A structural shift is underway in Southeast Europe’s electricity markets as carbon pricing begins to reshape cross-border economics, triggering a surge in trading activity and the entry of new market participants. What initially appeared as a regulatory adjustment tied to EU climate policy is rapidly evolving into a price-formation mechanism that is redrawing arbitrage strategies, redistributing margins, and accelerating the financialisation of regional power trading.
At the centre of this transformation lies a widening divergence between EU carbon-priced electricity and non-EU generation systems, particularly those still anchored in lignite and coal. With EU ETS prices fluctuating in the range of €70–90/tCO₂, the embedded carbon cost in thermal generation within the EU now translates into an additional €55–85/MWh depending on plant efficiency. In contrast, much of Southeast Europe’s coal-based generation—particularly in Serbia, Bosnia and Herzegovina, and North Macedonia—continues to operate without a fully internalised carbon cost.
This divergence has created persistent cross-border price spreads of €20–60/MWh, with episodic spikes exceeding €80/MWh during peak demand or low renewable output periods. These spreads are no longer purely driven by fuel or hydrology, but increasingly by carbon-adjusted marginal pricing, which introduces a new layer of volatility and opportunity.
Emergence of a new trading layer
One of the clearest consequences has been the rapid entry of independent trading firms and portfolio players into Southeast Europe. These actors are not traditional utilities but capital-driven market participants specialising in spread trading, short-term positioning, and cross-border optimisation.
Their strategies are built around several core mechanisms.
First, forward curve positioning. Traders are taking positions on expected divergence between EU day-ahead prices (e.g. Italy, Hungary, Romania, Greece) and Balkan markets (Serbia, Bosnia, Montenegro). For example, forward contracts for Q3 2026 have shown spreads between Hungary (HUPX) and Serbia (SEEPEX) widening to €25–35/MWh, reflecting both carbon costs and tightening EU supply dynamics.
Second, physical arbitrage optimisation. Electricity flows across interconnectors are increasingly scheduled not only based on system needs but also on expected carbon-adjusted profitability. The Serbia–Hungary, Bosnia–Croatia, and North Macedonia–Greece corridors have become focal points for this activity, with interconnection capacity frequently booked at maximum levels during high-spread periods.
Third, intraday volatility capture. With renewables penetration increasing in EU markets, intraday price swings have intensified. Traders are exploiting short-term mismatches between solar-heavy midday price collapses in Greece or Italy and thermal-driven price stability in Balkan systems, capturing spreads that can exceed €40–70/MWh within a single trading day.
Carbon arbitrage corridors take shape
The region is effectively reorganising into a set of carbon arbitrage corridors, where electricity flows are increasingly dictated by carbon intensity rather than purely by generation cost.
Coal-heavy systems such as EPS in Serbia or Elektroprivreda BiH produce electricity at marginal costs often below €50–60/MWh, thanks to low-cost lignite. However, once adjusted for CBAM-equivalent carbon pricing, the effective cost of this electricity rises to €110–140/MWh, rendering it uncompetitive in EU markets without structural changes.
By contrast, EU markets—despite higher nominal prices—offer carbon-compliant electricity, which maintains its tradability within the bloc. This creates a paradox: electricity that is cheaper to produce becomes less competitive to export, while higher-cost but lower-carbon electricity gains market access.
This dynamic is most visible in Italy. The Italian PUN base price, frequently ranging between €110–150/MWh in recent months, continues to attract imports, but only from sources that can meet carbon-adjusted criteria. Historically, Balkan exports into Italy—particularly via Montenegro and Bosnia—played a balancing role. Under the new regime, these flows face increasing friction unless backed by low-carbon generation.
Financialisation of power trading
What is unfolding is a rapid financialisation of Southeast Europe’s electricity markets, echoing earlier developments in Northwest Europe during the expansion of the EU ETS.
Market behaviour is shifting along three dimensions.
The first is the transition from bilateral utility contracts to exchange-based and portfolio trading. Platforms such as SEEPEX (Serbia) and CROPEX (Croatia) are seeing increased activity, while cross-border hedging is increasingly tied to EEX-linked forward products.
The second is the rise of short-term positioning strategies. Instead of long-term power purchase agreements dominating flows, a growing share of electricity is being traded on day-ahead and intraday markets, where volatility can be monetised.
The third is the integration of carbon as a tradable risk variable. Traders are not only pricing electricity but also implicitly pricing carbon exposure, using EU ETS futures as a reference. This introduces a new layer of correlation between power prices, carbon markets, and gas benchmarks.
Quantifying the market shift
The scale of the transformation becomes clearer when looking at regional flows and volumes.
Between 2015 and 2024, Southeast Europe exported approximately 10–15 TWh of electricity annually to EU markets, with peak years exceeding 18 TWh. Serbia alone has periodically exported 3–5 TWh per year, depending on hydrological conditions and domestic demand.
Under current carbon pricing assumptions, up to 60–70% of these export volumes are at risk of becoming economically unviable unless restructured. This implies a potential contraction of 8–10 TWh annually in cross-border flows, equivalent to €800 million–€1.2 billion in lost trading value at current price levels.
At the same time, trading margins on remaining flows are increasing. For active traders, capturing a €20–40/MWh spread on 1 TWh of traded volume translates into €20–40 million in gross margin, explaining the surge in market participation.
Case study: Serbia–Hungary corridor
The Serbia–Hungary interconnection illustrates the new trading logic.
Hungary, fully integrated into the EU ETS, reflects carbon costs in its wholesale prices. Serbia, operating outside the ETS, maintains lower generation costs but faces CBAM exposure on exports.
During high-demand periods in winter 2026, the price spread between HUPX baseload and SEEPEX baseload exceeded €30/MWh, with intraday spikes reaching €50/MWh. Traders positioned on this spread were able to capture margins by:
• Scheduling exports during peak price windows
• Hedging forward positions against expected carbon price increases
• Exploiting congestion patterns on interconnectors
This corridor has effectively become a testing ground for carbon-driven electricity arbitrage in Southeast Europe.
Structural risks emerging
While trading activity is increasing, the system is also becoming more fragile.
Price volatility is intensifying, particularly during periods of:
• Low renewable output in the EU
• Cold weather demand spikes
• Transmission congestion
In such conditions, price swings of €100/MWh within 24 hours are no longer unusual.
At the same time, the growing role of speculative capital introduces non-fundamental flows, where electricity movements are driven more by trading strategies than by system optimisation. This can complicate balancing operations for transmission system operators such as EMS (Serbia) and CGES (Montenegro).
Liquidity is also becoming more fragmented. While trading volumes are increasing, much of the activity is concentrated in short-term markets, reducing visibility for long-term investment decisions.
Investment signals are shifting
Perhaps the most significant impact lies in how CBAM-driven trading dynamics are reshaping investment signals.
Coal-based generation, once the backbone of export strategies, is facing structural decline. Even with low operating costs, the inability to compete in carbon-adjusted markets reduces long-term revenue certainty.
In contrast, renewable energy is gaining a dual advantage:
• Lower marginal cost
• Full compatibility with EU carbon pricing
Wind and solar projects in Serbia, Bosnia and Montenegro—typically with CAPEX ranges of €0.9–1.3 million/MW for wind and €0.5–0.8 million/MW for solar—are increasingly positioned not just as domestic supply assets but as export-oriented, carbon-compliant generation platforms.
Battery storage is emerging as a critical complement. With intraday spreads frequently exceeding €50/MWh, BESS systems with 1–2 hour duration can capture arbitrage value while supporting grid stability.
A transitional market becomes a trading frontier
What is emerging across Southeast Europe is not merely an adjustment to carbon policy, but the formation of a new type of electricity market.
It is a market where:
• Carbon defines competitiveness
• Price spreads drive capital flows
• Trading strategies shape physical electricity movements
In this environment, value is shifting away from pure generation and toward market access, portfolio optimisation, and carbon positioning.
The Western Balkans, positioned between a carbon-priced EU and a legacy coal-based system, are becoming a frontier zone for carbon-linked electricity trading—a space where regulatory asymmetry creates both opportunity and instability, and where the next phase of market evolution will be defined as much by financial strategy as by physical infrastructure.
