Winter NatGas Inventories: Choose Your Temperature Adventure
Winter temperatures will determine the extent of the drawdown, although structural changes have us trending toward tighter markets in most scenarios
Whether it’s a mild or cold winter will determine much of how North American natural gas markets evolve over the next few months, with more than 1.5 trillion cubic feet of inventory between the two extreme scenarios.
Structurally higher exports and still-recovering domestic production (from the lows of the pandemic) will likely push natural gas inventories to lower than usual levels even in an average winter temperatures scenario, especially after accounting for total system inventory cover.
In a worst-case-scenario, a particularly cold winter—like, for example, one on par with the 2013-14 polar vortex—would significantly deplete inventories, likely driving them to their lowest effective level in over a decade.
North American benchmark Henry hub natural gas prices have had an extremely volatile past month, rising to a 13-year high of more than $6.30 per Million British thermal units (MMBtu) in early October and then retreating to the $5-6/MMBtu range in the weeks since. Now we’re entering the winter season with record-high exports and effective inventory cover at the low end of the 5-year range. As I noted in my last newsletter on natural gas, higher and inflexible exports to markets roiled by energy crises have increased the pressure on US natural gas infrastructure and, correspondingly, made what would have seemed like plenty of inventory cover 5 years ago look far more meagre today.
The stage has been set: the evolution of prices over the next six months will mostly come down to weather trajectory and resulting inventory draws. So, how extreme are the differences between a cold winter and a mild winter for natural gas inventories, all else equal? Based on my [quick] calculations, the answer is more than 1.5 trillion cubic feet. That is, the extent of the cold this winter means the difference between low but passable working inventories and critically low ones.
The three winter temperature scenarios here—average, cold, and mild—keep most parts of the natural gas system like production, exports, and non-heating-related demand constant (and I discuss these assumptions more at the end of this post). These scenarios only vary in their predicted weather patterns: the “average winter” uses 10-year seasonal average temperatures, the “mild winter” follows the abnormally warm 2011-12 experience, and the “cold winter” recreates the bone-chilling 2013-14 polar vortex.
Too Hot, Too Cold, Just Right—They’re All Still Pretty Tight
Let’s look at the three scenarios over a 10-year history. In the “average winter” scenario, temperatures follow their 10-year seasonal average and inventories fall to around 1.5 trillion cubic feet by the end of the winter drawdown in March. These levels are about 10% below the 5-year average, but still well within the 5-year range and in line with the 2014-15, 2017-18 and 2018-19 winter drawdowns. We’re in similarly normal inventory ranges in the “mild winter” scenario. This scenario puts us at the upper end of the 5-year inventory range, with a good number of historical parallels. Factoring for total system inventory cover (see my last natural gas post), the typical-temperature winter scenario looks notably tighter at roughly 20% below the 5-year average compared to the mild scenario that essentially traces the 5-year average.
Then there is the truly threatening “cold winter” scenario, with the depth of its potential drawdown going a long way towards explaining higher gas prices. The “cold winter” scenario looks at what happens if we get a repeat of 2013-14 frigid cold temperatures, which at the January-February peak was about 15% colder than the 10-year average. This type of cold winter combined with current high exports and still-recovering production would pull nearly 3 trillion cubic feet of gas out of inventories through March and bring us to a perilously low inventory position of less than 700 Bcf. That inventory level amounts to just more than 6 days of total system demand cover when most winters fail to break below 20 days of inventory cover and only a couple drop below 15 days.
Now, the probability of slipping into the “cold scenario” is low; we’ve only had one winter with those extreme temperatures in the past decade. However, the massive potential implications for natural gas market balances help explain why we’re seeing such high prices today: even the low probability of a high impact scenario warrants material repricing, especially given the rest of the energy crises buzz that is electrifying markets at present.
You know what they say about assumptions…
The purpose of this scenario-based piece was to give readers a sense of the magnitude of winter temperature variability on natural gas inventories. Therefore, I have kept the non-temperature assumptions quite basic and reasonably conservative:
I leverage the Energy Information Administration’s Short Term Energy Outlook forecast for domestic natural gas production, which assumes a steady but not dramatic output recovery through the winter. This is certainly not the kind of production recovery we would have expected in pre-COVID times, but you can read more about why producers aren’t snapping back as quickly in my first natural gas post.
I see LNG exports steadily rise to 12 billion cubic feet per day, reflecting a level previously achieved this past Spring. Flows will be further assisted by the start-up of new LNG export capacity through the first half of 2022, though no major uplift from these projects is assumed through May.
I keep pipeline exports to Mexico flatlined around current levels, while both exports to and imports from Canada reflect a typical seasonal patterns.
I also assumed Non-Residential, Non-Commercial domestic natural gas demand follow their typical seasonal pattern.
Overall, these three scenarios assume that there is no movement in non-temperature variables, which is obviously unrealistic: if inventories fell as deeply as the cold winter scenario foresees, prices would surely rise enough to depress power or industrial demand or further accelerate production bounce back before the implications of the cold winter scenario are fully played out.
We’re positioned for tight North American natural gas markets given higher export demands and continued pandemic production recovery, but ultimately the next six months of the natural gas market is largely up to the weather. The extent of the winter inventory drawdown varies by as much as 50% across three potential temperature-driven scenarios. Most notably, these scenarios highlight that the North American natural gas market faces a bullish near-term tilt as the combination of lower production and record exports are pressuring inventory cover lower.