LNG buyers are signing long-term supply contracts at an unprecedented clip, and those contracts are increasingly being linked to U.S. natural gas benchmarks such as Henry Hub, according to NGI Senior LNG Editor Jamison Cocklin.
Last year “was a record year” for the signing of these contracts, Cocklin said during a joint webinar with experts from NGI and the London Stock Exchange Group plc (LSEG). “Buyers sought cover from volatility on the spot market, and this was a marked shift from previous years,” he explained.
Global supply concerns triggered by Russia’s invasion of Ukraine caused a spike in prices and volatility, incentivizing long-term contracts linked to relatively cheap U.S. pricing.
Buyers across the world signed up for about 77 million metric tons/year (mmty) of liquefied natural gas supply last year, up from 51 mmty in 2021, Cocklin said, citing data from Cheniere Energy Inc.
Henry Hub-indexed deals drove much of the contracting activity, accounting for 70% of all the supply deals signed globally last year. “And those are largely U.S. projects,” Cocklin said.
This year, meanwhile, about 26 mmty of Henry Hub-linked offtake agreements have been signed as well, “and there’s still a lot of momentum in the market and a lot of contracting that’s still going on,” he added. “And I would say too that the conflict in Israel has really reinforced the supply security that these projects in North America offer.”
Cocklin noted that, “All the term contracts that have been signed have helped projects advance in North America and elsewhere.”
There are nearly 30 Bcf/d of liquefaction projects either under construction or operating in North America, according to NGI’S North American LNG Project Tracker.
While increased LNG exports bring the potential for more volatility in U.S. pricing, the market so far seems to think that U.S. production can keep up with increasing demand as more export terminals come online in the years ahead, Cocklin said.
He cited NGI Forward Curve prices, which show Henry Hub topping out around $5/MMBtu during the winter months from 2026 onward.
At a regional level though, the strip shows higher winter price spikes closer to $7 or $8 at locations such as SoCal Border and Cove Point. In the case of SoCal Border, the perception is that planned LNG projects on Mexico’s Pacific Coast will pull gas from the already constrained Western U.S. gas market, namely California.
In the case of Cove Point, “that’s more influenced by Transco Zone 5 prices…which can certainly spike in the winter, but LNG is a factor too,” Cocklin said.
Mexico, for its part, is poised to break onto the scene as an LNG supplier, namely to the Asia-Pacific market.
NGI’s Christopher Lenton, senior editor for Mexico and Latin America, described the market dynamics that are boosting Mexico’s profile as a potential exporter of the fuel.
More than 6 Bcf/d of liquefaction projects are in varying stages of development in Mexico, with developers planning to re-export feed gas sourced via pipeline from the Permian Basin.
Of these projects, Sempra’s Energía Costa Azul (ECA) Phase 1 (0.4 Bcf/d) and New Fortress Energy Inc.’s Altamira FLNG (0.2 Bcf/d) are the only ones under construction.
ECA is on the West Coast, which would allow Permian gas to bypass the Panama Canal and more easily reach fast-growing demand in the Asia Pacific region.
Asia is expected to account for 80% of global LNG demand growth from 2023-2030, said LSEG’s Olumide Ajayi, who shared the virtual stage with Cocklin and Lenton. China alone is expected to account for 29% of the total, he said.
Other LNG projects proposed for Mexico’s Pacific Coast include the 1.8 Bcf/d Saguaro Energía and 0.5 Bcf/d Vista Pacifico.
