For the NW Europe hubs, the TTF looks more bearish than it did at the start of May. The y/y storage gap dropped in the first two weeks by almost 2 bcm to 23.8 bcm, but it ended the month at that level. With the first week of June increasing the y/y storage surplus, there is real concern that we will hit storage tank tops well before the start of the withdrawal season.
The main causes of the higher injections forecast came on the supply side, as pipes showed no signs of being turned down in response to the high level of incremental LNG (sendout was up by 4.9 bcm y/y) and the resulting lower price environment. In particular, Russian gas flows came in around 0.94 bcm higher y/y. With selling on the ESP at a record-high 1.05 bcm, this points to a very modest drop in nominations over the month and a very aggressive pattern of sales to protect Gazprom’s market share. Gazprom’s aggressive approach in defending market share and signalling to LNG that it can make the EU gas market unattractive means there is likely to be more downside to prices to come.
Over the peak Q3 19 summer quarter, LNG imports are expected to be up by 5.6 bcm y/y, and storage injections will need to come off by 10-11 bcm y/y. As such, the Q3 19 balances are looking looser by around 16-17 bcm y/y. As pipes need to turn down, and we expect that supply will come off in aggregate by some 10 bcm y/y, demand needs to be up around 6 bcm y/y—and a little more if Gazprom keeps selling even after it hurts.
The maximum fuel switch that could be reached in western Europe would provide around an 8.4 bcm y/y increase in gas demand if all of last year’s hard coal-fired generation is replaced with gas-fired generation. While all of that is difficult to get given peak demand issues and transmission constraints, you would need to get to the fuel-switch trigger at the prompt to achieve even 7 bcm.
As the EU power sector must now provide even higher levels of additional demand for the market to balance, Europe’s hub gas prices will have to move lower. With headwinds to getting gas into the power sector, we now think this means TTF prices will need to hit the parity fuel-switch trigger as the mean for the remainder of summer. Given cif ARA coal at 53 $/t and carbon at 25 €/t, this would require a mean price for the TTF of 10.1 €/MWh over the remainder of the summer.
For winter 2019–20, in a normal weather and normal transit through Ukraine scenario, the market will likely trade between the 10% (14.4 €/MWh) and 15% fuel-switch triggers (16.7 €/MWh). The move back into those levels would keep the market at lower fuel-switch triggers than Q4 18 due to very loose supply-led balances and the fact that storage should be starting the withdrawal season with 12 bcm higher inventories y/y.
However, as we highlighted in last month’s Outlook, Q1 20 carries high risk—in the event of no NS2 and no transit through Ukraine over winter (a no-no winter), fuel-switch triggers will have no real bearing on the market, and we would expect to see gas prices north of 25 €/MWh. Given that risk, the EU hubs have curves with very wide levels of contango. Given the Russia transit risk shows no sign of ebbing, those future risk premiums are unlikely to come out of the market quickly.