Serbia has diversified the physical routes through which it can receive gas, but its supply position remains exposed to a more difficult question: whether alternative gas can reach the country at a commercially sustainable price and in sufficient volume during a regional shortage.
That distinction sits at the centre of the Vertical Gas Corridor, the network of pipelines, interconnectors, compressor stations, LNG terminals and capacity products intended to move gas northwards from Greece through Bulgaria and Romania toward Moldova, Ukraine and Central Europe. The corridor is no longer merely a political diversification concept. Infrastructure expansion, new tariff arrangements and capacity auctions are gradually turning it into a usable commercial route.
Serbia is geographically adjacent to this system rather than fully embedded in its main northbound axis. Its direct connection with Bulgaria gives it access to the Bulgarian gas network and, through that network, to Azerbaijani gas from the Southern Gas Corridor and LNG delivered through Greek terminals. Yet most Serbian imports still depend on gas entering Bulgaria from Turkey through the TurkStream and Balkan Stream system.
The Serbia–Bulgaria interconnector, running between Niš and Dimitrovgrad and onward to the Bulgarian network, provides approximately 1.8 bcm a year of capacity toward Serbia. It created an alternative to the dominant route through the Balkan Stream system and allowed Serbia to contract initial volumes of Azerbaijani gas. Its strategic value rises sharply when Greek LNG terminals and the Greece–Bulgaria Interconnector have spare capacity.
The Greek supply base now includes the Revithoussa LNG terminal, the Alexandroupolis floating LNG facility, the Trans Adriatic Pipeline and domestic transmission infrastructure operated by DESFA. The Greece–Bulgaria Interconnector, or IGB, has initial capacity of approximately 3 bcm a year, expandable to 5 bcm. Bulgaria is upgrading the south-to-north route so that more gas can reach Romania and the markets beyond it.
The emerging route nevertheless faces a difficult market test. Gas transported from an LNG terminal in Greece to Serbia passes through several commercial stages: LNG procurement, shipping, regasification, Greek transmission, interconnection capacity, Bulgarian entry-exit charges and Serbian network costs. The cumulative tariff can make diversification gas substantially more expensive than pipeline volumes delivered under established long-term arrangements.
This tariff stacking has constrained use of the Vertical Corridor in previous years. Operators from Greece, Bulgaria, Romania, Moldova and Ukraine have now agreed a revised commercial approach intended to make the route more competitive. The planned structure introduces daily, monthly, quarterly and annual capacity products for the 2026–2027 gas year, with implementation scheduled from October 2026.
Infrastructure demand is becoming visible in capacity bookings. Bulgartransgaz reported bookings of approximately 99,398 MWh per day at the Kardam–Negru Vodă exit toward Romania for the 2025–2026 gas year, representing more than 70% of the offered capacity of slightly above 140,000 MWh per day. The previous annual booking was about 44,710 MWh per day, indicating that market interest more than doubled.
That increase reflects demand from Ukraine and Moldova as well as commercial expectations that LNG and Caspian gas will play a larger role in Central and Southeast Europe. It does not guarantee equivalent physical utilisation. Shippers can book capacity as a strategic option, while actual flows depend on commodity spreads, Ukrainian demand, storage economics and the availability of LNG cargoes.
ENTSOG’s Summer Supply Outlook 2026 illustrates the scale of the challenge. EU gas storage stood at only 28%, equivalent to approximately 314 TWh or 29 bcm, on 1 April 2026. Reaching a 90% storage level by the end of the injection season would require roughly 943 TWh or 86 bcm of LNG, alongside continued pipeline supplies and intensive use of European gas infrastructure.
Serbia started the season in a comparatively stronger position. The country had around 2.0 TWh stored against working gas volume of approximately 4.1 TWh, giving a filling level of 48.8%. Bulgaria stood at 34.2%, Romania at 23.9%, Hungary at 32.5%, and Croatia at only 14.8%. ENTSOG Summer Supply Outlook 2026
Serbia’s percentage advantage should not be overstated. Its absolute storage volume is small relative to annual demand and potential winter consumption. Banatski Dvor provides essential seasonal flexibility, but the country still requires dependable import capacity during prolonged cold weather, industrial demand recovery or disruption of its primary supply route.
ENTSOG calculates that a complete interruption of remaining Russian pipeline flows would require an additional 66 TWh, or roughly 6 bcm, of LNG during summer 2026. Landlocked CEE and SEE markets would be more exposed than coastal countries because replacement gas must pass through several networks before reaching them.
Under an optimal-LNG scenario, the European network can technically support high storage levels. Under the tight-LNG case, storage would reach only around 76% by the end of September. Combining limited LNG availability with the loss of Russian pipeline supply reduces the modelled level to approximately 70%. The infrastructure can transport the gas, but only when sufficient cargoes are procured and commercial incentives support continuous injections.
For Serbia, this is the defining distinction between route diversification and supply diversification. A new interconnector creates the option to receive non-Russian gas. It does not secure the commodity, reserve regasification capacity, book transit rights or fix the final delivered price.
A robust Serbian portfolio would need several layers. Long-term pipeline supply can provide a baseload component. Azerbaijani gas can add source diversity through the Southern Gas Corridor. Greek LNG can serve as contracted diversification and a flexible marginal source. Banatski Dvor and other planned storage capacity can manage seasonality. Short-term capacity products can provide access during price dislocations or emergencies.
The portfolio also needs commercial discipline. Booking annual corridor capacity provides reliability but creates a fixed cost even when the route is unused. Relying entirely on short-term bookings lowers fixed expenditure but exposes the buyer to unavailable capacity during a regional shock. A balanced strategy would reserve a core level of firm capacity while retaining monthly and quarterly optionality.
Gas-fired electricity generation makes the exposure broader than the gas sector. Serbia currently has limited gas-fired power capacity compared with Greece, Italy or Hungary, but industrial cogeneration and future flexible generation could increase consumption. Regional gas prices already influence Serbian electricity through cross-border marginal pricing. A high-cost LNG replacement scenario can raise Greek, Hungarian and Italian power prices even before Serbia burns additional gas domestically.
This creates a mixed effect for EPS and renewable generators. Higher regional gas prices can lift wholesale electricity prices and improve merchant renewable revenues. They also raise industrial costs, weaken electricity demand and increase the price of balancing energy when flexible gas plants set the marginal price. A wind or solar project with a fixed-price PPA may receive little benefit while its offtaker absorbs the inflationary impact.
Energy-intensive Serbian companies face the largest combined exposure. Fertiliser, chemicals, metals, food processing, glass and other heat-intensive industries require predictable gas costs. Their European customers increasingly demand carbon and energy documentation, while CBAM and other climate policies place additional pressure on production economics. Expensive spot LNG delivered through multiple tariff zones can undermine export margins even where physical supply remains uninterrupted.
The Vertical Corridor therefore needs to be judged through delivered-cost competitiveness, not only engineering capacity. Expansion from 3 bcm to 5 bcm on the Greece–Bulgaria route is strategically valuable, but utilisation depends on reducing accumulated tariffs, coordinating capacity products and providing transparent access across the entire chain.
The corridor also creates a financing question. Compressor stations, pipeline reinforcement and storage expansion are regulated infrastructure with long asset lives. Their investment case depends on credible future throughput even as European methane demand declines. Operators must avoid building assets whose costs are recovered from a shrinking customer base through higher tariffs.
Hydrogen-readiness can strengthen the long-term argument, but only where conversion is technically and commercially credible. A pipeline labelled hydrogen-ready does not automatically become part of a future hydrogen market. Repurposing requires material compatibility, compressor changes, metering upgrades, purity management, confirmed production and bankable industrial demand.
Serbia could eventually connect regional hydrogen production, fertiliser demand, refining, steel and mobility applications. That opportunity remains behind the immediate requirement to secure affordable methane through the late 2020s. Gas still supports industrial heat, household demand and regional power-system flexibility, while new electricity and renewable infrastructure develops.
The Vertical Corridor gives Serbia a credible alternative route and stronger bargaining position. Its real value will be determined in capacity auctions, LNG tenders and delivered border prices rather than at intergovernmental ceremonies. Infrastructure has opened the door; commercial utilisation must now make diversification durable.
