LNG exports, Power demand, and Industrial consumption have been key focal points for the past couple of weeks with a historic rise in spot prices impacting all 3 S&D components in dramatic fashion. Following the calamity of the Feb 18 storage week the market has been left in a state of confusion as it pertains to daily demand assumptions, what to assume going forward, and the read-through when/if the market finds itself in need of deterring demand for more a longer duration next winter. The upcoming summer season may offer up more confusion as the progression through injection season will make for some jarring year-over-year S&D changes by month. As a precursor to the details provided below, we suggest market participants prepare for increased monthly and daily price volatility. However, there is always the possibility that the market goes to sleep for the summer. Inverted hibernation is not completely abnormal since it is impossible to run out of natural gas during an injection season. As a reminder all 7 months of the 2018 injection season expired inside of a $0.30 band between $2.70 and $3.00, despite the fact that a path to 3.2 Tcf was made clear as early as June.
As the 2020/2021 winter withdrawal season draws to a close for the North American natural gas market, a calm has settled over the NYMEX forward curve. Panic level pricing in the spot market observed in mid-February is seemingly a distant memory. Bal 2021 has been bouncing around between $2.75-$3.00 per MMBtu, Cal 22 is has predominantly remained in its comfort zone inside a $2.65-$2.75 band, and the back of the curve inaudibly awaits some lasting and meaningful price signal from the front of the curve before budging from its base near $2.50. Of course, there are still countless governmental hearings, lawsuits, and invoices yet to be settled related to the arctic blast which hammered the mild third of the country in mid-February.
The 2020/2021 withdrawal season is most likely to end with an overall inventory level somewhere between 1.5 and 1.6 Tcf. Such a level is wholly unremarkable at face value, with the market typically only getting over heated when inventory approaches either 1 Tcf or 2 Tcf. Weather could certainly cause a divergence of 50-75 Bcf from the aforementioned 1.5-1.6 Tcf range, but anything beyond that would be a product of either A) extreme weather events, or B) unforeseen supply side changes. In summary, the market is now poised to look beyond the winter and begin making assumptions on what will transpire in the upcoming injection season.
Before sharing our high-level thoughts on the 2021 injection season we believe it is first relevant to point out some important data points from the winter that is soon to conclude. First, the full winter withdrawal season (Nov-Mar) is most likely going to post a top 15 warm HDD count (70yr history), and potentially a top 10. In terms of lost weather driven demand this winter a rough approximation of -500 Bcf is justifiable. Secondly, LNG exports have surprised to the upside this winter with an average of more than 10 Bcf/d. Dry gas production has remained stagnant, and inline with public commentary re: ‘maintaining flat production until prices recover’. The remaining key S&D components (Industrial/Power/Canadian Imports/Mexican Exports) have seen their fair share of volatility, particularly in relation to the February cold blast, but generally speaking have shown a recovery from peak COVID-panic levels with no signs of new and lasting trends. Taking all of the above under consideration, a cumulative withdrawal of 2.3-2.4 Tcf is best categorized as a warning shot.
Now turning our attention to the summer injection season, we would first like to point out the importance of how last year’s COVID related S&D changes unfolded on a month-by-month basis, with a particular focus on LNG feedgas demand, production levels, and power consumption. How the market digests and reacts to year-over-year comparisons is a force that must be contended with regardless of whether or not it is the best barometer for price strength or weakness. As such, understanding what happened last year is an ideal starting point for contemplating what is yet to come in the 2021 injection season.
In April of last year LNG exports began to slip with early month feedgas demand at approximately 9.5 Bcf/d and an exit rate closer to 8 Bcf/d. Production levels moved through the month at a similar pace LNG exports, with early April production prints approximately 1.5 Bcf/d higher than the exit rate. April 2020 weather would be described as bullish in any normal year with the total HDD count coming in at 20 greater than the 30yr normal, or in the top third of all April observations in the past 71 years. However, government mandated COVID-19 restrictions were first issued in draconian terms in the Northeast and Upper Midwest, which muted the demand impact of colder than normal weather. Last April had a Henry Hub index price of $1.63, and unsurprisingly power demand was very strong. April 2020 power consumption was 25.5 Bcf/d according to the EIA. This was the highest April power burn ever recorded.
May 2020 was the peak COVID-19 response month from a natural gas demand perspective. Industrial demand was down 1.6 Bcf/d Y/Y and at the lowest level for the month of May in more than 3 years. Power demand held its own with a flat Y/Y print of 27 Bcf/d, and propped up by a Henry Hub index price of $1.79. LNG and Dry Gas Production continued to sink with LNG feedgas demand falling 1.8 Bcf/d from entry to exit, and a daily average 1.5 Bcf/d lower than April ’20. Dry gas production losses accelerated sharply in May posting a month-over-month decline of more than 2 Bcf/d, and the first recorded year-over-year deficit since April of 2017. May 2020 cooling demand per the CDD count was weak relative to recent history, and important to note since power demand managed to remain flat Y/Y. Total population weighted CDDs for the month tallied 120, which placed May 2020 as the coolest May since 2013. Although warmer than normal, gas intensity was minimized since the Southeast was cooler than normal.
For simplicity sake, we are going to group June-August 2020 together, and understandably omit the impact of tropical activity and varying week-to-week weather patterns. We are already a bit in the weeds, and want to ensure that attention is not completely lost. Stick with us and remember the path we are taking will drive home an important point.
June-August of 2020 were considerably warmer than normal and only bested by the same stretch in 2016 and 2011. However, please note that 2012 and 2018 were not far behind in terms of population weighted CDDs. Hot weather drove record setting power demand during a period which posted a three-month average index price of $1.69, or generally speaking at the same levels seen in April and May. Daily average power burn from June-August 2020 was over 40 Bcf/d per the EIA, while LNG feedgas demand and Dry Gas production had effectively bottomed. LNG feedgas fell to an average of of just under 4 Bcf/d, and Dry Gas production averaged 3 Bcf/d lower than prior year levels. At this point the market started to recover with forward prices steadily climbing through the Fall. Calendar 2021 eventually peaked at just under $3.20 and the winter ‘20/’21 strip had a one-touch high just over $3.40.
The price recovery was not without speed bumps in September and October. Forward looking balance assumptions and rapidly tightening market conditions in the immediate term were still subject to the impact of excessively high inventory levels. A race towards inventory constraints near the 4 Tcf level were almost inevitable and yet the market began to see how quickly LNG exports were rebounding, how sluggish Dry Gas production was, and the stickiness of power demand.
A cumulative injection of approximately 400 Bcf in Sept and Oct of 2020 prevented a breach of 4 Tcf, but largely due to late October cold and the first October withdrawal reported in more than a decade. LNG feedgas demand was up to a 2 month average of 7 Bcf/d, and by late October daily prints were closer to 10 Bcf/d. Dry gas production plummeted in response to shut-in pricing in Appalachia due a basis blowout, and temporary tropical storm related losses weighed on the daily average as well.
In total the summer ’20 injection season was one for the record books with shale era production losses setting records, power demand setting records, and extremely price responsive LNG export community wielding its market power. The cumulative storage injection from April-October of 2021 was 1.93 Tcf, or almost 700 Bcf lower than the prior year. However this total was still notably higher than the 2016, 2017 and 2018 inventory builds.
Looking forward to the upcoming 2021 injection season the above detailed discussion illuminates the following important observations:
- LNG feedgas demand at current levels will be approximately 4 Bcf/d higher year-over-year on average for the Apri-October period with the delta climbing as high as +6.5 Bcf/d at mid-summer
- Dry gas production flat at current levels will be down 1 Bcf/d in the first two months of injection season before posting steadily increasing Y/Y gains for the balance of injection season. By October year-over-year production growth would total 2-3 Bcf/d, if volumes remained flat v. current levels
- Power demand will be measured against an almost unreachable level without a calamitous price rout, and most likely be the market’s focal point at mid-summer
A walk through the granular discussion above is meant to provide market participants with the following cautionary notes:
- Early injection season storage builds may not accurately reflect risks which could arise as early as June. By late April-early June LNG export demand will be materially higher Y/Y and declines in Y/Y power demand could be more than offset by this component alone, and magnified if temps are warmer than normal
- At mid-summer lost power demand due to $1.00 or more increase in monthly index prices will only be relevant if temps are cooler than normal since LNG exports will be capable of completely offsetting price elastic demand losses
- Without a price signal in the next 30-60 days the ability for gas producers to significantly increase output ahead of the winter ‘21/’22 withdrawal season will be limited
The odds of an inventory build of significantly greater than 1.9 Tcf are very low without A) a cooler than normal summer, B) a rapid response from the crude producing community to $60/Bbl or better pricing, and/or C) European inventory refilling at a pace which pushes gas back in to the North American market late in the 2021 injection season.
In summary, we will leave readers to ponder the effects of how well suited they are to handle a static pricing environment for the majority of the 2021 injection season which would ultimately magnify the upside price risk ahead of next winter, or how they will respond if the market prices in low inventory risk early in the 2021 injection season.
Zane has been with Mobius Risk Group since February of 2016. His primary responsibility is a fundamental analysis of the North American natural gas market. Additionally, he assists in the valuation of gathering, processing, transportation, and physical sales agreements. His experience in energy has been focused on natural gas, however, as the North American hydrocarbon value chain has become a more integrated system his knowledge has expanded to crude oil, petroleum products, and seaborne LNG. Prior to joining Mobius, Zane spent 6.5 years with a Houston based hedge fund (Goldfinch Capital) with AUM of approximately $750M. In his time with Goldfinch Capital, Zane was tasked with developing detailed models of the North American natural gas market, including 1st derivative components such as power generation by fuel source, supply side impacts of liquids focused drilling, etc. Zane is a graduate of Rice University, and a former member of his alma mater’s baseball program as both a player and coach.