- Production growth will be key to determining how loose balances are this injection season. Early guidance from producers is indicating decreased Capex. While EQT and Gulfport have indicated minimal sequential gains and reduced Capex, compared to combined growth near 0.8 bcf/d y/y last year, SWN and Cabot are in the driver’s seat and calling for 1.0 bcf/d y/y gains based on guidance.
- Producers remain well hedged. The private producers’ permitting and rig activity we track indicated an ability to ramp up supply this injection season. Even if we assume that the level of production in December 2018 holds through every month of the injection season (i.e. no more sequential growth after freeze-off and operational issue recovery), we would still anticipate 5.3 bcf/d y/y of growth in domestic production. Consequently, anything other than largescale growth is unlikely. Given what we know just of the Appalachian producers’ guidance (without even accounting for private producers and gains from associated production), sequential growth is expected, though should not have the same momentum as in summer 2018, when Lower 48 m/m gains were near 1 bcf/d.
- Outside of weather risks, which could produce a massive swing, infrastructure timing is another major concern. The delays to LNG trains starting up at Cameron, which we had expected, have been confirmed. Demand growth from Mexico will be limited following confirmation of yet another delay to the Sur de Texas-Tuxpan gas pipeline. The delay, from Q1 19 to Q2 19, is likely due to the permitting issues reported by SENER on 20 February, though that pipe is mechanically complete on both sides of the US–Mexican border. However, even with these delays, structural US gas demand could potentially grow by over 3.0 bcf/d y/y over the injection season, largely accounted for by demand for LNG feedgas.
- Given our view on the potential for weakness in polyethylene prices in H2 19, an easing of industrial sector demand is a major risk to our total demand numbers. However, the downside risk could amount to around 0.2–0.3 bcf/d, so the impact is tangible but not major.
Storage and price outlook
- Sentiment is centred on a fairly bearish view of the injection season. However, our view of an end-October carryout near 3.37 tcf is far more constructive for price. Our balances are at a critical balancing point, as they were this time last year. If demand is too strong, inventories will appear too low, while low demand will make balances appear too loose. On the supply side, the potential risks this injection season include an extension of growth momentum post freeze-off recovery and from other recent pipeline operational issues. However, a critical mass of producers could prove truly disciplined and growth could come in weaker than our 7.2 bcf/d assumption. Weather risk is an issue as a repeat of summer 2018’s heat would add 2.0 bcf/d to demand, taking the end-October carryout to 3.15 tcf.
- Our models suggest that a price of around $2.50/mmbtu would induce an additional 1.0 bcf/d of gas into power demand above our reference case. All else being equal, a sustained price that low over the injection season would translate to a 3.15 tcf end-October carryout—a storage level that we think is too low to merit such price-induced power sector demand. We assume $2.87/mmbtu pricing in the injection season based on 10-year normal weather.