Southeast European day-ahead electricity markets posted strong gains for Tuesday delivery, but the higher regional average masked an increasingly pronounced divide between near-zero midday prices and expensive evening hours. Hungary’s HUPX market settled at €122.08/MWh, up €26.50/MWh from Monday, while forecast regional electricity demand increased by 1.66 GW to 31.74 GW.
The increase was not caused by a shortage of renewable generation. On the contrary, forecast solar production climbed by 1.36 GW to 7.49 GW, while wind generation increased by 523 MW to 2.08 GW. The key driver was the growing mismatch between renewable output and electricity demand. Strong solar generation pushed prices close to zero during midday, but the rapid decline in solar production during the evening forced markets to rely on thermal power plants, hydropower flexibility and imports to meet demand, resulting in a sharp price surge.
Hungary provided the clearest example of this evolving market structure. Hourly prices declined from approximately €150–170/MWh overnight and during the morning to single-digit levels between hours 11 and 16 before rebounding rapidly. By hour 19, prices exceeded €170/MWh, climbing above €210/MWh during the evening peak. The nearly €210/MWh intraday swing highlights the growing disconnect between daily average prices and the actual commercial value of flexible generation.
A similar pricing pattern emerged across Romania, Slovenia and Greece. Romanian prices briefly approached zero during peak solar production before recovering above €210/MWh in the evening. Slovenia closely mirrored the Hungarian curve, while Greece experienced a temporary easing during one evening hour before prices strengthened again. Across the region, the defining characteristic was a deep midday price trough followed by a four-to-five-hour period of evening scarcity.
This pricing profile is becoming the dominant summer trend across Southeast Europe. Expanding solar generation is increasingly capable of suppressing daytime prices across interconnected markets, yet it does little to eliminate evening adequacy challenges. As a result, dispatchable generation, reservoir hydropower, battery storage and flexible imports are capturing a growing share of overall market value.
Germany significantly narrowed the pricing gap with Hungary after recording the strongest day-on-day increase among major European markets. German day-ahead prices rose by €39.70/MWh to €116.82/MWh, exceeding Hungary’s daily increase of €26.50/MWh. Consequently, the Hungarian premium over Germany narrowed from €18.46/MWh to just €5.26/MWh.
The shrinking spread suggests Hungary is becoming more closely aligned with the broader Central European market. Imports from Austria and Slovakia remained substantial at 1.89 GW, although they declined by 841 MW compared with the previous session. The combination of lower imports and a narrower price premium indicates that tighter conditions in the core European market reduced the availability of low-cost electricity flowing eastward.
However, daily averages conceal much of the commercial opportunity. Electricity imports from Austria and Slovakia increased significantly during the evening ramp, precisely when Hungarian prices approached or exceeded €200/MWh. During the middle of the day, when abundant solar generation pushed prices sharply lower, the incentive for imports weakened considerably. Consequently, the greatest value of cross-border transmission capacity was concentrated within only a few high-priced evening hours.
Hungary’s €5.26/MWh premium over Germany compared with an Austrian market price of €126.77/MWh, while Slovenia settled at €125.48/MWh. Together, Austria, Slovenia and Hungary continued to form a relatively coherent regional price cluster, although transmission congestion and national generation patterns continued producing meaningful hourly price differences.
Eastern Southeast Europe remained comparatively inexpensive despite stronger electricity demand. Romania settled at €110.78/MWh, Bulgaria and Greece both cleared at €106.99/MWh, while North Macedonia finished at €107.54/MWh. Serbia settled at €116.54/MWh, gaining only €2.10/MWh from the previous session, while Croatia increased to €115.40/MWh.
Romania traded at an €11.30/MWh discount to Hungary, while Bulgaria and Greece remained €15.09/MWh lower. North Macedonia was €14.54/MWh below HUPX, and Serbia maintained a more modest €5.54/MWh discount. Although electricity demand increased by 703 MW in Greece and 584 MW across Romania and Bulgaria, stronger renewable production enabled these markets to maintain relatively low average prices.
Bulgaria remained the region’s largest net exporter with approximately 1.24 GW of surplus electricity, while Romania exported around 494 MW and Greece recorded a modest surplus of roughly 104 MW on average. These export positions explain why Bulgarian and Greek prices remained among the lowest in the region despite tightening conditions during evening peak hours.
By contrast, Serbia, Croatia and Hungary remained structurally dependent on imports. Serbia required approximately 686 MW of net imports, Croatia around 1.03 GW, while Hungary imported roughly 883 MW. These deficits placed the central Southeast European corridor in a tighter supply position than Romania and Bulgaria, although regional renewable production and available imports prevented a more pronounced price spike.
Montenegro settled at €125.06/MWh, almost identical to Slovenia and only €2.98/MWh above Hungary. The market recorded a daily increase of €22/MWh, positioning Montenegro above Serbia, Croatia and the eastern markets. The premium reflects the country’s relatively small and transmission-sensitive market, where hydrological conditions, interconnector scheduling and limited domestic liquidity can significantly influence daily pricing.
Albania emerged as the clear regional outlier. ALPEX surged by €84.50/MWh to €158.30/MWh, creating a premium of more than €36/MWh over Hungary and over €51/MWh above Bulgaria and Greece.
Such a sharp divergence is unlikely to be explained solely by fuel prices. Instead, it points toward local hydrological conditions, constrained import capacity, limited market liquidity or a combination of these factors. Despite abundant solar generation across neighboring countries, Albania remained largely disconnected from the broader regional pricing pattern, highlighting the continuing importance of transmission constraints and national balancing conditions.
Italy remained the most expensive major market despite a daily decline of €9/MWh, settling at €176.07/MWh. Its premium over Hungary widened to nearly €54/MWh, maintaining a powerful commercial signal for electricity exports from Southeast Europe toward the Italian market. Average exports to Italy reached approximately 1.02 GW, reinforcing the country’s role as the region’s strongest demand center.
This westward export flow continued to shape the regional supply balance. Although Bulgaria and Romania maintained significant surpluses, Hungary, Serbia and Croatia remained net importers while electricity continued flowing toward higher-priced Italy. Overall, Southeast Europe recorded net imports of approximately 897 MW, despite several countries maintaining positive export balances.
Regional import requirements nevertheless declined by 642 MW from Monday as stronger renewable generation improved the overall physical balance. Yet higher renewable output alone was insufficient to prevent rising electricity prices. The decisive factor remained the uneven hourly distribution of renewable generation rather than total daily energy availability.
The Hungarian forward curve continues to reflect expectations of near-term market 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 Weeks 32 and 33 illustrates a concentrated summer risk premium driven primarily by weather conditions, electricity demand and short-term system availability. Week 33 declined by €7/MWh during the latest session, while Week 32 eased by only €1/MWh, indicating that traders continue assigning the highest risk to the immediate delivery period.
Hungary’s Week 32 premium over Germany widened to €46/MWh, while Week 33 traded at a €23.50/MWh premium. Longer-term spreads narrowed to approximately €26.50/MWh for the 2026 average and €20/MWh for calendar 2026, suggesting that current market dislocations remain largely concentrated within the summer season.
Fuel markets moved in the opposite direction. Austrian CEGH natural gas fell by €4.90/MWh to €59.54/MWh, while EU carbon allowances declined by €1.10/t to €82.33/t. API2 coal prices also weakened, with the 2026 average contract falling to $118/t and the fourth-quarter contract to $123/t.
Ordinarily, lower gas, coal and carbon prices would reduce thermal generation costs. However, persistently elevated Hungarian power prices indicate that electricity markets are currently being driven less by fuel costs and more by hourly supply tightness, cross-border transmission availability and the steep evening ramp.
At current fuel and carbon prices, a modern combined-cycle gas turbine operating at approximately 55–58% efficiency carries an estimated short-run generation cost of roughly €135–150/MWh, excluding start-up costs and commercial margins. While Hungarian Week 32 forward prices provide sufficient profitability for efficient gas-fired generation, the daily spot average of €122.08/MWh masks the reality that thermal plants generate most of their revenue during evening peak hours when prices exceed €170–210/MWh.
Looking ahead, market fundamentals continue pointing toward elevated intraday volatility rather than a sustained increase in baseload prices. Regional temperatures are forecast to rise modestly from 24.3°C to 24.7°C, with Greece approaching 28.9°C, while electricity demand increases to 31.74 GW. At the same time, stronger solar and wind generation should limit total regional imports to around 897 MW.
The greatest market exposure remains concentrated in the evening hours, when electricity systems transition rapidly from abundant solar generation to thermal scarcity. This leaves prices increasingly sensitive to thermal outages, hydropower dispatch decisions, forecasting errors and available cross-border transmission capacity. Battery energy storage systems with two-to-four-hour discharge capability continue to benefit from exceptionally attractive arbitrage opportunities, while flexible hydropower retains significant commercial value despite relatively moderate daily average prices.
Hungary is expected to remain firmer than Romania, Bulgaria and Greece, although the narrower €5.26/MWh spread versus Germany reduces the likelihood of a broad Hungarian scarcity premium throughout the entire trading day. Italy continues to provide the region’s strongest export signal with a premium approaching €54/MWh, while Albania remains the principal source of local congestion and liquidity risk.
The overall trading picture is becoming increasingly defined by both time and location rather than simple daily averages. Near-zero midday prices driven by abundant solar generation, a steep regional evening ramp, sustained Italian demand and persistent premiums in Hungary, Montenegro and Albania continue to reshape market dynamics. As renewable penetration increases across Southeast Europe, the widening gap between midday generation value and evening system flexibility is becoming more commercially significant than movements in the daily baseload index itself.