Exceptional warmth near-term and an enduring supply buffer kept the pressure on regional natural gas forward prices during the Feb. 1-7 trading period, according to NGI’s Forward Look.
March fixed prices at benchmark Henry Hub dropped 13.6 cents to end at $1.976/MMBtu, setting the pace for coast-to-coast discounts at the front of the curve.
With only a handful of exceptions, Lower 48 hubs shed value across the 2024 strip, illustrating the prevailing bearish sentiment as weather-driven demand has largely missed the mark this heating season.
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Recent forecasts suggested a reprieve from exceptionally bearish weather could arrive mid-month. However, whether the pattern shift would serve up enough demand to rescue flagging prices remained an open question.
“The pattern will transition away from the anomalously warm conditions of the near term, but with the Midwest retaining above and much above normal coverage into the early half of the six- to 10-day period,” Maxar’s Weather Desk said in an updated forecast Thursday. “Otherwise, expectations are for a cooling pattern, with the emergence of below normal temperatures at times in the South and late along the East Coast.”
The updated 11- to 15-day outlook showed warmer trends for the Midwest but continued to advertise below normal conditions across the South and the East Coast, according to the forecaster.
However, Maxar noted that “the split flow typical of the strong El Niño continues to limit the intensity of cold in this forecast.”
Northeast Basis Strengthens
Even as prices generally drifted lower overall, Mid-Atlantic and Northeast locations saw incremental basis strengthening along the curve, including for 2025, Forward Look data for the Feb. 1-7 trading period show.
Cove Point basis, for example, surged 26.8 cents higher for January 2025, ending at plus-$2.058, with the hub also posting basis gains across the 2025 strip.
Tenn Zone 6 200L added 17.8 cents for January 2025 to reach plus-$8.858.
Farther upstream in Appalachia, basis ticked higher for 2024 contracts and for the 2025 injection season.
Millennium East Pool finished at an 88.3-cent discount to Henry Hub for July 2025, a 10.0-cent gain week/week. Eastern Gas South also picked up 10.0 cents for July 2025 to end at a 94.5-cent discount to the Henry.
In the nearer term, Eastern Gas South March 2024 basis narrowed by 6.6 cents to minus-48.8 cents, according to Forward Look.
Analysts at ClearView Energy Partners LLC recently said their modeling points to a narrowing differential between Eastern Gas South and Henry Hub year/year in 2024.
“We anticipate Appalachian gas pipeline takeaway capacity rising around 2.8 Bcf/d this year, well ahead of dry gas production growth in the region year/year,” the ClearView analysts said.
ClearView’s modeling suggests a “relatively strong correlation” between spare takeaway capacity out of Appalachia and Eastern Gas South basis differentials.
The startup of the 2 million Dth/d Mountain Valley Pipeline (MVP) accounts for most of the anticipated increase in Appalachian takeaway capacity in 2024, according to the firm.
Still, apparent constraints downstream of the project, as noted recently by the International Energy Agency (IEA), could affect capacity usage rates, the ClearView analysts said.
The IEA in its Gas Market Report for 1Q2024 said it sees the downstream constraints “weakening the debottlenecking effect on Appalachian production.”
Meanwhile, the Permian Basin and the Haynesville Shale should continue to lead production growth in the United States, according to IEA.
“However, the delay in bringing online the first train of the Golden Pass liquefaction project from 2024 to 2025 is set to soften production growth in southern basins close to the coast,” the agency said. “Overall, U.S. dry gas production growth is set to slow to below 2% in 2024.”
Will Producers Respond To Sub-$2?
With the front of the curve recently dipping below $2, the market is pressuring producers to pull back, Tudor, Pickering, Holt & Co. (TPH) analyst Jake Roberts said in a note.
“While we’ve yet to hear any desire to curtail volumes from coverage, that dynamic may become topical through earnings at current spot prices,” Roberts said. “In our view, producers should likely be looking at activity reductions across all of 2024 given the current strip outlook.”
TPH had been leaning toward “completion deferrals as the first salvo from the industry,” but given the extent of recent downward pressure on prices, “it could be we need to see more structural cuts from rig programs in 2024 to better balance the market as a setup to a constructive 2025,” Roberts said.
After an unseasonably light 75 Bcf withdrawal for the week ended Feb. 2, Lower 48 storage stood at 2,584 Bcf, with the surplus to the five-year average ballooning from 130 Bcf back up to 248 Bcf.
EBW Analytics Group analyst Eli Rubin said in a recent note the firm was modeling an October 2024 peak of 4,100 Bcf in storage.
“Although this continues to suggest bearish fundamental pressure ahead, the roughly 200 Bcf of projected oversupply is approaching the range where a severe late-winter cold spell” or producers cutting back on 2024 production guidance “could help draw the market into balance,” Rubin said.
Recent sub-$2 pricing is “forcing producers to at least reconsider the 2024 production cadence,” though “a late-winter cold stretch could prompt a modest short-covering rally at the front of the curve,” according to Rubin.
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