Serbia’s renewable-energy association has warned that regulatory changes could freeze a new investment cycle for at least four years, leaving more than 1.15 GW of wind and solar projects exposed to permitting delays, stranded development costs and expiring bank guarantees.
The Renewable Energy Sources of Serbia Association, known as OIE Srbija, submitted proposals to the Ministry of Mining and Energy seeking amendments to electricity-supply regulations and parts of the Energy Law.
The association said recent changes postpone the preparation of grid-connection studies for variable renewable projects until the fourth quarter of 2029. Because a connection study is the first formal step in determining whether and under what conditions a power plant can join the transmission system, the delay effectively prevents new wind and solar developments from entering the grid process.
Projects already holding connection studies also face difficulties. According to information collected from association members, developments with combined capacity above 1.15 GW are threatened by delays involving planning authorities, permit-issuing institutions and inconsistent application of construction legislation.
Investors have deposited bank guarantees of approximately €29 million with Serbia’s transmission-system operator under the newer connection procedure. These guarantees tie up credit capacity and liquidity even when delays arise from public authorities rather than from the project companies.
The affected capacity is commercially significant. OIE Srbija has not disclosed the exact division between solar and wind or identified all project sponsors, making it impossible to calculate a definitive investment value. Based on prevailing regional development costs, the pipeline could represent approximately €800 million to €1.4 billion of potential capital expenditure, depending on the technology mix, grid works and storage requirements.
An illustrative base case comprising roughly 70% solar and 30% wind would imply around 805 MW of solar and 345 MW of wind. At indicative construction costs of €600,000–€750,000 per MW for utility-scale solar and €1.25–€1.55 million per MW for onshore wind, combined investment would be around €915 million to €1.14 billion before major transmission reinforcement.
A more wind-intensive upside-generation case, with the portfolio divided equally between solar and wind, would require roughly €1.06 billion to €1.32 billion. It would cost more to build but produce a larger and more diversified volume of electricity because wind farms generally operate at substantially higher capacity factors than solar plants.
The distinction matters for Serbia’s electricity system. Solar projects are faster and cheaper to construct but concentrate production around daylight hours, increasing exposure to low midday prices and solar-specific curtailment. Wind farms require more capital, longer development periods and more complex environmental studies, but their output is spread across a broader part of the day and year.
A Serbian utility-scale solar project may achieve a capacity factor of roughly 14–17%, while a well-sited onshore wind farm can reach around 28–38%. The same megawatt of wind capacity can therefore produce approximately twice as much annual electricity as solar, although output remains variable and location-dependent.
Operating costs also differ. Annual solar OPEX is typically equivalent to about 1.2–1.8% of initial CAPEX, while wind operating expenditure can reach 2.5–3.5%, reflecting turbine maintenance, component replacement and more demanding access requirements.
Under current regional financing conditions, commercially viable solar projects with secure grid access and long-term offtake could target levered equity returns of roughly 9–12%. Wind projects may require around 10–14%, depending on wind resource, turbine procurement, balancing exposure and the terms of the power-purchase agreement.
Those returns deteriorate quickly when grid access is delayed. A 12–18 month postponement can reduce equity IRR by approximately 1.5–3 percentage points, depending on leverage and whether construction has started. The effect comes from deferred electricity sales, additional development expenses, higher capitalised interest and the cost of extending land, equipment and bank-guarantee arrangements.
Projects with short-dated permits or fixed-price supply contracts face additional exposure. Turbine, transformer and cable prices may change before construction, while equipment reservations can expire. Developers may also lose contracted grid capacity or be required to repeat technical studies under revised network assumptions.
Curtailment is another critical variable. A persistent 5% reduction in saleable output could cut solar equity returns by around 0.7–1.2 percentage points and wind returns by roughly 0.5–0.9 points, although the exact effect depends on market prices during curtailed hours. Solar is generally more exposed to simultaneous generation and midday price cannibalisation, while wind retains greater system value when production occurs outside the solar peak.
Serbia’s transmission and distribution networks are already processing a large volume of connection requests. The central challenge is no longer simply adding renewable capacity but determining which projects are technically mature, financially credible and compatible with planned network reinforcement.
Bank guarantees were introduced partly to deter speculative applications that reserve grid capacity without a realistic construction plan. The association’s objection is that credible developers can now be penalised for delays caused by institutions over which they have no control.
A blanket pause until late 2029 could also create a distorted development cycle. Rather than allowing projects to advance gradually as the network is upgraded, it risks producing a new wave of simultaneous applications and construction pressure at the end of the decade.
The freeze comes as Serbia prepares for higher electricity demand and the gradual retirement or reduced availability of ageing coal assets. Domestic wind and solar production would reduce exposure to imported electricity and fuel prices, but neither technology can replace dispatchable generation without storage, flexible thermal or hydro capacity, stronger regional interconnection and more active demand management.
Battery storage could ease part of the constraint, especially for solar, by moving production away from periods of grid congestion. Yet storage requires clear rules covering connection rights, charging from the network, market participation and balancing responsibility. Adding batteries cannot compensate for the absence of a connection study or an unavailable transmission node.
The association has asked the government to protect projects delayed by public authorities, revise the May 2026 regulation and reopen a workable route for new connection studies before 2029. It has submitted proposed amendments to both the regulation and the Energy Law.
The immediate financial exposure extends beyond the €29 million in guarantees. Development capital spent on land rights, measurements, environmental studies, engineering and permits remains at risk, while Serbia may lose a renewable investment cycle potentially exceeding €1 billion. The projects can wait on paper; Serbia’s future electricity deficit and ageing generation fleet will not.
