Southeast Europe has one of the most interconnected power systems in Europe, yet it remains divided by market rules, capacity-allocation procedures, regulatory borders and uneven liquidity. Electricity regularly moves across Serbia, Montenegro, Bosnia and Herzegovina, Albania and North Macedonia on its way between EU member states, but the Western Balkan markets still operate outside the full European day-ahead, intraday and balancing architecture.
This mismatch has become harder to defend as renewable generation expands. The region already experiences simultaneous periods of solar surplus, hydro scarcity, thermal outages and sharp evening demand ramps. Physical interconnection can move electricity between these conditions, but commercial fragmentation prevents traders, generators, storage operators and industrial consumers from using the network as efficiently as participants inside the EU’s coupled market.
The Energy Community estimates that as much as 70% of electricity passing through the Western Balkans can represent flows between different EU countries. Serbia sits at the centre of this transit structure, connected to Hungary, Romania, Bulgaria, North Macedonia, Kosovo, Montenegro, Bosnia and Herzegovina and Croatia. Montenegro adds the 600 MW first pole of the submarine interconnector with Italy, while Albania and North Macedonia link the western and southern parts of the regional system with Greece.
The hardware is European; the market treatment is not.
ENTSO-E’s 2026 Market Report shows that the EU electricity market has moved to 15-minute trading intervals in day-ahead and intraday markets. Intraday cross-border gate closure has been reduced from 60 minutes to 30 minutes on many participating borders. Balancing integration through the MARI and PICASSO platforms is expanding, while long-term flow-based capacity allocation is being prepared for larger European regions.
European balancing platforms produced more than €1.18 billion of surplus in 2025 through imbalance netting and more efficient reserve activation. That figure is significant because it demonstrates that market integration is not simply a regulatory exercise. It converts spare flexibility in one system into a tradable service for another, lowering balancing costs and reducing the quantity of reserves that each TSO must procure domestically.
In the formal Southeast Europe Capacity Calculation Region, however, the 2026 assessment still concentrates on Bulgaria, Romania and Greece. The Western Balkan TSOs remain in a transitional position even though EMS, CGES, MEPSO, NOSBiH, KOSTT and OST have agreed with EU neighbours on a framework intended to integrate their coordinated system operation and capacity calculation with the established European regions.
Serbia has the region’s most developed trading structure. SEEPEX, now part of the wider ADEX group with Slovenia’s BSP SouthPool and Hungary’s HUPX, operates day-ahead and intraday trading. Day-ahead volume in 2024 represented approximately 17.41% of Serbian electricity consumption, while intraday trading accounted for only about 0.34%.
That imbalance reveals the next market-development problem. A functioning intraday platform exists, but liquidity remains too low to provide a reliable adjustment market for a rapidly growing wind and solar fleet. Generators can sell or buy energy closer to delivery, but thin order books increase transaction costs and leave larger balancing exposures with EPS, traders and EMS.
SEEPEX’s introduction of negative prices in May 2026 was a necessary change. A zero-price floor hid the economic signal created when renewable output and inflexible thermal generation exceeded demand and export capability. Negative pricing allows the market to value curtailment, charging demand, storage and flexible consumption. It also exposes weaknesses in fixed-premium support schemes and PPAs that were designed around an assumption that the wholesale price could not fall below zero.
Montenegro, Albania, North Macedonia and Kosovo have established day-ahead markets through MEPX, ALPEX and MEMO-related arrangements, but liquidity remains constrained by small domestic consumption, limited participant numbers and the absence of full cross-border coupling. Bosnia and Herzegovina remains further behind, with fragmented institutional responsibilities adding to the difficulty of establishing a credible organised market.
The region’s prices already show strong correlation. That reflects interconnected generation fundamentals: Balkan hydrology, Bulgarian and Romanian nuclear availability, Greek gas-fired marginality, Serbian coal generation, Hungarian imports and Italian demand all influence the same physical system. Correlation, however, is not the same as convergence. Explicit border auctions, uncoordinated capacity calculation and administrative barriers can preserve material spreads even when the underlying supply position is similar.
Flow-based market coupling would change the use of regional transmission capacity. Bilateral net transfer capacities treat each border separately and cannot fully capture how a commercial exchange affects parallel flows across several countries. A Serbian export to Hungary can alter physical flows in Romania, Croatia or Bosnia and Herzegovina. Flow-based calculation uses a regional network model to allocate capacity according to the actual constraints, potentially increasing tradable capacity while maintaining operational security.
The transition is technically and politically demanding. TSOs must exchange sufficiently detailed grid models, agree common contingencies and remedial actions, harmonise calculation methodologies and accept regional scrutiny of internal constraints. Regulators must approve compatible terms and conditions. Power exchanges and market participants need operational procedures aligned with European algorithms and gate times.
The 70% minimum capacity requirement adds pressure. European rules require TSOs to make at least 70% of transmission capacity available for cross-border trade, subject to justified security limitations and approved action plans or derogations. Western Balkan grids often use internal and cross-border elements to carry the same transit flows, making it difficult to separate domestic constraints from regional trading capacity.
This is also where the lessons of the June 2024 Balkan blackout remain relevant. Physical integration without complete regional visibility can amplify disturbances. Market integration therefore cannot advance independently of coordinated security analysis, voltage assessment, contingency planning and real-time data exchange. More commercial capacity is valuable only when TSOs and Regional Coordination Centres can identify and manage the resulting flow patterns.
The economic value would be substantial. Serbia’s hydropower and future battery projects could sell balancing and flexibility into a larger market. Montenegro could use the Italian interconnector more efficiently, particularly when hydrology and Italian prices diverge. Albania could monetise reservoir flexibility beyond day-ahead exports. North Macedonia could reduce exposure to expensive emergency imports. Bosnia and Herzegovina could improve utilisation of its hydro and thermal portfolio while preparing for the commercial effect of carbon pricing.
Battery economics are particularly sensitive to integration. A BESS relying only on domestic day-ahead arbitrage may struggle to produce a bankable revenue case in a small market. Access to intraday volatility, balancing capacity, balancing energy and cross-border products can raise annual gross revenue materially. A diversified revenue stack also reduces dependence on any single price spread.
Industrial consumers face the opposite exposure. Fragmented markets reduce their ability to hedge electricity costs across borders, while low forward-market liquidity limits the availability of credible reference prices for long-term PPAs. An exporter buying renewable electricity in Serbia may have the physical power, guarantees of origin and metering data required for a low-carbon claim, yet still face basis risk because the local PPA price cannot be efficiently hedged against a liquid regional forward product.
CBAM reinforces the commercial case for integration. The EU’s definitive carbon-border regime places greater value on transparent electricity sourcing, verifiable emissions and credible market prices. Western Balkan electricity exports will increasingly compete on their carbon content rather than only their marginal production cost. Coal-heavy systems can no longer rely indefinitely on an implicit carbon advantage when selling into neighbouring EU markets.
Market coupling would not remove the region’s structural price differences. Serbia’s lignite fleet, Montenegro’s hydro concentration, Albania’s exposure to rainfall, Greece’s gas dependence and Bulgaria’s nuclear and coal portfolio will continue to produce different hourly fundamentals. Coupling would make those differences visible and tradable, while reducing artificial spreads created by inefficient capacity allocation.
The main obstacles are now institutional. VAT treatment, collateral requirements, licensing, financial settlement and cross-border taxation remain uneven. Market participants operating across several Western Balkan jurisdictions can face duplicated registrations, incompatible invoicing practices and higher working-capital requirements. These costs matter in markets where traded volumes are already small.
A credible integration sequence would combine coordinated capacity calculation, day-ahead coupling, intraday coupling and staged access to European balancing platforms. Advancing only the day-ahead layer would leave renewable generators exposed close to real time. Opening balancing without liquid intraday trading would transfer too much forecasting risk directly from generators to TSOs.
Serbia is positioned to become the regional liquidity anchor because it combines the largest Western Balkan power system, the deepest exchange, extensive interconnections and ownership links with EU exchanges through ADEX. That position is not automatic. Liquidity must grow beyond the present concentration in day-ahead trading, and market rules must support negative prices, aggregation, storage participation and faster products.
The Western Balkans no longer lack electricity exchanges. They lack the final commercial and regulatory links that would allow those exchanges to operate as part of one European market. The region’s physical grid already carries European electricity. Its trading architecture continues to price that grid as a collection of national systems.
