LNG

Security costs rather than freight fundamentals are increasingly determining LNG shipping economics. Owners face "between 6 and 10 million dollars for every single shipment" before vessels enter the Strait of Hormuz, simply to secure additional insurance cover, said Tom Beney, Senior Vice President of Ocean Freight at StoneX.

Fracking in the Permian Basin has staged a record 11% annual rise in gas production, adding 2.7 bcf/d to reach 27.7 bcf/d, suppored by break-even prices as low as $61 per barrel in the Midland Basin, one of the Permian's largest oil and associated gas formations.

US LNG outperforms coal in economic terms and carbon intensity when evaluated over its full lifecycle for power generation. Two-thirds of US LNG originates from Haynesville and Northeast basins, where drier gas production with less associated liquids create more favourable emission profiles, Wood Mackenzie finds.

The EU is paying a premium price for LNG as pipeline gas imports fell 9% in the first half of this year. LNG imports cost around 26.9 billion Euros over the same period, with 13.7 billion Euros of that paid for US cargoes.

Economics of gas production in the Appalachian Basin will become more favourable by 2030 as LNG-related demand soars. Natural gas liquefied for export could more than double to 9.8 Tcf, or almost 27 bcf/d, in 2037.

Shortfalls in Australia’s East Coast gas markets force regulators to make tough choices. Price caps, while offering short-term consumer relief, risk to undermine project economics and deter investment in future supply.

“Recent exemptions have effectively set a floor price as market participants anchor prices to the cap, making the market less responsive to supply-demand signals,” said Daniel Toleman, Wood Mackenzie’s research director of global LNG.

Export diversion is another option to help boost domestic supply but risks damaging Australia’s reputation as a reliable LNG supplier. “Queensland LNG projects were approved without domestic obligations and rely on long-term contracts,” Toleman said, explaining: “Diverting exports would require major infrastructure upgrades, as southern markets face the brunt of the shortfall.”

Imports 'commercially challenging'

Importing LNG through floating storage and regasification units (FSRUs) is “technically feasible but commercially challenging,” analysts warn. Global demand for FSRUs has surged since the Russia-Ukraine conflict, making units scarce and costly. The government may need to underwrite the commercial risk of such infrastructure.

Moreover, importing LNG would expose Australia to volatile global prices. Domestic gas prices would align with international LNG costs plus regasification and transport charges — potentially far exceeding current netback pricing.

Analysts pledge investors to come forward. Unlocking new domestic gas supply is the most effective way to reduce emissions and lower energy prices in Australia, Wood Mackenzie argues. But this would require a shift in government policy and a willingness to make politically difficult decisions.

Southeast Asia is expected to become a net LNG importer by 2032, with demand set to soar approximately 182% over the next decade. Wood Mackenzie forecasts the region’s gas demand will outpace both oil and coal, particularly in Malaysia, Thailand, the Philippines and Vietnam.

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.