Central SEE markets converged tightly around €168/MWh, while Albania retained a premium and Serbia, Montenegro and North Macedonia remained discounted. A sharp shift from wind toward solar and a strong increase in northern imports left evening hours as the clearest scarcity point in the regional curve.
Southeastern Europe’s day-ahead electricity market moved broadly higher for 19 August, but the headline increase concealed two distinct trading patterns. Hungary, Romania, Bulgaria, Slovenia and Croatia traded in an exceptionally narrow band around €168/MWh, showing strong price convergence across the central SEE corridor. Further south and west, however, the market remained fragmented. Albania climbed to €178.03/MWh, the highest price in the regional group, while Serbia remained the cheapest at €151.20/MWh despite recording one of the largest daily increases. Montenegro and North Macedonia also continued to trade at substantial discounts to HUPX.
The HUPX Hungarian base price settled at €167.99/MWh, up €3.5/MWh from the previous session. Romania’s OPCOM was almost identical at €168.04/MWh, just €0.06/MWh above HUPX, while Bulgaria’s IBEX reached €167.72/MWh, Slovenia’s BSP €167.94/MWh and Croatia’s CROPEX €167.91/MWh. The entire five-market group therefore traded within only about €0.33/MWh, an unusually tight range that effectively created a common central SEE price zone for the day.
Germany was slightly cheaper at €166.03/MWh, leaving the Hungarian-German spread at approximately €1.96/MWh, while Austria stood at €167.21/MWh. Italy remained firmer at €175.49/MWh, a premium of €7.50/MWh to HUPX. Greece moved higher by €6.2/MWh but remained below the central cluster at €159.88/MWh, leaving HUPX around €8.11/MWh above HENEX. The resulting pattern was less one of a uniformly expensive southeastern European market than of a tightly coupled central corridor positioned between cheaper southern Balkan zones and more expensive Italian and Albanian markets.
Across Hungary and the nine SEE exchanges included in the regional comparison, the unweighted base-price average was approximately €163.93/MWh. The difference between the highest and lowest market was still €26.83/MWh, however, almost entirely because of the €178.03/MWh Albanian price and Serbia’s €151.20/MWh settlement. That dispersion matters more than the regional average. It shows that the central part of SEE is increasingly capable of moving as a single price area under favourable cross-border conditions, while the peripheral Balkan markets can still detach sharply when their own generation, demand and available interchange positions differ.
The day-on-day movement was particularly strong in those peripheral markets. Albania gained €25.4/MWh, North Macedonia rose by €19.2/MWh and Serbia by €18.2/MWh. Montenegro increased much more modestly, by €1.4/MWh, to €156.01/MWh. Serbia nevertheless retained a €16.79/MWh discount to HUPX, North Macedonia traded €13.38/MWh below Hungary, and Montenegro was €11.98/MWh lower. Albania, by contrast, carried a €10.04/MWh premium over HUPX. The direction of the daily move was therefore overwhelmingly bullish, but cross-border price equalisation remained incomplete.
The physical balance explains much of the upward pressure. Forecast regional electricity consumption increased to 32,004 MW, a rise of 1,246 MW from the previous day. At the same time, the combined Hungary-SEE system shifted sharply toward imports. Net imports reached 1,720 MW, compared with a roughly balanced position of -36 MW a day earlier, while flows from the CORE side — principally Austria and Slovakia toward Hungary and Slovenia — jumped to 2,298 MW, an increase of 1,825 MW.
That change is one of the most important trading signals in the session. The regional market was not simply repricing because generation fuel costs increased; it was drawing materially more electricity from the north to balance stronger consumption. The HU+SEE balance simultaneously showed roughly 580 MW moving toward Italy, meaning the area could be a net importer overall while still supplying the higher-priced Italian market through its western interfaces. The market was therefore relying increasingly on northern inflows while maintaining economically attractive exports in another direction. This configuration helps explain why HUPX remained close to Austria and Romania but below Italy.
Renewable forecasts sharpened the intraday issue. Solar output was expected at 7,866 MW, up 1,266 MW, while wind generation was forecast to fall by 1,169 MW to just 673 MW. Taken together, the change in forecast solar and wind output was almost neutral in average megawatt terms. From a trading perspective, however, the two resources are not interchangeable. The additional solar production is concentrated around daylight hours, whereas the lost wind output removes generation across a much broader part of the day and becomes particularly important after sunset.
The result is visible in the hourly curves. On HUPX, the daily minimum fell at H14, when the price reached €127.5/MWh, before the market climbed to a maximum of €214.6/MWh at H21. The base price was €168.0/MWh, but the conventional peak block averaged only €158.3/MWh, while off-peak hours averaged a considerably higher €177.7/MWh. This apparent inversion of peak and off-peak pricing is not a contradiction. Hour 21, which contains the strongest evening scarcity signal, lies outside the standard daytime peak block. Solar depresses the middle of the day, then its disappearance combines with household and commercial evening demand to push the curve sharply upward.
The same shape appeared across much of the coupled region. Romania recorded a minimum of €127.5/MWh and a maximum of €214.7/MWh, with the high again at H21. Slovenia’s minimum was €127.8/MWh and its maximum €209.4/MWh, also at H21. Bulgaria reached €214.4/MWh at H21, Austria €209.9/MWh at H21, while Croatia peaked slightly earlier at H20 with €217.3/MWh. Greece’s curve was more distinctive: HENEX fell to €100.1/MWh at H10 before climbing to €214.4/MWh at H21.
The page-four hourly profiles reinforce the same market structure visually. HUPX, OPCOM and BSP follow a relatively smooth morning decline into a midday trough, then rise steeply from late afternoon toward the evening maximum. HENEX displays a deeper daytime depression but eventually converges toward the same evening price area. The trading risk is consequently concentrated less in the daily baseload number than in the transition between high-solar afternoon hours and the post-sunset period.
The southern Balkan markets amplify that pattern. Serbia’s SEEPEX price rose to €151.2/MWh, with an intraday low of €103.1/MWh at H12 and a maximum of €215/MWh at H20. Montenegro’s BELEN averaged €156.0/MWh, falling to €100.1/MWh before reaching €220/MWh at H20. North Macedonia averaged €154.6/MWh, with a €90/MWh minimum and a €226.3/MWh maximum at H21. Albania stood apart: its base price reached €178.0/MWh, its off-peak block surged to €207.9/MWh, and the daily maximum hit €250/MWh at H21.
Albania’s curve is especially revealing. Its daytime price still fell to €93.6/MWh, so the elevated daily average was not the product of uniformly high prices. Instead, the evening ramp was sufficiently severe to pull the whole day higher. The spread between Albania’s intraday minimum and maximum reached more than €156/MWh. Serbia’s equivalent spread was roughly €112/MWh, while North Macedonia’s exceeded €136/MWh. Such intraday volatility increases the value of flexible hydro, batteries, demand response and cross-border capacity even where the average baseload price itself does not appear exceptionally high.
Romania is another important test of the regional market’s resilience. Both 680 MW units at the Cernavoda nuclear plant were unavailable because low Danube flows had reduced cooling-water availability, removing roughly 1.36 GW of nuclear capacity. Romania responded by restarting almost 300 MW at Unit 4 of the Rovinari coal plant, while renewables and imports remained important for balancing the system. The source data indicated that the nuclear units were unlikely to return within the following ten days under the prevailing hydrological forecasts.
Despite that sizeable nuclear outage, OPCOM traded almost exactly in line with HUPX. That is a notable market outcome. Romania did not develop the large positive premium that might normally be expected from the simultaneous loss of both Cernavoda reactors. The combination of replacement thermal generation, renewable output and access to neighbouring markets appears to have prevented a more severe local price dislocation. The evening curve nevertheless climbed above €214/MWh, showing that the system retained little reason to discount post-solar scarcity.
The forward market was firmer but much less stressed than the day-ahead market. Hungarian Week 35 power stood at €151/MWh, Week 36 at €148/MWh, September 2026 at €158.5/MWh and Calendar 2026 at €128.5/MWh. Day on day, those contracts gained between €0.5/MWh and €2/MWh. HUPX day-ahead at €167.99/MWh was therefore almost €17/MWh above Week 35 and €9.49/MWh above September, leaving a clear prompt premium over the nearby forward structure.
Fuel and carbon markets were also modestly supportive. CEGH gas rose to €63.77/MWh, while EU allowances reached €82.31/t. September and fourth-quarter gas forwards were both €65/MWh, increasing by €2/MWh and €1.5/MWh respectively, while API-2 coal stood at $122/t for September and $126/t for Q4, both around $1/t higher. Greek gas moved in the opposite direction to €54.36/MWh, down €1.2/MWh. The overall fuel complex therefore provided some upward support, but the much larger prompt electricity premium points to a predominantly power-system-driven move rather than a simple pass-through from fuel markets.
For traders, the most relevant distinction on 19 August is consequently between baseload convergence and hourly scarcity. Hungary, Romania, Bulgaria, Slovenia and Croatia have almost completely converged around €168/MWh, reducing the value of simple base-price geographical spreads inside that central cluster. The larger opportunities and risks sit in the peripheral spreads — particularly Albania versus HUPX and the discounted Serbia-Montenegro-North Macedonia group — and in the hourly shape between the solar-rich midday period and the evening ramp.
The physical system is reinforcing that structure. Demand has recovered by more than 1.2 GW, wind has fallen by almost 1.17 GW, and northern imports have risen by more than 1.8 GW. Stronger solar generation keeps the central hours contained, but it does little to soften the market once production falls away. The persistent evening highs around €210-€226/MWh across most markets, and €250/MWh in Albania, show where marginal capacity is currently being valued. With the regional day-ahead price still trading above the nearby Hungarian forward curve, the market is pricing the present tightness primarily as a short-term balancing and shape problem rather than a sustained repricing of the entire forward structure.
