An extended outage at the Freeport liquefied natural gas (LNG) terminal continued to dominate the North American natural gas price outlook during the June 9-15 trading period, casting a wide shadow over regional markets from coast to coast, NGI’s Forward Look data show.
The initial outage following an explosion at the 2.0 Bcf/d Freeport terminal, located on Quintana Island on the Texas Coast, sent a shockwave through the natural gas market in the week-earlier period. The shock following reports Tuesday that the terminal won’t return to full service until late this year was similar in magnitude.
The prospect of prolonged downtime for a major source of export demand saw regional forwards contracts throughout the Lower 48 hemorrhage value. July fixed price Henry Hub plunged $1.279 week/week to average $7.421/MMBtu as of June 15 trading. Price action at the national benchmark during the June 9-15 time frame included a $1.420 day/day swoon as news of the extended Freeport outage spread through the market. The sell-off was similarly pronounced at other Lower 48 hubs.
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Meanwhile, after tumbling $1.420 in Tuesday’s session, July Nymex futures recovered some of their losses in Wednesday’s trading before inching higher on Thursday to settle at $7.464, well off of week-earlier levels.
Storage Trajectory Still Tight
Goldman Sachs Commodities Research following the latest Freeport outage news revised its end-October storage estimate to just over 3,500 Bcf, versus 3,424 Bcf predicted back in April.
“This remains a low storage level relative to history,” Goldman analysts Samantha Dart, Damien Courvalin and Romain Langlois said in a research note. “As a result…should our U.S. gas balances realize tighter than we expect in the coming months, the risk remains that U.S. natural gas prices may need to trigger max substitution towards Appalachia coal, which we estimate would require a sustained gas price rally to around $12/MMBtu.”
The net negative impact on the price outlook resulting from the higher end-October storage level is “more than offset by the higher potential weather volatility for the remainder of the summer” versus the firm’s previous modeling, along with “much higher Appalachia coal prices.”
All in all, the next nine months are likely to be “the tightest part of the U.S. gas forward balances of the next few years” amid lagging inventories and slow production growth year-to-date, the Goldman analysts said. “Once production growth becomes more visible, which we expect during 2H2022, this will set the stage for much softer U.S. balances in 2023 and 2024.”
A scenario in which hot summer temperatures drive up cooling demand and eat into the cushion provided by the Freeport LNG outage remains in play, according to Bespoke Weather Services.
“As long as we stay hot, we run the risk of chewing away a big chunk of what Freeport gave us,” Bespoke said. “Obviously, if the heat fades, and stays away, that’s a different ball game, but if our lean toward a hotter balance of summer comes to fruition, we stand by our view that there is upside risk to prices as we advance toward expiration of the July contract.”
Updated forecasting from the American weather model as of midday Thursday pointed to a “rather bullish pattern” for much of the 15-day outlook, NatGasWeather told clients.
“With highs of 90s to 100s continuing over Texas and much of the interior U.S. into the foreseeable future, national demand will remain stronger than normal most days,” the firm said. “It just won’t be as noticeable with Freeport LNG offline.”
The weeks ahead appear poised to deliver “challenging trade” for natural gas markets, the firm said. Traders will be left to weigh “bullish weather patterns and tight supplies” against a “suddenly bearish” LNG export outlook.
“Bigger picture, estimates for the next few week’s builds have increased due to the Freeport LNG outage, although the pattern is still hot enough where builds should print slightly smaller than normal, preventing deficits from meaningfully improving,” NatGasWeather said.
A net 92 Bcf injection reported by the Energy Information Administration (EIA) Thursday left Lower 48 inventories at 2,095 Bcf as of June 10, a 323 Bcf (minus 13.4%) deficit to the five-year average.
Northeast Basis Strengthens
The June 9-15 period saw basis strengthen at a number of hubs throughout the Northeast and Appalachia. Transco Zone 6 NY July basis ended the week at a 59.6-cent discount to Henry Hub, a 22.0-cent increase week/week. Further upstream, Eastern Gas South basis for July ended the period 79.2 cents back of Henry, a 31.2-cent swing higher week/week.
Prior to the 2021/22 winter, it had seemed pricing dynamics in the Northeast were on track for a repeat of recent history, when takeaway constraints drove deep discounts for Appalachian hubs, RBN Energy LLC analyst Sheetal Nasta observed in a recent blog post.
“Instead, the market went in the other direction the past few months,” Nasta said. “Takeaway utilization out of Appalachia has been lower year-on-year and, for the most part, Appalachian supply basin prices have followed Henry Hub higher even as that benchmark rocketed to 14-year highs.”
Still, takeaway constraints could be a concern for the region moving forward, even as “the market is now poised to escape the worst of it this year” despite further delays in the startup of the Mountain Valley Pipeline, according to the analyst.
What happens during the injection season will determine whether constraints emerge as a factor in Appalachian pricing, Nasta said.
This includes “the timing and extent of production gains versus in-region storage and demand needs, which in large part comes down to weather,” the analyst said. “If the weather in the Northeast is mild, causing storage levels to rebound by the fall when injections usually taper off and Cove Point LNG demand falls…then there might be little shock absorber left to soak up regional supplies.
“That said, the more likely scenario is that bullish fundamentals this winter and spring may have bought producers a bit of a longer runway to grow production,” Nasta added.
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