Montenegro is entering a new phase of renewable-energy investment in which installed capacity is no longer the sole measure of project value. The next challenge is whether new wind, solar, hydropower and storage assets can generate revenue that lenders can confidently underwrite after accounting for transmission costs, balancing risks, CBAM exposure, evidence requirements and counterparty risk.
The scale of this transition is becoming increasingly apparent. Montenegro’s 2026 Energy Balance projected total electricity generation of 3,798 GWh, a significant increase from the weaker 2025 baseline, and a system surplus of approximately 398 GWh. It also envisaged installed solar capacity reaching around 215 MW by year-end, provided planned public and private projects were delivered. This represents a meaningful shift for a power system in which hydropower and the Pljevlja thermal power plant have traditionally shaped the country’s electricity export position.
The first phase of the Gvozd wind farm has already moved the discussion from development pipelines to operating assets. The 54.6 MW facility entered trial operation in May 2026 following an investment of approximately EUR 82 million, with expected annual generation of around 150 GWh. European Bank for Reconstruction and Development (EBRD) project records describe a combined financing package of approximately EUR 108 million for the two-phase development, while Montenegrin project materials identify a second phase with 21 MW of capacity.
By October, the Energy Ministry was describing the first phase as completed, with work on the second phase under way. EPCG has stated that the second phase is expected to contribute approximately 63 GWh of electricity annually. For lenders, the significance extends beyond Montenegro’s transition from wind development to operational generation. An increasing share of future project revenue may depend on where the electricity is sold and which contractual and evidentiary arrangements accompany it.
Domestic sales, regional electricity trading and physical exports to EU importers can expose the same generating asset to substantially different combinations of price risk, balancing costs, collateral requirements, transmission rights and carbon-related obligations. Assigning a single revenue value to every generated megawatt-hour can obscure these differences and lead to unrealistic financing assumptions.
The same considerations are increasingly shaping grid investment and storage development. In July, the French Development Agency (AFD) and Montenegro’s transmission system operator, CGES, signed a EUR 25 million sovereign-guaranteed loan to modernise the Perućica and Pljevlja 2 substations. The financing is accompanied by a planned EUR 8.5 million EU grant through the Western Balkans Investment Framework. The government has also launched a process to select a strategic partner for battery energy storage systems.
These investments matter for project finance because grid capacity and flexibility influence much more than technical connection. They affect curtailment exposure, balancing costs, the ability to manage renewable output, access to export corridors and the reliability of operational data used to support commercial and regulatory claims. Battery storage can improve arbitrage opportunities and balancing economics, but under the current CBAM electricity methodology, stored and subsequently discharged electricity should not automatically be assigned the same actual-emissions treatment as renewable electricity generated directly in the relevant hour.
Montenegro’s renewable pipeline is also expanding. CWP Europe is developing the 400 MW Montechevo solar project near Cetinje, with project materials indicating expected annual production of approximately 650 GWh and a target commercial-operation date around the end of 2028. The development is associated with battery storage and a broader regional investment package. A project of this scale would represent a substantial addition to Montenegro’s electricity system, requiring decisions on grid reinforcement, market access, offtake arrangements, storage dispatch and export strategy.
For lenders, the changing market requires a more detailed assessment of project revenues, separating at least three components. The first is commodity revenue from domestic power purchase agreements (PPAs), merchant sales or regional trading contracts. The second is revenue from environmental attributes, including Guarantees of Origin (GoOs), where recognition and contractual transfer requirements are satisfied. The third is any evidence-dependent premium associated with demonstrating lower embedded emissions for electricity imported into the EU.
The third revenue stream should not be capitalised at face value without adequate evidence. Banks need to assess what proportion of generation can realistically meet the applicable contractual, routing, hourly matching and verification requirements; who bears the costs when those conditions are not met; how long settlement may be delayed; and whether the producer’s potential liabilities could exceed the premium received. Equity investors should apply the same discipline when valuing projects on the assumption that export-related premiums will be available.
This creates a growing distinction between a renewable-energy asset and a bankable export asset. Montenegro can add substantial wind and solar capacity, but projects capable of attracting lower financing costs will need more than strong generation potential. They will also require credible offtakers, reliable grid access, controlled data systems, clearly allocated downside risks and a commercially viable route to market that does not depend on unproven regulatory benefits.
For Montenegro’s next investment cycle, the decisive measure will increasingly be not how many megawatts of renewable capacity are announced, but how many megawatt-hours can be delivered, documented and paid for under a financing structure that remains viable even when the anticipated premium disappears.
By Virtu.Energy