The energy landscape in Southern South-Eastern Europe (SEE) is undergoing a significant transformation as local power markets evolve from being perceived as mere “discounted zones” to becoming structural curtailment basins. This shift, characterized by increasing renewable energy penetration, transmission constraints, and a lack of operational flexibility, fundamentally alters the dynamics of price formation across the region. The developments observed on 26 February 2026 underscore that this change is not merely cyclical but represents a long-term trend with far-reaching implications for market participants.
Recent pricing data illustrates this shift starkly. On that date, Serbia’s electricity market cleared at 42.64 EUR/MWh, while North Macedonia recorded 41.27 EUR/MWh, and Montenegro reached 47.82 EUR/MWh. In contrast, Hungary’s prices were significantly higher at 87.06 EUR/MWh, revealing a price differential exceeding 40 EUR/MWh between neighboring systems. This disparity cannot solely be explained by variations in fuel costs or demand; it is largely due to the inability to transport surplus renewable generation northward during peak production hours.
The systemic nature of price floor erosion is becoming increasingly apparent in these markets. The frequency of near-zero pricing in Serbia and North Macedonia, along with occasional occurrences in Croatia and Slovenia, indicates that this phenomenon is now embedded within the market structure itself. Even when electricity prices do not dip below zero, they are compressing towards levels that threaten the economic viability of thermal generation sources, leading gas plants to withdraw from the merit order for extended durations.
The concept of economic curtailment plays a pivotal role in this context. While grid operators may not officially limit renewable output, market conditions effectively impose similar restrictions through price suppression mechanisms. Midday prices often hover around 0–10 EUR/MWh, discouraging additional generation and undermining margins for all producers involved. Consequently, while increased capacity might initially seem positive for supply security, it has become increasingly detrimental to average price stability in these markets.
Transmission limitations exacerbate the challenges faced by Southern SEE power markets. Serbia’s capacity to export surplus generation to Hungary is significantly hindered during periods when Hungary relies on imports from Austria and Slovakia. As Hungary serves as a critical junction between Core Europe and SEE, it prioritizes northern imports based on price differentials, thereby trapping renewable generation within southern markets even when conditions would otherwise favor exports.
The rapid expansion of solar installations in Serbia and North Macedonia has not been matched by adequate storage solutions or demand response capabilities. Without sufficient grid-scale battery systems or responsive demand programs, excess midday solar generation continues to flood local markets without alleviating evening scarcity issues. Each increment of solar capacity only deepens midday oversupply without addressing the pronounced need for energy during peak hours.
The volatility experienced during evening hours further complicates this scenario. As solar output declines rapidly after midday, Southern SEE markets frequently witness sharp price increases; however, these spikes are generally shorter than in previous years due to a narrowing evening window where gas sets marginal prices—sometimes lasting only three to four hours. While peak prices can soar above 120–140 EUR/MWh, the limited duration of these peaks hampers generators’ ability to recover losses incurred during low-price periods.
For traders operating in this evolving market structure, there are both risks and opportunities presented by the characteristics of the structural curtailment basin. Long-term baseload positions are increasingly susceptible to midday price erosion despite seemingly stable average prices; intraday volatility can undermine flat positions significantly. Conversely, short-duration trading strategies that capitalize on predictable trough-and-spike patterns may yield substantial profits in this new environment.
The situation is further complicated by Romania’s fluctuating role within this framework. Although Romania does not experience discounts as severe as those seen in Serbia or North Macedonia, its energy balance oscillates between surplus and deficit depending on hydro conditions and interconnections with neighboring countries. The anticipated development of up to 500 MW of solar and storage projects could transform Romania’s status from a marginal exporter into a key swing market player—potentially alleviating or redistributing curtailment pressures depending on enhancements made to interconnection infrastructure.
The ongoing rise in carbon pricing also impacts operational dynamics within Southern SEE markets. Elevated EUA prices render coal-fired units less competitive; consequently, regions still reliant on coal face accelerated shifts towards reliance on renewables and gas-fired generation. This transition diminishes coal’s stabilizing influence over market volatility while intensifying fluctuations between surplus and scarcity conditions.
Gas corridor developments—including LNG supplies into Greece—affect peak pricing but do little to mitigate midday oversupply challenges inherent in the current market structure. While enhanced gas availability may temper extreme evening spikes, it fails to address underlying issues related to curtailment dynamics; rather than raising price floors for electricity producers, it risks compressing overall revenue streams further.
In terms of market structure evolution, Southern SEE appears poised for a bifurcated pricing system characterized by low solar prices juxtaposed against compressed scarcity pricing throughout daily cycles. This narrowing gap heightens competition among flexible assets while necessitating adjustments in modeling frameworks used by traders; traditional forecasting models reliant on linear demand-generation relationships will increasingly misrepresent potential outcomes.
As risk management strategies must adapt accordingly, recognizing the widening divide between daily averages and hourly extremes becomes crucial for stakeholders aiming to mitigate exposure to tail risks associated with concentrated spike events or missed trough opportunities that could jeopardize profitability even amid correct peak positioning strategies.
The outlook remains clear: unless substantial storage capacities are deployed or cross-border transmission infrastructures expanded significantly, Southern SEE will continue functioning as a structural curtailment basin where solar growth exacerbates trough pricing while export limitations hinder alignment with higher-priced markets like Hungary. Evening scarcity may persist but could narrow further due to improvements in gas infrastructure—ultimately defining a regional landscape characterized more by intraday polarization than average stability.
The events observed during the 26 February 2026 trading session serve as an illustrative example of how deeply entrenched these dynamics have become within regional price formation processes—marking Southern SEE as structurally distinct rather than merely cheaper compared to its northern counterparts.
