3.7 tcf beckons

Published at 19:09 29 May 2019 by

Supply

  • Weekly production readings have been unable to eclipse the record highs set in December 2018 until the current week which will narrowly best the record by 0.1 bcf/d. A laundry list of maintenance events have led to a less than 0.2 bcf/d m/m gain in production in May. Outside of October, when Gulf Coast XPress is scheduled to come online, our average injection season sequential production gain is forecast at 0.3 bcf/d m/m, which is not particularly strong.

Demand

  • Timing risks to structural demand regarding the start-up of new infrastructure have begun to dissipate for the injection season, except for Mexican pipeline timing. The Shintech, Westlake/Lotte and Indorama ethane crackers are all either running or in the process of starting up. Cameron LNG T1 and Freeport LNG T1 have been taking feedgas (in the case of Freeport, still intermittently). While both TransCanada and IEnova confirmed the end-June start-up for Sur de Texas-Tuxpan in their Q1 19 earnings calls, CFE’s mid-May tender for seven additional cargoes into Altamira from May to end-July suggests backfill is needed for cooling season demand and that the pipeline is subject to very real timing risk.
  • Though the two new LNG trains in the US no longer seem to have significant timing risk from an operational perspective, the weakness in both the TTF and JKM are pressuring arbs with Henry Hub. The European storage surplus y/y stands at more than 800 bcf currently and must pare down to 420 bcf by end-October to be within physical capacity constraints, risking further weakness in the TTF. With tanker day rates expected to be on the rise as well, there is a risk that the Henry Hub-TTF arb could close in Q3 19 and leave unhedged cargoes in the US. The threat of them being left in the US (as natural gas) as the forward arbitrage windows close could be enough to shift US prices down to pry that arbitrage window open again. While a race to the bottom could ensue, those lower Henry Hub prices would drive more demand either by keeping the export arbitrage window open or by pushing more gas into the US power sector. 
  • Gas burn intensity on a $/mmbtu basis has appeared anaemic y/y in Q2 19, but there has been no real cooling load as of yet. We have been expecting a slightly lower gas burn intensity given new efficient combined-cycle generation capacity commissioned over the past year will take market share from older, less-efficient gas plants. While that trend will slow this year—less than 5GW of new plants are due online in 2019 compared to 17GW in 2018—the impact from units which began operating in 2018 will be felt throughout most of this year.

Storage and price outlook

  • Our storage carryout of 3.71 tcf is 30 bcf higher compared to last month’s Outlook. Given the fairly low level of sequential production growth we expect until Gulf Coast XPress enters service, the only other factor that could provide price upside would be hotter-than-normal weather. Our models suggest even an overtly bullish weather assumption—10% warmer than normal—would induce an additional 170 bcf of gas demand from June-September, shaving expected end-October storage to just below 3.55 tcf, a figure that would allow for a price move up toward $2.80/mmbtu, but not much more.
  • In 5% and 10% milder-than-10-year scenarios for June to October, storage would top 3.8 tcf and 3.95 tcf respectively, justifying a drop in gas prices to drive more gas-fired generation. The approach of the psychologically bloated 4.0 tcf level would likely push prices toward $2.00/mmbtu at Henry Hub to redirect some of those injections into the power sector.
  • A storage carryout of 3.71 tcf is already looking fairly comfortable and should rule out the winter-risk rally that punctuated trading ahead of the 2018–19 heating season. We expect Henry Hub prices will average $2.83/mmbtu in the coming heating season. That said, concurrent cold events in the Gulf and US Northeast, like those that occurred in January 2018, could still send cash prices far higher than projected by central tendency pricing.

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