LNG

Bearish shoulder-season fundamentals have made prompt gas prices at Henry Hub fall to their lowest level in five months at just above $3/MMBtu. Appalachia production stayed robust, despite seasonal maintenance, while Haynesville basin output is set to rise by 1 bcf/d year-on-year, weighing on prompt prices.

Fundamentals are largely influencing price discovery at Henry Hub, the most liquid gas trading point in the United States.

Modelling by Energy Aspects indicates that gas production in the Lower 48 States exceeded 107 bcf/d over the past weekend, with gas flows from the Appalachia Basin remaining strong despite maintenance activities and lower regional consumption. Appalachia production notched up 0.3 bcf/d and averaged 34 bcf/d, offsetting the decline in associated gas production from the Permian Basin caused by maintenance on the Permian Highway pipeline which lowered flows by 0.9 bcf/d over the past few days.

Profitable regional economics – despite Henry Hub’s recent selloff – has led to robust Appalachia production in March and April. According to US government figures, regional flows averaged 33.5 bcf/d in March and 33.9 bcf/d in April, up from 32.8 bcf/d over the previous two months. Maintenance works since early March seem to have a "minimal effect on flows," analysts noted.

Appalachia gas volumes, in fact, reached a higher baseline and higher flows. The latest surge in production comes from MarkWest Liberty Midstream and DT Midstream, as per pipeline data.

Energy Aspect’s fundamental outlook for the remainder of the shoulder season is for the year-on-year storage gap to close considerably in the second quarter of 2025, with an estimated injection of 342 bcf for April and 438 bcf for May. Rising upstream gas supply would increase Lower 48 storage levels to about 2.60 trillion cubic feet, still 284 bcf lower year-on-year.

Haynesville flows stay tepid

Gas flows from the Haynesville basin, in contrast, stay subdued as producers were cautiously slow to respond to higher price at the start of the year. As of 17 April, the Haynesville rig count stands at 31 rigs, three rigs lower year-on-year.

Energy Aspects anticipates a modest increase in rig activity by the third quarter of 2025, averaging 33 rigs, two rigs higher quarter-on-quarter. This expectation is based on recent producer guidance indicating production growth for winter 2025–26 to support weather-induced demand and LNG feedgas expansion. Core Haynesville activity in Louisiana will likely contribute most of this growth, reaching 27 rigs by December, nine rigs higher than current levels.

Upstream investment drives further growth: Comstock in its Q4-24 earnings call announced plans to spend $130–150 million on Western Haynesville infrastructure in 2025. Funding will come from their partner, Quantum Capital Solutions. Comstock said it will operate four rigs in Western Haynesville in 2025 on average and intends to drill 20 further wells in the near future.

Aethon Energy, another major producer in Western Haynesville, earlier this year announced it would need Henry Hub prices to reach $5/MMBtu to incentivise investment to grow output. Analysts estimate the company’s rig count in Texas Haynesville will reach seven rigs by December, six rigs below current levels.

LNG export exposure

Latest US government data indicates Western Haynesville production reached 0.71 bcf/d in February, with Comstock averaging 0.32 bcf/d (45% of sub-basin production). Currently, Haynesville's production averages 11.5 bcf/d month-to-date, 0.1 bcf/d lower month-on-month.

“Yet, incremental production from new activity remains elusive due to producer discipline,” analysts commented.

Expand Energy announced estimates that its Q1 25 Haynesville production will average 2.6 bcf/d, some 0.2 bcf/d higher quarter-on-quarter, while operating seven regional rigs, one less than the first quarter. The company’s Haynesville portfolio has approximately 2 bcf/d of exposure to LNG export facilities, with an additional 2.5 bcf/d in deliverability expected by the end of 2025, including 1 bcf/d of Gillis volumes that will come to market via the new NG3 pipeline.

Scepticism abounds as to whether US LNG exports projects will gain traction following President Trump’s executive order to resume approvals for LNG exports to non-FTA countries. Analysts see this move as a “reshuffling” of which pre-FID projects are most likely to be sanctioned – not as an actual change to the number of FIDs.

“US LNG projects compete in a global market, and each additional FID draws on additional, higher-cost supplies, eroding their economic competitiveness,” commented Rystad Energy’s senior vice president, Oil & Gas Research, Amber McCullagh.

To-date, American LNG projects largely rely on feedgas from the Haynesville shale, where the remaining Tier 1 inventory is limited and ownership of acreage is increasingly consolidated among the largest operators. Appalachia shale, in contrast, is home to the most untapped gas reserves – but moving these molecules to the coast for liquefaction and export is deemed “prohibitively expensive.”

“Trump is likely to push for permitting reforms, but such changes would require an act of Congress, which saw some bipartisan interest in the last session,” she noted, indicating the actual revision or withdrawal of former President Biden’s pause on approving non-FTA export licenses will be limited. Biden’s action halted momentum on several projects that had previously been close to taking final investment decision which sparked fierce criticism from the industry.

Outlook of gas-fired generation uncertain

Regardless of Trump’s rush to declare a ‘National Energy Emergency’ on his first day in office, analysts caution the President’s “drill, baby, drill” mantra overestimates the industry’s willingness to prioritize growth over investor returns in light of Tier 1 inventory depletion in core oil basins after 2030.

Speeding up permitting on federal land may incentivise some operators to produce more oil and gas, though volume growth is expected to be marginal and mostly used as feedgas for LNG export projects. Gas-fired power generation, on the other hand, may not benefit much as domestic gas prices are unlikely to recede sufficiently to make burning gas more competitive than unabated coal in some areas, let alone renewables.

“Trump signalled he would block new offshore wind leases, but these are unlikely to meaningfully impact the US generation mix,” McCullgah commented, adding: “Removing subsidies for wind and solar generation would have a more significant impact, but such a move would also require Congressional approval, and Republicans’ margins are very small in the House of Representatives.”

Nontheless, momentum in gas-fired generation is already in place, so rising domestic fossil fuel demand is likely – especially since utilities struggle to meet rising electricity demand from data centers and e-vehicles, and are hard pressed to provide sufficient dispatchable generation for balancing power.

US natural gas production in the Mid-Atlantic and Ohio region from the Marcellus and Utica shale basins is continuing to grow, resulting in adequate domestic supplies being available in the northern region and feed-gas been transported south for LNG plants on the Gulf Coast.

US liquefied natural gas exports decreased in the past week to six shipments, four from Sabine Pass in Louisiana, one from Cove Point in Maryland and one from Corpus Christi in Texas, compared with eight the previous week, while two vessels were lifting cargoes at Sabine Pass through January 24.

LNG shipments fell as domestic natural gas demand increased over the holiday weekend and the start of the week, according to a report from the Energy Information Administration.

The average total supply of natural gas declined by 1 percent compared with the previous week and net imports from Canada dropped by 6 percent from last week as pipeline exports to Mexico rose by 1 percent.

“Total US consumption of natural gas rose by 4 percent compared with the previous week,” said the EIA.

“In the residential and commercial sectors, consumption increased by 8 percent as cold temperatures spurred heating demand,” it added.

“Natural gas consumed for power generation was flat, averaging 25.3 billion cubic feet per day,” stated the report.

Spot prices fell at most locations with the Henry Hub dropping from $3.61 per million British thermal units to $3.10 per MMBtu.

“Net withdrawals from working gas totaled 163 Bcf for the week. Working natural gas stocks are 2,370 Bcf, which is 1 percent more than the year-ago level and 11 percent lower than the five-year (2014-2018) average for this week,” said the EIA.

“Prices at the Algonquin Citygate, which serves Boston-area consumers, were volatile amid stretches of cold temperatures. Prices went down $7.85 from $11.38 per MMBtu on January 16 to $3.53/MMBtu,” added the report.

“At the Transcontinental Pipeline Zone 6 trading point for New York City, prices decreased $1.06 from $4.04 per MMBtu to $2.98 per MMBtu,” it said.

The EIA said that shale-gas prices in Appalachia fell as temperatures increased and takeaway capacity was restricted.

The Tennessee Zone 4 Marcellus spot prices decreased 67 cents from $3.43 per MMBtu on January 16 to $2.76 per MMBtu.

“Prices at Dominion South in southwest Pennsylvania fell 70 cents from $3.42 per MMBtu to $2.72 per MMBtu,” said the report.

“A combination of factors likely affected prices in the region. As in New England and New York City, cold temperatures throughout the Northeast over the long weekend receded, reducing heating demand,” it added.

“Prices west of the Rockies also decreased as a winter storm that brought snow to the mountains of Southern California moved out of the area,” according to the EIA.

Prices at the Pacific Gas & Electric Citygate in Northern California fell $1.02 per MMBtu to $3.60 per MMBtu.

Southwest and Texas prices were also lower. At the Waha Hub in West Texas, which is located near Permian Basin production activities, prices averaged $2.29 per MMBtu, $1.32 per MMBtu lower than Henry Hub prices.

U.S. shale gas developer eagerly await new Appalachian takeaway capacity to come online so the region can provide the bulk of 2018’s dry production growth. Delays of the $4.3-billion Rover Phase-2 pipeline project impact on the anticipated 4.0 bcf/d gains in shale gas output from the Appalachia region.