Supply strength continues to be the key feature of the LNG markets. Strong flows from several established exporters have been joined by supply from new trains. Our balances put y/y export growth at 3.4 Mt in March and 5.0 Mt y/y in April, with growth coming from Algeria and Egypt and new trains in Australia, Russia and the US. The robust supply performance, including in April, which marked the start of summer maintenance, does suggest supply in Q2 19-Q3 19 coming in a remarkable 19.7 Mt higher y/y.
Demand is somewhat getting overlooked but China, as expected, is having another stellar year. The strength of Chinese demand growth does feel like it is being underplayed, possibly because y/y growth is not as strong as it was last year. However, Q1 19 growth in LNG imports still has come in some 2.6 Mt higher y/y, largely in line with our summer 2019 forecast of 6.2 Mt y/y, which is about two new supply trains of growth. For the rest of NE Asia, it would take a much hotter-than-normal summer to provide much upside to demand, particularly given the fact that summer 2018 was hotter than normal and both Japan and South Korea added more solar power capacity in 2018—6.5 GW and 2.0 GW respectively.
We also expect summer 2019 to deliver higher demand growth from South Asia, with the region now starting to see the benefits of lower LNG spot prices as well as some new import capacity, with new regas terminals in both India and Bangladesh starting to come online. Still, the combined growth in South Asian demand over the summer is only expected to be 4.7 Mt y/y, less than growth from China.
With LNG demand in the rest of the world at best moderate, this leaves a chunky 12 Mt of incremental supply to find its way to the European market. As we mentioned last month, the biggest issue in the EU market is the 25 bcm y/y storage surplus registered on 1 April, which must be whittled down to no more than a 12 bcm y/y surplus come end-October as that pushes storage to capacity. That y/y storage surplus was largely unchanged by the end of April. Starting the process of eroding that storage overhang will require the whole TTF curve to drop low enough in price to get more gas into the power sector.
At current relative prices (EU carbon at 26 €/t and coal at 60 $/t), most of the EU coal-to-gas fuel switch will come at 13.5 €/MWh (4.3 $/mmbtu) and will be fully exhausted at 11.4 €/MWh (3.8 $/mmbtu). While TTF prices need to soften to that 4.3 $/mmbtu level for the EU market to balance in summer 19, we still think the Q3 19 global market will involve enough buying that the JKM-TTF spread will stay above 60 cents/mmbtu. This means an average summer 2019 JKM price of around 5.0 $/mmbtu. We think the winter 2019-20 curve is overpriced and forecast that the TTF will need to price around 18.8 €/MWh, with the JKM-TTF spread seasonally widening to around 1.6 $/mmbtu level – on an expected seasonal tightening of the freight market.
For summer 2019, a drop in the TTF all the way down to 3.8 $/mmbtu would still not close the arb window between the US Gulf Coast and NW Europe. Our end-October storage outlook for the US market of over 3.6 tcf is looking relaxed, as infrastructure constraints affecting US pipeline exports to Mexico, and plentiful gas supply has helped soften the US benchmark. For our summer strip, we expect US Henry Hub prices to average 2.6 $/mmbtu, even assuming it exports all of the LNG it can.