Regional natural gas forward curves offered hints of a market climbing out of the doldrums for the upcoming injection season, even as many hubs held flattish week/week for April delivery, NGI’s Forward Look data show.
Fixed prices at Henry Hub for April delivery added 2.2 cents for the Feb. 22-28 trading period to reach $1.897/MMBtu, according to Forward Look.
Contracts further along the 2024 strip showed a bit more life. The national benchmark rallied 13.0 cents for August to exit at $2.627. June through December 2024 all picked up around a dime or more week/week.
Lower 48 storage has drifted above the five-year maximum on persistently underperforming heating demand. Nymex futures have flirted with historic lows this winter, sending a strong signal to producers to curtail output.
And there have been signs that producers are listening, including a notable dip in dry gas production based on recent estimates.
Wood Mackenzie samples as of Thursday showed production totaling 101.9 Bcf/d. The recent seven-day average totaled 103.0 Bcf/d, versus a recent 30-day average of 104.6 Bcf/d, according to the firm.
Amid this softening in production figures, a number of Northeast, Appalachian and Mid-Atlantic hubs outgained the national benchmark for various contracts along the 2024 strip and into early 2025, Forward Look data show.
Cove Point August 2024 basis, for example, strengthened by 8.5 cents week/week to flip from a 5.5-cent discount to plus-3.0 cents. Eastern Gas South basis added 8.6 cents for September 2024, finishing $1.091 back of Henry. Tennessee Zn 4 Marcellus basis for October 2024 narrowed to minus-$1.289, a 10.2-cent gain, Forward Look data show.
Production In Spotlight
Nymex futures as of Thursday had similarly shown some strengthening in contracts along the 2024 strip. Forecasts suggested the window of opportunity for late winter weather to have an impact was rapidly closing, leaving the market to focus instead on the upcoming injection season.
The ICE End of Draw Index Future recently closed at 2,200 Bcf, which would comfortably top the 2019-2023 five-year maximum for Lower 48 storage exiting the withdrawal season.
“Although bulging storage surpluses at the front of the curve may weigh on near-term pricing, the market may increasingly take its cues from the production trajectory,” EBW Analytics Group analyst Eli Rubin said. “Producers already announced plans to release rigs and frac crews over the next six weeks — and evidence of lower upstream activity may help support upside.”
Heading into the shoulder season, already huge storage surpluses could further swell on weak power burns and potential LNG maintenance, according to Rubin.
“While power sector demand for natural gas has moved structurally higher in recent years…consumption gains are largest during the summer and winter,” Rubin said. “During the shoulder season, power sector demand gains are relatively muted — particularly if wind generation rebounds toward seasonal levels.”
Longer-Term View On Supply
While recent pricing dynamics reflect a market asking producers to pump the brakes, there remains significant growth on the horizon as new liquefied natural gas export capacity comes online.
Projecting changes in overall Lower 48 supply and demand balances out to 2035, RBN Energy LLC recently modeled an incremental 18.9 Bcf/d of production over this span, which would raise domestic output to 121 Bcf/d on average.
“Although the increase pales in comparison to the 66% jump in gas production from 2011 to 2023, we are still looking at a healthy amount of incremental gas,” RBN analyst John Abeln wrote in a recent blog post. “The growth trajectory is strongest over the next six or seven years, slowing to less than 1% year-on-year after 2030.”
In RBN’s forecast, which assumes an average crude oil price of $70/bbl, more than half of that production growth would come from the oil-focused Permian Basin. The other regions driving natural gas production growth in RBN’s forecast, which also assumes an average natural gas price of $4, are the Haynesville and Eagle Ford shales.
According to Forward Look prices, the recent average of Henry Hub contracts out to February 2034 was $3.525.
The Permian, Haynesville and Eagle Ford “would account for more than 80% of the total production bump, as the gas supply picture farther from the Gulf doesn’t net nearly as much growth, especially with Appalachian production constrained by a lack of takeaway capacity,” Abeln said.
As for the new demand sources that would soak up this growing supply, LNG exports unsurprisingly remained a key part of the outlook.
RBN’s projections would see LNG feed gas demand nearly double by 2035, but this excludes further upside from projects not already under construction or with a final investment decision.
This also assumes power sector gas demand, a subject of wide-ranging uncertainty, “plateaus rather than declines” over the period, according to Abeln. “A decline in power usage,” such as that predicted by the U.S. Energy Information Administration, “would free up an extra 15 Bcf/d that would need to find a home and could flow toward exports.”
