Cross-border electricity flows in Southeast Europe are entering a new operating reality where carbon-cost accounting is starting to outweigh traditional price-spread economics. For developers and grid planners, the shift matters because it changes how interconnectors are monetised, how liquidity forms on exchanges, and how future transmission and flexibility projects are underwritten.
In the past decade, traders relied on persistent but tradable spreads between Western Balkans generation systems and neighbouring EU markets. Coal-heavy systems in Serbia, Bosnia and Herzegovina, and Montenegro often produced power at lower marginal cost than gas-driven systems in Italy, Hungary, or Greece. Interconnectors were used as conduits for arbitrage, making cross-border trading a central driver of price formation and liquidity rather than domestic fundamentals alone.
Carbon costs rewrite import economics for coal-heavy supply
The Carbon Border Adjustment Mechanism (CBAM) in its definitive phase from the start of 2026 has altered the economics of cross-border electricity trade in a way that challenges arbitrage-based strategies. The clearest evidence is visible in Q1 2026 market behaviour, where carbon-cost assumptions tied to the EU Emissions Trading System directly affect effective import pricing.
In Q1 2026, the relevant carbon price averaged €75.36 per tonne of CO₂. That translated into effective import costs of approximately €70–86/MWh for electricity originating from coal-dominated systems in the Western Balkans. Instead of merely compressing margins, the additional cost layer often eliminates them entirely.
Widening spreads no longer translate into higher flows
Under a classic arbitrage setup, widening price spreads between two markets would typically stimulate increased cross-border trade until the spread narrows. In Q1 2026, the relationship broke down: price differentials between Western Balkan markets and neighbouring EU zones widened to levels rarely seen in recent years—often exceeding €30/MWh and reaching over €40/MWh in some corridors—while cross-border flows declined.
The Montenegro–Italy corridor illustrates how carbon-cost absorption can neutralise apparent opportunities. Southern Italy’s day-ahead prices averaged above €130/MWh while Montenegro’s hovered closer to €85/MWh. A spread of roughly €43/MWh would previously have supported exports via the submarine interconnector, but both scheduled and physical flows declined.
The explanation was not capacity or demand constraints but CBAM-related cost absorption. With Montenegro’s default emission factor implying a carbon cost of approximately €73–74/MWh, the arbitrage opportunity effectively disappeared even when spot spreads looked attractive on paper.
Regulatory uncertainty adds risk to cross-border trading models
The same pattern extends beyond one corridor. At the Serbia–Hungary border, Q1 2026 spreads were approximately €31/MWh, yet export flows did not increase as expected. CBAM costs combined with regulatory uncertainty around compliance and reporting reduced the economic attractiveness of cross-border trades.
For trading desks that influence operational scheduling and commercial contracting, this changes more than spot economics. Arbitrage depends on capturing predictable spreads; when policy-driven cost adjustments vary with carbon prices, risk profiles shift materially. Decision-making must incorporate regulatory risk, carbon price volatility, and CBAM implementation specifics rather than relying primarily on fuel costs, demand patterns, or weather-driven generation variability.
Interconnector capacity auctions signal reduced forward value
This complexity has fed into more cautious behaviour in capacity procurement. Evidence from cross-border capacity auctions indicates participants reduced exposure to forward commitments even before CBAM entered into force. Yearly auction prices for interconnection capacity declined by as much as 24–67% on key corridors.
Daily allocation rates remained high—often above 95%—showing that capacity continues to be booked. However, the value attributed to that capacity diminished, implying that interconnectors are still used but increasingly for purposes other than straightforward spread-capture arbitrage.
Exchange volumes diverge as generation-led trading gains ground
The market shift is also visible in regional power exchange performance. Total traded volumes across the Western Balkans increased modestly from 2.16 TWh to 2.39 TWh year-on-year, but exchange-level divergence points to a structural change in liquidity drivers. Markets with strong domestic generation—particularly hydro-rich systems—saw substantial growth.
Albania’s ALPEX saw volumes roughly double, while Montenegro’s MEPX recorded a 49% increase. By contrast, Serbia’s SEEPEX—which has historically functioned as a hub for transit-based trading—saw volumes decline by 11%. The divergence aligns with a broader move away from arbitrage-driven liquidity toward generation-driven activity.
Transit routes lose appeal as CBAM treatment becomes a planning constraint
Transit trading is particularly affected because it depends on routing power through non-EU countries to exploit intermediate price differentials across multiple borders. Prior to 2026, flows could move from Hungary through Serbia into Bulgaria while monetising along-the-way spreads. CBAM disrupts this model by introducing uncertainty regarding treatment of transit flows.
If electricity passing through a non-EU country is subject to carbon costs—even when it originates and is consumed within the EU—the economics of such routes become less attractive. Traders have begun avoiding transit paths involving the Western Balkans and favouring alternatives that remain entirely within the EU or involve low-emission systems.
Implications for transmission planning and flexibility investment readiness
This rerouting behaviour has broader consequences for how electricity trade is geographically shaped. Instead of a network optimised purely for economic efficiency, flows increasingly reflect regulatory considerations intended to minimise exposure to CBAM costs. That can introduce inefficiencies as electricity may travel longer distances or through less optimal corridors to avoid carbon charges.
Over time, these patterns could alter interconnector utilisation rates and influence which transmission projects appear bankable under congestion-rent or merchant revenue models. The erosion of arbitrage also affects interconnectors’ role as financial assets: when spread-capture opportunities diminish, willingness to pay for capacity rights declines. Forward auction price declines observed at the end of 2025 suggest investors and traders had already begun reassessing interconnector revenue potential under CBAM conditions.
System balancing shifts toward domestic generation under tighter economic constraints
From an operational system perspective, reduced arbitrage-based trading constrains cross-border contributions to balancing supply and demand across regions. Historically these flows helped smooth price volatility and enhance security of supply; when constrained by economic factors rather than physical limitations, system flexibility declines. Markets become more reliant on domestic generation that may not always be the most efficient or cost-effective option.
This can raise overall system costs and reduce resilience to shocks over time. For utilities planning grid modernisation and balancing resources—including dispatchable flexibility needed alongside wind and solar—commercial changes in cross-border liquidity can translate into greater emphasis on domestic balancing capability.
BESS relevance grows as carbon-linked volatility tightens operational assumptions
The interaction between CBAM and EU ETS adds another layer of uncertainty because CBAM costs track carbon prices directly. In Q1 2026 EU ETS prices declined sharply after an initial increase amid political discussions around potential reforms. That volatility feeds directly into electricity import costs from non-EU countries fluctuating with carbon pricing outcomes.
For operators preparing schedules across variable renewables output profiles, this effectively integrates power price risk with carbon price risk into commercial decision-making. In practice this increases the value of controllable flexibility resources such as battery energy storage systems (BESS), which can help manage short-term imbalances when external arbitrage channels weaken due to policy-linked cost swings.
Coal-dependent systems face transitional exclusion; hydro-rich supply gains conditional advantage
The implications for coal-dependent systems in the Western Balkans are particularly stark because their competitive position relied on cost advantages that CBAM erodes by attaching carbon costs reflecting higher emission intensity. While aligned with decarbonisation objectives, it creates a transitional challenge since investments in cleaner generation or emissions reduction technologies take time while CBAM impacts arrive immediately. In the interim these systems may be excluded from cross-border trade with limited opportunities to monetise existing generation assets.
Low-carbon systems gain relative advantage where default emission factors are effectively near zero. Albania can export electricity into the EU without incurring CBAM costs due to an effectively zero default emission factor, reinforcing incentives for traders to source from hydro-dominated supply. However this advantage depends on hydrological conditions that can vary significantly year-to-year, making competitive positioning uncertain for planning horizons relevant to EPC preparation and procurement cycles.
What changes next: clearer transit rules and aligned carbon pricing could reshape project cases
Looking ahead, adaptation by market participants will depend on how policymakers refine CBAM implementation details affecting transit treatment, default emission factors, and recognition mechanisms for actual generation characteristics rather than default assumptions alone. Greater clarity could influence whether cross-border trades regain some economic viability or remain structurally constrained by policy-linked cost layers.
A parallel development is the potential creation of regional carbon pricing mechanisms aligned with EU ETS principles to reduce asymmetry between EU and non-EU markets. If achieved, it could restore some conditions necessary for efficient arbitrage—though near-term planning will likely continue under higher regulatory sensitivity than before 2026.
Broader industry takeaway: trading architecture shifts feed into grid modernization priorities
The evidence from Q1 2026 indicates that straightforward cross-border arbitrage is coming to an end in Southeast Europe’s traditional form. Carbon pricing integration with trade economics has produced a disconnect between widening spreads and declining physical flows while reducing forward value signals from capacity auctions and weakening transit-based liquidity hubs like SEEPEX.
For developers pursuing wind and solar buildouts alongside grid upgrades—and for contractors preparing EPC packages for substations, interconnection works, or storage integration—the message is practical: commercial assumptions about congestion rents and external balancing support are changing faster than physical constraints alone would suggest. The resulting focus is likely to tilt toward domestic flexibility readiness, including BESS deployment planning supported by technical studies that account for policy-driven volatility rather than relying solely on historical spread dynamics.