The 6 July 2026 day-ahead session shows a clear post-weekend reset across SEE. The region moved out of the low-price Sunday structure and into a much firmer Monday curve as demand recovered, temperature pressure remained visible, and evening scarcity again became the main price-setting signal. HUPX settled at €116.43/MWh, up €44.1/MWh day on day, while Romania was almost identical at €116.29/MWh. Slovenia and Croatia also converged close to the Hungarian hub, at €116.22/MWh and €115.71/MWh, confirming that Central Eastern markets were again trading as one tightly coupled price zone during much of the day.
The sharpest move came from Montenegro. BELEN rose to €133.23/MWh, up €74.6/MWh, making it the most expensive SEE market in the data set outside Italy. The Italian national price reached €144.03/MWh, keeping Italy as the dominant premium market and preserving the incentive for south-eastern flows toward the Adriatic and Italian border. Serbia remained cheaper at €97.84/MWh, still €18.59/MWh below HUPX and more than €46/MWh below Italy, while North Macedonia was the regional low at €90.94/MWh. That spread structure matters: Serbia was not cheap because of surplus generation; it was cheap despite being a net importer, which points to local market segmentation, border capacity limits and different hourly scarcity patterns rather than a simple domestic surplus story.
The demand side explains much of the price rebound. Regional HU+SEE consumption rose to 30,779 MW, up 3,332 MW from Sunday. At the same time, total net imports fell to 1,294 MW, down from 2,006 MW, meaning the system met part of the demand recovery through stronger domestic generation and internal redispatch rather than simply pulling more from outside the region. Imports from the CORE direction remained material, with AT+SK to HU+SEE at 2,477 MW, while the region continued to send power toward Italy, with SEE to Italy at 1,089 MW. This is the central physical market story of the day: SEE and Hungary were still structurally importing from the north-west while exporting into the higher-priced Italian sink.
Hourly price formation was more important than the baseload number. On HUPX, the minimum price was €37.2/MWh at H11, while the maximum reached €215.2/MWh at H21. Romania showed the same curve, with €36.7/MWh at H11 and €212.6/MWh at H21. Serbia’s curve was even more compressed at the low end, with a €23/MWh minimum at H12 and a €150.1/MWh maximum at H21. This is a classic summer solar shape: midday prices are suppressed by photovoltaic output, while the evening ramp, after solar fades and cooling demand remains present, becomes the real scarcity window. The fact that HUPX peak averaged only €88.3/MWh while off-peak averaged €144.6/MWh shows that the traditional peak/off-peak label is becoming less useful in solar-heavy markets; the valuable hours are no longer the broad daytime block, but the evening residual-demand window.
For batteries and flexible assets, the daily arbitrage signal was unusually clear. HUPX showed a gross intraday spread of roughly €178/MWh between H11 and H21, Romania around €176/MWh, and Serbia around €127/MWh. Even after efficiency losses, degradation assumptions and trading costs, this is a strong signal for two-hour and four-hour storage economics. The shape also supports the investment logic for BESS attached to solar, merchant front-of-the-meter batteries and industrial behind-the-meter systems that can reduce exposure during the evening price ramp rather than only optimizing daytime consumption.
Country balances show why prices diverged. Bulgaria was the strongest exporter, with net exports of 1,393 MW, supported by generation of 5,323 MW against consumption of 3,931 MW. Greece also stayed in export mode, with 618 MW of net exports, while Bosnia and Herzegovina exported 355 MW. On the deficit side, Croatia imported 1,015 MW, Hungary imported 861 MW, Romania imported 588 MW, Serbia imported 545 MW, Slovenia imported 285 MW, Montenegro imported 217 MW, and Albania imported 120 MW. The region therefore did not trade as a single surplus block; it traded as a mixed system where Bulgaria, Greece and Bosnia provided export support while Hungary, Croatia, Serbia, Romania and Montenegro remained structurally dependent on cross-border balancing.
Serbia’s position is especially important for trading interpretation. SEEPEX at €97.84/MWh looked cheap relative to Hungary, Croatia, Slovenia and Montenegro, but Serbia was still a 545 MW net importer. Serbian generation was 2,807 MW against consumption of 3,352 MW, leaving a structural deficit. The flow table shows Serbia importing from Bosnia and Herzegovina, Croatia, Hungary, Bulgaria and North Macedonia, while exporting toward Romania and Montenegro. That split suggests Serbia’s market was not purely short or long; it was acting as a transit and balancing node with different border economics by direction. For traders, the key signal is that Serbian low prices cannot be read as domestic comfort. They may instead reflect local liquidity, hourly shape, border allocation and the value of neighbouring routes.
Montenegro’s price premium is also explained by flows rather than demand alone. Montenegro consumed only 426 MW and generated 209 MW, leaving a domestic deficit, yet the system still recorded strong flows toward Italy through the Adriatic route. The ME > Italy flow averaged 432 MW on base and 458 MW on peak. In practical terms, Montenegro was simultaneously a domestic deficit market and a corridor into the Italian premium. That is why BELEN could clear at €133.23/MWh, far above Serbia and above HUPX, even though the country itself was importing on a net basis.
The forward screen adds a second layer. Hungarian week-ahead prices remained elevated, with HU Week 28 at €110/MWh and HU Week 29 at €146/MWh, while the HU-DE Week 29 spread stood at €30.5/MWh. That spread says the market is still pricing Hungary as a regional premium hub for the next delivery week, not just reacting to one warm Monday. Gas was firm but not explosive: CEGH Austrian gas stood at €45.90/MWh, while Greece gas was €43.75/MWh. EUA prices were stable at around €80.6/t, meaning the day’s power move was driven more by load, flow and hourly flexibility than by a fresh carbon shock.
The wider news backdrop reinforces the direction of travel. The edition highlights €2.5bn of new EU Modernization Fund disbursements for clean energy systems, including large allocations to Romania, Hungary, Greece and Croatia. It also notes Romania’s continued RES pipeline activity, with 60 applications representing 4,222 MW after tougher guarantee rules, and PNE’s 99.2 MW Romanian agrivoltaic project with 57 MWh of battery storage reaching ready-to-build status. In Hungary, the first construction permit under a planned 550 MW wind programme signals that non-solar renewables are slowly returning to the investment frame. These are not short-term price drivers, but they show where the market is heading: more solar, more storage, more grid pressure and more value attached to dispatchability.
The trading read for 6 July is therefore straightforward. Monday demand recovery lifted the entire region, but the real price action sat in the evening ramp, not the baseload average. Italy remained the premium sink, Montenegro priced as a corridor market, Serbia stayed discounted despite import dependence, and Hungary remained the central reference for regional convergence. The curve continues to reward flexibility, cross-border optionality and assets that can shift volume from the solar trough into the H20–H22 scarcity window.
