Montenegro’s electricity transmission operator CGES has secured a €25mn loan from the French Development Agency, marking the agency’s first investment in the country’s energy sector and adding another important financing component to a rapidly expanding programme of grid modernisation.
The loan to Crnogorski elektroprenosni sistem, or CGES, is backed by a Montenegrin government guarantee and is expected to be accompanied by an €8.5mn European Union grant through the Western Balkans Investment Framework. The combined package will finance the reconstruction of the strategically important Perućica and Pljevlja 2 substations, whose ageing equipment has become a constraint on both system reliability and the connection of new renewable generation.
The agreement was signed by CGES chief executive Ivan Asanović and Arnaud Dauphin, director of the French Development Agency’s regional office for the Western Balkans. Montenegro’s guarantee was signed by finance minister Novica Vuković, while energy and mining minister Admir Šahmanović attended the ceremony.
The immediate transaction is modest when compared with the scale of European transmission investment. For Montenegro, however, it carries significance well beyond its €25mn face value. It brings concessional development finance into a grid that must absorb a growing pipeline of wind, solar and hydro projects, reinforce connections with neighbouring systems and make fuller commercial use of the country’s submarine electricity cable to Italy.
It also places another sovereign-backed obligation on the state’s balance sheet. Although the guarantee is small relative to Montenegro’s economy, it illustrates the financing model on which the country’s energy transition will increasingly depend: a combination of development-bank loans, EU grants, regulated transmission revenues and, where necessary, government support.
The substations covered by the project sit at two distinct but complementary points in the system. Perućica, in central Montenegro, is closely connected to the country’s most important hydroelectric infrastructure. Its modernisation is expected to facilitate the integration of as much as 350MW of hydroelectric capacity, improve operational security and replace equipment that is approaching or has exceeded its intended service life.
Pljevlja 2, in the north, performs a different strategic function. The substation is a gateway between Montenegro’s domestic system and the wider Trans-Balkan transmission corridor. It is also located in the country’s coal-dependent industrial region, where the eventual transition away from thermal generation will require the grid to support new renewable capacity, cross-border flows and a more diversified regional economy.
More detailed project documentation indicates that the two upgrades could unlock approximately 550MW of immediate renewable connection capacity across the transmission system: more than 250MW in the Perućica area and about 300MW around Pljevlja. This is not necessarily inconsistent with the government’s reference to 350MW of hydro capacity. The figures describe different parts of the project’s technical potential, with one focused on the hydro-related benefit at Perućica and the other on the wider renewable capacity that could be accommodated across both nodes.
The distinction matters for investors. A transmission project can create the technical capacity to connect generation, but it does not guarantee that every megawatt will be built. Renewable projects still require land, permits, environmental approval, connection agreements, credible offtake arrangements and finance. The 550MW figure should therefore be understood as an enabling envelope rather than a construction forecast.
Even so, the amount is substantial in a country whose existing power system is relatively small. Montenegro has significant renewable resources, but the scale of its investable project pipeline increasingly exceeds the capacity of the legacy grid. Without reinforcement, developers risk being offered delayed connection dates, restricted output or connection terms that require them to finance additional network assets.
The entire substation project is estimated to cost about €39mn. The AFD loan would cover roughly 64 per cent of that amount, while the proposed EU grant would account for almost 22 per cent. Together, the two sources would provide €33.5mn, or about 86 per cent of total project costs, leaving approximately €5.5mn to be covered by CGES or other sources.
That financing structure is favourable for the transmission operator. The grant component reduces the capital that must ultimately be recovered through regulated network tariffs, while the development loan should provide a longer maturity than would normally be available from commercial banks. The interest rate, grace period and repayment schedule have not been disclosed, preventing a precise assessment of debt-service costs. Nevertheless, AFD financing is generally designed for long-lived infrastructure whose economic return emerges over decades rather than within a conventional commercial lending cycle.
On the stated project value and potential connection capacity, the network investment equates to about €71,000 for each megawatt of enabled capacity. This is not comparable with the construction cost of a power plant: substations do not generate electricity and their benefits extend to system security, cross-border trading and existing users. It nevertheless provides a useful indication of the relatively low cost of removing a critical transmission bottleneck compared with the generation investment that could follow.
If the available capacity is eventually matched by a combination of hydro expansion, wind farms, solar parks and battery storage, the associated private and public investment could comfortably exceed €600mn and, depending on the generation mix, approach or surpass €1bn. Hydro projects are particularly site-specific and can require more than €1.5mn–€3mn per megawatt, while utility-scale wind projects in the region may cost approximately €1.2mn–€1.6mn per megawatt. Solar is generally cheaper, at perhaps €650,000–€850,000 per megawatt, but its production profile creates a different set of balancing and congestion requirements.
Wind and solar should not be treated as interchangeable merely because both are renewable. Northern Montenegro’s wind resources could produce at capacity factors of roughly 32–42 per cent at strong sites and may complement summer-dominated solar generation. Solar plants are faster to construct and usually less capital-intensive, but their output is concentrated around the same daytime hours, increasing the risk of price cannibalisation and local congestion as installed capacity rises. Hydro offers dispatchability and balancing value, although its output is exposed to hydrological volatility and environmental constraints.
The two substations can therefore create more value together than either would in isolation. Perućica can reinforce the system around flexible hydro resources, while Pljevlja can accommodate new northern generation and strengthen regional transfers. Combined with Montenegro’s interconnectors and the 600MW first pole of the submarine cable to Italy, this could allow the system to balance variable output domestically and export surpluses when regional prices are attractive.
Pljevlja’s role is especially important because the substation forms part of a larger European transmission architecture. The Trans-Balkan corridor links Romania, Serbia, Montenegro and Italy and is intended to support greater cross-border electricity exchange across south-eastern Europe. Two ageing 400/220kV autotransformers, each rated at 400MVA, are expected to be replaced at Pljevlja 2. Their renewal should reduce failure risk and increase confidence that the node can handle more complex power flows.
The investment also prepares the area for a future in which the Pljevlja thermal power plant may no longer dominate northern Montenegro’s energy economy. The coal plant remains important for domestic security of supply, employment and local public finances, but its long-term position is constrained by emissions standards, carbon costs and Montenegro’s alignment with EU energy policy. Modernising the transmission node before the generation mix changes is less risky than waiting until new projects are ready to connect.
At Perućica, the project involves the replacement of obsolete equipment in the 220/110kV substation. The benefit is not simply additional megawatts. New protection, control and switching systems can reduce outage duration, improve remote management and provide more accurate information about network conditions. These capabilities become increasingly valuable as generation shifts from a limited number of large plants to a more dispersed portfolio of renewable facilities.
The project is expected to require an extended implementation period. Consultancy work has been indicated for early 2027, with services potentially continuing for about 45 months. That timetable points towards completion around the second half of 2030, subject to procurement, permitting and construction progress.
For renewable developers, this schedule is as important as the financing announcement itself. Projects that receive permits before the network upgrade is operational may still face connection delays or temporary operational restrictions. A wind or solar project can be built in less than two years, but a major substation reconstruction involving live high-voltage infrastructure, international procurement and complex commissioning can take considerably longer.
A 12-to-18-month grid delay can materially weaken project economics. For a representative 100MW renewable project, additional interest during construction, extended guarantees, development overhead and contractor claims could add approximately €4mn–€10mn, depending on capital structure and the point at which the delay occurs. If the project has already drawn debt but cannot begin commercial operation, the effect is particularly severe.
Under plausible financing assumptions, such a delay could reduce an equity investor’s internal rate of return by around 1.5–3.5 percentage points. The impact would be greater if the developer loses part of a fixed-price support period, breaches a power-purchase agreement milestone or has to refinance short-term construction facilities. It would be smaller if the project has flexible offtake arrangements and debt repayment begins only after the connection date.
Curtailment is the second major risk. In a base case where the substations and related regional reinforcements are completed on time, renewable curtailment around the affected nodes could remain in the region of 1–3 per cent. If generation is commissioned faster than the wider network can be strengthened, or if cross-border capacity is unavailable during periods of high output, the figure could temporarily rise to 5–8 per cent.
For a wind farm, curtailment affects both energy volumes and the project’s ability to exploit higher-priced periods. For solar, the challenge is compounded by the tendency of wholesale prices to weaken during sunny midday hours as more photovoltaic capacity enters the market. Batteries can reduce part of that exposure, but they require a separate revenue case based on arbitrage, balancing services or network support. Storage should not be assumed to make every congested solar project economical.
The AFD transaction comes as CGES enters a much larger investment cycle. The operator’s investment programme for 2026–2030 is valued at close to €200mn, with projects spanning substations, domestic transmission lines and cross-border corridors. The balance-sheet value of newly commissioned assets is expected to reach about €111.7mn in 2026, €170.5mn in 2027 and €214mn in 2028.
By 2028, new infrastructure could account for more than half of CGES’s fixed assets. This represents a rapid renewal of a network comprising roughly 1,500–1,550 kilometres of transmission lines, close to 30 substations and more than 4,400MVA of transformation capacity. The system connects the Pljevlja thermal plant, the Piva and Perućica hydro stations, the Krnovo and Možura wind farms, neighbouring electricity markets and the Italy cable.
Other investments include the rehabilitation of the 220kV corridor linking Bosnia and Herzegovina, Montenegro and Albania, for which CGES secured a €15mn European Bank for Reconstruction and Development loan in 2026. The company is also developing the Brezna substation and reinforcing the transmission ring that connects Lastva, Pljevlja and the central part of the country.
This acceleration has consequences for CGES’s finances. The company reported net profit of approximately €21mn in 2025, down from €24.8mn in 2024 and €35.7mn in 2023. Its business plan anticipates substantially lower annual earnings of roughly €1.4mn–€1.7mn between 2026 and 2028, despite revenue remaining near €68mn–€72mn.
The expected decline does not necessarily signal a deterioration in the underlying grid business. It reflects rising depreciation, financing expenses and regulatory adjustments as new assets enter service. Transmission operators recover approved costs through regulated tariffs, but the timing of investment, commissioning and regulatory recognition can create significant fluctuations in reported profit and cash flow.
CGES’s net debt is projected to rise from approximately €17.8mn in 2026 to €59.1mn in 2027 and about €91mn in 2028. Against projected earnings before interest, tax, depreciation and amortisation of around €13mn–€14mn, leverage could move from a comfortable level to more than six times EBITDA.
That makes EU grants and long-tenor development finance increasingly important. Without them, CGES would have to rely more heavily on commercial borrowing, shareholder support or higher regulated charges. All three alternatives are politically or financially more difficult. Grants reduce the asset base that must be financed, while government guarantees can lower borrowing costs but transfer part of the risk to the sovereign.
The €25mn state guarantee is manageable in isolation. It represents only a fraction of one per cent of Montenegro’s projected gross domestic product and is attached to an income-generating infrastructure company rather than a loss-making budget entity. The relevant risk is cumulative: CGES, the power utility EPCG, municipalities and transport companies all have investment needs that may involve sovereign guarantees or public borrowing.
Credit investors will therefore examine whether CGES’s tariff settlements generate sufficient cash to service the enlarged debt portfolio without repeated state intervention. They will also consider currency risk, although euro use removes the foreign-exchange mismatch that affects many emerging-market utilities, and execution risk across a programme containing several simultaneous high-voltage projects.
CGES’s ownership provides some strategic support. The Montenegrin state holds about 55.4 per cent, while Italy’s Ternaowns roughly 22.1 per cent and Serbia’s transmission operator EMS about 15 per cent. Terna’s investment is tied to the Italy interconnector, while EMS has an interest in regional network integration. Their presence does not constitute a financial guarantee, but it aligns CGES with two larger transmission systems whose commercial interests depend on reliable cross-border flows.
The upside case is that Montenegro completes the substation works and associated corridors by around 2030, connects close to the full 550MW technical envelope and deepens electricity-market integration with Italy and neighbouring countries. Curtailment could then remain below 2 per cent, while better access to export markets would increase the value of flexible hydro and well-sited wind generation. Under those conditions, project-level equity returns might reach approximately 9–12 per cent for wind, 8–10 per cent for solar and 8–11 per cent for hydro, depending on financing, resource quality and offtake.
A more cautious base case would assume that 350–450MW is connected during the initial phase, with the remainder following as permits, generation economics and further network works allow. Curtailment of 1–3 per cent would be manageable, but developers would still need conservative production forecasts and clear compensation rules for network-imposed restrictions.
The downside is less about the announced financing than about coordination. If substation procurement, regional lines and generation projects progress on different schedules, capacity may exist on paper but remain commercially unusable. A 12-to-18-month delay, combined with higher interest rates or weaker wholesale prices, could reduce equity returns by several percentage points and cause marginal projects to be postponed.
The French loan does not resolve those risks. It does, however, finance two pieces of infrastructure without which Montenegro’s renewable ambitions would remain constrained by physical rather than financial scarcity. For developers, lenders and strategic utilities, the central question is no longer whether the country has renewable resources. It is whether CGES can convert a growing portfolio of development-bank commitments into commissioned grid assets quickly enough to keep investment capital moving.
