The war in Ukraine has fundamentally altered the outlook for LNG, compelling European capitals to try to shift away from Russian pipeline gas and towards the liquefied form of the fuel, with the US seemingly best-placed as supplier.
Russia provided 155bn m³ of gas to Europe last year, accounting for roughly one-third of the continent’s gas demand—consisting of 142bn m³ of pipeline gas and 14bn m³ of LNG. Replacing this volume of gas with LNG from other sources could lift Europe’s LNG demand by c.114mn t/yr, equivalent to 30pc of the global LNG market last year, as estimated by Shell.
The European Commission’s RepowerEU plan, released in early March, seeks to replace or displace c.100bn m³/yr of gas demand this year, equivalent to 73.5mn t/yr of LNG and nearly two-thirds of the 155bn m³ imported from Russia. This would be achieved mostly by diversifying gas supplies via additional LNG imports and pipeline supplies from non-Russian providers such as Norway and Azerbaijan, with the remainder being accounted for through demand-side measures such as energy efficiency, heat pumps and renewables.
Displacing such an enormous volume of Russian gas while simultaneously ensuring EU member states fill up underground gas storage to at least 80pc of capacity by the end of October will depend heavily on Europe’s ability to source additional LNG this year. This means benchmark European gas prices at the Dutch TTF will need to outbid the Asian JKM for supply.
European demand in full force
It is unclear if Brussels’ envisaged scale of supply increase is realistic. But, so far, Europe has been able to attract a greater share of LNG cargoes, taking volumes away from Asia. European inflows are expected to top 11mn t in April, which would be the strongest month since January, while Asia’s imports are forecast to be at their the lowest since June 2020 at 20.55mn t, according to commodity tracker Kpler.
The question is how long this will continue. Consultancy Rystad Energy believes European price signals on the TTF are likely to far exceed Asian spot prices this year. But even a relatively small substitution of any Russian gas shortfall in Europe with spot LNG has the potential to squeeze spot supplies in Asia, in turn leading to another cycle of heightened competition for remaining cargoes and the risk of further price spikes.
This would exacerbate Asia’s already high spot prices, which have remained elevated due to fundamental and geopolitical factors. Regional spot prices averaged $30.40/mn Btu in the first three months of this year, compared with $8.90/mn Btu in the same period of 2021 and just $3.70/mn Btu in 2020. Higher prices should result in demand destruction in Asia to balance the global market.
But the sense among LNG analysts in China surveyed by Petroleum Economist is that Asia will outbid Europe for marginal cargoes over the remainder of 2022, sourcing the bulk of volumes from the US. This implies the Northeast Asian spot market will maintain a premium to the TTF that covers the additional cost of shipping to the region.
It is unclear if this is, or will be, reflected by the JKM forward curve paper market, given the extreme price volatility in Europe and thin liquidity in JKM trading, particularly as Asian buyers are pivoting as much as possible to long-term contract takes.
Asian advantage
But Asian buyers have some ability to outbid Europe for cargoes, as their spot price exposure is very low as a share of aggregate demand. Asian buyers have been actively signing long-term contracts over the last year: China contracted a record 22.7mn t/yr of term LNG in 2021 and has already signed up more than 16mn t/yr to date this year.
Japan, South Korea and Taiwan have also increased their long-term contract coverage, outpacing growth in their LNG import demand. The expectation is that this gives the Northeast Asian market a 90pc contract coverage, making trade flows to Asia sticky and hard to redirect to Europe.
Asian buyers may still have to source spot cargoes and draw them away from Europe. But these will be a relatively small expenditure on their balance sheets compared with European buyers.
Long-term contracts on a typical oil-indexed basis to Japan and South Korea are projected to average c.$9.60/mn Btu for the rest of this year compared with a JKM price of $22.59/mn Btu in late April. Spot purchases can therefore be averaged out with this much cheaper term supply—as was demonstrated in South Korea last year, when independent power producers shunned the spot LNG market in favour of increased purchases from state-owned importer Kogas, where the seller was able to source the volumes from its contract portfolio.
Similar dynamics could play out with some of China’s second-tier importers that are more exposed to the spot market. They may look to buy LNG from state-owned importers Cnooc, Petrochina and Sinopec, which has access to a mixture of long-term contract and spot price exposure.
US to the rescue
The global LNG market has pulled almost every short-term lever for increasing supply and decreasing demand, and there is consequently little flexibility for Europe easily to raise LNG shipments further. LNG export projects in the US and Australia have been operating at nameplate capacity for weeks, leaving little scope for a further increase in output.
Similarly, price-sensitive drivers of Asian demand have already largely been priced out of the market. These include India’s power and industrial sectors cutting LNG consumption, the substitution of gas with high-sulphur fuel oil in Pakistan and Bangladesh, and Japan burning more oil for power.
The US is the most obvious supplier of incremental LNG, as it can add liquefaction trains quicker than any other country, is physically closer to European gas markets than Asia and the Middle East and is aligned politically with the bloc. Qatar has the upstream resources to expand, but there are only limited opportunities to debottleneck existing trains ahead of the arrival later in the decade of the six trains Qatargas already has under construction. Expansion in Australasia is possible but may have even longer development timescales.
If the US moves to fill in the gap in European demand created by the withdrawal of Russian gas, then it would put the US industry on course to overtake Australia by 2025, according to analysis firm Bernstein Research. By the end of this decade the US could have 200mn t/yr of LNG export capacity compared with c.100mn t/yr at present.
The anticipated growth in global LNG demand, due in part to Europe boosting imports, means as much as 120mn t/yr of new LNG capacity will need to be sanctioned by the middle of this decade. Most of the most commercially viable capacity lies on the US Gulf Coast, with Cheniere’s Corpus Christi Stage 3 and Venture Global LNG’s Plaquemines LNG developments among the projects tipped to move forward quickly.
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