In 2026, the Carbon Border Adjustment Mechanism has started to influence electricity trading across South-East Europe, but its effects have been less about long-term decarbonization and more about how marginal prices and cross-border routes behave in specific conditions. Market participants in Serbia, Bosnia and Herzegovina, Montenegro, North Macedonia, and Albania have seen CBAM act as a short-term friction point that changes dispatch incentives and alters where power ends up. Rather than creating a steady carbon price signal, CBAM has shown up as a rapidly arbitraged constraint that appears when export economics deteriorate.
CBAM applies a carbon-adjusted cost on electricity exports from non-EU countries into the European Union, with exposure defined by the entry point into the EU rather than the physical origin of the electricity. That design has introduced a pricing wedge between EU and non-EU markets, disrupting the traditional arbitrage logic that had supported cross-border flows in the region. The result is a mechanism that can shift market outcomes quickly when trading strategies can adapt faster than administrative processes.
Hydrology and administrative readiness drove the first-quarter divergence
The most visible disruption occurred during the first quarter of 2026 as unusually strong hydrological conditions across South-East Europe coincided with unseasonably warm weather. Low-cost hydro generation rose while demand stayed subdued, creating surplus conditions in non-EU systems that typically rely on exports during those periods. At the same time, CBAM administrative systems—especially those needed to verify carbon content and electricity origin—were not fully operational.
That combination produced a sharp split between non-EU and EU outcomes. Non-EU markets experienced significant price suppression, while EU markets saw marginally higher prices than they otherwise would have expected under similar fundamentals. In practice, persistent discounts emerged in markets such as Serbia and Bosnia, where electricity traded materially below Hungarian or Romanian benchmarks even when physical interconnection capacity remained available.
CBAM pressure was asymmetric for exporters versus EU-linked buyers
The burden of CBAM has been highly asymmetric across the region’s market structure. Non-EU systems that depend on exporting surplus faced direct competitiveness losses when CBAM-linked costs made EU-bound sales less attractive. EU markets were comparatively insulated because many are net importers or internally balanced, limiting how much CBAM-driven friction translated into tighter EU supply.
For developers and operators planning generation output around seasonal spreads, this matters because it changes what “export value” means during surplus hours. Instead of tightening supply in a way that would lift prices broadly, CBAM pushed down non-EU prices without a commensurate tightening of EU supply. The region therefore continued to behave like a price-taking periphery during constrained export windows.
Trading rerouted toward Ukraine and Moldova through EU infrastructure
Market responses emerged quickly once traders identified pathways to reduce CBAM exposure. Electricity flows were increasingly redirected toward Ukraine and Moldova—markets outside the CBAM regime—while still transiting through EU infrastructure such as Hungary and Romania. Carbon costs were avoided as long as the final destination remained outside the European Union.
This rerouting had two operational consequences for regional power flows. It helped SEE exporters recover part of their lost margin by finding alternative demand sinks, while also reducing reliance on EU power exchanges because Ukraine and Moldova sourced more directly from SEE rather than through hubs such as HUPX or OPCOM. In effect, CBAM reshaped not only pricing but also routing behavior across interconnected networks.
Thermal generation response: lignite output fell briefly then rebounded
Beyond trading spreads, CBAM-linked price depression fed into short-term thermal dispatch decisions, particularly lignite-fired generation in Serbia, Bosnia and Herzegovina, and Montenegro. During early 2026 price weakness, market prices fell below the marginal cost of lignite generation for some operators. That triggered a temporary reduction in coal output estimated at up to 500 MW during peak hydrological conditions.
However, the change did not represent structural decarbonization or fuel depletion. Lignite reserves were conserved with an expectation of redeployment once conditions improved; as hydrology normalized in March, coal generation recovered quickly with output only 200–300 MW below historical averages. The episode indicates that fuel switching impacts were transient and closely tied to short-run market distortions rather than long-run technology displacement.
Commodity prices limited CBAM’s longer influence
CBAM’s ability to suppress thermal profitability was further constrained by broader commodity dynamics. From March 2026 onward, rising natural gas prices lifted wholesale electricity prices across the region. That increase restored lignite plant profitability even under discounted SEE pricing levels, effectively neutralizing much of CBAM’s suppressive effect on thermal generation.
For investors assessing project execution readiness—whether for conventional plants supporting system adequacy or for new renewables intended to displace dispatchable capacity—the takeaway is that policy-driven distortions can be overridden by fuel-market movements. In this environment, revenue stacking assumptions for thermal assets may need scenario-based stress testing against both carbon-border effects and gas-price pass-through.
A regionalized trading pattern is emerging during constrained export hours
As exports to the EU became less attractive under CBAM-linked costs, trading behavior within South-East Europe shifted toward intra-regional transfers among non-EU countries. Early indications point to a regionalized SEE power market that can become partially decoupled from EU pricing dynamics during certain periods. This is consistent with a system where constraints bind episodically rather than continuously throughout the year.
The structural footprint remains limited because SEE countries are net exporters only in a minority of hours. Historical data cited for 2025 show exports exceeding 500 MW occurred in roughly 12% of total hours, underscoring how often surplus conditions—and therefore CBAM exposure—materialize. Consequently, CBAM affects marginal pricing periods rather than baseline system operation, distorting peak surplus outcomes instead of redefining overall equilibrium.
Outlook for 2026–2027: diminishing friction as frameworks mature
Looking ahead through 2026 into 2027, expectations are that CBAM influence will diminish further as administrative frameworks mature and traders integrate CBAM costs more fully into their strategies. Seasonal normalization of hydrology is also expected to reduce how frequently SEE enters export-heavy states that trigger carbon-adjusted exposure into the EU. Meanwhile, sustained export channels toward Ukraine and Moldova should continue to lower the frequency of CBAM-constrained scenarios.
Under these conditions, CBAM is likely to remain a situational constraint rather than a dominant pricing driver—shaping specific hours and flows without enforcing sustained decarbonization outcomes across the region’s operating profile. For grid modernization planners and renewable developers alike, this implies that market design interactions may affect short-term revenue signals more than long-term investment fundamentals.
Broader project implications for renewables, grids, EPC preparation
The 2026 experience highlights how cross-border policy mechanics can translate into real operational changes: price suppression during surplus hydro periods, rerouted transactions via alternative destinations outside CBAM scope, and temporary reductions in lignite output up to an estimated 500 MW before recovery within months. For wind and solar developers evaluating curtailment risk or merchant exposure windows tied to hydrology-driven spreads, these findings argue for tighter scenario modeling around episodic export constraints rather than assuming uniform annual impacts.
For transmission infrastructure owners and operators planning upgrades to interconnection capacity or congestion management tools, the observed rerouting underscores that physical capacity alone does not determine commercial outcomes; entry-point rules can redirect flows even when interconnectors are available. For EPC preparation teams supporting battery energy storage systems or grid-support projects intended to stabilize variability from renewables, the episode reinforces the need to align technical studies with market realities—especially how dispatch economics shift when commodity prices move alongside border adjustments.