North America

Published at 19:36 1 Aug 2019 by . Last edited 11:18 22 Aug 2019.

We forecast a North America end-October storage carryout of 106 bcm (3.75 tcf), which should help put a lid on North American gas prices for injection season 2020 and heating season 2019–20. We see Henry Hub cash at 2.25 $/mmbtu through October and expect cash in winter near 2.55 $/mmbtu. The arb remains open for US LNG exports through the injection season and looks more attractive as winter progresses given the wide contango at the TTF and JKM. As for the fundamentals in North America, we expect: net trade with Mexico to be capped by timing risk around new infrastructure; power demand declines y/y over August–October given a high baseline last year; production growth to slow but remain high at over 0.14 bcm/d y/y this heating season; and LNG feedgas demand to continue to rise.

Our end-October storage carry forecast has inched up, and gas prices reflect this bearish outlook. The put-call option skew for the rest of the injection season overwhelmingly favours price downside, especially at strike levels at 1.75–2.25 $/mmbtu (see Fig 3). Given the market’s short bias, an unexpected and significant heatwave could see prices move outside the current trading range, but the 15-day weather forecast suggests that is unlikely. For heating season 2019–20, a starting point for storage around 106 bcm should rule out the price escalation seen in November 2018 amid the first burst of winter cold and the lowest end-October inventories in years.

We remain cautious on US gas demand growth, with the headwinds we have been tracking reining in potential growth informing our end-of-season storage estimate. Our conservative view of Mexican net trade remains—underpinned by timing risk and lack of downstream connections and bolstered by last month’s news that CFE was entering arbitration with several pipeline project developers. CFE has tendered for four LNG cargoes through August, meaning that LNG will likely be used to backfill demand on Sur de Texas-Tuxpan until at least early September. The size and duration of any subsequent tenders for LNG delivered into Altamira will give an indication of any further delays to pipes starting up and how long they may last.

In the power sector, our reference case assumes a 25 mcm/d y/y decline in demand over August–October—even despite currently low gas prices—given that it was exceptionally hot over the same period in 2018.

Demand for gas for exports via LNG remains strong and is on track to rise by 92 mcm/d (3.26 bcf/d) y/y over August–October. We assume no shut-ins at US LNG facilities this injection season as the arbs to the TTF and JKM have predominantly been open, these cargoes are likely to have already been hedged, and the tanker day rate is a sunk cost for many. LNG feedgas demand will top 99 mcm/d (3.5 bcf/d) y/y growth in winter 2019–20 assuming the timely start-up of trains at Freeport LNG and at Cameron LNG.

US gas production growth is still high y/y despite slower permitting activity in Appalachia and Haynesville. June output surpassed expectations and July would have too if not for interruptions to production due to Hurricane Barry. Gulf Coast Express (GCX), which will help to debottleneck the Permian, will enter service 7–10 days earlier than its previously expected 1 October start date and will raise the baseline of production ahead of the upcoming heating season. We expect a slowdown in growth from gas-directed production, but supply will be propped up by associated output and near-term NGL fundamentals that point to ongoing ethane rejection. Overall, we see gas production growth slowing from 0.25 bcm/d y/y in July to only 0.14 bcm/d y/y this heating season, but that growth will still help keep a lid on US gas prices.

Fig 1: Henry Hub price forecast, $/mmbtu Fig 2: US production forecast, bcm/d
Source: ICE, Energy Aspects Source: EIA, Energy Aspects

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