Southeast European day-ahead markets converged into an unusually narrow range for delivery on Sunday, 19 July 2026, as lower weekend consumption and strong photovoltaic output displaced the import and thermal-generation pressures that had dominated the preceding week.
Hungary’s HUPX market settled at €85.90/MWh, followed by Romania at €86.14/MWh, Bulgaria at €86.21/MWh and Greece at €86.31/MWh. Serbia cleared at €87.32/MWh, Croatia at €89.11/MWh and Slovenia at €91.14/MWh.
Only €5.24/MWh separated Hungary, the cheapest of the seven markets, from Slovenia, the most expensive. Their simple regional average was approximately €87.45/MWh, down almost 18 per cent from €106.39/MWh for Saturday delivery.
The largest day-on-day reductions occurred in Romania, where the price fell €24.07/MWh, and Croatia, which declined €22.27/MWh. Slovenia lost €22/MWh, Hungary fell €20.24/MWh, Bulgaria and Greece dropped about €15/MWh, and Serbia decreased €13.95/MWh.
The convergence suggests that available generation and cross-border capacity were sufficient to prevent a material national scarcity premium during most of the day. It does not necessarily mean that every border was uncongested: closely aligned daily averages can conceal binding constraints in individual hours. The session nevertheless marks a sharp contrast with Week 27, when Romania, Hungary, Croatia and Serbia carried substantial premiums because of rising cooling demand, weaker renewables and increasing import dependence.
The combined system-load indicators for the seven markets fell to approximately 27.1 GW, from 28.7 GW on Saturday, a reduction of about 5.6 per cent. Serbia’s indicator declined from 3,772 MW to 3,371 MW, Croatia from 2,403 MW to 2,186 MW, Romania from 5,557 MW to 5,238 MW and Hungary from 4,464 MW to 4,150 MW. Greece remained the largest market in the group at approximately 7,010 MW.
Near-zero midday prices fail to remove the evening ramp
The baseload correction disguises a much larger redistribution of value between hours. Hungary traded at only €0.02/MWh at 10.00 CEST, before climbing to €153.71/MWh at 18.00. Its intraday range therefore approached €154/MWh, even though the daily average remained below €86/MWh.
Romania followed an almost identical curve. Prices dropped to €0.02/MWh during the solar window and reached €154.13/MWh after photovoltaic production began to retreat. Bulgaria fell to €0.04/MWh before rising to €154.96/MWh, while Greece moved from €0.04/MWh to €156.77/MWh.
The strongest hourly dislocation appeared in Slovenia. BSP SouthPool prices declined to €0.02/MWh during the late-morning period and reached €185.11/MWh in the evening, creating a spread of more than €185/MWh. Slovenia’s premium reflects its position between Italy, Austria, Hungary and Croatia, where the marginal value of cross-border capacity can change quickly as solar output falls and Italian and Balkan evening demand strengthens.
The market stopped just short of broadly negative pricing. That distinction matters. Near-zero prices show that solar generation was sufficient to displace almost every other marginal source, but not so excessive that generators had to pay to remain online across the principal coupled markets. The limited negative-price signal may reflect renewable curtailment, flexible hydro dispatch, export availability or thermal units bidding close to zero to avoid shutdown and restart costs.
Serbia’s SEEPEX auction reinforced the curve inversion. Baseload settled at €87.32/MWh, while the peak product averaged only €54.78/MWh. The lower peak price reflects the weight of inexpensive solar hours within the standard daytime block; morning, evening and overnight periods carried the greater scarcity value.
SEEPEX cleared 19,203.5 MWh for the delivery day, equivalent to an average hourly traded volume of approximately 800 MWh. The result strengthens liquidity, but physical balancing exposure remains much larger than the day-ahead average suggests. Forecast errors around solar decline and evening load can leave utilities buying replacement electricity during the most expensive hours of the session.
A one-megawatt battery completing a full cycle between Hungary’s lowest and highest hourly prices faced a theoretical gross spread of almost €154 per MWh of storage capacity before efficiency losses, degradation, grid charges and trading costs. Slovenia’s theoretical spread exceeded €185/MWh. Those figures are not bankable daily revenue assumptions, but they demonstrate why captured spread, rather than baseload price, has become the central operating metric for regional storage.
Week 27 import pressure leaves the market vulnerable after Sunday
The Sunday correction followed a materially tighter weekly balance. Southeast European electricity demand increased 2.1 per cent to 18.80 TWh in Week 27, from 18.41 TWh in the preceding week. Türkiye added 448 GWh to reach 7.73 TWh, while demand rose 8 per cent in Greece, 7.3 per cent in Romania and 2.9 per cent in Croatia.
Wind and solar production moved in the opposite direction, falling 3.3 per cent to 4.15 TWh. Wind generation declined 5.1 per cent and solar output decreased 1.8 per cent. Hydropower fell another 3.4 per cent, removing dispatchable renewable supply capable of serving the evening ramp.
Thermal generators filled the gap. Regional thermal output increased 6.5 per cent to 6.86 TWh, with lignite and coal production rising 11.6 per cent and gas-fired generation gaining 3.3 per cent. This pushed more hours towards the marginal costs of coal and gas plants and made national prices more sensitive to fuel, carbon and outage exposure.
Net electricity imports into the monitored SEE region consequently increased 28.2 per cent, from 972 GWh to 1.25 TWh. Hungary’s net imports rose 157.9 per cent to 202 GWh, while Romania imported 194 GWh, an increase of 44.8 per cent. Serbia moved from only 7 GWh of net imports in Week 26 to 90 GWh in Week 27.
Serbia’s change was particularly important because it coincided with weaker lignite-fired availability. Greater dependence on imported electricity raises the market value of capacity on the Romanian, Hungarian, Bulgarian, Croatian and Bosnian borders and increases exposure to simultaneous evening scarcity across neighbouring systems.
Greece, Bulgaria and Türkiye remained net exporters, although their surpluses narrowed. Their ability to provide affordable regional supply will depend on nuclear and coal availability in Bulgaria, Greek wind and gas dispatch, Turkish renewable production and the preservation of sufficient cross-border transfer capacity during evening hours.
Gas costs remain a supportive floor beneath weekday peak prices. TTF futures averaged €43.59/MWh during Week 27, up 5.5 per cent, and moved above €45/MWh by the end of the week. Sunday’s solar-driven collapse overpowered that fuel signal during daylight hours; gas economics regain influence as soon as photovoltaic output recedes.
Montenegro’s €129.4 million transmission corridor enters its operating test
Montenegro’s 400 kV Lastva–Pljevlja transmission line has entered trial operation, establishing the country’s first high-voltage north-south link and completing a critical section of the Trans-Balkan Electricity Corridor.
The wider investment package has a financing value of approximately €129.39 million. It combines €85 million of EBRD and KfW loans, €27.39 million of Western Balkans Investment Framework grants and €17 million of beneficiary funding. The system includes the Lastva substation, the Lastva–Čevo and Čevo–Pljevlja sections, integration with the Pljevlja network and access to the undersea electricity link with Italy.
CGES estimates that the reinforcement can increase gross transfer capability by approximately 500 MW and support secure operation during 500–1,000 MW of transit through the Italy–Montenegro cable. It should also reduce transmission losses, improve voltage and reactive-power management and create stronger connection conditions for northern renewable projects.
The most difficult section was rerouted away from populated areas and environmentally sensitive parts of Durmitor National Park. Contractor Kodar installed the AAAC Aster 366 conductor, intended to reduce electrical losses, corona noise and environmental disturbance compared with the earlier technical solution.
Trial operation is not yet the same as unrestricted commercial availability. CGES must identify operating defects, complete testing and obtain the final use permit. Actual cross-border value will also depend on coordinated capacity calculation, NTC and ATC allocation, maintenance schedules and progress towards market coupling with neighbouring systems.
The line nevertheless changes Montenegro’s position in regional trading. The country can move more electricity between northern generation, coastal consumption and the Italian interconnector without relying as heavily on the lower-voltage network. Its commercial value will be most visible during sessions such as 19 July, when near-zero Balkan solar prices create an export opportunity during the day and three-digit evening prices reward the ability to reverse, retain or redirect power after sunset.
