Montenegro is positioned to become a significant electricity hub in the region, but achieving this goal requires a comprehensive energy strategy beyond merely increasing solar and wind capacity. The country needs to enhance its transmission network, develop energy storage solutions, achieve market integration, maintain the flexibility of its hydropower resources, and create a viable pathway for low-carbon electricity exports to Italy and neighboring countries.
Remon Zakaria, who leads the European Bank for Reconstruction and Development (EBRD) in Montenegro, has highlighted the country’s potential based on its hydropower, wind, and solar resources, as well as regional interconnections and the submarine cable to Italy. The EBRD identifies Elektroprivreda Crne Gore (EPCG) as the key domestic partner in this transition, with the Gvozd wind farm exemplifying current efforts.
The EBRD initially invested €82 million in Gvozd in 2023 and subsequently added €26 million to expand the project from 55 MW to 75 MW. This enhanced wind farm is projected to generate around 186 GWh annually, enough to power over 35,000 households, with operations expected to commence by the end of 2026.
The significance of Gvozd lies in its status as EPCG’s first major new generating asset in over four decades and its inaugural wind project. It also establishes a model for procurement, construction, and financing that can be replicated for future investments in wind, solar, and storage technologies.
A critical component of Montenegro’s energy hub strategy is the 600 MW interconnector between Lastva and Villanova in Italy. Additionally, Montenegro is linked to Serbia, Bosnia and Herzegovina, Albania, and Kosovo. In 2024, electricity transit through Montenegro’s transmission system reached approximately 5,410 GWh, indicating its role as an essential corridor even before integrating a larger renewable portfolio.
The interconnector’s strategic importance extends beyond its capacity. Italy represents a more lucrative electricity market compared to Montenegro’s domestic system. This direct access facilitates renewable exports, cross-border optimization, and pricing arbitrage while enabling electricity flow between hydro-, coal-, solar-, and wind-dominated systems across the Balkans.
The transmission development plan by CGES includes the potential for a second 600 MW HVDC pole, which could theoretically increase the Italy-Montenegro link capacity to 1.2 GW. This development is tied to broader Balkan transmission enhancements and requires coordinated efforts among CGES, Terna, and neighboring operators.
Montenegro’s electricity balance underscores the urgency of these developments. Annual domestic consumption is approximately 3,000 GWh, while production remains vulnerable to hydrological conditions and relies heavily on the 225 MW Pljevlja thermal power plant. In 2024, total generation was around 3,447 GWh, reflecting a decline of 15% due to adverse hydrological circumstances.
This vulnerability became evident in 2025 when Pljevlja underwent extended environmental reconstruction while hydropower output was low. As a result, EPCG imported about 1,341 GWh, incurring costs of roughly €142 million. The utility transitioned from an €11 million profit in 2024 to a reported loss of €92 million in 2025, necessitating increased borrowing for imports.
This situation highlights the need for a realistic energy hub concept. Montenegro must not rely solely on annual renewable averages while facing financial exposure during dry years and outages. A credible hub requires sufficient flexible capacity to manage both hourly and seasonal imbalances rather than just achieving an annual surplus on paper.
The country’s hydropower assets present a competitive advantage. EPCG operates the 307 MW Perućica and 342 MW Piva hydropower plants. These facilities differ economically from variable renewable sources; they can adjust production according to demand fluctuations within operational constraints. As solar capacity increases, hydropower can conserve water during low-price periods and generate during peak demand hours.
This operational flexibility holds regional significance. A megawatt-hour supplied during high-demand hours commands greater value than additional solar output during saturated midday periods. Therefore, protecting reservoir options, modernizing turbines, and improving inflow forecasting may yield higher returns than merely increasing capacity.
The wind sector also warrants distinct consideration separate from solar energy. Montenegro’s existing wind projects include the 72 MW Krnovo and 46 MW Možura, with Gvozd contributing an additional 75 MW. Wind farms typically require more capital investment and longer development timelines compared to solar but can achieve capacity factors of around 32–40% at optimal sites in Montenegro.
The indicative capital expenditure (CAPEX) for wind projects ranges from €1.3 million to €1.7 million per MW, potentially leading to costs between €260 million and €340 million for a 200 MW wind portfolio, excluding substantial transmission upgrades.
Auction-supported bankable wind projects or those with long-term corporate power purchase agreements could target equity returns between 9% and 13%, contingent on leverage levels and connection risks. Commercial lenders typically seek debt-service coverage ratios between 1.25 and 1.40, particularly for projects exposed to merchant pricing volatility.
The dynamics of wind curtailment differ from those associated with solar energy. Wind generation tends to be more evenly distributed across various hours and seasons and may align better with winter demand peaks when regional prices are elevated. A reduction of annual wind production by 5% could lower equity internal rate of return (IRR) by approximately 60–120 basis points, while a decrease of 10% might reduce it further by around 150–250 basis points.
A delay of twelve months in grid connection could decrease a wind project’s equity IRR by about 120–200 basis points, while an eighteen-month delay could lead to reductions of up to 200–280 basis points.
The solar sector offers quicker deployment times at lower unit costs. EPCG’s pipeline includes around 221 MW of utility-scale solar alongside approximately 209 MW from rooftop installations. Montenegro has initiated plans for its first competitive auction targeting around 250 MW of solar PV as part of a broader commitment to publish a three-year auction plan for at least 400 MW of renewable capacity by 2027.
The CAPEX for utility-scale solar projects is estimated at about €650,000–€850,000 per MW based on variables such as land use and equipment specifications. Developing between 400–600 MW could necessitate investments ranging from approximately €260 million to €510 million before significant upstream grid enhancements.
A challenge faced by solar projects is their production concentration; large installations across Montenegro and neighboring regions often generate power simultaneously during peak sunlight hours. As regional capacity increases, midday price volatility may rise significantly. Consequently, average captured prices for solar plants might fall below baseload market rates despite seemingly attractive annual electricity prices.
A competitively procured solar project with reliable connections could yield an equity IRR ranging from about 8% to 11% and projects combining merchant sales with credible industrial power purchase agreements could reach returns between 10% and 13% ; however, these projections should not solely rely on historical pricing data.
A curtailment rate of five percent could diminish equity IRR by roughly between80–150 basis points and ten percent curtailment might increase this impact significantly depending on timing concerning high-priced delivery periods or aggressive debt repayment assumptions.
A twelve-month delay in project implementation can similarly reduce solar equity IRR by approximately100–200 basis points and an eighteen-month delay may lead to reductions ranging from180–300 basis points due largely due ongoing expenses incurred prior completion.
Solar investors will require more than basic connection approvals; lenders expect executed agreements clarifying responsibilities regarding substation construction along with valid permitting rights throughout revised schedules alongside comprehensive curtailment studies based on realistic dispatch scenarios instead relying solely on isolated outputs.
A crucial missing element within Montenegro’s energy framework is battery storage capabilities; EPCG previously aimed at procuring two systems totaling60MW/240MWh —representing four hours’ worth—at an estimated investment range between€48 million–€59 million but faced challenges leading them canceling procurement processes without securing any bids during follow-up tenders.
This experience underscores that successful storage solutions cannot simply arise from setting megawatt targets; tenders must outline commercial frameworks detailing grid connections along with dispatch controls degradation expectations warranties fire safety standards revenue streams available owners involved projects.
EPCG has since entered into a cooperation memorandum with Japan’sPowerX to explore potential development opportunities targeting up500MWh battery capacities over three years which could serve as foundational platform although yet no concrete investments have been finalized requiring feasibility studies procurement arrangements financing pathways revenue generation strategies based arbitrage balancing ancillary services renewable integration aspects involved operations moving forward .
Pursuant current market conditions four-hour batteries may incur CAPEX costs approximating€180–€280 per kWh resulting total investments ranging from€43 million – €67 million for240MWh up€90 million – €140 million for500MWh . Returns remain sensitive dependent upon design parameters whereby batteries integrating day-ahead arbitrage intraday trading balancing reserve services may target unleveraged returns approximating8-14% . Arbitrage alone however unlikely sustain favorable debt financing until price spreads become predictable over time .
Batteries can significantly mitigate issues related curtailment but do not entirely resolve network constraints; systems located behind congested connections face limitations absorbing excess output until fully charged duration charging rights grid locations matter equally installed capacities .
EPCG’s direct development portfolio encompasses approximately639MW/MWp entailing projected investments nearing€646.5mn with annual production estimates around1,024GWh . This portfolio comprises utility-scale solar rooftop systems Gvozd wind hydro projects alongside60MW battery operating power . When incorporating private strategic partnerships potential project universe exceeds4.6GW , though much remains uncertain earlier stages .
A potential joint venture involving EPCG Abu Dhabi-basedMasdar could strengthen financial backing international expertise . Proposed cooperation covers diverse areas including solar wind hydropower battery storage hybrid plant developments utilizing Italy cable facilitate green electricity exports ; Masdar already possesses familiarity Montenegrin landscape stemming previous interests Krnovo wind project .
A base-case energy program envisioned through decade-end would entail constructing or operationalizing roughly600-1 ,000MW new generation storage initiatives without double-counting auction commitments already captured either EPCG private developer pipelines comprising approximately400-600MWsolar ,150-250MWwind , 60-150MWbattery power featuring240-600MWhcapacity alongside hydro modernization efforts .
This associated investment envelope approximates€700mn-1 ,5bn covering 260mn-510mnsolar 195mn-425mnwind50mn-150mnstorage at least200mn-400mnfor transmission distribution connection infrastructure needed support expansion plans going forward .
An upside scenario anticipates introducing1 .5-2 .5GW new renewable generation early2030s bolstered by800-1600MWhstorage improved regional lines progress secondItaly cable pole requiring funding estimates ranging€1 .7bn-3 .9bn contingent upon balance between types generation proportionality grid costs complexity mountainous connections involved .
This optimistic outlook cannot be realized under present network configurations alone; CGES must develop substations internal400kV110kV corridors reactive-power capabilities digital control forecasting cross-border capacities distribution investments equally critical given rooftop systems smaller plants connecting below transmission levels creating local voltage reverse-flow constraints needing addressed effectively.
The existing600MWItaly cable should not viewed merely reserved Montenegrin generators operating under broader regional market transmission-allocation frameworks facilitating wider Balkan flows new ventures must accurately model actual available transfer capacities congestion expenses risks associated accessing higher-priced Italian hours constrained networks.
The introduction market coupling will enhance pricing formation cross-border accessibility while simultaneously exposing Montenegrin producers directly European volatility developers should anticipate experiencing lower negative pricing periods coinciding oversupply situations alongside elevated prices stemming weakened hydro conditions decreased wind outputs thermal availability constraints.
ELECTRICITY EXPORTS INTO EU FACE CARBON DOCUMENTATION CHALLENGES MONTENEGRO CANNOT SIMPLY TRANSFORM COAL BASED REGIONAL POWER INTO GREEN ELECTRICITY MERELY BY TRANSITING THROUGH COUNTRY CROSSING ITALIAN CABLE EXPORT ORIENTED PROJECTS WILL REQUIRE SOURCE SPECIFIC METERING CREDIBLE GUARANTEES ORIGIN AUDITABLE SCHEDULING DOCUMENTATION CAPABLE DISTINGUISHING RENEWABLE OUTPUT PLJEVLJA GENERATION IMPORTED REGIONAL ELECTRICITY.
This distinction gains significance under EU’S CARBON BORDER ADJUSTMENT MECHANISM MONTENEGRO’S PROSPECTIVE INTEGRATION EUROPEAN ELECTRICITY MARKET LOW CARBON GENERATION MAINTAIN EXPORT VALUES WHILE ELECTRICITY EMBEDDED COAL COMPONENTS FACES INCREASING CARBON COST DISADVANTAGES HOURLY TRACEABILITY RELIABLE DATA BECOME ESSENTIAL PROJECT BANKABILITY RATHER THAN SECONDARY COMPLIANCE EXERCISES.
The EBRD financing plays crucial role mitigating risks through extended tenors policy dialogue environmental social due diligence mobilization commercial lenders having invested over€1bn across100Montenegrin projects establishing centrality linking regulatory reforms investable infrastructures its involvement does not substitute thorough project preparations land rights environmental assessments grid studies procurement contracts operational evidence must withstand lender scrutiny.
MONTENEGRO’S HUB OPPORTUNITY FINALLY LIES IN COMBINING VARIOUS ASSETS RATHER THAN MAXIMIZING ANY SINGLE TECHNOLOGY SOLAR PROVIDE LOW COST DAYTIME PRODUCTION WIND CONTRIBUTES HIGH CAPACITY FACTOR LESS CORRELATED PROFILE PIVA PERUCICA SUPPLY FLEXIBILITY BATTERIES MANAGE SHORT DURATION VOLATILITY CGES MONETIZE TRANSMISSION REGIONAL FLOWS ITALIAN CABLE ACCESS DEEPER EUROPEAN MARKETS.
The import bill totaling€142mn incurred during2025 illustrated consequences failing deliver integration initiatives Gvozd250MWsolar auction EPCG639MWdirect portfolio prospective500MWhstorage program potentially second600MWcable pole now form credible sequences developments their values determined commissioning timelines connection readiness reliable access markets not aggregate megawatts announced.
