The journey of gas from a field to a power plant can be convoluted, driven by global and regional power dynamics. One such pathway emerging is the flow of gas extracted in the US Permian Basin and exported via Mexico for power in Malaysia.
Using GEM’s robust and complementary datasets covering extraction areas, pipelines, liquified natural gas (LNG) terminals, and power plants, this story tracks gas infrastructure connections around the globe — and explains why this pathway has emerged despite growing economic risks associated with oil and gas.
Development in these geographies will shape the future of the global gas market and the energy transition more broadly. The US is the world’s leading gas producer and LNG exporter; Mexico has among the world’s largest export industries in planning; and Southeast Asia is viewed by the gas industry as one of its biggest markets for demand growth.
This analysis ties broader trends to the stories of specific infrastructure projects. The top oil-producing basin in the US, the Permian, is expected to hit its peak in the coming years, and the oil and gas industry is attempting to recruit new buyers to continue fueling its extraction.
Gas companies operate on both sides of the supply chain, such as Malaysia’s E&H Energy, which is supporting the development of both an export terminal in Mexico and its own import terminal at home. Malaysia and other Asian economies risk becoming dependent on gas and delaying a transition to renewables that would strengthen energy security. While the Malaysian government boosts gas development in its national plans, solar power with storage is already competitive with gas-fired power.
Gas extraction begins in the US
The Permian Basin’s evolution has lended itself to high levels of gas production. Overall volumes of oil and gas production have increased over the past decade, and as this extraction continues, pressure in the reservoir drops and more gas is released from the geological formation. As a result of that and other factors, gas-to-oil ratios (GOR) are growing and more gas is being produced.
While crude oil production increased since the start of the shale revolution in this region of Texas and New Mexico, gas production has increased at a higher rate as of late. The Permian Basin’s gas production was projected to rise 9% in 2025, after rising 12% in 2024. At the same time, oil production stabilizes in the basin then slightly reduces through 2026. Longer term forecasts continue the trend of higher gas than oil growth through 2030.
Increased gas production from the Permian has led to a flurry of pipeline projects aimed at increasing takeaway capacity, with industry hoping to capitalize on the change. While the region’s regulatory and property rights framework allows for a wide array of companies to produce in the Permian, consolidation has picked up in the past few years.
Of the 80-plus companies producing in the basin, a few became standouts in 2024: Diamondback and Endeavor completed a US$26 billion merger, combining two “dominant” companies. Occidental, which had previously acquired Anadarko in 2019, closed an acquisition of CrownRock. In a notable example, ExxonMobil “doubled” its Permian production when it acquired Pioneer, and Exxon/Pioneer’s Spraberry Formation production area will likely source at least some of the gas being shipped out globally via the upcoming AMIGO LNG terminal in Mexico.¹ The proximity to the “prolific Permian” was also highlighted in Epcilon’s initial application for the AMIGO LNG project, and the basin is shown in the project summary as the feed gas.
Pipelines and LNG export terminals in Mexico
Seeking to capitalize on the LNG boom in the US, developers of Mexican LNG terminals plan to bring gas from the Permian to new facilities for export. By siting projects on Mexico’s Pacific coast, LNG companies can offer a shorter route to Asia. In bypassing the traditional Panama Canal route, transit times may be cut by more than two weeks.
Located at the Port of Guaymas in Sonora state, the AMIGO LNG terminal is one of several recently proposed LNG export terminals on Mexico’s Pacific coast. Gas for the AMIGO project would be imported from Texas, leveraging unused capacity along the extensive network of pipelines commissioned in northwestern Mexico over the past decade.
The AMIGO terminal is to be developed in two phases totaling 7.8 mtpa in capacity. In December 2020, the US Department of Energy issued a permit allowing the terminal to export up to 395 Bcf of fossil gas annually to FTA (Free Trade Agreement) and Non-FTA nations. Between August 2024 and August 2025, the terminal’s owners signed 15- to 20-year sales and purchase agreements with four different companies covering total LNG exports of 5.4 mtpa. The largest of these contracts called for the AMIGO terminal to ship 3.6 mtpa of LNG to E&H Energy of Malaysia over a 20-year period.
In August 2025, AMIGO LNG announced that it had awarded an EPC (Engineering, Procurement, and Construction) contract to Dubai-based Drydocks World for fabrication and delivery of an FLNG (Floating Liquefied Natural Gas) facility and associated FSUs (Floating Storage Units) to the AMIGO terminal. The company has confirmed that it expects to make an FID (final investment decision) on the project in Q1 of 2026, with exports beginning as early as October 2028.
LNG import terminals and power plants in Malaysia
Malaysia is set to increase its gas power capacity as electricity demand is rising due to data center demand and the nation’s plan to phase out coal by 2044. At the same time, driven by declining domestic gas production in Peninsular Malaysia and surging energy demand, Malaysia is positioning itself to pivot from being a major LNG exporter to a net importer.
The Malaysian government is developing a National Gas Roadmap, which is anticipated to contain even more proposed gas infrastructure. However, its gas sector has also developed with strong foreign involvement and influence. Major oil and gas companies like ExxonMobil and Shell own stakes in Malaysian upstream projects. In August 2025, Malaysia’s government announced a deal with the US to lower tariffs that includes a commitment by state-owned Petronas to purchase US$3.4 billion in US LNG per year.
Malaysia’s gas market is divided into two distinct regions: the East Malaysian states of Sabah and Sarawak, and Peninsular Malaysia. Peninsular Malaysia accounts for more than 70% of the total national gas demand, driven by both the power and industrial sectors.
Malaysia currently has two operational LNG import terminals that are already integrated with the Peninsular Gas Utilisation (PGU) pipeline grid. The PGU pipeline grid is an extensive network in Peninsular Malaysia that transports gas to fuel gas power plants and other industries across the peninsula. LNG can be injected into the PGU pipeline grid for delivery to major gas power plants.
In addition to the two existing LNG import terminals on Peninsular Malaysia, two new terminals are in development including E&H Energy’s Kemaman LNG Terminal. The project, also known as RGT Kemaman, is an independent, multi-user LNG import and regasification terminal in Terengganu expected to achieve FID by the end of 2025 and commence operations by 2028. The facility will have a capacity of 6 million tonnes per annum, supplied primarily from contracted LNG from the west coast of Mexico under the AMIGO agreement, and will be capable of both regasification and re-export.
Gas power plants in Malaysia are concentrated in Peninsular Malaysia. According to GEM data², of the 17.4 GW of operating oil- and gas-fired capacity in Malaysia, 15 GW is located in Peninsular Malaysia. Of the 10.9 GW of in-development oil- and gas-fired capacity, 9 GW is located in Peninsular Malaysia.
A recent BNEF analysis found that not only is utility-scale solar already the cheapest source of bulk power generation in Malaysia, solar-with-storage will achieve a lower LCOE than new gas and coal power plants by 2026.
Building Malaysia's energy security
As shown by this supply chain, Asian countries are being used as a fallback for remaining US gas in the Permian Basin, seemingly in an effort to pursue US geopolitical interests and corporate profits. However, for countries like Malaysia, considerations about cost, long-term energy security, and energy access all support expanding renewables, not gas power.
The economic case for nearly every stop along this gas route is weakening. The cost of extracting gas from the Permian continues to rise as the most accessible deposits have already been mined. By the time the AMIGO terminal is completed, the global gas surplus could depress the international price for LNG and challenge the project’s profitability. Finally, the cost of solar power in Malaysia has already fallen below the cost of gas power—and the disparity will be even greater by 2030.
While this case study traces only one possible route for the gas coming out of the Permian, it demonstrates the deeply integrated nature of the gas system. Various pieces of gas infrastructure rely on other infrastructure types to justify and require their existence. Without pipelines, LNG terminals wouldn’t be possible. Without gas-fired power plants, LNG terminals wouldn’t be needed.
The geographic context is similarly co-dependent. Without the possibility of gas demand in Asia, gas extraction in West Texas would begin to dwindle rapidly. Without supportive regulations in Mexico, gas transit to Asia would remain overly complicated and expensive. The fact that the system is so integrated creates opportunities to identify weaknesses throughout that system by expanding the scope to a global scale, rather than focusing on a single infrastructure type or geographic area. In this case, the data reveals that this sort of increasingly complex LNG extraction and transmission system does not add up to energy security or economic savings.
