Less than 3.5 tcf

Published at 16:34 27 Apr 2018 by . Last edited 17:58 27 Apr 2018.

Supply

  • The timing of both Atlantic Sunrise and Rover Phase 2 will be pivotal in determining how much more of a step-up in production we can see this summer beyond the 27 bcf/d flows from Appalachia as of late. There is still room to grow production above the current run rate, but our forecast requires at least one of these large-scale projects to enter service this cooling season.
  • Our forecast of a 1.70 $/mmbtu discount at Waha is informed by how full vs capacity flows are already on the north, west and east routes out of the Permian, together with the downstream delays in the Mexican market that prevent marked growth from volumes currently flowing south. Flaring volumes and some potential shut-ins can absorb some excess capacity above and beyond current takeaway.

Demand

  • As the shoulder season is underway, albeit late and abbreviated, and peak cooling season is a matter of weeks away, the levers of demand will be limited to structural demand growth from LNG feedgas, pipeline exports to Mexico and the industrial sector, as well as from power.
  • We expect growth in power sector gas demand reach just above 2.0. bcf/d y/y from May-October. The combination of a return to normal weather, vs the cooler 2017 summer, lower delivered gas prices in most of the key consuming regions, coal-fired plant retirements in the past year, and the buildout of new CCGT plants will serve to boost demand by some 2.0 bcf/d y/y.

Tying it together: Storage and price outlook

  • The US gas market’s view seems to be coalescing around a low end-October carryout. Yet, we have not seen any discernible increase in forward prices to suggest the market is pricing in any level of concern about storage adequacy—indeed, prices suggest a high degree of comfort. It would take more than a moderate re-pricing to substantially change our assumptions on the dispatch queue, and the consequent ramifications for end-of-season storage. Gas output has been growing sequentially as April ends, according to flow data. Producer guidance has suggested that Appalachia growth will be skewed toward Q3 18, in line with pipeline in-service dates, so we would expect production to step up as the injection season progresses. It is too early in the season to judge how long supply the market is, especially given how flat US output was over February-May 2017. As production started to ratchet up in June 2017, the true test of supply growth will come later in the season and in lock-step with stated in-service dates for Appalachian infrastructure and our outlook for both tight oil and gas takeaway in the Permian.
  • For a marked upward repricing above our 2.70-2.75 $/mmbtu May-October forecast, the supply side would need to see more concrete affirmation of delays to Appalachia infrastructure, even more severe evacuation issues from the Permian than currently anticipated, or other evidence that production estimates were to fall short of our 7.9 bcf/d y/y forecast. On the demand side, upside could come if much hotter-than-normal weather were to materialise and take gains in the power sector above our baseline growth estimate of 2.1 bcf/d y/y. As such, the next significant directional move in price (if any) hinges on the extent of the departure from normal in peak cooling season vs the uptick in supply deliverability.

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