Southeast Europe’s gas market is entering autumn with European benchmark prices above €70/MWh after a summer rally driven by Gulf LNG disruption, strong gas-fired power demand and lagging storage injections, leaving September and October exposed to further volatility despite improved regional supply routes.
European TTF prices rose steadily through the summer. The benchmark averaged about €44.74/MWh in June, €53.29/MWh in July and €61.55/MWh in August, while the provisional September average through Sept. 5 had climbed to around €71.49/MWh.
The move represents an increase of almost 60% from June to early September, reversing expectations earlier in the summer that improving LNG availability could push European gas prices lower ahead of winter.
The main change came from the global LNG market.
Renewed conflict around the Gulf and restrictions affecting Qatari LNG exports increased competition for flexible cargoes at the same time Europe was trying to rebuild depleted storage.
Hot weather added another source of demand by increasing gas-fired power generation across Southern and Southeast Europe.
That combination weakened the normal summer mechanism in which low prices encourage storage injections before the heating season.
EU underground storage stood at about 66% full on Sept. 4, holding roughly 747 TWh, compared with around 79% at the same point last year and a historical level above 80%.
Southeast European storage positions are mixed but generally stronger than those of Germany and the Netherlands.
Hungary was about 70% full, Romania 72%, Croatia close to 75% and Bulgaria around 63% in early September.
Those inventories provide a buffer but do not insulate the region from the European benchmark because imported gas and replacement LNG remain priced against international markets.
The European Commission has said there is no immediate security-of-supply threat, citing lower structural demand, expanded LNG capacity and greater diversification since the 2022 energy crisis.
The market is nevertheless pricing a tighter winter starting point.
That distinction is important for Southeast Europe.
The region has substantially more physical supply options than it did several years ago, but those routes do not guarantee cheap gas.
Greece has become the centre of that transformation.
Greek LNG imports through Revythoussa and Alexandroupolis reached about 27.9 TWh in the first eight months of 2026, up almost 32% year on year and a record for the period.
Alexandroupolis LNG imports more than doubled month on month in August to about 1.13 TWh, offsetting weaker deliveries through Revythoussa.
At the same time, Russian gas entering Greece through Sidirokastro rose to 2.62 TWh in August, its highest monthly level this year, while Azerbaijani gas through the TAP-linked Nea Mesimvria entry point fell sharply.
The result was not substitution of one source with another but a more diversified portfolio.
Greece also exported about 11.9 TWh of gas during the first eight months, a three-year high, reinforcing its emerging role as both consumer and transit market.
Gas use in Greek electricity generation remains a critical part of that balance.
Power plants consumed around 4.66 TWh in August, representing more than 80% of Greek domestic gas demand during the month.
That gives the regional gas market a direct link to electricity fundamentals.
Periods of weak hydro, nuclear outages or low wind increase gas-fired generation and can tighten gas demand even outside the heating season.
Bulgaria remains an important exception to the wider price shock.
Its regulated September gas price was set at €41.60/MWh, up 5.5% from August but still substantially below international hub prices because of the contribution of lower-priced Azerbaijani gas.
That creates a potential cost advantage for Bulgarian heating companies and industrial consumers relative to buyers fully exposed to TTF-indexed supply.
But even Bulgaria is moving in the same direction.
Its regulated price has risen from €35.62/MWh in June to €41.60 in September as the share of cheaper supply in the portfolio declined.
The summer also accelerated the physical integration of the Western Balkans into the southern gas system.
Serbia and North Macedonia formally joined the Vertical Gas Corridor on Sept. 4, extending cooperation between transmission operators from Greece and Bulgaria toward the Western Balkans.
The Greece-North Macedonia interconnector is under construction, while North Macedonia has already contracted work on its section of the future connection with Serbia.
The infrastructure increases access to LNG arriving in Greece and to Azerbaijani supply, but its most important impact will be security and optionality rather than a guaranteed price discount.
The September market is likely to remain caught between softer seasonal demand and continued storage buying.
Cooling demand should decline from August levels, reducing gas use in electricity generation if weather normalises.
But Europe still needs injections before winter, while LNG availability remains uncertain.
Current forward pricing around €70-72/MWh for September and October reflects that balance.
A reasonable base case is for European and hub-linked SEE gas to remain broadly in a €65-80/MWh range through September, with large day-to-day moves around LNG shipping and Middle East headlines.
October should normally reduce cooling-related gas demand but introduces the first meaningful heating load and moves the market closer to storage withdrawal season.
The current forward curve does not price a major autumn collapse, with October gas still near €71/MWh.
If Gulf LNG flows stabilise and September temperatures remain mild, prices could move back toward €55-65/MWh.
The main upside scenario is more severe.
A prolonged Qatari LNG disruption combined with an early cold period and continued low storage could push TTF toward €85-100/MWh, particularly if Europe is forced to outbid Asia for flexible LNG cargoes.
For Southeast Europe, the exposure 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 diversified terminal system gives it stronger physical security and growing transit value.
Hungary and Serbia retain access to Russian gas through the southern route while simultaneously building alternatives through Greece and Bulgaria.
The regional gas story for September and October is therefore different from the crisis of 2022.
The immediate risk is less about whether molecules can reach Southeast Europe and more about what price the region must pay for flexible supply when European storage is low and LNG is globally contested.
That keeps gas relevant to electricity prices as well.
With TTF around €70/MWh, flexible gas-fired plants enter the autumn with substantially higher short-run costs than they carried at the start of summer.
If hydro and nuclear availability remain weak, that gas price will increasingly set the ceiling for Southeast Europe’s evening power market through September and October.
Research verification: European storage was about 66.1% on Sept. 4, with Hungary near 70%, Romania 72%, Bulgaria 63% and Croatia 75%. TTF’s summer trajectory rose from €44.74/MWh in June to €53.29 in July, €61.55 in August and about €71.49 for early September. Greek LNG, consumption and export figures are based on DESFA-derived August data. Bulgaria’s September regulated price is €41.60/MWh. Serbia and North Macedonia formally joined the Vertical Gas Corridor on Sept. 4.
