Please note that we will not publish an August edition of North America Outlook. The monthly schedule will resume as normal in September.
- US output has surged since late June, growing sequentially by 1.6 bcf/d. Nearly half of that increase is sourced from Appalachia, although associated production is also making a tangible contribution. We continue to see timing risk surrounding new Appalachia infrastructure. But even if Atlantic Sunrise misses its expected late-August in-service date by several weeks, that pipe together with Nexus (which is 80% complete), should stave off any large-scale congestion concerns once they come online.
- For the upcoming heating season, we assume nearly 6 bcf/d of production growth, which will be supported by continued gains in Appalachia as well as associated gas.
- We expect just under a 1.0 bcf/d y/y gain in the power sector during the heating season. Without the structural shifts from new gas-fired capacity and coal retirements that have supported gas burn this injection season, further gains in gas-fired power burn over the next year are likely to be limited.
- From our three pillars of structural demand growth—LNG feedgas, pipeline flows to Mexico and industrial gas use—we expect growth of 2.0 bcf/d during the upcoming heating season. We expect high capacity utilisation of all US LNG trains given global demand for gas in the coming winter season will be high enough in aggregate. Mexican trade will continue to be highly dependent on the ramp-up of new pipelines and whether downstream connections come online on schedule, and such risk underpins our conservative outlook. Meanwhile, industrial demand has been humming along, and the start-up of two plants last week will help to underpin demand.
Tying it together: Storage and price outlook
- Even though a low end-of-season carryout is looking increasingly hard to avoid as the number of days left in the injection season dwindles, the market appears to be pricing in even less potential winter risk. Such a low, sub-3.5 tcf end-October storage level—which we forecast—should support prices, but the anticipated record-high output for the upcoming heating season continues to colour balances. That output will, in effect, act as latent storage even if not being physically pulled from caverns and aquifers.
- Given current NYMEX prices and some renewed strength in coal prices, our 2018-19 heating season reference case forecast is now for more power sector gas demand growth than in our last monthly outlook. However, weather remains the wild card. We still consider there to be upside risk to gas prices on winter weather, especially given the degree of complacency in the market on supply length. Under a 5% colder-than-normal weather scenario, end-March stocks look set to exit the heating season near 1.1 tcf. Such a low level would materially shift the curve from its current level to a three-handle price on a more sustained basis.
- Winter 2018-19 price risk on weather will be more acute if the cold materialises by the first week of December, at which point a sustained price of over $3/mmbtu would be more likely. However, a late start to winter—like in winter 2017-18—would hinder any weather-aided rally in the 2018-19 winter strip or Q1 19 contracts. A low end-of-season carryout would provide modest support to the injection season strip. The reverse weather pattern of 5% milder-than-normal weather would paint a particularly bearish scenario, with end-March 2019 stocks near 1.75-1.8 tcf. Given that our 10-year normal weather assumption yields an end-October 2019 carryout near 3.7 tcf, a milder-than-normal scenario would push the curve well below its current trading range and could see a foray for the 2019 injection season strip near $2.35/mmbtu.