Southeast Europe has one of Europe’s most interconnected power systems, yet its electricity markets remain divided by national rules, capacity-allocation procedures, regulatory borders and uneven liquidity. Electricity regularly flows across Serbia, Montenegro, Bosnia and Herzegovina, Albania and North Macedonia on its way between EU member states, but Western Balkan markets still operate outside the full European architecture for day-ahead, intraday and balancing-market integration.
This mismatch is becoming increasingly difficult to justify as renewable generation expands. The region is already experiencing simultaneous periods of solar oversupply, hydropower shortages, thermal outages and sharp evening demand ramps. Physical interconnections 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 in the EU’s coupled market.
The Energy Community estimates that as much as 70% of electricity passing through the Western Balkans may represent flows between different EU countries. Serbia sits at the centre of this transit structure, with connections 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 connect 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 towards 15-minute trading intervals in the day-ahead and intraday markets. Intraday cross-border gate closure times have been reduced from 60 minutes to 30 minutes on many participating borders. At the same time, balancing integration through the MARI and PICASSO platforms is expanding, while flow-based capacity allocation is being prepared for larger European regions.
European balancing platforms generated more than €1.18 billion in surplus in 2025 through imbalance netting and more efficient reserve activation. The figure demonstrates that market integration is not simply a regulatory exercise. It allows spare flexibility in one system to become a tradable service for another, lowering balancing costs and reducing the volume of reserves that each TSO must procure domestically.
In the formal Southeast Europe Capacity Calculation Region, however, the 2026 assessment still focuses on Bulgaria, Romania and Greece. 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 established European regions.
Serbia has the region’s most developed electricity trading structure. SEEPEX, now part of the wider ADEX group alongside Slovenia’s BSP SouthPool and Hungary’s HUPX, operates day-ahead and intraday markets. Day-ahead trading volume in 2024 represented approximately 17.41% of Serbian electricity consumption, while intraday trading accounted for only around 0.34%.
That imbalance reveals the next major market-development challenge. A functioning intraday platform exists, but liquidity remains too low to provide a reliable adjustment market for a rapidly expanding wind and solar fleet. Generators can buy or sell electricity 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 therefore a necessary development. A zero-price floor concealed the economic signal created when renewable output and inflexible thermal generation exceeded demand and export capacity. Negative prices allow the market to value curtailment, charging demand, storage and flexible consumption. They also expose weaknesses in fixed-premium support schemes and PPAs designed around the assumption that wholesale electricity prices 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 demand, limited numbers of market participants 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 electricity market.
Regional prices already show strong correlation. This reflects interconnected generation fundamentals: Balkan hydrology, Bulgarian and Romanian nuclear availability, Greek gas-fired marginal generation, Serbian coal output, Hungarian imports and Italian demand all influence the same physical system. Correlation, however, is not the same as convergence. Explicit border auctions, uncoordinated capacity calculations and administrative barriers can preserve significant price spreads even when underlying supply conditions are similar.
Flow-based market coupling could fundamentally change how regional transmission capacity is used. 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, for example, can alter physical flows in Romania, Croatia or Bosnia and Herzegovina. Flow-based calculation uses a regional network model to allocate capacity according to actual system constraints, potentially increasing tradable capacity while maintaining operational security.
The transition would be technically and politically demanding. TSOs would need to exchange sufficiently detailed grid models, agree common contingencies and remedial actions, harmonise calculation methodologies and accept regional scrutiny of internal constraints. Regulators would need to approve compatible terms and conditions, while power exchanges and market participants would need operational procedures aligned with European algorithms and gate times.
The 70% minimum capacity requirement adds further 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 capacity available for regional electricity trading.
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 of deeper integration could be substantial. Serbia’s hydropower and future battery projects could sell balancing and flexibility services into a larger market. Montenegro could use its Italian interconnector more efficiently, particularly when hydrological conditions and Italian prices diverge. Albania could monetise reservoir flexibility beyond day-ahead exports. North Macedonia could reduce its exposure to expensive emergency imports, while Bosnia and Herzegovina could improve the utilisation of its hydro and thermal portfolio while preparing for the commercial impact of carbon pricing.
Battery economics are particularly sensitive to market integration. A BESS relying solely 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 materially improve annual gross revenue. A diversified revenue stack also reduces dependence on any single price spread or market mechanism.
Industrial consumers face a different form of exposure. Fragmented markets reduce their ability to hedge electricity costs across borders, while limited forward-market liquidity restricts 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 greater integration. The EU’s definitive carbon-border regime places increasing value on transparent electricity sourcing, verifiable emissions and credible market prices. Western Balkan electricity exports will increasingly compete on their carbon content rather than solely on marginal production costs. Coal-heavy systems can no longer rely indefinitely on an implicit carbon advantage when selling into neighbouring EU markets.
Market coupling would not eliminate 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 instead make those differences visible, tradable and more efficiently priced, 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 across the region. Market participants operating across several Western Balkan jurisdictions can face duplicated registrations, incompatible invoicing practices and higher working-capital requirements. These costs are particularly significant in markets where traded volumes remain relatively 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 markets without sufficiently liquid intraday trading would transfer too much forecasting risk directly from generators to TSOs.
Serbia is positioned to become the region’s liquidity anchor because it combines the largest Western Balkan power system, the deepest organised exchange, extensive interconnections and ownership links with EU exchanges through ADEX. That position is not automatic. Liquidity must expand beyond the current concentration in day-ahead trading, while market rules must support negative prices, aggregation, storage participation and shorter trading products.
The Western Balkans no longer lack electricity exchanges. What they lack are 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, however, continues to price that grid as a collection of national systems.
