Production increased by 5.3 Bcf/d compared with 2024, according to the EIA’s latest Natural Gas Monthly. Three regions — Appalachia, Permian and Haynesville — accounted for 67 per cent of total U.S. marketed gas production and 81 per cent of the growth last year.

Higher natural gas prices helped support drilling activity. The Henry Hub benchmark price rose about 60 per cent in 2025 to US$3.52 per million British thermal units (MMBtu), improving the economics of production across multiple basins.

The Appalachian Basin in the northeastern United States remained the country’s largest natural gas producing region, accounting for 36.6 Bcf/d, or roughly 31 per cent of total U.S. marketed production.

Production growth there has slowed in recent years because of limited pipeline capacity to move gas to markets. However, additional capacity began coming online in 2024 when the Mountain Valley Pipeline was authorized to start operating. Combined with higher gas prices, that helped push Appalachian production up by 1.1 Bcf/d in 2025, compared with only modest growth in 2024.

The Permian Basin in Texas and New Mexico continued to play a major role in U.S. gas growth. Production in the region rose 11 per cent, or 2.7 Bcf/d, reaching an average of 27.7 Bcf/d in 2025.

Much of the natural gas produced in the Permian is associated gas, meaning it is generated as a by-product of oil production. Even though benchmark West Texas Intermediate crude prices declined from US$77 per barrel in 2024 to about US$65 in 2025, prices remained high enough to support oil-directed drilling.

Industry surveys suggest the basin remains economically viable at those levels, with breakeven prices estimated around US$61 per barrel in the Midland Basin and US$62 in the Delaware Basin.

Another factor contributing to higher gas production in the Permian is the region’s rising gas-to-oil ratio, meaning wells are producing more natural gas relative to oil over time.

The Haynesville shale, which spans Louisiana and Texas, also contributed to production growth. Output there averaged 14.9 Bcf/d in 2025, about four per cent higher than in 2024.

Haynesville wells are typically much deeper — between 10,500 and 13,500 feet — than wells in the Appalachian Basin, which generally range from 4,000 to 8,500 feet. The greater depth increases drilling costs, but the basin’s location provides an important advantage.

Haynesville sits close to liquefied natural gas export terminals and large industrial natural gas consumers along the U.S. Gulf Coast, making it an attractive supply source for both domestic and export markets.

The EIA expects U.S. natural gas production to continue growing in the coming years as additional infrastructure and export demand support drilling activity. Expansion of LNG export capacity along the Gulf Coast is expected to play a key role in shaping future natural gas markets.

The United States has been the world’s largest producer of natural gas for more than a decade, largely because of the expansion of shale gas production since the mid-2000s.

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March 2024 ended with 744 billion cubic feet (Bcf) of natural gas in storage in Canada; 44 per cent higher than the end of March last year, and 55 per cent above the average of the last 5 years. Natural gas storage levels are relatively high entering spring this year for two main reasons:

1. a mild winter
2. high natural gas production

Natural gas storage balances supply and demand of natural gas. Typically, gas is withdrawn from storage in winter when natural gas heating demand is high and injected into storage in spring, summer, and fall when heating demand is lower. This winter was characterized by a strong El Niño⁽¹⁾, which meant warmer temperatures during the season than is average. Homes and businesses needed less natural gas for heating, so less natural gas was withdrawn from storage.

Canada, typically in the spring, summer, and fall, produces more natural gas than it uses domestically. Any excess gas is either exported or stored. Market participants such as gas distributors and utilities will store some of this excess gas in the summer to prepare supply for their customers in the following winter. Producers, traders, or marketers might store gas in the summer hoping to sell it to distributors, power generators, or other consumers during the winter, when demand and prices are higher. By shifting this excess supply away from periods of lower demand and toward periods of higher demand, storage helps balance gas markets and reduces price volatility for both producers and consumers. Storage can also form an emergency reserve in the event of natural disasters or other disruptions to gas supply.

Exports of natural gas flow on pipelines and from LNG (liquefied natural gas) export facilities. Pipelines that export natural gas from the Western Canada Sedimentary Basin (WCSB) have been running near full capacity for the past few years⁽⁴⁾. Key export points for the WCSB include the East Gate and West Gate on NGTL, the Huntington point on the Westcoast/Enbridge BC pipeline, and Elmore on the Alliance pipeline.⁽⁵⁾ To address this, the market has increased export capacity by expanding some pipelines⁽⁶⁾ regulated by the Canada Energy Regulator. This has relieved some bottlenecks, though constraints may still happen during the spring, summer, and fall, when major pipelines undergo maintenance, increasing the importance of access to storage. LNG exports are expected to rise with the start of new commercial operations of LNG Canada in 2025⁽⁷⁾ and potential expansions or new LNG terminals in British Columbia⁽⁸⁾.

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Global LNG demand is showing increasing seasonality, and peak potential LNG production in Argentina during the summer months coincides with strong winter demand from utilities in Asia. This seasonal dynamic could attract Asian buyers and present a strong economic case for Argentinian LNG.

“Argentina’s LNG could be interesting to players who want to diversify supply outside North America,” said Mauro Chavez Rodriguez, principal analyst, Latin America Gas & LNG. “The seasonality of its output could be also seen as a virtue for Asian utilities that are looking to contract just for their peaking demand months in the northern hemisphere.

In addition, Argentinian LNG liquefaction plants have lower shipping costs to reach Asian markets than US Gulf Coast facilities, avoiding potential Panama Canal congestions and presenting an overall cheaper alternative to US exports.

Supported by the Vaca Muerta, Argentina’s production in the Neuquén basin will ramp up over the next few years, with major scale LNG production expected to begin in 2024. Based on the new research, Wood Mackenzie says it anticipates that LNG production volumes could potentially reach 6 million tonnes per annum (mmtpa) in that year, which could then grow to 10 mmtpa by 2030.

“Some Asian players are already active in the Argentinian shale,” said Rodriguez. “Petronas is participating with YPF in the joint venture of La Amarga Chica, while CNOOC participates indirectly through its subsidiary, Pan American Energy, in the Aguada Pichana Oeste. Meanwhile, Qatar Petroleum recently has shown interest in Argentina, buying a stake of ExxonMobil’s business unit in that country, and also partnering for exploration offshore.”

Rodriguez added that Asian investors may also become players in major midstream infrastructure, including gas processing plants, pipelines, petrochemicals and LNG export plants.

Speaking at Gastech in Houston, Rodriguez said “Vaca Muerta’s gas production has dramatically changed the outlook for Argentinian gas. It is already bringing cheap gas for local industry and also supporting the construction of new major gas pipelines.

Associated gas from Vaca Muerta will also represent 15 per cent of Argentina gas production by 2024, and other projects in the condensate and dry gas window with breakevens below US$3 per million British thermal units (mmbtu) will enter into full development in the upcoming years.

A lack of underground natural gas storage facilities close to demand centres in Argentina means that gas flow to potential LNG export terminals will also be seasonal.

Despite other price challenges posed by the seasonal utilization of LNG plants, Wood Mackenzie says it estimates breakevens for Argentina LNG of US$8/mmbtu at delivery ex. ship for Japan.

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