Freeport LNG outage dominates North American natural gas price outlook

A prolonged 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 deep shadow over markets. regional from coast to coast, NGI Future Prospects data exposure.

The initial outage following a 2.0 Bcf/d explosion at the Freeport Terminal on the island of Quintana on the Texas coast sent shockwaves through the natural gas market during the week former. The shock that followed reports on Tuesday that the terminal would not return to full service until the end of this year was of a similar magnitude.

The prospect of an extended downtime for a major source of export demand caused regional futures throughout to hemorrhage value lower 48. July Henry Hub fixed price plunged $1.279 $week/week to average $7.421/MMBtu as of June 15. Price action at the national benchmark during the June 9-15 period included a slump of $1,420 per day as news of Freeport’s extended outage spread through the market. The sale was similarly pronounced at other Lower 48 hubs.

Meanwhile, after falling as low as $1.420 in Tuesday’s session, July Nymex futures recovered some of their losses in Wednesday’s trading before recovering slightly on Thursday to settle at $7.464. , well above the levels of the previous week. July futures reversed course again on Friday, losing 52 cents to close at $6.944 as the market continued to weigh the impact of the Freeport blackout against scorching heat for parts of the country.

Storage trajectory still tight

Goldman Sachs Commodities Research, following the latest news on the Freeport outages, revised its end-October storage estimate to just over 3.5 trillion cubic feet from 3.424 billion cubic feet forecast in April.

“This remains a low level of storage relative to history,” Goldman analysts Samantha Dart, Damien Courvalin and Romain Langlois said in a research note. “As a result…if our U.S. gas balance sheets tighten more than expected in the coming months, the risk remains that U.S. natural gas prices should trigger maximum substitution toward Appalachian coal, which we believe would require an uptick. sustained gas prices at around $12/MMBtu. »

The net negative impact on the price outlook resulting from the higher level of storage at the end of October is “more than offset by the higher potential weather volatility for the remainder of the summer” compared to the company’s previous modeling , as well as “much higher Appalachian coal prices.”

Overall, the next nine months are likely to be “the tightest part of U.S. gas balances in years to come” amid lagging inventories and weak year-to-date production growth, analysts said. Goldman analysts. “Once production growth becomes more visible, which we expect in 2H2022, this will set the stage for much weaker US balances in 2023 and 2024.”

A scenario in which hot summer temperatures increase cooling demand and eat away at the cushion provided by the Freeport LNG outage remains in play, according to Bespoke Weather Services.

“As long as we stay warm, we run the risk of snacking on much of what Freeport has given us,” Bespoke said. “Obviously, if the heat fades and stays away, it’s a different ball game, but if our lean towards a warmer balance of summer materializes, we maintain our view that There is upside risk to prices as we move towards the expiry of the July contract.

Updated forecasts from the US weather model at noon on Thursday indicated a “rather bullish pattern” for much of the 15-day outlook, NatGasWeather told clients.

“With highs of 90 to 100 continuing in Texas and much of the interior of the United States for the foreseeable future, national demand will remain stronger than normal most days,” the company said. . “It just won’t be as noticeable with Freeport LNG offline.”

The coming weeks look set to deliver “tough trading” for natural gas markets, the company said. Traders will have to weigh “bullish weather and tight supplies” against a “suddenly bearish” LNG export outlook.

“Overview, estimates for next week’s builds have increased due to the Freeport LNG outage, although the model is still quite warm where builds should print a little smaller than normal, preventing deficits to improve significantly,” said NatGasWeather.

A net injection of 92 billion cubic feet reported by the Energy Information Administration (EIA) on Thursday left inventories lower from 48 to 2,095 billion cubic feet as of June 10, a shortfall of 323 billion cubic feet (minus 13 .4%) compared to the five-year average.

The northeast base is getting stronger

The June 9-15 period saw the base strengthen in a number of hubs in the northeast and Appalachia. Transco Zone 6 NY’s July base ended the week with a discount of 59.6 cents on Henry Hub, an increase of 22.0 cents week/week. Further upstream, the Eastern Gas South base for July ended the period 79.2 cents behind Henry, up 31.2 cents week/week.

Heading into winter 2021/22, it looked like Northeast pricing momentum was on track for a repeat of recent history, when on-the-go constraints led to steep discounts for Appalachian hubs, observed RBN Energy LLC analyst Sheetal Nasta in a recent blog post.

“Instead, the market has gone the other way over the past few months,” Nasta said. “Takeout usage out of Appalachia was lower year-over-year and for the most part, prices in the Appalachian supply basin tracked Henry Hub higher, even though that benchmark has peaked in 14 years.”

Still, take-out constraints could be a concern for the region going forward, even though “the market is now on course to escape the worst this year” despite further delays to the start of the Mountain Valley Pipeline, according to the ‘analyst.

What happens during injection season will determine whether constraints show up as a factor in Appalachia pricing, Nasta said.

This includes “the timing and extent of production gains relative to storage and demand needs in the region, which are largely dependent on weather conditions,” the analyst said. “If the weather in the northeast is mild, causing storage levels to rebound in the fall, when injections typically wane and Cove Point LNG demand drops…then there might be little buffer left to absorb regional supplies.

“Having said that, the more likely scenario is that the bullish fundamentals this winter and spring may have bought producers a bit longer runway to increase production,” Nasta added.