Day-ahead electricity prices weakened across most of Southeast Europe for delivery on 17 July 2026, but the regional decline was uneven. A sharp recovery in forecast wind and solar output reduced prices in Serbia, North Macedonia and the core Central European markets, while continued congestion, strong evening demand and fragmented cross-border access kept Hungary, Romania, Montenegro and Albania comparatively expensive.
The regional price range widened to €38.23/MWh, between Greece at €135.94/MWh and Albania at €174.17/MWh. This was not a uniformly bearish session. Instead, the market separated into several distinct price zones, reflecting different levels of renewable availability, import dependence and access to lower-cost generation.
Hungary cleared at €156.65/MWh, down €5.30/MWh from the previous session. The decline was modest compared with Germany, where the day-ahead price fell by €19.20/MWh to €140.63/MWh, and Austria, which dropped €16.20/MWh to €144.79/MWh. The resulting Hungary–Germany premium expanded from only €2.10/MWh to €16.02/MWh in a single session.
That spread is the clearest trading signal in the daily data. Central Europe had substantially more renewable and lower-cost supply available, but only 1,835 MW of average net imports were forecast from Austria and Slovakia into Hungary and Slovenia, almost unchanged from the previous day. Stable north-to-south flows were therefore insufficient to transmit the full German and Austrian price decline into Hungary.
Hungary’s premium over Austria reached €11.87/MWh, while its premium over Romania was only €1.36/MWh. Romania settled at €155.29/MWh, effectively unchanged day on day. The close alignment of the Hungarian and Romanian markets indicates that the eastern part of the coupled region remained exposed to the same relatively tight evening balance, despite improving renewable output during daylight hours.
The Hungarian hourly profile confirms that the daily average masks considerable intraday volatility. Prices remained close to or above €150/MWh during the night and early morning, eased toward approximately €90–100/MWh during the solar-rich afternoon and then climbed rapidly after sunset. The evening peak approached €260–270/MWh. This was below the previous session’s peak of more than €300/MWh, but it was still high enough to support a daily average above €156/MWh.
The reduction in the evening peak explains much of Hungary’s €5.30/MWh day-on-day decline. It also shows that additional renewable generation primarily compressed peak-hour scarcity rather than producing a deep midday price collapse. Conventional generation and imports remained necessary once solar output declined, keeping gas-fired generation relevant to marginal price formation.
The wider SEE balance was considerably more renewable-heavy. Forecast solar output increased by 1,634 MW to 8,132 MW, while wind rose by 1,004 MW to 2,595 MW. Combined wind and solar availability therefore reached 10,727 MW, an increase of 2,638 MW, or approximately 32.6%, from the previous day.
Regional consumption, by comparison, increased by only 244 MW, or around 0.7%, to 34,563 MW. Renewable supply growth was therefore more than ten times larger than the rise in demand. This produced a fundamentally softer daytime balance and reduced the amount of thermal generation or imports required during renewable-producing hours.
The demand increase was concentrated in Romania and Bulgaria, where combined consumption rose by 436 MW to 10,154 MW. Greek demand increased by 31 MW to 7,694 MW. Hungary’s consumption fell by 232 MW to 4,930 MW, while Slovenia and Croatia recorded a combined reduction of 75 MW, with consumption forecast at 10,155 MW.
Serbia registered one of the largest price corrections. SEEPEX declined by €18.00/MWh to €142.39/MWh, placing it €14.27/MWh below Hungary. North Macedonia followed almost the same pattern, falling €17.00/MWh to €141.76/MWh. The spread between Serbia and North Macedonia narrowed to only €0.63/MWh, creating a clearly aligned southern-central price zone.
The strength of the Serbian and North Macedonian correction suggests that these markets were particularly responsive to higher regional renewable output and southward electricity availability. Serbia nevertheless remained an average net importer of approximately 365 MW. Its lower clearing price therefore did not reflect a structural surplus, but a temporary improvement in the cost of marginal imported and regional supply.
Bulgaria cleared at €145.28/MWh, down just €0.70/MWh, while remaining a substantial average exporter at approximately 1,278 MW. This combination points to competitive domestic supply and a strong export position, although Bulgaria’s daily price did not fall as sharply as Serbia’s. The Bulgarian market stood €11.38/MWh below Hungary and €9.34/MWh above Greece.
Greece was the lowest-priced market at €135.94/MWh, down €6.30/MWh. Its hourly curve remained highly volatile: prices fell sharply during the solar window before recovering toward approximately €200/MWh in the evening. Greece was also an average exporter of around 1,347 MW, with the directional regional flow suggesting more than 1.2 GW moving from Greece toward the wider SEE system.
The combination of the region’s lowest daily price and substantial exports confirms that Greek renewable and conventional supply was helping to depress prices beyond the domestic market. It also illustrates the limits of daily averages: Greek midday electricity was materially cheaper than its evening output, creating a pronounced intraday arbitrage opportunity for storage, flexible demand and cross-border traders.
Slovenia, Croatia and Montenegro formed another closely grouped price area. Slovenia cleared at €152.28/MWh, Croatia at €151.32/MWh and Montenegro at €152.36/MWh. The maximum spread within this group was only €1.04/MWh.
Croatia remained an average net importer of approximately 1,162 MW, one of the largest national deficits in the regional balance. Slovenia’s and Croatia’s prices nonetheless fell by €8.20/MWh and €5.10/MWh, respectively, as improved northern renewable availability and stable core imports reduced replacement-power costs.
Montenegro’s price declined by only €2.30/MWh, leaving it €9.97/MWh above Serbia and €16.42/MWh above Greece. That premium suggests that access to cheaper Serbian and Greek supply remained constrained or insufficient during critical hours. Montenegro’s alignment with Croatia and Slovenia, rather than Serbia, is particularly relevant for short-term cross-border positioning.
Albania was the principal exception to the regional decline. ALPEX rose by €4.60/MWh to €174.17/MWh, the highest price in the monitored area. Albania traded €17.51/MWh above Hungary, €21.81/MWh above Montenegro and €38.23/MWh above Greece.
The Albanian premium, despite cheaper supply in neighbouring systems, indicates a locally tight hydro and import balance or constrained access to regional surpluses. Italy also remained expensive at €168.73/MWh, only €5.44/MWh below Albania. SEE exported an average of approximately 828 MW toward Italy, allowing the Italian market to absorb part of the region’s excess supply while supporting prices along the Adriatic corridor.
Aggregate Hungary and SEE net imports fell by 60 MW to 898 MW. This relatively small regional import requirement conceals large opposing national positions. Hungary, Romania, Serbia and Croatia were net importers, while Bulgaria and Greece supplied significant export volumes. The regional system was therefore balanced less by an overall shortage of generation than by the location of supply, cross-border capacity allocation and the timing of renewable production.
Hungary alone imported approximately 965 MW, Romania about 676 MW, Croatia 1,162 MW and Serbia 365 MW. These deficits were partly covered by Bulgarian exports of 1,278 MW and Greek exports of 1,347 MW, alongside the 1,835 MW entering the core region from Austria and Slovakia. The simultaneous export of 828 MW toward Italy reduced the volume available to cover inland deficits and helped preserve high prices in Hungary and the western Balkans.
Forward-market signals remained firmer than the softer day-ahead settlement might suggest. Hungarian Week 30 power increased by €3.00/MWh to €123.00/MWh, while Week 31 gained €2.50/MWh to €136.00/MWh. The Week 31 Hungary–Germany forward spread widened to €21.00/MWh, compared with €10.50/MWh for Week 30. The market is therefore pricing a greater Hungarian scarcity and congestion premium for the later delivery period.
Longer-dated Hungarian power moved marginally lower, with the average 2026 product at €140.50/MWh, down €0.50/MWh, and the calendar product at €122.50/MWh, down €1.00/MWh. The corresponding Hungary–Germany spreads remained substantial at €20.50/MWh and €19.50/MWh. This indicates that the north–south price separation is not being treated as a single-day anomaly.
Fuel markets continued to support relatively high thermal generation costs. CEGH gas rose by €0.20/MWh to €55.93/MWh, while the Greek gas benchmark increased by €0.40/MWh to €45.89/MWh. EU carbon allowances declined by €2.00/t to €79.19/t, partly reducing the carbon component of gas- and coal-fired generation costs. Forward gas remained elevated at €56.00/MWh for the 2026 average and €56.50/MWh for the fourth quarter, while coal held at $118/t for the 2026 average and increased to $119.50/t for the fourth quarter.
At current gas and carbon levels, efficient combined-cycle gas generation remains expensive enough to support peak electricity prices well above €130/MWh before variable operating costs. This aligns with the observed Hungarian, Romanian and evening SEE price profiles. More renewable generation can sharply reduce daytime prices, but the thermal stack continues to set the economic floor for non-solar hours.
The 17 July generation-by-fuel table in the daily report does not provide usable individual generation values, and its accompanying chart allocates 97% to “Other”, which is evidently a presentation or data-population error. The defensible 17 July supply assessment must therefore rely on the published renewable forecasts, consumption outlook, cross-border flows and hourly price curves rather than the incomplete fuel-mix graphic.
The trading structure for the session is consequently defined by a renewable-rich daytime market and a thermally exposed evening market. Serbia, North Macedonia, Bulgaria and Greece offer the lower-priced regional supply zone; Hungary and Romania retain a congestion and peak-hour premium; Slovenia, Croatia and Montenegro remain closely coupled around €151–152/MWh; and Albania stands apart as the most expensive and locally constrained market. The widening €16.02/MWh Hungary–Germany spread, the €38.23/MWh Albania–Greece range and the persistence of evening prices near or above €200/MWh preserve meaningful value for cross-border capacity, flexible hydro, demand response and short-duration battery dispatch.
