Montenegro’s attempt to accelerate renewable-energy development has opened a deeper dispute over who bears the cost of the transition. Amendments adopted by parliament promise faster planning, environmental screening and construction procedures for wind, solar, storage and associated grid infrastructure. Residents around Brezna, however, argue that the framework shifts too much legal power towards developers while weakening the protection of private land, water resources and rural livelihoods.
The criticism from the Save Brezna civic initiative centres on amendments to the Law on the Use of Energy from Renewable Sources and parallel changes to spatial-planning and construction legislation. The group claims that the combined package allows the state to designate large areas for accelerated renewable development, shorten parts of the environmental process and treat private generation projects and their connections as matters of overriding public interest.
The law has implications extending well beyond one village or one wind farm. Brezna, in north-western Montenegro, is being transformed from a local 110/35 kV substation into a 400/110/35 kV transmission node intended to accommodate as much as 400 MW of additional renewable capacity. The upgrade is financed by a sovereign-guaranteed €28mn loan from the European Bank for Reconstruction and Development, accompanied by Western Balkans Investment Framework grants, including €6.4mn reported for implementation and an earlier €1.1mn technical-assistance allocation.
The project includes two 300 MVA transformers, expansion of the substation and integration with Montenegro’s emerging 400 kV ring and the wider Trans-Balkan transmission corridor. The system is also expected to reduce network losses by approximately 13 GWh a year, worth more than €1mn annually at recent wholesale electricity values, while cutting emissions by about 6,000 tonnes of CO₂.
Brezna is therefore both a public transmission investment and the connection point for privately developed generation. The legal and political difficulty lies in separating those functions. A transmission substation that improves national system security has a clearer public-interest character than every privately owned wind turbine, solar array, battery unit, access road and dedicated connection line that may use it.
The largest project associated with the area is Alcazar Energy Partners’ 118.8 MW Bijela wind farm, planned primarily in the municipality of Šavnik, with smaller project components extending towards Nikšić, Plužine and Kolašin. The development is expected to comprise 17 turbines, associated roads, internal cables, a project substation and a 110 kV transmission line connecting it to Brezna.
The Environmental Protection Agency approved the project’s environmental impact assessment in February 2026. Estimated annual output is about 350 GWh, implying a capacity factor of approximately 33.6 per cent—a plausible level for high-altitude onshore wind and materially above the expected capacity factor of utility-scale solar in Montenegro.
Alcazar acquired the project from local developers Simes Inženjering and Sistem MNE in 2023. The investment has been estimated at $200mn, equivalent to roughly €165mn–€185mn depending on procurement timing and exchange rates. The project company, Vjetro Park Bijela, is controlled by Alcazar’s second investment vehicle.
A connection agreement was signed with transmission operator CGES in September 2024, while negotiations over a possible power-purchase agreement with state utility EPCG began after a memorandum signed in January 2025. Alcazar has subsequently indicated that its total Montenegro investment programme could rise to $500mn, placing Bijela at the beginning of a wider regional portfolio rather than treating it as an isolated asset.
Residents argue that land is already being acquired or subjected to long-term rights for the wind project and its associated infrastructure. Save Brezna alleges that some proposed payments amount to only tens or hundreds of euros for rights extending over 30 years. The exact compensation depends on the type of parcel, area affected, ownership documentation and whether the transaction concerns full acquisition, lease or easement. The allegation nevertheless identifies a central weakness in the present model: landowners can face permanent restrictions while the economic value of the project is measured in hundreds of millions of euros.
Formal ownership may remain with a household even after a transmission easement, access-road corridor or turbine-safety restriction makes the land unusable for construction, tourism or some agricultural activities. Compensation based only on the narrow strip physically occupied by a pylon or cable can ignore the reduction in value of the remaining parcel.
The amendments do not automatically abolish ownership rights or compensation requirements. A declaration of overriding public interest is not, by itself, a completed expropriation. The state must still establish the legal basis for taking land or creating an easement, define the affected property and provide compensation subject to review.
Yet the presumption changes the balance of the process. The developer and state no longer begin by proving that a particular project’s public benefit outweighs competing interests. Residents instead face the burden of demonstrating that the proposed location, route or construction method creates harm that has not been properly assessed or cannot be mitigated.
Article 11e of the amended renewables framework appears to place the planning, construction and operation of renewable plants, grid connections, related network infrastructure and storage systems within a presumption of overriding public interest, public health and safety. This language broadly follows the direction of the EU’s revised Renewable Energy Directive, RED III.
The government is therefore not inventing the public-interest concept solely for Montenegro. RED III directs EU member states to presume that renewable generation and associated grid and storage infrastructure serve an overriding public interest until climate neutrality is achieved. The presumption was introduced to reduce delays where renewable projects conflict with other environmental or land-use interests.
The European framework is more conditional than a simple declaration that every renewable project should proceed. The presumption can be rebutted where a development would cause significant environmental effects that cannot be mitigated or compensated. Member states can restrict its application by location, technology or technical characteristics. Natura 2000, water and protected-species obligations continue to require legally defined assessments and case-specific reasoning.
Montenegro is not yet an EU member, and Save Brezna disputes the government’s claim that immediate adoption of these specific RED III provisions was required by the Energy Community framework or the EU Growth Plan. The Growth Plan and the country’s existing reform obligations are more directly connected to RED II, auction development, prosumers and streamlined permitting. Montenegro may legitimately choose to align ahead of a formal deadline, but early alignment should include both the acceleration mechanisms and the safeguards accompanying them.
Article 11d creates another source of concern by introducing decision periods of 45 days, or 30 days for smaller projects and repowering, within designated renewable-acceleration areas. These deadlines appear to govern environmental screening—determining whether a full project-level assessment is required—rather than compressing an entire environmental impact assessment into 30 or 45 days.
That distinction is important, but it does not eliminate the risk. A credible accelerated regime depends on high-quality strategic environmental assessment before an area is designated. Baseline data must cover settlements, water sources, forests, agricultural use, protected habitats, migration corridors, geotechnical conditions, cultural heritage and the combined effect of all projects expected to connect in the zone.
A short project-level screening can work where those questions have already been examined comprehensively at the planning stage. It becomes dangerous where the regional assessment is incomplete and the shortened procedure is used to compensate for missing baseline work.
This is particularly relevant at Brezna because the development is not limited to Bijela. EBRD documentation has identified Bijela, the proposed 195 MW Dubrovska–Duži solar project, the 240 MW Somina solar project and expansion of the Gvozd wind complex among the projects associated with the broader grid development. Their combined nominal capacity exceeds the substation’s stated 400 MW integration capability.
Not every listed project is at the same stage, and they may not all be constructed or operate simultaneously at full output. The discrepancy nevertheless shows why cumulative assessment is indispensable. Each project can appear manageable when examined alone, while their combined roads, substations, transmission corridors, foundations and construction traffic change the character of an entire rural area.
CGES had already signed six renewable connection agreements representing approximately 1,327 MW of planned wind and solar capacity by late 2024. That pipeline was larger than Montenegro’s existing conventional generation fleet and far above the amount the domestic electricity system could absorb without substantial reinforcement, exports, storage and active congestion management.
The Brezna upgrade is one response, but it is not the end of the grid programme. Its usefulness depends on the completion of associated 400 kV lines, system studies, protection schemes, balancing arrangements and reinforcement elsewhere on the network. A transformer nameplate does not guarantee firm connection capacity under every system condition.
Montenegro’s annual electricity consumption is only a few terawatt-hours. An additional 400 MW split between wind and solar could generate approximately 900 GWh–1.2 TWh a year, depending on the technology mix. That would materially reduce the country’s reliance on the 225 MW Pljevlja thermal power plant and improve electricity exports in favourable periods. It would also produce large hourly surpluses during windy or sunny conditions.
The undersea cable to Italy, regional interconnectors and market coupling can provide export routes, but cross-border capacity is finite and affected by regional production. A sunny, windy period in Montenegro often coincides with strong renewable output in Albania, Croatia, Greece, Bulgaria and southern Italy. Export capability cannot be valued as unlimited access to premium Italian prices.
Wind and solar require separate curtailment treatment. High-altitude wind such as Bijela is likely to generate across a wider range of hours, including evenings, nights and winter periods when solar output is absent. Its capacity factor and system value are therefore materially different from those of a photovoltaic plant.
Solar generation is concentrated around midday and becomes increasingly exposed to price cannibalisation as additional capacity enters the market. A 250 MW solar auction portfolio operating at a capacity factor of 18–20 per cent could produce 394–438 GWh annually, much of it during a relatively narrow daily window. Simultaneous completion of several solar projects would create sharper congestion and more negative-price exposure than an equivalent amount of geographically dispersed wind.
Montenegro’s first solar auction was designed for up to 250 MW, with a minimum project size of 400 kW, a ceiling price of €65/MWh and a 12-year market-premium or contract-for-difference structure. The quota could be expanded by as much as 20 per cent, adding another 50 MW under specified ranking conditions.
At current regional construction costs, 250 MW of utility-scale solar would require approximately €138mn–€175mn of capital, based on €550,000–€700,000 per MW before exceptional grid reinforcement or difficult terrain. At annual generation of about 400 GWh and a strike price close to €65/MWh, gross contracted revenue would be approximately €26mn a year.
Operating costs of €10,000–€15,000 per MW annually, together with land, balancing, insurance and asset-management costs, could leave project-level EBITDA of around €21mn–€23mn before financing. Unlevered returns would generally fall in the high-single-digit to low-double-digit range, depending on the winning tariff, degradation, curtailment and connection cost.
Solar projects bidding materially below the €65/MWh ceiling would need inexpensive land, strong irradiation, low-cost debt and limited grid charges. A five-percentage-point curtailment rate would remove approximately 20 GWh from a 400 GWh portfolio, cutting annual revenue by roughly €1.3mn at the ceiling price. A 10 per cent curtailment rate would double that loss and could reduce equity returns by 1.5–3 percentage points, particularly where debt-service coverage is tight.
A battery can shift part of the midday output, provide balancing services and reduce some curtailment, but storage is not free grid capacity. A 100 MW/200 MWh battery would currently require an indicative €50mn–€80mn of capital at €250–€400 per kWh, excluding unusually expensive connection works. Its bankability would depend on combining energy arbitrage, balancing services, congestion management and possibly capacity payments rather than relying on a single revenue stream.
Bijela’s wind economics are different. Using a base capital cost of €175mn, net annual production of approximately 330–335 GWh after technical losses and availability, and a realised price of €68/MWh, annual revenue would be about €22.5mn–€22.8mn. Operating expenditure of €4.5mn–€5mn would leave EBITDA near €18mn.
With project debt covering around 65–70 per cent of capital expenditure at an all-in interest cost of 5.5–6.5 per cent, this base case could support an equity internal rate of return in the region of 10–12 per cent, subject to the final turbine contract, financing tenor, PPA structure and tax treatment.
An upside case with capital expenditure closer to €165mn, net generation approaching 345–350 GWh and a realised price of €73–€75/MWh would raise annual revenue to approximately €25mn–€26mn. EBITDA could exceed €20mn–€21mn, lifting the equity return towards 14–16 per cent.
These are indicative financial envelopes rather than company guidance. They illustrate why the classification of grid, land and permitting risk is commercially decisive. A project with attractive wind resources can lose much of its equity premium if its connection arrives late or legal challenges prevent full access to the site.
A 5 per cent curtailment rate at Bijela would remove about 17.5 GWh of output and reduce annual revenue by approximately €1.2mn–€1.3mn at realised prices of €68–€75/MWh. A 10 per cent reduction would cost around €2.4mn–€2.6mn annually. Depending on leverage, the first could reduce the equity IRR by roughly 0.7–1.5 percentage points, while sustained curtailment of 10 per cent could compress returns by 1.5–3 percentage points.
The more immediate risk is connection delay. The Brezna expansion remains in implementation, with main works expected to begin during 2027 after procurement. A wind farm completed before the transmission infrastructure is energised would incur debt interest and fixed operating costs without receiving energy revenue.
On an assumed debt balance of €115mn–€125mn, a one-year delay at a 6 per cent funding cost produces €7mn–€7.5mn of additional interest before allowing for commitment fees, guarantees, insurance and preservation of installed equipment. The project would also defer gross revenue of more than €22mn.
Under a leveraged base case, a 12-month grid delay could reduce the equity IRR from approximately 11–12 per cent to around 8.5–10 per cent. An 18-month delay could push it towards 7–9 per cent, a decline of roughly 3–4.5 percentage points. The loss becomes more severe where turbine warranties, PPA milestones or loan availability periods expire before energisation.
This is why a fast-track renewables law cannot substitute for a synchronised grid-delivery plan. Accelerating the generation permit while the substation, overhead line and system studies remain behind schedule merely moves risk from the state’s administrative timetable into the project-finance structure.
The new Article 74a of the construction legislation reportedly allows certain renewable installations to proceed through notification and technical documentation without a conventional building permit. Such treatment is commercially sensible for rooftop solar, small prosumer installations and standardised low-risk equipment. Applying a similar philosophy to major generation or network assets requires a much more precise distinction between small installations and projects involving complex foundations, high-voltage systems, mountain roads and large areas of private land.
International lenders will continue to require environmental and social evidence regardless of what national legislation allows. An EBRD, European Investment Bank or commercial-bank financing package typically requires land-acquisition records, stakeholder engagement, biodiversity studies, livelihood-restoration measures and a functioning grievance process. A shortened domestic permit does not remove these conditions.
Weak public participation can therefore make a project less bankable rather than more. Unresolved land claims delay site access, create injunction risk and undermine the representations on which loan drawdown depends. Environmental challenges can affect turbine micro-siting, transmission routes and construction schedules after procurement contracts have been signed.
A credible framework would pair acceleration with mandatory sensitivity mapping, published grid-hosting data and enforceable community protections. Land compensation should reflect both the rights acquired and the loss in value of the remaining property, supported by independent valuation and an accessible appeal mechanism. Long-term easements should be indexed rather than fixed in nominal terms for 30 years.
Revenue-sharing would also change the local economics. Allocating even 1 per cent of Bijela’s annual gross revenue would provide approximately €230,000–€260,000 a year for affected communities. A fixed community payment of €2,000 per installed MW would produce almost €238,000 annually. Either model would be small relative to project revenue but substantial for rural settlements facing the permanent visual and land-use effects of the development.
Municipal tax receipts, road improvements and temporary construction employment are not a full substitute for direct community value. The project has been promoted as creating more than 700–800 construction jobs, but wind farms employ relatively few people after commissioning. The enduring local bargain must therefore be built around land payments, municipal income, infrastructure, continued agricultural access and measurable community benefits.
Montenegro has a strong economic case for building renewable generation. Existing wind capacity at Krnovo and Možura, the EPCG-backed Gvozd project, the planned solar auctions and the connection to Italy give the country a plausible route from a hydro-and-coal system towards a more diversified export platform. A recent spatial assessment identified approximately 650 MW of wind and as much as 15.6 GW of theoretical solar potential in areas considered to have relatively low environmental and social conflict.
That finding weakens the argument that projects must be pushed through disputed locations because Montenegro lacks alternatives. Low-conflict siting should become the first layer of project selection, with acceleration reserved for areas where grid access, biodiversity, land ownership and community acceptance have already been examined.
Brezna can become the transmission anchor for several hundred megawatts of new generation. Its financial value depends on timely construction, credible grid studies and wind and solar projects capable of surviving lender scrutiny. The transition will carry a higher cost of capital when planning shortcuts leave landowners and communities to challenge projects after permits, turbines and financing commitments are already in place.
