The conflict in the Middle East has altered the global gas supply picture. Disruptions to shipping through the Strait of Hormuz have restricted access to more than 280 million cubic metres per day of LNG, equivalent to roughly one-fifth of global supply, much of it originating from Qatar’s Ras Laffan complex. QatarEnergy has declared force majeure on affected supplies. Although Qatar accounts for a relatively small share of EU LNG imports, Europe must compete with Asian buyers for flexible US cargoes, which can be redirected towards whichever market offers the highest price.
The supply shock has compounded Europe’s storage challenges. Following a cold winter, EU gas storage fell to 28% of capacity at the end of the withdrawal season, compared with 56% and 34% in the corresponding periods of earlier years. Storage replenishment has also proved challenging, with inventories reaching approximately 811 TWh, or 72% of working capacity, compared with 940 TWh, or 83%, in the previous year. The shortfall of around 130 TWh is equivalent to roughly one and a half times the volume of gas transported through the Greek transmission system in a full gas year.
The comparison with the first winter following Russia’s invasion of Ukraine is instructive. In both cases, a geopolitical shock removed a major source of supply, prompting Europe to rely more heavily on LNG. Prices remain below the 2022 peak, when the Dutch TTF benchmark approached €340/MWh. However, the physical supply buffer is thinner than it was when European storage reached approximately 95% of capacity before that winter, equivalent to around 1,060 TWh.
ENTSOG’s winter assessment illustrates the limited margin for error. Under normal temperatures and adequate LNG availability, Europe could finish the heating season with storage at 29%. If LNG supplies remain constrained, inventories could fall to 13%. In a cold winter, demand reductions of 7% to 12% could be required even after storage is drawn down to strategic reserves equivalent to 11% of capacity, which are excluded from ENTSOG’s model. Releasing these reserves, estimated at approximately 125 TWh, could ease the pressure but would not eliminate the need for substantial demand reductions under the cold-weather scenarios.
The challenge extends beyond the heating season. EU regulations require storage to reach 90% of capacity within a designated autumn filling window, subject to flexibility provisions for difficult market conditions. ENTSOG’s assessment indicates that Europe could rebuild storage to the target under adequate LNG supply, but inventories would reach only around 65% if LNG availability remained constrained.
The regional implications are particularly important for Greece. ENTSOG identifies landlocked countries in Central and South-Eastern Europe as especially vulnerable to LNG scarcity. Under a cold-weather peak scenario, with storage at 35% and no Russian pipeline gas, unserved demand could reach 12% in South-Eastern Europe, compared with 6% across the EU. Limited pipeline capacity restricts the volume of gas that can move from Western European LNG terminals towards the south-east, increasing the importance of supply routes through Greece.
The price signal: TTF reflects sustained supply pressure
European gas prices have responded to the supply shock in successive waves. Before the disruption, TTF traded at relatively moderate levels of approximately €28–40/MWh. The closure of the Strait of Hormuz triggered a sharp price increase, with monthly gains exceeding 60% and month-ahead volatility reaching 160%.
A ceasefire between Iran and the United States subsequently eased prices, before concerns about slower storage replenishment contributed to another increase. TTF averaged €76.48/MWh in September, crossed €80/MWh for the first time since 2023 and reached €86/MWh in October, its highest level since late 2022.
The forward curve suggests that the market expects supply pressure to be concentrated in the near term. At the end of September, the winter gas contract traded at €72.35/MWh, compared with €53.41/MWh for the following summer, a backwardation of almost €19/MWh. By comparison, the corresponding winter and summer contracts in the previous year traded at €31.72/MWh and €30.46/MWh, respectively. The winter contract was therefore approximately 128% higher year on year.
Spot prices have also moved above the winter contract, indicating that buyers are paying a premium for immediate delivery, even as the forward curve points to lower prices in the following summer.
For Greece, where LNG purchases are closely linked to TTF and underground storage is unavailable, elevated European benchmark prices feed directly into the cost of gas supply.
Greece: demand growth is driven by exports
Analysis of gas allocations at the exit points of the Greek transmission system shows that total throughput increased by approximately 13% over the first nine months of the reporting period, from 56.4 TWh to 63.5 TWh.
The headline figure conceals two opposing trends. Domestic consumption declined by 3%, from approximately 51.3 TWh to 49.9 TWh, while exports almost tripled, rising by 169% from around 5.1 TWh to 13.6 TWh. Without the additional 8.5 TWh of exports, overall gas throughput would have declined.
Within domestic demand, consumption through distribution networks increased by 6% to approximately 10 TWh. Gas use for power generation declined by 3% to around 33.2 TWh, while industrial consumption fell by 10% to approximately 6.8 TWh. Power generation nevertheless remains the anchor of the domestic market, accounting for roughly two-thirds of consumption.
Monthly figures indicate that export growth is not simply seasonal. Domestic consumption fell by 22% between August and September, from approximately 5.6 TWh to 4.4 TWh, while exports increased by 4% to around 1.74 TWh. Exports consequently represented approximately 28% of all gas leaving the system, reflecting strong external demand.
With approximately one-fifth of gas throughput re-exported over the nine-month period, Greece has evolved from a domestic gas consumer into a regional LNG gateway for South-Eastern Europe, a region particularly exposed to supply constraints.
Greece: LNG has become the marginal source of supply
Total Greek gas imports increased by approximately 13%, with LNG accounting for all of the growth. Pipeline imports remained broadly stable at around 33.4 TWh, down 1%. Flows through Sidirokastro, an entry point associated with Russian gas, remained at approximately 25.4 TWh, while TAP deliveries through Nea Mesimvria declined by 3% to around 8 TWh.
LNG imports increased by 32% to approximately 30.2 TWh. Revithoussa received around 24.3 TWh, an increase of approximately 2.6 TWh, while the Alexandroupolis floating storage and regasification unit (FSRU) supplied around 5.8 TWh, an increase of approximately 4.8 TWh.
LNG now accounts for almost half of Greek gas supply, linking the country’s supply costs closely to global LNG market conditions. Alexandroupolis has also become a significant source of supply, providing much of the additional regasification capacity supporting export growth.
Data from DESFA indicate that Revithoussa handled approximately 80% of Greek LNG imports. Cargo volumes reveal a shift towards larger deliveries. Thirty-two cargoes carrying 24.25 TWh were unloaded during the reporting period, compared with 36 cargoes carrying 22.41 TWh in the corresponding prior-year period. This reflects a move towards full-size cargoes of approximately 1 TWh, replacing smaller deliveries of around 0.5 TWh.
Larger cargoes can reduce unit supply costs, but in a system without underground storage, delays or diversions affecting individual cargoes can have a greater impact on the overall gas balance.
The origin of supply is another important consideration. The United States supplied 17.88 TWh, approximately 74% of total LNG volumes, followed by Nigeria with 4.16 TWh, or around 17%. Congo, Egypt, Algeria and Mauritania collectively accounted for less than 10%.
This concentration in US supply highlights the potential value of diversifying procurement across a wider range of suppliers and regions.
No cargo unloaded at Revithoussa originated in Qatar or elsewhere in the Gulf during the period covered by the data. Greece therefore appears to have limited direct exposure to the Hormuz disruption in terms of physical LNG volumes, but remains exposed through prices. Its US and West African cargoes compete in the same Atlantic Basin market as supplies sought by European and Asian buyers.
Monthly import data further illustrate LNG’s role as a flexible source of supply. Total imports fell by 17% to approximately 6.1 TWh, while LNG imports declined by 24% to around 2.3 TWh. Pipeline gas consequently accounted for 63% of supply. Lower demand, including a 31% reduction in gas consumption for power generation, explains part of the change, while the remainder reflects LNG’s role as the balancing source.
Within pipeline supplies, Sidirokastro accounted for approximately 76% of September flows and TAP for 24%. Across the nine-month period, Sidirokastro supplied around 40% of Greek imports. The EU’s planned phase-out of Russian gas will require these volumes to be replaced, increasing the importance of LNG imports through Revithoussa and Alexandroupolis and higher utilisation of TAP.
Greece and the wider South-Eastern European region are therefore likely to become more dependent on LNG and, consequently, on TTF-linked prices for marginal supply. To reduce exposure to future price spikes, the EU and national governments could encourage medium- and long-term LNG contracts through joint purchasing arrangements, including the AggregateEU platform, or state-backed credit support for buyers.
Storage replenishment could also be planned more evenly throughout the injection season, using the flexibility available under EU storage regulations to reduce the risk of concentrated purchasing during periods of high prices.
Implications for the Greek gas market
Greece’s exposure to elevated gas prices is substantial. Gas-fired power generation accounts for a large share of domestic gas consumption, meaning higher gas prices can translate directly into higher wholesale electricity costs.
Annualising domestic consumption suggests that every €10/MWh increase in TTF adds approximately €0.67 billion annually to the cost of gas consumed in Greece. A price increase from approximately €31/MWh to €86/MWh would therefore imply an additional annualised cost of around €3.7 billion if sustained.
These estimates are illustrative. They assume that all gas volumes are priced at TTF, whereas hedging strategies, long-term supply contracts and alternative price indexation can materially reduce actual exposure.
Export growth also creates an operational trade-off. During a cold spell, demand in importing markets to the north could peak simultaneously with Greek heating and power demand, placing competing demands on the same regasification and transmission infrastructure.
National and EU capacity allocation and emergency supply rules provide a framework for managing such situations. However, simultaneous peaks in domestic and export demand could still expose operational constraints. Stress-testing these arrangements would help ensure that Greece’s role as a regional hub does not compromise domestic security of supply.
Strategic implications for Greece’s gas market
Greece has developed into a regional gas gateway for South-Eastern Europe, supported by infrastructure that is already in place. This creates strategic and commercial opportunities for the country and neighbouring markets.
At the same time, the Greek market has a concentrated risk profile: no underground storage, substantial exposure to spot LNG prices, a power sector heavily reliant on gas, and a significant pipeline supply stream that must be replaced as Russian gas is phased out.
Four areas deserve particular attention.
- Securing supply before the market tightens
Greek suppliers and large consumers could secure part of their gas requirements through medium- and long-term LNG contracts rather than relying exclusively on short-term purchases. Diversifying supply across the United States, Nigeria, Egypt, Algeria and other producers could further reduce concentration risk.
Over the medium term, the absence of underground storage remains a structural weakness. Addressing this gap should be considered a security-of-supply priority as well as a commercial issue.
- Managing the regional hub role
Export growth is strategically valuable, but capacity allocation and emergency supply arrangements should be stress-tested against scenarios in which domestic and regional demand peak simultaneously.
Coordination with neighbouring transmission system operators would help identify bottlenecks and clarify how available capacity should be allocated during periods of regional scarcity. This is a regional as well as a national priority, given the particular vulnerability of South-Eastern Europe to constrained LNG supplies.
- Preparing for the replacement of Russian gas
Russian pipeline volumes entering through Sidirokastro will need to be replaced as EU restrictions take effect. Potential alternatives include additional LNG imports through Revithoussa and Alexandroupolis and increased utilisation of TAP.
Planning should account not only for aggregate import capacity but also for the availability of cargoes, competition with other buyers, transportation costs and the ability of the transmission network to deliver gas where it is needed.
- Managing the pass-through from gas to electricity prices
Suppliers and industrial consumers can use systematic hedging strategies, including layered forward purchases over a 12- to 24-month horizon and swaps or price collars to limit exposure to price volatility.
Gas-fired power generators can hedge gas and electricity prices together to manage clean spark spreads. Large industrial consumers can also consider fixed-price power purchase agreements, including agreements linked to renewable generation.
Meanwhile, flexibility resources such as battery storage and demand response can reduce the number of hours in which gas-fired power stations set wholesale electricity prices, helping to limit the impact of gas market volatility on electricity costs.
Greece’s development as a regional gas hub offers substantial strategic advantages, but infrastructure alone is not enough. The long-term resilience of the market will depend on securing reliable supplies, diversifying procurement, establishing clear rules for allocating capacity during periods of scarcity and strengthening risk-management practices across the gas and electricity sectors.
