CBAM’s first test in South-East Europe: flow reshaping, not a lasting price reset

CBAM’s rollout into European electricity markets in 2026 is being widely interpreted as a carbon-driven price shock. But the first months of implementation show a different, more operational effect: the mechanism has primarily reconfigured cross-border power flows across South-East Europe, while leaving the region’s broader price dynamics largely intact.

A split between EU-linked and non-EU systems

CBAM has created a dual-market structure within the region, sharply distinguishing EU-integrated markets such as Hungary and Romania from non-EU systems including Serbia, Bosnia and Herzegovina, and Montenegro. Electricity exported from these non-EU countries into the EU is now subject to an implicit carbon cost. In practice, that functions like an export fee linked to the exporting system’s generation mix.

Early 2026: price divergence driven by constrained exports

The most noticeable impact on price formation occurred at the start of 2026. During the first quarter, non-EU SEE markets saw significant price suppression, while EU markets cleared at a relative premium. The divergence was especially evident in January and February, when non-EU prices fell below levels justified by underlying supply-demand conditions—largely because export routes into the EU became economically constrained.

Two temporary factors intensified that early-year pressure. First, administrative procedures needed to certify the origin of electricity flows under CBAM were not fully operational at the beginning of the year. That added inefficiency and uncertainty for exporters, further discouraging shipments into the EU. Second, exceptionally strong hydrological conditions across the Western Balkans produced surplus electricity at precisely the time export pathways were restricted. The result was deeper oversupply in exporting systems and stronger downward price pressure.

Why absolute price effects proved limited

Even with those disruptions, CBAM’s influence on absolute price levels remained asymmetric. EU markets did register higher prices versus a no-CBAM scenario, but the increase was modest. The analysis points to a structural constraint: non-EU SEE countries are rarely sustained exporters of electricity. Export surpluses tend to be confined to periods of high hydro generation, which limits how much volume is exposed to CBAM over an annual basis—and therefore constrains its ability to drive broader European pricing.

Trading behaviour changes—and so does the map of flows

Where CBAM mattered most was in trading behaviour and physical flows. As export profitability into the EU declined, market participants redirected surplus power toward alternative destinations not subject to the mechanism. In early 2026, a significant portion of Western Balkan surplus was rerouted toward Ukraine and Moldova, often transiting through Hungary and Romania.

This shift effectively established a new eastward corridor for SEE electricity. Rather than simply constraining exports outright, CBAM reshaped where those exports go—partially neutralising its intended effect on EU-bound volumes while maintaining overall system balance. At the same time, it reduced reliance by Ukraine and Moldova on EU hubs such as HUPX and OPCOM, easing indirect pressure on those markets.

Generation response in non-EU markets: deferral rather than decarbonisation

Within non-EU systems themselves, CBAM also influenced generation decisions during Q1 2026. With domestic prices suppressed, operators of lignite-fired plants—particularly in Serbia and Bosnia—chose to reduce output rather than dispatch into a low-price environment. Estimates cited reductions of several hundred megawatts relative to previous years during peak hydrological conditions.

However, this should not be read as structural decarbonisation. The analysis indicates lignite generation was deferred rather than displaced: as hydrology normalised and prices recovered, stored fuel would be redeployed later in the year. On that basis, CBAM had not yet driven a sustained shift in SEE’s generation mix across non-EU markets.

The impact fades as conditions change

The timing matters for interpreting results. CBAM’s strongest effects were concentrated in Q1 2026 when high hydro output coincided with administrative inefficiencies and constrained export channels. As March progressed and hydrology moved back toward average levels—with fossil generation resuming—the price gap between EU and non-EU markets narrowed.

Looking ahead to summer months, CBAM is expected to have minimal impact because non-EU SEE countries are typically net importers then; electricity flows mainly from EU markets into the Western Balkans meaning CBAM is not triggered. Even during export periods later in the year, improved administrative processes and more established trading routes are expected to reduce early-year distortions.

Gas prices also reshape incentives

A further moderating factor has been Europe’s broader energy backdrop. Natural gas prices rose from March 2026 onward, lifting wholesale electricity prices across Europe and restoring profitability for lignite-fired generation in non-EU markets despite CBAM-related discounts. That reduced incentives to curtail output further weakening CBAM’s influence on generation decisions.

A short-term distortion layered on an unchanged system

Taken together, these dynamics suggest CBAM’s role in South-East European power markets is best understood as a short-term distortion mechanism rather than a fundamental reset of regional pricing or supply structure. It introduces friction at the EU–non-EU interface, alters trade geography by shifting volumes away from EU destinations while keeping overall balance intact, and temporarily suppresses prices where surpluses coincide with constraints.

For investors and market participants assessing longer-term implications, the key takeaway is that CBAM should not be treated as a primary driver of sustained price levels in SEE. Its effects appear episodic—peaking when surplus hydrology meets administrative bottlenecks and constrained export channels—and diminishing when regional flows revert toward typical import patterns or when broader commodity prices improve generator economics.