by Dr. Andreas Prokopiou, former Senior Researcher in the field of Smart Grids at the University of Melbourne and researcher at Électricité de France R&D in France
The Great Sea Interconnector is, technically, a multi-terminal 525-kV VSC-HVDC system with two poles at ±500 kV, a 1,208-kilometer subsea cable reaching depths of up to 3,000 meters, and a transmission capacity of 1,000 MW, expandable to 2,000 MW. Behind these specifications lies a 14-year history of ownership changes, cost revisions, and regulatory complexity, yet the project remains Cyprus’s only realistic way out of its energy isolation. The question is not only how much it costs, but also how that cost is measured—through a feasibility analysis or a strategic value analysis—two approaches that do not always lead to the same conclusion. No serious assessment can consider one without the other.
ΣΧΕΤΙΚΑ ΑΡΘΡΑ
Fourteen years, two changes in ownership
The idea was presented in January 2012 by the DEI-Quantum consortium, led by Nasos Ktoridis, with an initial cost estimate of €1.5 billion. EuroAsia Interconnector Ltd conducted studies as a private entity for nearly a decade, until 2021, when a €100 million grant was received from the Recovery Fund, and in January 2022, the largest grant to date—€657 million—was provided by the CEF. In 2023, the Greek transmission system operator ADMIE took full charge of the project and renamed it the Great Sea Interconnector, while costs continued to rise, reaching €1.9–2 billion for the Cyprus–Greece leg specifically, or up to €2.4 billion if the entire trilateral project is taken into account. ADMIE counters this with an estimated benefit of up to €8 billion, a figure that is equally unconfirmed.
The most recent change occurred on August 5, 2026, when the French company Meridiam acquired 66% of the company for €3.05 million, at its book value. What really matters is not the purchase price, but its commitment to a €17 million to resume offshore exploration—which has been stalled for months—by September, a prerequisite for proceeding with the cable laying.
Beyond the GSI, what does security really mean?
As an isolated system, Cyprus must maintain a reserve margin that meets the N-1 criterion, that is, the loss of its largest power plant, which typically amounts to 30% or more of peak demand. The GSI does not solve this as much as one might expect, because as an asynchronous HVDC interconnection, it does not automatically synchronize the frequency of the Cypriot grid with the European one, so Cyprus will still need its own system inertia (grid-forming technology could, in principle, change this, though there is no confirmation that it will be implemented here). The cable’s structure itself does, however, provide some redundancy, since it consists of two poles; a failure in one leaves the other available. The risk is not merely theoretical. On July 22–23, 2026, simultaneous failures at power plants in Dekeleia and Vasiliko coincided with a record-breaking surge in demand, 1,372 MW, leading to rolling blackouts in certain areas.
The rest of the picture is just as significant. The existing generation capacity, with the Dekeleia and Vasiliko power plants accounting for a total installed conventional capacity of 1,478 MW, currently covers nearly all of the country’s electricity needs, albeit with aging oil-fired units. In fact, the plan calls for the decommissioning of approximately 750 MW of old units at the two power plants, with no realistic replacement for this lost capacity currently in sight. However, two newer units are on hold for exactly the same reason. PEC, the country’s first privately owned power plant, with gas turbines and a capacity of approximately 240 MW, and the EAC’s 6th Unit in Vasilikos, a 160-MW combined-cycle plant, have both been designed specifically for natural gas. Both have been built or are nearly complete, but remain underutilized or idle, since natural gas has not yet reached Cyprus—a dependency that links them directly to the LNG terminal at Vasilikos, the most delayed of all the country’s major energy projects. Storage is progressing more quickly, as the system operator has awarded a contract to a consortium to build a central storage system with a capacity of 120 MW/400 MWh, with one of its units capable of grid-forming operation, and has already issued connection terms for eight private storage projects totaling 231 MW/570 MWh, with another 26 in the pipeline. The need is not merely theoretical, as Cyprus curtailed more than 47% of its annual renewable energy production last year, a figure that reached 65% on a daily basis during the first five months of 2026.
Or perhaps a cheaper, local solution?
If all of this is already underway, the reasonable question arises as to whether Cyprus and the GSI are truly necessary. The Cyprus-Greece segment costs €1.9–2 billion, with Cyprus committed to an additional €125 million by 2029 without even holding a stake. A comparison with local investments is revealing. PEC cost €211 million in private capital, the operator’s central storage facility cost €50 million in public funds, while the 231 MW of private storage projects cost the public nothing. Even Unit 6, already completed at a cost of €160 million, shows, however, that even local solutions are not entirely risk-free, since it remains underutilized due to the delay in the LNG terminal. Despite this risk, the total cost remains a fraction of that of GSI, enough for Cyprus to add significant domestic power generation and storage capacity, mostly with private capital. However, there is one thing that no local solution on its own can offer: access to a much larger market, both for importing and exporting energy, with all that this entails for price competition and system flexibility. The due diligence study being conducted by the EIB can provide estimates of market revenues for financing purposes, but the full value of this access will essentially only become apparent through the actual operation of the interconnector over time.
Who Pays, and How Is It Calculated
At the heart of the financial picture are the €25 million per year that the Cyprus Energy Regulatory Authority has approved for ADMIE, part of Cyprus’s total commitment of €125 million through 2029, even though the country holds no shares in the company. The cost of the Cyprus-Crete section is allocated 63% to Cyprus and 37% to Greece, based on the net benefit calculated by the European cross-border cost allocation mechanism, under Regulations (EU) 2019/943 and 2022/869. However, as Professor Dr. Andreas Poullikkas explains, this ratio does not automatically translate into a charge to consumers, since subsidies are first deducted, followed by the market’s own revenue from cross-border transmission capacity auctions, and only any remaining balance is passed on to regulated tariffs. If market revenues fully cover the permitted revenue for a given year, no additional charges are imposed; conversely, in the event of over-recovery, the surplus may be credited to consumers.
The same cost uncertainty also affected the cable manufacturer. Nexans, with a €1.43 billion contract for the Cypriot section, saw ADMIE freeze a €70 million payment in March 2025, due to the harassment of research vessels by Turkish warships; it canceled subcontractor tenders in December, and announced a rescheduling in January 2026, with delivery postponed beyond the initial target of 2028–2029. At the same time, an ongoing investigation by the European Public Prosecutor’s Office is examining the period prior to 2023, when the project was still managed by the private company EuroAsia, specifically examining whether undue political influence was exerted to secure EU funding, as well as a 2023 transaction in which €48.8 million was returned just a few days after it was received. No investigation in and of itself proves any irregularity, but it adds yet another layer of uncertainty to a project that is already facing delays and cost revisions.
The Unresolved Question
As noted at the outset, two methodologically different approaches remain pending for the same project. One is a feasibility and cost analysis, which examines whether the project is financially viable under current conditions, and the other is a strategic value analysis, which measures benefits that are more difficult to quantify, such as energy security. The two approaches do not guarantee the same answer, and the due diligence study requested by the EIB in April 2026 is not even the first such effort. Its focus, however, is primarily financial—that is, whether the project is bankable—rather than its strategic value in the broader sense described above. Even once it is completed, the question of strategic value will remain largely a matter of judgment, while the final cost to the consumer will also depend on future market conditions through the CBCA mechanism—something no study can predict with certainty today.
Source: cyprusenergy.news
