Southeast European day-ahead electricity prices moved sharply higher for Wednesday, 26 August, with the main Hungary-Romania-Bulgaria-Greece cluster settling between €184/MWh and €187/MWh. Stronger cross-border demand, lower regional net imports and a pronounced late-evening price ramp outweighed improving nuclear availability in Hungary.
Hungary’s HUPX day-ahead baseload price settled at €184.04/MWh, up €8.70/MWh day on day. Romania was the most expensive market in the central SEE cluster at €186.50/MWh, an increase of €11.50/MWh, followed by Bulgaria at €185.33/MWh and Greece at €184.47/MWh. Croatia rose to €182.56/MWh, while Slovenia reached €181.82/MWh.
The six markets therefore remained within a narrow range of less than €5/MWh, highlighting strong price convergence across the central Hungary-SEE trading area.
The move higher was not primarily driven by stronger electricity demand. Forecast consumption across Hungary and SEE increased by only 100 MW day on day to an average of 33.755 GW, while regional temperatures were expected to ease slightly.
Instead, the regional cross-border balance became tighter. Total net imports fell by 182 MW to 2.521 GW, despite a 354 MW increase in inflows from the Austria-Slovakia core, which reached 3.235 GW. At the same time, exports towards Italy increased by approximately 446 MW, reaching 1.097 GW.
This combination is important for understanding Wednesday’s price formation. More electricity was entering the northern part of the SEE system from Central Europe, but a larger volume was simultaneously being directed towards Italy, where prices were significantly higher.
Italy cleared at €198.08/MWh, around €14/MWh above HUPX, creating a strong economic incentive to maintain westbound and south-westbound flows wherever transmission capacity allowed. Germany, meanwhile, remained much cheaper at €153.65/MWh, leaving Hungary with a €30.39/MWh premium to the German market.
Austria was considerably closer to Hungary, at €178.19/MWh.
The resulting market structure positioned SEE between relatively cheaper Central European supply and more expensive Italian demand. The HU-DE spread narrowed by around €3.60/MWh from the previous session but remained sufficiently wide to support continued imports towards Southeast Europe.
At the opposite end of the system, Italy’s premium strengthened the economic pull on electricity available in Slovenia, Croatia and the Western Balkans.
The hourly price curves provide an even clearer explanation for the elevated baseload levels.
HUPX reached a daily low of just €129.90/MWh in hour 14, before climbing rapidly as solar generation declined. The market reached €246.50/MWh in hour 23.
The Hungarian peak-load average was €169.20/MWh, while the off-peak average reached €198.90/MWh. The unusual relationship between the two products reflects the concentration of extremely high prices in the late evening.
Romania displayed a similar pattern. OPCOM fell to €124/MWh in hour 14 before climbing to €251.80/MWh in hour 23. Its off-peak average reached €205.10/MWh, compared with €167.90/MWh for the peak product.
Bulgaria recorded a daily minimum of €124.30/MWh and a maximum of €249.10/MWh, also in hour 23. Greece moved from around €121/MWh during the solar-heavy middle of the day to €250/MWh during the evening.
The shape of the market therefore increasingly reflects the solar ramp rather than the traditional working-day peak.
Strong photovoltaic production continues to suppress prices around the middle of the day, but the rapid withdrawal of solar generation creates a sharp requirement for dispatchable generation and imports during the evening. For short-term traders, the most important scarcity hours are consequently moving further into the evening.
Renewable generation provided a mixed signal for Wednesday.
Regional solar output was forecast at approximately 7.923 GW, up around 1.453 GW day on day. Wind generation, however, was expected to fall by approximately 867 MW to just 1.137 GW.
As a result, the net improvement in renewable availability was considerably smaller than the solar increase alone suggested. Moreover, much of the additional photovoltaic output arrived during hours when prices were already close to their daily lows.
The latest generation mix also pointed towards greater reliance on dispatchable capacity.
Coal generation increased by 577 MW to 7.218 GW, while gas-fired generation rose by 539 MW to 5.248 GW. Nuclear output increased by 298 MW to 4.055 GW.
At the same time, wind generation fell by 766 MW to 2.003 GW, solar output declined by 389 MW to 6.470 GW and hydro generation slipped by 137 MW to 4.945 GW.
This shift is significant because it leaves the marginal SEE power price exposed to gas, coal and carbon costs, even as installed solar capacity continues to expand.
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, while the Q4 contract eased to $128/t.
The mixed movement across the fuel complex suggests that Wednesday’s power-price increase was driven more by short-term physical conditions and hourly scarcity than by a broad increase in generation costs.
Hungary provides an important example.
HUPX prices increased even as availability at the Paks nuclear plant continued to recover.
Three reactors were already operating close to full capacity on 25 August, with units 1-3 producing around 1.448 GW. Unit 4 had also restarted and was generating approximately 244 MW, bringing total site output to around 1.69 GW.
Full production of approximately 2 GW was expected to return as Danube conditions improved.
Hungarian nuclear production averaged around 1.632 GW on 25 August, compared with 1.304 GW a day earlier and just 828 MW on 23 August.
Yet Hungary remained a substantial net importer for Wednesday, averaging approximately 942 MW.
This changes the interpretation of the Paks story.
During the period of reduced output caused by low Danube conditions, weaker nuclear generation was an obvious bullish factor for HUPX. Wednesday’s market shows that restoring nuclear production does not automatically eliminate Hungary’s premium.
Hungary remains part of a wider regional system in which electricity entering from Slovakia and Austria can be directed towards Romania, Croatia, Serbia and Slovenia, while Italy continues to provide a higher-priced destination for available power.
Romania represented one of the clearest tightening points.
Its average net import requirement increased to approximately 751 MW, compared with only 290 MW on the previous day. Consumption rose to around 5.94 GW.
Romania traded €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 remained a net exporter, averaging around 896 MW, although this was down from 1.018 GW a day earlier.
Greece was almost balanced, with average net imports of just 25 MW. Hungary imported around 942 MW, Croatia approximately 945 MW and Serbia around 426 MW.
Together, these flows produced the regional net import requirement of 2.521 GW.
The Western Balkan markets continued to trade at a significant discount to 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 market rose by €3.80/MWh to €169.31/MWh, while Montenegro’s BELEN reached €176.23/MWh after gaining €11.60/MWh.
Albania was the main exception to the regional increase. ALPEX fell by €17/MWh to €153.65/MWh, widening its discount to HUPX to more than €30/MWh.
Serbia’s hourly prices ranged from €113.10/MWh in hour 12 to €228/MWh in hour 20. Montenegro moved from €130/MWh to €230/MWh, while North Macedonia reached €240.50/MWh despite its lower baseload average.
The divergence highlights the continued differences between the tightly coupled central SEE markets and the Western Balkans.
The regional price structure remained clearly directional rather than uniform: German power was around €154/MWh, the central SEE cluster around €182-187/MWh, Western Balkan markets between approximately €154/MWh and €176/MWh, and Italy close to €198/MWh.
The short-term Hungarian forward curve also strengthened.
Week 36 increased by €7.50/MWh to €154/MWh, while Week 37 rose €5/MWh to €156/MWh. September gained €2/MWh to €165/MWh.
Calendar 2026, however, declined by €0.50/MWh to €133/MWh.
The combination of stronger front-end prices and a broadly stable longer-term contract suggests that the market is pricing near-term operational tightness rather than a structural repricing of power.
For the next trading sessions, the principal risk remains the evening ramp.
Strong solar generation can continue to push prices lower during the middle of the day, particularly around hours 12-16. But Wednesday’s market demonstrates that this does little to remove scarcity once photovoltaic output disappears.
With HUPX, OPCOM and IBEX all approaching or exceeding €250/MWh in individual late-evening hours, the difference between midday and evening prices is becoming increasingly important.
For short-term traders, therefore, the key signal is no longer simply the country-to-country baseload spread.
The shape of the curve — and how quickly prices reprice as solar disappears — is becoming just as important as the average day-ahead price.