Southeast European day-ahead electricity markets converged into an unusually narrow price range for delivery on Sunday, 19 July 2026, as lower weekend demand and strong photovoltaic generation displaced the import and thermal-generation pressures that had dominated the previous 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, leaving the seven markets within a remarkably tight range.
Only €5.24/MWh separated Hungary, the cheapest of the seven markets, from Slovenia, the most expensive. The simple regional average was approximately €87.45/MWh, almost 18% below the €106.39/MWh average recorded for Saturday delivery.
The sharpest day-on-day declines occurred in Romania, where prices fell by €24.07/MWh, and Croatia, which recorded a €22.27/MWh decrease. Slovenia fell by €22/MWh, Hungary by €20.24/MWh, while Bulgaria and Greece declined by approximately €15/MWh. Serbia recorded the smallest reduction among the seven markets at €13.95/MWh.
The convergence indicates that available generation and cross-border capacity were broadly sufficient to prevent a significant national scarcity premium during most of the day. It does not mean that every border was uncongested, as closely aligned daily averages can conceal binding constraints during individual hours. The session nevertheless represented a sharp contrast with Week 27, when Romania, Hungary, Croatia and Serbia carried significant premiums amid rising cooling demand, weaker renewable output and increasing import dependence.
Combined system-load indicators for the seven markets fell to approximately 27.1 GW, from 28.7 GW on Saturday, a reduction of roughly 5.6%. Serbia’s indicator declined from 3,772 MW to 3,371 MW, Croatia’s from 2,403 MW to 2,186 MW, Romania’s from 5,557 MW to 5,238 MW and Hungary’s 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 failed to eliminate the evening ramp. The baseload correction concealed a much larger redistribution of value between individual hours. Hungary traded at just €0.02/MWh at 10:00 CEST before climbing to €153.71/MWh at 18:00, creating an intraday spread of almost €154/MWh despite a daily average below €86/MWh.
Romania followed a similar curve, with prices falling to €0.02/MWh during the solar window before reaching €154.13/MWh as photovoltaic output began to decline. Bulgaria dropped 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 fell to €0.02/MWh during the late-morning period before reaching €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 rapidly as solar output declines and Italian and Balkan evening demand strengthens.
The market stopped just short of widespread negative pricing. That distinction is important. Near-zero prices indicate that solar generation displaced almost every other marginal source, but not to the extent that generators were forced to pay to remain online across the principal coupled markets. The limited negative-price signal may reflect renewable curtailment, flexible hydropower dispatch, export availability or thermal units bidding close to zero to avoid shutdown and restart costs.
Serbia’s SEEPEX auction reinforced the inversion of the traditional daily price curve. Baseload settled at €87.32/MWh, while the peak product averaged just €54.78/MWh. The lower peak price reflects the weight of inexpensive solar hours within the standard daytime block, while morning, evening and overnight periods carried 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 market liquidity, but physical balancing exposure remains significantly larger than the day-ahead average suggests. Forecast errors around the decline in solar output and the evening increase in demand can leave utilities purchasing 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 accounting for efficiency losses, degradation, grid charges and trading costs. Slovenia’s theoretical spread exceeded €185/MWh. These figures are not bankable daily revenue assumptions, but they demonstrate why captured spread, rather than baseload price, is becoming the central operating metric for regional storage.
The Sunday correction followed a materially tighter weekly balance. Southeast European electricity demand increased by 2.1% to 18.80 TWh in Week 27, up from 18.41 TWh in the previous week. Türkiye added 448 GWh to reach 7.73 TWh, while demand increased by 8% in Greece, 7.3% in Romania and 2.9% in Croatia.
Wind and solar generation moved in the opposite direction, falling 3.3% to 4.15 TWh. Wind output declined by 5.1% and solar generation by 1.8%. Hydropower fell by a further 3.4%, removing dispatchable renewable supply capable of serving the evening ramp.
Thermal generators filled the gap. Regional thermal output increased by 6.5% to 6.86 TWh, with lignite and coal generation rising by 11.6% and gas-fired output increasing by 3.3%. The shift pushed more hours towards the marginal costs of coal and gas plants, increasing national price sensitivity to fuel costs, carbon prices and generation outages.
Net electricity imports into the monitored SEE region consequently increased by 28.2%, from 972 GWh to 1.25 TWh. Hungary’s net imports rose by 157.9% to 202 GWh, while Romania imported 194 GWh, an increase of 44.8%. Serbia moved from only 7 GWh of net imports in Week 26 to 90 GWh in Week 27.
Serbia’s shift was particularly significant because it coincided with weaker lignite-fired availability. Greater dependence on imported electricity increases the value of capacity on the Romanian, Hungarian, Bulgarian, Croatian and Bosnian borders and raises 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 Bulgaria’s nuclear and coal availability, Greek wind and gas dispatch, Turkish renewable production and sufficient cross-border transfer capacity during evening hours.
Gas prices continued to provide a supportive floor beneath weekday peak prices. TTF futures averaged €43.59/MWh during Week 27, up 5.5%, and moved above €45/MWh by the end of the week. Sunday’s solar-driven price collapse overwhelmed that fuel signal during daylight hours, but gas economics regain influence as soon as photovoltaic output recedes.
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 renewable projects in northern Montenegro.
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, designed to reduce electrical losses, corona noise and environmental disturbance compared with the earlier technical solution.
Trial operation is not yet equivalent to unrestricted commercial availability. CGES must identify operating defects, complete testing and obtain the final use permit. The line’s 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 project nevertheless changes Montenegro’s position in regional electricity trading. The country can move more electricity between northern generation, coastal consumption and the Italian interconnector without relying as heavily on its lower-voltage network. Its commercial value will be most visible during sessions such as 19 July, when near-zero Balkan solar prices create export opportunities during the day while three-digit evening prices reward the ability to retain, redirect or transfer electricity after sunset.