On Thursday, August 13th, the European natural gas market re-entered a phase where pricing is driven by a combination of factors: inventory, weather, and liquefied natural gas (LNG) supply. Recently, benchmark European natural gas prices briefly surpassed €62/MWh, approaching the highs of late July. Meanwhile, European gas storage levels remain historically low for this time of year. The core signal from the market is clear: the biggest challenge is not an immediate physical supply disruption, but rather how high a price the European energy system must pay for a safety margin given the simultaneous increase in restocking costs, peak winter demand, and global LNG competition. The European natural gas inventory problem cannot be viewed solely by the amount stored; more importantly, it depends on whether the market has sufficient incentive to shift natural gas consumption from current demand to winter. As of August 10th, European inventories stood at approximately 59%, the lowest level for this time of year since 2009. Gas storage is essentially an inter-period arbitrage opportunity. Under normal circumstances, summer natural gas demand is low, and the price of longer-term winter contracts is higher than near-term contracts. Only when the price curve covers financing, storage, and loss costs will companies be willing to inject gas. However, the Middle East conflict this year has led to a tightening of the immediate liquefied natural gas supply, which has driven up near-month prices rapidly. The traditional price difference between summer and winter prices has been compressed and even reversed at one point, resulting in a decrease in the commercial incentive for gas storage. This is also the most noteworthy structural issue in the current market. Low inventory levels do not necessarily lead to a crisis; what truly needs to be guarded against is the simultaneous occurrence of low inventory levels and insufficient incentives for restocking. When gas storage activities increasingly rely on policy requirements rather than the economic returns provided by the forward curve itself, the natural gas pricing mechanism will become more sensitive to expectations of government intervention. The impact of the Middle East conflict on the natural gas market far exceeds that of traditional energy transportation disruptions. The Strait of Hormuz normally carries nearly 20% of the world's liquefied natural gas (LNG) supply. Data from the International Energy Agency shows that after transportation through the strait was affected, the supply and demand pattern of the global natural gas market, which was originally expected to improve from the second half of 2025, was disrupted. From March to June, LNG shipments from Qatar and the UAE decreased by approximately 35 billion cubic meters year-on-year. Although new supply from other regions offset about three-quarters of this, global LNG production still decreased by about 4% year-on-year. More importantly, medium-term supply expectations have also changed. The International Energy Agency (IEA) predicts that global liquefied natural gas (LNG) supply from 2026 to 2030 may be reduced by approximately 140 billion cubic meters compared to previous forecasts, due to facility damage and project delays, with the impact concentrated in 2026-2027. This means that the previously anticipated new round of LNG supply easing has been postponed. Therefore, Europe is not currently facing a simple inventory replenishment issue, but rather a marginal repricing of gas sources. Europe can attract more LNG by raising import prices, but this mechanism implies a direct trade-off between supply security and price pressure. As long as global LNG supply remains tight, every percentage point increase in European inventories could result in higher marginal procurement costs than in normal years. Another anomaly in the natural gas market this year is the significant increase in demand for natural gas from the power system during the summer. Europe has recently experienced consecutive days of high temperatures, leading to increased air conditioning loads, while some nuclear, coal, and hydropower plants have been constrained by high temperatures and water levels. Some nuclear power units in France have experienced output limitations due to excessively high river water temperatures, and wind power generation in Germany was once about 60% lower than the seasonal average, forcing the power system to increase the use of gas turbine units. Data shows that in July, European demand for natural gas for power generation was approximately 714 million cubic meters higher than normal. Recently, the Dutch TTF benchmark natural gas price briefly exceeded €62 per megawatt-hour, not far from the peak reached around July 24th. This will create a classic inventory squeeze effect. Natural gas that should have gone into storage is being consumed prematurely in summer power generation; simultaneously, high temperatures are often accompanied by weak winds, causing natural gas to also serve as a peak-shaving power source. The end result is a linkage between gas injection speed, weather, and electricity prices. However, there is another side to Europe's energy structure. Since 2026, wind and solar power installations have continued to expand, which can significantly reduce gas-fired power generation demand during periods of normal wind and sunlight. Latest data shows that European wind and solar power installations have reached nearly 750 million kilowatts, which, in the long term, is weakening the base load attribute of natural gas in the power system. Therefore, the risks this winter should not be simply understood as an absolute shortage of natural gas, but rather as a more fragile dynamic balance between weather, renewable energy output, inventory, and liquefied natural gas imports. The current European gas storage rules maintain the 90% storage target, but allow member economies to complete it between October 1st and December 1st, with an additional 10% flexibility in challenging market conditions; the target can be further adjusted by 5% if adverse conditions persist. This change is crucial. Regulators have realized that requiring the market to replenish its stockpiles at any cost within a fixed period could actually turn the policy target itself into a catalyst for price increases. When all buyers know that Europe must reach a certain inventory level, sellers naturally gain more pricing power in negotiations. From April to July this year, European authorities repeatedly stated that a storage level of around 80% is sufficient to guarantee supply for the winter of 2026-2027 under certain conditions, and there is currently no immediate gas supply security issue. This effectively shifts market focus from "whether 90% can be achieved" to "at what cost to achieve what level of safe inventory." Therefore, what truly needs to be observed in the coming months is not a single inventory figure, but whether there is a divergence between the speed of gas storage, the TTF near-month/far-month spread, LNG arrivals, gas-fired power generation demand, and the intensity of policy intervention. If inventories continue to increase at the cost of persistently high prices in recent months, Europe may gain a greater margin of energy security, but at the same time bear greater pressure on energy costs for industry and residents.