Day-ahead electricity prices strengthened across most of Southeast Europe for delivery on 14 July 2026, but the increase did not produce regional convergence. Instead, the market divided into three distinct price zones: a higher-priced Hungary–Slovenia–Austria cluster, an intermediate Romania–Bulgaria–Greece–Croatia group, and a substantially cheaper southern Balkan area covering Serbia, Montenegro, Albania and North Macedonia.
Hungary’s HUPX day-ahead baseload price rose by €7.90/MWh to €133.75/MWh. Slovenia settled almost identically at €133.65/MWh, while Austria reached €135.72/MWh. This effective convergence indicates that the Hungarian market was closely connected to the Central European price formation zone, despite continued physical imports into Hungary.
Germany remained cheaper at €123.97/MWh, leaving the Hungarian premium over Germany at €9.78/MWh, up by €3.00/MWh from the previous session. Available imports from Austria and Slovakia into Hungary and Slovenia averaged 1,496 MW, a reduction of 438 MW day on day. The combination of stronger Hungarian demand and lower Core imports explains much of the widening spot spread.
The Hungarian price was nevertheless below the Italian benchmark of €151.89/MWh. Italy’s premium over Hungary reached €18.14/MWh, while the broader SEE region exported an average of approximately 1,025 MW toward Italy. That export pull provided firm support to Slovenia, Croatia and the western part of the Balkan trading corridor.
The eastern interconnected markets settled below Hungary. Romania reached €121.72/MWh, while Bulgaria and Greece both cleared at €118.40/MWh. Hungary consequently traded at premiums of €12.03/MWh over Romania and €15.35/MWh over Bulgaria and Greece. The unchanged Bulgaria–Greece daily average points to relatively effective price transmission across their coupled border, even though hourly congestion may still have been present.
Croatia occupied an intermediate position at €126.65/MWh, around €7.10/MWh below Hungary but €22.68/MWh above Montenegro. Commercial flows into Croatia remained substantial, including approximately 587 MW in baseload and 745 MW during peak hours from Hungary, alongside 503 MW in baseload and 456 MW during peak hours from Slovenia. Croatia was still a net importer of around 1,214 MW, making it the largest net-importing market shown in the regional country balance.
The sharpest discounts appeared further south. Serbia’s SEEPEX price increased by €10.60/MWh to €108.15/MWh, but remained €25.60/MWh below Hungary. Montenegro settled at €103.97/MWh, Albania at €103.77/MWh, and North Macedonia at €104.74/MWh. The four-market southern cluster was therefore tightly grouped within less than €4.40/MWh, but separated from Hungary by approximately €25–30/MWh.
Albania recorded the largest daily increase, rising by €19.50/MWh, yet it remained the cheapest market at €103.77/MWh. Montenegro rose by €8.70/MWh, while North Macedonia was virtually unchanged. Serbia traded €4.18/MWh above Montenegro and €4.38/MWh above Albania, a much narrower difference than its discount to Hungary.
The persistence of large regional spreads despite active cross-border flows illustrates the continuing fragmentation of the SEE market. Bulgaria exported an average of approximately 1,498 MW and Greece around 541 MW, while Romania was almost balanced. Hungary imported approximately 864 MW, Serbia 489 MW, and Croatia 1,214 MW.
Commercial schedules show Bulgaria supplying Serbia by around 284 MW in baseload and 324 MW during peak hours, North Macedonia by approximately 181–189 MW, and Romania by 466–551 MW. Bosnia and Herzegovina supplied Serbia by 186 MW in baseload and 113 MW during peak hours, while North Macedonia exported 80 MW in baseload and 225 MW during peak hours toward Serbia.
Some scheduled flows moved against the direction implied by daily average prices. Bulgaria, for example, remained more expensive than Serbia while continuing to export into the Serbian system. Such patterns can reflect bilateral contracts, previously acquired transmission rights, hourly price differences, counterflows and the absence of full implicit market coupling on several borders. Daily baseload prices alone therefore do not fully describe the commercial value of regional interconnection capacity.
Montenegro received approximately 229–233 MW from Bosnia and Herzegovina, while scheduled flows of around 163–183 MW moved from Serbia toward Montenegro. Montenegro also received approximately 94 MW in baseload and 141 MW in peak hours from Albania. These flows supported the close price alignment between Montenegro and Albania.
Regional electricity consumption was forecast at 32,728 MW, increasing by 1,384 MW, or approximately 4.4%, compared with Monday. Hungary’s demand rose by 215 MW to 4,712 MW, while Greek consumption increased by 398 MW to 7,470 MW. Combined Romanian and Bulgarian demand reached 9,677 MW, up by 400 MW, while the remaining western Balkan consumption group increased by 471 MW.
The regional temperature forecast excluding Greece increased by 1.7°C to 23.5°C, supporting stronger cooling demand. Hungary was forecast at approximately 25.5°C, Serbia at 24.6°C, and Montenegro at 29.1°C. The temperature outlook continues to strengthen through the end of the week, with Montenegro approaching 30.9°C, Serbia 27.1°C and Hungary 26.9°C by Friday. This should keep afternoon and early-evening demand elevated.
Higher renewable output absorbed much of the incremental load. Forecast solar generation increased by 350 MW to 6,782 MW, while wind rose by 576 MW to 2,498 MW. Combined solar and wind production therefore reached approximately 9,280 MW, equivalent to 28.4% of forecast regional consumption.
The 926 MW increase in wind and solar covered roughly 67% of the 1,384 MW daily growth in consumption. The remaining balance required approximately 458 MW of additional dispatchable generation or changes in other renewable and cross-border positions.
Total regional net imports declined by 204 MW to 635 MW, covering less than 2% of forecast consumption. Based on the consumption and net-import balance, regional generation would need to reach approximately 32,093 MW, around 1,588 MW above Monday’s actual generation. After accounting for the forecast wind and solar increase, hydro, thermal, nuclear and other sources would collectively need to contribute approximately 660 MW of additional output.
Monday’s generation mix provides the clearest indication of which technologies were carrying the system. Regional output reached 30,505 MW, an increase of 4,246 MW from Sunday. Solar supplied 6,432 MW, coal 6,187 MW, nuclear 5,561 MW, hydro 4,940 MW, gas 4,065 MW, wind 1,923 MW, and other sources approximately 1,398 MW.
The return of weekday demand was met by a broad production increase rather than greater imports. Hydro rose by 877 MW, solar by 847 MW, wind by 788 MW, gas by 519 MW, coal by 213 MW, and other generation by 1,034 MW. Nuclear availability was broadly stable, declining by only 33 MW. At the same time, imports fell by 952 MW, demonstrating that the regional fleet had sufficient operational flexibility to cover the Monday demand recovery.
The publication did not yet contain a complete technology breakdown for Tuesday’s generation. Its provisional chart assigned 98% of production to “other”, which should be treated as a reporting placeholder rather than an actual generation mix.
Hourly curves remained more volatile than the baseload averages suggest. HUPX declined toward approximately €75–90/MWh around the midday solar maximum before rising above €200/MWh during the evening peak. Romania, Greece and Slovenia showed comparable solar-driven troughs followed by evening prices around €175–185/MWh.
The approximate HUPX intraday difference between the midday minimum and evening maximum exceeded €120/MWh. Similar spreads appeared in Greece and Romania. This preserved strong gross arbitrage potential for batteries and flexible hydro despite the rise in renewable production. At an illustrative 85% round-trip efficiency, buying at €80/MWh and selling at €200/MWh would leave a gross energy margin of roughly €106/MWh discharged, before degradation, imbalance, network charges and market fees.
Fuel markets reinforced the evening price floor. Austrian CEGH gas increased by €2.30/MWh to €52.05/MWh, Greek gas rose to €44.20/MWh, and EU carbon allowances reached €80.11/t, up by €0.90/t. Gas and carbon at these levels place a modern combined-cycle gas plant’s indicative variable cost around €124–136/MWh, depending on efficiency and emissions intensity. HUPX’s daily average was therefore close to gas-fired marginal generation economics, while its evening peak provided a much stronger dispatch margin.
Hungarian forward prices sent a mixed signal. Week 30 fell by €8/MWh to €120/MWh, while Week 31 increased by €4.50/MWh to €133/MWh. The €13/MWh premium of Week 31 over Week 30 points to expectations of a temporary near-term easing followed by renewed tightness. The Hungarian premium over Germany was priced at €11.50/MWh for Week 30 and €20/MWh for Week 31, indicating that the market expects Central European congestion and Hungary’s import dependence to become more valuable later in the curve.
The immediate trading structure remains defined by cheap midday solar, expensive evening flexibility and wide geographic spreads. Southern Balkan baseload is abundant at close to €104–108/MWh, but transmission constraints prevent that discount from fully reaching Hungary, Slovenia or Italy. Hungary’s dependence on reduced Core imports, Croatia’s large deficit and Italy’s €151.89/MWh price continue to place the greatest commercial value on northbound and westbound transmission capacity rather than on the regional baseload price alone.
