LNG: Liquefaction, Regasification, SPAs, and US Export Boom

Introduction

Liquefied natural gas (LNG) has fundamentally transformed the global energy landscape and created one of the most significant infrastructure investment themes in energy banking. By cooling natural gas to approximately -260 degrees Fahrenheit, it is converted to a liquid that occupies approximately 1/600th of its gaseous volume, making it transportable by specialized cryogenic tanker ships to energy markets anywhere in the world, fundamentally connecting previously isolated regional gas markets into a global commodity. This technology has turned the United States from a natural gas importer (as recently as 2015) into the world's largest LNG exporter, with exports surging from 0.5 Bcf/d in 2016 to 15.0 Bcf/d in 2025. US LNG export capacity is forecast to nearly double by 2031, and the capital investment required to build this infrastructure is creating enormous deal flow for energy bankers.

For energy banking, LNG sits at the intersection of midstream infrastructure (the physical liquefaction and pipeline assets), commodity markets (the linkage between Henry Hub domestic gas prices and international LNG prices), and project finance (the multi-billion-dollar capital commitments required for each liquefaction train). Understanding the LNG value chain, its commercial economics, and its unique transaction structures is essential for bankers covering midstream infrastructure, power and utilities, and international energy markets.

The LNG business connects natural gas producers to consumers through a multi-stage infrastructure chain.

Liquefaction

Liquefaction is the process of cooling pipeline-quality natural gas to approximately -260 degrees Fahrenheit, converting it from a gas to a liquid. Liquefaction facilities (often called "LNG trains," referring to the modular processing units) are among the most capital-intensive infrastructure projects in the energy sector. A single LNG train costs $3-8 billion to construct and has a processing capacity of 4-6 million metric tons per annum (MTPA), equivalent to approximately 0.6-0.8 Bcf/d of natural gas.

LNG Train

A modular liquefaction processing unit that cools natural gas to liquid form. Each train operates as a semi-independent processing line with its own compressors, heat exchangers, and refrigeration systems. Major US LNG export facilities typically consist of multiple trains: Sabine Pass LNG (Louisiana) has six trains, Corpus Christi LNG (Texas) has three trains plus a midscale expansion, and the under-construction Golden Pass LNG (Texas) will have three trains totaling approximately 18 MTPA of capacity. The number of trains at a facility determines its total export capacity.

The major US LNG export terminals and their operators include:

Cheniere Energy is the dominant US LNG operator, with Sabine Pass and Corpus Christi accounting for approximately 55% of total US export capacity. Cheniere reported 2025 consolidated adjusted EBITDA of up to $7.0 billion and distributable cash flow of up to $5.2 billion, reflecting the enormous cash generation of contracted liquefaction capacity.

Shipping

LNG is transported from the liquefaction terminal to the destination market on specialized LNG carriers (tankers with cryogenic containment systems that maintain the liquid temperature during the voyage). A typical modern LNG carrier can transport 125,000-175,000 cubic meters of LNG, equivalent to approximately 2.6-3.6 Bcf of natural gas. The global LNG carrier fleet has expanded rapidly alongside US export capacity growth, with shipbuilding orders concentrated at South Korean and Chinese yards.

Shipping costs vary from $0.50 to $2.50 per MMBtu depending on the distance: the Gulf Coast to Europe costs approximately $0.50-1.00 per MMBtu, while the Gulf Coast to Asia (via the Panama Canal or around the Cape of Good Hope) costs $1.50-2.50 per MMBtu. These shipping costs are a critical component of the LNG netback economics: the buyer must earn enough spread between the FOB cost and the destination market price to cover shipping and still generate a positive margin. When international gas prices spike (as they did during the 2022 Russia-Ukraine energy crisis, when European TTF prices exceeded $60 per MMBtu), the netback economics for US LNG are extraordinarily favorable. Under more normalized conditions (TTF at $10-15 per MMBtu), the margins are tighter but still positive for most cargoes.

One of the most distinctive features of US LNG contracts is their destination flexibility. Unlike traditional long-term LNG contracts (common in Asian markets) that restrict where the buyer can deliver the cargo, most US LNG SPAs are sold on an FOB (free-on-board) basis, meaning the buyer takes ownership of the LNG at the loading port and can deliver it to any regasification terminal in the world. This flexibility allows buyers (and the portfolio traders who acquire US cargoes) to optimize deliveries based on real-time global price spreads, directing cargoes to whichever market (Europe, Asia, Latin America) offers the highest netback at any given time.

Regasification

At the destination market, the LNG is received at a regasification terminal where it is heated back to gaseous form and injected into the local pipeline system. Regasification terminals include both permanent onshore facilities and Floating Storage Regasification Units (FSRUs). FSRUs have become an increasingly popular and faster-to-deploy alternative to onshore terminals: Germany commissioned several FSRUs in 2022-2023 within months to replace Russian pipeline gas supply, a process that would have taken 5-8 years for a traditional onshore terminal.

Regasification terminals are found in importing countries across Europe (UK, Spain, France, Italy, Belgium, Netherlands, Germany), Asia (Japan, South Korea, China, India, Taiwan), and Latin America (Brazil, Argentina, Chile). The buildout of regasification capacity, particularly in Europe (where the Russia-Ukraine conflict fundamentally reoriented gas supply away from Russian pipelines and toward LNG imports), is creating additional demand for US LNG and supporting the investment case for new liquefaction capacity in the US.

US LNG export facilities operate primarily on a tolling model, which creates a fee-based revenue structure analogous to the midstream pipeline model but with even longer contract durations.

Sale and Purchase Agreement (SPA)

A long-term contract (typically 15-20 years) between an LNG liquefaction operator and a buyer (typically a utility, gas marketer, or trading company) that specifies the volume of LNG to be purchased, the pricing formula, the delivery terms (FOB at the liquefaction terminal or DES at the destination), and the take-or-pay obligations. SPAs are the contractual foundation of LNG projects: developers must secure sufficient long-term SPAs before making a final investment decision (FID) to proceed with construction, because the SPAs provide the revenue certainty needed to secure project finance debt.

Pricing formula. Most US LNG SPAs are priced as a fixed liquefaction fee (approximately $2.25-3.50 per MMBtu, escalated annually for inflation) plus a variable feedgas cost (typically 115% of the Henry Hub natural gas price). The 115% factor accounts for the fuel gas consumed during the liquefaction process (approximately 10-12% of input gas is used as fuel for the refrigeration compressors, plus small losses). Under this structure, if Henry Hub is $3.50 per MMBtu, the total LNG cost to the buyer on an FOB basis is approximately:

Liquefaction fee: $3.00 per MMBtu + Feedgas: $3.50 x 1.15 = $4.03 per MMBtu = Total FOB cost: $7.03 per MMBtu

The buyer then ships the LNG to its destination market and sells it at the prevailing local price (TTF in Europe, typically $8-15 per MMBtu; JKM in Asia, typically $10-18 per MMBtu). The spread between the destination price and the all-in delivered cost determines the buyer's margin. Chinese companies have increasingly signed five-year Henry Hub-indexed contracts because these contracts offer prices below projected spot prices for 2025-2027, providing cost certainty at attractive levels.

LNG infrastructure creates advisory mandates across multiple banking work streams:

Project finance. LNG liquefaction projects are among the largest project finance transactions in the world. The debt package for a new liquefaction facility typically includes $5-15 billion in project finance debt, structured with non-recourse or limited-recourse terms backed by the contracted SPA revenue. Banks like JPMorgan, Citi, MUFG, and Societe Generale are active arrangers in LNG project finance. The project finance advisory mandate involves structuring the debt terms, coordinating the lending syndicate, and negotiating the security package.

M&A and equity advisory. The ownership stakes in LNG projects are frequently traded, creating M&A advisory mandates. ExxonMobil and QatarEnergy's joint venture for Golden Pass, Blackstone's investment in Cheniere, and various infrastructure fund investments in LNG capacity all generated advisory fees. The Chevron/Hess merger was partly motivated by the strategic value of Hess's gas supply position relative to Gulf Coast LNG demand.

Midstream advisory. The pipeline infrastructure connecting gas supply basins to LNG facilities creates midstream advisory mandates. Pipeline companies like Williams, Kinder Morgan, and Energy Transfer are expanding capacity to deliver feedgas to Gulf Coast liquefaction terminals, and these expansion projects generate both capital markets and M&A advisory work. The EQT/Equitrans merger was partly motivated by the desire to create an integrated gas supply platform that could serve both domestic power markets and Gulf Coast LNG demand, demonstrating how LNG export growth drives M&A across the full midstream value chain.

Capital markets. LNG companies access debt and equity markets frequently. Cheniere Energy has been one of the most active issuers in the investment-grade bond market, refinancing its project finance debt with lower-cost corporate bonds as the company matured. New LNG projects under construction require multi-billion-dollar debt packages, typically structured as project finance with non-recourse terms. The equity component often involves co-investment by infrastructure funds (Brookfield, GIP, KKR), sovereign wealth funds (QatarEnergy, ADIA), and the developer's own balance sheet. Each financing creates advisory, underwriting, and placement mandates for energy bankers.

The US competes for global LNG market share with several other major supply sources:

Qatar is the world's largest LNG exporter by existing capacity and is executing the massive North Field Expansion project that will increase its capacity from approximately 77 MTPA to 142 MTPA by 2030. Qatar's LNG is among the cheapest to produce globally due to the enormous scale and low extraction costs of the North Field gas reservoir.

Australia is the second-largest LNG exporter, with facilities on both the northwest coast (Gorgon, Wheatstone, North West Shelf) and the east coast (Curtis Island). Australian LNG faces higher production costs than Qatar or the US but benefits from geographic proximity to Asian buyers, reducing shipping costs.

Russia remains a significant LNG supplier through the Sakhalin-2 project and the Yamal LNG facility in the Arctic, though Western sanctions following the Ukraine invasion have constrained new project development and financing.

The US has several competitive advantages: the Henry Hub-indexed pricing model (which is attractive to buyers during periods of low US gas prices), destination flexibility (FOB contracts that allow buyers to optimize global deliveries), and a regulatory environment that permits private-sector development (unlike Qatar and Russia, where state-owned entities control LNG exports). However, the US also faces disadvantages: higher shipping costs to Asian buyers (compared to Australian or Qatari supply), periodic policy uncertainty (the Biden administration paused new LNG export permits in 2024 before they were reinstated), and the need for extensive pipeline infrastructure to deliver feedgas from remote producing basins to coastal liquefaction terminals.

The LNG value chain from wellhead to international buyer involves multiple infrastructure steps, each requiring its own investment, contracts, and financing. Understanding this full chain is essential for energy bankers who may work on any segment.

The US LNG export market is in a multi-decade growth phase driven by strong global demand for reliable, flexibly sourced natural gas. US export capacity is expected to nearly double by 2031 as projects under construction (Golden Pass, Plaquemines LNG Phase 2, Rio Grande LNG) and recently sanctioned projects (Cheniere's CCL Midscale Trains 8 & 9, which received FID in June 2025, adding approximately 4 MTPA) come online. LNG exports are forecast to exceed 18.1 Bcf/d by 2027, up significantly from 15.0 Bcf/d in 2025.

This export growth has significant implications across the energy sector. For upstream producers, LNG export demand supports Henry Hub gas prices by absorbing domestic production growth that would otherwise depress prices (as happened in 2024 when Henry Hub averaged a record-low $2.21 per MMBtu partly because LNG capacity additions lagged production growth). For midstream operators, LNG demand drives new pipeline construction and gathering system expansion in gas-rich basins, particularly the Haynesville (which benefits from proximity to Gulf Coast liquefaction) and the Permian (where associated gas production feeds into Gulf Coast pipelines). For power markets, LNG exports compete with domestic power generation for gas supply, potentially supporting higher electricity prices and reinforcing the value of nuclear and renewable generation that does not consume gas.

The AI-driven power demand surge adds another dimension: both LNG exports and data center power generation are competing for the same natural gas supply, creating a structural demand environment that could support Henry Hub prices above $4.00 per MMBtu on a sustained basis for the first time since 2022. This dual demand driver (international LNG plus domestic power) is the core investment thesis for gas-weighted E&P companies, Haynesville-focused operators, and the midstream infrastructure companies that connect gas supply to both end markets.

US LNG exports have taken on significant geopolitical importance since Russia's invasion of Ukraine in 2022. European countries that previously relied on Russian pipeline gas (Germany imported approximately 40% of its gas from Russia in 2021) have redirected their supply toward LNG imports, with US LNG filling a substantial portion of the gap. This energy security dimension adds a strategic overlay to the commercial investment case: US LNG is valued not only for its economic returns but also for its role in diversifying global gas supply away from Russian dependence.

For energy bankers, the geopolitical dimension creates additional advisory opportunities. Government-to-government energy partnerships (e.g., the US-EU LNG task force), bilateral LNG supply agreements (e.g., between US producers and European utilities), and the involvement of sovereign wealth funds and national oil companies in US LNG project equity all generate cross-border advisory mandates that require both commercial and geopolitical expertise. Banks with strong international networks (JPMorgan, Citi, Goldman Sachs) and those with dedicated LNG practices are best positioned for these mandates.