South-east Europe’s power market opened the 18 June 2026 trading day with a clear regional split: Hungary, Slovenia, Croatia, Romania and Italy held close to the upper end of the European day-ahead price stack, while Greece, Bulgaria, Serbia, Montenegro, Albania and North Macedonia traded at a steep discount. The result was not a simple story of weak demand or renewable oversupply, but a sharper picture of how grid constraints, export positions, thermal dispatch, solar timing and forward-market risk are now separating neighbouring electricity markets that are often treated as a single regional block.
The Hungarian day-ahead benchmark, HUPX, cleared at €133.60/MWh, up €9.80/MWh day on day. That placed Hungary slightly below Germany at €139.92/MWh and Italy at €139.58/MWh, while Austria cleared at €131.78/MWh. Romania followed at €124.26/MWh, Slovenia at €129.30/MWh and Croatia at €127.27/MWh, confirming that the northern and central part of the SEE corridor remained linked to the higher-priced continental and Italian marginality.
The southern Balkan markets moved in the opposite direction. Greece fell to €76.83/MWh, Bulgaria to €84.09/MWh, Serbia to €79.14/MWh, Montenegro to €81.29/MWh, Albania to €79.81/MWh and North Macedonia to €82.80/MWh. The gap between Hungary and Greece widened to €56.78/MWh, while Hungary traded €54.47/MWh above Serbia and more than €52/MWh above Montenegro. For traders, this was the day’s most important signal: price formation was no longer merely following fuel and carbon, but increasingly reflecting the ability, or inability, of each bidding zone to move surplus energy into higher-value markets.
Regional consumption rose to 29,836 MW, up 887 MW from the previous day, as the average SEE+Hungary temperature increased to 23.4°C. The demand increase was not yet extreme summer air-conditioning stress, but it was enough to lift the northern markets where residual load was tighter and interconnection value was higher. Hungary’s own demand forecast stood at 4,538 MW, while Greece was at 6,173 MW and the Romania-Bulgaria block at 8,900 MW.
The system balance, however, showed that stronger demand did not translate into a broadly tighter SEE market. The region shifted into a net export position of around 1,121 MW, compared with a positive import position a day earlier. That reversal was crucial. The market was not short of energy as a region; it was short of tradable flexibility in the right places. The aggregate export position masked a fragmented map in which Greece and Bulgaria were exporting strongly, Serbia and Croatia were importing, and Hungary sat between the higher-priced CORE/Italian structure and cheaper southern flows.
Bulgaria exported around 1,167 MW on average, while Greece exported roughly 1,630 MW. Serbia, by contrast, was a net importer at around 533 MW, Croatia imported around 1,191 MW, and Hungary imported around 377 MW. This flow pattern explains why the price spread did not close despite large southern discounts. Cheap energy existed in the region, but the relevant question was whether it could reach the premium zones at scale and at the right hours. The day’s answer was only partially.
Generation data added another layer. Total regional generation stood at 28,313 MW, down 608 MW day on day, while hydro output was broadly stable at 6,138 MW. Coal generation declined to 4,728 MW, while gas-fired output increased to 4,804 MW, suggesting that flexible thermal units remained needed despite stronger renewable availability. Nuclear generation rose modestly to 4,942 MW, while wind climbed sharply to 1,551 MW, up 830 MW. Solar generation fell to 5,565 MW, down 1,671 MW, but solar still represented a major part of the midday price formation.
That mix explains the shape of the daily curve. The region had enough low-marginal-cost supply to compress southern prices during renewable-heavy hours, but the evening ramp remained expensive in Hungary and neighbouring central markets. HUPX reached a maximum of €389.60/MWh, with the highest price at hour 22, while the minimum was €18.60/MWh at hour 15. This intraday spread is now the central commercial reality for the SEE power market: average prices matter less than the volatility between solar-saturated afternoon hours and evening scarcity hours.
The pattern was similar across higher-priced markets. Slovenia reached a maximum of €369.80/MWh, Croatia €374.20/MWh, Austria €381.70/MWh and Romania €386.80/MWh. These were not baseload stories; they were evening flexibility stories. Battery storage, pumped hydro, responsive industrial demand, cross-border nominations and intraday trading are increasingly being priced through these short windows. A generator or trader exposed only to daily averages would miss the value concentration in the late-evening peak.
Serbia’s SEEPEX, despite clearing at a much lower base price of €79.14/MWh, also showed a meaningful daily range, with a maximum of €140/MWh and a minimum of €8.10/MWh. Montenegro cleared at €81.29/MWh, with a maximum of €139.10/MWh and a minimum of €7.10/MWh. Albania’s ALPEX zone cleared at €79.81/MWh, while North Macedonia was at €82.80/MWh. These figures point to a southern market that is not structurally insulated from peak scarcity, but remains heavily discounted in baseload terms because its daytime supply-demand balance is softer and its export route to premium markets is constrained.
Fuel and carbon markets gave limited support to the move. CEGH Austrian gas stood at €42.74/MWh, down €0.80/MWh, while Greek gas was €41.51/MWh, down €0.50/MWh. EU Allowances were effectively flat at €79.78/t, down €0.10/t. Coal forwards moved slightly higher, with July coal at $114.50/t and Q3 coal at $114/t. The day-ahead power move in Hungary, therefore, cannot be explained simply by a fuel rally. It was a power-system move: residual load, interconnection value and evening scarcity carried more weight than the marginal shifts in gas, coal and carbon.
Forward prices reinforced the same message. Hungarian Week 26 power held at €129.50/MWh, Week 27 rose to €123.50/MWh, July 2026 moved to €119.50/MWh, and Cal-26 remained at €111.50/MWh. The HU-DE spreads also stayed materially positive in the forward curve, with July at €21.50/MWh and Cal-26 at €19/MWh. The market is still pricing Hungary as a premium zone relative to Germany, even when individual spot sessions see Germany or Italy at the top of the stack. That premium reflects structural risk: import dependency in tight hours, limited local flexibility, and exposure to SEE flow volatility.
For industrial buyers, the message is uncomfortable. The southern Balkans may show attractive daily baseload prices, but industrial procurement cannot be built on baseload averages alone. A Serbian, Montenegrin or North Macedonian offtaker exposed to market-indexed supply can still face sharp evening costs, while a Hungarian or Croatian consumer remains exposed to a more consistently premium price environment. The commercial value of shaped PPAs, consumption flexibility and behind-the-meter storage is rising because the price risk is increasingly hourly rather than monthly.
For renewable developers, the day also underlines the changing economics of solar and wind. Solar continues to push down midday prices, but the revenue capture risk is visible across the region. The stronger wind output on 18 June helped the system, yet wind has a different commercial profile from solar because it is less concentrated in midday hours and can capture value during shoulder and peak periods when system tightness is higher. That distinction matters for lenders. A solar project selling merchant exposure into the southern Balkans faces a growing cannibalisation discount unless it is paired with storage, contracted to a creditworthy industrial offtaker, or located at a node with credible export access.
The wider news flow points in the same direction. Europe is expected to add around 151 GW of wind capacity between 2026 and 2030, with approximately 117 GW coming from onshore projects and 34 GW from offshore. The EU is expected to account for 112 GW of that expansion, while total European installed wind capacity could reach 439 GW by 2030. For SEE, the important part is not the headline capacity number, but the grid and market consequence. More wind capacity means more low-marginal-cost supply, more volatile hourly spreads, and higher value for balancing, forecasting, congestion management and storage.
Regional project announcements are already moving in that direction. Montenegro’s environmental approval for EPCG’s Kapino Polje B1 solar project adds another 11.43 MW to the domestic renewable pipeline, with expected first-year generation of about 15.79 GWh. The wider Kapino Polje complex, including B1, B2, L1 and L2, carries an estimated investment value of around €35.1mn. In Romania, Patria Bank’s green PPA with Alive Capital is tied not only to renewable electricity supply backed by Guarantees of Origin, but also to financing for projects including the Vanatori hybrid scheme, combining 10 MW of wind, 5 MW of solar and 2.5 MW/10 MWh of battery storage.
That hybrid structure is closer to where the regional market is heading. Pure energy production is no longer the only bankability variable. The financeable product is increasingly a shaped, documented and dispatch-aware electricity profile, especially for industrial buyers facing carbon, ESG and supply-chain pressure. The ability to combine renewables, storage, Guarantees of Origin, credible metering and contractual delivery discipline is becoming a commercial advantage rather than a sustainability add-on.
The thermal and security-of-supply side remains equally important. Bulgaria’s Bulgargaz is proposing a 5.84% wholesale gas price increase for July, to around €37.70/MWh, while Croatia has updated INA’s North Adriatic gas production permit through 2040, with the area accounting for roughly a quarter of INA’s gas production. Serbia’s NIS secured a new OFAC license until 1 July, preserving operational continuity while negotiations involving MOL and GazpromNeft remain politically and commercially sensitive. These are not isolated corporate events; they affect fuel security, refinery logistics, gas-fired generation assumptions and the credit risk premium attached to national energy systems.
Nuclear also remains a stabilising factor. Slovenia’s Krsko nuclear plant generated 5.547 TWh in 2025, with availability and capacity factors above 91%, and management is targeting more than 6 TWh in 2026 because no major outage is planned. For Slovenia and Croatia, which both benefit from Krsko’s output structure, nuclear availability remains one of the few sources of firm low-carbon baseload in a market increasingly shaped by weather-driven volatility. The constraint is not only technical availability, but also summer river-temperature limits and the rising cost of nuclear equipment, materials and services.
Turkey’s financing signal adds a broader regional benchmark. The World Bank’s additional €400mn package for renewable energy and storage, channelled through Turkish development finance institutions, could support 1,579 MW of renewable capacity and 392 MWh of battery storage, while mobilising up to $405mn in private investment. Turkey is not part of the SEE day-ahead price table in the same way as Hungary or Serbia, but its scale matters for equipment procurement, contractor capacity, regional storage learning curves and investor expectations across the wider power market.
The trading lesson from 18 June is direct: SEE is becoming more liquid, more renewable, more interconnected and more volatile at the same time. That combination rewards traders and investors who can read hourly spreads, cross-border constraints and technology-specific capture rates, while punishing strategies built on simple average-price assumptions. Hungary’s premium to the southern Balkans, Greece and Bulgaria’s export position, Serbia and Croatia’s import needs, and the widening evening peaks all point to the same market structure. The next phase of regional value will sit less in producing electrons and more in delivering the right electrons, at the right hour, through a grid that is becoming the main economic bottleneck.
