From January 2026, electricity exported into the EU carries a carbon cost. For a region that generates from lignite and sells across that border, this changes the economics of every generation asset.

The EU's Carbon Border Adjustment Mechanism entered its definitive phase on 1 January 2026. Importers of covered goods must now surrender certificates against the embedded emissions of what they bring into the Union.

Electricity is one of the covered goods. This is the detail that matters here, and it is frequently overlooked in discussions that focus on steel, cement and aluminium.

The arithmetic

Lignite-fired generation emits roughly one tonne of CO₂ per megawatt-hour. The precise figure varies with plant efficiency and fuel quality, but for the older units still operating across the Western Balkans it sits close to that mark and often above it.

CBAM certificates are priced against the EU Emissions Trading System. At recent ETS levels, that places a carbon cost of tens of euros on each megawatt-hour of lignite electricity crossing into the EU — a cost measured against wholesale electricity prices in the region of 100 EUR/MWh.

The exposure is not marginal. On the most carbon-intensive generation, the carbon charge approaches the value of the electricity itself.

Renewable generation carries none of it.

Why the Balkans are exposed

The Western Balkans are electricity exporters to the EU, and the generation fleet behind those exports is coal-heavy. Kosovo, Serbia and Bosnia and Herzegovina remain substantially lignite-dependent. North Macedonia and Montenegro carry significant coal capacity alongside hydro.

The region's transmission infrastructure was built to move power across these borders, and the commercial relationships follow the infrastructure. That is precisely the trade CBAM now prices.

The domestic dimension

The mechanism has a second effect that is less discussed.

As Energy Community contracting parties, Western Balkan countries face pressure to introduce domestic carbon pricing — both as an accession obligation and as the route to reducing CBAM exposure. Where a country prices carbon at home, that cost is deductible against the border charge.

The consequence is the same either way. A carbon cost lands on coal generation in this region: at the border if it is exported, at home if domestic pricing is introduced, or both. Coal generation gets more expensive on a schedule that is now set.

What this means for renewable projects

A structural cost advantage, not a subsidy. Renewable generation does not receive a payment for being clean. Its competitor receives a charge for not being. The gap widens as ETS prices rise and as domestic carbon pricing is introduced, and it widens without any policy support being extended to the renewable asset.

Export value. A renewable megawatt-hour can cross into the EU without a carbon liability attached. A lignite megawatt-hour cannot. Where the two compete for the same export contract, this is decisive.

Corporate offtake demand. European buyers subject to carbon accounting, supply chain reporting and CBAM obligations of their own increasingly need verifiably low-carbon supply. This is producing power purchase agreement demand in a market where PPA activity has until now been limited — and PPAs are the most bankable offtake structure available to a generation project.

Coal retirement acceleration. Every additional cost on coal brings forward the retirement of capacity the region currently depends on. Demand is rising. Supply is being withdrawn. Both curves move in the direction of higher prices for the generation that remains.

The investment conclusion

Renewable generation in this region is not competing against coal on levelised cost alone. It is competing against coal plus a carbon charge that is scheduled to rise, on a fleet that is scheduled to close.

Assets reaching commercial operation over the next several years will enter a market where that repricing has substantially played out. The models financing them were built before it did.