LNG Industry - North America 2026

NORTH AMERICA A supplement to LNG Industry

ONE PARTNER. TOTAL INFRASTRUCTURE. Premium workforce accommodations for the most challenging locations.

We are the only turnkey marine company that integrates PREMIUM FLOATELS, MARINE LOGISTICS and MARINE CONSTRUCTION into a single offshore ecosystem, allowing resource leaders to hit ‘GO’ on remote projects without the delays of land-based infrastructure.

Most major offshore infrastructure projects stall because they can’t house 1,500 workers without destroying the local environment or getting tied up in years of land-permitting. We bypass the land entirely. Bridgemans provides turnkey ‘floatels’ - fully integrated marine colonies - that deploy in weeks, not years, with zero footprint on the local soil.

sales@brgmans.com | T +1 604.210.5232 | bridgemans-services.com

Current and completed floatel projects.

ISSN 1747-1826

CONTENTS

NORTH AMERICA 2026

03 Comment

23 North American LNG after the

04 Going for double

André Jäger, Head of Industry Solutions Group at ION Commodities, explores the strength of North America's LNG project optionality in a volatile global energy market.

Persian Gulf shock

RBAC asks the question: what changes for North American LNG supply, flows, and pricing to 2035?

27 One decade on, US LNG is just getting started

Charlie Riedl, Executive Director, Center for LNG (CLNG), highlights the US LNG industry’s projections for growth and the obstacles currently hindering progress.

30 Henry Hub: Moving on up

RBAC asks the questions: what changes for North American LNG supply, flows, and pricing to 2035?

T

he North American LNG industry recently marked a decade of LNG exports. This was an interesting twist of fate; especially in the US, where gas production had started to decline in the 2000s with the country expected to import gas in the early 2010s. Yet, the Shale Revolution dramatically changed its trajectory from importer to becoming the world’s largest LNG exporter.

On 24 February 2016, Cheniere shipped its first cargo from its Sabine Pass facility, equal to approximately 3.3 billion ft3.1 Fast forward a decade, and the US exported 17 billion ft3/d in LNG to five continents in January 2026, with Canada’s new LNG Canada facility contributing another 1.1 billion ft3/d, and Mexico’s NFE Altamira an additional 0.1 billion ft3/d during that time.

As remarkable as that growth may seem, North American LNG exports are projected to double again within the next decade, reaching roughly 37.7 billion ft3/d by 2035, with export demand surpassing North America’s residential and commercial sectors combined.

Golden Pass, which started producing LNG in March 2026 and shipped its first cargo on 22 April 2026,2 signals the next

wave of new LNG facilities, which will need growing quantities of natural gas to satisfy export demand.

Against this backdrop, this article aims to answer four questions:

Kristy Kramer, Head of LNG Strategy and Market Development, and Dulles Wang, Director, Americas Gas and LNG Research, Wood Mackenzie, detail why US Henry Hub gas prices are set to rise.

1. What basins, areas, or producing regions provide natural gas to LNG facilities across North America?

2. How does gas flow to these LNG facilities; which pipelines does the gas travel through, and where are expansions needed to satisfy demand?

3. How do Canadian and Mexican LNG exports feature in this picture?

4. What role will this increase in North American LNG exports play in the global market, and where is US LNG expected to flow?

RBAC will use the GPCM market simulator to address these questions in the sections that follow, drawing on scenario and

4

5

04

10 Inside North America's LNG boom

Christina Andersen, President of Gas and LNG, Honeywell Process Technology, talks to LNG Industry about the outlook for North American LNG, and the impact technology and artificial intelligence are having.

15 All eyes on US LNG

Fauzeya Rahman, LNG Americas Editor, ICIS, reveals why US output will continue to drive global volumes.

18 Diverging paths emerge on

CBP019982

industry’s next supply super hub

Rebecca Scott, Western LNG, Canada, establishes why Canada’s Pacific Coast is emerging as one of the most compelling new LNG supply options globally.

39 Smarter project delivery

Rob Shaul, McDermott Senior Vice President, Low Carbon Solutions, UK, looks at how large scale modularisation is leading the next wave of LNG projects.

Melanie Lovatt, Finance Adviser, Poten & Partners’ Business Intelligence Division and Managing Editor of LNG Finance in World Markets, provides an insight into current US LNG export project financing behaviour and highlights future growth.

ON THIS MONTH’S COVER

Monica Hwang, Partner and Co-Head of the firm’s LNG Industry Group, and Samer Mahjoub, Associate, White & Case, USA, consider recent trends for US LNG projects taking final investment decisions, including financing pathways and impacts on global LNG supply.

18

37 Why Canada's west coast is the LNG

bonanza continues in 2026

Monica Hwang, Partner and Co-Head of the firm’s LNG Industry Group, and Samer Mahjoub, Associate, White & Case, USA, consider recent trends for US LNG projects taking final investment decisions, including financing pathways and impacts on global LNG supply.

he traditional roadmap to final investment decision (FID) for North American LNG projects has long been straightforward – secure long term, take-or-cancel/pay LNG sale and purchase agreements (SPAs) spanning 20 years, lock in a lump-sum turnkey EPC contract, and launch and secure non-recourse project financing. The CEO of commodities trading house, Trafigura, recently commented that a new financing pathway is necessary for LNG. Those who have followed US LNG FIDs over the past few years know there have been shifts away from this traditional roadmap. This article examines the diverging paths to FID: increased reliance on private credit and use of sponsor offtake commitment to facilitate FID. With analysts predicting a potential oversupply for the industry, lessons from recent North American LNG projects should prove valuable for developers facing a more challenging path to FID in an increasingly crowded market.1 However, it is

With 16 of its 19 modules now on site, 65% of construction complete, and a second floating workforce vessel in operation, Woodfibre LNG demonstrates how a project that began going vertical just one year ago is now charging towards commissioning.

43 US LNG export project financing

roadmap to FID

T

33 Modules and milestones

worthwhile to remember that the industry cycles between periods of oversupply and shortage. Furthermore, events such as the recent damage to Qatar’s Ras Laffan complex and the effective closure of the Strait of Hormuz can quickly shift industry dynamics. The recent price spike has sharpened buyers’ focus on supply diversification and security, underscoring the importance for expanded capacity development in North America. At the same time, many industry leaders warn that a prolonged high price environment may actually have a negative effect on demand growth.

Emerging financing pathway: Reliance on private credit

The past year has seen a marked shift towards alternative sources of capital, including private equity, infrastructure funds, and other institutional investors. Several factors are driving this

19

18

With decades of LNG expertise including pretreatment, liquefaction, automation, and digital solutions, Honeywell offers an integrated end-to-end portfolio that delivers the efficiency, reliability, safety, and performance required for next-generation LNG projects.

Its coil-wound heat exchangers, manufactured in Port Manatee, Florida, are at the heart of many LNG facilities. Operators and EPCs rely on Honeywell’s scalable LNG solutions to optimise assets, reduce risk, and create value from reservoir to revenue.

Copyright © Palladian Publications Ltd 2026. All rights reserved. No part of this publication may be reproduced, stored in a retrieval system, or transmitted in any form or by any means, electronic, mechanical, photocopying, recording or otherwise, without the prior permission of the copyright owner. All views expressed in this journal are those of the respective contributors and are not necessarily the opinions of the publisher, neither do the publishers endorse any of the claims made in the articles or the advertisements. Printed in the UK.

PER

FOR M

The GD10P series sets the standard ANC

E•

SAF ETY •

for Infrared Gas Detection RES

PON S

E TIM

E•

STA BIL

ITY

• Solid State IR Sources (SimSourceTM )

approve

d

• No Recalibration Required

UL

Certified for hazardous areas : GD10P std Class 1 div 2 GD10 UL Class 1 div 1

Download the GD10P Brochure

Download our Oil and Gas Application Note

www.TeledyneGFD.com gasandflamedetection@teledyne.com

JESSICA CASEY EDITOR

COMMENT

Managing Editor

James Little james.little@palladianpublications.com

Senior Editor

Elizabeth Corner elizabeth.corner@palladianpublications.com

Editor

Jessica Casey jessica.casey@palladianpublications.com

Editorial Assistant

Abby Butler abby.butler@palladianpublications.com

Sales Director

Rod Hardy rod.hardy@palladianpublications.com

Sales Manager

Will Powell will.powell@palladianpublications.com

Production Designer

Siroun Dokmejian siroun.dokmejian@palladianpublications.com

Head of Events

Louise Cameron louise.cameron@palladianpublications.com

Event Coordinator

Chloe Lelliott chloe.lelliott@palladianpublications.com

Digital Events Coordinator

Merili Jurivete merili.jurivete@palladianpublications.com

Digital Content Assistant

Kristian Ilasko kristian.ilasko@palladianpublications.com

Video & Motion Graphics

Amélie Meury-Cashman amelie.meury-cashman@palladianpublications.com

Digital Administrator

Nicole Harman-Smith nicole.harman-smith@palladianpublications.com

Administration Manager

Laura White laura.white@palladianpublications.com

Senior Web Developer

Ahmed Syed Jafri ahmed.jafri@palladianpublications.com LNG Industry Subscription rates: Annual subscription: £50 UK including postage £60 overseas (postage airmail) Two year discounted rate: £80 UK including postage £96 overseas (postage airmail) Subscription claims: Claims for non receipt of issues must be made within 3 months of publication of the issue or they will not be honoured without charge.

Applicable only to USA & Canada.

LNG Industry (ISSN No: 1747-1826, USPS No: 006-760) is published monthly by Palladian Publications Ltd, GBR, and distributed in the USA by Asendia USA, 701C Ashland Avenue Folcroft, PA 19032. Periodicals postage paid at Philadelphia, PA, and additional mailing offices. POSTMASTER: send address changes to LNG Industry, 701C Ashland Ave, Folcroft PA 19032.

I

n the January 2026 issue of LNG Industry, I discussed some of the headlines the FIFA World Cup 2026TM was making before the tournament had even begun. Fast forward a few months, and the event has broken even more records. Curaçao has made history on a couple of occasions: scoring their first World Cup goal with a momentary leveller against Germany (they eventually lost 7-1), and earning a first World Cup point with a 0-0 draw against Ecuador, in which the goalkeeper made 15 saves to equal the men’s World Cup record.1 One of the biggest stories from the competition is Cape Verde’s unexpected success. Despite being placed 67th in FIFA’s latest rankings,2 produced one of the biggest World Cup surprises by holding the current European champions, Spain, to a goalless draw in their opening match. This was in part thanks to their 40-year old goalkeeper, who has since gained 15 million Instagram followers. The team caused another shock when they scored their first (and second) goal at a World Cup against Uruguay, earning another point,eventually becoming the smallest nation to qualify for the knockout stage.3 As one of the host nations, Canada has also broken a record, winning a knockout game at the tournament for the first time to reach the last 16.4 Canada is also making strides in the LNG industry, with a couple of notable announcements. SEFE Securing Energy for Europe and Ksi Lisims LNG have signed a heads of agreement for an LNG supply deal for up to 20 years, under which SEFE will purchase 1 million tpy of LNG on a free-on-board basis, with deliveries expected to begin in the early 2030s.5 Once concluded, this would be SEFE’s first partnership with a Canadian LNG supplier. Uniper, another European company, has also followed suit and signed a letter of interest for a pending supply and purchase agreement (SPA). The SPA would see Uniper purchase 2 million tpy of LNG on a long-term basis, diversifying its LNG portfolio further and adding to security of supply.6 In addition, Fluor Corp. has announced that its JGC Fluor BC LNG II joint venture with JGC Corp. has received limited notice to proceed for the proposed Phase 2 expansion of the LNG Canada export facility in Kitimat, British Columbia. If a final investment decision is achieved, the Phase 2 expansion would double the facility’s production capacity to approximately 28 million tpy.7 Elsewhere in North America, it is fair to say the US LNG industry is being transformed as a result of the Middle East conflict. By mid-March 2026, the US had shipped 378 cargoes of LNG compared to 308 in the year previous – a historic high. With more projects in the pipeline such as Plaquemines, Golden Pass, and Corpus Christi Stage 3, experts expect an increase in exports of 18.43 million t in 2026 (approximately 16.5% y/y growth).8 President Trump’s stance on offshore wind is also proving beneficial to the US LNG industry, with TotalEnergies, Bluepoint Wind, and Golden State wind all having separately signed agreements to voluntarily end their offshore wind leases. As part of its settlement agreements with the U.S. Department of the Interior, TotalEnergies will reinvest the refunded lease fees for the Carolina Long Bay and New York Bight lease to finance the construction of the Rio Grande LNG plant and developments of its oil and gas activities.9 Global Infrastructure Partners has committed to invest the original bid amount for the Bluepoint Wind project into a US-based LNG facility, while Golden State Wind will instead invest an equal amount of fees for the offshore wind lease located in the Morro Bay Wind Energy Area in the development of US oil and gas assets, energy infrastructure, and/or LNG projects along the Gulf Coast.10 Finally, in Mexico, another LNG export project, Sempra Infrastructure’s ECA LNG Phase 1 liquefaction project in Ensenada, has started producing LNG as part of the commissioning process towards commercial operations.11 Phase 1 is expected to reach substantial completion in the summer of 2026, with long-term SPAs commencing shortly thereafter. A second phase is already under development at the same site.

This edition of our North American supplement offers a closer look at the region, and the progress the LNG industry is making, starting with a regional report on the changes for North American LNG supply, flows, and pricing to 2035 before moving on to keynote reports and showcasing some project case studies.

References

A full list of references is available on request.

Editorial/Advertisement Offices, Palladian Publications Ltd 15 South Street, Farnham, Surrey, GU9 7QU, UK

Tel: +44 (0) 1252 718 999

Website: www.lngindustry.com

RBAC asks the question: what changes for North American LNG supply, flows, and pricing to 2035?

T

he North American LNG industry recently marked a decade of LNG exports. This was an interesting twist of fate; especially in the US, where gas production had started to decline in the 2000s with the country expected to import gas in the early 2010s. Yet, the Shale Revolution dramatically changed its trajectory from importer to becoming the world’s largest LNG exporter.

On 24 February 2016, Cheniere shipped its first cargo from its Sabine Pass facility, equal to approximately 3.3 billion ft3.1 Fast forward a decade, and the US exported 17 billion ft3/d in LNG to five continents in January 2026, with Canada’s new LNG Canada facility contributing another 1.1 billion ft3/d, and Mexico’s NFE Altamira an additional 0.1 billion ft3/d during that time.

As remarkable as that growth may seem, North American LNG exports are projected to double again within the next decade, reaching roughly 37.7 billion ft3/d by 2035, with export demand surpassing North America’s residential and commercial sectors combined.

Golden Pass, which started producing LNG in March 2026 and shipped its first cargo on 22 April 2026,2 signals the next

4

wave of new LNG facilities, which will need growing quantities of natural gas to satisfy export demand.

Against this backdrop, this article aims to answer four questions: 1. What basins, areas, or producing regions provide natural gas to LNG facilities across North America?

2. How does gas flow to these LNG facilities; which pipelines does the gas travel through, and where are expansions needed to satisfy demand?

3. How do Canadian and Mexican LNG exports feature in this picture?

4. What role will this increase in North American LNG exports play in the global market, and where is US LNG expected to flow?

RBAC will use the GPCM market simulator to address these questions in the sections that follow, drawing on scenario and

5

sensitivity analysis to quantify likely changes in supply sources, pipeline flows, and LNG trade and price outcomes.

Two US states lead LNG supply

Looking at which US states supply LNG export facilities (Figure 1), Texas and Louisiana remain the primary suppliers of natural

Figure 1. Projected natural gas flows to US LNG export facilities, by state of origin (billion ft3/d). Source: GPCM Analytics, 26Q1 Base Case.

Figure 2. Projected US annual natural gas flows to US

LNG export facilities, by GPCM supply area (billion ft3/d).

Source: GPCM Analytics, 26Q1 Base Case. Note: This excludes flows from Canada and LNG imports. Flows less than 1.5 billion ft3/d for 2035 and 2050 are not labelled.

gas for export through 2050, while a few other states provide additional gas to facilities in the Gulf and Atlantic.

Natural gas produced in Texas is the greatest source of supply, providing 7.3 billion ft3/d, or 40% of all LNG exported in 2026. By 2035, flows from Texas are expected to comprise 43% of all natural gas exported from US LNG facilities, equal to 13.6 billion ft3/d – nearly double the volume provided to LNG export facilities in 2026.

Flows from Louisiana see similar increases, rising from 4.5 billion ft3/d (25% of supply) in 2026 to 7.7 billion ft3/d (or 24% of supply) in 2035. Combined flows from West Virginia, Pennsylvania, and Ohio provide an additional supply for LNG facilities, growing from 4.1 billion ft3/d in 2026 to 5.3 billion ft3/d in 2035.

Texas, Louisiana, and the Appalachian region (Ohio, Pennsylvania, and West Virginia) contain the major production basins in the US – the Permian Basin, the Haynesville, and the Marcellus/Utica Shale. Combined, these three basins account for 69% of all US natural gas production, and hence represent the primary sources for LNG exports.

Breaking it down even further into districts and zones, there is even more granularity in where this growth will come from.

Within Texas, production regions are organised into districts under the Texas Railroad Commission. Figure 2 illustrates much of the growth in supply will come from Texas Railroad Commission district 8 (TX RRC 8), in the Western part of the state, right over the Permian Basin (Figure 3). Production of natural gas for LNG in the region is expected to increase to 6 billion ft3/d, then gradually decline to 4.8 billion ft3/d as the region’s production capacity decreases. There are, however, some early indications that deeper, gassier plays in this area could become economic at relatively low gas prices, thereby enhancing productive capacity. TX RRC 7C (also located over the Permian Basin) and TX RRC 2 and 4 (over the Eagle Ford play) will also contribute natural gas to LNG exports, while TX RRC 6 includes gas from Haynesville on the Texas side of the play.

Most Louisiana natural gas production used in LNG exports comes from the northern part of the state, which contains the Haynesville Shale. This gas is a key resource for many of the LNG facilities within the state, supplying 7.6 billion ft3/d of gas to terminals operating by 2035. Supplies from the area increase to 8.9 billion ft3/d by 2050.

Natural gas from Pennsylvania, West Virginia, and Ohio – located above the Marcellus and Utica Shale plays – will also supply LNG export terminals. Flows from this area are less than those from Texas and Louisiana, due to the longer distance and stronger seasonal demand surrounding the region. However, this area is forecast to provide 6 billion ft3/d of natural gas to LNG facilities by 2050.

In summary, LNG facilities in the Gulf will primarily source their gas from the Permian basin. Supplies from Northern Louisiana/Haynesville Shale will remain a critical source, while production from the Appalachian region will play a significant supporting role.

LNG demand driving US infrastructure expansion

Figure 3. Texas Railroad Commission districts.

6

North America 2026

To serve new LNG capacity coming online over the next decade (Figure 4), additional pipeline infrastructure is required along the Gulf Coast (facility connectors and header lines), with further takeaway expansions linking inland Texas and Louisiana basins to Gulf Coast facilities.

Most LNG terminals use a dedicated pipeline segment (header pipeline) to connect their facility to existing infrastructure. For example, the Cameron LNG facility uses its Cameron Interstate Header (currently 2.2 billion ft3/d), which is connected to major long-haul pipelines (e.g. Tennessee, Transco, TETCO). The Cameron LNG facility is planning an expansion to 2.9 billion ft3/d via adding an additional LNG train (Train 4).

Alternatively, facilities like Rio Grande LNG will receive gas via the Rio Bravo pipeline (capacity of 4.5 billion ft3/d, completing by late 2026) and Golden Pass LNG via the Trident pipeline (capacity of 2.5 billion ft3/d, in-service 2027). Here, the LNG facilities are the anchor customers for major greenfield pipelines, connecting this new demand to upstream supply.

Infrastructure expansions also include new pipelines that connect existing supply hubs to demand hubs on the Gulf Coast.

Examples include the bidirectional Traverse pipeline (capacity 1.8 billion ft3/d, in-service 2027) that could bring supply from the South Texas Agua Dulce Hub – which itself gets substantial gas supply from West Texas Permian (Waha Hub) – up to the East Texas storage and demand hub of the Katy/Houston Ship Channel area. CP Express (capacity of 2.2 billion ft3/d, in-service 2028, with a possible additional expansion) will also link the CP2 LNG facility with Permian supply by tapping into the Katy Texas Hub. Within Louisiana, the Driftwood Line 200 and 300 pipelines connecting Woodside’s Louisiana LNG facility may potentially expand to 4.6 billion ft3/d by 2031, connecting the facility to Haynesville capacity further north.3 The Port Arthur LNG Louisiana and Texas Connectors (both with capacities of approximately

2 billion ft3/d, in-service 2027) will serve a similar role, bringing in supply from both states to the facility.

Canada to serve Asian LNG demand

Canada recently entered the world LNG market, exporting its first LNG cargo on 30 June 2025.4 Located on the west coast in Kitimat, British Columbia (B.C.), LNG Canada and other facilities are well situated to service growing Asian LNG demand, given its physical proximity and relatively calm shipping lanes.

Current forecasts expect Canada will export 2.3 billion ft3/d of LNG from the LNG Canada, Cedar LNG, and Woodfibre LNG export facilities by 2030. That capacity increases notably by 2035, with the start of the Ksi Lisims LNG facility in 2033 and the 1.8 billion ft3/d expansion of LNG Canada in 2034. After 2035, exports remain steady, reaching approximately 5.3 billion ft3/d by 2050.

The bulk of these exports are supplied by increased production from the Montney Shale area in Northeast B.C. and Northwest Alberta provinces (Figure 5); production from this area increases by 57% from 2027 – 2050, rising from 12.9 billion ft3/d to 19 billion ft3/d, while domestic demand remains relatively flat.

This new production flows to these LNG facilities along three major routes. For LNG Canada and Cedar facilities, gas flows arrive along the Coastal GasLink, which receives Montney shale gas from the NOVA pipeline system. Flows are expected to increase to 2.2 billion ft3/d by 2030, and 4 billion ft3/d by 2035.

The Prince Rupert Gas Transmission (PRGT) pipeline, which recently began construction, is expected to serve the Ksi Lisims LNG facility, providing the terminal with approximately 1.6 billion ft3/d of gas. Finally, the Woodfibre LNG facility will source gas via a header pipeline from the Westcoast pipeline’s Alberta connections.

The Mexico outlook

Figure 4. Additional US LNG capacity coming online to

2050 (million ft3/d). Source: GPCM Analytics, 26Q1 Base Case.

Like Canada, Mexico recently entered the global LNG market, shipping its first LNG cargo in August of 2024 from the NFE Altamira facility. Mexico LNG exports are set to expand to around 0.5 billion ft3/d by 2030, with Mexico’s Costa Azul LNG facility expected to reach full operational capacity early 2027.

NFE Altamira is largely supplied by US natural gas exports from the Permian via the Sur de Texas-Tuxpan pipeline. Costal Azul, located in Baja California, will offtake additional gas from the Permian Basin in Texas via the Baja Norte pipeline.

The North American LNG outlook

In terms of future demand, Europe is the primary destination for North American LNG; however, Asian markets are an increasing demand source for LNG terminals. In 2025, the US shipped 10.3 billion ft3/d of LNG to European countries (68% of all exports);5 however, it shipped another 2.5 billion ft3/d to Asian countries, namely Japan and South Korea. While those volumes are down from 2024 due to trade tensions, volumes are expected to increase. Canada shipped all its produced LNG – approximately 3.5 billion ft3/d – to Asia, specifically Japan, South Korea, and China. Mexico’s export locations were more mixed, but smaller volumes than either the US or Canada.

Questions for global LNG demand Figure 5. Projected annual Canada LNG exports, by facility (million ft3/d). Source: GPCM Analytics, 26Q1 Base Case.

8

North America 2026

Future LNG demand paints a dynamic landscape. Today’s geopolitics act as a bullish driver for current operating LNG facilities and expansions thereof, increasing short term demand and potentially leading to additional brownfield expansion.

Some of the major open questions that will impact global LNG markets include: z The long-term consequences of the US-Israeli-Iran war, which are a function of the duration and degree of conflict escalation.

Most notable among these consequences are the impacts on emerging LNG markets, such as the substitution effects stemming from higher prices. z The impact of LNG exports on domestic US natural gas prices, especially when combined with competing electricity demand from data centres. z The actual quantity of new pipeline infrastructure that manifests in high LNG demand regions, and the time frame to reach in-service dates.

risks therein, turning the uncertainty of global conflict and domestic demand into a clear, actionable roadmap.

About this study

This study was executed by Robert Kachmar, Scott McKenna, David Brooks, Grace Wheaton, and Oscar Tobar of RBAC’s North America team using GPCM® Market Simulator for North American Gas & LNGTM, integrating complex supply, demand, and infrastructure variables into a single, cohesive framework.

By using this system to run detailed scenarios and sensitivity analyses, the team’s analysts quantify the impact of geopolitical shifts and domestic infrastructure bottlenecks on future flows and pricing.

References 1.

‘Ten years after first Sabine Pass cargo, U.S. LNG exports are still on the rise’, U.S. Energy Information Administration (EIA), (24 February 2026), www.eia.gov/todayinenergy/detail. php?id=67224

2.

‘The 9th U.S. liquefied natural gas export terminal, Golden Pass, ships first cargo’, EIA, (23 April 2026), www.eia.gov/todayinenergy/detail.php?id=67564

3.

‘Driftwood Line 200 Project: Driving Economic Growth and Reliability for Louisiana’, Williams, (2025), www.williams.com/ wp-content/uploads/sites/14/2026/02/Driftwood-Line-200Fact-Sheet-Final.pdf

4.

‘First Cargo Puts Canada on the Map of LNG Exporting Nations’, LNG Canada, (1 July 2025), www.lngcanada.ca/ news/first-cargo-puts-canada-on-the-map-of-lng-exportingnations

5.

‘U.S. natural gas exports to grow nearly 30% by 2027 as LNG facilities ramp up’, EIA, (16 April 2026), www.eia.gov/todayinenergy/detail.php?id=67484

Looking ahead

The projected doubling of North American LNG exports by 2035 represents a massive expansion of not only export terminals, but of the continent’s midstream architecture. What started with Sabine Pass in 2016 has become a sophisticated export-oriented network.

Geopolitical and domestic pressures ensure that the North American LNG sector will remain dynamic, and the ability to optimise around infrastructure constraints and navigating price volatility will define competitive advantage.

In this environment, the success of the next wave of exports, related infrastructure, and market activity depends largely on how effectively participants can quantify both opportunities and

F E I L E R U GIVING YO

E R U S S E R UNDER P tact ion’s safety? Con at er p o r u yo e ad Ready to upgr ote. personalized qu a r o n io at rm fo in

Scan the QR code to learn more!

us today for more

Protect your cryogenic systems with our ASME approved safety relief valves, engineered for reliability when it matters most. Our solutions put safety in the forefront, allowing you to operate with confidence and give you peace of mind.

10

Christina Andersen, President of Gas and LNG, Honeywell Process Technology, talks to LNG Industry about the outlook for North American LNG, and the impact technology and artificial intelligence are having.

N

orth America’s LNG sector is entering a new phase of growth. Developers are racing to bring additional capacity online to meet rising global energy demand, while delivering projects with greater execution certainty, operational reliability, and long-term plant performance.

Meanwhile, companies are investing in expanding existing facilities while navigating tight project economics and pressure to accelerate delivery timelines.

Against this backdrop, technology providers are playing a larger role in helping LNG developers reduce complexity and improve project economics across the full facility lifecycle.

Greater integration between systems is changing how projects are designed, built, and operated, particularly as producers look

for ways to increase output from existing infrastructure. On this topic, Christina Andersen, President of Gas and LNG at Honeywell Process Technology, discusses the outlook for North America’s LNG market and the growing role of technology and artificial intelligence (AI) in LNG operations.

1. What is the current landscape of the North American LNG market?

North America remains one of the most attractive LNG markets globally – and one of the most competitive. The region benefits from abundant natural gas resources, a mature industrial ecosystem capable of delivering large scale energy infrastructure, and a stable operating environment.

11

At the same time, competition is intensifying, making project economics and execution more critical than ever.

Operators, developers, and investors are increasingly focused on cost per tonne of LNG, schedule certainty, and long-term operational performance. To attract investment, projects must demonstrate bankability – underpinned by proven technologies that drive efficiency, reduce complexity, and effectively manage execution risk.

LNG will continue to play a vital role in global energy security as demand for reliable power (driven in part by AI and data centres) rises, and geopolitical disruptions reinforce the value of politically stable supply. North America continues to be a key region for supporting the world’s growing energy needs.

2. What are some of the key challenges and opportunities facing LNG producers and exporters in North America today?

North American producers and exporters have a significant opportunity to expand capacity by optimising existing infrastructure and executing incremental expansions. Many are pursuing ‘train-plus-one’ additions that leverage existing utilities, permitting frameworks, and industrial infrastructure. These expansions are often more capital-efficient than greenfield developments and can reach the market faster – an important advantage in an increasingly competitive environment.

Figure 1. Honeywell’s modular coil-wound heat exchanger technology enables efficient, high-throughput LNG production with a compact footprint.

Another major opportunity lies in unlocking incremental LNG volumes through digitalisation, automation, and connected solutions. Even modest improvements in efficiency, reliability, or uptime can translate into meaningful output gains and create additional uncommitted volumes that producers can sell into the spot market, supporting global energy needs while improving overall project economics.

One of the biggest challenges for developers is maintaining project attractiveness throughout the planning and development phase, which often spans several years. As a result, developers are prioritising proven, scalable technologies and integrated solutions that reduce interfaces, simplify construction, and support predictable cost and schedule outcomes.

Maintaining rotating equipment, such as pumps and compressors, is another critical challenge. These assets are among the most vital and heavily used components of an LNG facility, requiring regular operating expenses through maintenance cycles. Integrating equipment health monitoring, controls, and digital analytics has become increasingly important to sustaining performance, reliability, and asset lifespan.

3. How are shifting regulatory landscapes in North America impacting LNG project development and timelines?

Regulatory guidelines remain a key consideration for LNG projects, given their scale and complexity. In North America, there is positive momentum towards improved co-ordination among agencies and efforts to streamline certain approval processes.

Developers that demonstrate robust safety practices, well-defined execution strategies, and the use of proven, integrated technologies are better positioned to navigate regulatory processes, mitigate schedule risk, and build confidence among regulators, investors, and other stakeholders.

Working with trusted industry partners can also provide developers with credibility and reduce risk to agencies and funding sources.

Modular delivery and standardised designs are also playing a growing role in managing regulatory complexity. More repeatable project configurations can support consistent execution and help shorten the time it takes for new facilities to enter operation by reducing variability that can complicate the approval process from one project to the next.

4. Honeywell has a long history in the energy sector. How has the company’s technological expertise shaped the evolution of LNG production and processing in the region?

Figure 2. Honeywell’s LNG Accelerate is an integrated

modular LNG solution designed to speed construction and maximise production efficiency.

12

North America 2026

Honeywell’s technological expertise has helped shape LNG production and processing in North America by enabling a more integrated, scalable, and bankable approach to project development. Rather than supplying individual technologies in isolation, Honeywell brings pretreatment, liquefaction, compressors, and pumps together with automation and connected digital systems for one end-to-end solution.

This integrated approach is grounded in long-standing technical expertise. Honeywell invented synthetic zeolite,

Learn more

an adsorbent that remains central to LNG pretreatment and is widely used across the industry today. This early innovation helped establish Honeywell’s leadership in gas purification, a critical step in LNG processing that continues to underpin modern LNG facilities in North America and globally.

Honeywell’s liquefaction technology has evolved to support systems at mid scale, as well as at some of the world’s largest LNG trains, offering scalability that aligns well with the diverse project sizes and configurations seen across North America. Extensive global deployment has further reduced perceived technical and execution risk for developers and investors.

Over the past two years, the company has expanded its LNG capabilities through targeted acquisitions that strengthen its integrated offerings. The acquisition of Sundyne, for example, added highly-specialised pumps and compression equipment used to move and pressurise natural gas. When combined with Honeywell’s automation systems, compressor controls, and digital asset performance monitoring, this equipment can be operated more efficiently and protected from damaging operating conditions.

For North American developers, this evolution to an integrated technology portfolio has enabled greater design flexibility, broader execution scope, and increased certainty around cost, schedule, and performance. Today, Honeywell process technology is used to pretreat approximately 40% of the world’s LNG, the company provides liquefaction technology for roughly two-thirds of global capacity, and its automation and digital solutions are being used in more than 80 LNG trains worldwide.

5. How are automation, advanced analytics, and AI transforming LNG plant operations and decision-making?

Automation, advanced analytics, and AI are transforming LNG plant operations by helping producers extract more value from existing assets while improving efficiency, reliability, and supporting the workforce.

Automation has long been integral to LNG operations, but the industry is now moving beyond basic monitoring and control towards systems that deliver predictive insights and proactive performance recommendations.

Honeywell has more than 1000 digitally-connected units in plants around the world, generating billions of data points every day. When paired with deep process-domain expertise, this data becomes a powerful tool. Operators can identify performance gaps, detect emerging equipment issues, and shift from reactive to proactive maintenance strategies. Even modest gains in uptime, throughput, or efficiency can translate into meaningful increases in LNG output– without adding new physical infrastructure.

AI further enhances decision-making by applying these insights in real time. AI models trained on real operating data and grounded in process expertise can recognise patterns, anticipate abnormal conditions, and provide guidance during unique events. As experienced operators retire, digital solutions are also helping capture institutional knowledge and make it accessible to the next generation of workers. The result is LNG facilities that are more efficient, more reliable, and better positioned to meet growing global demand while delivering stronger economic performance.

14

North America 2026

6. Can you share a specific example of new technologies or digital solutions that Honeywell has introduced to enhance efficiency, safety, or reliability in LNG operations?

Honeywell’s digital technologies help LNG plants start up faster, run more smoothly, and operate more reliably.

Pre‑configured control systems (built using Honeywell’s deep LNG expertise) are engineered, tested, and validated early in the project, reducing integration challenges and shortening commissioning. Embedded process models that reflect the facility’s specific process and equipment design give operators realistic training on start-up, shutdown, and upset scenarios before the plant goes online. Once in operation, these same models support advanced process control that reduces variability, speeds stabilisation, and minimises manual intervention. The result is safer, more consistent operations, higher throughput, longer equipment life, and stronger overall project economics.

7. Looking ahead, what trends or innovations will have the biggest impact on the North American LNG industry over the next 5 – 10 years?

The next phase of LNG innovation will likely focus on helping customers achieve incremental, compounding improvements.

Greater efficiency, tighter integration, and increased standardisation will drive meaningful gains in both project economics and operational performance.

Another key trend is the growing interest in modular and mid scale LNG solutions, particularly where speed to market and capital efficiency are priorities. In response to growing demand in North America for modular and mid scale LNG solutions, Honeywell recently launched Honeywell LNG Accelerate, a modular offering that integrates pretreatment, liquefaction technology, and fully integrated control systems into pre-engineered units. This approach reduces engineering and construction complexity, lowers project risk, and accelerates timelines – helping mid scale operators improve returns and speed to market.

Across all project sizes, tighter integration between process technology, automation, and digital solutions will remain a defining factor for success.

8. Finally, what advice would you give to LNG companies seeking to leverage technology to stay competitive in this rapidly changing market?

Engaging technology providers early is critical. Early collaboration allows developers to evaluate multiple execution paths and select the approach that best aligns with their goals. Decisions made during early design phases can have lasting implications for cost, schedule, operability, and long-term performance.

Whether pursuing large scale developments, incremental expansions, or modular solutions, companies that prioritise integration, standardisation, and connected operations will be best positioned to succeed, particularly in a market where tight margins make even incremental gains in efficiency and reliability decisive.

Fauzeya Rahman, LNG Americas Editor, ICIS, reveals why US output will continue to drive global volumes.

T

he US will continue to top global output in 2026, though the pace of growth will be slower than before.

The world’s top LNG exporter broke a new record in March 2026 for monthly loadings, according to ICIS data. The recent lack of Qatari LNG supply has also boosted demand for US LNG cargoes, but this is coming at a time when US output is already forecast to grow about 13%, to 130 million t in 2026, with plants operating at nearly peak capacity.

Unsold capacity

Some additional US volumes could come from unsold commissioning cargoes at either Corpus Stage 3 or Plaquemines LNG, as well as excess output beyond nameplate capacity at different LNG plants.

With Plaquemines LNG ramping up, Venture Global counts 31% of its expected 2026 cargoes as uncontracted, the company said in its 4Q25 earnings call.

With total output from both Calcasieu Pass and Plaquemines LNG expected between 486 – 527 cargoes, that means at least 150 cargoes would be available to be sold to the highest bidder.

Venture Global counts 11 vessels in its shipping fleet, including three ship deliveries expected in 2026: Venture Cameron, Venture Manatee, and Venture Venice, according to the earnings presentation.

US LNG ramp-up continues

More US LNG volumes will come online, although at a slightly slower pace compared to 2025. New supply will come from the 18 million tpy Golden Pass LNG project, the ongoing commissioning at Cheniere’s Corpus Stage 3 and Venture Global’s Plaquemines LNG. Golden Pass LNG achieved first production at Train 1 on 30 March 2026, the developer said, with LNG exports scheduled to start in 2Q26.1 Prior to contractor Zachry’s bankruptcy filing, Golden Pass LNG expected to start production in mid-2025.

This will add some incremental volumes to the market when the global balance has tightened considerably from the ongoing Middle East conflict.

ICIS assumes global supply is cut by 17 – 19% during the months of March, April, and May, and then 3% for the rest of the year, according to a 23 March 2026 update.

15

QatarEnergy owns 70% of the three-train, 15.6 million tpy Golden Pass LNG, while ExxonMobil owns the remaining 30%.

Two more trains will follow.

Extra volumes available for Asia

As the Shell-led LNG Canada continues ramp-up activities, more volumes will be available for Asian markets directly or via portfolio sales.

Meanwhile, Sempra’s Mexican Costa Azul LNG is targeting first LNG later in 2026, which will also boost Pacific coast supply in closer proximity to East Asian buyers.

US commercial activity to slow from 2025

After a record six final investment decisions (FIDs) in 2025, US commercial LNG activity will slow in 2026.

Venture Global announced FID on the second phase of its third LNG project, CP2, on 13 March.2 Across both phases, CP2 will have a peak capacity of 29 million tpy, the developer said, with the first phase counting for 20 million tpy followed by the second 9 million tpy phase.

In early April, Commonwealth LNG said FID was anticipated in the coming weeks. The project has faced previous delays, with a 2025 FID as the most recent target.

The 9.5 million tpy US Commonwealth LNG announced FID on 15 May 2026, the second US LNG project to advance this year following Venture Global’s second CP2 phase FID in March 2026.

Operations are expected to start in 2030, according to a press release from United Arab Emirates sovereign fund-linked Mubadala Energy,3 which owns an equity stake in Commonwealth developer, Caturus.

The FID decision comes after another offtaker, Mercuria Trading, increased its contracted volume to 1.5 million tpy from the original 1 million tpy sales and purchase agreement.4 US EQT and Glencore also increased offtake from Commonwealth previously. Total contracted offtake now stands at 8.5 million tpy out of the 9.5 million tpy project capacity:

z Aramco: 1 million tpy. z Mercuria Trading: 1.5 million tpy.

Japan’s JERA terminated a 1 million tpy deal with the project earlier this year.

Maintenance timelines

Though maintenance at US LNG plants can tighten output, planned shoulder season work was scheduled to take place ahead of a potentially busy summer, when competition for flexible US LNG cargoes can heat up on higher weather demand in Asia and the start of injection season in Europe.

Slower shoulder season demand meant any added supply tightness from the US could have less of a market impact beyond the current conditions, a source said, citing US FOB cargo availability in May. ICIS demand forecasts show July demand in Asia could be about 8% higher than the prior month, while Europe could see a 17% demand increase in July.

Planned maintenance work at US Corpus Christi LNG wrapped up in May, followed by confirmed planned outages at both Freeport LNG and Golden Pass LNG. Cheniere executives said in the first quarter earnings call in May that “no major turnarounds” were planned at its two plants this summer.

Train 2 at US Cameron LNG was offline for maintenance, sources said in early May, though the duration of the outage was not known.

Maintenance along the Cameron Interstate Pipeline was scheduled to last from 27 April – 30 May 2026, though it was not clear if the train maintenance would align with pipeline maintenance.5 Work at Trinidad’s Atlantic LNG Train 4 was expected to wrap up sometime in July.

US LNG as key Henry Hub driver

Demand from US LNG plants will be a key driver of US Henry Hub natural gas prices throughout the year, although expected higher domestic natural gas production will help moderate the Henry Hub benchmark in 2026. In 2027, z EQT: 2 million tpy. increased demand could push Henry Hub spot prices higher.

While global gas prices have surged following the start z PETRONAS: 1 million tpy. of the US war with Iran, Henry Hub prices have not reflected that volatility because of strong production and weaker z Glencore: 3 million tpy. seasonal demand.

US producer, EQT, says it will cut 2Q26 production by 10 – 15 billion ft3/d because of the relatively flat pricing environment, and it is considering additional cuts in the autumn, which could be larger, ahead of the higher demand winter period.

EQT counts 2 million tpy with Sempra’s Port Arthur Phase 2 project, 1.5 million tpy from Rio Grande Train 5, some 2 million tpy from the proposed Commonwealth LNG project, and a 0.5 million tpy tolling agreement with the proposed Texas LNG project. znop said EQT will offer both longer-term and short-term contracts as well as spot cargoes, with most of its offtake based on various indices.

EQT expects to sign agreements around 2028 – 2029, closer to when its US LNG offtake will become available, EQT CEO, Toby Rice, said in a 1Q26 Figure 1. Canada, Mexico projects add to North American supply wave. earnings call.

Source: ICIS supply forecast.

16

North America 2026

Other Americas projects

Argentina’s proposed LNG export project will be closely watched. Eni and YPF are targeting FID on the second 12 million tpy phase in 2026 and have already signed a non-binding agreement with ADNOC subsidiary, XRG. In the meantime, the first floating 6 million tpy phase is on track to start operations in Argentina in 2H27 and 2H28, respectively. It is being developed by Southern Energy, whose shareholders include Pan American Energy (30%), YPF (25%), Pampa Energia (20%), Harbour Energy (15%), and Golar LNG (10%).

Energy major, Shell, could take FID on “one or two” gas projects before the end of this year in Venezuela, if the right legal and fiscal frameworks are worked out, said Shell CEO, Wael Sawan, at the CERAWeek energy conference by S&P Global in March 2026.

Sawan also said FID on the second LNG Canada phase could be this year as well, following Shell’s US$16.4 billion acquisition of Canadian producer, ARC Resources.6

that will only grow more pronounced the longer this conflict rages in the Middle East.

References 1.

Golden Pass LNG social media post on LinkedIn, (30 March 2026), www.linkedin.com/posts/first-lng-achievedugcPost-7444370636812120064-F4lT

2.

‘Venture Global Announces Final Investment Decision and Financial Close for Phase 2 of CP2 LNG’, Business Wire, (13 March 2026), www.businesswire.com/news/ home/20260313159214/en/Venture-Global-Announces-FinalInvestment-Decision-and-Financial-Close-for-Phase-2-ofCP2-LNG

3.

‘Mubadala Energy, Kimmeridge and CPP Investments Announce Final Investment Decision for Caturus’ commonwealth LNG Investment in the U.S’, Mubadala Energy, (15 May 2026), https://mubadalaenergy. com/news/mubadala-energy-kimmeridge-and-cppinvestments-announce-final-investment-decision-forcaturus-commonwealth-lng-investment-in-the-u-s

4.

‘Commonwealth LNG Terminal Long-Term Contract Information and Registration at U.S. LNG Export Facilities’, U.S. Department of Energy’s Hydrocarbons and Geothermal Energy Office, (14 April 2026), www.energy.gov/hgeo/articles/ commonwealth-lng-terminal

5.

‘Planned Service Outage’, Cameron Interstate Pipeline LLC, (29 April 2026), www.gasnom.com/ip/CAMERON/notice_ details_new.cfm?id=287&type=3

6.

‘Shell announces agreement to acquire Canadian energy company, ARC Resources Ltd’, Shell, (27 April 2026), www.shell.com/news-and-insights/newsroom/newsand-media-releases/2026/shell-announces-agreementto-acquire-canadian-energy-company-arc-resources. html?ref=lngglobal.com

Conclusion

US LNG will continue to play a major role in balancing global demand in the absence of Qatari supply. However, there are limitations to how much more US LNG can be produced when volumes are already forecast to grow about 13% (to 130 million t) in 2026. Meanwhile, any plant maintenance, along with shifts or delays to project ramp-ups, will add more pressure to a global balance already facing supply shortages

LNG Industry Website

The home for the latest LNG industry news, analysis, comment and events Visit our website today:

www.lngindustry.com

18

Monica Hwang, Partner and Co-Head of the firm’s LNG Industry Group, and Samer Mahjoub, Associate, White & Case, USA, consider recent trends for US LNG projects taking final investment decisions, including financing pathways and impacts on global LNG supply.

T

he traditional roadmap to final investment decision (FID) for North American LNG projects has long been straightforward – secure long term, take-or-cancel/pay LNG sale and purchase agreements (SPAs) spanning 20 years, lock in a lump-sum turnkey EPC contract, and launch and secure non-recourse project financing. The CEO of commodities trading house, Trafigura, recently commented that a new financing pathway is necessary for LNG. Those who have followed US LNG FIDs over the past few years know there have been shifts away from this traditional roadmap. This article examines the diverging paths to FID: increased reliance on private credit and use of sponsor offtake commitment to facilitate FID. With analysts predicting a potential oversupply for the industry, lessons from recent North American LNG projects should prove valuable for developers facing a more challenging path to FID in an increasingly crowded market.1 However, it is

worthwhile to remember that the industry cycles between periods of oversupply and shortage. Furthermore, events such as the recent damage to Qatar’s Ras Laffan complex and the effective closure of the Strait of Hormuz can quickly shift industry dynamics. The recent price spike has sharpened buyers’ focus on supply diversification and security, underscoring the importance for expanded capacity development in North America. At the same time, many industry leaders warn that a prolonged high price environment may actually have a negative effect on demand growth.

Emerging financing pathway: Reliance on private credit

The past year has seen a marked shift towards alternative sources of capital, including private equity, infrastructure funds, and other institutional investors. Several factors are driving

19

this trend; rising interest rates and increased risk aversion among traditional lenders have made bank financing more expensive and harder to secure. At the same time, the long-term, stable cash flows associated with LNG projects have become increasingly attractive to private investors seeking to diversify their portfolios and hedge against volatility in other asset classes.

A prime example is Stonepeak’s acquisition of a 40% equity stake in Woodside Energy’s Louisiana LNG project, which enabled Woodside Energy to proceed with a positive FID. LNG projects are often structured so that investors can inject equity at different levels: a lower level closer to the physical assets, with limited exposure to commodity pricing risk (e.g. InfraCo); and a higher level with exposure to the long-term offtake contracts and potential benefits from access to overbuild capacities (e.g.

HoldCo), as demonstrated in Figure 1.

Stonepeak’s investment is on a lower project entity level and supported by steady tolling fees from a tolling agreement from Woodside. In addition, Stonepeak further improved its return profile by procuring back-leveraged financing to fund its investment.2 Private credit brings several advantages to project developers.

Private credit investors often have greater flexibility in deal structuring, allowing them to tailor financing arrangements to the specific needs of each project. In the Stonepeak example, Woodside and Stonepeak agreed for Stonepeak to make its share of equity contributions on an accelerated basis in 2025 and 2026; this provided Woodside additional timing to seek out additional investors to fund construction.

In contrast to non-recourse project financing, private investors typically require fewer restrictive covenants, thereby allowing the project sponsor more operational control. They can also make decisions more quickly than traditional banks, reducing the time required to reach financial close and begin construction. In some cases, private credit investors are willing to take on higher levels of risk in exchange for the potential returns.

In September 2025, Sempra Infrastructure announced a positive FID on its Port Arthur LNG Phase 2 project. Its financing included a 49.9% of equity investment by a Blackstone-led consortium.

The consortium provided US$3.4 billion in immediate capital and an additional US$3.6 billion to be paid later and receives initial distributions at the higher percentage of 59.9%.3 The influx of private credit also presents new challenges.

Private credit investors typically demand higher returns than banks, which can increase the overall cost of capital for LNG projects. Although the restrictive covenants are more tailored,

Figure 1. A sample LNG project investment structure.

20

North America 2026

private credit generally has higher oversight (sometimes with seats on the borrower’s board) and more frequent disclosure requirements (e.g. provision of quarterly financial statements) than project lenders. As the financing landscape continues to evolve, project sponsors will need to be increasingly creative and proactive in sourcing capital and structuring deals.

Emerging financing pathway: Increased sponsor offtake commitment

Another notable development is the trend towards increased sponsor offtake commitments. In calling for new financing pathways, Trafigura’s CEO lamented the traditional requirement that an LNG project must have 80 – 90% of its capacity under long-term contracts.4 While such long-term commitments remain important to financing parties, including private credit, recent project sponsors have either underpinned such commitments themselves or reserved a larger stake as a sweetener to attract equity investors.

In June 2024, Cedar LNG announced a positive FID on its 3 million tpy LNG project, with a total capital cost of approximately US$4 billion, 60% of which is funded via a construction loan and the remaining 40% through equity contributions by its two partners, the Haisla Nation and Pembina Pipeline Corp. The revenue commitment underpinning the FID consists of two tolling agreements: 1.5 million tpy by ARC Resources and 1.5 million tpy by its sponsor, Pembina. In 2025, Pembina offloaded its capacity to Petronas and Ovintiv. In this case, one sponsor underpinned not only 20% of the costs via its equity investment, but also half of the capacity commitment.5 Note that this project is relatively smaller in size and capital commitment. The same level of commitment may not be feasible for many sponsors for a typical US LNG project with a price tag of at least US$20 billion.

In October 2024, Woodside completed its acquisition of Tellurian, Inc. and its Driftwood LNG project. Within about six months, in April 2025, Woodside renamed the project Louisiana LNG and announced a positive FID on the 16.5 million tpy project with an estimated capital cost of US$17.5 billion. At the time, Woodside had concluded a 1 million tpy offtake contract with Uniper for the project, plus the Stonepeak investment described previously. The Stonepeak investment is underpinned by Woodside’s commitment to subscribe for the entire capacity of the project. Since FID, it has announced Williams Companies as an investor and offtaker for 1.5 million tpy, with Turkey’s BOTAŞ for 0.5 million tpy to be supplied from Woodside’s portfolio of LNG projects (including Louisiana LNG), and JERA for a five-year winter cargo transaction. Before Meg O’Neill left for BP, the former CEO of Woodside consistently articulated that the strategy is a “staged approach” to sell down additional stakes as construction progresses.6 With respect to Port Arthur LNG Phase 2, FID was supported by 10 million tpy of 20-year offtake agreements, of which approximately 2.5 million tpy is committed by Sempra through its affiliate. Another Sempra affiliate also committed to any excess quantities of up to 0.75 million tpy above the committed 10 million tpy.7 This commitment by Sempra demonstrates the importance of committed offtake, which provides the revenues fundamental to financing.

While the LNG industry’s attention is fixated on the starkly different outcomes between Venture Global’s

arbitrations with its customers, BP and Shell, a few US LNG projects are explicitly giving themselves a prolonged commissioning period, often much longer than the typical few months historically necessary to complete commissioning, and reserving the cargoes produced during the prolonged period for the project sponsor in order to use the higher economic returns from these cargoes as a sweetener to attract equity investors.

Historically, project sponsors used overbuild or excess cargoes as a means to attract equity investors; in contrast, ‘commissioning’ cargoes occur before commercial operations and thus can provide earlier returns directly to the equity investors. The returns can be sizeable, as demonstrated by Venture Global’s Calcasieu Pass LNG project, which had a weighted average fixed liquefaction fee for its LNG cargoes of US$6.67/million Btu in 3Q24 compared to US$1.76/million Btu in 3Q25.8 The key difference between those two figures is that the Calcasieu Pass LNG project achieved commercial operations in April 2025.9 Thus, the US$6.67 figure reflects spot prices achieved by Venture Global from commissioning cargoes, while the US$1.76 figure reflects the prices under Venture Global’s long-term SPAs.

Looming oversupply?

The global LNG market is at a critical juncture, with a wave of new supply set to come online over the next several years.

Some forecasts predict a 50% increase in supply by 2030, and many market analysts are predicting an oversupply scenario in the near term.10 While many US LNG projects under development are racing to achieve FID before oversupply fears deter buyers, it is important to note that these projects are targeting late 2029, if not after 2030, to come online and begin commercial operations.10 Figure 2 shows forecasted growth of liquefaction capacity in North America over the next three years.

Lower LNG prices also create good opportunities to advance demand side development. Some energy companies, commodity traders, and power generating companies are doubling down on LNG: z JERA has been reported to target new LNG to power opportunities in Southeast Asia, and New Zealand is planning its own LNG import terminal.11,12 z Vitol Group was also reported to be backing a consortium developing a US$3 billion LNG import terminals and a gas-to-power project in South Africa.13

z Shell CEO, Wael Sawan, highlighted Shell’s bullish stance on LNG at the LNG2026 conference in Doha, Qatar, expecting demand to surge by 60% by 2040.15 Recent policy developments are fostering new commercial opportunities across the LNG value chain. The US government has reportedly requested that the EU exempt US LNG from its methane emissions regulations, and commercial parties are already positioning bio-LNG to support compliance requirements. In Japan, the government has enacted a low-carbon hydrogen framework and amended its Gas Business Act to define synthetic methane and establish cost-recovery mechanisms for e-methane. Both bio-LNG and e-methane can be transported with existing LNG infrastructure and vessels, meaning growth in these fuels can support growth in LNG demand – albeit on a smaller scale. On the shipping side, the International Maritime Organization has deferred adoption of its Net Zero Framework by one year, but compliance obligations are approaching. Taken together, these demand-side shifts are poised to aid increase in LNG consumption.

The Middle East conflict has delivered a structural shock to global LNG and energy markets, including damage to the Ras Laffan LNG terminal that will take up to five years to repair (impacting approximately 17% of Qatar’s export capacity)16 and the threat to safe sea passage through the Strait of Hormuz (impacting approximately 20% of global LNG and oil trade).17 This has forced LNG buyers to scramble for alternative supply sources virtually overnight. Spot prices have surged and key LNG buyers are considering or implementing additional mitigation measures in case the conflict is expected to be protracted.18,19 While many North American LNG project developers have hopes that the same supply disruption will accelerate the next North American LNG investment cycle, executives at major LNG players warn that prolonged high LNG prices may actually have the opposite effect and deter investments in new LNG demand and even encourage fuel switching to another fuel.20 The conflict has therefore illustrated that the global LNG supply and demand is vulnerable to geopolitical shocks, triggering immediate price surges, supply scrambles, and uncertainty around both new investment and demand growth.

Conclusion

As North American LNG projects navigate a rapidly evolving landscape, divergent paths to FID are emerging, shaped by shifts in financing and contracting. While forecasts point to near-term challenges and risk of oversupply, new demand opportunities offer reasons for optimism. As project sponsors seek to develop new LNG liquefaction projects, success may come from innovative approaches to financing and contracting, as well as new sources of demand.

References

A full list of references is available on request.

Note Figure 2. North America LNG export capacity by project (2016 – 2029) (billion ft3/d). Source: U.S. Energy Information Administration.14

22

North America 2026

Any views expressed in this publication are strictly those of the authors and should not be attributed in any way to White & Case LLP.

André Jäger, Head of Industry Solutions Group at ION Commodities, explores the strength of North America's LNG project optionality in a volatile global energy market.

A

t the start of 2026, the International Energy Agency (IEA) predicted that global LNG supply would rise by more than 7%.1 That global outlook has been fundamentally reshaped by conflict in the Middle East.

The central issue is no longer simply supply growth, but resilience; the ability to leverage asset and contractual flexibility during disruptions. The global LNG system is being redefined by overlapping uncertainties: new supply coming online, contested demand across regions, geopolitical instability, weather-related volatility, and rising regulatory and financing pressures.

The disruption has exposed Asia’s deep structural reliance on Qatari LNG while also underscoring how even more diversified markets, like Europe, remain highly sensitive to disruptions in Qatari supply. Prior to February 2026, QatarEnergy was the world’s second-largest LNG exporter, with its facilities in Ras Laffan processing and exporting 20% of the global supply through the Strait of Hormuz. Iranian strikes on Qatar’s Ras Laffan complex have removed an estimated 12.8 million tpy – around 17% of Qatari capacity2 – from the market for potentially up to five years. At the same time, disruption to shipping through the Strait of Hormuz has

23

periodically reduced Qatari exports to Asia from over 6 million t pre-conflict to about 800 000 t in April 2026,3 highlighting the vulnerability of globally critical energy chokepoints.

In this context, LNG is increasingly behaving less like a conventional commodity and more like a “geopolitical market” as Muhammed Aziz Khan, Summit Group Chairman, has described it. The market is defined by a growing security premium, renewed emphasis on long-term, diversified supply, and the increasing importance of physical availability – where cargoes must not only be purchased but also reliably delivered.

Why US LNG matters more in a disrupted market

For North America, these developments have thrust the region to dominance on the global stage. At the centre of this system sits the US. In 2016, the US exported its first cargo of LNG from the Lower 48. By 2025, it had become the world’s largest LNG exporter, shipping 111 million t – the first country ever to exceed 100 million t in a single year4 – and accounting for roughly one-quarter of global LNG trade.

The US has become Europe’s main LNG supplier as the region has tried to phase out Russian energy since Moscow’s invasion of Ukraine. This shift reflects the structural flexibility of the US LNG model, which has allowed it to respond rapidly to price shocks – from the invasion of Ukraine to the recent conflict in the Middle East.

Most US export contracts are typically structured on a free-on-board (FOB) basis, allowing buyers to control shipping and determine the final destination of cargoes after loading. As a result, cargo flows can respond rapidly to price signals, redirecting supply between regions as market conditions evolve.

This flexibility is increasingly used in trading strategy. In early 2026, more than 1 million t of LNG that had already departed US terminals remained without a fixed destination, with vessels idling near the Suez Canal awaiting clearer price signals – a clear indication that trading and optimisation possibilities are being used to manage disruption and improve the bottom line.

In March 2026, US LNG exports reached a record 11.7 million t.5 While Europe remained the primary destination, deliveries to Asia rose sharply as regional spot prices increased, highlighting how supply is reallocated in real time across regions. In practice, this means that the same Atlantic Basin cargoes move towards whichever region offers the highest netback after freight, canal costs, timing, and portfolio optimisation.

This dynamic is driven by arbitrage between regional gas benchmarks – notably the Asian spot LNG price (JKM) and Europe’s main gas hub (TTF). When Asian prices rise above European levels, cargoes are pulled east; when the spread reverses, flows return west. For example, on 4 March 2026, the JKM – TTF spread had flipped to favour Asia by about US$5/million Btu; JKM for April 2026 delivery surged 68.52% to US$25.393/million Btu, while northwest European gas prices rose 57% to US$15.479/million Btu.6 Chinese firms, for example, have continued purchasing US LNG under long-term contracts, but instead of importing it domestically, have redirected cargoes into Europe to capture

24

North America 2026

higher prices. This reflects a broader reality: contracts no longer determine destination – price does.

While the US’ commercial model for LNG benefits from this flexibility, it is not an unlimited backstop. The opportunity to supply countries such as India, South Korea, Taiwan, China, Pakistan, and Bangladesh – which collectively hold more than 50 million tpy of contracted Qatari supply7 – is constrained by the physical limits of US supply. US liquefaction plants are already operating near maximum capacity, and near-term additional supply is unlikely to exceed around 2 billion ft3/d, compared with a roughly 10 billion ft3/d gap created by disrupted Qatari volumes, according to Reuters calculations.8 The greatest strength of US LNG – its destination flexibility – is also a concern for some buyers. While it allows for rapid redirection to supply-constrained markets (like Europe during the Russia-Ukraine crisis), it also means the gas goes to the highest bidder, which can make it appear uneconomic for price-sensitive emerging economies.

Sustained periods of elevated LNG prices are already reshaping demand in price-sensitive markets. Pakistan provides a clear example. Between 2015 and 2021, LNG imports rose by roughly 50% annually as the country rapidly expanded gas-fired power generation. However, the 2022 energy crisis exposed the fragility of this model. As global LNG prices surged, Pakistan was increasingly priced out of the market, forcing a shift towards alternative energy sources – particularly solar – with imports now remaining significantly below their 2021 peak.

Ultimately, this illustrates how the Middle East crisis has exposed the underlying issues with energy dependence. As well as shocks overseas, developments in the US can significantly affect global LNG prices. During the January 2026 Arctic cold snap, US gas demand surged and supply tightened, driving price increases across both Asia and Europe. Moreover, as higher gas prices feed through to consumers, rising LNG exports risk becoming a cost of living issue within the US, potentially leading to political interference or regulation if prices rise significantly. Reliance on imported energy exposes countries to price volatility. The commodity industry must adopt a more adaptive, future-facing risk management playbook to combat this uncertainty.

Canada and Mexico: Diversification and differentiation

If the US provides flexibility and scale, Canada and Mexico represent differentiated extensions of the North American LNG system.

Canada has entered the market through LNG Canada and is progressing additional projects such as Woodfibre and Cedar LNG, while Mexico has positioned itself as a re-export hub, using US pipeline gas and Pacific coast infrastructure to target Asian demand.

Canada’s position has strengthened significantly following the Persian Gulf disruption. LNG Canada, which began exports in 2025, is ramping towards its full 14 million tpy capacity.9 In early 2026, it shipped multiple cargoes to Asian markets, demonstrating its role in regional balancing.

Its Pacific coast location is central to its appeal. Unlike US Gulf Coast exports, Canadian LNG offers more direct access to Asian markets, avoiding some of the congestion and routing risks associated with global chokepoints.

More importantly, Canada is increasingly being viewed as a ‘safe supply’ source. European buyers, including Germany’s Uniper, are exploring imports of Canadian LNG via the Panama Canal despite higher costs, reflecting a willingness to prioritise supply security over pure economics.

Canada’s second wave of new projects is also taking shape. Woodfibre LNG (2.1 million tpy) is under construction, Cedar LNG (approximately 3 million tpy) is advancing, and Ksi Lisims LNG (12 million tpy) is under development. While these projects will not deliver immediate scale, they reinforce Canada’s role as a strategic diversification option.

Mexico presents a different proposition. Strategically, it does not function as a separate gas basin: it is a re-export and route-optimisation platform for US molecules. Its LNG ambitions are based less on domestic gas supply and more on geography and infrastructure. The country imports the majority of its gas from the US,10 and Pacific coast liquefaction offers a shorter and more direct route to Asian markets.

In practice, however, progress has been uneven. While projects such as Energía Costa Azul and Altamira are advancing, several Mexican LNG projects have faced delays,11 cost pressures, and redesign challenges, limiting their ability to capitalise on current market conditions.

The next phase of strategic competition

The contrast across North America is therefore increasingly clear. The US offers scale and flexibility. Canada offers stability and lower geopolitical risk. Mexico offers geographic advantage – but with higher execution risk.

Taken together, however, the strategic point is not about scale alone. It is that the region now offers different forms of optionality. The US provides the most liquid and flexible molecules, capable of arbitrage between Europe and Asia.

Canada offers a politically-stable Pacific supply source with lower perceived geopolitical risk. Mexico, if projects progress, offers route optimisation for US gas into Asia without relying on the US Gulf Coast.

These points matter because the market is no longer shaped solely by price. Flexibility may be critical, but flexibility is only valuable if it can be understood and executed effectively. Even as new supply capacity comes online, there remains uncertainty around demand in both Europe and Asia, weather-related shocks, shifting freight economics, domestic political sensitivities in the US, sanctions exposure, and a growing need to prove compliance with emissions and other regulatory requirements. The market is becoming more creative in how contracts are structured and how optionality is embedded – but it is not getting simpler.

There is also a longer-term tension building behind the current market opportunity. New LNG demand may yet come not only from traditional importers, but from power-hungry sectors such as data centres and artificial intelligence (AI). In the US, electricity consumption is now expected to reach record highs in both 2026 and 2027, with demand surging in part because of AI and data centres. At the global level, QatarEnergy has argued that AI-related power demand could turn the expected LNG surplus later this decade into a shortage by 2030.12 The real challenge is no longer just securing supply. It is understanding the optionality in a portfolio, modelling what happens when conditions change, and having a playbook for

26

North America 2026

the next disruption. If Qatari supply is interrupted, if freight costs spike, if Asian benchmarks pull cargoes east, if US domestic prices rise sharply, or if regulation and sanctions tighten in key markets, participants need to know not only what they have contracted, but what they can actually do with it.

That is where the market is heading. Market participants will not compete on access to molecules alone, but on their ability to see and act on market changes quickly. In a market defined by rerouting, repricing, and rebalancing, portfolio visibility becomes strategic. The next phase of LNG competition will not be won by building more capacity alone.

It will be won by those who can make better decisions, quickly and flexibly deploying their physical assets. In a market where uncertainty has become structural, those able to combine trading sophistication with a clearer view of risk and opportunity will have the advantage.

References 1.

‘Growth in global demand for natural gas is set to accelerate in 2026 as LNG wave spreads through markets’, International Energy Agency, (23 January 2026), www.iea.org/news/growthin-global-demand-for-natural-gas-is-set-to-accelerate-in-2026as-lng-wave-spreads-through-markets

2.

EL DAHAN, M., MILLS, A., and SABA, Y., ‘Exclusive: Iran attacks wipe out 17% of Qatar’s LNG capacity for up to five years, QatarEnergy CEO says’, Reuters, (19 March 2026), www.reuters. com/business/energy/iran-attack-damage-wipes-out-17-qatarslng-capacity-three-five-years-qatarenergy-2026-03-19/

3.

RUSSELL, C., ‘China’s LNG imports plunge, helping Asia adjust to Iran war losses’, Reuters, (23 April 2026), www.reuters.com/ markets/commodities/chinas-lng-imports-plunge-helping-asiaadjust-iran-war-losses-2026-04-23/

4.

WILLIAMS, C., ‘US sets new LNG export records in banner year marked by new capacity’, Reuters, (2 January 2026), www.reuters.com/business/energy/us-sets-new-lng-exportrecords-banner-year-marked-by-new-capacity-2026-01-02/

5.

WILLIAMS, C., ‘US LNG exports break record high as Middle East war disrupts global supply’, Reuters, (1 April 2026), www.reuters.com/business/energy/us-lngexports-break-record-high-middle-east-war-disrupts-globalsupply-2026-04-01/

6.

BOUSSO, R., ‘China Isn’t Importing Any US LNG, But It’s Still in the Game’, EnergyNow Media, (18 February 2026), https://energynow.com/2026/02/china-isnt-importing-any-uslng-but-its-still-in-the-game-bousso/

7.

‘Argus Analytics: A x-commodity assessment of the Middle East conflict’, Argus Media, (4 March 2026), https://view. argusmedia.com/rs/584-BUW-606/images/ALL-Insight-paperAnalytics-X-commodity-update-on-ME-Conflicts-Mar-26.pdf

8.

WILLIAMS, C., DISAVINO, S., and CLARK, H., ‘U.S., Australia can do little to replace lost Qatari LNG cargoes’, Reuters, (4 March 2026), www.reuters.com/business/energy/thereis-little-us-lng-producers-can-do-immediately-replace-lostqatari-cargoes-2026-03-04/

9.

WILLIAMS, C. and STEPHENSON, A., ‘LNG Canada produces first liquefied natural gas for export’, Reuters, (23 June 2025), www.reuters.com/business/energy/lng-canada-produces-firstliquefied-natural-gas-export-sources-say-2025-06-22/

10. ‘U.S. natural gas exports to grow nearly 30% by 2027 as LNG facilities ramp up’, U.S. Energy Information Administration, (16 April 2026), www.eia.gov/todayinenergy/detail. php?id=67484 11. EVANS, C., 'Mexican and Canadian LNG Projects Compete to Supply Asia', Energy Intelligence, (26 January 2026), www.energyintel.com/0000019b-ed08-db06-a1bf-fd2f8eb70000 12. CHOW, E., SABA, Y., and MILLS, A., 'AI power needs may turn LNG glut to gap by 2030, says Qatar Energy CEO', Reuters, (2 February 2026), www.reuters.com/business/energy/rising-aipower-needs-could-turn-lng-supply-glut-into-a-2030-shortagesays-2026-02-02/

Charlie Riedl, Executive Director, Center for LNG (CLNG), highlights the US LNG industry’s projections for growth and the obstacles currently hindering progress.

2

026 marks the 10-year anniversary of the US becoming a major LNG exporter. A decade ago, the idea of the US as a global energy powerhouse was just a goal; today, it is a reality. The US has transformed domestic abundance into a cornerstone of global energy security. The region has made significant progress, but it is just getting started.

Over the past few years, momentum has been strong. Now, the US has massive projects like Golden Pass LNG, which just came online, set to produce 2 billion ft3/d, and Port Arthur Phase 1 steadily advancing towards completion, set to produce 1.6 billion ft3/d.1 These new projects, along with expansions at current sites, will boost production and the

many domestic and international benefits of growing US LNG exports.

The U.S. Energy Information Administration (EIA) estimates that average US LNG exports reached 17.9 billion ft3/d in March 2026, the second-highest LNG export volume on record following December 2025.2 If the trend continues, by 2027, US LNG exports could rise to as much as 20 billion ft3/d.

Looking further down the road, long-term growth is even more significant. Estimates from Natural Gas Intelligence suggest that by 2030, the US will supply a staggering one-third of the entire global LNG supply.3 Those estimates were made before recent geopolitical events took capacity

27

offline in other parts of the world, meaning the US share of the global LNG market is likely to grow even further. Supply at this scale would cap a decade of investment that has positioned the US as a global leader in LNG. But sustaining this growth requires the right policy environment at home.

For a period, US LNG exporters were bogged down in unnecessary regulatory uncertainty. In 2024, the LNG export pause created unnecessary friction that kept new LNG supply from coming online and generated hurdles for countries looking to secure volumes of US LNG. In January 2025, the Department of Energy (DOE) reversed its push to halt new export licenses, placing the industry back on track for a new phase of rapid growth, just as the world needed more reliable, affordable, and clean energy. The DOE’s reversal was a critical step, it signalled to partners abroad that the US is once again a reliable, open-for-business supplier.

However, there are additional regulatory hurdles that must be addressed – most notably on the issue of permitting.

US policymakers must move beyond the ‘stop-and-go’ nature of project approvals that America’s broken permitting system imposes. Policymakers and regulators must push for legislative, comprehensive, bipartisan, and durable federal permitting reform.

This is not just about making things easier for US LNG project developers, it is about providing the regulatory certainty to move forward with multi-billion-dollar investments. And the issue extends beyond export terminals.

The US needs to build the right infrastructure across the broader natural gas system to prevent bottlenecks and safely meet skyrocketing demand. As more domestic industries, like artificial intelligence (AI) data centres, and international buyers continue to turn to US natural gas, infrastructure is needed to match the pace of demand.

The forces driving demand

Recently, disruptions in the Middle East have revealed new risks in global supply chains and the global energy system.

The situation does not change the long-term growth outlook, but it is shifting near-term expectations as global LNG supplies tighten.

Demand for US LNG is surging, with US LNG exporters already operating above nameplate production capacity, and some as high as 130% of nameplate capacity. But US LNG exporters cannot immediately replace all the volumes displaced in the Persian Gulf. Partners abroad, however, can remain confident that US exporters are doing what they can and will remain a trusted, reliable supplier of independent energy.

While the short-term impacts will be most pronounced, over time it can be expected that a larger pool of international buyers will seek fixed, long-term supply agreements to hedge against regional volatility. Even before the Middle East conflict, a narrative had emerged amongst industry analysts fearing a potential ‘supply glut’. As recent geopolitical events show, the conversation can shift from ‘too much LNG’ to ‘securing reliable supplies’ almost overnight.

Energy finds buyers

History shows us that excess LNG does not sit idle, it creates demand.

28

North America 2026

During the COVID-19 pandemic, lower prices made US LNG accessible to new buyers in countries like India and Vietnam. Similarly, an International Energy Agency (IEA) report published in October 2025 found that buyers who were priced out during the invasion of Ukraine re-entered the market as supply increased.4 Industry leaders, including the CEO of Shell, have noted that a supply surplus can ultimately foster gas demand in new markets so long as prices remain steady.5 The world is also facing a structural surge in power demand driven by AI and data centres, creating a new wave of first-time LNG buyers. An IEA report from January 2026 confirmed that additional supply, primarily from the US, will drive further demand growth, particularly across Asian markets highly exposed to AI megatrends driving power-hungry electrification, automation, and advanced chip manufacturing.6 The takeaway is clear. The ‘glut’ narrative misunderstood how energy markets work. Demand is not static, it grows alongside supply.

Three pillars of US LNG leadership

The value of US LNG exports rests on three foundational pillars.

Economic strength

US LNG is a major driver of the domestic economy and trade.

S&P Global found that 37% of the jobs created by LNG exports were from non-producing states, as many as the number of jobs supported in Texas.7 There is a persistent, but false, narrative that exports raise natural gas prices for American families. The data does not support it. Over the last decade, US LNG exports surged while domestic prices did not. Since 2016, domestic production has outpaced export growth 3:1, and Henry Hub prices have averaged 37% lower than in the previous decade prior to exports beginning.

LNG is also helping reduce trade imbalances. According to S&P Global,8 the value of US LNG exports now exceed soy bean exports, are 2.4 times higher than corn exports, surpass revenue from American movie and TV exports, and represent over half the value of US semi-conductor exports.

The industry has a significant and growing economic footprint with benefits spread around the country, not just at the export terminals.

Geopolitical strength

US LNG reinforces global energy security. This became clear when European demand rose following the invasion of Ukraine. Analysis from the Atlantic Council confirms that US LNG strengthens alliances and expands US influence, acting as a buffer against countries that weaponise energy supplies.8 Since the invasion of Ukraine by Russia, over 60% of US LNG exports have arrived in Europe, helping blunt one of the worst energy crises in living memory. As conflict in the Persian Gulf continues, US LNG will play a key role in ensuring energy gets to where it is needed most.

As more US LNG supply enters the market by the end of the decade, the benefits will only continue to grow.

Emissions reduction

US LNG helps lower global greenhouse gas emissions. By exporting natural gas, the US helps other countries displace dirtier energy sources like coal, biomass, and dung. The IEA

notes that using LNG creates a 25% emission reduction over coal,9 and the US is deploying new technologies to drive those numbers even lower. Natural gas partners with renewable energies like solar and wind by providing the reliable, dispatchable power needed to stabilise grids during periods of intermittency, while allowing more and more renewables to enter into the market. LNG also helps reduce traditional pollutants like sulfur oxides and nitrous oxides, helping keep air clean.

The next 10 years

US LNG is an indispensable national asset. It drives economic growth, strengthens global stability, and provides a practical pathway for partners to secure reliable energy supplies amid rising demand all while reducing emissions.

At home, the US must take the steps necessary to sustain leadership by reducing regulatory hurdles, building critical infrastructure, and reforming the nation’s permitting system.

The role of US LNG, at home and abroad, cannot be overstated. America has become a global energy powerhouse, providing independent, reliable energy to partners and allies across the globe.

With one decade behind it, the US now looks to the next.

The future of US LNG is brighter than ever.

References 1.

‘North America’s LNG export capacity could more than double by 2029’, U.S. Energy Information Administration (EIA), (16 October 2025), www.eia.gov/todayinenergy/detail. php?id=66384

The Summer issue of Global Hydrogen Review is out now Read the issue here Subscribe for free:

www.globalhydrogenreview.com

2.

‘Short-Term Energy Outlook’, EIA, (7 April 2026), www.eia.gov/outlooks/steo/report/natgas.php

3.

DICK, J., ‘U.S. LNG to Supply One-third of Global Market by 2030, Tightening Price Spreads’, Natural Gas Intelligence, (28 October 2025), www.naturalgasintel.com/news/us-lngto-supply-one-third-of-global-market-by-2030-tighteningprice-spreads/

4.

‘Coming surge in LNG production is set to reshape global gas markets’, International Energy Agency, (27 October 2025), www.iea.org/news/coming-surge-in-lngproduction-is-set-to-reshape-global-gas-markets

5.

BEDESCHI, B., ‘Shell CEO says LNG glut will foster gas demand in new markets’, Gas Outlook, (12 February 2026), https://gasoutlook.com/news/shell-ceo-says-lng-glut-willfoster-gas-demand-in-new-markets/

6.

‘Growth in global demand for natural gas is set to accelerate in 2026 as LNG wave spreads through markets’, International Energy Agency, (23 January 2026), www.iea. org/news/growth-in-global-demand-for-natural-gas-is-setto-accelerate-in-2026-as-lng-wave-spreads-through-markets

7.

YERGIN, D., PASCUAL, C., STOPPARD, M., et al., ‘Major New US Industry at a Crossroads: A US LNG Impact Study – Phase 2’, S&P Global, (March 2025), www.spglobal.com/en/ research-insights/special-reports/major-new-us-industryat-a-crossroads-us-lng-impact-study-phase-2

8.

YERGIN, D., PASCUAL, C., STOPPARD, M., et al., ‘Major New US Industry at a Crossroads: A US LNG Impact Study – Phase 1’, S&P Global, (December 2024), www.spglobal. com/en/research-insights/special-reports/major-new-usindustry-at-a-crossroads-us-lng-impact-study-phase-2

9.

YERGIN, D. and JOWDY, M., ‘The importance of US LNG for economic growth and the global energy transition’, Atlantic Council, (20 February 2025), www.atlanticcouncil. org/content-series/global-energy-agenda/the-importanceof-us-lng-for-economic-growth-and-the-global-energytransition/

30

Kristy Kramer, Head of LNG Strategy and Market Development, and Dulles Wang, Director, Americas Gas and LNG Research, Wood Mackenzie, detail why US Henry Hub gas prices are set to rise.

F

or more than a decade, the US Henry Hub natural gas price held within a narrow range that made LNG economics predictable and feedgas assumptions reliable. That stability is now ending. Wood Mackenzie’s latest research sets out why prices are heading higher and what the shift means for operators, buyers, and investors across the global gas market.

The US natural gas market is entering a new phase. For most of the past decade, Henry Hub traded within a nominal range of US$2 – US$4/million Btu, a period of stability that underpinned the construction of US LNG export infrastructure and the expansion of gas-fired power generation now supporting artificial intelligence (AI)-driven data centre growth. The conditions producing that stability are no longer all in place.

Wood Mackenzie’s June 2026 Horizons report, Defying Gravity, forecasts a sustained increase in Henry Hub prices approaching US$5/million Btu in real terms by 2035. The case is grounded in structural shifts on both the demand and supply sides of the US gas market that are, for the first time in more than a decade, working in the same direction simultaneously.

Understanding the structural shift

The structural case for higher Henry Hub prices rests on two forces converging at the same time. Demand is rising faster than the US gas market has previously had to accommodate, while the supply base is maturing and the cost of growing production is increasing.

Neither condition is short-term in nature.

Henry Hub also functions, to a significant degree, as a localised price shaped by supply, demand, and infrastructure conditions in southern Louisiana. As demand and export growth concentrate in Texas and Louisiana, the benchmark is increasingly influenced not by the lowest-cost supplies hundreds of miles away, but by the

investment in midstream infrastructure required to bring those molecules to the region. New pipeline developments covering longer distances require greenfield investment and face increased local opposition, state-level regulatory intervention, and litigation.

Henry Hub is therefore rising not only with underlying supply costs, but also with growing midstream costs.

Power sector demand growth

Data centres and AI investment are placing significant new load on the US electricity grid, and gas-fired generation is absorbing a substantial share. Wood Mackenzie estimates that an additional 17 billion ft3/d of gas-fired generation will be required by the mid-2030s to meet power sector demand from these sources, a near-50% increase from 2025 levels.

The power sector’s increasing reliance on gas to balance intermittent renewable generation has also changed the character of demand: swings have become structurally more pronounced, weather events amplify price movements, and storage capacity – long underinvested relative to the demands now placed on it – is not absorbing those movements effectively. Geopolitical developments, including the ongoing conflict in the Middle East, have demonstrated their capacity to rapidly reshape global gas flows with a direct read-across to US pricing. Near-term volatility is, in this context, a symptom of the same structural tightening that underpins the long-term forecast.

LNG export capacity expansion

The second major demand driver is the continued expansion of US LNG export capacity. Approvals for new capacity reached a record high in 2025, with further projects reaching final investment decision in 2026. US LNG capacity is forecast to more

31

than double from current levels. By the early 2030s, the US is expected to account for more than one-third of global LNG supply, a concentration that is already beginning to reshape how buyers approach long-term contract negotiations.

As the marginal supplier to the global LNG market, the US would feel any slowdown in demand growth disproportionately.

Buyer concerns about over-concentration of supply are emerging, and conflict-driven pressure to diversify could provide momentum for LNG projects outside North America – Argentina is a credible recent example of this. Should those projects advance at scale, the share of incremental demand flowing to US facilities could reduce.

US LNG’s scale is currently a commercial strength. At sufficient concentration, it risks becoming a liability when buyers begin to treat supplier diversity the way they treat shipping routes or counterparty risk.

The aggregate demand picture from both the power sector and the LNG export market points to continued expansion into the 2040s, with limited near-term opportunities for meaningful substitution.

Declining impact of associated gas

Over the past decade, gas produced as a co-product of oil drilling at near-zero marginal cost accounted for roughly half of all US gas supply growth. Permian-driven associated gas volumes, at their peak, materially offset the need for dedicated gas drilling, suppressing the price signal required to incentivise new supply.

That dynamic is changing.

As the Permian Basin matures and more operators focus on margins over volumes, associated gas is forecast to account for less than 20% of US supply growth over the next 10 years, compared with approximately 50% over the previous decade. The gap will need to be filled by dedicated gas-focused drilling – at higher cost, and only at higher prices.

Exploration and production capital discipline

Listed US exploration and production companies are not about to accelerate drilling without a clear and sustained price signal. Capital discipline remains the defining feature of the sector. Operators are committed to returning cash to shareholders before committing to incremental production and will choke back output when cash prices fall below operating costs. With the elasticity of supply to price lower than it has historically been, Henry Hub will need to rise further, and hold for longer, before investment follows.

Not all capital in the sector behaves in the same way. Operators with firm supply commitments to LNG export facilities can invest against long-term contract values rather than local spot economics.

Factors that could temper the outlook

Wood Mackenzie is direct that reversing the price forecast would require a major shift on the demand side – a significant slowdown in power sector consumption or a fundamental reshaping of global LNG trade flows. Supply-side developments, while worth monitoring, are more likely to moderate the pace of price increases than to prevent them.

On the supply side, the revival of dormant plays such as tight gas acreage in the Rockies, or frontier resources including the western extension of the Haynesville/Bossier and deep gas along the Texas Gulf Coast, could add a few billion cubic feet per day in aggregate. The firm characterises this as meaningful at the margin.

A pipeline renaissance is a further wildcard: an easing of the regulatory and opposition barriers that have stifled new interstate pipeline development could compress basis differentials and moderate Henry Hub. Some barriers may be softening, but lead times remain long.

On the demand side, a slowdown in AI-driven power consumption, through chip efficiency improvements, a correction in technology investment, or advances in battery economics, would carry direct price implications. A political shift in US energy policy after the current administration could also accelerate the deployment of clean energy in ways that reduce gas intensity over time.

Implications for LNG market participants

Even with the forecast increase, Wood Mackenzie notes that Henry Hub will remain globally competitive. For domestic US producers, structurally higher prices translate into rising margins.

For other market participants, the structural shift in what drives Henry Hub pricing is prompting a strategic reassessment across the value chain.

For LNG buyers, the concentration of US supply at more than one-third of global LNG by the early 2030s is already shaping how contracts are approached. Buyer concerns about over-reliance on a single supply source are emerging, and geopolitical considerations are adding further impetus to supply diversification. This dynamic could provide meaningful tailwinds for LNG projects outside North America as buyers look to manage concentration risk with the same discipline they apply to shipping routes and counterparty diversity.

For companies holding material Henry Hub supply positions, the evolving price environment is prompting active portfolio management. The approaches vary. Some operators are responding through contracting solutions that index supply to international price signals rather than local Henry Hub economics; others, including internationally-backed operators with Haynesville positions, are investing upstream in ways that reflect longer-term contract values. Traders with broader value-chain positions are finding further ways to capture spread dynamics as they evolve.

For project developers finalising financing cases and for buyers currently in long-term offtake negotiations, the direction of Henry Hub pricing is now a central variable rather than a stable background assumption. The strategies being deployed today will determine how individual market participants are positioned as the structural shift in US gas pricing plays out over the next decade.

Note Figure 1. US gas demand into power by forecast vintage

– AI/data centres are boosting demand materially. Source: Wood Mackenzie Lens Gas & LNG; vintages annual Strategic Planning Outlooks.

32

North America 2026

Wood Mackenzie’s Horizons report, Defying gravity: why US Henry Hub natural gas prices are set to rise, is available on the Wood Mackenzie website: www.woodmac.com/horizons/ why-us-henry-hub-natural-gas-prices-are-set-to-rise/

With 16 of its 19 modules now on site, 65% of construction complete, and a second floating workforce vessel in operation, Woodfibre LNG demonstrates how a project that began going vertical just one year ago is now charging towards commissioning.

T

he global energy landscape has rarely offered a clearer argument for Canadian LNG. As geopolitical and trade turmoil continue to reshape traditional supply chains, and Asian economies double down on natural gas as a bridge fuel, the window for shipping reliable, lower-carbon LNG supply from Canada’s Pacific Coast has never been wider. Against that backdrop, Woodfibre LNG, the single-train liquefaction and export facility under

construction near Squamish, British Columbia, has spent the past year steadily making progress on bringing new Canadian LNG to global markets.

The results are visible. The project site that had just begun to ‘go vertical’ in May 2025 by setting its first modules in place, is now unrecognisable from what it was one year ago. All major modules have been delivered as of March 2026, with the delivery of the liquefaction and

33

powerhouse modules. Personnel are joining the project in greater numbers. A second floating accommodation vessel (floatel) is on the water, enabling an additional 650 on-site construction personnel to push the project across the finish line. The story of Woodfibre LNG in 2026 is no longer one of groundbreaking ambition, but one of execution.

A facility takes shape through modular design

From the outset, Woodfibre LNG’s project team chose modular construction as the right approach for this site, and the past year has demonstrated why. Building major process units at the QMW McDermott Fabrication Yard in China, rather than a stick-built construction approach, has enabled Woodfibre to adhere to its construction goals while reducing its environmental footprint. The modules are assembled under controlled conditions that foster replicable high-quality craftsmanship and robust quality assurance and testing, before being delivered by sea from a location that has no chokepoint standing in the way of Canada’s west coast.

The marine offloading facility (MOF), completed in May 2025 and engineered to handle modules exceeding 11 000 t, has been a workhorse within this strategy. Built on 169 steel piles driven into the seabed, it has served as

the primary gateway for every module that has arrived at Woodfibre LNG – 16 to date, with the final three still to come.

The centrepiece of the site, and the milestone that most visibly marks the project’s maturation, has been the arrival and installation of the liquefaction module. Now that it has been successfully delivered, the heavy foundation work that dominated earlier phases has given way to the complex mechanical, piping, and instrumentation integration that defines a facility entering its final construction stages.

Earlier module deliveries laid the groundwork for this moment. The seven pipe rack modules that arrived in May 2025, each a fully constructed steel framework for routing process piping, cable trays, and utilities, established the infrastructure corridor connecting the liquefaction unit to the project’s floating storage tanks (FSTs) and LNG loading area. The boil-off gas compressor module, weighing roughly double the combined tonnage of those first seven pipe racks, is critical for managing vaporised LNG within storage tanks by recompressing it back into the liquefaction system. Subsequent deliveries brought the feed gas pretreatment module, which removes water, carbon dioxide, and other impurities from the incoming natural gas stream before it enters the liquefaction train, and the knock-out drum module, which removes liquids and particulates from the gas feed.

The use of self-propelled modular transporters (SPMTs) to move completed units from the MOF to their permanent foundations has been one of the innovative aspects of the build. These hydraulically-controlled, computer-guided platforms can carry loads of extraordinary weight with millimetre-level precision, positioning modules on foundations prepared to exact tolerances. The efficiency gains relative to conventional stick-built construction are significant: complex process systems that would otherwise require thousands of individual work hours on site arrive pre-assembled, pre-tested, and ready for integration.

The integration challenge ahead

Figure 1. Work continues on Woodfibre LNG’s marine

infrastructure with the facility’s floating storage tanks due to arrive late in 2026.

Figure 2. Together, the MV Saga X (left) and MV Isabelle X

house roughly 1300 tradespeople and construction workers just minutes from the project site.

34

North America 2026

Delivering modules to site is one achievement. Integrating them into a functioning plant is another, and it is the defining challenge of the construction phase now underway. While the arrival of the liquefaction and powerhouse modules signals how far the project has come, the scope of what remains is a reminder of how much complexity is woven into a facility of this kind.

More than 450 km of power, instrumentation, and control cabling must be pulled throughout the facility to connect every module and system into a single, functioning whole. That task alone will take several months to complete. More than 5 km of welding is required to tie modules together at their process connections, work that must be executed to exact codes and verified through rigorous testing protocols. These are not finishing touches; they are fundamental to the facility operating safely and efficiently.

Alongside the integration of the modules already on site, the project is beginning construction of the permanent operations buildings that will be needed once the facility moves from construction to commissioning and commercial operation. Warehouses, control rooms, and associated infrastructure are taking shape – further evidence of a

site transitioning from a construction zone into an operating plant.

The last few modules and the FSTs, which will hold LNG on site for loading onto carriers, are expected to arrive in late 2026. With an LNG carrier expected to show up approximately every 10 days once the facility is in commercial operation, the FSTs and their associated modules will be the last major structural components standing between Woodfibre LNG and its first cargo.

Building the team that will run the plant

Construction milestones may get the most headlines but, for a facility approaching completion, the workforce story at Woodfibre is shifting.

The project has now hired around 27% of its full-time operations staff, with ambitious recruitment continuing as the project moves towards commissioning. This matters for reasons that go beyond headcount. Operations personnel are not simply employees who will eventually show up for the first day of work once the facility is running. In a commissioning process, they will be active participants – the people who will walk the systems from cold steel to live plant, and whose deep familiarity with the facility’s design and intricacies will be essential when the first gas flows through the liquefaction train.

Integrating operations personnel early is an approach that reflects lessons learned from other major LNG projects. It compresses the knowledge curve, reduces the risk of handover gaps between construction and operations teams, and accelerates the path to stable commercial production. Building Woodfibre’s operations team now, while modules are still being installed, is a deliberate choice with long-term payoff.

The project’s Operator Training Program, developed in partnership with SḵwẊwú7mesh Úxwumixw (Squamish Nation) Training and Trades Centre and the British Columbia Institute of Technology (BCIT), has been an important part of training the operators of the future facility. Following the graduation of the first two Indigenous operators from the programme in May 2025, additional trainees are progressing through the three-phase curriculum, from foundational skills training through power engineering certification and into live operations experience at the Woodfibre LNG Vancouver office and the project site near Squamish.

Working with Squamish Nation to develop career opportunities for Indigenous Peoples at Woodfibre LNG has been a priority for the company and maintain the spirit of Swiy̓át (the name of the historical Squamish Nation village that occupied the site) lives on as a place of work.

The second floatel: Expanding capacity, maintaining high standards

When Woodfibre LNG announced in May 2025 that it intended to apply for regulatory approval for a second floatel, the intent was clear: to expand the project’s workforce capacity to meet the demands of an accelerating project build. That second floatel, the MV Saga X, arrived on site in November 2025, and is now

Figure 3. The process utility module, along with the

pretreatment module, getting set to be unloaded at the marine offloading facility.

Figure 4. The ‘heart’ of the Woodfibre LNG facility, the

liquefaction module (centre) will produce 2.1 million tpy of LNG for export.

Figure 5. Heavy cargo transports carrying facility modules, like the Seaway Swan pictured here, have been a frequent sight on the waters of Átl’ka7tsem (Howe Sound) over the last year.

fully operational and housing hundreds of new construction workers at Woodfibre LNG. The success of Woodfibre’s first floatel, the MV Isabelle X, which has been in continuous operation since June 2024, made the benefits of a second deployment clear. Operational data from the Isabelle X’s first year demonstrated how effectively the floatel model reduced community impact by having all construction workforce based at site aboard ship, which allows the project to avoid impacting Squamish’s already tight housing supply and

North America 2026

35

creating additional pressure on community services.

For example, only 11 emergency room visits from Woodfibre LNG workers were recorded at the Squamish General Hospital over the year, a result directly attributable to the vessel’s onboard medical clinic.

Beyond sheltering the community from the strain of a surge in residents, the floatel has also proven to be a preferred housing option for the construction workforce.

Resident satisfaction surveys showed 71% of respondents rating the experience as high quality relative to other remote work camps.

The Saga X follows the same housing formula as the Isabelle X, providing roughly 650 individual cabins with dedicated en-suites along with extensive onboard recreation options and a gourmet quality food service throughout the day. The Saga X also offers some new amenities to the construction workforce including a 200-seat auditorium and an outdoor basketball court.

The Saga X also mirrors the environmental and operational standards of the Isabelle X. It is connected to BC Hydro’s clean hydropower grid via shore connection, eliminating diesel-powered boilers. Electric heat pumps provide heating, cooling, and hot water.

The same workforce protocols apply: mandatory cultural and gender safety training, strict access restrictions to local communities during rotations, and dedicated security arrangements. Together, the two vessels extend the project’s peak workforce capacity to approximately 1500 workers, the scale needed to pursue a construction schedule that brings Canadian LNG to overseas markets as soon as possible.

Kelp, currents, and marine life

Not everything at Woodfibre LNG is measured in module tonnage and workforce targets. The project’s environmental conservation and emissions reduction commitments have continued to advance along a parallel track.

The project has been supporting local experts working on important kelp reforestation initiatives. The Nexwnéwu7ts Átlḵ’a7tsem (Howe Sound), the fjord in which the Woodfibre LNG site sits, has undergone significant ecological recovery over the past two decades following earlier industrial use of the waterway. Kelp forests, which provide critical habitat for fish and invertebrates,

Figure 6. Marine mammal monitors, supported by an

extensive system of hydroacoustic technology, continually scan for marine mammals near the project site.

36

North America 2026

are central to that continued recovery. Woodfibre LNG has been supporting ongoing research and restoration work around kelp transplantation and seeding in Howe Sound, contributing to the understanding of kelp ecology in the region, the conditions that support its continued health and the ongoing monitoring of kelp growth.

Woodfibre also manages a rigorous Marine Mammal Monitoring Program (MMMP) for its site, a central component of the project’s commitment to environmental stewardship and Indigenous-led oversight within the UNESCO Biosphere of Howe Sound. Developed in partnership with the SḵwẊwú7mesh Úxwumixw, the programme exists to protect sensitive marine species from underwater noise and construction activities through a rigorous, real-time mitigation framework. With an advanced array of 15 observation posts, seven hydroacoustic monitors, and six patrolling boats, the system enables Woodfibre to identify species – such as orcas, humpback whales, and seals – and automatically halt construction via ‘red light’ orders if animals enter designated exclusion zones. The programme successfully managed 830 work stoppages or delays to protect marine life in the 2024 – 2025 construction period.

These two initiatives are emblematic of Woodfibre’s much larger commitment to protecting the climate, species, habitats, and surrounding communities. A fully electrified liquefaction process, carbon offsets, advanced systems to reduce flaring, water treatment, and recycling systems at site and on the floatels – all are woven into the fabric of this project.

Canada’s LNG moment

The macro-economic context in which Woodfibre LNG is completing its construction has shifted dramatically from when the project broke ground. International demand for LNG has continued to grow as energy security concerns in Europe and Asia translate into long-term supply diversification strategies. Buyers who once treated spot market access as sufficient are now seeking the kind of contracted supply that long-established LNG exporters have reliably delivered for years – and that Canada, with its world-class Montney gas resource and Pacific coast access to Asian markets, is uniquely positioned to offer.

While Woodfibre is not the largest LNG project Canada has produced, it is, in many respects, a model for what responsible large scale industrial development in Canada can look like.

It is modular, efficient, and electrified with renewable hydropower. It is the first project in Canada to recognise a non-treaty Indigenous government, the SḵwẊwú7mesh Úxwumixw, as a full environmental regulator. It will be the first export facility in Canada to achieve net-zero emissions in its operations. It manages its construction workforce in a way that protects rather than burdens the community in which it operates.

When the first LNG carrier departs Howe Sound, it will carry more than Canadian natural gas. It will carry a proof of concept: that it is possible to build a major LNG export facility that is technically sophisticated, commercially viable, environmentally responsible, and socially grounded.

Construction is not done yet, but Woodfibre is already a pioneer in building projects the right way.

Rebecca Scott, Western LNG, Canada, establishes why Canada’s Pacific Coast is emerging as one of the most compelling new LNG supply options globally.

T

he recent crisis in the Strait of Hormuz will be remembered as the most severe disruption to global oil and gas markets in modern history – not simply for what it halted, but for what it revealed. It exposed, with startling clarity, the fragility of global energy supply chains and the extent to which the world’s energy system remains vulnerable to geopolitical shock.

For the LNG industry, the takeaway is clear. Diversifying supply away from potentially conflicted geographies is no longer a theoretical exercise in risk management; it has become a commercial imperative. In that context, Canada’s Pacific Coast is emerging as one of the most compelling new LNG supply options globally.

A short, unobstructed path to Asia

British Columbia’s northwest coast offers the shortest sailing distances to Asia in the Americas. Cargoes from Canada’s Pacific terminals reach key Asian markets in roughly half the time required from the US Gulf Coast, where shipments must transit congested canals or significantly longer alternative routes.

For example, Ksi Lisims LNG estimates one‑way transit times of 11 days to North Asia, compared with roughly 22 days from the US Gulf Coast via the Panama Canal and more than 30 days via the Suez route.

Shorter voyages reduce shipping costs, lower boil‑off losses, improve fleet utilisation, and enhance delivery reliability.

37

Just as importantly, Canada’s west coast route avoids maritime chokepoints entirely, offering open‑ocean access from load port to destination.

Rule of law, responsible supply, and strong government backing

Beyond proximity to Asian markets, Canada offers what buyers prize most: predictability.

Canada’s legal framework, abundant low‑cost natural gas supply, and long history as a reliable trading partner have underpinned an accelerating LNG buildout. That momentum has been reinforced by Ottawa’s stated ambition to position Canada as a global energy superpower.

Recent permitting decisions also reflect that confidence. In the past six months, Ksi Lisims LNG has secured environmental approvals from both the federal and provincial governments as well as an LNG facility permit, making the project fully approved and shovel‑ready.

The federal government has since referred Ksi Lisims LNG to its Major Projects Office as a project of national interest, signalling a clear intent to see the project advance.

De‑risking by design

Canada’s stable but stringent regulatory environment is shaped by high public expectations that major projects go beyond minimum standards to mitigate social and environmental impacts, driving design choices that materially reduce execution risk.

For example, in choosing a floating design led by Black & Veatch and Samsung Heavy Industries, Ksi Lisims LNG shifts critical fabrication to experienced shipyards in South Korea. By minimising greenfield construction at site, the project reduces workforce, environmental disturbance, and schedule uncertainty, resulting in a more predictable capital profile and a lower‑risk path to first cargo.

Equally important to Canadians is the meaningful participation of impacted First Nations. Co‑developed and hosted by the Nisga’a Nation on its treaty lands, Ksi Lisims LNG reflects a modern Canadian model of Indigenous partnership grounded in legal certainty and long‑term stewardship.

Upstream risk is similarly mitigated through Rockies LNG, a consortium of Canada’s leading natural gas producers representing approximately half of the country’s natural gas production and reserves. By aggregating supply from multiple well‑capitalised operators across the Western Canadian

Figure 1. Artist rendering of Ksi Lisims LNG project.

38

North America 2026

Sedimentary Basin, Rockies LNG provides scale, redundancy, and resilience, reducing dependence on any single producer and ensuring consistent feed gas availability over the life of the project.

Ksi Lisims LNG will be supplied via the Prince Rupert Gas Transmission (PRGT) pipeline, a 750‑km, fully-permitted project acquired in 2024 by Western LNG and the Nisga’a Nation from TC Energy. With agreements in place with the majority of right‑of‑way Nations and a clear path to completing the remainder, PRGT further reinforces the project’s execution certainty.

A quantifiable environmental edge

Cool ambient temperatures, access to clean grid power, stringent emissions regulation, and shorter shipping distances give Canadian west coast LNG a carbon advantage. As a result, projects in British Columbia are consistently benchmarked at less than half the global average emissions intensity for LNG facilities.

Independent analyses also show that Canadian LNG displacing coal in Asian power markets can reduce sector emissions by approximately 50%. Even when replacing other LNG supply, Canadian projects can deliver meaningful lifecycle emissions reductions, supporting buyer decarbonisation strategies without compromising energy security.

Ksi Lisims LNG exemplifies this advantage. The facility will be powered by British Columbia’s hydroelectric grid using electric‑drive compressors, enabling one of the lowest carbon intensities in the global LNG industry (estimated at approximately 0.02 t of CO₂-e/t of LNG). Once fully connected, it is expected to become Canada’s first net‑zero large scale LNG export facility, allowing buyers to embed a lower lifecycle emissions profile directly into customer disclosures.

An adaptive and modern supply strategy

History will likely judge the Strait of Hormuz crisis not as a singular disruption, but as a turning point for global energy strategy. The episode underscored a reality the industry has long understood but rarely had to confront so directly: peace and stability along even the most established global shipping routes can no longer be assumed.

What comes next is adaptation. As portfolios are rebalanced and future contracts shaped, LNG buyers are placing greater emphasis on shorter shipping routes, open‑ocean transit, and geopolitical security.

Canada offers these advantages and more: stable trade partnerships, rule of law, and some of the lowest‑carbon LNG molecules available at scale.

The federal government aims to quintuple its current LNG export capacity over the coming decade, and given its advantages, it may well meet or exceed that target.

Ksi Lisims LNG brings those advantages together in a single project: full regulatory approvals and strong government backing; best‑in‑class, de‑risked floating LNG engineering and construction; grid‑powered electrification on a clear pathway to net zero; and Indigenous co‑development that reflects rights‑holders actively choosing to participate in, and help shape, the next chapter of the global LNG industry.

Rob Shaul, McDermott Senior Vice President, Low Carbon Solutions, UK, looks at how large scale modularisation is leading the next wave of LNG projects.

A

s global energy dynamics evolve and LNG demand continues to grow, project delivery models are being re‑evaluated to improve delivery, efficiency, and cost control. Demand projections from the International Energy Agency and Shell point to consumption surpassing 600 million tpy by 2040, driven by Asia’s continued industrialisation, Europe’s post-Russia energy diversification, and emerging markets in South America and Africa seeking a reliable, lower-emission bridge fuel. That trajectory represents annual growth of 3 – 4% over the next 15 years – a powerful signal for developers and contractors alike.

Yet, the momentum of LNG expansion is meeting significant resistance in the form of escalating capital costs and constrained labour markets. On the US Gulf Coast alone, more than 80 million tpy of LNG capacity is under development, and project CAPEX has inflated by nearly 20% since 2022. While material supply chains have changed substantially in the post-COVID era, a major factor is the dominance of stick-built construction that exposes projects to qualified craft labour shortages, weather-related productivity losses, quality control variability, and heightened community impact. In a region where energy sector and data centre construction activity is already

39

stretching available labour resources, these headwinds are structural rather than cyclical.

The industry needs a different approach; one that transfers risk from the field to the factory, provides greater certainty with schedules, reduces on-site labour demand, and delivers more LNG output from a smaller physical footprint. Large scale modularisation is that answer, and McDermott and ConocoPhillips have spent a significant amount of time developing and refining a standardised solution to deliver it.

The modular paradigm: From offshore to onshore

The origins of McDermott’s onshore modular LNG design lie in an earlier collaboration with ConocoPhillips on a nearshore floating LNG concept. That work forced both organisations to think rigorously about spatial efficiency: how does one pack maximum processing capacity into a constrained envelope while preserving safety, operability, and maintainability? The answers developed for the marine context translated directly – and powerfully – to onshore applications.

The result is a standardised modular LNG plant design built around ConocoPhillips’ Optimized Cascade® Process (OCP), a technology with more than 50 years of operating history and over 120 million tpy of licensed global capacity.

The OCP’s architecture – three multi-staged, cascaded refrigerant circuits using pure refrigerants and brazed aluminium heat exchangers – lends itself naturally to modularisation. Its compact, systemised configuration minimises the number of inter-module connections, supports maximised pre-commissioning in the fabrication yard, and enables the layout densities required to achieve meaningful footprint reduction.

McDermott’s role brings a complementary capability: more than 100 years of large scale module design and fabrication, honed through offshore projects where weight, footprint, and structural integrity are existential engineering constraints. By applying an offshore module philosophy to onshore LNG – engineering mega-modules of up to 80 m long, 40 m wide, and 45 m tall, weighing 10 000 t or more – the collaboration targets a performance envelope stick-built projects simply cannot match.

Maximising LNG output per square metre of plot

One of the most commercially compelling metrics in modern LNG development is production per unit of land area. Real estate constraints on prospective US Gulf Coast sites (compounded by

Figure 1. Module Optimized Cascade® Process design

overlayed on typical stick-built plot. Source: Google Earth 2025.

40

North America 2026

permitting complexity, environmental sensitivity, and community considerations) are increasingly shaping project feasibility. The ability to produce more LNG per square metre is not merely a technical achievement; it is a commercial differentiator.

Internal modularisation studies using the OCP design have demonstrated a more than 50% reduction in plot area compared to equivalent stick-built facilities on the US Gulf Coast. By increasing on-module equipment density, the design shortens piping runs, reduces electrical and instrumentation cable lengths, and minimises the earthworks, piling, and concrete foundations that contribute significantly to stick-built costs. The land freed by this compact configuration can accommodate additional LNG trains, laydown areas, or supplementary process units such as carbon capture systems – all critical to project economics and long-term flexibility.

Importantly, higher equipment density is not achieved by simply packing equipment closer together. It requires detailed material handling studies to preserve crane and forklift access for routine maintenance and major overhauls. Reserve maintenance volumes are built into the 3D design model. Monorail capacity, hoist locations, and emergency egress routes are engineered from day one. The result is a facility that is dense but not cramped – optimised for both construction efficiency and operational reliability over a multi-decade lifecycle.

Benefits beyond economics

Cost reduction is the headline benefit of modularisation, but it is far from the only one. The advantages span the entire project lifecycle.

On cost, evaluations indicate a 15 – 25% CAPEX reduction potential vs stick-built baselines, contingent on logistics and site-specific conditions. Site workhours can be reduced by 60 – 70%, since the majority of assembly occurs in controlled fabrication yards. In regions with high labour costs or skilled labour scarcity (conditions endemic to the US Gulf Coast), this shift in where the workhours are spent is particularly impactful.

For schedule, modularisation enhances predictability by isolating fabrication from the weather, labour risks, or unique environmental windows that dominate stick-built timelines.

Module fabrication proceeds in parallel with site preparation, reducing the compounding delays that can cascade through traditional construction sequences. Fewer site activities mean fewer interfaces where disruptions can propagate.

As for safety and quality, a fabrication yard is a fundamentally different environment from a construction site. Controlled conditions enable improved oversight, better access to specialised equipment, and more thorough quality assurance protocols. Non-destructive testing, pre-commissioning activities, and compliance verification all occur in the yard before modules are shipped, reducing the likelihood and cost of rework during final integration. This approach consistently delivers higher-quality outcomes while reducing lost-time incidents.

Sustainability metrics also improve. McDermott’s analysis indicates that modularisation achieves approximately a 20% reduction in carbon footprint during the execution phase relative to stick-built construction. Concentrated fabrication in specialised facilities enables more efficient, less carbon-intensive processes.

As module fabrication yards increasingly source sustainable energy, this advantage is expected to improve further.

On community impact, reducing on-site headcount directly reduces the demand for temporary workforce housing,

A new podcast for LNG industry professionals, brought to you by LNG Industry

t s a c Pod

Never miss an episode - subscribe to the LNG Industry Podcast at the link below or on your favourite podcast app.

www.lngindustry.com/podcasts

support infrastructure, and local services. A smaller construction footprint means less land disturbance, reduced noise and traffic, and a lighter community footprint throughout the construction phase.

Engineering for modular realities

The benefits of modularisation are not automatic; they require disciplined engineering attention to challenges that do not exist or exist in a fundamentally different form to stick-built projects.

Transport stability is one such challenge. Mega-modules must be designed to withstand the dynamic loads of lifting, sea transport, and on-site transportation, including accelerations, wind forces, and vessel motions. The module envelope must comply with port constraints and road transport limitations that govern maximum width, height, and weight thresholds.

McDermott’s fabrication yards have recently executed the load-out of multiple modules for a North American LNG project, several of which exceeded 10 000 – 12 000 t – validating the practicality of the mega-module concept at commercial scale.

Safety engineering for compact module layouts requires additional rigour around blast overpressure analysis, jet fire and cryogenic spill scenarios, and pressure vessel survivability. Passive fire protection coatings, blast walls, and strategic equipment positioning are integrated into the design to mitigate consequences from potential loss-of-containment events. Human factors engineering – ensuring accessible control room interfaces, adequate valve access, and clear emergency egress – is embedded from the earliest design phases rather than treated as a downstream check.

Logistics planning is the third discipline that can make or break modular execution. Heavy-haul transport requires co-ordination with specialised vessels, trailers, and port facilities.

Route surveys must confirm that roads, bridges, and infrastructure can handle oversized loads. Installation methodology, whether using heavy-lift cranes or self-propelled modular transporter (SPMT) systems, must be defined during front-end engineering, not resolved in the field. McDermott’s track record with SPMT load-outs for large modules demonstrates that these logistical challenges are manageable with appropriate planning.

Commissioning: The yard as a pre-operations environment

One of the most underappreciated dimensions of the modular approach is its impact on commissioning. In a well-executed modular project, the fabrication yard functions as a pre-operations environment, not merely a construction facility.

Figure 2. Recent mega-module load-out from McDermott’s

module yard using a self-propelled modular transporter system.

42

North America 2026

Pre-commissioning activities performed in the yard before shipment include piping system flushing and air blowing to remove debris, hydrostatic and pneumatic pressure testing to verify integrity, loop testing and calibration of instrumentation, electrical continuity checks, and control valve response verification. Subsystem boundaries – refrigeration loops, power distribution, control systems – are aligned and tested against their design specifications before a module leaves the yard.

This strategy means modules arrive at the project site in near-ready-for-start-up condition. Integration work is reduced to tie-ins between pre-tested subsystems, with clear documentation and tagging to guide the final commissioning sequence. The practical result is fewer site work hours, more certain schedule progression through mechanical completion, and higher confidence in first-gas timing, a critical metric for LNG project economics given the capital deployed.

Realising success

McDermott is using the modular design philosophy described here not just in theoretical terms, but actively shaping the next generation of LNG infrastructure.

McDermott’s master services agreement with Monkey Island LNG demonstrates the approach in action. The project involves front-end engineering and planning services for a world scale natural gas liquefaction facility in Cameron Parish, Louisiana. By utilising McDermott’s compact modular LNG train design and the ConocoPhillips OCP, the project is targeting delivery of up to 60% more LNG per acre than comparable facilities – a metric that speaks directly to the land-efficiency advantage of the modular paradigm.

The Woodfibre LNG project in British Columbia, Canada, provides another reference point. Leveraging modular construction from McDermott’s QMW fabrication yard in Qingdao, China, alongside integrated project delivery, Woodfibre is demonstrating how modularisation can streamline execution and reduce on-site complexity in an environmentally sensitive, geographically constrained setting – precisely the conditions where stick-built construction struggles most.

Shaping the next wave and future outlook

As the LNG industry looks towards its next cycle of investment decisions, the competitive landscape has shifted. Final investment decisions are under pressure from cost escalation and schedule risk. Skilled labour on the US Gulf Coast is a constrained resource that will only become more contested as demand for domestic power generation and associated infrastructure continues to increase. Additionally, the social and environmental license to build large infrastructure is more carefully scrutinised than at any point in the industry’s history.

Large scale modularisation addresses each of these pressures directly. It transfers labour from the field to the fabrication yard, secures schedule certainty by enabling parallel workstreams, reduces the community footprint of construction, and lowers the carbon intensity of project execution. It standardises design to reduce engineering variability and improve cost predictability across multiple trains and projects.

The message is clear for the next wave of LNG development: success will be defined not only by scale, but by agility, sustainability, execution excellence, and capital efficiency. Large scale modularisation is not a future option; it is a present imperative.

Melanie Lovatt, Finance Adviser, Poten & Partners’ Business Intelligence Division and Managing Editor of LNG Finance in World Markets, provides an insight into current US LNG export project financing behaviour and highlights future growth.

U

S LNG export project finance reached record levels in 2025, and the momentum continued into 2026 as another large US deal was completed. More North American developers are targeting final investment decisions (FIDs) and looking to raise capital, with projects appearing set to benefit from the focus on security of supply after the Iran war upended previous forecasts of a growing LNG surplus.

US LNG producer, Venture Global, closed US$8.6 billion in new debt financing in March 2026 to build the 5.6 million tpy Phase 2 expansion of its CP2 LNG export project. This comes after externally-raised finance for global liquefaction projects hit a record of US$83 billion in 2025, according to estimates

by Poten & Partners (Figure 1). US developers propelled LNG financing to new highs in 2025 as they made FIDs on an unprecedented six export projects.

43

Of the US$83 billion in external finance raised globally for liquefaction, almost US$79 billion was focused on North America. The bulk of this went to the US projects that made FID and also included some transactions to refinance project debt and finance pre-FID activities, such as permitting processes.

The six US projects making FID in 2025 used a variety of financing methods: NextDecade’s Rio Grande Train 4 and Train 5 projects and Venture Global’s CP2 LNG Phase 1 project used classic project finance structures, while US investment firm, Stonepeak, used a back-leveraged project financing structure for its purchase of a stake in Woodside’s Louisiana LNG. Sempra’s Port Arthur Phase 2 focused on raising third party equity, while Cheniere’s Corpus Christi LNG mid scale trains 8 and 9 project did not need external finance.

Equity was also financed by commercial banks or institutional investors for CP2 LNG Phase 1 and Rio Grande Trains 4 and 5.

Despite US projects enjoying strong bank interest and being able to tap liquid capital markets, the increase in equity raising in 2025 by developers suggests an impetus to offload risk onto others due to the high capital outlay for liquefaction projects. LNG export terminals are among the most expensive projects of any sector and costs have been increasing over the last few years on rising labour and raw materials prices.

Figure 1. Liquefaction finance by year.

Bank appetite remains hearty for US LNG deals

The commercial bank loans supplied for the US project financings completed in 2025 were in a range of 200 – 275 basis points (bps) over the secured overnight financing rate (SOFR). The margins for CP2 LNG Phase 2 remained the same as Phase 1, which was completed in 2025, at 225 – 275 bps over SOFR. These are attractive levels. Coupled with the ability of each project to attract a lineup of 15 – 30 lenders, this suggests commercial banks have a strong appetite to provide loans to US LNG export projects.

While a few commercial banks have exited or reduced LNG lending as they try to reduce loan portfolios’ exposure to fossil fuels, others are looking to fill the gap.

In Poten’s 2026 commercial bank rankings, which is based on 2025 financings, and appears in the ‘LNG Finance in World Markets’ quarterly research report, the tone for placement was set by contributions to these US export projects, with the big international project finance lenders across Japan, Europe, the US, and Canada continuing to provide large loans to the sector.

Japanese banks took the top three places in Poten’s 2026 ranking of LNG project finance lenders, as they also did in 2023 and 2021. Japan’s MUFG climbed the ranking and was first after coming second in 2024 and third in 2023 and 2021.

Also in the top ten were three banks from Europe: the UK’s Standard Chartered; Spain’s Santander and BBVA; JPMorgan from the US; and three Canadian banks tied in seventh place which were National Bank of Canada, Royal Bank of Canada, and Scotiabank.

Some European banks, especially those in France that are being pressured by climate change activists, have reduced their support to projects that secure gas from fracking and, as a result, have seen their positions slip down the ranking over the last several years because US LNG export project financing prevailed; US projects dictated the 2024 and 2023 rankings as well as the current one.

Poten data shows a total of 69 commercial banks from 21 countries provided bank loans worth US$42.6 billion for LNG project finance in 2025. This surpassed the total of US$12 billion in 2024 (which dictated the 2025 ranking) when the pause in issuing US non-free trade agreement export licenses and stricter criteria for extensions meant there were no US LNG export project FIDs that year.

Most of the US liquefaction finance deals closed in 2024 were refinancings of debt raised in previous years for projects that were completed or already under construction.

Project finance loans and equity contributions dominate financing Figure 2. North American liquefaction financing.

44

North America 2026

Commercial bank loans supplied in project finance structures were the prevailing finance

Clive Zanker, Chair of UKOPA.

Elizabeth Corner

30 years of UKOPA: Safety, stewardship and the energy transition

A conversation about the origins of UKOPA and how the sector has changed over the last three decades: from the development of robust safety frameworks and industry standards, to today’s conversations around energy transition, decarbonisation, and public perception. Featuring Clive Zanker, Chair of UKOPA.

LISTEN NOW CATCH UP ON RECENT EPISODES CCS Forum 2026: CCUS panel discussion [part 2 of 2] CCS Forum 2026: CCUS panel discussion [part 1 of 2] Future makers: Meet the 2026 Young Achievers

Listen and subscribe here

method used by US LNG export projects in 2025 and 2026, closely followed by externally-raised equity contributions (Figure 2).

Louisiana LNG was different and most of developer Woodside’s LNG and equity sales came after its April 2025 FID because it did not use bank loans structured as non-recourse project financing to advance the project. This approach is beyond the means of many project developers, except the largest, which are often oil majors. The only project finance-type structure used for Louisiana LNG was Stonepeak’s and was to support its purchase of an equity stake in the project.

US projects have been able to secure financing because they have made sales of mostly 20 years’ duration to creditworthy customers, which ensures loan payback and meets banks’ requirements for risk tolerance. Even though banks typically refinance these loans before the end of the loan’s tenor, which is mostly seven years in the US, the contract lengths need to be sufficient to provide steady returns for others, such as bond investors, who then take on the risk.

US projects have been able to attract customers because they offer flexible supply, with pricing that has remained competitive, typically indexed to 115% of US Henry Hub with liquefaction fees mostly landing in the mid to high US$2/million Btu range.

Unlike other projects in emerging economies, US projects have not needed to use export credit agencies (ECAs), because 20-year commitments by investment-grade customers typically provide enough security for their lenders.

However, if US project developers need to include sub-investment grade customers or those without credit ratings in their offtaker lineup, ECA support could help.

The Export-Import Bank of the United States (EXIM) was given permission in 2025 to finance US LNG export projects after providing over US$14 billion over the last two decades to foreign LNG export projects to support US exports of equipment and services.

On 2 April 2026, EXIM approved an export credit insurance authorisation of over US$2 billion to support US LNG exports to Egypt from trading company, Hartree. This follows a provision of US$400 million in insurance for two revolving credit facilities for Trafigura in 2023 to buy LNG cargoes from US exporters to supply customers in Europe, Asia, and South America. These facilities were renewed in September 2025. In March 2026, EXIM also identified the Delfin LNG project as one of the strategic deals its loans would unlock.

Bond refinancing allows banks to ‘recycle’ capital to new projects

US projects were active in issuing bonds, mostly for refinancing, with around US$12.7 billion of this type of activity in 2025, which beat the 2023 record of US$12.6 billion. US LNG export project bank debt is often refinanced in the bond market once construction is advanced or completed to reduce financing costs, extend loan maturities, diversify sources of capital, and recycle bank capital into new projects.

Bond investors typically shun construction risk, preferring the lower risk profile offered by operating assets,

46

North America 2026

although some specialised project bond investors will invest at an earlier stage in the financing process.

Unusually, the Rio Grande Train 5 project issued bonds – via a private placement of senior secured notes – as it reached financial close of its bank loans. This activity is not without precedent because in its initial financing for Phase 1 (Trains 1 – 3) in 2023, Rio Grande issued bonds.

However, these out-of-the-gate bond issues are small relative to the bank loans taken out by the project. Rio Grande Train 5 issued US$500 million of senior notes and took out US$3.95 billion in bank loans, and Rio Grande Phase 1 issued US$700 million of senior notes and took out US$11.6 billion in bank loans. They are also small compared to the bond issues US LNG export projects use for refinancing project debt once construction is advanced or completed, which are typically more than US$1 billion, with issues of as much as US$3 billion and US$4 billion also seen over the last several years.

More North American projects seeking finance in 2026

More developers of US, Canadian, and Mexican projects are actively seeking debt and/or equity finance in 2026, with at least six of them fully permitted and likely sufficiently advanced enough commercially to bring them close to FID. They have a combined 47.8 million tpy of liquefaction capacity and comprise: z US projects: The 4 million tpy Texas LNG, Delfin’s first 4.4 million tpy floating liquefaction project (Delfin FLNG1), and the 9.5 million tpy Commonwealth LNG. z Canadian projects: The 12 million tpy Ksi Lisims project and 14 million tpy LNG Canada Phase 2, although the latter is unlikely to seek external finance. z Mexican project: The 3.9 million tpy Amigo LNG Train 1.

In addition to these projects, there are others with a combined liquefaction capacity of over 63 million tpy that are fully permitted, including Alaska LNG, that need to advance commercially, and others that have partial permits or are not yet permitted with almost 230 million tpy of capacity combined.

Even with the focus on security of supply after the Iran war halted shipping traffic through the Strait of Hormuz, with attacks taking out 12.8 million tpy or 17% of Qatar’s LNG production offline for up to five years and causing delayed output from its North Field expansions, competition to secure customers will be tough.

US projects will compete against Canadian and Mexican projects, as well as those from other countries because some buyers will be aiming for supply diversity as well as security. Countries with large LNG export projects looking to secure finance in 2026 and 2027 include Mozambique, Papua New Guinea, Indonesia, and Argentina.

However, if US developers can offer well-structured projects that are low on the global cost curve with the appropriate commercial arrangements in place, financiers are likely to remain receptive and continue to provide them with capital.

Tanks & Terminals Online

The home for the latest oil, gas and petrochemical storage news For the latest news visit: www.tanksterminals.com

ADINDEX Advertiser

Page

Advertiser

Page

Black & Veatch

13

OPW Clean Energy Solutions

09

Bridgemans

IFC

Quietflex Manufacturing

25

Emerson

OBC

Sempra Infrastructure

07

Global Hydrogen Review

29

Tanks & Terminals

47

Honeywell

OFC, 21

Teledyne Gas and Flame Detection

02

LNG Industry

17 ,IBC

World Pipelines Podcast

45

LNG Industry Podcast

41

www.lngindustry.com

15FACTS

...ON NORTH AMERICA

The US exported 17 billion ft3/d in LNG to five continents in January 2026 Mexico is home to

It has now been over 10 years

the world’s smallest volcano:

since the first export

The Cuexcomate Volcano

of LNG in North America

is only 13 m high

North American LNG

Wood Buffalo National Park in Alberta is larger than Switzerland

Texas and Louisiana remain

exports are projected to double by 2035

the primary suppliers of

Québec produces 75%

natural gas for export through 2050

of the global supply of maple syrup

By 2035, gas flows from Texas are expected to

Canada exported its

The US and Canada each span

comprise 43% of all

first LNG cargo on

six different time zones

30 June 2025

natural gas exported from US LNG facilities

Current forecasts expect Canada to export 2.3 billion ft3/d

Mexico has 35

of LNG from its LNG

UNESCO World Heritage sites

export facilities by 2030

Mexico is the largest

The first official document to name

Spanish-speaking

‘The United States of America’ was the

country in the world

Declaration of Independence, in 1776

Mexico shipped its first LNG cargo in August 2024

LNG Industry will be in Bangkok!

Visit us at Booth MV10 at Gastech

Pick up your copy of the September 2026 issue at Gastech

De-risk modular LNG and FLNG. Valves are where fast track LNG schedules are won.

Or lost.

In modular LNG and FLNG, valve requirements often vary by package vendor, creating risks in integration, documentation, and startup.

Emerson helps teams align on valve requirements early, optimize sizing, and standardize smart positioner technology with baseline diagnostics for smoother integration and commissioning.

Over 70% of the world’s LNG flows through Emerson valves

Scan to watch our experts on this topic

Emerson.com/LNGvalves