The day-ahead electricity markets across Southeast Europe (SEE) and Hungary on 25 February 2026 reveal a fragmented pricing structure, highlighting the challenges of achieving regional integration. Base electricity prices varied significantly, with Hungary’s HUPX recording a rate of 107.7 EUR/MWh, while ALPEX in Albania saw prices as low as 45.5 EUR/MWh. Other notable rates included Slovenia’s BSP at 100.4 EUR/MWh, Croatia’s CROPEX at 94.1 EUR/MWh, Romania’s OPCOM at 59.0 EUR/MWh, Greece’s HENEX at 54.5 EUR/MWh, Serbia’s SEEPEX at 53.6 EUR/MWh, and Montenegro’s BELEN also at 54.5 EUR/MWh. The stark price difference of over 60 EUR/MWh between Hungary and Albania underscores the incomplete convergence of prices across the region, influenced by factors such as generation mix, transmission constraints, and liquidity levels.
Hungary’s pricing above the 100 EUR/MWh mark situates it within a Central European pricing framework, primarily driven by gas-fired marginal units and cross-border electricity flows that increasingly dictate market clearing levels. Slovenia’s price alignment further reflects its integration with Austrian and German power markets. In contrast, exchanges in the Western Balkans continue to operate at significant discounts due to their reliance on hydroelectric resources, lower liquidity, and less effective market coupling mechanisms.
The observed intraday volatility emphasizes these structural disparities. On HUPX, prices fluctuated significantly, reaching a peak of 177.5 EUR/MWh and a low of 46.3 EUR/MWh, indicating considerable stress during peak load periods and the need for ramping capabilities. Similar peaks were noted in Slovenia and Croatia, while SEEPEX and ALPEX faced sharp hourly price spikes despite lower average daily rates. Notably, Albania recorded a maximum hourly price of 163 EUR/MWh, illustrating how thin liquidity can exacerbate volatility when marginal units dominate pricing.
The overall system balance further contextualizes these market dynamics, with total regional generation reported at 38,560 MW, against a consumption level of 36,485 MW. Hydro power contributed significantly with 11,961 MW, followed by coal with 7,182 MW, gas at 5,877 MW, wind generating 2,510 MW, solar contributing 3,194 MW, and nuclear energy providing 5,539 MW. The prevalence of hydro generation in several Balkan countries tends to suppress local prices during stable water conditions; however, Hungary’s reliance on gas links it more closely to carbon-adjusted pricing trends seen in Central Europe.
The net import figures for the SEE + Hungary system indicated an outflow of -2,652 MW, with core imports from Austria and Slovakia amounting to only 177 MW. This dependency on external markets for balancing supply highlights the region’s vulnerability during peak demand periods. The observed spot spread between Hungary and Germany was noted at 13.7 EUR/MWh, suggesting active arbitrage opportunities driven by these price differentials.
A critical factor contributing to ongoing price fragmentation is liquidity asymmetry across markets. HUPX, BSP, and CROPEX benefit from deeper order books and stronger connections to EPEX markets which facilitate greater price convergence with broader continental hubs. Conversely, exchanges like SEEPEX, BELEN, and ALPEX operate under thinner trading conditions that make them more susceptible to fluctuations in generation capacity. The persistent discounts observed in Serbia and Albania reflect not only cyclical trends but also deeper structural differences in market design.
The increasing penetration of renewable energy sources adds another layer of complexity to this landscape. Combined wind and solar output reached approximately 5,704 MW, which can depress midday prices in southern markets while exacerbating evening volatility during ramp-up periods for thermal generation units operating at around 13,600 MW installed capacity. As renewable capacities expand further within the region’s energy mix, it is expected that intraday price spreads will widen rather than narrow—emphasizing the need for flexible resources and enhanced cross-border capacity for effective grid management.
The pricing data from 25 February illustrates a multi-tiered regional structure: Central European-linked markets cluster around the threshold of 100 EUR/MWh; intermediate markets like Romania and Greece settle within the range of 50–60 EUR/MWh; while Western Balkan exchanges continue to show significant structural discounts. These interconnected tiers highlight ongoing challenges related to transmission bottlenecks and varying levels of renewable energy integration that prevent full market harmonization.
This environment presents ongoing arbitrage opportunities across different corridors within the region; for instance, there exists a notable differential exceeding 50 EUR/MWh</span between HUPX’s rate of “107.7 EUR/MWh”and SEEPEX’s rate of ““53.6 EUR/MWh” . Additionally, ALPEX demonstrates a discount exceeding ““60 EUR/MWh” relative to Hungary—indicative either of oversupply or structural isolation within its market framework.
The implications suggest that SEE spot markets function as a semi-integrated system tethered to Central European dynamics while simultaneously influenced by localized hydro resources and transmission limitations. Until comprehensive flow-based coupling mechanisms are established alongside enhanced balancing harmonization efforts across borders are achieved , price dispersion will remain entrenched within this regional trading landscape.
The data from 25 February encapsulates more than just daily market fluctuations; it reflects an evolving energy landscape—partially aligned with EU frameworks yet fundamentally segmented internally . As carbon pricing influences dispatch economics alongside increasing renewable uptake , heightened volatility is anticipated across SEE spot markets , reinforcing the necessity for thorough analysis concerning cross-border spread dynamics alongside system balance forecasting as integral components in shaping regional power trading strategies.
