Where does natural gas come from?

Natural gas is mostly methane, with smaller amounts of ethane, propane and butane. It is trapped in porous rock under an impermeable cap, sometimes on its own (a gas field) and sometimes dissolved in or sitting above crude oil (associated gas). Because it forms from the same buried organic matter as oil, only cooked at higher temperatures or from more gas-prone source rock, the map of gas production overlaps the oil map but is not the same. The figures on this page are marketed production, meaning gas that is sold rather than flared, vented or reinjected, as defined by the Energy Institute.

In 2025 United States produced 1,074 billion cubic metres, 26% of the world's 4,196 billion cubic metres (Energy Institute). Russia was second with 609 billion cubic metres and Iran third with 265 billion cubic metres. The top five countries together accounted for 58% of world output, and 49 countries reported production at all. World production was +19% compared with ten years earlier, and output in United States grew at +3.8% a year over that decade, a pace set by horizontal drilling and hydraulic fracturing in shale formations such as the Marcellus in Appalachia and the Permian in Texas.

The geology behind the leaders is distinct in each case. United States output is dominated by shale, where gas is held in the fine-grained source rock itself and released by fracturing it. Russian output comes largely from giant conventional fields in the Yamal-Nenets region of West Siberia, discovered in the 1960s and 1970s. Iran and Qatar share a single offshore accumulation, called South Pars on the Iranian side and the North Field on the Qatari side, which is the largest non-associated gas field known. Australia's gas is offshore on the North West Shelf and in Queensland's coal seams; Norway's is in the North and Norwegian Seas; Canada's is in the Western Canadian Sedimentary Basin. China's rising output comes from tight gas, shale in Sichuan and coal-bed methane.

Production and export are different rankings. The United States and Russia both consume most of what they produce; Qatar, Australia and Norway consume little of theirs and are built around export. A country's position in gas trade depends less on how much it produces than on whether it has pipelines to neighbors or liquefaction plants on its coast.

Gas crosses borders in two physical forms, and the exporters differ by form. Pipeline gas (HS 271121) moves at high pressure through steel lines and is limited to land neighbors and short sea crossings; Norway was the largest pipeline exporter by value in 2024. Liquefied natural gas, or LNG (HS 271111), is methane chilled to about minus 162 degrees Celsius so it shrinks to one six-hundredth of its volume and can be shipped in insulated tankers anywhere with a regasification terminal; Australia was the largest LNG exporter by value in 2024. Counting all petroleum gases under HS 2711, which also includes propane and butane, United States was the top exporter with 18% of world export value in 2024, and China was the top importer with 18% of import value (CEPII BACI). World exports of natural gas including LNG (HS 2711) were worth $475.8 billion in 2024.

Import patterns follow infrastructure. Japan, South Korea and Taiwan have no pipeline connections and take everything as LNG; China was the largest LNG importer by value in 2024. Continental Europe historically leaned on pipelines from Russia, Norway and North Africa and has shifted toward LNG since 2022. China imports both, by pipeline from Central Asia and Russia and as LNG on its coast. Some countries re-export: Belgium, the Netherlands and Spain reload LNG cargoes and forward pipeline gas, so their trade figures overstate their own production and consumption.

There is no world gas price. Because moving gas is expensive and infrastructure-bound, each region has its own benchmark, and the gaps between them can be several times the price itself. In North America the reference is Henry Hub, a pipeline interchange in Erath, Louisiana, where the NYMEX (CME Group) Henry Hub Natural Gas futures contract (ticker NG, 10,000 MMBtu, quoted in US$/MMBtu) settles. In Europe it is the Dutch Title Transfer Facility, or TTF, a virtual trading point on the Gasunie network, traded as the ICE Endex Dutch TTF Gas futures (ticker TFM, 1 MW, quoted in €/MWh). In Northeast Asia spot LNG cargoes are assessed against the Japan Korea Marker (JKM), while much long-term LNG is still indexed to crude oil under contracts negotiated in the 1970s and 1980s.

This site's primary series is US Henry Hub, which was $2.77/MMBtu in August 2026, down 5% from a year earlier (World Bank Pink Sheet). Its highest monthly average on record was $13.52/MMBtu in October 2005, and its lowest was $0.14/MMBtu in January 1960; the series begins in 1960. For comparison, the European TTF series stood at $21.11/MMBtu in August 2026 and the Japanese LNG import price at $13.94/MMBtu in August 2026. Read the three together and the regional spread is visible in a single glance.

A quoted price is for a unit of heat, not volume. One million British thermal units (MMBtu) is roughly the energy in 28 cubic meters of gas; a megawatt-hour is 3.412 MMBtu. Henry Hub and TTF quotes are for delivery at the hub in the named month, excluding transport to the customer. A Japanese import price is a customs average of landed cargoes, so it lags spot markets and blends oil-linked contracts with spot purchases. When this page says "gas prices rose", it means the named benchmark in the named month.

Gas demand is the most weather-sensitive of the major fuels. In the Northern Hemisphere, residential and commercial heating peaks in December to February, and a cold snap can lift daily demand by a third within a week. Summer heat matters too, because gas-fired power plants run harder to meet air-conditioning load. Traders watch heating-degree-day forecasts as closely as production data, and a single revised two-week forecast can move Henry Hub or TTF by ten percent or more.

Because demand swings with the seasons and production does not, gas is injected into depleted fields, salt caverns and aquifers from April to October and withdrawn in winter. The market compares the amount in store with the five-year average for the same week. A storage deficit heading into winter means less buffer against cold, so prices rise to ration demand and pull in LNG; a surplus at the end of winter does the opposite. Weekly storage reports from the EIA and from Gas Infrastructure Europe are scheduled price events.

LNG links otherwise separate regional markets, but only up to the capacity of the liquefaction trains, tankers and regasification terminals in service. New export plants take four to six years to build and arrive in lumps, so the global balance swings between tight and loose as projects in Qatar, the United States and Australia come online. Outages at a single large plant, such as Freeport in Texas in 2022, tighten Europe and Asia at once. Shipping distance and tanker availability set how quickly cargoes can chase the highest regional price.

Pipeline gas ties buyer and seller to fixed steel for decades, which makes it a lever in disputes. Russian flows to Europe fell sharply from 2022 as contracts were cut, transit through Ukraine ended and the Nord Stream lines were damaged. Sanctions and licensing decisions on LNG projects, export permits in the United States, and transit agreements between Russia, Ukraine and Central Asian producers all change where gas can physically go. When a route closes, the affected market must pay up for LNG until infrastructure is rerouted.

Much of the LNG sold to Asia under long-term contracts is priced as a percentage of the Japanese crude import price, typically with a lag of three to six months. Rising oil therefore raises delivered gas costs in Japan, South Korea and Taiwan even when spot LNG is cheap, and buyers respond by shifting volumes between contract and spot. Associated gas also links the two markets on the supply side: when oil producers drill more in basins such as the Permian, gas output rises as a by-product regardless of the gas price.

Where both fuels are available, power generators run whichever is cheaper per unit of electricity after carbon costs. In the United States gas displaces coal below roughly $3 per MMBtu and cedes ground above it; in Europe the EU carbon price tilts the calculation toward gas. This switching acts as a shock absorber, limiting how far gas can rise before demand falls away, and it means coal and carbon prices feed directly into gas markets.

Shale wells decline quickly, so United States output depends on continuous drilling. When Henry Hub falls below the cost of dry-gas wells in Appalachia and the Haynesville, rigs are laid down and production plateaus within months. But gas from oil-directed drilling in the Permian keeps coming as long as oil is profitable, which has held Henry Hub down through periods that would otherwise have tightened. Pipeline takeaway constraints out of the Permian can push local prices below zero even while the national benchmark is positive.

A gas well is drilled into a reservoir, cased with steel and cement, and connected to a wellhead that controls flow. In conventional fields the gas flows under its own pressure; in shale the rock is first fractured with high-pressure water and sand to open pathways. What comes out of the ground is called wet or raw gas: methane mixed with heavier hydrocarbons, water vapor, carbon dioxide, hydrogen sulfide and sometimes nitrogen or helium. A field's gas is characterized by its methane share, its liquids content and whether it is "sour" (high in hydrogen sulfide) or "sweet".

At a gas processing plant the water is removed with glycol, acid gases are stripped out with amine solvents, and the natural gas liquids (NGLs: ethane, propane, butane and pentanes) are separated by chilling and fractionation. NGLs are sold into the petrochemical and LPG markets and can be worth more than the methane. What remains is pipeline-quality dry gas, which must meet a heating value and purity specification before it enters the transmission grid. Sulfur recovered from sour gas is a by-product; helium from a handful of fields in the United States, Qatar and Russia is another.

To export by sea the dry gas is piped to a liquefaction plant, where a series of refrigeration cycles chills it to about minus 162 degrees Celsius. The plant is built in parallel units called trains, each producing several million tonnes a year, and the LNG is stored in insulated tanks before loading. On the receiving end, a regasification terminal warms the liquid back to gas with seawater or burners and feeds it into the local grid. Roughly a tenth of the energy in the gas is used in liquefaction, shipping and regasification, which is one reason pipeline gas is cheaper when the route exists.

The traded products differ by route. Pipeline gas is sold as a flow at a hub, in energy units per day. LNG is sold by the cargo, usually 60,000 to 80,000 tonnes, with the heat content specified because gas from different fields has different energy density. Boil-off during the voyage is used as ship fuel, so a cargo shrinks slightly between loading and discharge.

Gas is burned to make electricity, to heat buildings and to drive industrial processes such as glass, steel and cement making. It is also a feedstock, not just a fuel: methane is reformed into hydrogen for ammonia and thus for nitrogen fertilizer, and into methanol; ethane from gas processing is cracked into ethylene, the base of most plastics. Where gas is cheap, as in the United States and the Persian Gulf, fertilizer and petrochemical plants cluster around it.

The balance among these uses varies by country. In the IEA's accounting, electricity and heat generation and buildings together take the largest shares of world gas consumption, with industry and feedstock behind them (IEA, World Energy Outlook 2023). In a gas-poor, coal-rich economy such as India or China, gas is a small share of the energy mix; in Iran, Russia and Qatar it is the dominant fuel for power and industry.

Gas infrastructure is fixed and concentrated, so a small number of places matter out of proportion to their size. Ras Laffan in Qatar hosts liquefaction trains that supply a large share of world LNG, and every cargo from there must transit the Strait of Hormuz, a channel about 33 kilometers wide at its narrowest between Iran and Oman. United States LNG leaves from a cluster of plants on the Gulf Coast, above all Sabine Pass and Cameron in Louisiana and Corpus Christi and Freeport in Texas, and much of it bound for Asia passes through the Panama Canal, whose transit slots are limited by canal capacity and, in drought years, by water levels. Australian LNG ships from the North West Shelf, Gladstone and Darwin, and Northeast Asian imports funnel through the Strait of Malacca and the South China Sea.

In Europe the chokepoints are pipes rather than straits. Norwegian gas reaches the continent and Britain through a handful of subsea lines that land at Easington, Dunkirk, Zeebrugge and Emden; the Baltic Nord Stream lines, once the largest single route from Russia, were damaged in 2022 and are out of use. Transit through Ukraine ended at the start of 2025 when the transit agreement expired, leaving TurkStream as the only Russian pipeline route into the EU. Regasification capacity is itself a bottleneck: Germany had none until floating terminals were installed in late 2022, and Spain's terminals sit behind a thin pipeline link to France.

Processing is a further point of concentration. LNG liquefaction is engineered by a small number of licensors and built by a handful of contractors, so a shortage of specialized labor or equipment delays projects worldwide at once. Helium and ethane supply depend on a few large plants. And the entire system runs on long-term contracts and dedicated ships, so a lost plant cannot be replaced by buying elsewhere in the way a lost oil cargo can.