The split inside Serbia’s energy sector in 2025 was not just qualitative; it was measurable in revenues, margins, cash generation and balance-sheet behaviour. Oil and refining remained systemically important but financially constrained, while electricity trading and renewables produced cleaner, more scalable cash flows with materially higher return on capital.
Naftna Industrija Srbije continued to dominate the sector by size. In revenue terms, NIS historically operates at €4.0–4.5 billion annually, and even under sanctions pressure in 2025 its turnover remained above €3.5 billion, driven by stable domestic fuel demand of roughly 3.2–3.4 million tonnes of petroleum products. Refinery throughput at Pančevo was constrained but still exceeded 3 million tonnes, compared with nameplate capacity closer to 4.8 million tonnes.
However, margin compression was severe. Refining EBITDA margins, which exceeded 12–14 percent in favourable pre-sanctions cycles, fell into the 5–7 percent range in 2025 due to constrained crude sourcing, higher logistics costs, insurance premiums, and restricted access to cheaper feedstock blends. Working capital intensity increased sharply, with inventory financing requirements estimated to be 25–30 percent higher than normal. As a result, free cash flow declined materially despite high nominal revenues, and dividend capacity was curtailed in favour of liquidity preservation and operational continuity.
Fiscal exposure mirrored this pressure. While NIS still contributed several hundred million euros annually in excise duties, VAT, and corporate taxes, the volatility of these flows increased. Budget predictability deteriorated compared with years when NIS could freely arbitrage regional fuel margins and optimise refinery runs.
The electricity side of the sector told a fundamentally different story. Serbia-based electricity trading companies collectively handled an estimated 35–40 TWh of power in 2025, equivalent to 70–80 percent of Serbia’s domestic consumption when including cross-border flows. Aggregate electricity trading revenues are estimated at €3.2–3.8 billion, despite lower headline prices than crisis peaks, due to high turnover velocity and cross-border activity.
Average realised wholesale prices for baseload power ranged between €95 and €115 per MWh, with peak products frequently clearing €140–160 per MWh during congestion and hydrological stress. Pre-2021 baseload averages of €45–55 per MWh now appear structurally obsolete, underpinning sustained topline strength even in a “normalised” year.
Integrated utilities and state-linked entities such as Elektroprivreda Srbije generated wholesale and trading revenues estimated at €2.0–2.3 billion. However, EPS’s trading EBITDA margins were constrained to 8–12 percent due to regulated domestic supply, coal cost exposure, and social pricing obligations. Coal-fired generation costs rose as lignite extraction and environmental compliance expenses increased, eroding potential upside from higher market prices.
Foreign-owned electricity traders and renewable-backed portfolios materially outperformed on a margin basis. Entities such as MVM Srbija and subsidiaries of Austrian, Italian and Slovenian utilities reported Serbian trading revenues in the €150–600 million range per platform, with EBITDA margins typically between 15 and 18 percent. Net trading spreads averaged €6–10 per MWh in stable conditions and expanded to €12–18 per MWh during volatility episodes, particularly when cross-border capacity constraints appeared.
Renewable energy producers delivered the cleanest financial profile. Wind and solar assets operated at marginal costs well below €20 per MWh, while contracted or hedged sales prices remained above €90 per MWh for much of the year. Capacity factors for wind assets averaged 30–35 percent, and for utility-scale solar 18–22 percent, generating predictable cash flows. As projects commissioned between 2021 and 2023 moved fully into operational maturity, annual EBITDA yields of 18–22 percent on invested capital became common, with declining capex requirements and rising dividend capacity.
Balance-sheet intensity differed sharply across sub-sectors. Electricity traders with parent-group backing operated with effective funding costs of 4–6 percent, while independent traders faced 8–10 percent, materially affecting net profitability after collateral and hedging costs. Margining and collateral requirements on regional exchanges increased by 25–40 percent year-on-year, making liquidity management a decisive competitive factor.
Capital allocation patterns reinforced the divergence. In 2025, estimated sector capex in oil and refining was limited largely to maintenance and compliance, roughly €100–150 million, while electricity-related investments — renewables, grid-adjacent services, trading systems and analytics — exceeded €400–500 million. Trading companies alone invested €60–90 million in IT systems, forecasting tools, and collateral optimisation platforms, underscoring the financialisation of the power market.
From a macro standpoint, electricity increasingly replaced oil as the sector’s stabilising cash engine. While hydrocarbons remained larger in absolute fiscal contribution, electricity provided more predictable margins, lower geopolitical exposure, and better scalability under EU-aligned market rules. Serbia’s role evolved toward that of a regional electricity execution and balancing hub, rather than a purely domestic supply market.
By the end of 2025, the financial data left little ambiguity. Oil remained large but constrained, profitable but brittle. Electricity trading and renewables were smaller in legacy terms, but cleaner, faster-growing, and structurally better aligned with regional integration. Capital, margins and strategic attention followed the numbers.
