Argentina's LNG Bet

21/09/2026

Javier Milei’s government in Argentina is progressing on its ambitions to transform shale gas reserves in the Vaca Muerta region and enable state-owned energy companies to tap into the lucrative world of LNG exports. The country shipped its first LNG cargo in 2019, a mere 30,000 m³ (0.0135 Mtpa). Over the past 6 years, significant political and economic incentives mean that current projects now envisage a combined capacity of 17.95 Mtpa by the early 2030s. Turning that capacity into dependable exports could transform Vaca Muerta’s gas economics and create a substantial source of dollar earnings for the resource-laden economy.

Spread across Argentina’s Neuquén Basin, the Vaca Muerta shale formation is the most productive unconventional play outside North America. The EIA estimates technically recoverable resources of approximately 320bn MMBtu of gas and 16bn bbl of oil and condensate. These are resources, rather than proved commercial reserves. Argentine oil production hit an all-time record of 915,000 bbl/d in July 2026, unconventional output (from shale) reached 71% of the national total, and energy exports posted a record surplus of $7.8bn in 2025, and most recently, the 437 km ‘Vaca Muerta Oil Sur’ (VMOS) pipeline to the Atlantic reached fit-for-service status in late June 2026, with an initial start-up capacity of 180,000 bbl/d and first export cargos scheduled for later this year; full commercial operations are anticipated to commence by mid-2027, lifting evacuation capacity towards ~550,000 bbl/d.

The Permian Basin in Texas and New Mexico is the obvious benchmark for comparison. In 2025 it produced 6.6 m bbl/d of crude, up 280,000 bbl/d, and approximately 28.7 m MMBtu/d of marketed gas, up 11%. The Dallas Fed survey estimates cited by the EIA reported Permian operators needing an average of ~$67/bbl WTI to drill a new well profitably, up from $65/bbl a year earlier, and $43/bbl to cover operating expenses on existing wells. Speculation over the longevity of Permian reserves has been a divided topic in recent years as production data began pointing to a plateau. The EIA in January 2026 bluntly stated, "We expect little change in production from the Permian region as rig activity declines along with falling prices." Proved reserves at year-end 2024 stood at 26.71bn bbl across Texas and New Mexico, 58% of the US total, and 11 years of cover on 2025 production, with Texas down 3%, the steepest decline of any state. It appears operators in the Permian are now drilling deeper to stand still, with average lateral length rising by 77%, from 1.87 km in 2015 to 3.31 km in 2025, while annual completions held flat near 6,000.

Permian gas is driven primarily by associated gas produced during crude oil extraction. The gas-to-oil ratio rose from approximately 3.76 to 4.36 MMBtu/bbl between 2021 and 2025 as reservoir pressure fell. If the gas-to-oil ratio had remained the same as in 2021, Permian gas production in 2025 would have been approximately 24.74 m MMBtu/d, 14% below actual production. Approximately 3.96 m MMBtu/d of 2025 Permian gas arrived through reservoir ageing alone. The urge to pump oil when prices are high leads to huge surplus quantities of associated gas in the Permian. Storage capacity is regularly filled to the brim, and limited pipeline capacity to export has led producers to pay buyers to clear space. Waha hub gas (the benchmark for natural gas pricing in West Texas) traded below zero on 42% of trading days in 2024 and set a record 25 consecutive negative days to 12 March 2026, touching −$7.15/MMBtu.

Meanwhile, US LNG exports averaged the equivalent of approximately 114.8 Mtpa in 2025, up 26%. This is the national export total. Permian gas feeds coastal liquefaction terminals through an interconnected network that also receives gas from other basins. No attribution of LNG exports by basin of origin is published, but what can be said is that the Permian is the largest single source of US gas production growth in 2026, at approximately +1.45m MMBtu/d, with four takeaway lines totalling approximately 12.13m MMBtu/d built or building into a market whose incremental demand is now dominated by liquefaction.

The Permian basin operational model and the highly lucrative contracts available for liquefaction provide a blueprint for Argentina to develop a shale reserve in a modern and efficient way.

Argentina’s LNG expansion has two distinct steps. Southern Energy’s floating programme will combine the Hilli FLNG project’s 2.45 Mtpa of nameplate capacity with Esperanza’s 3.5 Mtpa. Golar LNG’s second-quarter 2026 update targets operations in the second halves of 2027 and 2028 respectively. A second dedicated feed gas pipeline known as the San Matias pipeline (~470 km) is due in early 2028, supporting liquefaction at scale. An eight-year agreement with Germany’s SEFE for 2 Mtpa (approximately 30.5m MWh/year of thermal energy) provides tangible evidence of buyer demand.

The larger Argentina LNG project, promoted by majority state-owned YPF, Eni and XRG, envisages another 12 Mtpa from two floating units off Río Negro. YPF’s 13th August 2026 application to the Large Investment Incentive Regime, RIGI, targets Final Investment Decision by year-end and start-up of both units by 2031. Its first-stage requirement of $15.5 bn drew proposals from 47 banks offering 2.4 times the amount sought, and a contract for a third pipeline (527 km) in the region was awarded on 8 July 2026 for $1.2bn. YPF anticipates $29bn of investment in 2031 and $51bn across the project’s life. YPF retains 36% and operatorship of the associated five-block upstream development, with Eni and XRG holding 32% each.

Together, the two programmes imply 17.95 Mtpa of annual capacity, or around 16% of US LNG exports in 2025. Actual exports will depend on commissioning and utilisation, while upstream supply must additionally cover liquefaction fuel and losses. Illustratively, at 90% utilisation, 52 MMBtu/t and realised export prices of $8–12/MMBtu, gross LNG sales would reach $6.7bn–$10.1bn annually. These are scenario revenues at max export capacity before costs, taxes and partners’ shares, but they provide a good indication of the potential scale for future LNG exports.

Vista Energy shows what greater scale and access to the export market can achieve. Vista realised $3.00/MMBtu on gas in Q2 2026. Two-thirds of its volume went to Argentine industrial buyers at $2.60/MMBtu, while the 5% it exported fetched $5.30/MMBtu. In Q4 2025 the industrial price collapsed to $1.00/MMBtu as the export price held at $5.00/MMBtu. The same molecule is worth multiple times more the moment it crosses the border. Developing large-scale liquefaction is what will allow Argentina to sell gas profitably against Atlantic basin netbacks.

The legal architecture underpinning LNG projects is one of the more interesting and underappreciated aspects to the story. Argentina spent roughly two decades diverting contracted export gas to domestic users whenever winter arrived. Javier Milei’s reforms have sought to legislate this problem out of existence.

Decree 1057/2024, implementing Law 27.742, makes LNG export authorisations firm for 30 years from plant start-up and grants the right to export "in continuous form without interruptions nor restrictions, reductions or redirections for any cause".

LNG projects are supported by the Regimen de Incentivo para Grandes Inversiones (RIGI), an economic framework designed to attract large-scale domestic and foreign investments. RIGI provides a 30-year guaranteed corporate income tax reduction of 25% (down from 35%), accelerated asset depreciation, and freedom to bypass strict capital controls and keep export earnings in offshore US dollar accounts.

Clearly, Milei’s reforms have been popular with the US government, which unexpectedly stepped in to prevent a rout in the Argentine peso last October ahead of the Argentine mid-term elections. It marked the first time in 25 years that the US had openly sold USD on the open market in order to boost a foreign currency, and the conditionality of the deal was explicit. At the White House on 14 October 2025, President Trump said of Milei, "If he loses, we are not going to be generous with Argentina." Thankfully, Milei won. With allies it holds more than a third of both legislative chambers, enough to sustain presidential vetoes.

The relationship was then formalised in treaty text. The Agreement on Reciprocal Trade and Investment, signed on 5 February 2026, obliges Argentina to facilitate US investment across critical minerals and energy resources, prioritises the United States for copper and lithium, bars purchases of nuclear reactors, fuel rods or enriched uranium from certain countries, and restricts its 5G and 6G suppliers. This was supposed to be a resource alignment agreement. Argentina renewed its CNY 130bn swap with the People's Bank of China on 5 August 2026 all the same.

The IEA’s Gas 2025 outlook anticipated roughly 220.6 Mtpa of new liquefaction capacity by 2030, primarily from the US and Qatar, underlining some competitive risk prior to middle eastern supply disruption. Argentina’s commercial LNG revenue runs to roughly $10bn a year on YPF's own projection. The geographic price differential between Argentina and the Atlantic basin has been a credible candidate for arbitrage, from $1.00–2.60/MMBtu domestically to $5.30/MMBtu at the border, and the export right is now statutory for 30 years in a country whose historic sin was tearing up energy contracts.

What remains to be seen is whether Argentina is still governed by Javier Milei, who is running for his second term in October 2027. Size accordingly.

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