South East Europe’s power markets are entering a more sophisticated and competitive phase. The next two years are likely to be defined by 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 is not one of full market convergence. Instead, it is a period of partial integration combined with persistent volatility, creating both opportunities and challenges for market participants.
EU markets within South East Europe will continue aligning 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 create more granular price signals and increase the commercial value of flexibility.
Western Balkan markets will continue to develop, although at varying speeds. Serbia remains 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, while North Macedonia has expanded market functionality through the launch of intraday trading on MEMO. Bosnia and Herzegovina remains the largest missing component in organized market development.
Market coupling is expected to advance, but not immediately. The Energy Community stated in December 2025 that the earliest market coupling for Contracting Parties could occur in 2028, subject to compliance verification by the European Commission. As a result, traders should prepare for several more years of hybrid market conditions characterized by a combination of coupled borders, explicit transmission arrangements, and uneven liquidity.
Price volatility is likely to remain a defining feature of the regional market. ACER’s monitoring of Southeast Europe has highlighted limited cross-zonal capacity and insufficient system flexibility as major contributors to market stress events. As renewable generation continues to expand, the region will likely experience more low-price or negative-price periods during midday hours and increasingly valuable flexibility during evening demand peaks.
Battery storage will gradually reshape price formation, but it is unlikely to eliminate volatility. While storage deployment should reduce some intraday price extremes, cross-border constraints, hydro variability, heatwaves, natural-gas market developments, and CBAM-related effects will continue to create significant market movements.
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%, while day-ahead prices in Energy Community Contracting Parties 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.
The primary beneficiaries of this evolving market structure are likely to be sophisticated trading firms, integrated utilities, battery operators, hydro asset managers, flexible industrial consumers, and exchanges capable of attracting deeper liquidity.
Conversely, participants relying on simplistic baseload assumptions, weak compliance structures, undercapitalized trading operations, or merchant-only renewable exposure without effective shape-risk management may face increasing challenges.
For traders, the successful model will combine weather forecasting expertise, cross-border capacity management, quarter-hour optimization, REMIT compliance, CBAM documentation capabilities, and disciplined collateral management.
For utilities, trading is becoming a portfolio-optimization function rather than a standalone activity. Generation assets, customer supply obligations, PPAs, storage resources, balancing responsibilities, and cross-border positions will need to be managed as an integrated portfolio.
For renewable-energy developers, market assumptions must increasingly incorporate negative pricing, capture-price risk, imbalance exposure, and basis risk. Future project revenues will depend not only on how much electricity is produced, but also when and where it is delivered.
For industrial buyers, electricity procurement strategies must move beyond traditional annual baseload thinking. Key commercial risks will increasingly be tied to hourly and quarter-hourly shape exposure, evening peak pricing, solar PPA mismatches, and index basis risk.
For regulators, the priorities are becoming increasingly clear: accelerate market coupling, expand usable cross-zonal capacity, strengthen balancing-market design, clarify storage regulations, improve REMIT enforcement, and reduce CBAM-related trade distortions.
South East Europe is unlikely to become a simple or perfectly integrated electricity market by 2028. However, it is expected to become more transparent, more liquid, and more attractive for investment. At the same time, participation in the market will require higher levels of technical, commercial, and regulatory sophistication.
The region’s future trading value will increasingly be defined across five dimensions: time, location, flexibility, carbon, and compliance.
That is the emerging SEE power-market outlook: more exchange-based trading, greater cross-border complexity, continued volatility, and greater rewards for participants capable of managing all three successfully.