Blame the weather

Published at 18:03 31 Jan 2018 by . Last edited 15:12 5 Nov 2018.


  • Q1 18 Lower 48 output growth will fall beneath initial expectations due to winter well-head disruptions which are now approaching 60 bcf. For full-year 2018, we expect robust production growth of nearly 7 bcf/d y/y. Our Appalachia outlook calls for a 6 bcf/d y/y gain. We anticipate that of the 8 bcf/d or so of infrastructure scheduled to come online in the Northeast before the 2018-19 heating season, not all will be on time, and flows on the portion of pipe that does come online this year will be made up of a combination of new production and re-shuffled supply, much as we have already seen with Rover Phase 1 and Leach.
  • For the Permian, our reference case includes 1.5 bcf/d y/y growth. Infrastructure in the basin could begin to look tight vs production in late 2018 if downstream Mexican issues are not resolved. A much higher capacity utilisation of the already-online Trans-Pecos and Comanche Trail pipeline would effectively allow for adequate capacity from the play. Importantly, even a moderate capacity utilisation increase would help. The market continues to wait for El Encino-La Laguna and La Laguna-Aguascalientes to come online so that Permian pipeline flows into Mexico can increase.


  • Q1 18 res-com demand has already been lifted more than 1 bcf/d on the early January cold vs our initial estimate based on the 10-year normal. With commercial forecasts calling for another cold event in February, an even more elevated level is possible.
  • For the injection season, the three pillars of structural demand growth (exports to Mexico, feedgas for LNG exports and gas-intensive manufacturing) will be the largest source of demand growth, nearing 2.6 bcf/d y/y. However as a result of the downside risk from what seems to be an ever longer list of delays to infrastructure south of the border, we have downwardly revised our forecast for y/y growth in Mexican pipeline trade to 0.5 bcf/d, and also increased our forecast for LNG imports to a 0.1 bcf/d y/y increase. For LNG feedgas, we expect 1.6 bcf/d of y/y growth, while we see industrial demand growing by 0.5 bcf/d y/y based on a string of projects that have come online since H2 17. 

Tying it together: Storage and price outlook

  • Our reference cased, based on a 5% colder than normal February and 10-year normal weather in March, is for a 1.26 tcf end-March carryout. However, with forecasts pointing to cold still extending into March, there is still a risk storage could end the season even lower than that. Given how low inventories have already fallen, if the carryout turns out to be less than the already low 1.26 tcf that would have a measurable impact on price for the injection season.
  • In a 10% colder-than-normal scenario for March (together with our reference case assumption of 5% colder-than-normal weather in February), end-of-season inventories would dip to 1.15 tcf. While that figure is still higher than the Polar Vortex carryout of 837 bcf, such a level might nonetheless involve demand destruction in the electric power sector. Injection season pricing in such a scenario could reach as high as 3.15-3.2 $/mmbtu level.

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