Southeast Europe’s gas market is entering autumn under renewed price pressure, with European benchmark prices moving above €70/MWh after a strong summer rally driven by disruptions to Gulf LNG supplies, rising gas-fired power demand and slower-than-expected storage injections. The combination leaves September and October exposed to further volatility, even as the region benefits from improved supply routes and greater diversification compared with the energy crisis of 2022.
European TTF prices climbed steadily throughout the summer, averaging around €44.74/MWh in June, €53.29/MWh in July and €61.55/MWh in August. The provisional September average through Sept. 5 had risen to approximately €71.49/MWh, representing an increase of almost 60% from June to early September. The move reversed earlier expectations that stronger LNG availability would push European gas prices lower ahead of the winter season.
The main shift has come from the global LNG market. Renewed conflict around the Gulf and restrictions affecting Qatari LNG exports have increased competition for flexible cargoes at a time when Europe is still rebuilding storage inventories. At the same time, hot weather has supported electricity demand and increased gas-fired generation across Southern and Southeast Europe. This combination has weakened the traditional summer pattern in which lower gas prices encourage aggressive storage injections ahead of winter.
EU underground gas storage stood at approximately 66% full on Sept. 4, with around 747 TWh of gas in storage. That compares with roughly 79% at the same point last year and a historical level above 80%. Storage positions across Southeast Europe are somewhat stronger but remain mixed, with Hungary at around 70%, Romania at 72%, Croatia close to 75% and Bulgaria at approximately 63% in early September.
These inventories provide an important buffer, but they do not fully protect the region from European benchmark prices. Imported gas and replacement LNG remain closely linked to international market conditions, meaning that stronger physical security does not necessarily translate into lower prices for consumers.
The European Commission has maintained that there is no immediate security-of-supply threat, pointing to structurally lower gas demand, expanded LNG infrastructure and greater diversification since the 2022 energy crisis. However, the market is clearly pricing a tighter starting position for the coming winter, creating a significant distinction between physical availability and the cost of securing additional supply.
That distinction is particularly important for Southeast Europe. The region now has substantially more physical supply options than it did several years ago, but those additional routes do not guarantee cheap gas. Greece has emerged as the centre of this transformation, increasingly connecting the region to global LNG markets while also developing its role as a regional transit hub.
Greek LNG imports through Revythoussa and Alexandroupolis reached approximately 27.9 TWh during the first eight months of 2026, almost 32% higher year on year and a record for the period. Alexandroupolis LNG imports more than doubled month on month in August to around 1.13 TWh, helping offset weaker deliveries through Revythoussa.
At the same time, Russian gas entering Greece through Sidirokastro increased to around 2.62 TWh in August, the highest monthly level recorded this year, while Azerbaijani gas through the TAP-linked Nea Mesimvria entry point declined sharply. The result has been less a direct replacement of one source with another than the development of a more diversified regional gas portfolio.
Greece is also becoming increasingly important as an export and transit market. The country exported approximately 11.9 TWh of gas during the first eight months of the year, the highest level in three years. This strengthens Greece’s position as both a major domestic gas consumer and an increasingly important supplier to neighbouring Southeast European markets.
Gas demand from the Greek electricity sector remains central to that balance. Power plants consumed around 4.66 TWh of gas in August, accounting for more than 80% of Greek domestic gas demand during the month. This creates a direct link between regional gas and electricity fundamentals, meaning periods of weak hydro generation, nuclear outages or low wind availability can rapidly increase gas-fired power demand.
Bulgaria remains an important exception to the broader regional price shock. Its regulated gas price for September was set at €41.60/MWh, up 5.5% from August but still significantly below international hub prices. The difference is largely supported by lower-cost Azerbaijani gas, providing Bulgarian heating companies and industrial consumers with a potential cost advantage over buyers more directly exposed to TTF-indexed supply.
Even Bulgaria, however, is moving in the direction of the broader European market. Its regulated gas price has risen from €35.62/MWh in June to €41.60/MWh in September, reflecting a decline in the contribution of cheaper supply within the overall portfolio. The country therefore retains some protection, but that protection is not completely insulated from wider European price movements.
The summer also accelerated the physical integration of the Western Balkans into the southern European gas system. Serbia and North Macedonia formally joined the Vertical Gas Corridor on Sept. 4, extending cooperation between transmission system operators from Greece and Bulgaria toward the Western Balkans.
The Greece-North Macedonia interconnector is currently under construction, while North Macedonia has already contracted work on its section of the future connection with Serbia. Once developed, the infrastructure will improve access to LNG arriving through Greece as well as Azerbaijani gas. Its most important benefit, however, will be greater security and supply optionality rather than a guaranteed price discount.
The September market is therefore likely to remain caught between softer seasonal demand and continued storage requirements. Cooling demand should decline from August levels if temperatures return to normal, reducing gas consumption in electricity generation. At the same time, Europe still needs to inject gas into storage before winter, while the availability of LNG remains uncertain.
Current forward pricing around €70-72/MWh for September and October reflects this delicate balance. A reasonable base case is for European and hub-linked Southeast European gas prices to remain broadly within a €65-80/MWh range through September, with significant day-to-day movements possible in response to LNG shipping developments and geopolitical headlines.
October presents a more complicated outlook. Cooling-related demand should normally fall, but the first meaningful heating demand begins to emerge as the market moves closer to the winter withdrawal season. The current forward curve does not anticipate a major autumn collapse, with October gas still trading near €71/MWh.
If Gulf LNG flows stabilise and September temperatures remain mild, prices could move back toward €55-65/MWh. The upside scenario is considerably more challenging. A prolonged disruption to Qatari LNG exports, combined with an early cold spell and continued low storage levels, could push TTF prices toward €85-100/MWh, particularly if Europe is forced to compete more aggressively with Asia for flexible LNG cargoes.
The impact across Southeast Europe will not be uniform. Bulgaria should retain some protection from contracted Azerbaijani supply, while Romania benefits from substantial domestic production. Greece will remain more directly exposed to LNG economics, but its increasingly diversified terminal system provides stronger physical security and greater regional transit value.
Hungary and Serbia continue to have access to Russian gas through the southern route while simultaneously developing alternatives through Greece and Bulgaria. This creates a more flexible regional supply structure, allowing countries to balance different sources depending on availability, infrastructure and market prices.
The regional gas story for September and October is therefore fundamentally different from the crisis of 2022. The immediate concern is less about whether gas molecules can physically reach Southeast Europe and more about what price the region must pay for flexible supply when European storage remains below historical levels and global LNG cargoes are contested.
That dynamic also keeps gas closely linked to regional electricity prices. With TTF around €70/MWh, flexible gas-fired power plants enter autumn with substantially higher short-run generation costs than they faced at the beginning of summer. If hydro and nuclear availability remain weak, gas prices are likely to increasingly influence the ceiling for Southeast Europe’s evening electricity market throughout September and October.
