As Serbia approaches a critical juncture in its energy landscape between 2026 and 2032, the country faces significant challenges influenced by external market dynamics, increased renewable energy adoption in neighboring EU countries, and inherent grid limitations. The pressing issue is not merely the necessity for dispatchable capacity but rather identifying the optimal form of dispatchability that minimizes fiscal exposure, curtailment risk, and overall system costs amid diminishing baseload economics.
The current framework of Serbia’s dispatchable power is primarily reliant on aging lignite units operated by the state-owned utility EPS, alongside hydropower sources that are becoming increasingly volatile from year to year. Despite the marginal role of gas-fired generation at present, shifts in cross-border electricity pricing have already begun to alter operational strategies. During periods characterized by high solar output, imported electricity from Hungary, Romania, and Croatia increasingly dictates marginal pricing, while scarcity pricing typically emerges during peak demand hours in the evening and winter months. This evolving price structure plays a crucial role in determining the economic viability of various assets.
A preliminary stress test for Serbia’s power system over this period indicates a dramatic reduction in expected full-load hours across all thermal generation assets. Traditionally operational for around 6,000 to 6,500 hours annually, lignite plants are projected to operate between 3,500 and 4,200 hours moving forward. In contrast, new combined-cycle gas turbines (CCGTs), if developed on a merchant basis, may struggle to achieve even 2,000 to 2,500 operational hours—insufficient for recouping capital expenditures without long-term contracts or capacity payments. In this context, battery storage systems emerge as a viable alternative that leverages market volatility rather than volume.
The financial implications of these developments are stark. A modern CCGT with a capacity of 400–500 MW in Serbia would require an initial investment ranging from €350 million to €450 million, not accounting for necessary upgrades to gas infrastructure or fuel hedging strategies. Even under favorable market conditions, annual earnings before interest, taxes, depreciation, and amortization (EBITDA) would face significant volatility and heightened risk as solar energy penetration in Hungary and Romania approaches levels exceeding 30% of total generation—a threshold that appears imminent.
While coal reserve options may initially appear more economical, they mask deeper structural inefficiencies. Maintaining lignite units in cold or strategic reserve avoids immediate capital expenditure but incurs ongoing costs related to maintenance and staffing while risking forced outages. The realistic cost of keeping older lignite units in reserve is estimated at €70 to €90 per kilowatt per year—translating to an annual expenditure of €140 million to €180 million for a reserve fleet totaling 2 GW. Importantly, these costs do not provide operational flexibility; instead, they ensure availability with long start-up times that do not align with the system’s evolving needs.
In contrast, utility-scale battery energy storage systems (BESS) present a compelling alternative. A deployment of approximately 1 GW / 4 GWh would necessitate capital investment between €700 million and €850 million at current prices but could decrease toward €550 million to €650 million by the late 2020s. While initial capital costs may seem higher than those associated with gas peakers or coal reserves, batteries offer distinct advantages by capturing intraday price fluctuations and reducing reliance on imports during scarcity events while simultaneously lowering reserve margins and deferring infrastructure upgrades.
Grid constraints further complicate Serbia’s energy landscape. Internal transmission bottlenecks between northern and southern regions limit the ability to accommodate low-cost imports or export excess hydropower generation effectively. In this environment, strategically placed batteries can outperform centralized thermal plants by mitigating redispatch expenses associated with congestion points. Conversely, gas peakers situated away from these bottlenecks lose their competitive edge while coal reserves provide no relief from congestion issues.
From a financial perspective, it becomes evident that coal reserves externalize costs indefinitely while gas peakers introduce stranded asset risks within a decade. Battery storage solutions require upfront capital investment but stabilize ongoing operating expenses while minimizing vulnerability to price shocks from imports. Under conservative projections for system cost minimization in Serbia’s future energy framework favors accelerated deployment of storage solutions alongside strategic reductions in lignite reserves over new baseload gas installations.
This analysis underscores that Serbia’s evolving grid dynamics reward agility and flexibility over traditional fuel throughput metrics. Future capacity remuneration frameworks must prioritize technology neutrality while emphasizing flexibility; otherwise, there is a risk of entrenching public investments into declining asset classes.
