January also revealed an emerging market segment that does not yet price directly into spot markets but will materially reshape trading economics from 2026 onward: CBAM-linked electricity emissions accounting. While January power prices were driven by flexibility and grid constraints, the pattern of cross-border flows exposed a future compliance and cost asymmetry that traders and industrial buyers are already positioning for.
From 2026, electricity imports into the EU will be subject to CBAM reporting and, over time, cost exposure based on the emissions intensity of the exporting system, unless verifiable low-carbon origin is demonstrated. This fundamentally changes the economics of SEE power flows, particularly for non-EU exporters supplying EU markets during high-price periods.
January’s flow patterns show why this matters. Bulgaria exported more than 400 GWh of electricity into Romania during the month, largely underpinned by nuclear and hydro generation. These flows are structurally low-emission and, if properly certified, will carry minimal CBAM exposure. In contrast, flows from non-EU Western Balkan systems into EU markets during peak hours may be emissions-weighted at system-average intensity, not at the marginal unit actually producing the power.
This distinction is critical. In January, Serbia and Bosnia and Herzegovina physically exported electricity into EU-linked systems at times, even when domestic marginal generation was coal or gas. Without granular emissions attribution or aligned Guarantees of Origin, these exports risk being classified under CBAM using default emissions factors, potentially exceeding 400–700 kg CO₂/MWh depending on methodology. At carbon prices implied by EU ETS levels, this could translate into a CBAM cost of €30–70/MWh layered on top of wholesale power prices.
Montenegro presents a paradox that January made visible. Physically, its system is overwhelmingly hydro-based. Economically, however, without deep integration into EU-recognised certification and emissions accounting frameworks, its exports risk being treated as carbon-intensive by default. January’s extreme price dispersion on MEPX did not reflect this risk, but forward contracting behaviour increasingly does.
For industrial buyers, the risk is asymmetric. Importing electricity during peak scarcity hours—when prices already exceed €200/MWh—may also mean importing embedded carbon costs that are not visible in the power price. This transforms what looks like a rational short-term procurement decision into a multi-year compliance liability. January showed that peak hours dominate cost; CBAM will ensure they also dominate emissions exposure.
For traders, CBAM introduces a new basis risk between physical power flows and financial outcomes. A profitable cross-border trade on a price spread can become loss-making once emissions attribution is applied. This is particularly acute for traders sourcing from mixed or fossil-heavy systems and selling into EU markets without certified low-carbon attributes. The risk is slow-moving but cumulative, exactly the kind that is easy to ignore until it becomes material.
Structurally, January confirms that EU-integrated nuclear and hydro systems gain a durable advantage. Bulgaria and Romania can export not only energy, but compliance certainty. Western Balkan systems risk paying a carbon premium even when physically exporting surplus power. This will reshape flow economics over the next two years, favouring long-term contracts with explicit emissions attribution and penalising spot-only trading strategies.
The market implication is clear. CBAM will not reduce volatility; it will reprice it. High-price hours will also be high-carbon-risk hours unless backed by certified low-carbon origin. January’s trading patterns already hint at this future: power markets clear on flexibility today, but the next layer of value and risk will be set by who can prove what their electrons actually represent.
By virtu.energy
