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Fundamentals show multiple possible outcomes to US natural gas storage volumes in 2020

US natural gas storage volumes look to exit winter 2019-20 at nearly 300 Bcf above the five-year average and about 600 Bcf above last year, painting a bearish picture barring the arrival of colder-than-normal temperatures during the last half of the heating season.

However, increasing LNG feedgas demand coupled with a recent dip in US production could lead to lower storage volumes than expected and provide support for higher gas prices in 2020, according to S&P Global Platts Analytics.

US natural gas inventories started out the winter of 2018-19 at the lowest levels reported by the US Energy Information Administration in at least five years. Not that you could tell by looking at Henry Hub, which yawned at the prospect of low winter stocks, comforted by the cushion of gas coming out of Appalachia and the Permian.

With an extra 9 Bcf/d of gas coming out of the ground, it only makes sense the market would begin to reconsider just how much gas needed to be stashed away for the winter, according to Platts Analytics data. Throughout 2019, production grew more than expected, seemingly immune to the persistently low price environment. Northeast production will exit this year 131 MMcf/d higher than the levels that were anticipated this time last year, according to Platts Analytics.

Even more surprising, Texas onshore production for December averaged more than 2 Bcf/d higher than last year’s forecast expected. As a result, 2019 marked the longest consecutive bearish streak of EIA Weekly Natural Gas Storage Reports, going back as far as data is available. So while inventories may have started out this year at record lows, they ended the summer in line with five-year average levels.

Although the current storage shows end-of-winter stock falling to a low of 1.9 Tcf, if recent production figures and LNG deliveries hold through the balance of winter, roughly 200 to 250 Bcf of downside risk exists to Platts Analytics’ end-of-March storage forecast.

Furthermore, an additional 20% decline in the Northeast rig count could result in significant production declines in the region, tightening summer 2020 balances. Texas has also demonstrated some slight recent production declines as the Permian Basin continues to shed rigs as well.

Cabot Oil & Gas said during its most recent earnings call it was ready to show no growth in production volumes at all next year if gas prices stay below the $2.50/MMBtu mark. While not offering any specific guidance yet, Southwestern Energy indicated it would consider pausing drilling altogether if prices continue to fall, repeating actions it took in early 2016 when prices were low.

Appalachian drillers Range Resources and CNX Gas also pointed to lower spending on drilling and completions next year, with the former not ruling out a scenario where the producer would “allow production to go into a modest decline” in 2020 should market conditions dictate.

Also, LNG feedgas demand is exceeding Platts Analytics’ base case forecast for the balance of winter, further tightening balances. Total US feedgas deliveries reached a new all-time high of 8.51 Bcf/d in late December, with the recent surge driven by higher flows to Cameron LNG and Sabine Pass.

Deliveries to Cameron have reached a new high of 0.8 Bcf/d as commissioning activities ramp up for the facility’s second train. Train 2 is scheduled to enter commercial service in April 2020. In addition to Cameron, deliveries to Sabine Pass strengthened above 4.2 Bcf/d. US LNG feedgas set a record-breaking monthly average in December at 7.95 Bcf/d. That mark is 250 MMcf/d higher than Platts Analytics’ base forecast for feedgas deliveries for winter 2019-20.

The year has also ended with a steady decline in Permian rigs as well, which lost nine in the final week to 395, according to Enverus. This marked the lowest active rig count in the basin since June 2017. However, operators in the basin hold a plethora of drilled but uncompleted wells, allowing them to grow production without punching new holes. Total US active rigs ended the year at 686, the lowest level since March 2017.

Taken together, if US production holds near 91 Bcf/d for the balance of winter, which is not out of the question given recent Northeast production readings and stalling drilling activity, there would be roughly 2 Bcf/d (or about 200 Bcf) of downside risk to end-of-March storage levels in the US.

Coupled with the upside risk to feedgas, stocks could finish the winter about 200 to 250 Bcf below Platts Analytics’ forecast, leaving inventories around 1.7 Tcf exiting the winter. This tightness would likely carry into the summer and present upside risk to Henry Hub prices, especially if rig declines continue in the Northeast.


Despite some bullish indicators, Henry Hub futures remain at multiyear lows, especially for the balance of winter, which ended the year at an average price of $2.17/MMBtu. No futures priced above $2.20 appeared until the June contract.

The summer build-up is expected to push inventories above their previous five-year maximums, continuing through injection season to finish October at 3.9 Tcf, according to Platts Analytics. This is a surplus relative to the five-year average of 3.7 Tcf.

As always, the major uncertainty in the inventory forecast is from the weather. Platts Analytics uses 10-year normals for the reference case five-year forecast, but alternative weather scenarios show end-of-March storage could swing up or down by 450 to 500 Bcf — with January explaining almost 45% of this potential change. Under a colder-than-normal scenario, additional pressure on end-March storage would materialize through production disruptions via freeze-offs and/or delays to completion activity. Historical analysis suggests roughly 50 to 100 Bcf of production could be affected.
Source: Platts

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