Serbia’s energy companies entered the second quarter with some of the strongest export expectations in the economy, even as official data showed a severe contraction in electricity exports and a new carbon-cost barrier to sales into the European Union.
Around 32% of surveyed exporters in the broad energy and coal-mining category increased exports during the first quarter. For Q2, 45% expected further growth, the highest proportion among the sectors covered by the business survey. Approximately 46% of energy companies also expected higher turnover.
The electricity data tell a more difficult story. Serbian electricity exports fell by approximately 48.4% year on yearduring Q1. The National Bank of Serbia attributed part of the decline to the definitive phase of the EU Carbon Border Adjustment Mechanism, which has changed the economics of electricity originating from carbon-intensive power systems.
The apparent contradiction partly reflects different measurements. The business survey compares Q1 with Q4 and combines electricity, energy and coal-mining activities. Official electricity data isolate one commodity and compare it with the same period of 2025. An energy company can also report higher revenue because of price changes or non-electricity activity even when exported electricity volumes decline.
For Elektroprivreda Srbije, the deeper issue is the carbon intensity of lignite generation. Thermal power plants remain essential for domestic security of supply, but electricity produced from lignite carries a significantly higher embedded-emissions burden than hydropower, wind or solar. When exported to the EU, that difference increasingly becomes a direct commercial discount or CBAM cost.
The domestic carbon tax of €4 per taxable tonne of CO₂ provides only limited protection against the much higher EU carbon-price signal. It may be credited against the corresponding CBAM obligation where the legal conditions are satisfied, but the remaining gap can still eliminate the export margin of lignite-based electricity.
EPS is responding through a large investment programme. Its principal renewable project envisages 1 GW of solar capacity distributed across at least five sites and a battery-storage system of at least 200 MW, with planned storage energy of up to 400 MWh. The official development envelope places the project at approximately €1.7bn, with expected annual generation of around 1.7 TWh.
The published base-case economics indicate a project-level internal rate of return of about 3.2%, reflecting the strategic rather than purely merchant nature of the investment. The programme is intended to reduce portfolio emissions, improve self-balancing and preserve electricity-system reliability. Its financial value therefore includes avoided carbon exposure, reduced imports and portfolio-level risk reduction that a conventional standalone IRR does not fully capture.
The private renewable pipeline is also significant. Serbia’s first two market-premium auctions allocated close to 1,300 MW of wind and solar capacity. The second round selected projects with total capacity of up to 645 MW, with bids as low as €53.6/MWh for wind and €50.9/MWh for solar.
Onshore wind projects in Serbia typically require CAPEX of approximately €1.25m-€1.55m per MW, depending on turbine selection, roads, terrain and grid connection. Solar projects generally fall within €0.60m-€0.85m per MW, excluding material reinforcement of the grid. Wind can deliver capacity factors of 30-38% at good Serbian sites, while utility-scale solar generally operates around 15-18%.
A base-case Serbian wind project supported by a market premium or long-term PPA can target an equity IRR of approximately 9-12%, while stronger wind resources, controlled connection costs and moderate leverage can move returns toward 12-15%. Solar equity returns are commonly around 8-11%, with upside available from corporate PPAs, storage and merchant-price optimisation.
Grid delay remains the critical downside. A 12-month delay can reduce wind equity IRR by roughly 1.5-2.5 percentage points, while an 18-month delay may remove 2.5-4 points, depending on debt drawdown, commitment fees, turbine-storage costs and whether the project receives compensation under its contracts. Solar is exposed to similar delay economics but generally faces lower absolute construction complexity and greater midday curtailment risk.
The strongest path for Serbian electricity exports is therefore not a return to the previous lignite-based model. Export competitiveness increasingly depends on verifiable low-carbon generation, hourly production evidence, cross-border capacity and an electricity portfolio capable of supporting industrial buyers exposed to CBAM.
