CBAM’s early impact in Southeast Europe: renewables gain, but cross-border trade faces new friction

The first quarter of 2026 delivered an early, investor-relevant signal for Southeast Europe’s power sector: the Carbon Border Adjustment Mechanism is beginning to reshape how capital should be allocated across electricity markets. With CBAM entering its definitive phase, the region is no longer moving under a single, coherent investment logic. Instead, competitiveness is increasingly determined by carbon-adjusted economics—creating both decarbonisation tailwinds and fragmentation risks that can affect revenue stability, financing terms and grid planning.

Price spreads disrupted by carbon costs

At the core of the shift is the interaction between electricity pricing, carbon cost exposure and access to cross-border trade. In Q1 2026, Western Balkan markets recorded significantly lower electricity prices than EU benchmarks. Serbia averaged €94.7/MWh, Montenegro €85.8/MWh and North Macedonia €96.7/MWh, compared with EU benchmarks in the €120–130/MWh range.

Under conventional conditions, those spreads would have supported exports into higher-priced markets and—by extension—investment in generation capacity geared toward supplying EU demand. CBAM disrupts that mechanism by introducing carbon costs of €70–86/MWh on imports from coal-intensive systems. That effectively neutralises the price advantage for higher-carbon exporters and constrains access to higher-value markets.

What changes for investors: bankability and cash-flow predictability

For market participants, the implication is a change in revenue expectations. Projects that depend on cross-border exports as a key part of their business model now face more uncertain—and often less favourable—outlooks. For assets with high carbon intensity in particular, monetising capacity in EU-priced markets is no longer assured.

This matters directly for project bankability. Lenders and equity investors are likely to reassess how stable future cash flows will be when regulatory costs and carbon pricing dynamics can alter export economics.

Hydro-rich systems see an advantage; coal-heavy systems face pressure

The divergence becomes clearer when comparing low-carbon and high-carbon power systems. Hydro-dominated Albania benefits from a structural advantage under CBAM because its exports are not subject to carbon charges. In Q1 2026 this translated into increased export activity and improved market access, reinforcing the attractiveness of hydro and other renewable investments by allowing these systems to capture full value from price differentials with EU markets.

By contrast, coal-heavy systems face a tougher environment. Serbia, Bosnia and Herzegovina, and Montenegro rely significantly on thermal generation and therefore incur substantial CBAM costs that erode their competitiveness in cross-border trade. For existing plants this can reduce utilisation and revenue potential; for new investments it raises questions about long-term viability. The traditional approach of using low-cost coal generation to serve regional demand while exporting surplus power appears less sufficient in a carbon-constrained setting.

Renewables: stronger incentives, but less room for scale

CBAM can strengthen the case for renewables by penalising carbon-intensive generation and improving the relative position of low-emission technologies. Yet market fragmentation—and reduced cross-border trade—can undermine the scale and integration needed to support large renewable projects.

Wind and solar generation often require access to broader markets to help balance variability and optimise revenues. If trade becomes constrained, the effective market size for these projects shrinks, potentially limiting their economic viability even as decarbonisation incentives rise.

Grid integration becomes decisive

The ability to connect new renewable capacity to the grid—and transmit electricity across borders—is highlighted as a critical factor for turning investment into value. In Q1 2026, divergence between commercial schedules and physical flows pointed to challenges for transmission system operators managing increasingly complex flow patterns.

Crowding on transmission paths can create congestion risks; loop flows can complicate dispatch outcomes; and mismatches between scheduled versus actual flows underline the need for enhanced grid infrastructure and better coordination. Without improvements, integrating new renewable capacity may be constrained.

Contracts may need rethinking as carbon pricing adds complexity

The financial structure of renewable projects is also affected by CBAM-linked dynamics. Power purchase agreements that provide revenue certainty must now factor in how carbon pricing influences cross-border trade economics. Contracts assuming stable price convergence between markets may need re-evaluation if price spreads persist alongside regulatory costs.

That increases negotiation complexity and could lead to higher risk premiums—raising the cost of capital for new projects.

A risk of semi-autonomous markets

The broader concern is that differential treatment based on carbon intensity could introduce friction into Western Balkans integration with the EU internal energy market—where cross-border trade has been central to aligning prices and optimising resource allocation.

If those differences persist, the region could evolve toward semi-autonomous power systems with limited integration rather than a unified market structure. That would affect supply security and investment efficiency: integrated systems allow surplus generation in one area to meet demand elsewhere, reducing redundant capacity needs and lowering overall system costs; fragmented outcomes can push each system toward relying more heavily on its own resources—raising risks of overinvestment or underutilisation.

EU ETS volatility feeds into CBAM uncertainty

The interaction between CBAM and EU ETS adds another layer of uncertainty because carbon prices fluctuate over time. As those prices move, so does the cost of exporting electricity from non-EU systems into CBAM-impacted routes—affecting revenue projections for both existing assets and planned projects.

In Q1 2026 specifically, a decline in EU ETS prices introduced volatility into CBAM costs, underscoring how sensitive investment returns can be to carbon-market dynamics. Investors therefore need scenario-based modelling that incorporates potential carbon price outcomes when evaluating projects.

What could reduce divergence—and what remains uncertain

Looking ahead, how investment signals evolve will depend on responses from both policymakers and market participants. Greater alignment between EU carbon pricing mechanisms and Western Balkan approaches could reduce asymmetry driving divergence. Regulatory adjustments that improve emissions representation—such as plant-level reporting rather than reliance on default emission factors—could also mitigate distortions introduced by simplified assumptions.

At the same time, continued investment in grid infrastructure and market coupling initiatives could help preserve integration benefits even as regulatory costs change competitive conditions.

The bottom line for capital allocation

The first quarter of 2026 does not settle how CBAM will play out long term across Southeast Europe’s electricity markets—but it does indicate a clear direction: carbon intensity is becoming central to competitiveness; cross-border trade faces increased regulatory friction; and investment decisions must account for more variables than before than just resource fundamentals or local power prices.

For investors, opportunities appear strongest where projects can align with EU-adjusted economics—supporting stronger market access and more stable revenues—while assets unable to do so face growing pressure to adapt or risk marginalisation. The emerging evidence suggests CBAM will not deliver a single outcome; rather it is likely to produce a spectrum where some systems accelerate decarbonisation while others experience fragmentation pressures as they adjust at different speeds.