While the oil price mounts a slow recovery to around $55 per barrel, the liquefied natural gas market is on fire. After a mid-year slump, one Asian cargo just fetched the equivalent of around $200 per barrel of oil. Is this a temporary glitch, or signs of a sustained recovery for the gas market?
In April, the Japan-Korea marker (JKM), used to assess LNG sales to north-east Asia, dropped to a record low of $1.825 per million British thermal units (MMBtu), the equivalent of about $10.60 for a barrel of oil. Now it is more than 10 times higher. Other commodities have recovered from the coronavirus-induced slump, but nothing to this degree.
The turnaround is particularly surprising given that the LNG market has, for a couple of years, been thought to be in a long-term glut. A wodge of new export plants in Australia, Russia and the US came online between 2016 and 2019. Additional American and Russian facilities, the planned massive expansion by Qatar in the mid-2020s and new entrants such as Canada, Mozambique, Senegal and Mauritania, would mean ample supply this decade.
The effects of Covid-19 led to worries that European storage might fill up entirely over summer. As prices fell very low in April and May, US LNG producers cut shipments as their margins turned negative, helping to rebalance the market.
In the immediate term, the winter price surge is the result of a pile-up of circumstances and, as usual, demand and supply both play a role. Weather in north-east Asia and Europe, the two key centres of LNG demand, has been unusually chilly. The cold snap has seen the lowest temperatures in Beijing in half a century, a metre of snow in Japan’s Niigata prefecture, and a rare heavy snowfall in Madrid. On the other hand, US prices have fallen back since October as the weather there has been mild.
Japan’s demand is unusually strong because of remote working, leading to the need to heat both homes and offices. Windows are also left open to improve ventilation to limit the coronavirus spread.
Domestic energy shortages in central Asia have led Uzbekistan to cut gas supplies to China. Several LNG plants are out of commission: Algeria’s Arzew because of bad weather in December, Norway’s Snøhvit for a year due to a fire in September, Shell’s floating Prelude plant in Australia for most of last year owing to technical problems, and maintenance issues in Qatar. China’s informal ban on coal imports from Australia over a trade dispute has further encouraged reliance on gas.
Logistics are a further hitch. The scramble for cargoes has required longer voyages, boosting the rates to hire specialist LNG tankers. Shipments from the Atlantic to east Asia have backed up at the Panama Canal.
This episode illustrates three key points.
Firstly, China is becoming the key customer in LNG, as it already is in most commodities. Long-term demand from traditional customers Japan, South Korea and Taiwan is large, but stagnant. Gas is just 8 per cent of the Middle Kingdom’s energy consumption, compared to the world average of almost a quarter, but this still makes it the world’s third-largest market for the fuel. Most of its gas comes from domestic fields and pipelines from Central Asia and Russia.
Beijing wants to raise the share to 15 per cent, and most incremental supply will have to come from LNG imports. China will overtake Japan as the world’s biggest LNG buyer in the next year or two. Policy decisions to switch from coal to gas heating, and to pursue long-term decarbonisation, have become enormously influential, but unpredictable.
Secondly, the flexibility of the LNG business has improved greatly in recent years, but remains far from that of the oil trade. LNG transportation costs are much higher, seasonal and weather effects are key, and the primary consuming regions of North America, Europe and East and South Asia are imperfectly linked. Reliance on a relatively few large exporting facilities creates vulnerability to breakdowns or other disruptions.
The rise of the US as an exporter has added agility, as shown by the cuts to exports over summer, but not enough to prevent temporary shortages.
Thirdly, this reminds buyers of the value of long-term contracts. These, usually tying gas prices to those of oil, have been the mainstay of the historic LNG business. Gradually, the market has been moving to price LNG as a commodity in its own right, using markers such as JKM. But this winter episode shows such assessments can be volatile.
Oil-linked pricing has been increasingly disconnected from gas market fundamentals, but it has the appeal of dampening such spikes. A few spot cargoes at $20-30 per MMBtu make headlines but are not representative of most Asian utilities’ long-term purchases at $6-8 per MMBtu.
China is gradually liberalising its gas market. As with crude oil, as it becomes the pivotal global importer and consumer, it may well seek its own price benchmark at Shenzhen or Shanghai to rival JKM, Henry Hub in the US and TTF in Europe.
Bumper earnings for lucky sellers this winter are encouraging for LNG developers hard-pressed to raise finance. However, the mob of projects jostling to reach the market in the 2020s is enormous, and only the best will make it. The icy weather has warmed up the LNG market, but renewed investor interest will stop it boiling over.
Robin M. Mills is CEO of Qamar Energy, and author of The Myth of the Oil Crisis
