Across South-East Europe’s gas sector, feasibility studies have become a permanent layer of the energy system rather than a transitional step toward construction. The region is not short of concepts, routes, demand forecasts or engineering detail. What it lacks is the moment when capital, regulation and political ownership converge tightly enough to force execution. The result is a recognizable pattern in which the same projects resurface every two to three years, refreshed with updated assumptions, adjusted volumes and revised cost curves, but never converted into steel in the ground.
The Ionian–Adriatic Pipeline illustrates this condition in its purest form. Conceived as a strategic extension linking Albania’s TAP entry point through Montenegro and Bosnia and Herzegovina to Croatia, IAP has accumulated more than a decade of analytical work. Successive feasibility and pre-FEED phases have refined routing, compressor placement and capacity scenarios, usually clustered around 5–7 bcm per year in nominal design capacity. Capital expenditure estimates have oscillated between €1.8 and €2.4 billion, depending on route length, terrain treatment and compression assumptions. Each iteration confirms technical feasibility and regional relevance. None resolves the decisive question of who underwrites early underutilisation. Transit states expect security and geopolitical value, but no anchor shipper has committed to ship-or-pay volumes sufficient to support debt service in the first operating years. Without those commitments, lenders price the risk as sovereign-adjacent, while governments hesitate to assume contingent liabilities of €300–400 million per country. The pipeline therefore remains permanently “strategic” and permanently unbuilt, sustained by its narrative value rather than by a balance-sheet-ready structure.
Montenegro’s gasification story follows a similar arc but at a national scale. Over multiple planning cycles, the country has commissioned masterplans, economic assessments and tariff models for introducing gas into an energy system that currently has none. The LNG terminal concept at the Port of Bar sits at the centre of this vision, usually presented as a modular facility with 0.5–1.0 bcm per year of regasification capacity, expandable over time. Estimated upfront investment ranges from €180 to €250 million for a small-scale terminal and associated infrastructure, excluding downstream distribution and grid reinforcement. On paper, the numbers are manageable. In practice, the project stalls because the state has never resolved whether gas infrastructure is a regulated public utility with guaranteed cost recovery or a merchant asset exposed to volume and price risk. Without a tariff decision and without an anchor offtaker willing to commit to 0.2–0.3 bcm per year on long-term terms, EPCG and potential private partners cannot structure bankable contracts. Each new study postpones that decision, allowing the concept to survive politically while avoiding the fiscal and regulatory commitments that construction would require.
Bosnia and Herzegovina’s Southern Gas Interconnection demonstrates how governance uncertainty can trap a project in perpetual feasibility even when demand is real. The interconnector, designed to link Croatia’s system to central Bosnia, has been costed repeatedly at around €100–150 million, a relatively modest figure by regional infrastructure standards. Demand projections consistently show initial flows of 0.5–1.0 bcm per year, sufficient to displace higher-cost and less secure supply routes. Yet the project has remained stalled because no uncontested project owner exists. Disputes over transmission operator authority, tariff jurisdiction and political control mean that every feasibility implicitly assumes a governance solution that never materialises. Lenders view this as unquantifiable political risk, effectively inflating the cost of capital beyond viability. The study remains valid; the institutional framework does not.
Serbia’s gas interconnector with North Macedonia sits closer to execution, but still illustrates the narrow zone in which SEE projects stall after feasibility is formally complete. Capital expenditure for the Serbian section alone is estimated at €70–90 million, with design capacity sized for future expansion rather than immediate utilisation. The feasibility confirms system benefits and regional integration value. What delays kickoff is the transition from analytical readiness to irreversible commitments. Expropriation along the route, servitude agreements, final environmental permits and EPC procurement terms all carry upfront costs and political exposure. Until those are absorbed and capacity bookings justify full pipe diameter, the project remains in a liminal state where it is always “about to start” and never quite does.
Gas-to-power concepts in Serbia and Republika Srpska reveal the same dynamics at the generation level. Projects around Niš or Banja Luka are typically modelled at 300–500 MW combined-cycle capacity, with capital costs in the range of €250–400 million depending on technology choice and grid connection scope. Financial models assume competitive gas pricing, dispatch priority and some form of revenue stabilisation. In reality, none of those elements is secured. Gas supply pricing remains exposed to regional volatility, grid operators are reluctant to grant firm dispatch rights without capacity market mechanisms, and power offtake is largely merchant. The feasibility therefore shows acceptable internal rates of return only under optimistic assumptions that cannot be contractually locked. Rather than confronting this mismatch, sponsors commission updated studies that adjust spark-spread scenarios and carbon price forecasts, keeping the project alive on paper while deferring the hard decision to absorb merchant risk.
Even the newest layer of studies, focused on hydrogen readiness and blending in gas networks, fits the same structural pattern. Transmission operators commission analyses to demonstrate technical compatibility and long-term alignment with EU policy, often at costs of €1–3 million per study. These documents confirm that limited blending is technically possible with incremental capex of €50–100 million over time. What they cannot provide is a path to financial close, because no anchor hydrogen consumers exist, no tariff recovery framework is defined and no cross-border regulatory alignment is in place. The studies function as strategic signalling rather than as preparation for construction, extending the feasibility loop into the next technological narrative.
When these cases are viewed together, a consistent economic logic emerges. In SEE gas projects, feasibility studies are not failing because the numbers are wrong. They persist because they allow stakeholders to capture political and institutional value without triggering financial exposure. A study costs €0.5–5 million, delivers visibility, alignment with EU agendas and proof of activity. Construction requires hundreds of millions in capital, multi-year permitting battles and explicit assumption of utilisation risk. In systems where political reward is front-loaded and financial accountability is diffuse, rational actors prefer the former.
The few projects that do break this pattern do so only when at least two conditions are forced simultaneously: capital is committed early, often through sovereign guarantees or IFI co-financing; system acceptance is formalised through reserved capacity and binding connection offers; and revenue certainty is established via regulated tariffs, ship-or-pay contracts or long-term offtake. In most SEE gas projects, none of these conditions is locked during feasibility. Instead, feasibility becomes a holding pattern that defers conflict between national budgets, regulators, operators and investors.
The outcome is visible across the region. Shelves fill with increasingly sophisticated studies, while energy security and diversification objectives remain unmet. Until feasibility in SEE gas projects is redefined as a phase that must end with irreversible commitments rather than optional recommendations, the region will continue to produce documents at scale while importing risk, volatility and dependency at even greater scale.