Southeast European day-ahead electricity markets moved sharply higher for Tuesday delivery, but the regional average concealed an increasingly severe split between near-zero midday prices and expensive evening hours. HUPX settled at €122.08/MWh, gaining €26.50/MWh from Monday, while forecast regional consumption increased by 1.66 GW to 31.74 GW.
The rise was not driven by a shortage of renewable electricity across the full day. Forecast solar generation increased by 1.36 GW to 7.49 GW, while wind output rose by 523 MW to 2.08 GW. Instead, the price signal reflected the timing mismatch between renewable output and demand. Solar production compressed prices to almost zero during the middle of the day, but its rapid evening withdrawal left thermal generation, hydropower flexibility and imports to cover the steep upward ramp.
Hungary’s hourly profile fell from roughly €150–170/MWh overnight and during the morning to single-digit levels between approximately hours 11 and 16. Prices then accelerated above €170/MWh by hour 19 and exceeded €210/MWh during the evening peak. The intraday swing approached €210/MWh, illustrating the growing separation between daily baseload averages and the actual value of dispatchable capacity.
A similar structure appeared in Romania, Slovenia and Greece. Romanian prices briefly approached zero during the strongest solar hours before recovering above €210/MWh in the evening. Slovenia followed Hungary more closely, while Greece recorded a late-session distortion in which the evening curve softened during one hour before rebounding. The common feature was a deep midday trough followed by a four-to-five-hour scarcity window.
This is becoming the dominant summer trading pattern in SEE: solar output is increasingly capable of suppressing prices across several interconnected markets, but it does not remove evening adequacy risk. The most valuable position is no longer necessarily baseload generation. Fast-start thermal units, reservoir hydropower, battery storage and flexible imports capture a disproportionate share of daily market value.
Germany closes the Hungarian discount gap
Germany recorded the largest relevant day-on-day increase, with its day-ahead price rising €39.70/MWh to €116.82/MWh. Because the German advance exceeded Hungary’s €26.50/MWh rise, the HU–DE spread narrowed from €18.46/MWh to €5.26/MWh.
The convergence is important. Hungary was still trading at a premium, but the premium no longer pointed to acute isolation from the core market. Core imports from Austria and Slovakia remained substantial at 1.89 GW, although they declined by 841 MW from the previous session. The lower inflow coincided with Hungary’s smaller price premium over Germany, indicating that the core market itself had tightened and was providing less cheap electricity to the eastern region.
The average spread understates the hourly trading opportunity. Imports from Austria and Slovakia increased sharply during the evening ramp, when Hungarian prices approached or exceeded €200/MWh. During the solar-heavy middle of the day, the incentive weakened and occasionally reversed. Cross-border capacity therefore carried most of its economic value during a relatively narrow group of evening hours.
Hungary’s €5.26/MWh premium over Germany compares with an Austrian price of €126.77/MWh, which was €4.68/MWh above HUPX. Slovenia also traded slightly above Hungary at €125.48/MWh, a premium of €3.39/MWh. These relationships suggest a relatively coherent Austria–Slovenia–Hungary price cluster, albeit with congestion and national generation profiles still producing hourly divergences.
Eastern SEE remains cheaper despite stronger demand
Romania settled at €110.78/MWh, up €15.30/MWh, while Bulgaria and Greece both cleared at €106.99/MWh. The Romanian discount to Hungary reached €11.30/MWh, and the Bulgarian and Greek discounts stood at €15.09/MWh.
North Macedonia was similarly positioned at €107.54/MWh, or €14.54/MWh below HUPX. Serbia cleared at €116.54/MWh, gaining only €2.10/MWh and retaining a €5.54/MWh discount to Hungary. Croatia rose €18.30/MWh to €115.40/MWh.
The eastern discount persisted despite a substantial demand increase. Forecast consumption rose by 703 MW in Greece and 584 MW across Romania and Bulgaria. The combined regional increase was partly offset by much stronger solar and wind output, allowing Bulgaria and Romania to remain net exporters on average.
Bulgaria exported approximately 1.24 GW, making it the region’s strongest national surplus market. Romania exported about 494 MW, while Greece was marginally long by roughly 104 MW on a daily-average basis. The result helps explain why the Bulgarian and Greek averages remained at the regional floor even as their evening hours tightened.
Serbia and Croatia were positioned on the opposite side of the balance. Serbia imported approximately 686 MW, while Croatia required around 1.03 GW of net imports. Hungary was also short by roughly 883 MW. These deficits placed the central SEE corridor in a structurally tighter position than Romania and Bulgaria, but Serbia’s limited day-on-day price increase suggests that available imports and regional renewable output prevented a more pronounced scarcity premium.
Montenegro cleared at €125.06/MWh, almost level with Slovenia and only €2.98/MWh above Hungary. The price represents a €22/MWh day-on-day increase and places Montenegro materially above Serbia, Croatia and the eastern markets. That premium is consistent with a smaller and more transmission-sensitive market where hydro availability, interconnector scheduling and relatively limited domestic liquidity can have an outsized effect on the daily result.
Albania and Italy form the expensive edge of the region
Albania was the clear SEE outlier. ALPEX surged by €84.50/MWh to €158.30/MWh, producing a €36.22/MWh premium over Hungary and a spread of more than €51/MWh against Bulgaria and Greece.
Such a move is difficult to explain through regional fuel costs alone. It points instead to local hydro conditions, constrained import availability, thin market liquidity or a combination of these factors. Albania’s price separated sharply from neighbouring Montenegro and Greece even though the broader region had ample solar production. This is a reminder that increased renewable penetration does not guarantee price convergence when cross-border capacity and national balancing conditions remain restrictive.
Italy remained the highest-priced major market at €176.07/MWh, despite falling €9/MWh day on day. Its premium over Hungary widened to €53.98/MWh. SEE exported an average of approximately 1.02 GW toward Italy, allowing Italy’s structural premium to draw surplus electricity westward across the Adriatic-facing borders.
That export pull matters for the entire Balkan balance. Bulgaria and Romania provided large surpluses, but Hungary, Serbia and Croatia remained short, while electricity continued moving toward the more expensive Italian market. The region consequently recorded net imports of 897 MW, even though several southeastern markets were individually exporting.
The aggregate import requirement fell by 642 MW from Monday. Higher renewable availability therefore improved the regional physical balance, but the improvement was insufficient to prevent a sharp price rise. The decisive factor was not total daily energy availability; it was the distribution of supply across the hourly curve.
Forward prices retain a pronounced summer premium
The Hungarian forward curve continues to price near-term tightness. Week 32 traded at €174.50/MWh, compared with €146.50/MWh for Week 33, €152.50/MWh for the 2026 average and €126.50/MWh for calendar 2026.
The €28/MWh backwardation between Week 32 and Week 33 reflects an immediate weather, demand and availability premium rather than a uniform repricing of the longer curve. Week 33 fell by €7/MWh in the latest session, while Week 32 declined by only €1/MWh. The prompt risk premium consequently became more concentrated.
Hungary’s Week 32 premium over Germany widened to €46/MWh, an increase of €15/MWh. The Week 33 spread was lower at €23.50/MWh, while the average-2026 spread stood at €26.50/MWh and the calendar spread at €20/MWh. The forward market is therefore assigning the largest regional dislocation to the immediate summer period.
Fuel inputs moved in the opposite direction. Austrian CEGH gas declined €4.90/MWh to €59.54/MWh, with the average-2026 gas contract at €59/MWh and Q4 at €59.50/MWh. EU carbon allowances eased €1.10/t to €82.33/t, while API2 coal fell to $118/t for the 2026 average and $123/t for Q4.
Falling gas, coal and carbon prices should ordinarily reduce thermal generation costs. Their decline alongside persistently expensive Hungarian prompt power reinforces the conclusion that near-term electricity pricing is being governed by hourly system tightness, cross-border availability and the evening ramp rather than by a fresh rise in fuel costs.
At €59.54/MWh gas and €82.33/t carbon, a modern combined-cycle gas turbine operating at roughly 55–58% efficiency carries an indicative short-run generation cost of approximately €135–150/MWh, before start-up costs and operating margins. Less efficient units require materially higher prices. Hungarian Week 32 power at €174.50/MWh provides room for efficient gas generation, but the €122.08/MWh daily spot average does not fully describe profitability: gas plants earn mainly during the evening hours above €170–210/MWh, while remaining uneconomic during the solar trough.
Trading view
The immediate signal is a continuation of strong intraday volatility rather than an unqualified rise in baseload prices. Regional temperature is forecast to increase from 24.3°C to 24.7°C, with Greece reaching 28.9°C, while consumption rises to 31.74 GW. Yet solar and wind supply are also materially stronger, limiting the daily import requirement to 897 MW.
The most exposed position remains the evening peak. The system moves from near-zero solar-hour prices to thermal scarcity within several hours, leaving market participants sensitive to thermal outages, hydro dispatch, forecast errors and available cross-border capacity. Battery assets with two-to-four-hour discharge capability face an unusually strong gross arbitrage window, while flexible hydropower retains high system value even when the daily average price appears moderate.
Hungary should remain firm relative to Romania, Bulgaria and Greece, but the reduced HU–DE spread of €5.26/MWh limits the case for a broad Hungarian scarcity premium across the entire day. Italy continues to provide the strongest export signal at a premium of almost €54/MWh, while Albania represents the principal local congestion and liquidity risk.
The tradable structure is therefore increasingly temporal and locational: cheap or near-zero eastern and central SEE solar hours, a steep regional evening ramp, expensive Italian demand, and persistent but variable premiums in Hungary, Montenegro and Albania. The widening value gap between midday generation and evening flexibility is now more significant than the movement in the daily baseload index itself.
