Montenegro has the physical geography to become a regional electricity hub, but converting that position into an investable energy strategy will require considerably more than adding solar and wind capacity. The country must simultaneously strengthen its transmission network, introduce storage, complete market integration, protect the flexibility of its hydropower fleet and establish a commercially credible route for low-carbon electricity exports to Italy and neighbouring markets.
Remon Zakaria, head of the European Bank for Reconstruction and Development’s office in Montenegro, has identified the country’s combination of hydropower, wind, solar resources, regional interconnections and the submarine cable to Italy as the basis for a broader energy role. The EBRD sees Elektroprivreda Crne Gore, or EPCG, as the principal domestic partner for delivering that transition, with the Gvozd wind farm providing the clearest current example.
The bank originally provided €82mn for Gvozd in 2023 and later added another €26mn to expand the project from 55MW to 75MW. The enlarged wind farm is expected to produce approximately 186GWh annually, sufficient to supply more than 35,000 households, with commissioning scheduled by the end of 2026.
Gvozd matters because it is EPCG’s first major new generating asset in more than four decades and the utility’s first wind project. It also establishes a procurement, construction and financing template that can be reused—subject to the lessons emerging from delivery—for subsequent wind, solar and storage investments.
The regional-hub argument starts with the 600MW Montenegro–Italy interconnector between Lastva and Villanova. Montenegro is also interconnected with Serbia, Bosnia and Herzegovina, Albania and Kosovo. Electricity transit through the Montenegrin transmission system reached approximately 5,410GWh in 2024, showing that the country is already an important physical corridor even before a large new renewable portfolio is connected.
The cable’s strategic value is larger than its capacity number. Italy is a deeper and generally higher-value electricity market than Montenegro’s domestic system. Direct access can provide a route for renewable exports, cross-border optimisation and price arbitrage, while the Balkan interconnections allow electricity to flow between hydro-, coal-, solar- and wind-dominated systems.
CGES’s transmission-development plan retains the possibility of a second 600MW HVDC pole, which would theoretically double the Italy–Montenegro link to 1.2GW. That development is associated with wider Balkan transmission reinforcement and cannot be treated as an isolated cable project. Its investment case depends on sufficient generation and transit flows, stronger internal networks and coordinated development involving CGES, Terna and neighbouring transmission operators.
Montenegro’s present electricity balance explains the urgency. Domestic consumption is around 3,000GWh annually, while production remains highly exposed to hydrology and the availability of the 225MW Pljevlja thermal power plant. Generation totalled approximately 3,447GWh in 2024, down 15% because of weaker hydrological conditions.
The vulnerability became more visible in 2025, when Pljevlja was unavailable for an extended environmental reconstruction and hydro output was weak. EPCG imported around 1,341GWh, spending approximately €142mn on electricity purchases. The utility moved from an €11mn profit in 2024 to a reported €92mn loss in 2025, while short- and long-term borrowing increased to finance imports.
This experience places the energy-hub concept in a more realistic setting. Montenegro cannot build an export strategy around annual renewable averages while remaining financially exposed during dry years, plant outages and winter shortages. A credible hub needs enough flexible capacity to manage hourly and seasonal imbalances, not merely enough generation to produce an annual surplus on paper.
Hydropower provides Montenegro with a valuable starting advantage. EPCG operates the 307MW Perućica and 342MW Piva hydropower plants. These assets are economically different from variable renewable generation: within water and operational constraints, they can shift production towards periods of higher demand and prices. As solar capacity grows, hydro can conserve water during low-price midday periods and generate into evening peaks.
That flexibility carries regional value. A megawatt-hour supplied during a tight evening hour is worth more to the system than another unit of solar electricity arriving during an already saturated midday period. Protecting reservoir optionality, modernising turbines and improving inflow forecasting may therefore produce higher returns than headline capacity additions suggest.
Wind must also be treated separately from solar. Montenegro’s operating wind fleet includes the 72MW Krnovo and 46MW Možura projects, while Gvozd will add another 75MW. New wind farms generally require more capital and longer development periods than solar, but they can achieve capacity factors of approximately 32–40% at strong Montenegrin sites and provide a production profile that is less concentrated in the midday hours.
Indicative wind CAPEX is likely to fall within €1.3mn–€1.7mn per MW, with higher figures possible for mountainous sites, difficult transport routes, extensive grid works or complex foundations. A 200MW wind portfolio could therefore require €260mn–€340mn, excluding major transmission reinforcement.
Bankable wind projects supported by an auction, long-term corporate power-purchase agreement or floor-price structure could target equity returns in the region of 9–13%, depending on leverage, resource quality and connection risk. Commercial lenders would ordinarily seek a minimum debt-service coverage ratio of around 1.25–1.40, with stronger requirements for projects carrying merchant price exposure.
Wind curtailment behaves differently from solar curtailment. Wind output is spread more widely across hours and seasons and may coincide with winter demand and stronger regional prices. A 5% loss of annual wind production could reduce equity IRR by roughly 60–120 basis points, while 10% curtailment could remove around 150–250 basis points, depending on debt structure and whether compensation is available.
A 12-month grid delay could reduce a wind project’s equity IRR by approximately 120–200 basis points through additional interest during construction, extension costs and deferred revenue. An 18-month delay could remove 200–280 basis points, particularly when turbine-supply payments have already been made and debt is accruing before commercial operation.
Solar offers faster deployment and lower unit costs. EPCG’s direct pipeline includes around 221MW of utility-scale solar and approximately 209MW of rooftop and prosumer installations. Montenegro has also prepared a first competitive auction for around 250MW of solar PV, within a wider commitment to publish a three-year auction plan for at least 400MW of renewable capacity by 2027.
Utility-scale solar CAPEX can be modelled at approximately €650,000–€850,000 per MW, depending on land, connection works, terrain, equipment specifications and environmental requirements. Developing 400–600MW would therefore require approximately €260mn–€510mn before substantial upstream-grid reinforcement.
Solar’s challenge is its production concentration. Large projects in Montenegro, Albania, Greece, North Macedonia and southern Italy will often generate during the same hours. As regional capacity rises, midday prices will become more volatile and may turn negative more frequently. The average captured price of a solar plant can fall well below the baseload market price even when annual electricity prices appear attractive.
A competitively procured solar project with predictable connection and a bankable support structure could produce an equity IRR of approximately 8–11%. Projects combining merchant sales with a credible industrial PPA or export-oriented hedging structure could reach 10–13%, but those returns should not be underwritten solely on historical day-ahead prices.
A 5% solar curtailment rate could remove approximately 80–150 basis points from equity IRR. At 10%, the impact could rise to 180–300 basis points, particularly where production losses occur during the project’s highest-priced delivery periods or where debt repayment assumes an aggressive P50 generation case.
Grid delay is equally damaging. A 12-month postponement can reduce solar equity IRR by approximately 100–200 basis points, while an 18-month delay may remove 180–300 basis points. The smaller construction cost of solar does not eliminate the effect because the project earns no revenue while development expenditure, land costs, financing fees and equipment commitments continue.
Solar investors will consequently require more than a nominal connection approval. Lenders will expect an executed connection agreement, clear responsibility for substation and line construction, evidence that land and permitting rights remain valid through the revised schedule, and a curtailment study based on realistic regional dispatch—not merely the project’s isolated output.
Battery storage is the missing balancing layer. EPCG previously sought to procure two systems with a combined rating of 60MW/240MWh, representing four hours of storage, with an investment requirement discussed in the range of approximately €48mn–€59mn. The procurement was cancelled after financing and approval complications, and a second tender attracted no bids.
The failed procurement is instructive. Storage cannot be delivered by declaring a megawatt target alone. The tender must define the commercial model, grid-connection rights, dispatch control, degradation assumptions, warranty requirements, fire-safety standards and the revenue streams available to the owner.
EPCG has subsequently signed a cooperation memorandum with Japan’s PowerX targeting as much as 500MWh of battery capacity over three years. That could become a meaningful platform, but a memorandum is not yet an investment decision. The projects will need site-specific feasibility studies, procurement arrangements, financing and a route to revenues from arbitrage, balancing, ancillary services and renewable-energy integration.
At current market conditions, four-hour battery systems can be modelled at approximately €180–€280 per kWh, producing a CAPEX range of €43mn–€67mn for 240MWh and €90mn–€140mn for 500MWh. Returns are highly sensitive to market design. A battery able to combine day-ahead arbitrage, intraday trading, balancing and reserve services may target an unlevered return of 8–14%. Arbitrage alone is unlikely to support attractive debt financing until price spreads and operational history become more predictable.
Storage can materially reduce solar curtailment, but it does not eliminate network constraints. A battery located behind the same congested connection as a solar plant can absorb excess output only until it is full. Duration, charging rights and grid location matter as much as installed power.
EPCG’s direct development portfolio has been estimated at approximately 639MW/MWp, with projected investment of around €646.5mn and annual production of about 1,024GWh. This includes utility solar, rooftop systems, Gvozd wind, hydro projects and 60MW of battery operating power. When potential private and strategic partnerships are included, the stated project universe exceeds 4.6GW, although much of that larger figure remains at an earlier and less certain stage.
The potential joint venture between EPCG and Abu Dhabi-based Masdar could add financial strength and international development experience. The proposed cooperation covers solar, wind, hydropower, battery storage and hybrid plants, with the Italy cable presented as a route for green electricity exports. Masdar already has knowledge of Montenegro through its earlier interest in the Krnovo wind project.
A realistic base-case energy programme through the end of the decade would involve approximately 600–1,000MW of new generation and storage projects reaching construction or operation, without double-counting auction projects already included in EPCG or private-developer pipelines. This could comprise 400–600MW of solar, 150–250MW of wind, 60–150MW of battery power with 240–600MWh of capacity, together with hydro modernisation.
The associated base-case investment envelope would be approximately €700mn–€1.5bn, including €260mn–€510mn for solar, €195mn–€425mn for wind, €50mn–€150mn for storage and at least €200mn–€400mn for transmission, distribution and connection infrastructure.
An upside scenario would involve 1.5–2.5GW of new renewable generation by the early 2030s, supported by 800–1,600MWh of storage, stronger regional lines and progress on the second Italy cable pole. Such a programme could require €1.7bn–€3.9bn, depending on the balance between solar and wind, the proportion of grid costs included and the complexity of mountainous connections.
The upside case is not bankable under the existing network alone. CGES must develop substations, internal 400kV and 110kV corridors, reactive-power capability, digital control, forecasting and cross-border capacity. Distribution investment is equally important because rooftop solar and smaller plants connect below the transmission level and can create local voltage and reverse-flow constraints.
The 600MW Italy cable should not be treated as capacity reserved for Montenegrin generators. It operates within regional market and transmission-allocation arrangements and can carry wider Balkan flows. New projects must model actual available transfer capacity, congestion costs and the risk that higher-priced Italian hours are not accessible when the regional network is constrained.
Market coupling will improve price formation and cross-border access but will also expose Montenegrin generators more directly to European volatility. Developers should expect more low and negative prices during renewable-surplus hours, alongside high prices when hydro conditions are weak, wind output falls or thermal availability tightens.
Electricity exports into the EU also face a carbon-documentation test. Montenegro cannot transform coal-based regional power into “green” electricity merely because it transits the country or crosses the Italy cable. Export-oriented projects will need source-specific metering, credible Guarantees of Origin, auditable scheduling and documentation capable of distinguishing renewable output from Pljevlja generation and imported regional electricity.
That distinction is especially important under the EU’s Carbon Border Adjustment Mechanism and Montenegro’s prospective integration with the European electricity market. Low-carbon generation can retain export value, while electricity with an embedded coal component faces a growing carbon-cost disadvantage. Hourly traceability and reliable data may therefore become part of project bankability rather than a secondary compliance exercise.
EBRD financing can help lower risk through long tenors, policy dialogue, environmental and social due diligence, and the mobilisation of commercial lenders. The bank has invested more than €1bn across 100 Montenegrin projects, giving it a central role in linking regulatory reform to investable infrastructure. Its involvement does not replace strong project preparation. Land rights, environmental assessments, grid studies, procurement, construction contracts and operational evidence must still withstand lender scrutiny.
Montenegro’s hub opportunity ultimately lies in combining different assets rather than maximising any single technology. Solar can provide low-cost daytime production; wind can contribute a higher-capacity-factor and less-correlated profile; Piva and Perućica can supply flexibility; batteries can manage short-duration volatility; CGES can monetise transmission and regional flows; and the Italy cable can provide access to a deeper European market.
The €142mn import bill in 2025 demonstrated the cost of failing to deliver that integration. Gvozd, the 250MW solar auction, EPCG’s 639MW direct portfolio, the prospective 500MWh storage programme and the possible second 600MW cable pole now form a credible development sequence. Their value will be determined by commissioning dates, connection readiness and dependable market access, not by the aggregate megawatts announced.
