The narrative around European gas markets has seen the bearish summer story replaced with something closer to bemusement as an unexpected repricing upwards has left the market less certain of direction. While the price moves up at EU hubs had some triggers—a surge in EUA prices, some colder April weather, a seasonal easing of pipeline flows, some short covering—the size of the moves seem to have been overdone.
The colder start to April, which is forecast to persist until 16 April, is not likely to add much more than 1.8 bcm to summer demand forecasts. The demand increment has to be viewed in the context of early April storage levels pushing the y/y surplus above 25 bcm. With expectations that LNG increments could be as high as 14 bcm y/y over summer, the market is now estimated to be looser than last year by 39 bcm. As such, offsetting 2 bcm of that total on early spring cold does not shift the market balances from staying very loose.
Revisions to global balances have revised European LNG takes up to 14 bcm from 10 bcm more LNG y/y this summer, although the bias to Q2 19 in supply (+10 bcm y/y) is still there and stronger than Q3 19 (+4 bcm y/y). The new forecast is less conservative than the previous one, and upside and downside to those numbers are better balanced given how strong recent LNG takes have been.
We still see storage ending 11 bcm higher y/y (basically tank tops), taking the supply looseness from 39 to 28 bcm. We also still see all sources of pipeline gas coming off y/y, with EU and Norwegian supply dropping by 7 bcm, Algeria dropping by 7 bcm and Russia dropping by 5 bcm. That leaves some 10 bcm of additional supply that has to be met by additional EU demand. If it is not, then higher supply reductions would need to be seen.
While weather is helping add close to 2 bcm to summer demand, that still leaves a sizeable 8 bcm of fuel switch to come from the coal-to-gas fuel switch. The maximum level of fuel switch would add a maximum of 13 bcm power sector demand, but the needs to meet peak power demand and manage local transmission constraints mean an 8 bcm y/y switch is close as can be to getting all of the fuel switch possible.
Getting all of that gas into power has some headwinds. Both French and Belgian nuclear look like they will have higher availability this summer y/y. In addition, wind generation has been high this last winter, driven by a combination of new capacity (11 GW) added in 2018 and very high wind speeds. While summer generally sees lower wind speeds than winter, that additional capacity will still make y/y increases in generation likely. With capacity additions also seen in solar (up by 8.0 GW), renewable generation will continue to eat away at the need for thermal generation. Hydro could be a bit more constructive, although that is far less clear; while Norwegian hydro balances are better than last year, Alpine hydro balances look far less healthy.
The key is that EU balances still need to get more gas into power and that still suggests prices should tend towards the 5% fuel switch trigger. The fuel switch trigger is now higher than it was at the start of April given the surge in carbon, but with Cif ARA coal at 65 $/t and carbon around 25 €/t, that suggests a summer TTF mean of 14.1 €/MWh. Recent price movements away from that level may make it more likely that the market has to retreat to those levels for balance once heating demand finally finishes.