The Black Sea Submarine Cable has moved from a strategic concept towards formal preparation. Yet for a project of this scale, a viable route and suitable technology are only the beginning.

The more difficult questions concern exportable generation, domestic grid readiness, long-term buyers, cost allocation, security and the commercial structure that lenders would require.

Rouven Stubbe, Energy and Climate Policy Advisor at Helmholtz-Zentrum Berlin for Materials and Energy, examined the economic prospects of the project in a 2023 analysis prepared during his previous role at German Economic Team. In this interview, he revisits its central conclusions and sets out practical tests that Georgia and its partners should apply before a final investment decision.

The core constraint remains exportable electricity

The project’s price outlook has improved since 2023. But Stubbe argues that the central constraint has not changed: Georgia and Azerbaijan must be able to produce enough electricity beyond their own growing needs.

renewables.GE: Your 2023 analysis concluded that the cable could offer Georgia strategic benefits but did not yet have a clear standalone business case. Looking from today, which parts of that conclusion still stand, and which developments could realistically change the economics?

Rouven Stubbe: The core of our conclusion still stands: the economic value of the cable depends on sufficient export-oriented generation, and on that front the situation has not improved.

Georgia remains a net importer. In 2025, domestic generation fell to about 13.8 TWh while consumption rose to about 14.8 TWh. In the first quarter of 2026, thermal plants and imports again covered more than half of demand. The large hydropower projects that official plans relied on remain largely stalled.

In Azerbaijan, wind and solar capacity is finally growing, but much of it is primarily intended to replace domestic gas burn so that more gas can be exported.

What has changed most is the price picture, and for now it has changed in the cable’s favour. In 2023, the ENTSO-E projections available to us suggested that Türkiye would become the more lucrative market by 2030 and 2035. Since then, South-East Europe has consistently been a high-price region.

Romanian day-ahead prices averaged around €104/MWh in 2024 and €108/MWh in 2025, while Turkish wholesale prices averaged roughly $66/MWh in 2025, as Türkiye’s solar boom pushed midday prices towards zero. Forward prices suggest that South-East Europe will remain expensive for the next few years, partly because of the 2026 gas-price shock.

But the cable would only start operating in eight to ten years, and that longer-term outlook is genuinely uncertain. Solar, wind and battery storage are expanding rapidly across the region. South-East Europe could remain structurally above Türkiye, but I would not build the case for the cable on that assumption alone.

Two further developments matter for financing. The cable now has EU Project of Mutual Interest status, opening access to EU grant co-financing. Since January 2026, electricity imports into the EU also fall under the Carbon Border Adjustment Mechanism. That rewards contracted renewable exports over grid-mix power.

Overall, the main uncertainty has shifted from the choice of export market to whether Georgia and Azerbaijan will have enough electricity to export.

renewables.GE: Given that Georgian network-development projections have at times diverged significantly from actual project delivery, what should policymakers, lenders and potential offtakers look for—beyond official capacity announcements—to judge whether export-oriented generation will genuinely materialise?

Rouven Stubbe: Financial and contractual commitments are far more reliable indicators than capacity figures in plans. Georgia’s network-development plans have overestimated hydropower additions year after year. What we saw in reality were delays and cancellations rather than commissioning of new plants.

Announcements, memoranda and auction quotas are statements of intent. I would look at four indicators in particular.

First, financial close. A wind or solar project with signed financing, an EPC contract and a construction start is a different asset from one that has won an auction or signed an MoU.

Second, grid connection: a signed connection agreement, clarity on curtailment rules and agreement on who pays for reinforcements. GSE currently limits how much wind and solar it can connect, and that limit will bind long before any exportable surplus emerges.

Third, the hourly residual. Exportable electricity is what remains after domestic demand in each hour and season, not nameplate capacity. Georgian demand is growing fast. Lenders should ask for hourly dispatch modelling with conservative demand growth, not annual energy balances alone.

Fourth, the offtake chain: is there an EU buyer with a long-term contract, and is the plant explicitly dedicated to export?

A practical tool would be a public project tracker that applies historically observed conversion rates—from permit to financial close to commissioning—to the entire pipeline. In Georgia, those rates have been low, and official figures should be discounted accordingly until the track record improves.

A second market, not a replacement for Türkiye

Türkiye is likely to remain Georgia’s natural outlet for seasonal hydropower surplus. But the cable could reduce reliance on a single buyer and create a different kind of optionality.

renewables.GE: Your paper identified Türkiye as a potentially cheaper and, at times, more attractive export route for Georgian electricity. What economic or strategic function would the Black Sea Cable need to perform that existing and expanded links to Türkiye cannot? Under what conditions would the routes become complementary rather than competing?

Rouven Stubbe: The links to Türkiye are cheap, already built and will remain Georgia’s natural outlet for seasonal surplus. But they serve a single market.

Türkiye bought close to 80% of Georgian exports in 2025. When Turkish prices fell that year, Georgian exports roughly halved. Dependence on a single buyer weakens the bargaining position of Georgian exporters.

The cable would add three things the Turkish links cannot. First, direct access to the EU internal electricity market under EU rules: transparent capacity allocation, market-based prices and a legal framework that EU offtakers and lenders recognise.

Second, it would offer a different price profile. South-East Europe faces structural scarcity in evening hours and in winter, while Türkiye’s fast-growing solar fleet now pushes its midday prices towards zero for hundreds of hours each year.

Third, it would provide a back-up import route. In winter, Georgia will most likely continue to import mainly from Russia, since imports from the EU are unlikely to be cheaper. But the cable would provide a hedge against disruptions of Russian supplies, whether for technical or political reasons.

The routes are complementary when they serve different hours, seasons and products. Georgian reservoir hydropower is valuable precisely because it can choose when to generate and sell into whichever evening peak pays more. Long-term contracted flows into the EU and short-term trading with Türkiye can coexist.

They compete when exportable surplus is small. In that case, both routes compete for the same volumes and the more expensive one risks being underused.

The cable needs a revenue model lender can support

Rouven distinguishes between financing the cable itself and contracting the electricity that would flow through it. Both require a structure that can withstand changing market prices.

renewables.GE: For an interconnector of this scale, what commercial structure would make the project financeable in practice? In particular, how could long-term offtake agreements reduce the risk that electricity is diverted to higher-priced alternative markets, leaving the cable underutilised—and who should bear the associated price and volume risk?

Rouven Stubbe: It is useful to distinguish between two risks: volume risk, meaning that the cable is underused, and price risk, meaning differences between prices in Georgia and Azerbaijan, South-East Europe and Türkiye.

For the cable itself, a purely merchant model—where revenue depends only on price differences between the two ends—is not financeable for a €3–4 billion, first-of-its-kind asset in a contested sea.

A regulated model is more realistic: EU co-financing for part of the capital cost, plus a revenue framework such as the cap-and-floor regime used for several interconnectors to Great Britain. Lenders receive a guaranteed minimum revenue, while consumers retain the upside above the cap. The remaining volume risk would be shared among the countries that benefit through an agreed cross-border cost allocation.

For the electricity itself, long-term contracts are the main instrument. Generators in Azerbaijan and Georgia would sign long-term power-purchase agreements with EU buyers, paired with long-term transmission rights on the cable for a substantial share of its capacity.

Price risk would then sit with generators and offtakers, who are best placed to manage it. Since 2026, this has an additional benefit: under CBAM, imported electricity can only be counted at its actual low emissions if it is covered by a long-term contract and firmly nominated interconnector capacity.

What I would avoid is forcing physical flows through the cable against price signals. If Türkiye pays more in a given hour, power should flow there. The cable’s financing should be robust to that, rather than resting on contractual obligations that undermine efficient dispatch.

Rules, governance and transit matter as much as the cable

The four participating transmission-system operators have formed a joint project company. Stubbe sees that as an important foundation—but far from the complete institutional framework.

renewables.GE: The project involves several countries with different interests: producing electricity, providing transit, receiving electricity and financing infrastructure. What kind of governance and capacity-allocation arrangements would be needed to ensure that the cable operates as a functioning commercial link rather than mainly a political project?

Rouven Stubbe: The institutional skeleton now exists. The transmission-system operators of Azerbaijan, Georgia, Romania and Hungary have formed a joint project company registered in Romania, and the project holds EU Project of Mutual Interest status.

Whether the cable will operate as a commercial link depends mainly on three further elements.

First, a binding intergovernmental framework that settles the regulatory regime, the sharing of costs and revenues, the law that applies at the EU border and the resolution of disputes. These questions get much harder once construction has started and money is sunk.

Second, rule-based capacity allocation. All capacity should be allocated through transparent, non-discriminatory auctions: long-term rights for contracted flows and daily allocation for the remainder, with use-it-or-sell-it provisions so that no holder can block capacity.

There should be no reserved quotas for state companies or individual governments. The same rules should apply to any third-party supplier, whether from Armenia or, later, Central Asia.

Third, predictable transit. Much of the electricity is expected to originate in Azerbaijan and cross Georgia. Transit compensation should follow a published, cost-based methodology agreed between regulators, so that Georgia earns a fair return on its grid without any risk of hold-up.

Underneath this, both ends need functioning markets and independent regulators: day-ahead markets that actually set prices, market monitoring against manipulation, and operating agreements between system operators for running a 1,300 MW HVDC link.

Georgia’s domestic work cannot wait for the cable

A cable can operate in both directions. For Georgia, its value would therefore depend not only on summer exports but also on how it supports winter security and domestic system development.

renewables.GE: How should Georgia assess the balance between electricity exports, growing domestic demand and security of supply? Beyond the cable itself, what physical upgrades to the domestic grid—including the East-West corridor—and what market arrangements would be essential for the country to capture durable value from the project?

Rouven Stubbe: The trade-off is less pronounced than it may seem, since the cable can be used in both directions. Georgia exports hydropower in late spring and summer and imports in winter, mostly from Russia. A link to the EU is therefore as much a winter-import option as a summer-export route.

The real question is whether Georgia adds enough generation to cover its own growing demand first. Today it does not: demand is rising faster than supply and imports have increased sharply. The cable itself would not change that.

Physically, three things matter. First, a strong 500 kV backbone from the Azerbaijani border in the east to the Black Sea coast in the west, so that power can reach the converter station near Anaklia without congesting the domestic grid. This is where the East-West corridor comes in.

Second, reinforcement around the converter station, together with the protection and reserve arrangements needed for a 1,300 MW link. That would be as large as Enguri, today the largest unit in the Georgian system.

Third, flexible capacity—reservoir hydropower and batteries—so that Georgia can sell when prices are high rather than whenever water flows. The latest support auction’s focus on regulating hydropower and storage points in the right direction.

On the market side, Georgia needs a liquid day-ahead market in which exports follow prices rather than administrative decisions, cost-reflective domestic tariffs, transparent cross-border capacity allocation, and credible guarantees of origin and emissions reporting, which EU buyers will require.

Resilience has a public value

The cable’s route, depth and regional setting create risks that cannot be treated as a normal construction contingency. Rouven Stubbe argues that part of its resilience value will need explicit public backing.

renewables.GE: Your paper highlighted security, insurability and potential cost overruns as major concerns. In the current regional environment, how should those risks be reflected in the project’s design and financing? Can resilience be treated as part of the commercial case, or does it require an explicit public strategic commitment?

Rouven Stubbe: These risks have not diminished since 2023. Russia’s war against Ukraine continues at sea, while recent incidents in the Baltic Sea have shown how easily cables can be damaged and how long repairs can take.

In deep water, repair vessels and spare cable are scarce, so an outage could last months.

In the design, this argues for redundancy and staging: a configuration that does not lose all capacity with one fault, fibre-optic monitoring along the route, spare cable and pre-arranged repair capacity.

On costs, the estimate has already risen from €2.3 billion to €3.1–3.6 billion, while the market for HVDC cables and converters remains tight. Binding supplier offers, fixed-price contracts with clear risk allocation and realistic contingencies are essential.

The feasibility study’s own sensitivity analysis suggests that the economic case would disappear with a cost overrun of roughly a quarter—a margin that megaprojects of this kind often exceed.

Resilience can be part of the commercial case only to a limited extent. Some security value can be priced through reserve-sharing and emergency-assistance agreements between system operators. But much of it is a public good: diversifying away from Russian imports and from a single export market benefits the whole region, and no private investor will pay for that.

That part requires an explicit public commitment: EU grants, political-risk guarantees from institutions such as MIGA, and security cooperation among the littoral states. Such support should, however, be tied to clearly defined security benefits rather than used to compensate for a weak business case.

Six practical tests before an investment decision

renewables.GE: Before a final investment decision is taken, what are the most important conditions Georgia should insist on seeing demonstrated? What would be the practical “go/no-go” tests for the project?

Rouven Stubbe: I would apply six tests.

1. Contracted supply: Export-oriented generation in Azerbaijan and Georgia that has reached financial close—not just announcements—sufficient for high utilisation in the cable’s early years and backed by signed long-term offtake agreements with EU buyers.
2. A bankable revenue model: An agreed regulatory regime for the cable, cross-border cost allocation among the benefiting countries and confirmed EU grant funding.
3. A firm cost: Completed seabed surveys and binding offers from cable and converter suppliers, with an economic case that survives a cost overrun of 25–30% and a two-year delay.
4. A robust price case: Positive results across several price scenarios, based on the prices the cable would actually earn in the hours it operates rather than a single average-price forecast, including the treatment of imports under CBAM.
5. Domestic readiness: Financed and scheduled grid reinforcements that will be ready when the cable is, functioning market rules for exports, and a winter-adequacy plan that does not assume the cable is always available.
6. Security and governance: An insurance and guarantee package, a repair strategy, an intergovernmental agreement and capacity-allocation rules approved by the regulators.

If these conditions are met, there is a sound basis for an investment decision. When they are not yet met, it would make sense to continue the preparatory work—surveys, permitting and the commercial framework—while investing in what Georgia needs in any case: new domestic generation, a stronger internal grid and further market reform.

Source note: Written interview with Rouven Stubbe, Energy and Climate Policy Advisor at Helmholtz-Zentrum Berlin for Materials and Energy. Rouven Stubbe’s 2023 Black Sea Cable analysis was prepared during his previous role at German Economic Team. Responses have been lightly edited for clarity and length.