Natural gas returned to the center of Southeast Europe’s power-market risk in July 2026. A sharp increase in European benchmark prices, disruption to Gulf LNG shipping, below-normal storage levels and weak regional hydropower combined to raise the cost of dispatchable electricity.
At the same time, infrastructure developed since Europe’s 2022 energy crisis began to demonstrate its commercial value. Greek LNG terminals, the Greece-Bulgaria route and the wider Vertical Corridor are providing alternatives to Russian pipeline gas. However, those alternatives remain exposed to global LNG prices, transport tariffs and physical shipping risks.
The gas market moved from manageable conditions toward scarcity pricing. During Week 27, average TTF gas futures stood at approximately €43.59/MWh, up 5.5% week on week, while the front-month contract traded near €49.05/MWh. Regional thermal electricity generation increased by 6.5%, from 6.44 TWh to 6.86 TWh, as coal, lignite and gas compensated for weaker renewable and hydropower output.
By July 20, a CFD reference tracking the European benchmark had risen to €58.98/MWh, approximately 41% higher than one month earlier. The benchmark traded as high as €60.50/MWh during the session, reaching its highest level in four months.
The physical cause was not a direct shortage inside Southeast Europe itself, but the region’s exposure to the wider European and global LNG balance. European gas storage was less than 54% full, compared with 64% at the same point in 2025. Only 26 LNG cargoes had exited the Gulf since the conflict began at the end of February, compared with a normal rate of approximately 90–100 cargoes per month. Analysts also reduced their 2026 global LNG-supply forecast from 441 million tonnes to 431 million tonnes.
Shipping data reinforced the concern. No LNG tanker had been visibly recorded passing through the Strait of Hormuz since July 16, while the ten-day average of laden LNG transits fell from approximately 0.8 cargoes per day in late June to 0.2 by July 15. Seven loaded Qatari carriers holding around 0.57 million tonnes were waiting in the Gulf, although continued production and loading meant exports could rebound relatively quickly if passage normalized.
The risk premium is therefore partly reversible. A resumption of tanker traffic could release already loaded LNG. Until flows normalize, however, European buyers must price the possibility that storage will need to be replenished with fewer available cargoes before winter.
Gas is again determining the cost of evening electricity. At a gas price of €58.98/MWh, the fuel alone costs approximately €98/MWh for a 60%-efficient combined-cycle gas turbine and €107/MWh for a 55%-efficient plant. Carbon allowances, network charges, variable operating costs and start-up costs push the required electricity price even higher.
This calculation helps explain why Southeast European evening electricity prices can rise toward €150–€200/MWh even when midday solar electricity is inexpensive. Gas is not responsible for every high-price hour—imports, coal availability, congestion and broader scarcity conditions also matter—but it frequently becomes the marginal resource once photovoltaic production disappears and hydropower availability is limited.
On July 10, regional gas-fired output stood at approximately 4,521 MW as hydro generation fell by 520 MW. Serbia’s day-ahead market moved from €20/MWh at 14:00 to €208.10/MWh at 21:00. The spread reflected the contrast between midday solar abundance and evening scarcity, when gas and other dispatchable resources were required.
This is changing the commercial role of gas plants. Continuous high-load gas generation becomes increasingly difficult to justify when solar depresses daytime prices. Flexible plants capable of starting quickly and generating during high-value evening hours retain strategic importance, but their revenues become more volatile and increasingly dependent on a relatively small number of expensive periods.
The Vertical Corridor is passing its first meaningful commercial test. Southeast Europe has invested heavily in the idea that LNG arriving in Greece can move north through Bulgaria, Romania, Moldova and eventually Ukraine. July provided important evidence that market participants are willing to reserve that route when tariffs are competitive and the infrastructure offers genuine supply diversification.
Annual auctions held on July 6 resulted in more than 45% of the Vertical Corridor capacity offered for the next four gas years being booked. At the Sidirokastro interconnection between Greece and Bulgaria, 46% of available export capacity for 2026/27 through 2029/30 was reserved, together with 26% for 2030/31. A total of 100 GWh per day was offered.
The result followed targeted tariff reductions and discounts that made the corridor the fourth-cheapest route to Ukraine, compared with costs that had previously been almost three times higher. Atlantic SEE LNG Trade booked approximately 13,000 MWh per day, equivalent to around 4.7 TWh annually, while Metlen reserved 20,000 MWh per day.
This is a credible commercial validation, but not complete derisking. More than half of the offered capacity remains unbooked, and operators are still consulting on ways to make commitments more flexible. The corridor must compete with other European routes while accumulating tariffs across several national transmission systems.
Alexandroupolis returned at a strategically important moment. The floating LNG terminal underwent planned maintenance from April 1 through June 30, during which it could not receive cargoes. Its annual regasification capacity is approximately 5.5 billion cubic metres, and the facility is connected to the Greek transmission system for onward supply toward Bulgaria, Romania and other Balkan markets.
The terminal received its first post-maintenance cargo on July 6, delivered from the Sabine Pass facility in the United States. Gastrade expected regasification to resume on July 14, with two additional cargoes scheduled for August.
The timing is significant. A terminal can only provide diversification when it is physically available, commercially booked and supplied with cargoes. Alexandroupolis returned just as Gulf shipping risk was pushing European gas prices higher, strengthening Greece’s role as a regional entry point for non-Russian gas.
Nevertheless, LNG infrastructure does not guarantee inexpensive gas. It replaces dependence on a particular pipeline supplier with exposure to global LNG competition, shipping rates, terminal availability and geopolitical risks along maritime routes.
National gas prices can diverge from TTF—at least temporarily. Bulgaria illustrates why national procurement prices do not always move immediately with the European benchmark. The regulated July supply price was €37.70/MWh, excluding access, transmission, excise and VAT—well below the approximately €59/MWh European benchmark reference on July 20.
The figures are not directly comparable because the Bulgarian price reflects a procurement portfolio and regulatory methodology, rather than a same-day TTF transaction. Bulgargaz proposed a roughly 1% reduction for August despite lower scheduled Azerbaijani deliveries during maintenance. The supplier planned to compensate through withdrawals from the Chiren storage facility and LNG imported through Greece.
The Bulgarian example demonstrates the value of long-term contracts, storage and diversified procurement in smoothing short-term market shocks. But the protection is finite. Storage withdrawals reduce the gas available for winter, while replacement LNG will ultimately reflect global prices. A regulated price can delay benchmark volatility; it cannot permanently eliminate it.
The EU phase-out of Russian gas is turning corridor economics into a strategic issue. EU Regulation 2026/261 initiated a phased prohibition on Russian gas imports in March. Under the transition schedule assessed by ACER, certain legacy long-term Russian LNG contracts may continue until the end of 2026 and pipeline contracts until September 30, 2027.
ACER estimated that authorized Russian LNG and pipeline contracts still represented approximately 45–55 billion cubic metres of annual capacity, with long-term pipeline exposure concentrated partly in Greece, Hungary and Slovakia.
The implications extend beyond EU members. During January–April 2026, Russian pipeline gas transiting Bulgaria toward Serbia totaled approximately 36.8 TWh, with another 2.3 TWh moving toward North Macedonia. Serbia and North Macedonia do not face identical EU import obligations, but their supply routes, transit arrangements and counterparties remain connected to the changing European gas market.
Replacement is therefore not simply a question of finding an equivalent volume of gas. The molecules must arrive at the right entry point, pass through sufficient interconnection capacity, clear multiple tariff systems and be supported by commercially viable contracts. July’s Vertical Corridor bookings are important because they begin converting diversification infrastructure from political capacity into contracted transportation.
Romania’s Black Sea production could alter the medium-term regional balance. The largest potential supply change is the Neptun Deep project. Offshore pipeline construction began in May for a field estimated to contain approximately 100 billion cubic metres of recoverable gas. First production remains scheduled for 2027, when the project is expected to roughly double Romanian gas output and could turn the country into a net exporter.
Neptun Deep will not solve the July 2026 price shock, because its gas is not yet available. From 2027 onward, however, it could materially change Southeast Europe’s supply structure by increasing indigenous production close to Romania, Bulgaria, Moldova, Hungary and Ukraine.
Its effect on prices should not be overstated. Romanian gas will still be sold into an interconnected European market, and its value will reflect regional demand and alternative import costs. The more durable benefit is reduced dependence on distant LNG cargoes and individual external pipeline suppliers.
Gas remains necessary, but its optimal role is becoming narrower. Natural gas retains a critical role in Southeast Europe because it can provide firm capacity, rapid dispatch and heat as well as electricity. July demonstrated why systems with weak hydropower and high solar penetration still rely on gas after sunset.
The same month also demonstrated the financial vulnerability of excessive dependence. A geopolitical disruption thousands of kilometres away raised the fuel cost of Balkan power plants, increased concerns over winter storage replenishment and strengthened evening electricity prices.
The strongest gas-market positions will belong to countries and companies combining multiple forms of supply and operational optionality: indigenous production, storage, LNG-terminal access, interconnector capacity, flexible procurement and efficient power plants. Infrastructure supported by firm bookings and real commercial use will be more valuable than capacity built solely for strategic symbolism.
Gas is therefore unlikely to disappear from Southeast Europe’s energy system in the near term. Its role is instead shifting away from routine volume generation toward a more expensive form of insurance—used when solar, wind, hydropower, nuclear and imports cannot fully meet demand. July 2026 showed both why that insurance remains necessary and why reducing the number of hours in which it must be used has become an economic priority.
