Japan Maintains LNG Inventory Cushion as JKM Spot Climbs Past $15
Power sector stocks held above year-ago levels in mid-June as Asian LNG prices surged on Norwegian disruptions and Middle East supply uncertainty.
JKM Asian LNG spot prices reached $15.74 per MMBtu on June 24 (2026-06-24), extending gains that began when Norwegian supply disruptions in mid-June tightened the global LNG balance. The Northeast Asian benchmark moved from the mid-$9s to the mid-$13s during the week of June 12-16 (2026-06-12 to 2026-06-16) after extended maintenance at the Nyhamna gas processing plant disrupted Norwegian gas flows, according to European Gas Hub data.2
Japan's Ministry of Economy, Trade and Industry reported on June 14 (2026-06-14) that power sector LNG inventories totalled 2.30 million tonnes as of June 11 (2026-06-11), down 0.08 million tonnes week-on-week but 0.16 million tonnes above the same point in 2025.2 Japan sources roughly 98% of its domestic gas demand from LNG imports, and the power sector absorbs 55-65% of total consumption, so even a small year-on-year surplus in tank levels provides meaningful headroom against a supply shock or demand spike.1
The stock position carries more weight than usual given the Middle East war and effective closure of the Strait of Hormuz. About 90% of Japan's crude oil originates from the region, and Tokyo has already drawn down roughly 80 million barrels from strategic petroleum reserves, equivalent to about 26 days of domestic demand.1 The LNG exposure is more limited: only around 6% of Japan's LNG supply transits Hormuz, sourced from Qatar and the UAE. The bulk arrives from routes that bypass the Strait. Australia supplied 26 million tonnes in 2025, Malaysia 10 million tonnes, and Russia 5.8 million tonnes under the Sakhalin-II sanctions exemption covering Mitsui and Mitsubishi's stakes.1
Japan imported 66.3 million tonnes of LNG in 2025, down 1.5% year-on-year, retaining its position as the world's second-largest buyer after China.1 The declining trend reflects slower economic growth, renewables expansion, and a gradual return of nuclear capacity, which currently accounts for 9% of power generation. Gas-fired generation remains the largest single source at roughly 32% of output, followed by coal at 28%.1
The power mix creates a layered cost structure. Gas at 32% of generation sits above coal at 28%, with nuclear at 9% and oil-fired capacity at 7% filling the balance.1 At current JKM levels, gas-fired generation is meaningfully more expensive than coal, but Japan lacks the flexible fuel-switching capacity that European utilities use to arbitrage between fuels on short notice. Nuclear restarts are the more durable relief valve.
Coal's role as swing backstop is expensive in absolute terms. Newcastle physical coal settled at $125.90 per tonne on June 24 (2026-06-24). With gas and coal together accounting for more than 60% of Japan's power output, fuel costs remain the primary lever on wholesale electricity prices, and both are elevated relative to pre-crisis levels.
The domestic refining position provides partial insulation on the oil side. Japan covers nearly all of its gasoline demand and around 95% of its diesel through domestic refineries, buffering the retail fuel market from crude import cost spikes.1 But refinery margins compress when crude acquisition costs rise, and once the SPR draw-down ends, replacement purchases will come at market prices.
What utilities and policymakers need to see is whether upcoming METI inventory data sustains the year-on-year LNG surplus or begins to erode as spot procurement tightens into summer. Those holding long-term supply agreements with Australian and Malaysian counterparties are relatively insulated from JKM at current levels. Those more exposed to spot or short-term contracts face a procurement cost increase that will feed into Q3 earnings reports. The pace of nuclear restarts is the other variable: each gigawatt of capacity returned to service reduces gas burn and the volume needing to be sourced in an already-tight spot market.2