South-east Europe’s power trading landscape opened the 18 June 2026 trading day with a clear regional split. Hungary, Slovenia, Croatia, Romania and Italy traded at the upper end of the European day-ahead price spectrum, while Greece, Bulgaria, Serbia, Montenegro, Albania and North Macedonia cleared at a significant discount. The signal was not simply one of demand imbalance or renewable surplus, but a clearer reflection of how grid constraints, interconnector limits, dispatch structure and cross-border risk are increasingly shaping price formation across neighbouring markets.
The Hungarian benchmark, HUPX, cleared at €133.60/MWh, up €9.80/MWh day on day. This placed Hungary slightly below Germany (€139.92/MWh) and Italy (€139.58/MWh), while Austria followed at €131.78/MWh. Romania (€124.26/MWh), Slovenia (€129.30/MWh) and Croatia (€127.27/MWh) remained closely linked to the central European and Italian pricing complex, confirming that the northern SEE corridor continues to behave as part of the broader CORE-European price system.
In contrast, the southern Balkan markets moved significantly lower. Greece cleared at €76.83/MWh, Bulgaria at €84.09/MWh, Serbia at €79.14/MWh, Montenegro at €81.29/MWh, Albania at €79.81/MWh and North Macedonia at €82.80/MWh. The spread between Hungary and Greece widened to €56.78/MWh, while Hungary traded more than €50/MWh above several Western Balkan markets. This divergence highlighted the key trading reality of the day: price formation is increasingly driven by deliverability, not just generation cost.
Regional demand rose to 29,836 MW, up 887 MW day on day, as average temperatures across SEE and Hungary increased to 23.4°C. While not yet extreme summer peak conditions, the shift was enough to tighten northern residual load and increase the value of import capacity. Hungary’s demand forecast stood at 4,538 MW, Greece at 6,173 MW, and the Romania–Bulgaria block at 8,900 MW, reinforcing the uneven distribution of regional consumption pressure.
Despite rising demand, the system remained in a net export position of around 1,121 MW, reversing the previous day’s import balance. This is a key structural signal: the region was not energy-deficient overall, but rather constrained in its ability to shift power to where it was most valuable. Greece exported approximately 1,630 MW and Bulgaria around 1,167 MW, while Serbia imported 533 MW, Croatia 1,191 MW, and Hungary 377 MW. The flow pattern explains why price convergence failed despite large southern discounts—cheap energy existed, but transmission and timing bottlenecks prevented full arbitrage.
Generation data reinforced this structure. Total output stood at 28,313 MW, down 608 MW day on day. Hydro remained stable at 6,138 MW, coal fell to 4,728 MW, and gas increased to 4,804 MW, indicating continued reliance on flexible thermal generation. Nuclear rose modestly to 4,942 MW, while wind surged to 1,551 MW (+830 MW). Solar, however, dropped sharply to 5,565 MW (−1,671 MW), but still played a dominant role in midday price compression.
This mix explains the intraday structure. The region had sufficient low-marginal-cost generation to depress prices during solar-heavy hours, but the evening ramp became the dominant pricing event. HUPX reached a peak of €389.60/MWh at hour 22, with a minimum of €18.60/MWh at hour 15. Similar volatility appeared across Slovenia (€369.80/MWh peak), Croatia (€374.20/MWh), Austria (€381.70/MWh) and Romania (€386.80/MWh). The market is increasingly defined not by daily averages, but by short-duration scarcity pricing in evening hours.
Southern markets followed the same structure, albeit at lower levels. SEEPEX cleared at €79.14/MWh with a peak of €140/MWh and a minimum of €8.10/MWh. Montenegro and Albania showed similar ranges. This indicates that even discounted markets are not structurally insulated from scarcity—they are simply operating on a lower baseload due to weaker export access, softer demand profiles and more constrained integration into higher-priced zones.
Fuel and carbon signals provided limited direction. CEGH gas fell to €42.74/MWh, Greek gas to €41.51/MWh, and EUAs remained broadly flat at €79.78/t. Coal forwards showed only marginal strength. This confirms that the day’s pricing was not fuel-driven, but rather a function of system stress, residual load distribution and cross-border transmission value.
Forward curves reinforced the structural premium in Hungary. Week 26 traded at €129.50/MWh, Week 27 at €123.50/MWh, July 2026 at €119.50/MWh, and Cal-26 at €111.50/MWh. The persistent HU–DE spread reflects expectations of continued import dependency during tight hours and ongoing exposure to SEE flow volatility and interconnector constraints.
For industrial consumers, the implication is increasingly direct. Even in lower-priced southern markets, exposure is shifting from baseload cost to hourly volatility risk, particularly in evening peaks. Procurement strategies based solely on average prices are becoming less reliable, while shaped consumption, flexibility and storage integration are gaining importance across the region.
For renewable developers, the same structure defines revenue risk. Solar generation continues to compress midday prices, while wind provides more balanced exposure across higher-value hours. However, rising cannibalisation effects in solar-heavy periods highlight the importance of storage pairing, PPAs, and export accessibility for bankability in SEE markets.
The broader investment backdrop supports this direction. Europe is expected to add around 151 GW of wind capacity between 2026 and 2030, including 117 GW onshore and 34 GW offshore, pushing total capacity toward 439 GW. For South-east Europe, this does not only increase renewable supply—it increases hourly volatility, congestion pressure and balancing-market importance.
Regional developments already reflect this shift. Montenegro’s Kapino Polje B1 solar expansion adds 11.43 MW of new capacity, while Romania’s hybrid PPA structures—combining wind, solar and battery storage—signal a move toward dispatch-aware renewable financing models. These structures increasingly define bankable projects, where value depends not only on production, but on timing, flexibility and contractual shaping.
Thermal and gas fundamentals remain central to system security. Bulgaria’s proposed gas price increase, Croatia’s extended offshore production rights, and Serbia’s evolving ownership and licensing structure all feed into fuel-security assumptions and generation reliability expectations across SEE markets.
Nuclear continues to provide stability in an otherwise volatile system. Slovenia’s Krško plant remains a key anchor for regional baseload supply, with high availability and planned output increases into 2026 reinforcing its role as a low-carbon stability asset for Slovenia and Croatia.
Turkey’s growing renewable and storage financing pipeline further adds a regional reference point for scale, equipment supply chains and investment expectations, even if it sits outside the direct SEE price coupling zone.
The overall trading conclusion from 18 June is clear: South-east Europe is becoming simultaneously more interconnected and more fragmented. Prices are increasingly shaped by hourly scarcity, cross-border constraints and flexibility availability, rather than fuel alone. The key source of value is no longer just generation, but the ability to deliver power to the right market, at the right time, through a grid that is increasingly the binding constraint of the entire system.