The Final Countdown - Bearish 2023 Gas Market Punctuates Last Throes of Shale Era Abundance
Monday, 01/30/2023 Published by: Sheetal Nasta rbnenergy.com
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The Lower 48 natural gas market has had the most bearish start to a new year in a long time. Production has been at record highs, an exceptionally warm start to January suppressed demand, and LNG exports have been hobbled since last June when Freeport LNG went offline. The CME/NYMEX Henry Hub February gas futures contract slid to an 18-month low of $2.94/MMBtu last Thursday and expired Friday at $3.109/MMBtu, down 54% from where the prompt contract closed just two months earlier. The March contract extended the slide Monday to a 20-month low of $2.677/MMBtu. Freeport’s eventual return will restore existing export capacity, but there’s no new LNG export capacity due online this year — for the first time since 2016. After one of the tightest gas markets of the last decade in 2022, the stage is set for one of the most oversupplied markets we’ve seen in years. But the bulls out there can take solace: 2023 will also mark the final throes of the kind of oversupply conditions that defined the Shale Era as we know it. In today’s RBN blog, we discuss how we got here and RBN’s outlook for natural gas supply and demand.
If you’re suffering from a bit of whiplash from the gas market, you’re probably not alone. How did we go from almost $10/MMBtu gas and one of the tightest, most volatile markets in over a decade to sub-$3/MMBtu gas and one of the most bearish scenarios we’ve seen in a long time — all in the span of just over six months? Undoubtedly, the gas market has become increasingly volatile and notoriously hypersensitive to weather anomalies and market disruptions in recent years, and there was no shortage of that in 2022.
In Long Story Short, we discussed the bullish factors that sent futures soaring to almost $10/MMBtu in the first place (Figure 1), including the war in Ukraine and the resulting energy crisis in Europe, record U.S. LNG exports and domestic demand, and a lukewarm response from producers to higher prices. These factors made 2022 the most bullish gas market in nine years, with the supply-demand balance net short by an average 1.42 Bcf/d, the tightest since 2013. The Lower 48 storage inventory carried deficits to year-ago and five-year average levels for much of last year, when prompt gas futures prices averaged ~$6.82/MMBtu, the highest since 2008.
As recently as August, the market was bracing for prices to break through the $10/MMBtu level, after which it seemed the sky was the limit. But a number of market events turned that bullish scenario upside-down, at least for now (as evidenced by the precipitous slide in prompt futures prices in Figure 1).
Freeport LNG was taken offline following a fire in early June. Prior to the outage, the facility had been taking an average ~1.7 Bcf/d of feedgas, which amounts to almost 2% of Lower 48 production. The shutdown not only instantaneously wiped that demand out of the market, but kept it off for an extended period — approaching eight months now. Freeport was initially targeting a restart in October, but recommissioning plans have been delayed several times since then. (Finally, last week, the facility filed its first restart-related request and was approved to take the first step in the commissioning process — more on that in a bit.)
During the summer months, record power burn helped mask the demand loss at Freeport, but as shoulder season arrived and temperatures moderated, the market felt the full effect of the outage. While temperatures in October and November were somewhat cooler than normal and the previous year, that doesn't mean as much in the shoulder months when temperature “normals” are already mild. At the same time, production losses were minimal, as what was originally supposed to be an extremely active Atlantic hurricane season turned out to be fairly average, and the storms largely stayed out of the offshore production region in the Gulf of Mexico. Lower 48 dry gas production surpassed 100 Bcf/d for the first time in late August and continued to set records over the next few months. The year-on-year inventory deficit went from 300 Bcf in mid-August to zero by the end of the injection season in November. And, while Winter Storm Elliott brought extreme weather and production freeze-offs and tightened the market considerably in December — with the year-on-year storage deficit returning to the 300-Bcf level by the end of the month — it was no match for the balmy weather that followed in early January.
We should also note that European gas prices, which soared to record levels last summer, also cooled in the fall. European storage facilities were 80% filled by September, and that rose to 90% in October, allaying fears of winter shortages. A milder start to winter also helped, and by late October, global LNG prices had lost much of their injection-season premiums and come back down to earth.
Going back to Lower 48 fundamentals, as we mentioned earlier, January was one of the most bearish for the Lower 48 gas market in at least 13 years — possibly ever — due to exceptionally warm weather. It was marked by an unheard-of storage injection of 11 Bcf in the first week of January — what is typically the coldest, highest-demand month of the year. Since then, unseasonably high temperatures have continued to suppress withdrawals from storage, leaving the Lower 48 inventory at a triple-digit surplus vs. last year and the five-year average.
A look at the daily supply-demand balance data from our U.S. NATGAS Billboard report illustrates just how lopsided fundamentals have been in January. The columns in Figure 2 show the year-on-year changes for each of the components in the supply-demand balance. The dark-blue bars represent an increase vs. the same period last year and the red bars represent a decrease vs. last year.
On the supply side (section to left), the temperate weather has meant we haven’t seen the level of production curtailments from wellhead freeze-offs that we normally do. Dry gas production has averaged 101 Bcf/d in January in our model, the highest monthly average on record and 6.8 Bcf/d higher than January 2022. That was offset by a 1.1-Bcf/d drop in net imports from Canada and slightly lower LNG sendout (i.e., pipeline receipts from LNG imports) for a net year-on-year supply gain of 5.6 Bcf/d.
As for demand (center section), the ongoing outage at Freeport LNG has continued to weigh on the gas market in January, but the demand loss from that — ~1.7-2 Bcf/d — has been overshadowed by weather-related declines. Residential/commercial (res/comm) demand is down 12.7 Bcf/d to an average of just 46.1 Bcf/d, the lowest in 11 years. Industrial demand is down 2.2 Bcf/d to a five-year low of 24.2 Bcf/d, while power burn is nearly flat at 30.8 Bcf/d. Total Lower 48 demand from the three sectors has averaged 101.1 Bcf/d, the lowest for January in six years and down a whopping 15.1 Bcf/d year-on-year.
By comparison, LNG feedgas deliveries have been nearly flat year-on-year in January as gains at Sabine Pass and the addition of Calcasieu Pass counterbalanced the Freeport outage. LNG feedgas flows this month have averaged 11.9 Bcf/d (red line in Figure 2), down just 0.1 Bcf/d year-on-year. Exports to Mexico are also down a notch to 5.5 Bcf/d. All in all, the supply-demand balance in January is net 11.8 Bcf/d short, or 20.9 Bcf/d longer vs. last year’s negative 32.7 Bcf/d and the weakest balance in our data going back to 2010.
The stage is clearly set for a bearish 2023 and near-term prospects don’t look all that more supportive. A winter storm is still expected to boost demand and trigger production freeze-offs in the Bakken and Appalachia later this week, but forecasts have been moderating in recent days and have reduced demand in the 15-day outlook by ~100 Bcf. The latest weather runs indicate the cold snap will be short-lived and bookended by above-average temperatures. Our temperature-based storage model suggests inventory surpluses will balloon to more than 300 Bcf by the third full week of February.
The Freeport outage and warm January only compounded what was already a bearish scenario for the 2023 gas market. As we noted in our Top 10 Prognostications For 2023, there are two major factors that will weigh on prices this year: (1) a hiatus on new LNG export capacity additions and (2) year-on-year production growth.
No New LNG Export Capacity. This is the first year since 2016 that there’s no new LNG export capacity expected to come online. Venture Global’s Calcasieu Pass is poised to begin commercial service soon, but the facility began taking initial feedgas for commissioning in early 2022 and has been taking 1-1.7 Bcf/d on most days since May. This year to date, it’s taken 1.5 Bcf/d on average, not far off the 1.7 Bcf/d we expect will be the facility’s requirement at full utilization.
Freeport will eventually ramp to full operational capacity, of course, but that is the return of existing capacity, not new liquefaction. And it could still be some weeks before Freeport is taking meaningful volumes. As we alluded to earlier, the facility got approval from the Federal Energy Regulatory Commission (FERC) to begin cooling down the transfer piping and ramping up the boil-off gas management system, a preliminary step for restarting the first liquefaction unit. That process is expected to take 11 days (until February 6 at the earliest), after which Freeport will need to request approval for each new step. Moreover, as we saw in January, mild weather has the potential to eclipse returning demand at Freeport, and the more that weather remains a bearish factor, the more it will mute the impact of Freeport’s return when it does come online.
In regards to the Haynesville/Bossier shales, the pace of development will vary by operator but drilling will slow in general waiting for new LNG demand and associated pipeline projects. A number of mineral companies use the Henry Hub Futures forward strip to inform acquisitions. Futures are paper trades and they are nothing more than informed projections for monthly prices. I am unaware of their record of accuracy over the years. Here is a link:
How quickly times change.
Yeah, who saw this coming? I thought European LNG demand would serve to support prices. Now to see how quickly natural gas focused E&P companies ramp down their drilling plans. It can take time and I think a number entered new contracts for rigs over the last six to twelve months.
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