South-East Europe’s electricity markets now operate under formally liberalised and largely EU-aligned frameworks, yet their real-world behaviour continues to reflect structural fragilities that distinguish the region from deeper and more liquid European markets. Limited system size, persistent import dependence, thin trader participation and constrained interconnections combine to produce outcomes that are legally compliant but economically distortive. Over the past several years, and with growing visibility since 2024–2025, these weaknesses have repeatedly materialised through cross-border capacity pricing, especially in daily auctions, transferring significant value from consumers and industrial users toward a narrow set of market participants.
The case surrounding electricity imports into Kosovo, where the Kosovo Transmission System and Market Operator flagged anomalous outcomes in cross-border capacity auctions involving Elektroprivreda Srbije and the trader Noa Energy Trade, brought this issue into the public domain. However, that episode did not represent a deviation from regional norms. Rather, it exposed a pattern that has appeared across South-East Europe whenever structural import needs collide with daily auction mechanics and concentrated participation.
Across the region, electricity systems such as Kosovo, Montenegro and North Macedonia regularly depend on imports in a significant share of hours, not because of opportunistic arbitrage but because domestic generation cannot reliably cover demand. In these systems, imports are not discretionary. They are operationally essential. This reality fundamentally shapes price formation. When electricity must be imported regardless of price, the cost of accessing cross-border capacity becomes a lever through which scarcity rents can be extracted, even in the absence of explicit collusion or rule-breaking.
The Kosovo case illustrated this dynamic with unusual clarity. During much of 2025, daily cross-border capacity auctions into Kosovo were repeatedly cleared by only two participants. In such conditions, the auction ceases to function as a competitive discovery mechanism and instead reflects the urgency of the marginal buyer. Historical data cited by KOSTT showed that, on certain days, the transmission cost component of imported electricity reached levels as high as €800 per megawatt-hour, a magnitude that cannot be explained by generation scarcity alone. These outcomes were not the result of a single extraordinary event but of repeated structural conditions: limited bidder depth, daily urgency and the absence of alternative physical routes.
Comparable dynamics have appeared elsewhere in South-East Europe, even if they have attracted less public attention. In Montenegro, intraday and balancing markets during 2022 and 2023 repeatedly displayed price outcomes well above neighbouring benchmarks during periods of hydrological stress or grid constraints. Montenegro’s small system size and limited domestic flexibility meant that even modest constraints on interconnections transformed a thin intraday market into a price-setting environment dominated by one or two counterparties. Prices cleared at levels that bore little relationship to marginal production costs in the wider region, yet remained formally compliant with market rules.
Serbia and Romania experienced parallel phenomena in their balancing markets during 2023 and 2024. In both systems, balancing prices spiked sharply during stress events, not because of absolute shortages of generation capacity, but because a small number of units or traders repeatedly set the marginal price. In Serbia, where coal and lignite units remain structurally central, balancing prices at times reflected constraint rents rather than true marginal costs. Romania saw similar effects when limited participation and operational constraints converged. While these were not cross-border capacity auctions in the strict sense, the economic mechanism was the same: thin liquidity at short time horizons allowed a narrow set of actors to determine prices for the entire system.
Bulgaria offers a further instructive example. Between 2021 and 2023, market monitoring exercises highlighted how long-term bilateral contracting and concentration of generation ownership suppressed liquidity in the day-ahead and intraday markets. Although no auction abuse was formally established, the outcome was persistent volatility and price spreads that exceeded what fundamentals alone would justify. The Bulgarian case demonstrates that even without explicit auction mechanisms, structural dominance can yield economic effects similar to those observed in cross-border capacity pricing in smaller systems.
What unites these cases is not illegality but structural vulnerability. South-East Europe’s electricity markets are formally liberalised but functionally thin. In such an environment, the time horizon of trading becomes decisive. Annual and monthly capacity auctions, while not immune to concentration, allow participants to hedge, diversify and absorb risk over time. Daily auctions do not. They compress all uncertainty, urgency and physical constraints into a single clearing event. When imports are operationally necessary, daily demand for capacity becomes highly inelastic. The buyer must secure access today or face imbalance, curtailment or system risk.
This is why daily auctions are structurally the weakest point in the system. Liquidity collapses at short horizons. A border that may have a dozen registered participants at the annual level often sees only two or three active bidders in daily auctions, and sometimes only two. At that point, the clearing price is no longer a competitive outcome but a reflection of how much the marginal buyer is willing, or forced, to pay to keep the system balanced.
Operational realities amplify this effect. Transmission outages, maintenance works, N-1 security margins and internal grid bottlenecks routinely reduce usable capacity with little notice. When such constraints emerge close to real time, daily auctions price scarcity immediately, leaving no scope for arbitrage or alternative sourcing. Capacity acquired cheaply on longer horizons can then be reoffered into daily windows where urgency inflates its value. This sequencing behaviour may comply with formal rules, yet its economic effect is indistinguishable from scarcity rent extraction.
The magnitude of value transferred through these mechanisms can be modelled with conservative assumptions. If a structurally import-dependent border effectively prices up 150 megawatts of import capacity across the year, that capacity corresponds to approximately 1.31 terawatt-hours of electricity. Even modest deviations from competitive pricing matter at this scale. An excess congestion price of €5 per megawatt-hour applied to 0.8 terawatt-hours results in an annual transfer of roughly €4 million. This level is often absorbed quietly within system costs.
More commonly in South-East Europe, medium-stress conditions prevail. An excess price of €25 per megawatt-hour applied to 1.2 terawatt-hours produces an annual transfer of around €30 million on a single border. During prolonged stress periods, excess pricing of €80 per megawatt-hour on similar volumes implies transfers approaching €96 million. These are not abstract figures; they represent real cash flows embedded in tariffs, supplier margins and procurement costs.
Short-lived extreme events, which tend to dominate public perception, can be even more damaging. If 200 megawatts of capacity clear at an excess of €300 per megawatt-hour for just ten days, the resulting transfer exceeds €14 million in that brief window alone. Such episodes often shape annual cost outcomes and drive risk premiums long after the event has passed.
For industrial consumers, these dynamics have tangible consequences. Wholesale electricity prices incorporate congestion risk as a permanent premium rather than a temporary anomaly. When base wholesale prices sit around €70 per megawatt-hour, an additional €6–10 per megawatt-hour linked to congestion and cross-border risk represents a 9–14 percent increase in the energy component of industrial tariffs. Suppliers respond by shortening contract tenors, widening margins and embedding explicit congestion adjustment clauses.
Balancing and profile costs rise in parallel. Industrial loads with variable consumption profiles are particularly exposed when cross-border flexibility tightens. In such conditions, balancing prices spike more easily, and suppliers add €2–5 per megawatt-hour risk layers to contracts to cover exposure they cannot hedge efficiently.
For energy-intensive industries, the competitiveness impact is direct. Processes consuming 80–200 kilowatt-hours per tonne, such as cement, metals and chemicals, see production costs increase by €0.8–€2.0 per tonne for every sustained €10 per megawatt-hour uplift in electricity prices. For large industrial users consuming 200–500 gigawatt-hours per year, even a €10 per megawatt-hour increase translates into €2–5 million of additional annual cost. Under medium-stress congestion conditions of €25 per megawatt-hour, the burden rises to €5–12.5 million per year, often exceeding the margin of entire production lines.
Beyond price, reliability risk compounds the damage. When borders bind and domestic flexibility is limited, system operators resort to emergency imports at any price, industrial demand response or outright curtailment. The economic cost of a single curtailment event, through lost production, equipment stress and contractual penalties, frequently exceeds the annual congestion rent itself. These costs rarely appear in market statistics, yet they shape investment decisions and long-term industrial location choices.
Regulatory responses across South-East Europe have so far struggled to keep pace with these realities. High prices alone do not constitute proof of manipulation under existing frameworks. Enforcement regimes require evidence of intent or rule-breaking, not merely outcomes that appear economically excessive. As a result, most cases conclude without sanctions, even when the economic harm is substantial. Structural fixes, rather than punitive action, are therefore the only durable solution.
The core issue is not whether markets are liberalised, but whether they are sufficiently deep and resilient. Without greater liquidity, broader participation, alternative physical routes and redesigned short-term capacity mechanisms, daily auctions will continue to concentrate market power in small systems. In such an environment, price formation reflects urgency rather than competition, and value continues to flow away from productive sectors toward congestion rents.
Cross-border electricity pricing distortions in South-East Europe are thus not anomalies but predictable outcomes of market design interacting with structural constraints. The recent cases in Kosovo, Montenegro, Serbia, Romania and Bulgaria demonstrate that legal compliance does not guarantee competitive outcomes. Until the region addresses the underlying fragility of its short-term markets, similar episodes will recur, quietly reshaping electricity costs, industrial competitiveness and investment prospects across South-East Europe.