Montenegro’s long-delayed Brajići wind farm has returned to the active permitting pipeline after project company Vjetroelektrana Budva submitted documentation for an environmental-impact screening procedure covering a plant of up to 100.8 MW across the municipalities of Budva and Bar.
The filing, published by Montenegro’s Environmental Protection Agency on July 17, 2026, represents an important procedural step but does not amount to environmental consent or construction approval. The agency must first determine the requirement and scope for a full Environmental Impact Assessment, after which the developer would need to complete more detailed biodiversity, landscape, cultural-heritage and engineering studies.
The preliminary design allows for as many as 18 wind turbines, each with capacity of up to 6 MW. The environmental documentation uses the Vestas V150-5.6 MW platform as the reference configuration, with a 150-metre rotor diameter, although the turbine model, number of units and final layout remain open. Both 18-turbine and 14-turbine configurations have been considered, with the final arrangement to be determined through the main design after geotechnical, geological and environmental investigations.
This flexibility is commercially useful but also underlines the project’s early technical maturity. The submitted configuration is not yet an investment-grade final design. Turbine positions, access roads, crane platforms, foundations, the permanent land footprint, transformer substation and precise grid-connection solution still require development and verification.
The proposed site extends along a mountainous ridge between Paštrovska Gora and Crmnica, at elevations of approximately 800 to 1,130 metres. It covers cadastral areas including Brajići, Kuljače, Utrg, Ovtočići, Tomići and Brčeli, divided between Budva and Bar. The broader project envelope is approximately 447.3 hectares, although only a smaller part would be permanently occupied by turbine foundations, access roads, service platforms, the substation and associated infrastructure.
The distinction between the wider development envelope and the permanent footprint will be central to the environmental review. The project’s original land-lease arrangement covered approximately 235,462 square metres of state land, or around 23.5 hectares, considerably less than the total area now examined in the environmental documentation. The ultimate permanent footprint will depend heavily on road geometry, slope stabilisation, turbine transport requirements and the amount of terrain modification needed for crane operations.
The ridge offers a commercially credible wind resource. Measurements were undertaken using a 72-metre meteorological mast, while the submitted documentation indicates an average measured wind speed of approximately 6.32 metres per second at 72 metres. Extrapolation to a 120-metre hub height produced a mean wind speed of around 7.3 metres per second, with recorded ten-minute values ranging from 0.48 metres per second to 26.14 metres per second.
These figures support continued development, although a bankable energy-yield assessment will require a longer measurement record, correlation with long-term reference data, turbine-specific power curves, wake-loss calculations and an independent assessment of technical availability, electrical losses, icing, turbulence and curtailment. The ridge’s exposed position may improve production but also increases engineering demands for foundations, logistics, lightning protection, high-wind shutdown protocols and winter access.
The project’s earlier development case envisaged annual production of about 220 GWh, equivalent to a net capacity factor of approximately 24.9 per cent at the full 100.8 MW capacity. That output was presented as sufficient to supply more than 50,000 households. The capacity factor is not unusually aggressive for the region, but it will need to be reconciled with the more recent wind measurements and the final turbine selection. A modern large-rotor turbine layout could potentially raise net output above the original estimate, although environmental setbacks, reduced turbine numbers or grid constraints could move production in the opposite direction.
Brajići was awarded through a state process to a German-Montenegrin consortium led by wpd, with Vjetroelektrana Budva acting as the local project vehicle. The original commitment contemplated an investment of €101.3 million, alongside approximately €21.6 million of participation by domestic companies. A 30-year land lease was signed in August 2020, with an annual state-land rental rate of €2.50 per square metre.
Applied to the approximately 235,462 square metres covered by the original lease, that rate implies baseline annual land payments of about €589,000, or roughly €17.7 million over 30 years before indexation or contractual adjustments. Taxes, concession-related payments and wider fiscal contributions were expected to lift the state’s total receipts above the lease component alone.
The original €101.3 million investment figure now looks more like a historical tender commitment than a reliable 2026 construction budget. It equates to just over €1 million per MW, a level that leaves limited room for contemporary turbine pricing, mountainous civil works, transport modifications, transformer and grid infrastructure, financing costs, environmental mitigation and escalation accumulated during the project’s extended development period.
A current preliminary financial envelope would place total capital expenditure closer to €145 million–€180 million, or approximately €1.44 million–€1.79 million per MW. The lower end would require a competitive turbine supply agreement, limited grid reinforcement, efficient road design and controlled foundation quantities. The upper end becomes plausible where extensive access-road reconstruction, karst-related foundation treatment, slope stabilisation, additional grid works or environmental redesign are required.
Under a base operating scenario of 220 GWh of annual net generation and a realised electricity price of €72 per MWh, Brajići could generate gross annual electricity revenue of approximately €15.8 million. Depending on turbine service costs, insurance, balancing exposure, land payments, grid charges, environmental monitoring and site operations, annual operating expenditure could reach €4 million–€5 million, leaving indicative operating cash flow before debt service of around €11 million–€12 million.
With capital expenditure around €155 million, debt funding of approximately 60–65 per cent and an all-in borrowing cost in the region of 5.5–6.5 per cent, this base case would probably support a levered equity return in the low double digits, broadly around 10–13 per cent. That is potentially financeable, but it would leave limited tolerance for sustained low prices, construction overruns or a prolonged grid delay.
An upside case based on 235–240 GWh of annual production and a realised price of around €85 per MWh would lift annual revenue towards €20 million–€20.4 million. Operating cash flow could then reach approximately €15.5 million–€16.5 million, supporting a potential equity internal rate of return of around 15–18 per cent, subject to the final financing structure and timing of debt drawdown. These are analytical project scenarios rather than forecasts issued by the developer.
The absence of a guaranteed feed-in tariff means Brajići’s bankability will depend on a combination of merchant-price assumptions, a long-term power-purchase agreement or a structured route-to-market contract. The original project was explicitly designed to operate without state subsidies and guaranteed purchase prices, placing market risk with the investor.
A corporate PPA with an industrial buyer could improve debt capacity, particularly where the buyer requires renewable electricity for export-related decarbonisation or future carbon-cost management. Montenegro’s physical interconnection with regional markets and the submarine cable towards Italy creates broader commercial optionality, but export value cannot be assumed without modelling congestion, transmission losses, balancing costs and availability of cross-border capacity.
Wind generation has a different market profile from Montenegro’s rapidly expanding solar pipeline. Brajići should produce a larger share of its output during winter and shoulder periods, when hydrological conditions, heating demand and regional power prices can be more supportive. It is also less exposed than solar to concentrated midday output and price cannibalisation. That gives wind greater system value, but it does not remove curtailment risk.
Montenegro’s transmission pipeline already includes more than 1 GW of proposed wind and solar projects with grid-connection arrangements or advanced applications. CGES must therefore coordinate new capacity with substation reinforcement, system-stability requirements, balancing capability and cross-border transmission availability. Brajići’s environmental documentation refers to a new substation, underground medium-voltage collection system and a connection line, but does not yet provide a sufficiently developed final connection arrangement for a financing decision.
At a realised price of €72 per MWh, every 1 per cent of curtailed annual production would cost approximately €158,000 in lost revenue under the 220 GWh case. Curtailment of 5 per cent would remove roughly €790,000 a year, potentially reducing the equity return by around 0.6–1 percentage point, depending on debt structure and whether compensation is available. A more severe combination of network delay and operating curtailment would have a larger effect because it would weaken both cash flow and debt-service coverage.
A 12–18 month grid or permitting delay after major equipment commitments could add approximately €7 million–€14 million through interest during construction, contractual escalation, extended development costs and remobilisation. It could also defer between €16 million and €24 million of gross revenue. Depending on when debt is drawn and how turbine prices are locked, such a delay could reduce the equity IRR by approximately 1.5–3.5 percentage points.
The environmental process is likely to be at least as important to the schedule as the grid connection. The submitted documentation identifies several Natura 2000 habitat types, including Mediterranean juniper formations, pseudo-steppes, eastern Mediterranean screes and calcareous rocky slopes with specialised vegetation. It also recognises that the available fauna information remains incomplete.
The preliminary assessment identifies 42 potentially significant bird species, but acknowledges that detailed recent field surveys have not yet been completed. Bat populations are also insufficiently studied, despite bats being among the species most exposed to wind-farm collision and barotrauma risks. The documentation consequently calls for targeted baseline surveys covering species presence, population size, seasonal movement, habitat use and migration patterns before completion of a full environmental study.
These are not minor technical additions. Ornithological and bat monitoring normally needs to capture seasonal variation and may influence turbine micro-siting, rotor-clearance requirements, construction timing and operational curtailment. Sensitive flight corridors or feeding areas could require the relocation or removal of individual turbines, particularly under the more densely populated 18-unit layout.
The project documentation proposes mitigation through turbine setbacks, avoidance of important flight corridors, limited vegetation removal, daytime construction in bat-sensitive areas, reduced ultraviolet content in lighting and post-construction monitoring. Operational restrictions may be required where mortality monitoring identifies unacceptable bird or bat impacts.
Landscape and cultural-heritage concerns are more politically complex. Because the turbines would stand on elevated ridges above the coast, they would be visible from parts of the Budva and Bar hinterland, including settlements and viewpoints associated with Paštrovići and Crmnica. The developer’s documentation characterises the landscape effect as permanent, moderate and extending from the immediate site into a wider visual area.
Residents and local groups have previously opposed the project, citing possible impacts on traditional villages, cultural landscapes, archaeological locations and the visual identity of the Budva hinterland. The current documentation states that no protected cultural properties recorded in Montenegro’s Central Register lie directly within the project footprint. That finding does not dispose of the wider question of unregistered archaeological sites, potential cultural assets, historic routes and landscape context.
A credible assessment will therefore need more than a registry search. It will require archaeological fieldwork, a cultural-heritage baseline, viewshed modelling, photomontages from representative coastal and inland viewpoints and a transparent examination of cumulative landscape effects. The project’s proximity to one of Montenegro’s most valuable tourism corridors makes the quality of that work material to both permitting and social acceptance.
The documentation places the nearest potentially affected buildings at approximately 700 metres and uses international reference values of no more than 30 hours of shadow flicker per year and 30 minutes per day. It expects limited shadow-flicker exposure at the indicated distance, but the result will need to be confirmed against the final layout, turbine dimensions, topography and actual residential occupancy.
Brajići would materially expand Montenegro’s operating wind fleet, which is still centred on the Krnovo and Možura wind farms and the developing Gvozd project. Its output would strengthen the country’s ability to meet its adopted objective of raising renewables to at least 50 per cent of final energy consumption by 2030, while adding generation with a seasonal profile that complements solar and hydro.
The July 2026 filing nevertheless arrives almost six years after the land-lease agreement and well beyond the original development expectations. Brajići now has to convert a revived permitting process into a coordinated sequence of environmental consent, spatial-planning confirmation, final grid terms, detailed engineering, community engagement, construction authorisation, financing and turbine procurement. Even under an orderly process, commercial operation before 2028–2029 would require unusually disciplined delivery.
The project’s wind resource and 100.8 MW scale remain commercially relevant. Its next value-creating milestone will not be another headline capacity figure, but a final layout that reconciles energy yield with biodiversity, cultural landscape, turbine logistics and a demonstrably firm CGES connection.
