Serbia has initiated a RSD 625 million (approximately €5.3 million) public procurement process to prepare the technical and planning documentation for the proposed Đerdap 3 pumped-storage hydropower plant, marking a significant step in advancing one of the country’s largest long-term energy infrastructure projects.
The Ministry of Mining and Energy is seeking a consultant or consortium to deliver the General Design, Preliminary Feasibility Study, Special-Purpose Spatial Plan, and Strategic Environmental Assessment. Interested bidders have until 20 August 2026 to submit proposals. Rather than launching construction, the tender is intended to establish the technical, environmental and planning basis required to determine whether the project can be permitted, financed and developed while addressing impacts on the Danube River, the existing Đerdap hydropower system, navigation, protected areas and Serbia’s shared water management responsibilities with Romania.
Project configuration under evaluation
The proposed facility would function as a large-scale electricity storage system by using surplus electricity during periods of low demand or high renewable generation to pump water from the Đerdap 1 reservoir into one or two higher reservoirs. The stored water would later be released through reversible pump-turbine units to generate electricity during periods of stronger demand.
Current studies envisage installed capacity ranging from 1,200 MW to 2,400 MW, while the Ministry is currently assessing an intermediate configuration of approximately 1,800 MW. Technical assessments indicate a hydraulic head of about 400 metres, with Pesača and Brodica in the Northern Kučaj mountain range identified as potential upper-reservoir sites.
The Đerdap 1 reservoir on the Danube would serve as the lower reservoir. The proposed development area extends between Golubac and Donji Milanovac, roughly 65 kilometres upstream from the existing Đerdap 1 plant. The overall scheme would include intake and outlet structures on the Danube, pressure tunnels, penstocks, underground or surface waterways, upper dams and reservoirs, reversible generating units, a powerhouse, transformers, switchgear and a high-capacity grid connection to Elektromreža Srbije.
Investment scale and development priorities
The project currently carries an indicative investment value of approximately €2.6 billion, although final costs will depend on decisions regarding plant configuration, storage volume, geological conditions, tunnelling requirements and transmission infrastructure.
For the 1,800 MW concept under consideration, the estimate equates to roughly €1.44 million per MW, or about €1,440 per kW. However, costs could rise to between €3 billion and €3.4 billion if complex geological conditions, environmental mitigation, grid reinforcement or imported electromechanical equipment increase expenditure. A full 2,400 MW configuration could require €3.2 billion to €4 billion, depending on storage duration and reservoir design. The planning contract therefore represents only around 0.2% of the currently estimated construction cost. Its purpose is to establish the project’s optimal capacity, storage duration and construction sequence while producing lender-grade technical documentation before any engineering, procurement and construction contract is negotiated.
Under the intermediate configuration, the facility could provide approximately 14.4 GWh of storage with eight hours of full-load generation, increasing to 18 GWh with ten hours of operation. The maximum 2,400 MW option would offer between 19.2 GWh and 24 GWh, depending on operating duration. Although final reservoir volumes have not been determined, these figures indicate a storage project substantially larger than battery energy storage systems currently being developed across Southeast Europe.
Role within Serbia’s electricity system
The planned facility is intended to complement, rather than replace, Serbia’s Bistrica pumped-storage project. While Bistrica is at a more advanced development stage and designed on a smaller scale, Đerdap 3 is envisioned as a strategic regional storage asset capable of providing deep energy storage, peak generation capacity and cross-border balancing services. Its economic model would rely on multiple revenue streams rather than electricity-price arbitrage alone. In addition to buying and selling electricity across different market periods, the plant would be expected to generate income from capacity remuneration, ancillary services, reserves, frequency control, system restoration and availability payments.
Illustrative assumptions for a 1,800 MW project with capital expenditure between €2.6 billion and €3.2 billion, round-trip efficiency of 75%–80%, and annual discharged generation of 2.5–3.5 TWh suggest annual energy-arbitrage margins of approximately €150 million–€230 million. Additional revenues from ancillary services, reserve markets, capacity payments and congestion management could contribute another €60 million–€120 million annually. After operating costs equivalent to around 1.5%–2% of capital expenditure, annual EBITDA could reach approximately €170 million–€270 million.
For a larger 2,400 MW configuration with investment of €3.2 billion–€4 billion, annual discharged generation of 3.5–5 TWh, storage exceeding 19 GWh, and strong regional capacity payments, annual EBITDA could increase to €280 million–€400 million.
Financing and construction considerations
The project is expected to require financing comparable to major regulated infrastructure rather than conventional merchant renewable generation. An indicative financing structure could involve 20%–30% equity or sovereign-backed public funding, with the remaining 70%–80% financed through long-term debt from export-credit agencies, international financial institutions, US development-finance institutions and commercial banks.
For a project costing approximately €3 billion, this would imply €600 million–€900 million in equity or public capital and €2.1 billion–€2.4 billion in debt, with repayment periods of 20–25 years following completion. Lenders are expected to require stable revenue mechanisms, including capacity or availability payments, regulated cost recovery or long-term state-backed balancing-service agreements, rather than relying solely on wholesale electricity-price spreads.
Construction scheduling will also influence project economics. A delay of 12–18 months after financial close could increase costs by roughly €120 million–€300 million through inflation, contractor claims, additional owner expenses and higher interest during construction. Such delays could reduce equity internal rates of return by approximately 0.7–1.5 percentage points. To reduce funding pressure and construction risk, Serbia could consider phased commissioning, initially developing either a 1,200 MW or 1,800 MW section before expanding to the full project.
Current government planning targets completion of an initial phase around 2036, with the broader development potentially extending to 2038. The front-end engineering and initial contracting stage alone is expected to require approximately 36 months, while geological investigations, permitting, environmental studies and land acquisition will take several additional years.
US cooperation and international participation
Serbia has linked the project to its strategic energy cooperation framework with the United States, which entered into force in March 2025 following an intergovernmental agreement signed in 2024. A public invitation for US companies interested in participating in the project closed on 25 June 2026, attracting submissions from six companies.
The process aims to identify a strategic partner capable of supporting front-end engineering and potentially delivering a future engineering, procurement and construction contract. Applicants were required to demonstrate experience with hydropower or comparable infrastructure projects exceeding €1 billion, together with front-end engineering expertise.
The government has indicated that any strategic partnership will require transparent pricing, independently verified quantities and clear rules governing any transition from engineering services to construction activities. The €5.3 million planning tender and the strategic-partner selection remain separate legal and commercial processes. The planning documentation is intended to remain under state control so that technical studies are not shaped around the commercial interests of any future contractor.
Cross-border coordination with Romania
Although the project would be located entirely within Serbia, it would draw water from the Iron Gates (Đerdap) reservoir jointly managed by Serbia and Romania. On 16 July 2026, the two countries signed a memorandum in Bucharest to support information exchange and technical assessments related to the project.
Romania has stated that any future development must remain compatible with electricity generation at Iron Gates I and II, Danube navigation and environmental protection. Operating rules for Đerdap 3, including pumping schedules, reservoir levels and generation timing, will therefore require bilateral coordination, and these constraints will need to be reflected in the Preliminary Feasibility Study because they could influence commercial performance.
Transmission and environmental studies
Grid integration will form another major element of the planning process. Connection studies will assess the ability of Serbia’s 400 kV transmission network to accommodate injections of up to 2,400 MW, together with transmission capacity toward Romania, Bulgaria and Hungary. The project is expected to support the integration of additional renewable generation by storing surplus electricity during periods of high wind and solar output before returning it to the system during peak demand.
Planning scenarios indicate the facility could enable the integration of 3–5 GW of additional wind and solar capacity under a base case, while the larger configuration could support a wider regional renewable portfolio of 5–7 GW, including imported electricity used for pumping.
Avoided renewable curtailment of 500–1,000 GWh annually, combined with an average electricity value of €40–€70/MWh, could generate direct annual system benefits of approximately €20 million–€70 million, alongside broader benefits including reduced emergency imports, lower fossil-fuel peaking requirements and improved balancing capability.
Environmental permitting will also be central to project development because the proposed upper reservoirs lie within the wider Đerdap Gorge area, which includes Đerdap National Park and sites of ecological, cultural and archaeological importance.
The Strategic Environmental Assessment will compare alternative configurations, including the number and location of upper reservoirs, underground versus surface infrastructure, biodiversity impacts, sediment movement, water quality, construction traffic, landscape effects and cumulative impacts alongside existing hydropower facilities. The planning studies will determine whether the 1,800 MW concept or a larger 2,400 MW configuration offers the strongest balance between technical feasibility, environmental compliance, commercial viability and long-term system value.
