The introduction of carbon pricing in Southeast Europe is catalyzing significant changes in the region’s electricity markets, leading to increased trading activity and the emergence of new market players. This shift, initially perceived as a regulatory adjustment aligned with EU climate initiatives, is now becoming a pivotal mechanism for price formation, altering arbitrage strategies and enhancing the financialization of power trading.
Central to this evolution is the growing disparity between electricity priced under the EU carbon framework and that generated outside it, particularly in countries reliant on lignite and coal. Current EU Emissions Trading System (ETS) prices range from €70 to €90 per ton of CO₂, translating into an added cost of €55 to €85 per megawatt-hour (MWh) for thermal generation within the EU. Conversely, many Southeast European nations, including Serbia, Bosnia and Herzegovina, and North Macedonia, continue to operate thermal plants without incorporating a full carbon cost.
This divergence has resulted in persistent cross-border price spreads between €20 and €60 per MWh, with spikes surpassing €80 per MWh during periods of peak demand or low renewable energy output. These price variations are increasingly influenced by carbon-adjusted marginal pricing rather than traditional factors such as fuel costs or hydrological conditions.
The influx of independent trading firms and portfolio players into Southeast Europe marks a notable development. These entities are not conventional utilities; they are capital-driven participants focused on spread trading, short-term positioning, and cross-border optimization. Their strategies revolve around three primary mechanisms: forward curve positioning, physical arbitrage optimization, and intraday volatility capture.
Traders are actively taking positions based on expected price divergences between EU day-ahead markets—such as those in Italy, Hungary, Romania, and Greece—and Balkan markets like Serbia and Bosnia. For instance, forward contracts for Q3 2026 have indicated widening spreads of €25 to €35 per MWh between Hungary’s HUPX and Serbia’s SEEPEX due to carbon costs and tightening supply dynamics in the EU.
Electricity flows across interconnectors are now increasingly scheduled based on anticipated carbon-adjusted profitability. Key corridors such as Serbia-Hungary, Bosnia-Croatia, and North Macedonia-Greece are seeing maximum capacity bookings during high-spread periods. Additionally, traders are capitalizing on intraday price fluctuations caused by increased renewable penetration in EU markets, capturing spreads that can reach €40 to €70 per MWh within a single day.
The establishment of carbon arbitrage corridors is reshaping how electricity flows are determined in the region. Coal-dependent systems like EPS in Serbia or Elektroprivreda BiH can generate electricity at marginal costs below €50 to €60 per MWh due to low-cost lignite. However, factoring in CBAM-equivalent carbon pricing raises their effective production costs to between €110 and €140 per MWh, making them less competitive in EU markets unless structural changes occur.
In contrast, EU markets provide carbon-compliant electricity that remains tradable within the bloc. This dynamic creates a paradox where cheaper-to-produce electricity becomes less competitive for export while higher-cost but lower-carbon electricity gains market access. This trend is particularly evident in Italy, where the Italian PUN base price has fluctuated between €110 and €150 per MWh recently, attracting imports only from sources meeting stringent carbon criteria.
The financialization of Southeast Europe’s electricity markets mirrors earlier trends seen in Northwest Europe during the expansion of the EU ETS. Market behavior is evolving along three dimensions: a shift from bilateral utility contracts to exchange-based trading platforms like SEEPEX (Serbia) and CROPEX (Croatia), an increase in short-term positioning strategies favoring day-ahead and intraday markets over long-term agreements, and the integration of carbon as a tradable risk variable affecting pricing strategies.
Between 2015 and 2024, Southeast Europe exported approximately 10 to 15 terawatt-hours (TWh) of electricity annually to EU markets, peaking above 18 TWh in certain years. Serbia has contributed significantly to these figures with exports ranging from 3 to 5 TWh annually depending on hydrological conditions and domestic demand. However, under current carbon pricing scenarios, up to 60% to 70% of these export volumes risk becoming economically unviable without restructuring efforts. This situation could lead to a potential reduction of 8 to 10 TWh annually in cross-border flows—translating into a loss of trading value estimated between €800 million and €1.2 billion at current price levels.
Despite these challenges, trading margins on remaining flows are increasing. Active traders can achieve gross margins of €20 to €40 million by capturing spreads of €20 to €40 per MWh on 1 TWh of traded volume. The Serbia-Hungary interconnection exemplifies this new trading logic; while Hungary incorporates carbon costs into its wholesale prices as part of the EU ETS framework, Serbia maintains lower generation costs but faces exposure under the Carbon Border Adjustment Mechanism (CBAM).
During peak demand periods in winter 2026, price spreads between HUPX baseload and SEEPEX baseload exceeded €30 per MWh with intraday spikes reaching up to €50 per MWh. Traders successfully capitalized on these opportunities by scheduling exports during peak price windows while hedging against anticipated increases in carbon prices.
However, as trading activity surges, structural risks are emerging within the system. Price volatility is intensifying due to factors such as low renewable output in the EU, spikes in cold weather demand, and transmission congestion—leading to price swings exceeding €100 per MWh within short timeframes. The increasing influence of speculative capital introduces non-fundamental flows that may complicate balancing operations for transmission system operators like EMS (Serbia) and CGES (Montenegro).
Investment signals are also shifting significantly due to CBAM-driven dynamics reshaping market strategies. Coal-based generation faces structural decline despite low operational costs because it struggles to compete in carbon-adjusted markets. Conversely, renewable energy sources are gaining traction due to their lower marginal costs and compatibility with EU carbon pricing policies.
Wind and solar projects across Serbia, Bosnia, and Montenegro—typically requiring capital expenditures ranging from €0.9 million to €1.3 million per MW for wind projects and from €0.5 million to €0.8 million per MW for solar—are increasingly viewed not just as domestic supply assets but also as platforms for export-oriented carbon-compliant generation.
As Southeast Europe transitions into a new type of electricity market defined by carbon competitiveness and price-driven capital flows, it emerges as a frontier for carbon-linked electricity trading amid regulatory asymmetries that present both opportunities and challenges for market participants.
