As EU climate policy tightens the link between emissions and electricity costs, traders are finding that carbon pricing effects do not stop at the EU border. In early 2026, market participants reported a rise in new trading firms entering Western Balkan electricity markets, positioning for price divergences tied to how carbon costs are reflected in EU wholesale power. The shift is increasingly visible in cross-border flows and bilateral trades, where differences in carbon exposure can translate into persistent trading opportunities.
For policymakers and compliance teams, the development underscores a broader Green Deal reality: carbon-related regulation is influencing sectors beyond those originally targeted by emissions rules. For industry, it raises practical questions about how carbon-intensity assumptions are built into trading models and how exporters manage competitiveness when implicit carbon costs follow electricity into EU markets.
From industrial leakage prevention to electricity market arbitrage
CBAM was introduced to address carbon leakage risks associated with trade in carbon-intensive goods, but its market impact is now being felt through electricity trading. Traders describe the mechanism as a factor that changes competitive conditions between EU power markets where the EU Emissions Trading System applies and neighboring systems where carbon costs are not yet reflected in the same way. The result has been a widening of price spreads that can be exploited when electricity moves across interconnected markets.
In this transitional phase of market adjustment, firms have been reported taking significant positions across regional exchanges and bilateral arrangements. Their goal is to capture distortions between EU carbon-priced electricity and neighboring systems without equivalent carbon pricing, while managing the timing and pricing of cross-border deliveries.
EU ETS embeds carbon costs into power prices
The central driver of the emerging arbitrage is the difference between electricity markets governed by the EU Emissions Trading System and those operating outside it. Under the EU ETS, electricity generators must purchase allowances for each tonne of carbon dioxide emitted, making the allowance price a direct cost input for fossil-fuel generation. Recent allowance trading has been roughly between €60 and €80 per tonne of CO₂, with volatility linked to macroeconomic conditions and policy expectations.
That allowance cost can translate into substantial per-megawatt-hour impacts depending on fuel type. Coal-fired generation emitting approximately 0.9–1.1 tonnes of CO₂ per MWh faces an estimated carbon cost burden of roughly €55–€80 per MWh, while gas-fired plants typically incur €20–€35 per MWh due to lower emissions intensity. These costs are then embedded into wholesale electricity prices across EU markets.
Western Balkans face structural price differentials
Most Western Balkan countries do not yet participate fully in the EU ETS, so their electricity prices often reflect fuel costs and operational expenses without an explicit carbon price component. This creates a structural price differential between EU electricity markets and neighboring systems that can be narrowed when CBAM-related adjustments apply to cross-border trade. In effect, CBAM acts as a mechanism attempting to close part of that gap when electricity crosses into the EU market.
Market participants say this reduces the cost advantage previously associated with coal-based exports from systems lacking priced emissions. At the same time, it introduces volatility for traders because expected CBAM-related cost effects must be incorporated into pricing models rather than treated as a stable input.
A coal-heavy generation mix increases sensitivity
The Western Balkans remain among Europe’s more carbon-intensive electricity regions, with coal—especially lignite—still dominating generation in several countries. Serbia’s system relies heavily on lignite-fired plants operated by Elektroprivreda Srbije, primarily at the Nikola Tesla A/B complex and the Kostolac plants. Coal accounts for roughly two-thirds of Serbia’s electricity generation, while Bosnia and Herzegovina and North Macedonia also depend heavily on lignite-based generation.
Historically, these plants benefited from relatively low-cost lignite fuel combined with environmental costs not priced through carbon markets. That combination supported competitive export pricing into EU markets during many periods. With CBAM-linked adjustments affecting imports into the EU from countries without comparable carbon pricing, exporters face reduced room for price advantage—particularly when their generation portfolio remains emissions-intensive.
Spreads widen as carbon intensity becomes a trading variable
Electricity trading depends on differences between interconnected markets: when prices diverge, traders can buy in lower-price zones and sell in higher-price zones. CBAM adds a new variable by making carbon intensity a determinant of electricity price competitiveness across borders. As traders incorporate expected CBAM costs into their models, Balkan prices may diverge more frequently from EU benchmark markets such as Hungary’s HUPX exchange or Italy’s IPEX.
These divergences can persist for extended periods rather than appearing only briefly around regulatory announcements. Observations from market activity suggest that Balkan prices have already begun to decouple from EU benchmarks at certain times as firms attempt to price in future impacts of CBAM-related cost differentials.
Complex portfolios combine physical trades with hedging
Trading strategies across European power markets have become increasingly complex as carbon pricing interacts with fuel prices, renewable generation patterns, and cross-border transmission constraints. In the Western Balkans, CBAM adds further complexity because traders must evaluate multiple variables simultaneously: carbon intensity of generation in each market, expected EU ETS carbon price trajectories, renewable variability, transmission congestion, and hydropower availability in Balkan systems.
By combining these inputs, firms can construct portfolios designed to capture arbitrage opportunities between markets. Some reported strategies involve physical electricity trading paired with financial hedging instruments linked to carbon allowances and electricity futures—reflecting an effort to manage both commodity exposure and emissions-linked risk factors.
Financial investors deepen involvement
The reported surge in trading activity has drawn not only traditional energy traders but also financial investors seeking exposure through derivatives-driven approaches. Modern electricity trading companies often operate at the intersection of commodity and financial markets, using instruments such as electricity futures and options alongside carbon allowances to hedge risks and optimize portfolios.
Because CBAM integrates carbon costs into cross-border electricity trade, firms able to model carbon price trajectories gain an operational advantage in managing correlations between power prices and emissions-linked inputs. Some newly established companies entering Western Balkan markets appear to be positioning specifically for this type of cross-market arbitrage by combining electricity analytics with carbon market analytics.
Implications for decarbonisation incentives beyond industry
While increased trading activity may be the immediate visible effect of CBAM-related dynamics, longer-term implications for regional power markets could be more significant. The mechanism effectively exports elements of the EU carbon price into neighboring electricity markets through trade adjustments tied to cross-border flows. As a result, countries exporting electricity to the EU may face stronger incentives to reduce the carbon intensity of their generation portfolios.
This shifts competitiveness considerations toward low-emission supply options within export-oriented strategies. Renewable energy becomes more valuable not only for domestic supply but also for maintaining export competitiveness; wind and solar generation have negligible direct emissions and therefore would not face CBAM-related carbon adjustments in the same way as fossil-based generation. Over time, this could accelerate renewable deployment across Southeast Europe as trading economics increasingly reinforce decarbonisation outcomes that align with broader European Green Deal objectives affecting sectors such as cement, steel, aluminium, fertilisers, electricity and hydrogen through their respective emissions profiles under evolving compliance frameworks.
Synthesis: With EU ETS costs embedded into power pricing at allowance levels around €60–€80 per tonne CO₂—and coal emissions translating into roughly €55–€80 per MWh—CBAM-linked adjustments are narrowing historical export advantages from lignite-heavy systems while increasing volatility that traders can monetize through spreads between regional prices and EU benchmarks like HUPX and IPEX.