Serbia has approved the shareholder arrangements for a proposed 500 MW gas-fired power plant near Niš, clearing a corporate governance step for a joint venture involving Elektroprivreda Srbije (EPS), Srbijagas and Azerbaijan’s SOCAR. The facility is intended to expand domestic electricity generation, diversify energy supply and provide additional flexibility to the power system, with completion targeted for 2030.
The government authorised the necessary corporate approvals through two decisions published in Serbia’s Official Gazette. The decisions followed the signing of the shareholders’ agreement, advancing preparations for a project that would cover the development, financing, construction and operation of a combined-cycle power plant.
The proposed facility could generate up to 500 MW of electricity and approximately 150 MW of thermal energy. However, the project’s total investment cost, financing structure, final installed capacity, gas procurement arrangements and electricity sales model have not been publicly confirmed.
Joint Venture Establishes Equal Partnership
Under the proposed ownership structure, EPS and Srbijagas will collectively hold 50%, while SOCAR will own the remaining 50%. The individual stakes of EPS and Srbijagas within the Serbian shareholders’ share have not been specified publicly. The arrangement combines EPS’s electricity generation and market experience with Srbijagas’s knowledge of gas infrastructure and procurement. SOCAR brings an international energy industry partner with experience in natural gas production, trading and energy infrastructure.
The venture also expands Serbia’s economic relationship with Azerbaijan, which is an important partner in the country’s efforts to diversify gas imports. The shareholders’ agreement provides for joint management and unanimous approval of key decisions during the preparatory phase. While this framework protects each partner against unilateral commitments, it could create deadlocks over financing, procurement and contractual obligations if the shareholders’ interests diverge.
EPS will need to assess the plant’s generation costs and reliability, while Srbijagas will have an interest in additional gas demand and infrastructure utilisation. SOCAR’s potential commercial interests include gas sales, investment returns and a broader presence in Southeast Europe. For prospective lenders, the allocation of commercial risks and the effectiveness of shareholder decision-making will be important alongside the plant’s technical design.
Gas Supply and Fuel Costs Will Shape Operating Economics
The Niš area offers access to the Serbia–Bulgaria gas interconnector, which has a nominal annual transport capacity of 1.8 billion cubic metres, as well as connections to the wider regional transmission network. The infrastructure provides access to alternative supply routes, including Azerbaijani gas transported through the Southern Gas Corridor.
Available pipeline capacity, however, does not establish that fuel volumes have been contracted or guaranteed for the proposed plant. A facility operating at a substantial utilisation rate would require significant and recurring gas purchases. At a 50% capacity factor, a 500 MW plant would generate approximately 2.19 TWh of electricity annually. At 70% utilisation, annual output would rise to around 3.07 TWh. Actual production would depend on electricity demand, maintenance schedules, gas availability and the relationship between wholesale power prices and fuel costs.
Combined-cycle technology can deliver higher electrical efficiency than older gas-fired generation systems, reducing the fuel required for each unit of electricity. Nevertheless, exposure to international gas prices will remain a major factor in operating profitability. Assuming an illustrative electrical efficiency of 55%, producing one megawatt-hour of electricity would require approximately 1.82 MWh of gas energy input, before allocating costs to any useful heat production. At a gas price of €35/MWh, the implied fuel cost would be approximately €64/MWh of electricity, excluding variable operating expenses, network charges, financing and applicable carbon-related costs.
This calculation is illustrative rather than a forecast for the Niš project. Its operating economics will depend substantially on the difference between electricity revenues and fuel expenditure, which will influence how frequently the plant can generate profitably.
Flexible Generation and Electricity Sales
The proposed plant could provide balancing capacity as Serbia expands wind and solar generation. Gas-fired combined-cycle units can adjust output more readily than conventional coal-fired units, although their operational flexibility depends on turbine design, minimum stable output, ramping capabilities and maintenance requirements. For EPS, additional flexible generation could help reduce reliance on electricity imports when domestic renewable or hydropower production is weak. The facility could also contribute to system stability during unexpected outages or periods of high demand.
At the same time, increasing renewable generation is changing wholesale electricity price patterns across Southeast Europe. Strong solar output can depress midday prices, while higher evening demand may create more favourable conditions for flexible generators. The plant’s commercial performance will therefore depend on whether it is designed for continuous operation, flexible dispatch or a combination of electricity generation and contracted heat production.
Potential revenue sources include wholesale electricity sales, bilateral supply agreements and balancing services, where permitted under applicable market rules. A business model based heavily on merchant electricity sales would expose investors to price volatility. Long-term electricity purchase agreements or appropriately structured availability arrangements could provide greater revenue certainty. No such agreements have been publicly confirmed for the project.
Proposed Thermal Output Adds a Second Revenue Stream
The planned 150 MW thermal component could support combined heat and power production, allowing useful heat recovered from electricity generation to improve overall fuel utilisation and reduce the need for separate heating facilities. Potential customers in Niš could include district-heating networks and large industrial consumers. Commercial deployment would require suitable infrastructure connections, sufficient demand and agreements covering supply volumes, tariffs and seasonal delivery requirements.
Unlike electricity, which can be traded through the transmission network, heat generally requires customers to be physically connected to the generating facility. The project’s thermal economics will consequently depend on its location relative to existing heating infrastructure and potential industrial users. Where substantial heat demand is available, cogeneration could improve overall project returns. Limited or seasonal demand would leave electricity sales as the principal source of revenue.
The investment case will therefore need to establish how much of the proposed thermal capacity can be sold commercially, rather than assuming that the full output will automatically find a market.
Investment Budget and Financing Structure Remain Undisclosed
The partners have not disclosed the project’s total capital expenditure or the proposed balance between equity and debt financing. A combined-cycle power plant requires substantial upfront investment in turbines, generators, boilers, cooling systems, grid connections and gas infrastructure. Additional expenditure could cover heat transmission, water systems, environmental controls and site preparation.
Lenders will assess the final engineering configuration, construction costs, contractor guarantees and projected operating performance before determining whether the project can support long-term borrowing. A combination of shareholder equity and long-term debt is a potential financing approach, but no completed financing structure has been announced. Other outstanding questions include whether state guarantees will be sought, which entity will purchase the electricity, how gas-price exposure will be allocated and whether long-term commercial contracts will support revenue generation.
Carbon-related costs will also form part of the investment assessment. Although gas-fired generation generally produces less carbon dioxide per unit of electricity than conventional coal-fired generation, it remains dependent on fossil fuels.
Future Serbian climate policies and European electricity-trade rules could affect the competitiveness of the plant’s output. For electricity exported to the European Union, any applicable carbon-border treatment would depend on the relevant Carbon Border Adjustment Mechanism (CBAM) rules and the specific transaction, rather than automatically subjecting the Serbian generator to the EU Emissions Trading System. These factors will be relevant to an asset expected to operate well into the 2040s.
Project Development and Permitting
The joint venture brings together foreign participation and Serbian state-owned energy companies in a proposed power-generation business that could operate through merchant electricity sales, contracted supply or combined heat and power production. The project could also create work for engineering contractors, turbine suppliers, gas infrastructure companies and industrial users in southern Serbia.
Government approval of the shareholder arrangements does not constitute a final investment decision or confirm that construction will proceed. Further milestones include incorporating the joint venture, completing feasibility studies, finalising the technical design, obtaining permits and securing a financeable commercial model.
For Serbia, the proposed 500 MW combined-cycle facility would add a substantial source of flexible generating capacity and could support industrial electricity supply. For SOCAR, the project offers an opportunity to expand its participation in the Serbian energy market beyond gas deliveries. The investment will depend on the interaction between gas procurement costs, electricity revenues, heat demand and capital expenditure, as well as the partners’ ability to agree on financing, contractual commitments and the allocation of project risks.
