Pacific Money | Economy | East Asia

Japan’s Electricity Shock Is a Contract Problem

It’s not a matter of counting suppliers.

The International Energy Agency expects Japanese wholesale electricity prices to rise by nearly 40 percent year on year in the second half of 2026, reaching roughly $105 per megawatt-hour. The equivalent increase across the European Union is around 25 percent. Two advanced economies buying from the same global gas market are absorbing the same disruption at very different rates, and the reason has less to do with how much gas Japan imports, than with how the price of that gas is written into contracts.

Each market’s exposure is structural. Natural gas accounted for 32 percent of Japan’s power generation in fiscal year 2024, and almost all of it was imported by ship. When the delivered cost of a cargo moves, it feeds directly into the marginal cost of generation, and there is little in between that can help absorb the increase. The nature of European systems means that these have somewhat more options for substitution available. Europe’s geographic position also means that it has greater interconnectivity with neighboring markets. Japan’s geographic position means that very differently, its grid converts an LNG price shock into an electricity price shock at a significantly faster rate. This of late, has been climbing.

The Japan Korea Marker, the spot benchmark for Northeast Asian LNG deliveries, reached about $24 per million British thermal units (MMBtu) in August, up 13 percent over the month. More telling is the forward curve. Cargoes for October through December are trading above $22 per MMBtu, against an average of just under $17 for 2026 so far. Traders are not pricing a spike that fades before the heating season; rather they are pricing a winter that begins short.

The squeeze began upstream of Asia. Disruptions to Qatari exports and shipping through the Strait of Hormuz, a result of the ongoing U.S.-Iran war, have pulled flexible volumes out of a market that was already operating with a thin cushion. LNG is fungible in theory; in practice, it is not. A cargo redirected to a European regasification terminal is a cargo that does not reach its destination in Asia. Such unanticipated redirections come at an increased price. Japanese buyers are now bidding against European utilities rebuilding storage, as well as Chinese, Korean and South Asian buyers who are looking to ensure they are covered for their own winters.

The contest runs through a narrow layer of an already challenging market: portfolio sellers such as Shell and TotalEnergies, alongside independent trading houses including Vitol, Gunvor and BGN Group, hold some of the volumes that have not already been committed to a fixed destination. Their decisions about where a cargo ultimately goes are one of the mechanisms by which a disruption in the Middle East can potentially create a higher generation cost in Japan.

Dubai-based BGN Group is an instructive example of how this part of the market is changing. Having built its business around physical commodity trading and logistics, the company is now expanding its LNG portfolio across the Atlantic and Pacific basins, including through long-term supply arrangements and greater access to flexible FOB volumes. Its recent agreement for long-term LNG supply from Texas LNG is one example of that strategy at work, with BGN Group and Glenfarne Global Commodities agreeing on a framework for 1 million tons per annum and a proposed 20-year sale and purchase agreement. Such a model is important because the value of a portfolio seller is not simply the number of cargoes it controls. Rather, it is the ability to decide where those cargoes have the greatest commercial value as markets move. A Japanese utility competing for those volumes in the dead of winter in December negotiates from the weakest position possible, because the alternative to paying is not being capable of generating power at a time when their........

© The Diplomat