Goldilocks and the bears

Published at 14:57 30 Jan 2019 by . Last edited 11:18 22 Aug 2019.

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  • Some early producer guidance is indicating decreased Capex for 2019. Service companies are pointing to lower completion activity and frac spreads fell over the course of Q4 18. Market sentiment is less positive on the extent of production growth this year amid lower activity indicators and a m/m fall in US gas output in January.
  • However, we think that production growth could prove to be stickier than activity indicators suggest. From our Q3 18 survey of the largest US gas producers, 54% of output was indicated as hedged at an average of $3.10/mmbtu. In November, when the curve shifted higher, Swap Data Repository indicated some producers took the opportunity to put on more hedges, locking in prices near $3.25/mmbtu.
  • US oil production growth will come in at 1.2 mb/d in 2019, although growth is weighted to H2 19. For the Permian, we also peg gas production growth as being weighted to H2 19, given the expected October 2019 start-up of the 2.0 bcf/d Gulf Coast Xpress, which will add much needed takeaway capacity. For the Northeast, 2019 infrastructure additions are set to be much lower than the 6.3 bcf/d seen in 2018, especially given the risks around the Atlantic Coast Pipeline. In addition, 2019 guidance from EQT and Gulfport is calling for essentially flat production y/y. We expect a slowdown in y/y growth in Appalachia and await similar releases from other Northeast-focussed producers to see whether some firms have softened previous calls for y/y growth of near 20%. For the 2.7 bcf/d Mountaineer Xpress, which is partially in service, Antero, which is 100% hedged in 2019, SWN and others still have commitments on that pipe with demand charges near $0.40–0.60/mmbtu. We anticipate that new takeaway capacity will not be filled completely, but that it will drive some incremental growth.


  • We have trimmed our power burn forecast as the return of cold reduces the need to burn off excess inventory next summer compared to our outlook a month ago. For the injection season, we thus forecast power sector gas demand growth at a modest 0.2 bcf/d y/y.
  • Timing risk is still an issue for the injection season. The first trains at Elba Island and Cameron are at risk of missing their stated Q1 19 in-service dates. Our reference case accounts for this slippage, but we still forecast an incredibly strong 2.5 bcf/d y/y increase in the injection season.
  • Mexican pipeline infrastructure has been subject to prolonged delays. However, for Sur de Texas-Tuxpan and Valley Crossing progress may be advancing. Final trench surveys are still ongoing for Valley Crossing. However, EBB postings accepting nominations on the pipe through end-February indicate that initial flows could occur in the coming weeks. For the injection season we see US pipeline exports to Mexico growing by 0.6-0.7 bcf/d, with Mexican downstream constraints still a potential limiting factor.

Storage and price outlook

  • Warm weather in late December and early January led us to project an end-March carryout toward 1.55 tcf in early January, which shifted our view of the 2019 injection season to very bearish. However, a cold blast in late January has shaved that significantly, with balances now suggesting an end-March carryout near 1.20 tcf. Such a level appears to leave the upcoming injection season more evenly balanced, taking away some of the potential downside of a carry around 1.55 tcf. This all sets up February weather as crucial, as inventories could easily sway toward ‘too little’ under prolonged cold, or back toward ‘too much’ under mild weather.
  • As such, the 2019 injection season is still a weather play, but unless inventories move to a level deemed too low, the injection season is looking well supplied. Our reference case calls for Henry Hub pricing of $2.80/mmbtu for the injection season, assuming normal weather beyond the 15-day forecast period. If February realises 10% colder-than-normal weather and is followed by a normal March, our balances would result in an end-March carry of just above 1.0 tcf, and this would put pressure on summer prices to trend towards $3.00/mmbtu.

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