Electricity markets in South-East Europe, while officially liberalised and aligned with EU standards, are increasingly revealing structural weaknesses that diverge from more stable European counterparts. Factors such as limited system capacity, heavy reliance on imports, minimal trader involvement, and inadequate interconnections have resulted in economically distorted outcomes that, while legally compliant, disadvantage consumers and industrial users. The visibility of these issues has grown since 2024-2025, particularly through the mechanics of cross-border capacity pricing.
The situation in Kosovo exemplifies these dynamics. The Kosovo Transmission System and Market Operator reported irregularities in cross-border capacity auctions involving Elektroprivreda Srbije and Noa Energy Trade. This case highlighted a recurring pattern across the region where essential import needs clash with daily auction processes dominated by a few participants.
Countries like Kosovo, Montenegro, and North Macedonia frequently depend on imports to meet demand due to unreliable domestic generation. In these scenarios, imports are not optional; they are critical for operational stability. This dependency influences price formation significantly. When imports are necessary regardless of cost, the access fees for cross-border capacity can be manipulated to extract scarcity rents without any overt collusion or rule violations.
The Kosovo scenario was particularly illustrative during 2025 when daily cross-border capacity auctions were often settled by only two bidders. Under such circumstances, auctions fail to serve their intended purpose of competitive price discovery and instead reflect the urgency of buyers needing immediate supply. Data from KOSTT indicated that transmission costs for imported electricity reached as high as €800 per megawatt-hour on certain days—an anomaly not solely attributable to generation shortages but rather indicative of persistent structural issues.
Similar pricing phenomena have been noted in Montenegro’s intraday and balancing markets throughout 2022 and 2023. Prices surged above regional benchmarks during periods of hydrological stress or grid constraints due to the small size of Montenegro’s system and limited flexibility in domestic generation. This led to a market dominated by one or two players setting prices disconnected from broader production costs while still adhering to market regulations.
Serbia and Romania experienced analogous situations in their balancing markets during 2023 and 2024. In both countries, spikes in balancing prices were observed not due to severe shortages but because a few traders consistently influenced the marginal price. In Serbia, coal and lignite units played a crucial role in this dynamic, while Romania faced similar challenges from limited market participation and operational constraints.
Bulgaria provides another pertinent example where long-term bilateral contracts and concentrated generation ownership stifled liquidity within day-ahead and intraday markets from 2021 to 2023. Although no formal auction manipulation was identified, persistent volatility led to price spreads that could not be justified by market fundamentals alone—demonstrating how structural dominance can yield economic outcomes akin to those seen in smaller systems’ cross-border pricing.
These cases reveal a common thread: structural vulnerability rather than illegality defines South-East Europe’s electricity markets. Despite being formally liberalised, these markets lack depth. The trading horizon is critical; while annual auctions allow participants to manage risks over time, daily auctions compress uncertainty into single events where buyers must secure capacity immediately or face potential operational risks.
The vulnerability of daily auctions is underscored by liquidity issues at short timeframes. A border may have numerous registered participants annually but often sees only two or three active bidders during daily auctions—shifting the clearing price away from competitive outcomes toward what the marginal buyer can afford under pressure.
Operational constraints further exacerbate this situation. Routine transmission outages or maintenance can swiftly reduce available capacity without prior notice, forcing immediate pricing responses that leave no room for alternative sourcing strategies. Consequently, capacity acquired cheaply over longer terms may be resold at inflated rates during urgent daily windows—a practice compliant with regulations yet economically indistinguishable from rent-seeking behavior.
The financial implications of these practices can be substantial when viewed through conservative modeling assumptions. For instance, if a border effectively prices 150 megawatts of import capacity annually—equating to approximately 1.31 terawatt-hours—modest deviations from competitive pricing at this scale become significant. An excess congestion price of €5 per megawatt-hour applied to 0.8 terawatt-hours translates into an annual transfer close to €4 million absorbed within system costs.
Under more typical medium-stress conditions prevalent in South-East Europe, an excess price of €25 per megawatt-hour applied over 1.2 terawatt-hours could generate an annual transfer around €30 million on a single border; during extended stress periods with excess pricing reaching €80 per megawatt-hour on similar volumes could lead to transfers nearing €96 million—figures that represent real economic impacts embedded within tariffs and supplier margins.
For industrial consumers facing these dynamics, the consequences are tangible as wholesale electricity prices now include congestion risk as a permanent premium rather than an occasional fluctuation. With base wholesale prices around €70 per megawatt-hour, an additional €6-10 per megawatt-hour due to congestion represents a significant increase—9-14 percent—in energy costs for industrial tariffs.
The rise in balancing costs compounds these challenges further; industries with variable consumption profiles face higher exposure when cross-border flexibility diminishes leading suppliers to incorporate additional risk layers into contracts ranging from €2-5 per megawatt-hour.
The competitiveness impact is stark for energy-intensive sectors such as cement or metals manufacturing where production costs can escalate by €0.8-€2.0 per tonne for sustained increases of €10 per megawatt-hour in electricity prices—resulting in additional annual expenses for large users ranging from €2-5 million even under medium-stress conditions where congestion costs rise further still.
Reliability risks also intensify financial strain; constrained borders force operators into emergency imports at any cost or resorting to demand response measures that can incur significant economic losses exceeding annual congestion rents due to production losses or contractual penalties—costs that often go unreported yet heavily influence investment decisions across industries.
Regulatory frameworks throughout South-East Europe have struggled to adapt adequately to these realities; high prices alone do not equate manipulation under existing rules which require demonstrable intent or violations rather than merely excessive outcomes leading many cases unresolved despite evident economic harm present within the system.
Structural solutions rather than punitive measures appear necessary for lasting change.
The fundamental challenge lies not merely within market liberalisation but ensuring sufficient depth and resilience exists within these systems moving forward; without enhanced liquidity options wider participation alternative routes along with redesigned short-term mechanisms daily auctions will likely continue reinforcing concentrated power dynamics inhibiting competitive pricing structures across smaller systems.
In this environment value tends towards scarcity rents rather than productive sector benefits highlighting urgent needs for reform addressing underlying fragility affecting short-term market operations across South-East Europe’s energy landscape.
