- The swift pace in sequential production gains in place throughout the injection season finally began to narrow this month, but October still appears on track for a healthy 0.6-0.7 bcf/d m/m gain. That gain, however, has been tempered by some temporary factors including shoulder season maintenance, shut-ins related to Hurricane Michael, and maintenance at the Enchilada Platform. Nevertheless, in recent days the US has reached a new record-high level of daily output. We maintain our outlook for over 8.5 bcf/d of supply growth during the heating season and over 5.0 bcf/d y/y in the injection season.
- Long-awaited Appalachian infrastructure entered service this month, but while flows ramp-up on Atlantic Sunrise, it appears to largely be supply moved from existing pipes. Given NEXUS is not fully subscribed, we do not expect a significant ramp of ‘new’ output once all its remaining facilities enter service, especially given its large percentage of demand-side customers. Some Antero Resources and Range Resources volumes should ramp this quarter on Rover. We still anticipate Appalachia will grow at a healthy 4.0 bcf/d this heating season, dipping toward 3 bcf/d in the injection season.
- For the heating season, our balances assume demand around the 10-year norm, which leads to an essentially flat y/y reading in the res-com sector. In the power sector, we anticipate 1.3 bcf/d y/y growth with another 2.6 bcf/d from structural demand growth (pipeline exports to Mexico, LNG feedgas and industrial sector gas use). Depending on how consistent feedgas flows are into Sabine Pass T5 and Corpus Christi T1, there is upside to our LNG figure of around 0.2 bcf/d.
- For injection season 2019, the massive y/y gains in the power sector seen this summer scale back to 0.5 bcf/d y/y based on 10-year-normal weather. Structural demand will be driving demand at a forecast 3.6 bcf/d higher y/y. That said, structural demand is the most prone to timeline risks, and we continue to maintain a cautious stance on Mexican exports given the proliferation of delays to domestic infrastructure. While LNG export facilities have also been vulnerable to delay, FERC approvals for Freeport LNG could see that facility enter service ahead of schedule.
Tying it together: Storage and price outlook
- Our 3.2 tcf end-October carryout raises significant concerns over peak day deliverability this upcoming winter. While the market has recently backed off on pricing that concern on a stretch of warmer-than-normal weather expected in November, even the extra ‘padding’ from that warmth would not be enough to assuage deliverability concerns—for that to happen, a widespread warm end to Q4 would have to occur. If concurrent cold was to hit both the Northeast and West South Central, the build out in structural demand and rise in power fuel prices are likely to lead to cash price spikes above last year’s levels.
- Our balances under 10-year normal weather lead to an end-March inventory level near 1.45 tcf, with no allowance made for freeze-offs. With the wait-and-see attitude the market is taking toward winter, another pivot in price could occur depending on how mild (or cold) winter starts off, after the warming trend expected in early November. Putting scenarios around the upcoming season (see Insight: Winter outlook: deliverability vs availability, 24 September 2018), a 5% colder-than-normal scenario underscores the weather risk that comes with such a low end-of-season carryout. End-October stocks are nearly on par with the third week of December last year. Adjusting for increases in demand from res-com, industrial heating, power load, and price-related givebacks in the power sector, winter-wellhead disruptions, and an uptick in net trade with Canada, such a scenario puts end-March storage at 0.9-1.0 tcf and would spur winter prices toward $3.40–3.50/mmbtu. However, a 5% milder-than-normal scenario would significantly loosen balances, pushing inventories toward 1.7 tcf. Given that our 10-year-normal end-October 2019 carryout is now over 3.7, the additional demand loss from mild weather would carry price reverberations through the winter and into injection season 2019. In such a mild scenario, we would anticipate winter prices at $2.75-2.85/mmbtu and an injection season price of around $2.35/mmbtu.
- For the 2019 injection season, we anticipate that power burn gains will narrow substantially, toward 0.5 bcf/d y/y. The main driver of demand will be structural demand, which carries an inherent timing risk given the amount of new LNG export trains, Mexican infrastructure projects and industrial facilities anticipated to come online. The risk here tends towards delays, rather than quicker-than-anticipated additions to demand.