Sticky production growth pegged at 7.1 bcf/d (0.2 bcm/d) this injection season (April-October) will help keep US balances loose. The demand side is set to be coloured by timing risks, particularly around pipeline export growth into Mexico and feedgas for LNG. Delays to the start-up of Cameron LNG T1 and Elba Island have long been factored in into our balances, as has summer-period maintenance on existing facilities. Still, we anticipate LNG feedgas to be the main demand driver in US balances this injection season, growing by 2.6 bcf/d (74 mcm/d) y/y to 5.9 bcf/d (0.17 bcm/d). While global LNG demand is weak, we anticipate the global arbs will nevertheless remain open for those growing US volumes. While the US demand-side will also receive a modest boost from the industrial sector and pipeline exports to Mexico, the supply growth will support an end-October carryout topping 3.4 tcf (96 bcm), neither on the historically high or low side. Given this, we expect that Henry Hub will average near 2.90 $/mmbtu over summer 2019.
A change in weather forecasts to a much milder-than-normal end to March has shifted our end-of-winter-season inventory estimate to 1.06 tcf (30 bcm) versus a low projection of 950 bcf (26.9 bcm) on 7 March. From here on, the storage withdrawal rate falls off of a proverbial cliff and our first forecast injection is for the week ending 5 April, a significant departure from last year, when withdrawal activity extended through the third week of April. Still, the injection season strip has remained supported despite that upward adjustment to inventory estimates. Potential risks on the supply side, include extensions of unplanned outages at pipelines and a slow recovery from supply-side freeze-offs. Some 65 bcf (1.8 bcm) in Appalachia alone was lost due to freeze-offs. A repeat of summer 2018’s heat would add 2.0 bcf/d (57 mcm/d) to demand and would take the end-October carryout to 3.15 tcf (89 bcm).
Outside of swings in weather, which will impact load in the power sector, production growth momentum is key to fundamentals this summer. While the bulk of US producers have reported decreased Capex y/y, most are still guiding toward y/y output gains this year. Even if we assume every production reading for the injection season comes in flat to the December 2018 estimated reading, output would still grow by 5.3 bcf/d (0.15 bcm/d) y/y.
Guidance from the top Appalachian producers—even assuming flat output from heavyweights EQT and Gulfport—points to 1.2 bcf/d (34 mcm/d) of growth y/y without accounting for volumes from private producers or associated production in other regions. In effect, even the lowest of reasonable estimations of growth this injection season will still yield sizeable gains. There are also a number of factors that suggest US production will still grow, including the fact that US producers are quite highly hedged for 2019 and the netback currently available for the production of liquids is still highly positive. Our reference case assumes moderating sequential gains in output, with y/y growth dropping just below 5 bcf/d (0.14 bcm/d) in October. However, that October figure is propped up by a spike in m/m growth as we assume Gulf Coast Xpress enters service on time that month.
It’s all about timing
Timing risks are our key demand-side concern this summer and we remain cautious on Mexican exports and industrial demand. There has already been confirmation of delays at Cameron LNG T1 and Mexico’s Sur de Texas-Tuxpan gas pipeline, with the latter now expected to come online in mid-to-late Q2 19 at the earliest. Beyond this, Cheniere’s trains appear poised for timely starts, and Freeport LNG T1 has stated that it could begin to take feedgas in April or May, but those initial volumes are likely to be minimal and will not materially sway balances as first LNG exports are not expected until July at the earliest. Timing regarding Mexico is more of a risk. Protests along Fermaca’s pipeline routes in Durango state forewarn of potential delays to the Wahalajara pipeline system starting up on time for its stated May in-service date. Our 0.7 bcf/d (20 mcm/d) y/y outlook for growth in exports to Mexico still assumes Sur de Texas-Tuxpan enters service in Q2 19 in order to meet peak summer cooling load.
Given our view on the potential for weakness in polyethylene prices in H2 19, an easing of industrial sector demand is a risk to our total demand numbers. However, the downside risk is minimal on our total growth of 0.2 bcf/d (5.7mcm/d), so the impact is tangible but not major. Structural demand could potentially grow by over 3.0 bcf/d (85 mcm/d) y/y in the injection season, largely accounted for by demand for LNG feedgas (+2.6 bcf/d or 74 mcm/d y/y).
|US liquefaction projects|
|Source: DOE, Company websites, Energy Aspects|