Off to the races

Published at 21:50 29 Nov 2018 by . Last edited 11:18 22 Aug 2019.


  • Another month, another new record daily high in production. While one-off factors appear to have muted gains this month to 0.8 bcf/d m/m, we still anticipate a heavy baseline of production growth of 9.5 bcf/d, magnified by freeze-offs last winter. Given the 5 bcf/d y/y gains in Appalachia and Permian output combined, a proportionally similar amount of freeze-offs would risk a much larger absolute volume of potential losses this winter. Our balances make no allowance for disruption, but winters have typically averaged 50-70 bcf of freeze-offs on that lower baseline.
  • Permian congestion is worsening, and flaring activity appears to be picking up. November already saw 325 approved flaring permits, making it the fifth consecutive month with more than 300 such approvals. Before this summer, the Texas RRC had only approved more than 300 permits in a month once this decade (August 2015). We have deepened our discount for Waha to $2.10/mmbtu for the 2019 injection season, and if negative pricing persists, it will be lowered. Minor, but transitory upside exists during the heating season given the potential for freeze-offs, increased local demand and export demand to the Gulf/Southern California.
  • Q3 earnings calls occurred before the most recent run-up in prices and contained plans for conservative capital budgeting. Our survey of producers pointed to 2019 hedging near $3.10/mmbtu. Depending on the day, the 2019 strip has now ranged $3.15-3.25/mmbtu in the past several trading sessions. According to the Swap Data Repository (SDR) report, some producers have been taking advantage of the recent rally to put on last-minute Cal 19 hedges at higher levels. From the last two weeks, we observed Cal 19 hedges with prices ranging from $3.04 to $3.25/mmbtu, with several transactions over $3.20/mmbtu. While a nickel might not be enough to change plans, 15 cents could encourage more output. Our survey showed that 50% of volumes from publicly traded producers were hedged, but that does not include the private producers with growing shares in regions like the Haynesville. Our injection season 2019 outlook currently sees near 6 bcf/d y/y production growth.


  • Our forecast of higher Henry Hub prices through March 2019 than previously expected has nudged our gas burn forecast this winter lower by 0.7 bcf/d, with gains at 0.5 bcf/d y/y. Our gas burn forecast for summer 2019 has risen amidst continued coal retirements and stickiness in gas-fired generation. However, for the injection season this still amounts to some 0.5 bcf/d y/y growth, meaning that structural demand will be at the fore of the call on gas supply. LNG and Mexican net trade are still vulnerable to timing risk. For industrial projects, especially the handful of expected ethane crackers, tightness in frac and pipeline capacity should lead to competition for incremental ethane, resulting in volatile spot ethane markets and low initial cracker operational rates.

Tying it together—Storage and price outlook

  • Our currently projected end-December inventory position of less than 2.5 tcf is still too low to ease deliverability concerns. End-March inventories are tightly balanced at 1.3 tcf. That level is not full enough to ease deliverability concerns. Utilities and local distribution companies are likely holding their storage, purchasing in the physical market to ensure they can maintain deliverability, thereby keeping gas bid. As Q1 19 progresses, and deliverability concerns ease, they should be able to dip into storage coffers, which have a lower weighted-average cost of gas (WACOG) than physical purchases. Consequently, we are foreseeing a relative easing in cash price once these actors believe they can safely pull inventories without risking baseload withdrawals.
  • Injection season 2019 remains a weather play, and the ultimate trajectory of end-March inventories will drive refills this summer. This heating season is likely to prove that a 3.2 tcf carryout is insufficient to ensure physical deliverability capability for peak winter. Consequently, a 1.1 tcf carryout would keep prices supported near $2.90-3.00/mmbtu for the injection season. A significant mild event, which would put coffers toward 1.7 tcf at the end of the withdrawal season, would take projected end-October inventories toward 3.9 tcf. In our view this would merit a need for additional price-induced demand, bringing the injection season strip at least temporarily toward $2.50/mmbtu.

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