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Evolution - How LNG Exports Came to Dominate U.S. Natural Gas, and Where the Market is Heading

Tuesday, 09/23/2025Published by: Jason Lindquist

Link to full article:  https://rbnenergy.com/evolution-how-lng-exports-came-to-dominate-us...

Ten years ago, U.S. exports of natural gas in the form of LNG were a footnote in the market. But that all changed in 2016. In February of that year, the first shipment of LNG from the Lower 48 states set sail when the vessel Asia Vision departed from Cheniere Energy's Sabine Pass export terminal in Louisiana. This was the culmination of a remarkable turnaround, not only at Sabine Pass, but for the U.S. natural gas market as a whole. Eight years earlier, Sabine Pass had been completed as an import terminal, as it was projected that the U.S. would face significant shortages of natural gas supplies. Shale turned that business model on its head. 

U.S. LNG exports also reshaped global trade patterns. Before U.S.-sourced cargoes hit the market, most LNG shipments were locked into destination-specific contracts, requiring delivery to a designated port. In addition, buyers were largely limited to long-term supply deals priced off crude oil through rigid formulas. The emergence of flexible, Henry Hub-linked pricing broke that mold, giving buyers new negotiating leverage and fostering a more liquid, globally interconnected LNG market.

Today’s RBN blog is the first in a multi-part series that will trace the rise of U.S. LNG exports, examine their influence on the global gas trade, and take a closer look at the quirky mechanics of LNG pricing.

History of U.S. Natural Gas Exports

U.S. pipeline exports of natural gas have been around for a long time, with small volumes moving to Canada and Mexico since the 1950s. There was nothing unusual about these cross-border pipeline flows. Growing supplies of U.S. gas in the 1960s, ’70s and ’80s were able to meet increasing demand in the two neighboring countries with some relatively modest investment in gas pipeline infrastructure. By the early 1970s, about 1 Bcf/d of U.S. gas was flowing to Mexico and Canada.

There was another source of U.S. natural gas that did not have access to the North American gas pipeline grid. That was Alaska. The development of oil production from Alaska’s North Slope in the early 1970s provided an important new source of U.S. crude oil, which also came with significant volumes of associated natural gas. But there was no pipeline network to take that gas, and miniscule local demand. However, there was an alternative disposition — a relatively new technology at the time that would super-cool the natural gas down to the point where it would liquify, reducing its volume by 1/600th (see Figure 1 below), making it possible to transport the natural gas on specially designed ships to distant markets, such as Asia.

Alaska’s Kenai Peninsula LNG Plant south of Anchorage began operations in 1969. It was the first LNG export facility in the U.S., coming online almost 50 years before Cheniere’s Lake Charles facility. And for decades, it shipped small volumes of LNG, averaging about 200 MMcf/d, mostly to Japan.

Unfortunately, the process of super-cooling natural gas to negative 260° Fahrenheit, where it liquifies, is a capital-intensive and very expensive process. Over the next 40 years, LNG facilities around the globe were developed only in producing areas that had limited local markets for the natural gas — including the Middle East, Australia and north Africa. As Alaskan oil and gas production declined in the 2000s and 2010s, the economics for production of LNG in Alaska ultimately deteriorated to the point that Kenai was permanently shut down in 2016, not coincidentally the same month that Cheniere’s Lake Charles LNG export facility came online. (Earlier this year, Harvest Alaska agreed to buy Kenai and repurpose it to be a regasification terminal.)

During the 40 years when Kenai exports were flowing, natural gas production in the Lower 48 was remarkably stable. From 1967 through 2007, gas production averaged 51 Bcf/d (see bracketed section of black line in Figure 2 below), never getting higher than 59 Bcf/d nor lower than 43 Bcf/d. That is not to say the U.S. gas market was not changing. In fact, the geography of natural gas production made a huge shift from offshore and Louisiana production to Rocky Mountain production, as older wells declined and producers discovered new plays in Colorado and Wyoming. But in total, volume growth was stagnant until the shale production surge (right end of black line) kicked in during the mid-to-late 2000s.

During the decades, there was some demand growth, with most of that being satisfied by imports from Canada, which was enjoying some solid production increases. U.S. net imports from Canada ramped up from 2.5 Bcf/d in 1985 to 9 Bcf/d in 2006, completely overshadowing the small U.S. export volumes to Canada.

Gas and LNG Exports: The Same, but Radically Different

By the time the Shale Revolution arrived, the pipeline export market was dominated by Mexico, whose power generation market seemed to have an insatiable need for additional U.S. gas supplies. From only 0.9 Bcf/d in 2006, U.S.-to-Mexico exports were up to 6.1 Bcf/d by 2023 (line with blue circles in Figure 3 below), with almost all of that volume coming from the Permian and Eagle Ford basins. These exports to Mexico move via pipeline essentially in the same way volumes move within the Lower 48 gas grid, with similar transportation costs and pricing mechanisms.

In contrast, LNG exports are a completely different world, literally. Following the startup of Cheniere’s Sabine Pass terminal, another six terminals were built, along with expansions of Sabine Pass. From zero LNG exports in 2016, outbound volumes (line with gray boxes) climbed to 6.5 Bcf/d in 2020, then to 12 Bcf/d in 2023-24, blasting past pipeline exports to Mexico.

To export natural gas as LNG, it must first be transported as a gas by pipeline to an LNG export facility. There, it is supercooled to its liquefaction temperature before being loaded onto ships as a liquid. These ships then transport the LNG to overseas markets, where it is regasified — meaning heating the LNG so that it evaporates back into natural gas’ vapor state. Together the cost of this process is about $3/MMBtu, sometimes well above the cost of the U.S. natural gas itself. The economics only work because the price of natural gas in the global marketplace over the past decade has averaged 3.5 times the price of natural gas in the U.S., sometimes getting to as much as 10 times U.S. gas. Consequently, the profit for each cargo of LNG transported from the U.S. to international markets is far above pipeline gas markets in North America.

As natural gas export flows have increased, the U.S. natural gas market has transformed from an isolated entity, disconnected from global markets, into a crucial component of global natural gas supply and demand. As illustrated in Figure 4 below, exports (teal bar segments) comprised just 6% of production in 2016, rising to 21% by 2023-24, with further growth anticipated as additional LNG export capacity becomes operational.

But there is a potential gotcha, and it’s a big one. The low cost of U.S. natural gas, which has been a huge benefit for homeowners, businesses, industrial operations and power generation, hasn’t risen to match the prices paid in other parts of the world for a simple reason: the U.S. lacks sufficient LNG export capacity. Most likely, if export capacity was unconstrained, the price gap between U.S. and global markets would narrow, converging around the cost of liquefying and transporting U.S. gas overseas. This hasn’t occurred yet due to the current limitations in export capacity. But if more capacity were available, U.S. prices could be expected to rise, global prices would fall, or most likely both would adjust to narrow the differential between them.

In the next installment of this series, we’ll examine how U.S. export pricing mechanisms have evolved over time and how those shifts have influenced global markets.