What Is LNG? Storage, Terminals & Infrastructure Guide

What Is LNG? The Terminal & Storage Infrastructure Guide

Liquefied natural gas (LNG) is natural gas — predominantly methane — that has been cooled to approximately −162°C (−260°F), converting it from a gas into a liquid that occupies roughly 1/600th of its original volume. That compression ratio is what makes LNG commercially viable: it enables natural gas to be transported by sea across distances where pipelines are impossible, connecting production basins in Qatar, the United States, and Australia with consuming markets in Japan, China, South Korea, and Europe.

For terminal operators and storage engineers, understanding what LNG is means understanding a product with fundamentally different infrastructure requirements from liquid hydrocarbons like crude oil or diesel. Cryogenic temperatures, boil-off gas management, and full containment tank design define every aspect of LNG storage — from capital cost to operational regime.

What Is LNG Made Of

LNG is predominantly methane (CH₄), typically comprising more than 90% of the final liquefied product. Small quantities of ethane, propane, butane, heavier alkanes, and nitrogen make up the remainder. The exact composition varies by source field and liquefaction train design, and matters commercially because it determines the calorific value — the energy content per unit volume — of the cargo.

Before liquefaction, raw natural gas undergoes a purification process to remove water, carbon dioxide, hydrogen sulphide, mercury, and heavy hydrocarbons. These components would freeze at cryogenic temperatures, damaging equipment and blocking process streams. The purification stage adds cost and complexity but is non-negotiable: any gas entering the liquefaction train must meet strict specification limits, typically verified by gas chromatograph at the liquefaction facility boundary.

LNG quality — measured primarily by calorific value and Wobbe index — is a critical commercial variable. Asian markets (Japan, South Korea, Taiwan) import rich, high-calorific-value LNG with a gross calorific value above 43 MJ/m³. UK and US markets traditionally handle leaner gas below 42 MJ/m³. Continental Europe accepts a wider range. Off- specification LNG — gas that does not conform to the agreed sale and purchase agreement — can be refused by the buyer, triggering liquidated damages provisions.

How LNG Is Produced: The Liquefaction Process

LNG is produced at liquefaction facilities — large onshore plants or floating production units built adjacent to gas fields or connected to pipeline infrastructure. The core unit of production is the LNG train: an independent processing line comprising a compression area, propane pre-cooling section, and methane/ethane liquefaction stages. Most large baseload LNG plants operate multiple parallel trains to provide redundancy and increase total throughput.

The dominant liquefaction technology is the AP-C3MR process developed by Air Products & Chemicals (APCI), used in the majority of the world’s baseload LNG trains. The Optimised Cascade process, developed by ConocoPhillips and first deployed commercially at Kenai LNG in Alaska in 1969, is the second most widely used. Both cool the gas through successive refrigeration cycles — propane pre-cooling followed by mixed refrigerant for final liquefaction — achieving the −162°C endpoint required for atmospheric pressure storage.

The largest single LNG trains in operation are in Qatar at Ras Laffan, each with a capacity of 7.8 million tonnes per annum (MTPA). Qatar remains the world’s largest LNG exporter by installed capacity, with the North Field Expansion programme targeting 127 MTPA by the late 2020s. The United States became the world’s largest LNG exporter by volume in 2023, with Sabine Pass, Freeport, Cameron, Corpus Christi, Calcasieu Pass, and Plaquemines among its major export terminals. See our ranking of the top 10 LNG export terminals by capacity.

What Is LNG Storage: Cryogenic Infrastructure

What is LNG storage in engineering terms? It is one of the most technically demanding storage challenges in the energy sector — a product that must be maintained at −162°C, at near-atmospheric pressure, with continuous management of vapour generation (boil-off gas) and strict materials compatibility requirements.

Modern large-scale LNG storage tanks are of the full containment type: a high-nickel steel inner tank (typically 9% nickel steel, which retains ductility at cryogenic temperatures) surrounded by a prestressed concrete outer wall, with highly efficient perlite or foam glass insulation filling the annular space. Tank capacities at major import terminals typically range from 100,000 m³ to 200,000 m³ per tank, with large hub terminals operating multiple tanks in parallel.

Despite the insulation, heat ingress into LNG storage tanks is unavoidable. This causes a proportion of the LNG to vaporise — generating boil-off gas (BOG). At a well-insulated large storage tank, BOG generation runs at approximately 0.05–0.1% of tank volume per day. BOG management is a critical operational challenge: the gas must either be recompressed and returned to storage via reliquefaction, fed into the regasification send-out stream, or — in some configurations — used as fuel for site utilities. Unmanaged BOG represents both a product loss and a safety hazard.

An alternative to onshore full containment storage is the Floating Storage and Regasification Unit (FSRU) — a purpose-built or converted LNG carrier moored offshore or at a jetty, equipped with onboard regasification equipment. FSRUs have become the fast-track solution for new LNG import markets: they can be deployed in 12–24 months versus 4–6 years for a conventional onshore terminal, at a fraction of the capital cost. Major FSRU operators include Höegh LNG, Golar LNG, and Excelerate Energy.

How LNG Is Traded and Priced

LNG trade is governed by long-term sale and purchase agreements (SPAs), typically 15–25 years in duration, linking a liquefaction project to a downstream buyer. This long-term contract structure reflects the capital intensity of LNG infrastructure: a baseload liquefaction plant costs at least $1.5 billion per MTPA of capacity, and project financing requires contracted revenue streams before a final investment decision can be taken.

LNG pricing varies by region. In Asia — historically the largest LNG import market — contracts were traditionally indexed to a basket of Japanese crude oil imports (the Japan Crude Cocktail, or JCC), linking LNG price to oil parity. US export contracts, led by Cheniere Energy, pioneered a different model: a fixed liquefaction tolling fee plus a percentage of Henry Hub natural gas prices, decoupling LNG from oil indexation for the first time at scale. European import pricing blends oil-indexed, gas hub-indexed (TTF, NBP), and spot market components.

A spot and short-term LNG market has grown significantly since 2010. The Japan Korea Marker (JKM), published by S&P Global Platts, has emerged as the primary Asia-Pacific spot LNG price reference. In Europe, TTF gas hub prices serve as the primary benchmark. Global LNG trade volumes and import/export statistics are published annually by the International Group of LNG Importers (GIIGNL). Current LNG spot prices are tracked on our LNG price page.

LNG Storage Economics: Contango and Terminal Utilisation

LNG market structure directly affects terminal storage utilisation in the same way contango drives crude oil storage demand. When LNG spot prices are depressed relative to forward prices — a contango structure — storing LNG in tank and selling forward becomes commercially attractive, driving demand for ullage at import terminals and FSRUs. When the market moves into backwardation, with spot prices above forward, the incentive to hold inventory falls and terminal throughput increases as buyers minimise stock.

The seasonal demand pattern for LNG is particularly pronounced. Winter heating demand in Northeast Asia and Northern Europe drives sharp seasonal price spikes — the JKM winter premium has historically run $2–5/MMBtu above summer levels — which incentivises pre-season inventory building at import terminals during summer and autumn. Terminal operators with large sendout capacity and multiple storage tanks have a structural advantage in capturing seasonal arbitrage on behalf of utility customers.

Geopolitical supply disruptions amplify price volatility and storage demand. The 2022 European energy crisis — triggered by the reduction in Russian pipeline gas supply — drove an unprecedented surge in LNG import terminal utilisation across Europe, with new FSRU deployments in Germany, Italy, the Netherlands, and Finland accelerating within months. Shell’s LNG terminal portfolio was central to European supply security during this period — see our Shell LNG terminals profile.

LNG in the Global Supply Chain

The LNG supply chain connects gas fields to end consumers through four distinct infrastructure layers: upstream production and liquefaction; LNG carrier shipping; import terminal reception and storage; and downstream regasification and pipeline distribution. Each layer involves specialist operators, long-term contracts, and significant capital investment.

LNG carriers — double-hulled cryogenic vessels with insulated membrane or Moss-type spherical cargo tanks — are the connecting link between export and import terminals. A standard Q-Flex carrier holds around 210,000 m³ of LNG; the largest Q-Max vessels, operated exclusively by QatarEnergy on long-haul routes from Ras Laffan, carry up to 266,000 m³. Cheniere Energy, Sempra Infrastructure, and Venture Global are among the major US export terminal operators supplying the global LNG fleet. See our Sempra LNG infrastructure profile.

The tank terminals global guide covers LNG terminal infrastructure in the context of the broader liquid storage sector, including regasification capacity by region and the independent terminal operators active in LNG import.