South East Europe’s power markets are entering a more sophisticated and competitive phase. The next two years are expected to feature deeper exchange liquidity, expanding intraday trading, wider adoption of 15-minute pricing, growing battery participation, continued cross-border constraints, and increasingly demanding compliance requirements.
The base-case scenario for 2026–2028 involves partial integration rather than full market convergence. It also points to persistent volatility that can create both opportunities and challenges for market participants.
EU market coupling and the move to 15-minute day-ahead trading
EU markets in South East Europe are continuing to align with broader European market design principles. Hungary, Romania, Bulgaria, Greece, Croatia, and Slovenia are already integrated into the wider EU market-coupling framework.
The transition to 15-minute day-ahead trading from 30 September 2025 is expected to produce more granular price signals. It is also expected to increase the commercial value of flexibility.
Western Balkan market development and organized trading gaps
Western Balkan markets are developing at different speeds. Serbia is described as the region’s most strategically important market due to SEEPEX, the introduction of negative pricing, its central geographic position, and its role in regional electricity flows.
Albania and Kosovo have established a coupled day-ahead market through ALPEX. North Macedonia has expanded market functionality through the launch of intraday trading on MEMO, while Bosnia and Herzegovina remains the largest missing component in organized market development.
Hybrid conditions as coupling advances toward 2028
Market coupling is expected to advance but not immediately. The Energy Community said in December 2025 that the earliest market coupling for Contracting Parties could occur in 2028, subject to compliance verification by the European Commission.
Traders are therefore expected to operate under hybrid conditions for several more years. These conditions are described as a mix of coupled borders, explicit transmission arrangements, and uneven liquidity.
Volatility drivers and battery storage effects on price formation
ACER monitoring of Southeast Europe has highlighted limited cross-zonal capacity and insufficient system flexibility as major contributors to market stress events. With renewable generation expansion, the region is expected to see more low-price or negative-price periods during midday hours.
The same monitoring points to increasingly valuable flexibility during evening demand peaks. Battery storage is expected to gradually reshape price formation but is unlikely to eliminate volatility.
The source links storage deployment with reduced some intraday price extremes while noting that cross-border constraints, hydro variability, heatwaves, natural-gas market developments, and CBAM-related effects will continue driving significant market movements.
CBAM uncertainty affecting Western Balkans–EU electricity trade
CBAM is expected to remain one of the largest uncertainties for Western Balkan–EU electricity trade. During Q1 2026, commercially scheduled exchanges between the EU and the Western Balkans declined by 25%.
In Energy Community Contracting Parties, day-ahead prices averaged €30/MWh below neighboring EU markets. Unless carbon-accounting frameworks, transit rules, and origin-certification requirements become clearer, some economically rational trades may remain commercially unattractive.
Compliance-focused trading requirements across time, location and flexibility
The primary beneficiaries of the evolving market structure are expected to include sophisticated trading firms, integrated utilities, battery operators, hydro asset managers, flexible industrial consumers, and exchanges able to attract deeper liquidity.
The source also flags challenges for participants relying on simplistic baseload assumptions, weak compliance structures, undercapitalized trading operations, or merchant-only renewable exposure without effective shape-risk management.
{{}} For traders, the model described combines weather forecasting expertise with cross-border capacity management and quarter-hour optimization. It also includes REMIT compliance, CBAM documentation capabilities, and disciplined collateral management.
Portfolio management for utilities; risk factors for renewables and industry
{{}} For utilities, trading is described as becoming a portfolio-optimization function rather than a standalone activity. Generation assets, customer supply obligations, PPAs, storage resources, balancing responsibilities, and cross-border positions are described as needing integrated management.
{{}} For renewable-energy developers, market assumptions are said to increasingly incorporate negative pricing, capture-price risk, imbalance exposure, and basis risk. Future project revenues are described as depending not only on output but also on when and where electricity is delivered.
{{}} For industrial buyers, electricity procurement strategies are described as moving beyond traditional annual baseload thinking. Key commercial risks are tied to hourly and quarter-hourly shape exposure, evening peak pricing, solar PPA mismatches, and index basis risk.
Regulatory priorities for coupling progress and trade distortions
{{}} For regulators, priorities are listed as accelerating market coupling. They also include expanding usable cross-zonal capacity, strengthening balancing-market design, clarifying storage regulations, improving REMIT enforcement, and reducing CBAM-related trade distortions.
The source states that South East Europe is unlikely to become a simple or perfectly integrated electricity market by 2028. It expects greater transparency and liquidity alongside higher levels of technical, commercial, and regulatory sophistication for participation.
{{}} It adds that future trading value will increasingly be defined across five dimensions: time, location, flexibility, carbon, and compliance.
