As Europe slowly leaves the heating season behind, the European gas market is looking tight, with a y/y storage deficit of almost 10 bcm, 80% of which is accounted for by NW Europe’s storage facilities. The imperative this summer is to inject gas into storage.
This need has been made even stronger by the Dutch government announcing its intended path for the closure of the large Groningen gas field. While the government still needs to finalise the exact annual production caps, the intention is to see annual y/y reductions of 2–4 bcm/y from the field for the next four gas years, dropping the field’s production from this year’s 21.6 bcm to around a 12 bcm/y by gas year 2021-22. This is then followed by a 7 bcm/y drop in 2022-23, which would leave the field’s output at just under 5 bcm/y. From there, it slowly reduces to zero by 2030.
The proposed cuts take out a huge amount of gas production from the heart of the European market, and it will be felt most acutely in the winter peaks. This will result in higher EU gas prices (if all other factors remain equal), higher levels of imported gas (encouraging drilling in both Russia and the US) being supported, and TTF spreads to other hubs being kept narrower and more likely to be at a premium.
The Dutch government has focused most on the low-calorific (L-gas) balances. It has proposed adding nitrogen capacity to convert 7 bcm/y of high-calorific gas (H-gas) to L-gas by 2022, starting a program to switch all industrial users to H-gas by 2022, making all new builds in Netherlands gas free, and working with neighbouring countries to eventually stop Dutch L-gas exports entirely.
The more immediate implication is that the cap for gas year 2018-19 is likely to require Groningen production to fall by around 2.2 bcm/y (the indicative number provided for a normal weather year). While in theory there is a production allowance of an additional (vs indicative) 6 bcm during cold years, only on the rarest occasions would all that flexibility be utilised. Groningen production will have fallen y/y in winter 2017-18, despite HDDs being 3% above normal over the full six months. Given this, and how low storage in NW Europe ended the 2017-18 gas winter (just 5 bcm of gas was still in storage), injecting gas into inventories is even more important.
For the coming summer, the imperative to inject puts a whole new emphasis on LNG imports. Our balances forecast that Europe will receive 3.3 bcm more LNG y/y in Q2 18 and 7.1 bcm more y/y in Q3 18. Experience has taught us that there is much more potential downside than upside to those numbers, as LNG imports are at the mercy of timely project completion, supply outages and Asian demand growth. If LNG imports do fall short of our projection—particularly given our forecast of a 4 bcm increase in Russian gas imports to compensate for drops in Dutch and UK production—then the market will have to balance by further reducing the gas available for the power sector.
Our EU gas price forecasts for 2018 have been revised modestly upwards because the rise in the EUA price has increased the fuel switch triggers. We are still pricing Q2 18 and Q3 18 on the same forecast trigger levels, which means we now forecast that the TTF will come in at 18.1 €/MWh in Q2 18, up from our previous forecast of 17.5 €/MWh. For Q3 18, we still expect prices to slide q/q on a healthy LNG import outlook, but our forecast has been revised up by around 60 cents to 16.7 €/MWh. If the LNG does not appear, upside is likely to all of these prices.