North America

Published at 10:23 5 Apr 2019 by . Last edited 11:18 22 Aug 2019.

A mild end to March has shifted our end-October estimated US storage position from 3.4 tcf (96 bcm) to more than 3.6 tcf (102 bcm), leaving balances much looser. As a result, we have revised our previous $2.87/mmbtu Henry Hub injection season strip down to just below $2.80/mmbtu. On top of this storage shift, based primarily on end-of-winter weather and slightly higher production expectations, is an incredibly bearish global gas price backdrop. The May-19 and Jun-19 JKM-TTF spreads have fallen to below where we estimate they need to be to keep the netback for US cargoes to Asia higher than to Europe. The precipitous decline in global pricing means that the LNG market is now not far from seeing the first ever closing of the TTF-Henry Hub arb. If US cargoes are to be left in the US market, we think the potentially shut-in volume will be limited to 96–144 bcf (2-3 Mt) over summer 2019. In such a scenario, we expect the gas not exported to be diverted to price-induced domestic coal-to-gas switching and for some volumes to head to storage.

Aside from the constant weather wild card, the risks for the US injection season appear to be leaning toward more supply, less demand and therefore looser fundamentals. Maintenance at Sabine Pass T1 and T2, a marked uptick in production growth, and the potential for closed LNG arbs could easily leave storage even more well-stocked. Our balances have always assumed a full-month shutdown for two generic US trains for maintenance (we have placeholders in April and October). Bearish drivers also include possible delays to the start of the 2.6 bcf/d (74 mcm/d) Sur de Texas-Tuxpan and uncertainty as to whether Freeport will hit its April/May feedgas target.

Already, Sur de Texas-Tuxpan is poised to miss an early Q2 19 in-service date, with CFEnergía (CFE) tendering for cargoes into Altamira through the third week of April. CFE has recently stated that issues delaying permitting for the pipe are now resolved, and it will start flowing gas between 15 April and 1 May. We assume in our balances a mid-Q2 19 Sur de Texas-Tuxpan start-up, which underlies the majority of our projected 0.5 bcf/d (14 mcm/d) y/y growth in injection season Mexican pipeline exports. The Wahalajara pipeline system, the other major pipeline system that could facilitate direct US pipe exports to Mexico, appears to be tangled in ejido collective ownership issues and faces protests and sit-ins in Durango state. Consequently, that incremental relief for the Permian is unlikely to be arriving this summer and should not be a notable contributor to pipe cross-border pipeline trade.

New LNG feedgas demand slow to start up

Ramp-up of Cameron feedgas has been back to zero in the past six days before a 5,000 mmbtu (0.14 mcm) take on 4 April, despite the facility receiving FERC’s blessing to commission its feed gas system on 27 March and to commission its dry flare system on 3 April, but some pick-up is expected this shoulder season. Incremental gas is flowing to Corpus Christi 2 and could also move the needle on demand before peak cooling season. Meanwhile, Freeport’s chance of a timely start-up will be determined in the coming weeks, hinging on when it requests FERC feedgas permission, which it expects to do in April or May. As Corpus Christi T2 and Cameron T1 ramp up, along with some incremental gas from Freeport T1, LNG feedgas is to add 1.5 bcf/d (42 mcm/d) of demand this injection season.

The stuttering nature of demand growth takes some pressure off the supply side and the degree to which production needs to grow y/y. Q1 19 production growth has been pockmarked by pipeline operational issues and freeze-offs. Our estimates suggest that some 100 bcf (2.8 bcm) has been lost due to freeze-offs, although that still leaves Q1 19 y/y growth at 9.1 bcf/d (0.26 bcm/d). Our reference case assumes slowing sequential production growth as the injection season progresses, and while y/y increases are still high, this will drop to an average 7.4 bcf/d (0.21 bcm/d) y/y growth over the full injection season.

We expect some potential weakness this shoulder season. Based on an end-October carryout that has now risen from just below 3.4 tcf (96 bcm) to more than 3.6 tcf (102 bcm), we have revised our previous $2.87/mmbtu price view down to just below $2.80/mmbtu.

While global demand for US LNG may be waning

There is potential downside risk to that figure, given the potential for delays at new LNG terminals and Mexican infrastructure as well as recent global price falls that have significantly narrowed TTF-HH and JKM-HH arbs. For the TTF-Henry Hub arb to close though, the TTF will need to fall below $4.15/mmbtu. Of course, variable versus fixed costs are not necessarily the same for all market players, and that arb estimate does include the daily freight rate. For participants with long-term vessel charters, that freight could be seen as a fixed cost, effectively narrowing the spread at which the TTF-HH arb closes. Though shutting in some US volumes is not in our reference case, it has nonetheless now become a tangible US market risk. At most, we expect 96-144 bcf (2-3 Mt) of LNG could be at risk of being shut-in over summer 2019, although whether that risk materialises depends on how Russian pipeline exports into Europe behave.

The bearish tilt of the global gas market could weigh on Henry Hub, as could mild weather. Still, we see some downside support for prices from power sector demand. If prices average $2.70/mmbtu over the injection season, another 0.7 bcf/d (19.8 mcm/d) of gas head into power.

In the absence of any other changes and under 10-year normal weather, the added power demand would take end-October storage back toward 3.43 tcf (97 bcm), which would again raise potential deliverability concerns for next winter. A move below that storage level seems unlikely unless supply outpaces our forecasts, or demand (particularly the call on feedgas from LNG exports) falls short. If either of those events happen, then both added demand from power and higher injections into storage will happen and facilitate a move lower on prices.

With a storage carryout of just over 3.6 tcf (102 bcm), the heating season is already looking fairly comfortable and should rule out the winter risks rally that punctuated trading ahead of the 2018–19 heating season. We expect Henry Hub prices will average $2.95/mmbtu next heating season.

Fig 1: 2019 prices, $/mmbtu Fig 2: US 2019 injection season y/y change, bcf/d
Source: NYMEX, Energy Aspects Source: Energy Aspects

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