South-east European day-ahead electricity prices corrected sharply on Wednesday as cooler weather and a substantial increase in forecast renewable generation eased the regional balance. The decline was broad but uneven. HUPX settled at €122.30/MWh, down €15.10/MWh from the previous session, while prices in Serbia, Bulgaria, Greece and North Macedonia fell by more than €20/MWh. Italy and Montenegro remained clear high-price zones, demonstrating that lower generation costs across the region have not eliminated transmission constraints and local supply scarcity.
The main shift in the physical balance came from renewable generation. Regional solar output was forecast at 7,424 MW, up 570 MW, while wind generation increased by 717 MW to 1,922 MW. The combined renewable gain of 1,287 MW was almost four times larger than the 353 MW increase in forecast demand. Total consumption reached 33,678 MW, but the additional load was comfortably absorbed by wind and solar generation rather than by higher imports or thermal output.
Net regional imports consequently fell by 582 MW, or approximately 26%, to 1,627 MW. Imports from Austria and Slovakia declined by 580 MW to 2,996 MW, although northern inflows remained a central component of the South-east European power balance. At the same time, around 1,277 MW was scheduled to flow from the region towards Italy, where the €170.21/MWh day-ahead price continued to provide a strong export incentive.
This combination explains the apparent contradiction in Wednesday’s market: South-east Europe remained a net importing region while simultaneously sending substantial volumes towards the more expensive Italian market. Electricity entered through the Austrian and Slovak borders, moved through Hungary and the northern Balkans, and partly continued towards Italy. The configuration supported prices in Austria, Slovenia and Croatia while limiting the extent to which lower-cost generation in Serbia, Bulgaria and Albania could pull the entire region lower.
HUPX’s €122.30/MWh settlement placed Hungary almost exactly in line with Romania and Croatia. Romania cleared at €121.68/MWh, only €0.62/MWh below Hungary, while Croatia settled at €122.92/MWh, just €0.62/MWh above it. This tight clustering points to strong short-term price integration along the Hungary–Romania–Croatia corridor, despite differences in national generation mixes.
Slovenia remained slightly firmer at €127.01/MWh, a €4.71/MWh premium to HUPX. Its proximity to Italy and exposure to westbound commercial flows supported prices above the central South-east European cluster. Austria was more expensive again at €134.16/MWh, or €11.86/MWh above Hungary.
The German benchmark fell to €100.43/MWh, leaving the Hungary–Germany spread at €21.87/MWh. Although the spread narrowed by €2.50/MWh, it remained wide enough to preserve a strong economic incentive for eastward flows whenever cross-border capacity was available. The persistence of a Hungarian premium despite almost 3 GW of combined imports from Austria and Slovakia indicates that available transmission capacity was still insufficient to produce full convergence with Germany.
The eastern South-east European markets recorded the largest daily declines. Bulgaria fell by €23.70/MWh to €114.51/MWh, while Greece dropped by €26.30/MWh to €115.88/MWh. The two markets cleared just €1.37/MWh apart, with Bulgaria maintaining its position as a regional exporter. Bulgaria’s average net export position was approximately 706 MW, while commercial schedules showed deliveries towards Serbia, Romania, North Macedonia and Greece.
Romania, by contrast, recorded net imports of approximately 678 MW even though its price remained almost perfectly coupled with Hungary. The Romanian market therefore combined a relatively tight physical balance with effective access to neighbouring supply. Commercial flows from Bulgaria and changing schedules across the Romanian–Hungarian border helped prevent a larger Romanian price premium.
Serbia recorded one of the weakest settlements in the region. SEEPEX fell by €24.50/MWh to €106.99/MWh, leaving Serbia €15.31/MWh below Hungary, €15.93/MWh below Croatia and €40.27/MWh below Montenegro. Serbia nevertheless remained a net importer by approximately 338 MW.
That relationship is important for market interpretation. Serbia’s low day-ahead average did not represent a simple national generation surplus. The country was receiving electricity from several directions while also supporting neighbouring systems, particularly Montenegro. Its price therefore reflected the domestic hourly supply curve and the availability of export capacity rather than an unconstrained regional equilibrium. The deep discount to Montenegro points to a transmission bottleneck or capacity-allocation constraint between two geographically close markets.
Albania was the only market in the surveyed region to rise on the day. ALPEX gained €1.70/MWh to €104.52/MWh, making it the cheapest day-ahead market. North Macedonia fell by a pronounced €32.40/MWh to €108.25/MWh, bringing it close to the Serbian and Albanian cluster. The southern Balkan markets consequently cleared between approximately €104.50/MWh and €108.30/MWh, well below Greece and the northern corridor.
Montenegro was the principal exception. BELEN settled at €147.26/MWh, only €1.40/MWh below the previous day and almost €25/MWh above HUPX. Montenegro’s premium over Albania reached €42.74/MWh, while the premium over Serbia was €40.27/MWh.
Available commercial-flow data show Montenegro receiving electricity from Bosnia and Herzegovina, Serbia, Albania and Kosovo, yet prices remained elevated. The result suggests that import capability, rather than the absence of neighbouring low-cost electricity, was determining the marginal value of supply. For participants exposed to the Montenegrin market, Serbian or Albanian day-ahead prices are therefore poor standalone hedges when cross-border capacity is scarce. Basis risk can exceed the underlying directional market move.
Italy remained the most expensive market at €170.21/MWh, despite a daily decline of €7.10/MWh. The Italian premium reached €47.91/MWh over Hungary, €47.29/MWh over Croatia and more than €63/MWh over Serbia. These spreads kept interconnector economics decisively directed towards Italy and contributed to the afternoon and evening firmness observed in Slovenia and Croatia.
Hourly price profiles revealed a more volatile market than the daily averages suggested. On HUPX, OPCOM and BSP, prices fell towards approximately €45–60/MWh during the solar-rich early afternoon before recovering to around or above €190–210/MWh during the evening ramp. The indicative gross intraday spread in Hungary and Romania was therefore close to €150/MWh, while Slovenia also displayed a pronounced evening price premium.
The midday decline was deeper than on Tuesday, particularly in Hungary and Romania, consistent with the additional 570 MW of regional solar generation and lower temperatures. After sunset, the loss of more than 7 GW of average solar output pushed the system back towards thermal generation, hydro flexibility and imports. The resulting evening rebound demonstrated that the region was long energy during daylight hours but short flexibility.
This profile is favourable for battery storage, pumped-storage hydropower and flexible hydro generation. The day-ahead charging opportunity was concentrated around hours 12–16, while the main discharge window emerged during hours 19–22. Gross spreads were sufficient to support a full storage cycle, although realised returns would depend on efficiency losses, imbalance exposure and access to the relevant market zone. A battery located in Montenegro or near an export-constrained node could capture a very different value stack from one settled against HUPX or SEEPEX.
The previous session’s generation mix illustrated the region’s continued reliance on dispatchable assets. Solar supplied approximately 6,855 MW, coal 6,434 MW, hydro 5,662 MW, nuclear 5,549 MW and gas-fired generation 5,082 MW. Wind contributed only 1,206 MW. The subsequent increase in forecast wind output to 1,922 MW was therefore material, displacing imports and reducing the call on marginal thermal generation.
Hydrological conditions were supportive but not exceptionally loose. Danube flow at the relevant measurement point stood at approximately 4,919 cubic metres per second, close to the long-term seasonal average and above comparable trajectories for 2023 and 2024. Hydro generation had increased by 363 MW in the previous session to 5,662 MW, providing useful ramping capacity but not enough to eliminate evening dependence on gas, coal and cross-border supply.
Thermal availability also remained significant, with roughly 11.2 GW of installed thermal capacity activated in the latest available observation. This was below the approximately 12.4 GW seen several days earlier, consistent with softer demand and stronger renewable generation. Nevertheless, the steep evening price recovery confirmed that thermal capacity remained marginal during the post-solar ramp.
Fuel markets did not reinforce the decline in day-ahead power prices. Austrian CEGH gas rose by €1.10/MWh to €60.68/MWh, while the Greek gas benchmark increased by €3.10/MWh to €52.39/MWh. EU carbon allowances were broadly unchanged at €83.20/t, slipping by only €0.10/t. API2 coal strengthened, with the 2026 average contract at $122.50/t and Q4 2026 at $125.50/t, both up $1.50/t.
The combination of weaker electricity prices and firmer fuel costs compressed thermal generation margins, particularly outside the evening peak. Gas-fired plants faced the greatest pressure during solar hours, while coal economics were also challenged by carbon costs above €83/t. The day-ahead correction was therefore driven primarily by weather, renewable availability and cross-border flows, rather than by an improvement in the thermal cost base.
The forward curve continued to price renewed tightness. Hungarian Week 31 power declined by €2.50/MWh to €131.00/MWh, but Week 32 rose by €1.00/MWh to €148.50/MWh. The €17.50/MWh premium of Week 32 over Week 31 indicates that the market views the current renewable-led weakness as temporary. Week 31 remained €8.70/MWh above the day-ahead settlement, while Week 32 carried a premium of more than €26/MWh.
The average 2026 Hungarian contract held at €146.50/MWh, while Calendar 2026 increased by €1.00/MWh to €126.00/MWh. Hungarian forward premiums over Germany also widened. The Week 31 HU–DE spread rose to €20.50/MWh, Week 32 to €21.50/MWh, the 2026 average spread to €22.00/MWh and the calendar spread to €19.50/MWh. The forward market is therefore retaining a structural risk premium for Hungary and South-east Europe despite the immediate fall in spot prices.
Weather forecasts support continued softness through the next two sessions. The regional temperature indicator excluding Greece is expected to decline from 20.0°C to 19.8°C and then 18.6°C. Greece is forecast to cool much more sharply, from 30.3°C to 27.6°C, 24.7°C and eventually 23.5°C, reducing air-conditioning demand and the probability of another Greek price spike. Bulgaria is also expected to cool towards 15.8°C before recovering.
The near-term trading bias consequently remains softer during solar hours, particularly in Hungary, Romania, Bulgaria and Serbia. Evening contracts retain considerably more support because fuel costs remain firm, Italian export demand is strong and regional flexibility is still limited. The clearest market expression is therefore an increasingly pronounced solar-hour discount against the evening peak, rather than an outright short position across the full baseload strip.
Cross-border basis remains the dominant risk. The Italy–South-east Europe premium, the Montenegro–Serbia dislocation and the persistent Hungary–Germany spread show that regional price formation is divided into several congestion zones. Wednesday’s lower system price did not eliminate scarcity; it shifted scarcity into specific hours and locations, leaving midday energy cheaper while preserving a high value for evening flexibility, interconnector capacity and dispatchable generation.