The SEE electricity market entered Friday with a pronounced split between the tightly coupled Hungarian–Romanian–Slovenian–Croatian zone and the cheaper southern Balkan markets. The immediate catalyst was the worsening availability outlook for Hungary’s Paks nuclear power plant, where exceptionally low Danube levels have raised the possibility of a complete shutdown. The resulting risk premium was visible across spot prices, cross-border flows and, most sharply, the Hungarian week-ahead curve.
Hungarian day-ahead power settled at €157.81/MWh, rising €25.70/MWh from Thursday. Romania followed at €155.33/MWh, while Slovenia and Croatia cleared at €157.65/MWh and €156.49/MWh respectively. The four markets were effectively converged within a range of little more than €2/MWh, indicating that the regional price signal was being set by the same combination of Hungarian supply tightness, elevated imports and expensive thermal replacement.
Germany also strengthened to €148.59/MWh, but Hungary retained a premium of €9.22/MWh. Austria cleared at €155.61/MWh, only €2.20/MWh below HUPX. These relatively narrow western spreads show that Hungary remained well connected to the central European price formation zone, even as constrained domestic generation forced the country to absorb considerably more imported electricity.
Hungary’s average domestic generation was projected to fall to 2,667 MW, down from 3,209 MW on Thursday and more than 20% below Monday’s level. At the same time, consumption increased to 4,871 MW. The country’s net import requirement therefore expanded to approximately 2,203 MW, compared with 1,599 MW one day earlier. Hungary’s import dependency was particularly pronounced during off-peak hours, when the net deficit averaged 3,285 MW.
The underlying vulnerability was already visible in Thursday’s generation mix. Paks output had fallen to an average of only 961 MW, compared with around 1,830–1,850 MW during the previous weekend. Nuclear generation supplied approximately 31% of Hungarian output on 30 July, while solar contributed 51%. That mix leaves the system exposed after sunset: solar production disappears just as air-conditioning demand and evening consumption remain elevated, while reduced nuclear availability removes the stable baseload normally used to bridge that transition.
The hourly HUPX profile reflected this structure. The daily minimum was still unusually high at €83.30/MWh during hour 16, while the evening maximum reached €268.60/MWh in hour 20. HUPX peakload averaged €136.00/MWh, but off-peak power averaged €179.60/MWh. The counterintuitive premium for the nominal off-peak block reflects the inclusion of expensive evening and overnight hours, while solar generation depresses prices during the daytime peak block.
Romania experienced almost identical price formation. OPCOM rose by €25.20/MWh to €155.33/MWh, with a minimum of €83.30/MWh and a maximum of €271.20/MWh in hour 20. Romania’s net position deteriorated from imports of 376 MW to 480 MW, despite generation increasing slightly to 5,228 MW. Consumption rose to 5,708 MW.
Commercial flows underline Romania’s role in covering the Hungarian shortfall. Average exports from Romania to Hungary increased to 1,605 MW, with the peak-hour flow reaching 2,301 MW. Romania simultaneously imported around 2,088 MW from Bulgaria, effectively transmitting Bulgarian surplus northwards into the Hungarian deficit zone. This Bulgaria–Romania–Hungary pathway became one of the dominant regional trading routes.
Bulgaria’s generation increased from 4,516 MW to 5,242 MW, allowing net exports to rise to 1,379 MW even as domestic consumption climbed by 531 MW to 3,863 MW. Bulgaria exported an average 2,088 MW to Romania and approximately 297 MW to Serbia. These exports were partly offset by imports of 1,101 MW from Greece.
IBEX nevertheless cleared materially below the northern cluster at €124.75/MWh, leaving Bulgaria at a discount of €33.06/MWh to HUPX. Bulgaria’s hourly minimum was €40/MWh, while the maximum reached €180.70/MWh. The wider range indicates that local renewable output and northbound congestion continued to limit full price convergence with Romania.
Serbia remained one of the cheaper markets despite a clear increase in demand. SEEPEX rose by €8.30/MWh to €113.07/MWh, maintaining a substantial €44.74/MWh discount to Hungary. Serbian consumption increased by 327 MW, or approximately 9%, to 3,940 MW. Projected generation rose more strongly, from 3,053 MW to 3,400 MW, allowing the net import requirement to edge down from 560 MW to 540 MW.
Serbia’s import exposure remained heavily concentrated in peak hours. Net imports averaged 906 MW during the peak block but only 174 MW off peak. The largest scheduled inflows came from North Macedonia at 374 MW, Bulgaria at 297 MW, Hungary at 115 MW and Bosnia and Herzegovina at 41 MW. Serbia exported an average 121 MW to Montenegro and 105 MW to Croatia.
SEEPEX’s daily minimum of €60.10/MWh occurred in hour 13, while the evening maximum reached €250.10/MWh in hour 20. The relatively low baseload average therefore masks a severe intraday ramp: Serbia traded more than €44/MWh below Hungary on a daily basis, but its evening scarcity price approached the levels recorded in Hungary, Romania and Montenegro. This increases the value of short-duration battery flexibility, hydro dispatch and intraday hedging around hours 18–21.
The southern markets diverged even more clearly. Greece fell by €2.60/MWh to €89.96/MWh, creating a record-wide daily discount of €67.85/MWh to HUPX. Greek generation increased to 9,008 MW, exceeding consumption of 7,222 MW and supporting net exports of 1,787 MW. Greece sent approximately 1,101 MW to Bulgaria, 469 MW to North Macedonia and 200 MW to Albania.
HENEX recorded a zero-price hour at hour 16, while its daily maximum was only €154.80/MWh. The Greek peak block averaged just €40.30/MWh, compared with an off-peak average of €139.60/MWh. Strong daytime renewable availability and high export volumes kept Greece structurally cheaper, but limited interconnection capacity prevented the surplus from fully relieving the Hungarian and central SEE deficit.
Albania moved in the opposite direction, surging by €70.10/MWh to €158.09/MWh after clearing at only €87.99/MWh on Thursday. ALPEX consequently moved marginally above HUPX, while its evening maximum reached €260.20/MWh. Montenegro eased by €5.30/MWh to €146.43/MWh, but its off-peak block remained expensive at €181.20/MWh, with a maximum of €250/MWh in hour 21. Montenegro’s consumption rose to 461 MW, while generation reached only 326 MW, leaving net imports of 135 MW.
North Macedonia was the cheapest market after Greece, declining €12.40/MWh to €105.31/MWh. Its net balance improved to a modest 18 MW export, although commercial flows continued to show its importance as a transit market between Bulgaria, Greece, Kosovo and Serbia.
The aggregate SEE and Hungarian system consumed 33,397 MW, an increase of 1,129 MW, or approximately 3.5%, from Thursday. Forecast generation reached 32,080 MW, leaving net imports of 1,317 MW. Imports from Austria and Slovakia into Hungary and Slovenia averaged 1,858 MW, down 240 MW, while exports from SEE to Italy fell to 765 MW. Reduced exports to Italy helped retain some electricity inside the region, although Italy’s national price remained the daily maximum at €186.23/MWh.
Thursday’s confirmed generation data show the supply transition behind Friday’s prices. Regional wind output increased by 746 MW to 3,191 MW, but nuclear generation fell by 323 MW to 4,143 MW. Solar declined by 376 MW to 7,331 MW, while coal generation increased by 355 MW to 5,821 MW. Gas-fired production fell slightly to 4,597 MW. The published 31 July technology-level renewable forecast contains a spreadsheet error, so Friday’s aggregate generation and country balances are usable, but the detailed renewable split should not be treated as validated.
The week-ahead market carries a much stronger risk signal than the spot market. Hungarian Week 32 jumped €70/MWh in one session to €282/MWh, creating a premium of €155/MWh over Germany and €105.50/MWh over Italy. Week 33 increased to €184.50/MWh, up €27/MWh. Hungarian August power rose to €184.50/MWh, gaining €20.50/MWh on the day and almost 18% over the preceding seven sessions.
By contrast, German Week 32 fell to €127/MWh, while Italian Week 32 stood at €176.50/MWh. The extreme Hungarian premium is therefore a specific regional adequacy and nuclear-availability risk rather than a broad European power rally.
CEGH gas strengthened to €61.44/MWh, while EU allowances eased to €81.29/tCO₂. At those levels, an efficient gas-fired plant faces an indicative clean variable generation cost around €140–145/MWh before operational and balancing costs. HUPX baseload at €157.81/MWh provides a positive but relatively narrow margin for efficient combined-cycle generation, while the €268.60/MWh evening price strongly rewards flexible thermal capacity, storage and hydro. Greek gas at €47.08/MWh remains significantly cheaper, but HENEX’s renewable-driven daytime collapse limits conventional generation margins outside the evening ramp.
The next price move rests principally on Paks availability and the Danube cooling-water constraint. Regional temperatures are forecast to rise over the weekend and into early next week, with Hungary moving above 30°C, while the reported Danube flow at the relevant point was approximately 4,692 cubic metres per second. Persistent nuclear restrictions would keep Hungarian imports high, support Romanian and Bulgarian northbound flows and preserve sharp evening premiums across the interconnected SEE markets. Serbian baseload can remain discounted while domestic coal and hydro availability hold, but the convergence visible around hour 20 shows that Serbia is not insulated from the regional evening scarcity event.
