Carbon pricing and CBAM reshape power trading risk across South-East Europe

South-East Europe’s electricity markets are moving into a structurally different phase, where carbon pricing, cross-border rules and transmission constraints are no longer separate influences. Instead, they are combining to shape value, volatility and risk—forcing utilities, traders and industrial buyers to rethink how they hedge power exposure.

ETS sets the baseline; CBAM decides when it reaches non-EU systems

The EU Emissions Trading System (ETS) remains the foundational pillar of European electricity pricing. By assigning a monetary value to CO₂ emissions, it directly affects the marginal cost of thermal generation—especially gas and coal. In markets such as Hungary, Romania and Bulgaria, wholesale prices are effectively anchored to CO₂-inclusive production costs. Even when renewables are abundant, forward curves still reflect expectations around emissions pricing.

Non-EU systems—including Serbia, Bosnia and Herzegovina and Montenegro—operate outside the ETS framework. Their generation mix is dominated by lignite and hydro, meaning there is no direct carbon cost embedded in marginal production in the same way as in ETS-linked markets. Under normal conditions, this can look like a structural advantage through lower marginal costs and more competitive pricing.

That advantage has become conditional because of CBAM. When electricity flows from non-EU systems into the EU, CBAM transmits a border-adjusted carbon-equivalent cost that mirrors ETS exposure. The mechanism does not formally integrate non-EU markets into ETS, but it extends ETS economics beyond EU borders—making carbon costs relevant for cross-border trading decisions.

Early 2026 shows how exports can trigger friction—and price splits

The interaction between ETS-linked pricing and CBAM became especially visible in early 2026. Strong hydrology across South-East Europe produced a surplus of low-cost electricity in the first quarter and pushed non-EU systems toward export mode.

In theory, that should have supported robust cross-border flows into EU markets. In practice, CBAM introduced friction: exporting into the EU required absorbing a carbon-equivalent cost that eroded margins. The result was a persistent discount between SEE market prices and EU benchmarks. In some cases, the discount reached 40–60 €/MWh relative to Hungarian prices—reflecting both CBAM costs and limited export competitiveness.

This exposed an asymmetry in how carbon costs enter prices. EU markets incorporate ETS costs continuously, while non-EU markets face them only conditionally when exports trigger CBAM adjustments. When exports are constrained or redirected, SEE prices can decouple sharply from EU levels—creating sudden revenue compression risk for producers.

Traders respond by changing physical routing; hedging becomes partly physical

Market participants adapted quickly rather than simply absorbing CBAM-related costs. Traders reconfigured flows by redirecting electricity toward Ukraine and Moldova—markets not subject to the mechanism. These flows often transited EU infrastructure but avoided carbon adjustments by keeping non-EU destinations.

The episode underscored a key shift: hedging is no longer purely financial. The ability to reroute electricity can function as risk management by mitigating exposure to regulatory costs without relying solely on derivatives.

Carbon hedging extends regionally through EUA tracking—even for non-EU players

Despite its visible role in trade frictions, CBAM sits on top of the deeper driver: ETS pricing itself. For EU-based traders and utilities, managing carbon exposure remains central through standard practice—aligning forward power sales with purchases of EUA (European Union Allowance) so that emissions costs are locked alongside expected generation revenues.

In the SEE context described here, that logic extends beyond formal ETS participation. Even non-EU participants must track EUA prices closely because their export competitiveness depends on how their generation costs compare with ETS-adjusted EU prices. Through this channel, CBAM effectively turns EUA prices into a reference cost for cross-border trading across the region.

The complexity is heightened by CBAM’s conditional nature: unlike ETS, which applies continuously, CBAM is triggered only by specific trade flows. Because there is no liquid forward market for CBAM itself, participants must build synthetic hedges rather than hedge directly.

Spread trading and network constraints become part of the hedge design

A widely used method involves cross-border spread trading between hubs such as HUPX (Hungary), SEEPEX (Serbia) and OPCOM (Romania). Positioning against these spreads allows traders to capture combined effects from carbon pricing pressures, transmission constraints and regulatory adjustments.

A widening spread between Hungarian and Serbian markets may reflect multiple drivers at once—including CBAM pressure, reduced export capacity or rising ETS costs embedded in EU pricing—so hedging that spread becomes a proxy for managing all three factors simultaneously.

Transmission constraints add further complexity. As highlighted by regional behavior in 2026, electricity prices increasingly reflect flow-based market coupling and grid limitations rather than pure supply-demand fundamentals. A reduction in available transmission capacity can move prices more than an equivalent change in generation availability.

This shifts hedging attention from commodities alone toward physical infrastructure risk. Monitoring grid parameters such as Remaining Available Margin (RAM), cross-border capacities and operator interventions becomes essential—turning network risk management into a core part of trading strategy.

Industrial buyers face indirect carbon exposure through procurement choices

For industrial consumers—particularly those linked to EU value chains—the implications extend beyond where power is sourced. Electricity procurement strategies now need to account for both direct and indirect carbon exposure: even if nominal power prices look lower when sourcing from non-EU systems, CBAM can reintroduce carbon costs through the value chain and affect export competitiveness.

This has contributed to “shadow ETS” hedging strategies in which companies align energy procurement with financial positions tied to EU price benchmarks—not only to secure competitive electricity but also to stabilize embedded carbon cost assumptions tied to production outcomes.

The next phase: more consistent carbon transmission—and fewer hours driving volatility

Looking ahead, the distinction between ETS-linked and non-ETS markets in South-East Europe is likely to narrow further as CBAM implementation becomes more robust and market coupling deepens. At the same time, rapid expansion of renewable generation and battery storage is reshaping when price volatility concentrates—shifting volatility toward fewer critical hours rather than spreading it evenly over time.

In this evolving setup described here, ETS remains the baseline price anchor; CBAM acts as a selective adjustment mechanism; and transmission constraints determine how value moves across borders. The emerging market structure therefore requires integrated hedging approaches that combine CO₂-market awareness with power spread positioning and physical flow optimization—because managing risk now depends on both regulatory economics and grid physics.