Ho, ho, ho and a bottle of rum

Published at 18:05 13 Dec 2018 by . Last edited 11:18 22 Aug 2019.

Today’s report (week ended 7 Dec): EIA: -77 bcf, EA: -79 bcf

  • To true up to today’s EIA print, we downwardly adjusted our res-com estimate by 0.2 bcf/d.

Next Thursday’s report (week ending 14 Dec): EA preliminary: -152 bcf

  • Our models show that next Thursday’s withdrawal number will be the largest until at least the week ending 4 January. Our balance is informed by a 1.2 bcf/d w/w retrenchment in production with a nearly 10.5 bcf/d w/w surge in demand.

Ho, ho, ho and a bottle of rum

The 10-day forecast is promising a very balmy weather trend ahead of the holiday season. Our balances, based on 10-year normal weather, were pointing to an end-December storage carryout near 2.5 tcf, but the mild forecast weather has pushed that carryout up to 2.54–2.55 tcf, still well below the Polar Vortex December 2013. While that additional 50 bcf does not totally offset the weather-aided demand gains from November’s abnormal cold, it does account for a meaningful portion. As such, this swing puts our end-March inventory estimate closer to 1.35 tcf (making no allowance for freeze-offs), which is still not a level that suggests the market is out of the woods in terms of deliverability with more than 90 days of the heating season still to go.

While market bulls may be disheartened to be entering the holiday season on a tropical note, an assessment of where near-term balances stand is appropriate. Weather is garnering the lion’s share of the market’s attention, but the new headline weekly record production figure, featured in the reference week, turned heads as well. However, the current week is showing a retrenchment in output. As production steps down, we are also seeing a step-up in LNG feedgas demand and a potential ramp in industrial demand. In other words, there could be some fundamental tightening in the offing, with weather somewhat masking those impacts right now.

Recent pipeline flow data has been subject to revisions. But for the week in progress, the output decline suggested by the data appears substantial and justified—we expect that the data will not see a substantive upward revision. Appalachia receipts took a hit after flows on NEXUS slid by 0.2 bcf/d w/w to 0.7 bcf/d. A 0.3 bcf/d decline in Permian output is stemming from a force majeure at NGPL’s 103 compressor station in Kansas, as it effectively chokes northbound flows. Gulf of Mexico (GoM) output is also on track for a 0.3 bcf/d w/w decline due to lower flows in three places. Maintenance on Tennessee Gas’s Station 524 had hindered GoM flows by 0.1 bcf/d, volumes flowing on Kinetica Deepwater also fell by 0.1 bcf/d w/w (to 0.2 bcf/d), and maintenance on Shell’s Auger platform appears to be shaving flows on Garden Banks, by 0.1 bcf/d w/w. At the time of writing, Shell had not released details on the scope or duration of the works.

Further out, the extent of the production recovery will be crucial in determining December balances. Assuming the weeks ending 21 December and 28 December return towards the reference week’s output level, December is on track for a 1.3 bcf/d m/m gain. But if production stays at levels near the week in progress, December would post a m/m gain of only 0.7 bcf/d.

From a structural demand perspective, feedgas flows for LNG have picked up perceptibly in the past three days at Corpus Christi T1, close to the facility’s full capacity of 0.7 bcf/d. Feedgas for the rest of the month, therefore, could easily trend higher than has been seen in the first half of December. In addition, feedgas volumes at Sabine Pass have not indicated yet that T5 is ramping up to capacity yet. Given that Cheniere has anticipated first LNG at both trains this year, there is still a good chance that these numbers can move higher. For the industrial sector, we expect to see some gas directed to Indorama and Sasol’s new Gulf Coast petrochemical plants.

Looking beyond the 15/20-day forecast, the next move in weather expectations for January is key. The potential for a shift colder later in December did re-invigorate trading today, but the duration of any potential upcoming warming trend, like the one currently in progress, is clearly an issue for Q1 19 pricing. At some point, the market will anticipate deliverability has started being de-risked if notable warmth drags on too far into January. Physical strength in the market has been a mainstay this heating season as utilities and local distribution companies (LDCs) are holding on to gas in storage early in the heating season to ensure they can satisfy their obligation to serve their customer base in the latter half of the heating season and even through April, given the experience of last winter.

At whatever point the utilities/LDCs determine their stocks look adequate enough to dip into inventories, they should be financially compelled to favour withdrawals given the weighted-average cost of gas in storage is substantially lower than spot gas purchases at this winter’s prices. Though a projected end-March carryout just below 1.35 tcf may not be comfortable enough just yet, especially with operators such as Dominion flagging their potential deliverability issues in the latter half of winter, a warm January that would move that projected end-March inventory higher could initiate the process of easing those deliverability concerns. By that token, a cold event (or a short-term forecast of one) to start January would easily shoot prices well above the current trading range.

While December storage activity may seem anaemic with only two triple-digit withdrawals forecast, December 2014 and December 2015 were also characterised by a lack of blockbuster withdrawals (each month recorded only one) and both ensuing Q1s had divergent outcomes in terms of withdrawal activity. A tropical lead in to Christmas may not be the right gift for gas bulls, but it is also no bag of coal. We continue to expect that cash prices on peak demand days should be more severe y/y and that the market is still not out of danger from deliverability issues.

Fig 1: Projected EIA weekly storage change, bcf Fig 2: Projected storage y/y change, bcf/d
Source: EIA, Energy Aspects Source: EIA, Energy Aspects

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