Hungary with a €30.39/MWh premium versus Germany. Austria was closer to Hungary at €178.19/MWh.
The resulting structure placed SEE between relatively cheaper Central European supply and more expensive Italian demand, with the HU-DE spread narrowing by around €3.60/MWh from the previous session. The wider Italian premium also strengthened the economic pull on electricity available in Slovenia, Croatia and the Western Balkans.
Late-evening price ramps dominate hourly curves
The hourly price pattern explained the elevated baseload levels across markets. On HUPX, prices fell to a daily low of €129.90/MWh in hour 14 before rising rapidly as solar generation declined, reaching €246.50/MWh in hour 23. The Hungarian peak-load average was €169.20/MWh and off-peak averaged €198.90/MWh, reflecting concentration of very high prices in late evening hours.
A similar profile appeared on Romania’s OPCOM market, where prices dropped to €124/MWh in hour 14 before climbing to €251.80/MWh in hour 23. Romania’s off-peak average reached €205.10/MWh compared with a peak product average of €167.90/MWh.
Bulgaria recorded a daily minimum of €124.30/MWh and a maximum of €249.10/MWh in hour 23, while Greece moved from around €121/MWh during solar-heavy midday hours to about €250/MWh in the evening.
The market shape increasingly reflected the solar ramp rather than a traditional working-day peak, with photovoltaic output suppressing prices around midday but solar withdrawal creating higher requirements for dispatchable generation and imports during evening hours.
Renewables output shifts; dispatchable generation increases
Renewable generation provided a mixed signal for Wednesday’s market outcomes. Regional solar output was forecast at approximately 7.923 GW, up around 1.453 GW day on day, while wind generation was expected to fall by approximately 867 MW to just 1.137 GW. Much of the additional photovoltaic output arrived during hours when prices were already close to daily lows.
The generation mix pointed toward greater reliance on dispatchable capacity as coal generation increased by 577 MW to 7.218 GW, gas-fired generation rose by 539 MW to 5.248 GW, and nuclear output increased by 298 MW to 4.055 GW. At the same time, wind fell by 766 MW to 2.003 GW, solar declined by 389 MW to 6.470 GW, and hydro slipped by 137 MW to 4.945 GW.
The fuel complex showed mixed movements: the CEGH gas marker stood at €68.02/MWh down €1.10/MWh, while the Greek gas marker increased by €3.40/MWh to €65.43/MWh; EU allowances reached €84.42/t up €0.60/t; September coal was at $127.50/t and Q4 eased to $128/t.
Paks output recovers but Hungary remains a net importer
Paks nuclear availability continued improving into Wednesday even as HUPX prices rose further from the prior session date referenced in the market data for 25 August and Danube conditions affecting output levels . Three reactors were operating close to full capacity on 25 August with units 1-3 producing around 1.448 GW, while unit 4 had restarted and generated approximately 244 MW for total site output around 1.69 GW.
Total production of approximately 2 GW was expected to return as Danube conditions improved, and Hungarian nuclear production averaged around 1.632 GW on 25 August versus 1.304 GW a day earlier and just 828 MW on 23 August . Despite this recovery, Hungary remained a substantial net importer for Wednesday, averaging approximately 942 MW.
Northern SEE imports rise; Romania tightens most clearly
The wider regional system allowed electricity entering from Slovakia and Austria to be directed towards Romania, Croatia, Serbia and Slovenia while Italy remained a higher-priced destination for available power . Romania showed one of the clearest tightening points: its average net import requirement increased to approximately 751 MW from about 290 MW on the previous day as consumption rose to around 5.94 GW.
Romania traded at about €2.45/MWh above HUPX, while commercial Hungary-Romania flows reached approximately 756 MW baseload including more than 1.4 GW during off-peak periods . Bulgaria stayed a net exporter with average net exports around 896 MW compared with about 1.018 GW a day earlier.
Greece was almost balanced with average net imports of just 25 MW, while Hungary imported around 942 MW, Croatia about 945 MW and Serbia around 426 MW . Together these flows produced a regional net import requirement of 2.521 GW.
Western Balkans trade discounts; forward curve strengthens near term
The Western Balkans markets traded at discounts versus the central SEE cluster: SEEPEX in Serbia increased by €4.80/MWh to €162.78/MWh leaving it €21.26/MWh below HUPX . North Macedonia’s MEMO rose by €3.80/MWh to €169.31/MWh while Montenegro’s BELEN reached €176.23/MWh after gaining €11.60/MWh.
An exception was Albania where ALPEX fell by €17/MWh to €153.65/MWh widening its discount versus HUPX to more than €30/MWh . Hourly prices in Serbia ranged from €113.10/MWh in hour 12 to €228/MWh in hour 20; Montenegro moved from about €130/MWh to around €230/MWh; North Macedonia reached up to €240.50/MWh despite its lower baseload average .
Differentiated pricing across Germany, central SEE and Italy; curve moves higher early
The regional price structure remained directional rather than uniform: Germany traded around €154/MWh, central SEE around €182-€187/MWh, Western Balkans between roughly €154-€176/MWh, and Italy close to €198/MWh. The short-term Hungarian forward curve strengthened with Week 36 up by €7.50/MWh to €154/MWh and Week 37 rising by €5/MWh to e156 Mwh . September gained another €2/MWh to reach €165/MWh.
The Calendar year contract for 2026, however, declined by €0.50/MWh to €133/MWh. The front-end increase alongside broadly stable longer-term pricing indicated near-term operational tightness rather than a structural repricing of power . For upcoming sessions, the main risk remained continued sensitivity around the evening ramp as solar output can keep prices lower during hours such as 12-16.
