Parliamentary amendments aimed at accelerating Montenegro’s wind, solar, storage and related grid projects have prompted a dispute over who bears costs of the energy transition. The changes are designed to speed up planning, environmental screening and construction procedures for renewable plants and associated infrastructure. Residents near Brezna say the framework shifts legal leverage toward developers while weakening protections for private land, water resources and rural livelihoods.
The Save Brezna civic initiative focuses on amendments to the Law on the Use of Energy from Renewable Sources alongside revisions to spatial-planning and construction legislation. The group argues the combined package enables the state to designate broad 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.
Brezna substation upgrade tied to 400 MW renewable integration
Brezna in north-western Montenegro is being upgraded from a local 110/35 kV substation into a 400/110/35 kV transmission node. The stated purpose is to accommodate up to 400 MW of additional renewable capacity. The upgrade is financed by a sovereign-guaranteed €28mn loan from the European Bank for Reconstruction and Development.
The financing package also includes Western Balkans Investment Framework grants, with €6.4mn reported for implementation and an earlier €1.1mn allocation for technical assistance. The project scope includes two 300 MVA transformers, expansion of the substation and integration with Montenegro’s emerging 400 kV ring. It is also linked to the wider Trans-Balkan transmission corridor.
The upgrade is expected to reduce network losses by about 13 GWh per year, valued at more than €1mn annually at recent wholesale electricity prices. It is also expected to cut emissions by around 6,000 tonnes of CO₂. Brezna therefore functions both as a transmission investment and as a connection point for privately developed generation.
Bijela wind farm EIA approval and connection steps
The largest project associated with the area is Alcazar Energy Partners’ 118.8 MW Bijela wind farm. The project is planned primarily in the municipality of Šavnik, with smaller components extending toward Nikšić, Plužine and Kolašin. The development is expected to include 17 turbines, associated roads, internal cables, a project substation and a 110 kV transmission line connecting it to Brezna.
The Environmental Protection Agency approved Bijela’s environmental impact assessment in February 2026. Estimated annual output is about 350 GWh, implying a capacity factor of approximately 33.6%. Alcazar acquired the project from local developers Simes Inženjering and Sistem MNE in 2023.
The project company, Vjetro Park Bijela, is controlled by Alcazar’s second investment vehicle. A connection agreement with transmission operator CGES was signed in September 2024. Negotiations over a possible power-purchase agreement with state utility EPCG began after a memorandum signed in January 2025.
Alcazar has indicated its total Montenegro investment programme could rise to $500mn, placing Bijela at the start of a broader regional portfolio. Residents argue land for Bijela and related infrastructure is already being acquired or placed under long-term rights. Save Brezna alleges some payments cover only tens or hundreds of euros for rights lasting over 30 years.
Land rights, easements and compensation process under scrutiny
The alleged compensation level depends on parcel type, affected area, ownership documentation and whether transactions involve full acquisition, lease or easement arrangements. The criticism highlights what it describes as a mismatch between long-term restrictions faced by landowners and project value measured in hundreds of millions of euros. Formal ownership may remain with households even after transmission easements, access-road corridors or turbine-safety restrictions make land unusable for certain uses.
The dispute also points to how compensation based only on narrow strips physically occupied by pylons or cables can ignore reduced value across remaining parcels. The amendments do not automatically abolish ownership rights or compensation requirements. A declaration of overriding public interest is not described as completing expropriation on its own.
The state still needs to establish legal grounds for taking land or creating an easement, define affected property and provide compensation subject to review. However, residents argue the presumption changes how burdens are allocated during decision-making. They say developers and the state no longer start by proving that a project’s public benefit outweighs competing interests.
RED III-style public-interest presumption cited in renewables law changes
The amendments include Article 11e, which appears to place 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. The language broadly follows direction set out in the EU’s revised Renewable Energy Directive, RED III. Under RED III guidance cited in the debate, EU member states presume renewable generation plus associated grid and storage infrastructure serve an overriding public interest until climate neutrality is achieved.
The presumption was introduced to reduce delays when renewable projects conflict with other environmental or land-use interests. It can be rebutted if a development would cause significant environmental effects that cannot be mitigated or compensated. Member states may restrict application by location, technology or technical characteristics.
Natura 2000 protections alongside water obligations and protected-species requirements continue to require legally defined assessments and case-specific reasoning. Montenegro is not an EU member, but Save Brezna disputes claims that immediate adoption of these specific RED III provisions was required by the Energy Community framework or the EU Growth Plan. The Growth Plan is described as more directly connected to RED II measures including auction development, prosumers and streamlined permitting.
Accelerated environmental screening timelines tied to designated zones
A further concern raised relates to Article 11d introducing decision periods within designated renewable-acceleration areas: 45 days, or 30 days for smaller projects and repowering. The deadlines are described as governing environmental screening that determines whether a full project-level assessment is required rather than compressing an entire environmental impact assessment into those timeframes.
A credible accelerated regime depends on strategic environmental assessment before areas are designated, according to the concerns raised. Baseline data should cover settlements, water sources, forests, agricultural use, protected habitats, migration corridors, geotechnical conditions and cultural heritage as well as cumulative effects from multiple projects expected to connect in the zone.
A short project-level screening can work where those issues were examined comprehensively at planning stage. It becomes risky where regional assessment remains incomplete yet shortened procedures are used despite missing baseline work.
Cumulative grid pipeline around Brezna exceeds stated integration capacity
The issue is framed as relevant at Brezna because development extends beyond Bijela alone. EBRD documentation identifies Bijela alongside proposed solar projects including Dubrovska–Duži at 195 MW, Somina solar at 240 MW, and expansion of the Gvozd wind complex among projects linked to broader grid development . Their combined nominal capacity exceeds Brezna substation’s stated integration capability of 400 MW.
The listed projects are not necessarily at identical stages and may not all be built or operate simultaneously at full output. Even so, the discrepancy is used to argue that cumulative assessment remains necessary because roads, substations, transmission corridors, foundations and construction traffic can change conditions across an entire rural area . CGES had signed six renewable connection agreements representing about 1,327 MW planned wind and solar capacity by late 2024.
This pipeline was described as larger than Montenegro’s existing conventional generation fleet and above what domestic electricity demand could absorb without substantial reinforcement plus exports storage and active congestion management . The Brezna upgrade is presented as one response rather than completion of grid works overall . Its usefulness depends on completion of associated 400 kV lines**, system studies**, protection schemes**, balancing arrangements** and reinforcement elsewhere on the network . A transformer nameplate alone does not guarantee firm connection capacity under all system conditions .
Renewables output mix affects curtailment exposure and financing assumptions
An additional 400 MW** split between wind and solar could generate approximately **900 GWh–1.2 TWh** annually depending on technology mix . This would materially reduce reliance on the **225 MW Pljevlja thermal power plant** while improving export performance during favourable periods . It would also create large hourly surpluses during windy or sunny conditions .
The undersea cable to Italy together with regional interconnectors and market coupling can provide export routes but cross-border capacity remains finite . A sunny or windy period in Montenegro often coincides with strong renewable output across Albania Croatia Greece Bulgaria and southern Italy . Export capability therefore cannot be treated as unlimited access to premium Italian prices .
Curtailment characteristics differ between high-altitude wind and solar PV windows
Bijela-type high-altitude wind is expected 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 therefore differ materially from photovoltaic plants . Solar output concentrates around midday which increases exposure to price cannibalisation as additional capacity enters markets .
Auction design parameters for Montenegro’s first utility-scale solar tranche
A set out figure for Montenegro’s first solar auction targets up to 250 MW** with a minimum project size of **400 kW** . The ceiling price was set at **€65/MWh** with a **12-year market-premium** or contract-for-difference structure . The quota could expand by up to **20%**, adding another **50 MW** under specified ranking conditions .
Solar capital costs EBITDA range under curtailment scenarios
If built at current regional construction costs described in the material 250 MW utility-scale solar would require about **€138mn–€175mn** capital based on **€550,000–€700,000 per MW** before exceptional grid reinforcement or difficult terrain . At annual generation around **400 GWh** with strike prices close to **€65/MWh**, gross contracted revenue would be roughly **€26mn** per year . Operating costs estimated at **€10,000–€15,000 per MW annually** plus land balancing insurance and asset-management could leave EBITDA around **€21mn–€23mn** before financing . Unlevered returns are described as generally falling in high-single-digit to low-double-digit ranges depending on tariff degradation curtailment and connection cost .
Curtailment impacts on revenue from solar portfolios
A five-percentage-point curtailment rate would remove about **20 GWh** from a **400 GWh** portfolio reducing annual revenue by roughly **€1.3mn** at the ceiling price . A ten-percentage-point curtailment rate would double that loss potentially reducing equity returns by **1.5–3 percentage points**, particularly where debt-service coverage is tight . A battery can shift midday output provide balancing services reduce some curtailment but storage does not create free grid capacity .
Battery sizing indicative cost assumptions for shifting PV generation
A **100 MW/200 MWh** battery would currently require indicative capital of about **€50mn–€80mn** at **€250–€400 per kWh**, excluding unusually expensive connection works . Bankability would depend on combining energy arbitrage balancing services congestion management and possibly capacity payments rather than relying on one revenue stream [no marker].
Bijela wind financial envelope links curtailment delay risk to equity returns
The material provides indicative economics for Bijela using base assumptions including capital cost around **€175mn**, net annual production near **330–335 GWh** after technical losses availability and realised price around **€68/MWh** [no marker]. Annual revenue would be about **€22.5mn–€22.8mn**, while operating expenditure estimated at **€4.5mn–€5mn** would leave EBITDA near **€18mn** [no marker]. With project debt covering roughly **65–70%** of capex at all-in interest cost between **5.5%–6.5%**, base-case equity internal rate of return could fall around **10–12%**, subject to turbine contracts financing tenor PPA structure tax treatment [no marker].
Curtailment sensitivity for Bijela output reductions [no marker]
An upside case assumes capex closer to **€165mn**, net generation approaching **345–350 GWh** and realised price between **€73–€75/MWh**, lifting annual revenue toward **€25mn–€26mn** [no marker]. EBITDA could exceed **€20mn–€21mn**, raising equity return toward **14–16%** [no marker]. These figures are described as indicative financial envelopes rather than company guidance [no marker].
Curtailment rates translate into revenue losses [no marker]
A five-percentage-point curtailment rate at Bijela would remove about **17.5 GWh** reducing annual revenue by roughly **€1.2mn–€1.3mn** at realised prices between **€68–€75/MWh** [no marker]. A ten-percentage-point reduction would cost around **€2.4mn–€2.6mn annually**, with potential equity IRR impacts depending on leverage [no marker]. Sustained curtailment of ten percent could compress returns by about **1.5–3 percentage points** [no marker].
Main near-term concern: connection delay timing versus energisation [no marker]
The more immediate risk described relates to connection delay because Brezna expansion remains in implementation with main works expected to begin during **2027** after procurement [no marker]. If a wind farm completes before transmission infrastructure is energised it would incur debt interest fixed operating costs without receiving energy revenue [no marker]. With assumed debt balance between **€115mn–€125mn**, a one-year delay at a funding cost of about **6%** produces roughly **€7mn–€7.5mn** additional interest before commitment fees guarantees insurance or preservation costs [no marker]. It would also defer gross revenue exceeding **€22mn** [no marker].
Tying delay duration to equity IRR outcomes [no marker]
A leveraged base case indicates that a twelve-month grid delay could reduce equity IRR from approximately **11–12%** down to about **8.5–10%** [no marker]. An eighteen-month delay could push returns toward **7–9%**, described as a decline around **3–4.5 percentage points** [no marker]. Losses become more severe where turbine warranties PPA milestones or loan availability periods expire before energisation [no marker].
Narrow permit changes versus lender requirements for environmental evidence [no marker]
The material notes Article 74a of construction legislation reportedly allows certain renewable installations to proceed through notification plus technical documentation without a conventional building permit [no marker]. Such treatment is described as commercially sensible for rooftop solar small prosumer installations and standardised low-risk equipment [no marker]. Applying similar logic to major generation or network assets requires clearer distinctions between small installations versus projects involving complex foundations high-voltage systems mountain roads or large areas of private land [no marker]. International lenders are said to continue requiring environmental social evidence regardless of national permit shortcuts [no marker].
Lender due diligence includes land records stakeholder engagement grievance processes [no marker]
An EBRD European Investment Bank or commercial-bank financing package typically requires land-acquisition records stakeholder engagement biodiversity studies livelihood-restoration measures plus functioning grievance processes [no marker]. A shortened domestic permit does not remove these conditions [no marker]. Weak public participation can therefore make projects less bankable rather than more because unresolved land claims can delay site access create injunction risks and undermine representations needed for loan drawdown [no marker]. Environmental challenges can also affect turbine micro-siting transmission routes construction schedules after procurement contracts have been signed [no marker].
Cumulative assessment needs published data community protections compensation approaches indexed over easements [no marker]
A credible framework described in the material pairs acceleration with mandatory sensitivity mapping published grid-hosting data enforceable community protections plus compensation mechanisms reflecting both acquired rights and loss in value across remaining property supported by independent valuation and accessible appeal options [no marker]. Long-term easements should be indexed rather than fixed in nominal terms for thirty years according to the same set out concerns [no marker]. Revenue-sharing models discussed include allocating even one percent of Bijela’s annual gross revenue which would provide about €230,000–€260,000 per year for affected communities depending on gross revenues used in calculations [no marker]. A fixed community payment model set out at €2,000 per installed MW would produce almost €238,000 annually under those assumptions [no marker].
Brezna transition economics depend on local impacts beyond temporary construction jobs [no marker]
The material says municipal tax receipts road improvements temporary construction employment are not considered full substitutes for direct community value because wind farms employ relatively few people after commissioning even if promoted job creation during construction exceeds 700–800 jobs [no marker]. It argues enduring local economics must instead rely on land payments municipal income infrastructure continued agricultural access plus measurable community benefits tied directly to site impacts [no marker]. Montenegro’s broader renewables build-out includes existing wind capacity at Krnovo Možura EPCG-backed Gvozd project planned solar auctions plus connection developments toward Italy described as part of moving from hydro-and-coal toward diversified export capability [no marker].
Siting potential identified through spatial assessment includes low-conflict areas first layer selection approach [no marker]
A recent spatial assessment identified approximately 650 MW of wind potential alongside up to 15.6 GW theoretical solar potential in areas considered relatively low conflict environmentally socially according to the material presented here [no marker]. This finding is used within the dispute framework against arguments that disputed locations must be pushed through due solely to lack of alternatives [no marker]. Low-conflict siting is presented as an initial layer for project selection while acceleration should be reserved for areas where grid access biodiversity land ownership community acceptance have already been examined according to those concerns [no marker].
Brezna role as transmission anchor depends on timely grid delivery lender scrutiny financial viability assumptions [no marker]
Brezna can serve as a transmission anchor for several hundred megawatts of new generation within Montenegro’s plans according to figures cited in this material [no marker]. Its financial value depends on timely construction credible grid studies plus wind and solar projects capable of passing lender scrutiny while planning shortcuts increase cost-of-capital risk when landowners communities challenge projects after permits turbines or financing commitments are already in place [no marker].
