In August 2024, Mexico shipped its first cargo of liquefied natural gas. New Fortress Energy produced it aboard a floating liquefaction vessel off Altamira, in Tamaulipas, and sent it through the Panama Canal to Mexico's own import terminal in Baja California Sur. The unit can liquefy up to 0.199 billion cubic feet a day of gas. A second identical unit is under construction, and on the Pacific coast Sempra is building the 0.4 Bcf/d first phase of Energía Costa Azul at the site of an existing import terminal.
Mexico is now formally an LNG exporter. But the gas it liquefies is not Mexican. It arrives by pipeline from the United States. That simple fact shapes everything about how Mexican LNG should be understood: as an extension of the US export system, with its own advantages and its own regulatory dependence on Washington.
Pipeline gas in, LNG out
The US Energy Information Administration describes the supply chain plainly. Fast LNG Altamira's units are fed by US gas delivered through the Sur de Texas-Tuxpan pipeline. Energía Costa Azul will be supplied with gas from the Permian Basin. Because the feed gas is American, LNG exports from these projects require approval from the US Department of Energy. DOE has authorised 0.43 Bcf/d of exports from Fast LNG Altamira to countries with which the United States has a free trade agreement, and the developer has requested authorisation for 0.4 Bcf/d of exports to non-FTA countries.
That non-FTA authorisation matters. Most of the world's large LNG buyers, including Japan, China and the European Union, do not have free trade agreements with the United States. In January 2024 the Biden administration paused new non-FTA export approvals pending a review of how they are assessed. Projects that rely on US gas, wherever their terminals sit, are caught by that pause.
Why build in Mexico at all
The case for Mexican terminals rests on geography. A terminal on Mexico's Pacific coast, such as Energía Costa Azul, can ship to Asia without crossing the Panama Canal, cutting voyage times to Japan, South Korea and China substantially compared with US Gulf Coast terminals. During the 2023 Panama drought, when canal slots were rationed, that advantage became concrete.
The east coast project at Altamira has a different rationale. Floating liquefaction can be installed relatively quickly, close to existing pipeline infrastructure, without the long build of an onshore terminal. New Fortress uses it partly to supply its own import terminals, as the first cargo to Baja California Sur shows.
Developers have proposed several more west coast projects: Saguaro Energía LNG at 2.0 Bcf/d, Amigo LNG at 1.0 Bcf/d, Gato Negro at 0.6 Bcf/d, Salina Cruz at 0.4 Bcf/d and Vista Pacífico at 0.5 Bcf/d, for a combined 4.5 Bcf/d. None has yet taken a final investment decision.
The North American picture
The EIA expects North American LNG export capacity to more than double from 11.4 Bcf/d in 2023 to 24.4 Bcf/d in 2028, if projects under construction start on schedule. Mexico's share of the growth is modest: 0.8 Bcf/d, against 2.5 Bcf/d in Canada and 9.7 Bcf/d in the United States. In Canada, LNG Canada plans to start exports from its first train in summer 2025, with Woodfibre LNG targeting 2027.
So Mexico will remain a small part of North American LNG supply for the rest of the decade. Its importance is not volume but optionality: a Pacific outlet for US gas that does not depend on Panama, and a way for US gas to reach Asian buyers on shorter routes.
There is a logic to that division. Canada's west coast projects use Canadian gas from British Columbia and Alberta, and they add genuinely new supply to world markets. US projects on the Gulf Coast add supply from the largest producing country in the world. Mexican projects mostly redistribute US supply to a more convenient coastline. They compete with US Gulf Coast terminals for the same molecules and the same buyers, and they win when route length or canal risk matters most.
What Mexico gets
For Mexico itself, the benefits are indirect. The country already depends heavily on US pipeline imports for its own gas needs. US gas exports, mostly by pipeline to Mexico, reached a record 6.2 Bcf/d in 2023, 8 per cent more than in 2022, and gas made up 13 per cent of the value of US energy exports to Mexico that year. LNG terminals add investment, port activity and some tax revenue, but they do not change Mexico's dependence on its northern neighbour for gas.
There is a policy tension here. Mexican governments have emphasised energy sovereignty and a larger role for state companies Pemex and CFE. LNG export projects built by private and foreign developers, using US gas, sit uneasily with that framing. CFE has interests in some of the proposed projects, which helps with political support, but the projects' economics depend on US supply and US regulatory approval.
Risks to the model
The model has three main risks. The first is regulatory: US approval of non-FTA exports can be delayed or reconsidered, as the 2024 pause showed. The second is supply: Mexican LNG depends on pipeline capacity from Texas, and any disruption on the US side would stop exports. The third is political: a change in US-Mexico relations, on trade or other issues, could affect the willingness of either side to support cross-border gas exports.
Against those risks, the developers can point to strong demand from Asian buyers looking for diversified supply and shorter routes, and to the continuing growth of low-cost US gas production.
A gate, not a well
Mexican LNG is best thought of as an additional gate for US gas into world markets. The first cargo from Altamira was a milestone for New Fortress and for Mexico's energy sector. It does not make Mexico a gas producer of global significance. It makes Mexico's coastline part of the US export system, with the same regulatory exposure and the same reliance on Permian and Eagle Ford supply.
If the west coast projects are built, they will offer Asian buyers a faster route to North American gas. Whether they are built depends less on Mexico City than on Washington.