The EPS power utility company in Serbia is grappling with the persistent challenge of advancing its energy projects, particularly in the realms of reversible hydropower and gas-fired generation. These initiatives have been recognized for over a decade as critical solutions to address the country’s pressing needs for flexibility, balancing, and supply security. However, they remain largely theoretical, confined to feasibility studies and conceptual plans.
The Bistrica reversible hydropower plant exemplifies this dilemma. As a key project for EPS, it is positioned as essential for future system balancing amid increasing integration of wind and solar energy. The proposed facility is designed with a capacity of 600–700 MW and storage capabilities sufficient for 8–10 hours of operation, equating to approximately 5–6 GWh of usable energy. The estimated capital expenditure for Bistrica ranges from €900 million to €1.2 billion, largely due to extensive civil works, electromechanical equipment costs, and grid integration requirements.
Repeated feasibility studies have consistently highlighted the project’s significant value to the energy system. It promises to mitigate curtailment risks, enhance peak shaving capabilities, stabilize frequency, and reduce import dependencies during high-demand periods. However, financial viability remains elusive under current market conditions. The monetization of pumped storage relies on arbitrage opportunities and ancillary services; yet Serbia lacks a developed capacity or flexibility market that would ensure stable revenue streams. Consequently, EPS finds itself in a position where the project is deemed essential but financially uncertain and capital-intensive.
Similar challenges confront gas power plant concepts associated with EPS. Over the past decade, various gas-fired generation projects have been proposed, typically within the 300–500 MW range. Projected capital costs are estimated between €250 million and €400 million, contingent upon configurations and gas supply connections. These plants are often framed as transitional assets that would provide flexible support to renewable sources while replacing aging lignite facilities.
While feasibility studies for these gas projects have produced favorable technical assessments regarding layouts and emissions profiles, execution remains hindered by structural uncertainties. Long-term gas pricing continues to be volatile in the wake of recent European market shifts. Additionally, power offtake arrangements are predominantly merchant-based without a domestic capacity market to stabilize revenues. The introduction of carbon pricing further complicates financial projections. As a result, EPS faces an environment where feasible returns can only be anticipated under scenarios that presume future regulatory clarity and market depth.
Both Bistrica and gas power plants share a common characteristic: they are flexibility assets whose benefits are collective rather than easily monetized. While they contribute to system stability, the existing market framework does not adequately compensate for this stability. Feasibility analyses frequently cite system advantages such as reduced import costs and improved reliability, potentially saving €50–100 million annually during peak stress periods. However, these benefits are broadly distributed among consumers and the state while the associated capital risks remain concentrated on EPS’s balance sheet.
This situation creates an institutional conundrum for EPS; it is expected to operate commercially while simultaneously fulfilling national energy security mandates and transition goals. Approving projects like Bistrica or large gas plants would necessitate substantial capital commitments—between €1 billion and €1.5 billion—without guaranteed revenue streams. By conducting repeated feasibility studies, EPS can align itself with government policy objectives without assuming excessive financial risk.
Moreover, there exists a sequencing issue regarding these investments. Both reversible hydro and gas plants would only become economically viable once significant market reforms are implemented—such as capacity remuneration mechanisms or well-defined ancillary service markets. In Serbia, discussions about these reforms occur concurrently with project planning. Thus, feasibility serves as an intermediary step between a current system that inadequately rewards flexibility and a future system that is presumed to do so.
In this context, Bistrica and gas power plants reflect broader institutional behaviors within EPS regarding classical hydropower projects. Initiatives that could substantially enhance the energy system remain stalled in analysis due to their concentration of long-term risks amid an environment that disperses responsibilities and shortens decision-making timelines.
The pressing reality is that Serbia requires these assets as coal-fired units age and renewable energy sources proliferate. Without substantial storage capabilities and flexible thermal backup options, reliance on imports will likely increase alongside emergency measures. Yet within EPS, the prevailing response has been to continuously refine feasibility rather than commit to implementation.
Until Serbia clarifies who bears the costs of flexibility—whether through tariffs, capacity payments, or direct state support—flagship projects like Bistrica and associated gas plants will likely remain theoretical ambitions rather than operational realities. Feasibility studies will persist in evolving; however, decisive action on risk ownership remains crucial for progress in Serbia’s energy landscape.
