Natural gas moved back to the centre of Southeast Europe’s power-market risk in July 2026 as European benchmark prices rose sharply. Disruption to Gulf LNG shipping, below-normal storage levels and weak regional hydropower increased the cost of dispatchable electricity. The combination also lifted exposure to fuel-price volatility for evening power demand.
Since the start of Europe’s 2022 energy crisis, regional infrastructure has been used to diversify supply away from Russian pipeline gas. Greek LNG terminals, the Greece-Bulgaria route and the wider Vertical Corridor are providing alternatives. Those options still depend on global LNG pricing, transport tariffs and physical shipping conditions.
TTF rises and thermal generation increases
Market conditions shifted toward scarcity pricing during Week 27. Average TTF gas futures were about €43.59/MWh, up 5.5% week on week, while the front-month contract traded near €49.05/MWh. Regional thermal electricity generation rose by 6.5%, increasing 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 reached €58.98/MWh, around 41% higher than a month earlier. The benchmark traded as high as €60.50/MWh during the session, its highest level in four months. The move reflected broader European and global LNG balance rather than a direct shortage within Southeast Europe.
LNG balance tightens with lower storage and fewer Gulf cargoes
European gas storage was below 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, versus a normal rate of roughly 90–100 cargoes per month. Analysts also cut their 2026 global LNG-supply forecast from 441 million tonnes to 431 million tonnes.
Shipping indicators pointed to continued disruption. No LNG tanker was visibly recorded passing through the Strait of Hormuz since July 16, while the ten-day average of laden LNG transits fell from about 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 exports could rebound if passage normalized.
The supply risk premium is described as partly reversible if tanker traffic resumes and releases already loaded LNG cargoes. Until flows normalize, European buyers were expected to price the possibility that storage would need replenishment with fewer available cargoes before winter. This links regional power-price exposure to global logistics constraints.
Gas sets evening power costs as flexibility becomes more valuable
Gas again determined the cost of evening electricity as benchmark prices climbed. At a gas price of €58.98/MWh, fuel alone was estimated at about €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 pushed required electricity prices higher.
Southeast European evening electricity prices could rise toward €150–€200/MWh even when midday solar electricity was inexpensive. Gas was not identified as responsible for every high-price hour because imports, coal availability, congestion and broader scarcity conditions also matter. However, it frequently became the marginal resource when photovoltaic output disappeared and hydropower availability was limited.
On July 10, regional gas-fired output was about 4,521 MW while 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 by 21:00. The spread reflected midday solar abundance versus evening scarcity when gas and other dispatchable resources were required.
Vertical Corridor auctions book capacity for multiple gas years
The Vertical Corridor moved into its first meaningful commercial test as market participants reserved capacity for northbound LNG movements from Greece through Bulgaria, Romania and Moldova toward Ukraine. Annual auctions held on July 6 resulted in more than 45% of offered capacity for the next four gas years being booked. At Sidirokastro interconnection between Greece and Bulgaria, 46% of available export capacity for 2026/27–2029/30 was reserved along with 26% for 2030/31.
A total of 100 GWh per day was offered at Sidirokastro interconnection during those auctions. Tariff reductions and discounts 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 about 13,000 MWh per day, equivalent to around 4.7 TWh annually, while Metlen reserved 20,000 MWh per day.
The bookings were described as validation but not complete derisking because more than half of offered capacity remained unbooked. Operators were still consulting on ways to make commitments more flexible across multiple national transmission systems while competing with other European routes.
Alexandroupolis returns after maintenance; Bulgarian procurement diverges from TTF
The floating LNG terminal at Alexandroupolis returned after 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, connected to the Greek transmission system for onward supply toward Bulgaria and Romania among other Balkan markets.
The terminal received its first post-maintenance cargo on July 6 delivered from Sabine Pass in the United States . Gastrade expected regasification to resume on July 14 with two additional cargoes scheduled for August.
LNG infrastructure did not remove price exposure because it shifts dependence toward global LNG competition, shipping rates, terminal availability and maritime geopolitical risks . National prices could diverge from TTF; Bulgaria’s regulated July supply price was €37.70/MWh excluding access, transmission, excise and VAT despite an approximately €59/MWh European benchmark reference on July 20.
Bulgargaz proposed roughly a 1% reduction for August despite lower scheduled Azerbaijani deliveries during maintenance . The supplier planned compensation through withdrawals from the Chiren storage facility and LNG imported through Greece . The Bulgarian case highlighted how long-term contracts and storage can smooth shocks but cannot permanently eliminate benchmark volatility because replacement LNG ultimately reflects global prices.
Russian import phase-out changes corridor economics; Neptun Deep targets later supply
The EU phase-out of Russian gas is turning corridor economics into a strategic issue under EU Regulation 2026/261. The regulation initiated a phased prohibition on Russian gas imports in March; under ACER’s assessed transition schedule some legacy long-term Russian LNG contracts may continue until end-2026 and pipeline contracts until September 30, 2027.
ACER estimated authorized Russian LNG and pipeline contracts still represented about 45–55 billion cubic metres of annual capacity, with long-term pipeline exposure concentrated partly in Greece, Hungary and Slovakia . Beyond EU members, Russian pipeline gas transiting Bulgaria toward Serbia totaled about 36.8 TWh during January–April 2026 with another 2.3 TWh moving toward North Macedonia .
The replacement challenge involves more than volumes because molecules must reach appropriate entry points with sufficient interconnection capacity and commercially viable contracts supported across tariff systems . July’s Vertical Corridor bookings were positioned as steps converting diversification infrastructure into contracted transportation rather than political capacity alone .
A medium-term supply change could come from Romania’s Black Sea production via the Neptun Deep project. Offshore pipeline construction began in May for a field estimated to contain about 100 billion cubic metres of recoverable gas; first production remains scheduled for 2027. The project is expected to roughly double Romanian gas output and could make Romania a net exporter.
