The Serbian energy sector experienced significant changes in 2025, reflected in measurable financial outcomes, revenue generation, and operational dynamics. While oil and refining remained crucial to the economy, they faced substantial financial constraints. In contrast, the electricity trading and renewable energy segments emerged as more profitable and scalable, yielding higher returns on capital.
Naftna Industrija Srbije (NIS) continued to be a dominant player within the sector, generating annual revenues between €4.0 billion and €4.5 billion. Despite facing sanctions, NIS reported a turnover exceeding €3.5 billion in 2025, supported by stable domestic demand of approximately 3.2 million to 3.4 million tonnes of petroleum products. Although refinery throughput at Pančevo was limited, it still surpassed 3 million tonnes against a nameplate capacity of nearly 4.8 million tonnes.
However, the refining segment experienced severe margin compression. EBITDA margins that previously ranged from 12% to 14% in favorable conditions fell to between 5% and 7% due to challenges such as constrained crude sourcing, increased logistics costs, higher insurance premiums, and limited access to cheaper feedstock blends. Working capital intensity rose sharply, with inventory financing requirements estimated to be 25% to 30% higher than usual. Consequently, free cash flow saw a notable decline despite high nominal revenues, leading to reduced dividend capacity as liquidity preservation became a priority.
The fiscal implications mirrored these challenges. NIS contributed several hundred million euros annually through excise duties, VAT, and corporate taxes; however, the volatility of these contributions increased significantly. The predictability of budgetary flows deteriorated compared to prior years when NIS could effectively manage regional fuel margins and optimize refinery operations.
Conversely, the electricity sector demonstrated a more robust performance. Electricity trading companies based in Serbia managed an estimated 35 TWh to 40 TWh of power in 2025, accounting for roughly 70% to 80% of domestic consumption when factoring in cross-border transactions. Estimated aggregate revenues from electricity trading reached between €3.2 billion and €3.8 billion, attributed to high turnover velocity despite lower prices compared to crisis peaks.
Wholesale prices for baseload power averaged between €95 and €115 per MWh, with peak pricing often reaching €140 to €160 per MWh during periods of congestion or hydrological stress. Previous averages for baseload prices of €45 to €55 per MWh appear outdated, supporting sustained revenue growth even in otherwise normalized market conditions.
State-linked entities like Elektroprivreda Srbije generated wholesale and trading revenues estimated at €2.0 billion to €2.3 billion but faced constrained EBITDA margins of 8% to 12%. This was largely due to regulated domestic supply pressures, coal cost exposure, and social pricing obligations that limited profitability.
In contrast, foreign-owned electricity traders and renewable energy portfolios achieved significantly better margins. Companies such as MVM Srbija reported trading revenues ranging from €150 million to €600 million per platform with EBITDA margins typically between 15% and 18%. Net trading spreads fluctuated from €6 to €10 per MWh under stable conditions but could rise to between €12 and €18 per MWh during periods of market volatility.
Renewable energy producers showcased the most favorable financial profiles, with wind and solar assets operating at marginal costs below €20 per MWh. Contracted sales prices remained above €90 per MWh for much of the year. Capacity factors averaged between 30% and 35% for wind assets and between 18% and 22% for utility-scale solar projects, resulting in predictable cash flows as new projects commissioned from 2021 to 2023 reached operational maturity.
The balance-sheet intensity varied widely across different sectors within the energy industry. Electricity traders backed by parent groups operated with funding costs between 4% and 6%, while independent traders faced costs ranging from 8% to 10%. This disparity had a significant impact on net profitability after accounting for collateral and hedging expenses.
Investment patterns also highlighted this divergence: capital expenditures in oil and refining were restricted primarily to maintenance and compliance at around €100 million to €150 million, whereas investments related to electricity—covering renewables, grid services, trading systems—exceeded €400 million to €500 million. Trading companies alone allocated between €60 million and €90 million towards IT systems and forecasting tools.
From a macroeconomic perspective, electricity increasingly took precedence over oil as a stabilizing cash engine within the sector. While hydrocarbons continued to contribute more substantially in absolute fiscal terms, electricity provided greater predictability in margins along with lower geopolitical risks and enhanced scalability under EU-aligned market frameworks.
By the close of 2025, financial indicators clearly delineated the state of the sectors: while oil remained significant yet constrained and vulnerable, electricity trading alongside renewables appeared smaller historically but demonstrated cleaner growth trajectories aligned with regional integration efforts.
