Natural Gas: From Ancient Fires to the Fuel of the Modern Age

Natural gas is a fossil fuel composed primarily of methane (typically eighty to ninety-five percent), with smaller proportions of ethane, propane, butane, and other hydrocarbons, as well as non-hydrocarbon gases including nitrogen, carbon dioxide, and sometimes hydrogen sulfide. It is formed by the same geological processes that create oil — the accumulation and burial of organic matter over millions of years, followed by transformation under heat and pressure — and is found both in association with oil deposits (associated gas) and in reservoirs containing little or no oil (non-associated gas or dry gas).

Natural gas is the fastest-growing major energy source in the world and has become the preferred fuel for electricity generation in many markets, displacing coal on economic and efficiency grounds. It is the dominant residential fuel for heating and cooking in most of the developed world, the primary industrial feedstock for nitrogen fertilizer production, and the fuel of choice for the most efficient combined-cycle power stations. Its combination of high energy content, clean combustion (producing significantly less carbon dioxide, sulfur dioxide, and particulate matter than coal or oil per unit of energy), ease of distribution through pipelines, and competitive cost has driven its rise to become the second or third largest energy source in the global primary energy mix.

The geopolitics of natural gas differ importantly from those of oil. Because natural gas is more expensive to transport than oil — it is less energy-dense than oil by volume, and either requires compression into pipelines or liquefaction and specialized tankers (LNG, or liquefied natural gas, ships) for transportation — natural gas markets were historically regional rather than global. European countries depended on gas from nearby deposits in the North Sea or from pipeline imports from Russia; Asian countries depended on LNG imports from Indonesia, Malaysia, Australia, and the Middle East. The United States was essentially self-sufficient in natural gas for most of the twentieth century. Only with the shale revolution and the expansion of LNG trade has natural gas become a more genuinely global commodity, with prices in different regions becoming more correlated.

The history of natural gas as a commercial energy source is substantially shorter than that of coal or oil — commercial natural gas production did not begin until the mid-nineteenth century — but its use in certain applications (eternal fires, gas seeps, early gas wells) extends back thousands of years.

Ancient Encounters with Natural Gas

Natural gas seeps to the surface in many parts of the world where subsurface gas deposits are under pressure and can find pathways through rock fractures. These seeps have been observed and, in some cases, deliberately exploited since ancient times.

The most culturally significant natural gas seeps in history were those in the ancient Near East that gave rise to the "eternal fires" of Zoroastrian religion. The Zoroastrian eternal fire at Baku on the western shore of the Caspian Sea — at the site now occupied by the Ateshgah Fire Temple — burned continuously for centuries, fed by natural gas venting from shallow deposits. The temple was a place of pilgrimage for Zoroastrian priests from Persia and Hindu pilgrims from India who came to worship the sacred eternal flame. The Baku eternal fire was still burning when Russian engineers arrived in the nineteenth century to begin commercial oil and gas extraction.

The Oracle at Delphi in ancient Greece is now believed by many historians and geologists to have been associated with natural gas or other hydrocarbon vapors. Plutarch, writing in the first century CE, described the Oracle as being located above a fissure from which gases arose that induced the trance states of the Pythia (the priestess who delivered the oracle's pronouncements). Geological surveys of the Delphi site in the late twentieth and early twenty-first centuries found fractures associated with limestone geology typical of hydrocarbon seep environments. The natural gas or light hydrocarbon vapors (possibly ethylene) that might have accumulated in the Oracle chamber could plausibly have induced the altered states of consciousness described in ancient accounts.

The ancient Chinese exploitation of natural gas in Sichuan province is the most clearly documented case of deliberate ancient gas use. Chinese texts from approximately the first century CE describe the use of bamboo pipelines to convey natural gas from seeping ground surfaces or shallow wells to salt evaporation pans, where the gas was burned to evaporate brine and produce salt. The natural gas seeps of Sichuan were associated with the brine deposits used for salt production, and the combination of salt and energy sources in the same location made the Sichuan basin one of the most industrially developed regions of ancient China.

The Burning Mountain (Chimaera) in Lycia (present-day southwestern Turkey) is a natural gas seep that has burned continuously since ancient times and is still burning today. The ancient Greeks believed the eternal fire was the breath of the Chimaera — the mythological fire-breathing monster — and the site was mentioned by Homer. The fire at Chimaera is fueled by methane and hydrogen seeping from Mesozoic metamorphic rocks; the gas contains unusually high proportions of hydrogen, which contributes to the flame's distinctive blue color. The Chimaera fire is one of the oldest continuously burning natural fires in the world.

The Early Commercial Gas Industry: from Coal Gas to Natural Gas

As described in the Coal article, the manufactured gas industry — producing coal gas by heating coal in retorts — provided piped gas to European and American cities for lighting, cooking, and heating from the early nineteenth century. This industry created the infrastructure — pipelines, meters, appliances, and consumer familiarity — on which the natural gas industry would later build.

The transition from manufactured coal gas to natural gas occurred progressively through the late nineteenth and twentieth centuries, driven by the discovery of natural gas deposits near or connected to population centers. The first long-distance natural gas pipeline in the United States was built in 1886, carrying gas from wells in Murrysville, Pennsylvania, to Pittsburgh. The pipeline — approximately 32 kilometers of two-inch iron pipe — was built by Equitable Gas Company and demonstrated that natural gas could be transported by pipeline to urban consumers.

The development of seamless pipe technology and improved welding techniques in the early twentieth century enabled the construction of larger diameter, higher pressure pipelines capable of carrying gas over longer distances. The Texas-Eastern pipeline, completed in 1947, converted a wartime petroleum products pipeline (the "Big Inch" and "Little Big Inch" pipelines built to carry oil from Texas to the Northeast during World War II) to natural gas service, carrying Texas Panhandle gas to the Northeast. This pipeline initiated the transformation of American natural gas from a local fuel to a national one.

The interstate natural gas pipeline network in the United States grew rapidly through the 1950s and 1960s, connecting the producing regions of the Gulf Coast, Texas, Oklahoma, and Kansas with consuming markets in the Northeast, Midwest, and California. By the 1960s, natural gas had largely displaced manufactured coal gas in the United States, and the natural gas revolution in residential and commercial heating was underway. American homeowners switched from coal furnaces to natural gas furnaces in large numbers through the 1950s and 1960s, attracted by the cleanliness, convenience, and lower operating cost of natural gas heating compared to coal.

The North Sea Gas Discoveries and European Supply

The discovery of natural gas in the North Sea in the 1960s and the subsequent development of European offshore gas fields transformed the energy supply of northwestern Europe, providing an abundant, domestic source of gas that reduced dependence on imported fuel.

The first major North Sea gas discovery was made in 1959 at Groningen in the Netherlands — the Groningen gas field proved to be one of the largest natural gas fields in the world, with reserves estimated at 2.7 trillion cubic meters. The Groningen discovery demonstrated that the North Sea basin contained major gas resources and prompted a wave of exploration that found fields throughout the Dutch, British, Norwegian, and Danish sectors. The UK government auctioned offshore licenses in 1964, and the first major British North Sea gas field — West Sole — was discovered in 1965.

The development of North Sea gas required entirely new technology for drilling and production in water depths of between 50 and 200 meters in the harsh environmental conditions of the North Sea — 15-meter waves, powerful currents, and frequent severe storms. The first production platforms were fixed steel structures installed on the seabed; later developments used gravity-based concrete structures and eventually floating production systems for the deeper Norwegian fields.

Norwegian gas exports began in 1977 with the Ekofisk field, connected by pipeline to the German coast at Emden. The North Sea pipeline network subsequently expanded to include the Flags (Far North Liquids and Associated Gas System), Norpipe, Vesterled, Langeled, and other major pipelines carrying Norwegian and British gas to continental European markets. The Langeled pipeline, completed in 2007, carries gas from the giant Ormen Lange field off the Norwegian coast to Easington in Yorkshire, England — at approximately 1,200 kilometers, it is among the world's longest subsea gas pipelines.

Liquefied Natural Gas: the Global Trade in Frozen Fuel

The development of liquefied natural gas (LNG) technology transformed natural gas from a regional commodity, constrained by the reach of pipeline networks, into a global commodity that can be traded between any two locations with access to LNG terminal infrastructure. LNG is natural gas cooled to approximately minus 162 degrees Celsius (minus 260 degrees Fahrenheit), at which temperature methane liquefies and occupies approximately one six-hundredth of its gaseous volume — making it practical to store and transport by ship.

The first commercial LNG plant was built at Cleveland, Ohio, in 1941 by East Ohio Gas Company, primarily as a peak-shaving facility — storing gas in liquid form during summer low-demand periods and revaporizing it to meet winter peak demand. A catastrophic failure of one of the storage tanks at the Cleveland facility in October 1944 — when a cryogenic metal failure allowed LNG to leak into the sewer system, where it vaporized and ignited, killing 128 people and destroying several city blocks — demonstrated both the potential of LNG technology and the critical importance of containment safety. The Cleveland disaster halted LNG development for more than a decade while the industry worked out safer containment designs.

The world's first transoceanic LNG shipment was made in January 1959 by the Methane Pioneer — a converted World War II cargo vessel fitted with aluminum LNG tanks — which sailed from Lake Charles, Louisiana, arriving at Canvey Island, England on February 20, 1959, after a 27-day Atlantic crossing. This pioneer shipment demonstrated the feasibility of transoceanic LNG trade and opened the way for the development of the international LNG industry. The first permanent commercial international LNG contract followed in 1964, supplying Algerian LNG from the Arzew terminal to Canvey Island (via the dedicated LNG tanker Methane Princess) and the Zeebrugge terminal in Belgium, establishing the commercial model that subsequent LNG projects would follow.

The LNG industry grew rapidly from the late 1960s as Japanese utilities signed long-term supply contracts with Alaskan, Bruneian, and Libyan LNG projects to secure energy for Japan's rapidly growing economy. Japan, which has no domestic oil or gas production of significance, became and remains the world's largest LNG importer, receiving shipments from Australia, Malaysia, Qatar, Russia, and multiple other sources. The Japanese LNG import model — long-term contracts with oil-indexed pricing, dedicated receiving terminals, and tight integration with the utility buyers — became the template for the Asian LNG market that has dominated global LNG trade for decades.

Qatar became the world's largest LNG exporter in the 2000s-2010s, leveraging its enormous North Field gas deposit (the world's largest natural gas field, shared with Iran's South Pars field) to build the world's largest LNG export capacity. Qatar's RasGas and QataxGas LNG plants, built over several phases from the early 1990s, gave Qatar LNG production capacity of approximately 77 million metric tons per year — roughly a quarter of global LNG trade. Qatar's LNG success transformed the emirate from a minor Gulf state into one of the wealthiest countries in the world by per-capita GDP.

The US shale revolution and the development of American LNG export capacity from 2016 onward added a new major source of LNG supply to the global market. The Sabine Pass LNG terminal in Louisiana — built by Cheniere Energy, the first US LNG exporter — began exports in 2016. By 2022, the United States had become the world's largest LNG exporter, with capacity at Sabine Pass, Corpus Christi, Freeport, Elba Island, and Cove Point terminals totaling approximately 95 million metric tons per year. American LNG, priced on Henry Hub (the US gas pricing benchmark) rather than on the oil-indexed basis of traditional long-term contracts, provided buyers with more pricing diversity and helped create a more liquid global LNG market.

Russia and European Gas: the History of a Strategic Dependency

Russia's natural gas exports to Europe represent one of the most consequential energy relationships in modern history — a relationship that provided Europe with reliable, affordable gas for four decades while simultaneously creating a strategic dependency that became deeply problematic when Russian-European political relations deteriorated.

The Soviet Union began exporting natural gas to Western Europe in 1968, when the first pipeline to Austria was completed. Soviet gas exports to Europe expanded steadily through the 1970s and 1980s, driven by the commercial interests of both sides: the Soviet Union needed hard currency and Western technology; Western European countries (particularly West Germany) wanted affordable energy and were willing to offer both currency and technology equipment financing to get it. The relationship was controversial from the start in the United States, which worried that European dependence on Soviet gas would give Moscow political leverage. The Reagan administration attempted to block the construction of the Trans-Siberian pipeline in the early 1980s, applying sanctions to European companies that supplied equipment; the Europeans ultimately defied the sanctions and completed the pipeline.

By the early 2000s, Russia was supplying approximately forty percent of Europe's natural gas through a network of major pipelines: the Brotherhood pipeline through Ukraine, the Yamal-Europe pipeline through Belarus and Poland, the Nord Stream 1 pipeline under the Baltic Sea (completed 2011), and multiple other routes. Gazprom, the Russian state-controlled gas company, was one of the world's largest companies by market capitalization and a primary instrument of Russian state power.

The Russia-Ukraine gas disputes of 2006 and 2009 — in which Gazprom cut gas supplies to Ukraine (and thereby to Europe, which received gas through Ukrainian pipelines) during price and payment disputes — demonstrated the vulnerability of European gas supply to Russian-Ukrainian political tensions. The 2009 cutoff, which left several European countries without gas during a period of severe winter weather, was a turning point in European energy security thinking. The European Union began developing policies to reduce gas import dependence and diversify supply routes.

Russia's invasion of Ukraine in February 2022 and the subsequent mutual energy decoupling — European countries choosing to reduce Russian gas imports; Russia cutting supplies in retaliation — produced the most significant energy crisis in Europe since the 1970s. European gas prices rose more than tenfold from pre-crisis levels at their peak, driving severe industrial disruption, government spending on household energy subsidies, and an accelerated transition to alternative supplies and energy efficiency. European countries secured emergency LNG supplies from the United States, Qatar, Norway, and elsewhere, reduced gas consumption through efficiency programs and fuel switching, and diversified pipeline supplies from Norway, Azerbaijan, and North Africa. By the winter of 2022-23, Europe had largely replaced Russian gas imports with alternative sources and emergency conservation measures.

The Shale Gas Revolution and the United States

The shale gas revolution — part of the same technological development that produced the shale oil revolution — transformed natural gas markets in the United States and ultimately globally with a speed and completeness that few energy analysts had anticipated.

American natural gas production had been declining from its 1973 peak for three decades when the shale gas boom reversed the trend dramatically. The Barnett Shale in Texas, where George Mitchell pioneered the hydraulic fracturing techniques that made tight gas production economical, was the first major shale gas play. Production from the Barnett grew from essentially zero in 2000 to over 5 billion cubic feet per day by 2010. The Haynesville Shale in Louisiana, the Fayetteville Shale in Arkansas, and the Marcellus Shale in Pennsylvania and West Virginia followed in rapid succession.

The Marcellus Shale proved to be one of the largest natural gas fields in North America. Underlying large portions of Pennsylvania, West Virginia, New York, and Ohio, the Marcellus contains an estimated 141 trillion cubic feet of recoverable gas — more than enough to supply the entire United States for several years. Production from the Marcellus grew from negligible quantities in 2007 to over 20 billion cubic feet per day by the mid-2010s, making Pennsylvania one of the top gas-producing states in the US and transforming the energy economics of the northeastern states that had previously relied heavily on imported LNG and Canadian pipeline gas.

The surge in American shale gas production pushed Henry Hub natural gas prices from above eight dollars per million BTU in 2008 to below two dollars per million BTU in 2012 — a price collapse that made natural gas dramatically cheaper than coal for electricity generation in many American markets. Electric utilities switched from coal to gas in large numbers: American coal-fired electricity generation fell from approximately 2,000 terawatt-hours per year in 2007 to approximately 700 terawatt-hours per year by 2020, with natural gas generation growing correspondingly. The displacement of coal by gas reduced American power sector air pollutant emissions significantly.

Low gas prices also benefited American manufacturers, particularly in energy-intensive industries including chemicals, steel, fertilizers, and aluminum. American chemical companies benefited from cheap ethane (a byproduct of shale gas production) as a feedstock for plastics production. Several large chemical and fertilizer investments that had previously been planned for the Middle East or Asia were redirected to the United States, attracted by the cheap gas advantage.

Natural Gas Extraction: from Conventional Wells to Shale

Natural gas is extracted from the earth through a wide variety of methods depending on the geological characteristics of the deposit. Conventional gas is extracted from porous and permeable reservoir rocks (sandstone, limestone) where gas is held under pressure and flows readily to a well bore. Unconventional gas — including shale gas, tight gas (in low-permeability sandstone), and coalbed methane — requires additional stimulation techniques to enable commercial production.

Conventional gas wells are drilled in a similar manner to oil wells, using rotary drilling equipment and weighted drilling mud to control pressure. When the drill bit penetrates a gas reservoir, the pressure differential causes gas to flow into the well and up the casing to the surface. Well completion includes perforating the casing at the reservoir interval, setting production tubing, and installing wellhead equipment to control gas flow and divert it to surface processing facilities.

Gas processing — separating the methane from associated heavier hydrocarbons, water vapor, hydrogen sulfide, and carbon dioxide — is required before most natural gas can be delivered to pipelines. Gas sweetening (removing hydrogen sulfide) uses chemical absorption (typically an amine solvent that selectively absorbs the acidic gas) in processing plants that must be located near production facilities. Liquids extraction separates propane, butane, and heavier hydrocarbons (natural gas liquids or NGLs) from the methane stream; these liquids are valuable products in their own right, used as LPG fuel and petrochemical feedstocks.

Coalbed methane (CBM) is natural gas adsorbed onto the surfaces of coal particles in underground coal seams. Commercial CBM production began in the United States in the early 1980s, following the development of techniques for dewatering coal seams (the gas is released as water pressure in the coal seam is reduced) and drilling horizontal wells through the coal. CBM production contributed significantly to US gas supply in the 1990s and 2000s; Australia, China, and Canada have also developed significant CBM industries.

Major Natural Gas Producing and Consuming Countries

The geography of natural gas production and consumption reflects a different distribution than oil, with large reserves concentrated in Russia, the Middle East, and Central Asia.

Russia has the world's largest natural gas reserves and has been the world's largest or second largest producer for decades. Russia's vast West Siberian Basin — which includes the giant Urengoy, Yamburg, and Medvezhye fields — contains more gas than any other region outside the Middle East. Gazprom, the Russian state-controlled gas company, produces approximately sixty to seventy percent of Russian gas; the remainder comes from independent producers including Novatek and the oil companies.

Iran has the world's second largest natural gas reserves, primarily in the giant South Pars field in the Persian Gulf (which is the Iranian portion of the same geological structure as Qatar's North Field). Iran's domestic gas consumption is very high — gas is heavily subsidized and widely used for industrial and residential heating, power generation, and vehicle fuel — leaving limited surplus for export. Iran exports some gas to Turkey and Iraq by pipeline but its potential as a major LNG exporter has been constrained by international sanctions and the difficulty of financing major capital investment.

The United States became the world's largest natural gas producer by 2009, driven by the shale revolution, and has maintained that position since. American gas is produced primarily in the Permian Basin, Appalachian region, and Gulf Coast. The United States exports LNG and also significant volumes by pipeline to Mexico and Canada.

Qatar, with its North Field gas reserves, exports the vast majority of its production as LNG to Asian and European customers, making it one of the world's largest gas exporters by volume despite its small geographic size.

Australia has undergone a major expansion of LNG export capacity since 2010, building multiple LNG projects in Queensland (coal seam gas), Western Australia (Gorgon, Wheatstone, Northwest Shelf), and the Northern Territory (Ichthys, Darwin LNG). Australia is now one of the world's top three LNG exporters, competing with Qatar and the United States for the top spot.

Turkmenistan has the world's fourth largest natural gas reserves, primarily in the giant Galkynysh (South Yolotan) field, which is one of the largest gas fields in the world. Turkmenistan exports gas primarily to China through the Central Asia-China Gas Pipeline and to Russia, which then on-sells to European customers.

Natural Gas and Electricity Generation

Natural gas has displaced coal as the preferred fuel for new electricity generating capacity in most developed markets, driven by the combination of lower capital cost, higher efficiency, lower emissions, and greater operational flexibility of gas-fired power stations compared to coal-fired equivalents.

The combined-cycle gas turbine (CCGT) power station is the most efficient fossil fuel electricity generating technology available. A CCGT burns natural gas in a combustion turbine (similar to an aircraft jet engine), then uses the hot exhaust gases to raise steam in a heat recovery steam generator, which drives a second steam turbine. The combination of the gas turbine cycle and the steam turbine cycle achieves electrical efficiencies of fifty-five to sixty-two percent — approximately twice the efficiency of early coal steam turbines and substantially higher than even the most advanced ultra-supercritical coal plant. The high efficiency of CCGT plants significantly reduces the carbon dioxide emissions per unit of electricity generated compared to coal.

Gas-fired power stations also offer operational flexibility that coal cannot match. A CCGT plant can start from cold to full power in less than thirty minutes, and can ramp up and down quickly to follow changes in electricity demand. This flexibility makes gas plants valuable complements to inflexible baseload plants (nuclear, coal) and intermittent renewable generators (wind, solar) in the electricity system.

Open-cycle gas turbines (OCGTs) — combustion turbines without the heat recovery steam cycle — can start up in minutes and reach full power in under five minutes, making them ideal for emergency reserve capacity and peak demand response. Their electrical efficiency (approximately thirty-five to forty percent) is lower than CCGT plants, but their speed of response and lower capital cost make them valuable for short-duration applications.

Inventions and Key Figures in Natural Gas History

The history of natural gas technology has fewer single dramatic inventors than coal or oil — the industry grew more gradually from ancient knowledge of natural gas seeps through incremental technological developments rather than sudden breakthroughs. Nevertheless, several figures stand out.

Robert Bunsen (1811-1899), the German chemist whose name is given to the laboratory burner that bears his name, developed the Bunsen burner in 1855 specifically for efficient gas combustion. The Bunsen burner mixes gas with air before ignition, achieving complete combustion at high temperature without a yellow sooty flame. The design principles of the Bunsen burner — premixed combustion, controlled air-fuel ratio — underlie modern domestic gas burners and industrial combustion equipment.

Michael Faraday (1791-1867) was the first person to liquefy certain gases, including chlorine, in experiments conducted in 1823. His work on gas liquefaction established the scientific basis for the eventual liquefaction of methane, though natural gas liquefaction technology was not developed commercially until more than a century later.

Karol Olszewski and Zygmunt Wroblewski, Polish physicists, first liquefied methane in 1884, demonstrating that natural gas could in principle be stored and transported in liquid form. The engineering of industrial-scale methane liquefaction required many subsequent decades of cryogenic engineering development.

George Mitchell (1919-2013), whose role in the shale gas revolution has been described above, is arguably the most important figure in the history of natural gas technology since the advent of pipeline distribution. His development of economically viable hydraulic fracturing techniques for shale gas production transformed global gas markets and energy geopolitics.

Natural Gas Pipelines: the Invisible Infrastructure

The natural gas pipeline network is among the most extensive and least visible pieces of infrastructure in the modern world. In the United States alone, approximately three million kilometers of pipelines carry natural gas from production areas through transmission lines to distribution systems that deliver it to hundreds of millions of homes, businesses, and power stations. This network was built over more than a century through the investments of hundreds of companies and is the physical foundation of the natural gas economy.

The basic technology of gas pipelines — steel or iron pipes carrying gas at elevated pressure — was established in the nineteenth century. The key technical challenges were managing the high pressures needed to push gas through long-distance lines, constructing reliable compressor stations to maintain pressure over the pipeline route, and ensuring the integrity of the pipe and its connections against leakage. Early gas pipelines operated at relatively low pressures and were limited in the distance they could economically transport gas. As high-strength steel became available and compressor technology improved, pipeline pressures and distances increased dramatically.

The development of electric arc welding in the early twentieth century was crucial to pipeline construction, enabling the joining of pipe sections with gas-tight welds that could withstand the stresses of high-pressure operation and ground movement. Radiographic inspection of welds — using X-rays to identify internal defects — and later ultrasonic testing gave pipeline operators reliable methods to verify weld quality before pipelines entered service.

The Trans-Canada pipeline, completed in 1958, was one of the most ambitious engineering projects of its time — a 3,750-kilometer natural gas pipeline from the Alberta fields to the population centers of central and eastern Canada. The pipeline required crossing major rivers, the Canadian Shield's rocky terrain, and the populated St. Lawrence Valley. Its construction was a major feat of engineering and a major political controversy in Canada, as the pipeline financing debates helped bring down the Liberal government of Louis St. Laurent in the 1957 election.

Modern pipeline construction uses horizontal directional drilling to cross major rivers, highways, and other obstacles without surface disturbance. Pipeline integrity management — using in-line inspection tools ("smart pigs") that travel through the pipeline measuring wall thickness, identifying corrosion, and detecting mechanical damage — allows operators to identify and remediate problems before they result in failures. The safety record of modern natural gas pipelines, while not perfect, is substantially better than that of road transport of equivalent energy quantities.

The Trans-Mediterranean pipeline system — including the Transmed pipeline from Algeria through Tunisia and Sicily to Italy, the Medgaz pipeline from Algeria directly to Spain, and the Galsi pipeline under development from Algeria to Italy — illustrates how pipeline infrastructure has connected North African gas reserves to European markets, diversifying European supply and providing revenue to the exporting countries.

Natural Gas in Residential and Commercial Applications

Natural gas became the dominant residential fuel for heating and cooking in most developed countries through the twentieth century, displacing coal, oil, wood, and manufactured gas as the preferred energy carrier for domestic applications.

The development of the modern central heating system — a furnace or boiler burning natural gas, connected to a distribution system of pipes, radiators or forced-air ducts, and thermostatic controls — was the primary domestic application of natural gas from the 1950s through the 1970s in North America and much of Europe. Gas furnaces and boilers have improved dramatically in efficiency since their introduction: modern condensing boilers, which capture the latent heat of water vapor in the flue gases by condensing it before exhausting it, achieve thermal efficiencies of ninety to ninety-eight percent of the fuel's energy content, compared to sixty to seventy percent for older non-condensing designs.

Gas cooking ranges offered a major advantage over electric ranges in providing immediate, controllable heat that can be adjusted instantaneously rather than through the thermal inertia of an electric heating element. Professional chefs have traditionally preferred gas cooking for this reason, and gas ranges remain the preference of many serious home cooks despite the availability of modern induction electric cooking that has superior controllability to gas.

Natural gas hot water heaters — both tank-type (storing hot water at temperature) and instantaneous or "combi" boilers (heating water on demand) — are major domestic gas appliances. Instantaneous gas water heaters, which became standard in many European countries from the early twentieth century and have been the dominant hot water technology in much of Asia and Latin America, offer the advantage of providing unlimited hot water without the standby heat losses of tank storage.

Gas fireplaces and decorative heaters — which provide the visual appeal of a flame without the fuel handling and ash removal of wood-burning equivalents — became a major domestic appliance market from the 1970s onward. Modern balanced-flue gas fires, which draw combustion air from outside the building and exhaust combustion gases through a concentric flue, avoid the air quality issues of open-flue gas appliances and are suitable for well-insulated modern buildings.

Natural Gas and Industrial Applications

Natural gas is a major fuel and feedstock for a wide range of industrial processes, from the relatively simple (space heating, process heating, steam generation) to the chemically sophisticated (ammonia synthesis, methanol production, hydrogen production).

The steel industry uses natural gas both as a process fuel (in electric arc furnaces, casting operations, and heat treatment) and increasingly as a direct reducing agent in direct reduced iron (DRI) production. The DRI process uses natural gas to convert iron ore to metallic iron (sponge iron) without melting it, providing an alternative to the blast furnace route that does not require coking coal. DRI-based steelmaking is particularly prevalent in regions with cheap natural gas, including the Middle East, where natural gas prices have historically been very low.

The cement industry uses natural gas as a fuel for the high-temperature kilns that calcine limestone and sinter the clinker that is the primary component of Portland cement. The glass industry similarly uses gas-fired furnaces for melting silica sand and other raw materials. Ceramic manufacturers, food processors, paper mills, and chemical plants all use natural gas for process heat in a wide range of temperature ranges from low-temperature drying to high-temperature thermal processing.

The largest single industrial use of natural gas, as noted in the Oil and Biomass articles, is in the Haber-Bosch ammonia synthesis process. Approximately two percent of world natural gas production — approximately 150 billion cubic meters per year — is used as feedstock for ammonia production. The hydrogen required for ammonia synthesis is produced by steam methane reforming (SMR), in which natural gas is reacted with steam over a catalyst at high temperature to produce hydrogen and carbon dioxide. The same SMR process is also used to produce hydrogen for other chemical applications, including the hydrocracking processes in oil refineries.

Methanol — a simpler alcohol than ethanol, with one carbon compared to ethanol's two — is produced from natural gas by steam reforming followed by catalytic synthesis. Methanol is used as a chemical feedstock (for formaldehyde, acetic acid, and dozens of other products), as a motor fuel blending component, and for the production of dimethyl ether, which has properties similar to LPG and can be used as a clean diesel substitute in appropriately modified engines.

The chemical conversion of natural gas to liquid fuels — the Fischer-Tropsch synthesis developed in Germany in the 1920s — was used on a significant scale in Germany during World War II (using coal as the feedstock) and has been employed commercially since the 1950s at the Sasol plant in South Africa (which processes coal and natural gas) and since the 1990s in several large-scale gas-to-liquids (GTL) plants including Shell's Pearl GTL in Qatar. GTL technology produces clean synthetic diesel and other liquid products from natural gas, offering an alternative route to liquid transportation fuels and a way to monetize gas reserves in remote locations where pipeline or LNG infrastructure is not economic.

Compressed Natural Gas and Vehicle Fuel Applications

Natural gas has been used as a vehicle fuel since the 1930s, compressed to high pressure (approximately 200 bar) and stored in steel or composite cylinders on the vehicle. Compressed natural gas (CNG) vehicles have been deployed primarily in urban bus fleets, taxi fleets, and refuse collection vehicles, where the need for frequent fueling stops at a central depot makes the infrastructure challenges of CNG less significant than for private vehicles.

The natural gas vehicle (NGV) sector grew significantly in several major markets through the 1980s and 1990s. Italy has had a significant NGV fleet since the 1930s and today operates approximately one million CNG vehicles — primarily private cars attracted by the significantly lower fuel cost of CNG compared to gasoline in the Italian market. Pakistan and Iran have large NGV fleets driven by government subsidies and domestic gas price policies. Argentina has one of the world's largest NGV fleets, with approximately 2.5 million natural gas vehicles attracted by subsidized domestic gas prices.

Biomethane — produced by upgrading biogas (from anaerobic digestion or landfill gas collection) to pipeline-quality methane — can be used as a vehicle fuel in CNG vehicles indistinguishable from fossil natural gas. Sweden has developed the most extensive biomethane vehicle fuel infrastructure in the world, with biomethane produced from wastewater treatment plants, food waste digesters, and agricultural waste digesters fueling a fleet of natural gas buses, trucks, and cars.

Natural Gas: a Summary Timeline

The history of natural gas spans from ancient seep fires through the commercial gas industry of the nineteenth century to the modern global LNG trade and shale revolution. Key milestones include: the Zoroastrian eternal fire at Baku, burning for centuries before the common era; Chinese use of natural gas for salt production in Sichuan approximately 2,000 years ago; the burning Chimaera in Lycia mentioned by Homer; the first manufactured coal gas street lighting in London in 1807; the commercial discovery of natural gas at Titusville, Pennsylvania (alongside oil) in 1859; the first US long-distance natural gas pipeline from Murrysville to Pittsburgh in 1886; the discovery of the Groningen gas field in the Netherlands in 1959; the first international LNG shipment from Louisiana to England in 1964; the North Sea gas discoveries beginning with West Sole in 1965; Soviet gas exports to Western Europe beginning in 1968; the development of Qatar's North Field beginning in the 1970s; Robert Bunsen's development of the efficient gas burner in 1855; George Mitchell's shale gas breakthrough in the Barnett Shale in 1997; and the shale gas revolution transforming American and global gas markets from 2008 onward.

The countries most shaped by natural gas include Russia, whose vast Siberian gas reserves made it the dominant supplier to Europe for four decades; Qatar, which built a $100,000+ per capita annual income economy on North Field LNG exports; the United States, whose shale gas revolution created the largest gas industry in the world and transformed global markets; the Netherlands, whose Groningen field discovery initiated North Sea development and whose subsequent gas depletion has raised land subsidence challenges; and Australia, which became a major LNG exporter and the world's largest LNG exporter in some years.

Natural Gas Storage and Peak Demand Management

The seasonal and daily variation in natural gas demand — driven primarily by heating demand in winter and cooling (air conditioning) demand in summer — creates a fundamental challenge for the gas industry: production from wells is relatively constant, but consumption is highly variable. Gas storage facilities bridge this gap, accepting gas when demand is low and releasing it when demand is high.

Underground gas storage — using depleted oil and gas reservoirs, aquifer formations, and excavated salt caverns to store large quantities of natural gas under pressure — is the primary storage technology for large volumes. Depleted gas reservoirs, which already have the necessary containment structure and porous rock to hold gas, are the most common storage facility type. The United States has approximately 400 underground gas storage facilities with a total working capacity of approximately 4.5 trillion cubic feet — equivalent to approximately sixty days of average US gas consumption. European gas storage capacity, significantly smaller relative to consumption, proved inadequate for the supply disruption caused by the Russian invasion of Ukraine in 2022, contributing to the severity of the energy crisis.

Salt cavern storage facilities are particularly valuable for short-term, high-deliverability storage. Salt caverns are excavated by injecting fresh water into underground salt formations, dissolving the salt and creating a cavity. The smooth, impermeable walls of salt caverns make them ideal for rapid cycling — gas can be injected and withdrawn at rates far higher than aquifer or depleted reservoir storage. Salt cavern facilities are used to provide emergency response capacity and to manage short-term demand peaks.

Liquefied natural gas peak shaving — storing LNG in insulated tanks at distribution terminals and revaporizing it to meet peak demand — has been a component of gas distribution systems since the development of LNG technology. Small-scale LNG storage is also used to supply gas to communities and industrial facilities not connected to the pipeline grid, with LNG delivered by road tanker and stored in local tanks.

The Economics of Natural Gas

The economics of natural gas have been transformed by the shale revolution, shifting from an era of tightening supply and rising prices in the early 2000s to a period of abundant supply and, in many markets, historically low prices. This transformation has affected every segment of the gas value chain, from producers to pipeline operators to end consumers.

Natural gas prices vary significantly by region because gas is more expensive to transport than oil — the cost of building and operating long-distance pipelines or LNG liquefaction and shipping chains is substantial relative to the commodity value of the gas. American Henry Hub prices, European TTF (Title Transfer Facility) prices, and Asian LNG spot prices can diverge substantially, particularly when regional supply-demand balances differ. The extreme divergence of 2022 — when European gas prices reached ten times American prices following the Russian supply disruption — illustrated the continuing importance of regional market separation even as global LNG trade grows.

The "energy commodity" nature of natural gas means that gas producers face price cycles driven by the balance of supply and demand, modulated by storage levels, weather patterns, and geopolitical events. The American shale gas industry has been characterized by boom-and-bust cycles driven by the rapid response of shale production to price signals: when prices rise, drilling activity increases rapidly; when prices fall, drilling activity cuts back quickly. This high responsiveness creates a more stable long-term price environment than the historical pattern of natural gas prices, which were prone to sharp spikes when pipeline capacity was constrained.

Environmental Considerations in Natural Gas Production

While natural gas produces significantly less carbon dioxide per unit of energy than coal (approximately forty to fifty percent less) and also produces less sulfur dioxide, nitrogen oxides, and particulate matter, its environmental profile is complicated by the issue of methane leakage from the production, processing, and distribution system.

Methane is a far more potent greenhouse gas than carbon dioxide on a short-term basis — approximately eighty-six times more powerful over a twenty-year period. If methane leaks during gas production, processing, or distribution at rates above a certain threshold, the climate benefit of burning gas rather than coal is partially or wholly offset by the methane emissions. The actual leakage rate from the US natural gas system has been controversial, with estimates ranging from approximately one percent to over three percent of production volume.

Well completion and hydraulic fracturing operations have been identified as a major source of methane emissions, along with pneumatic controllers (devices that use gas pressure to operate valves and instruments and vent gas to the atmosphere as part of their operation), storage tank vents, and pipeline leaks. The Environmental Protection Agency and the gas industry have developed regulations and voluntary programs to reduce methane emissions from gas operations, with significant progress made in reducing flaring (the burning of associated gas at oil wells where there is no pipeline connection) and in replacing high-bleed pneumatic controllers with low-emission alternatives.

The practice of hydraulic fracturing itself has been controversial on water quality grounds — concerns that fracturing fluid chemicals might contaminate underground drinking water supplies. The scientific consensus, based on extensive studies including a major EPA study completed in 2016, is that hydraulic fracturing has not caused widespread, systemic harm to drinking water resources at the national level, but that specific incidents of contamination have occurred related to well casing failures, surface spills, and wastewater disposal. The management of produced water — the large volumes of water that flow from shale wells along with gas — including its disposal in deep injection wells, has been linked to increased seismic activity in some regions.

Natural Gas in the Energy Transition

The role of natural gas in the long-term energy transition — from a global energy system dominated by fossil fuels toward one based primarily on low-carbon energy sources — is one of the most contested questions in contemporary energy policy.

The case for natural gas as a "transition fuel" rests on its lower carbon emissions compared to coal, its ability to complement the variability of wind and solar power with fast-responding backup generation, and its role in displacing coal in electricity generation (as has occurred dramatically in the United States and to a lesser extent elsewhere). In the US electricity sector, the shift from coal to gas was responsible for a larger reduction in power sector carbon emissions between 2005 and 2020 than the growth of wind and solar combined.

The case against natural gas as a transition fuel argues that new gas infrastructure — pipelines, LNG terminals, power stations, and heating systems — will have a lifetime of decades, creating a lock-in of gas consumption that may be incompatible with deep decarbonization. If gas power stations built today are still operating in 2040-2050, they will be emitting carbon dioxide at a time when essentially zero-emission electricity is required. Similarly, domestic gas boilers and industrial gas processes, once installed, are typically used for fifteen to thirty years, creating long-term demand that is difficult to redirect.

The rise of green hydrogen — hydrogen produced by electrolysis using renewable electricity — offers a potential pathway for decarbonizing gas-dependent applications by substituting hydrogen for methane in combustion and chemical applications. Some natural gas infrastructure can be adapted for hydrogen transport and use; others require modification or replacement. The economics of green hydrogen relative to natural gas are currently challenging, but technology learning curves and scale effects are expected to reduce green hydrogen costs substantially over the next decades.

Natural Gas in Africa: Emerging Producers and Consumers

Africa's natural gas sector has grown significantly in the twenty-first century, with major discoveries in East Africa and the expansion of existing producing regions in North and West Africa. The continent has substantial undiscovered gas potential and is increasingly recognized as a major future supply region, particularly for European and Asian markets.

Nigeria is the largest natural gas reserve holder in Africa, with approximately 5.6 trillion cubic meters of proven reserves. Nigeria's gas has historically been largely flared at oil production facilities because the infrastructure to capture and commercialize it was lacking, but the development of the Nigeria LNG (NLNG) facility at Bonny Island has enabled the export of substantial gas volumes since 1999. Plans for the Trans-Saharan Gas Pipeline, which would carry Nigerian gas through Niger and Algeria to Europe, have been discussed for decades but face enormous technical, political, and financial challenges.

Tanzania and Mozambique made major offshore gas discoveries in the early 2010s that have the potential to transform both countries into significant LNG exporters. The Mozambique LNG project, led by TotalEnergies at the Anadarko/Area 1 offshore fields, began construction of a major LNG facility before being suspended due to security concerns in 2021 when Islamic insurgents attacked nearby communities. The security situation in northern Mozambique has remained a major challenge for the development of this potentially transformative gas resource.

Algeria is North Africa's largest gas producer and exporter, exporting gas to Europe through the Transmed pipeline to Italy and the Medgaz pipeline to Spain, as well as by LNG from its Arzew and Skikda terminals. Algerian gas has been an important component of European supply since the late 1970s and became more significant following the disruption of Russian supplies in 2022, as European countries sought to increase Algerian imports.

Egypt has undergone a remarkable energy transition in the 2010s, moving from a gas importer (following a period of rapid domestic demand growth that outpaced supply in the early 2010s) to a gas exporter following the discovery of the giant Zohr field in the Mediterranean in 2015. The Zohr field, discovered by the Italian company Eni at a water depth of approximately 1,450 meters offshore Egypt, has estimated reserves of approximately 850 billion cubic meters, making it the largest gas discovery in the Mediterranean. Zohr entered production in 2017 and restored Egypt's gas self-sufficiency within two years of startup.

Coal Seam Gas and Australia's Lng Boom

Australia's emergence as one of the world's largest LNG exporters in the 2010s was driven partly by conventional offshore gas developments in Western Australia and partly by an innovative and controversial technology: the large-scale development of coal seam gas (CSG, equivalent to coalbed methane) in Queensland for LNG export.

Queensland's coal seam gas fields — in the Surat and Bowen basins — were known to contain large gas reserves, but their development for export required overcoming significant technical and social challenges. The gas is held in coal seams hundreds of meters below the surface by the pressure of groundwater in the coal. To produce the gas, water must be pumped from the seam (reducing pressure and allowing gas to desorb), and the produced water must be managed. The scale of water production from CSG fields — potentially hundreds of millions of liters per day across all Queensland CSG operations — raised concerns about impacts on the Great Artesian Basin, one of the world's largest underground water systems, and on agricultural landholders whose properties overlaid the gas fields.

Three large LNG projects — Australia Pacific LNG (APLNG), Queensland Curtis LNG (QCLNG), and Gladstone LNG (GLNG) — were built at Gladstone in Queensland to export CSG-derived LNG to Asian customers. These projects, costing approximately fifty billion dollars in total, represented the first time that CSG had been used as the feedstock for large-scale LNG export — a significant technical and commercial achievement. The projects began production in 2014-2015 and have exported approximately 22-25 million metric tons per year to Japan, South Korea, China, and other Asian buyers.

The Queensland CSG-to-LNG projects attracted significant opposition from farming communities and environmental groups concerned about water, land access, and the long-term social impacts of industrial development in agricultural regions. The conflict between agricultural landholders and gas companies over land access rights created lasting political tensions and led to the development of new regulatory frameworks for managing the social and environmental impacts of CSG development in Australia.

Artificial Lift and Production Enhancement Technologies

As natural gas wells age and reservoir pressure declines, maintaining economic production rates requires intervention. A variety of artificial lift and production enhancement technologies are used to extend the productive life of gas wells and maximize the recovery of gas from reservoirs.

Compressors — installed at the wellhead or in the pipeline system — reduce the back-pressure on the well, allowing gas to flow from the reservoir at higher rates even as reservoir pressure falls. Wellhead compression is the simplest and most widely used form of artificial lift for gas wells. As the reservoir pressure falls further, field compression systems and eventually larger centralized compressor stations are required to maintain production.

Hydraulic fracturing, as described in the shale section, is used not only to initiate production from tight formations but also to re-stimulate aging wells in which the original fractures have closed or in which production has declined due to formation damage near the wellbore. Re-fracturing — perforating and fracturing a well that has already been hydraulically fractured — can restore and in some cases exceed original production rates.

Coiled tubing operations — using a continuous reel of small-diameter tubing that can be inserted into a live, producing well without a full workover rig — are widely used for well stimulation, cleanout of debris or liquid accumulations (a common cause of production decline in gas wells), and other downhole interventions. Coiled tubing technology has advanced significantly in the past three decades, enabling interventions in deviated and horizontal wells that were previously impractical.

Market Structure and Regulation of the Natural Gas Industry

The market structure of the natural gas industry varies significantly between countries, reflecting different regulatory philosophies, historical development patterns, and national energy security priorities.

In the United States, natural gas markets were deregulated over the period from the Natural Gas Policy Act of 1978 through the Federal Energy Regulatory Commission's Order 636 in 1992, which required pipeline companies to provide open access transportation services to any shipper rather than controlling both the gas and the pipeline. This deregulation created a competitive wholesale gas market and a commodity trading system centered on Henry Hub, which has become the world's most important gas pricing benchmark.

In Europe, natural gas market liberalization occurred more gradually and unevenly through the 1990s and 2000s, driven by European Union directives requiring the separation of gas production and sales from pipeline operation (unbundling) and the establishment of competitive markets. The European model of market liberalization coexists with long-term supply contracts and state-owned or state-influenced gas companies in many countries.

In Asia, natural gas markets remain largely organized around long-term bilateral contracts between producers and buyers, often linked to oil prices (the "Japan Crude Cocktail" or JCC pricing formula). The development of spot LNG trading and the growth of trading hubs in Singapore and Japan are gradually making Asian gas markets more liquid and price-responsive, but the long-term contracted structure remains dominant.

Natural Gas Safety and the History of Gas Incidents

Natural gas is generally a safe fuel when properly handled, but its flammability and the potential for leaks to create explosive mixtures in confined spaces have been the source of serious accidents throughout the history of the gas industry. The development of safety standards, regulations, and detection technologies has substantially reduced the risk of gas incidents over time.

The use of odorants to give natural gas a distinctive smell was introduced to enable detection of leaks that would otherwise be undetectable by human senses. Natural gas in its raw state is odorless; the rotten-egg smell associated with natural gas leaks comes from tetrahydrothiophene (THT) or tertiary butyl mercaptan (TBM) added to the gas in tiny quantities at distribution entry points. This odorant addition was made standard practice in the United States following a catastrophic explosion at the New London School in New London, Texas, on March 18, 1937. Odorless natural gas from a nearby gas field had leaked into the school's foundation through an unauthorized connection to a residue gas line; the gas accumulated undetected until a spark from shop class equipment ignited it, destroying the school building and killing between 295 and 319 students and teachers in the worst school disaster in American history. The Texas state legislature mandated gas odorization within weeks of the disaster.

The 1944 Cleveland LNG disaster, described earlier, was another landmark in gas safety history. The lessons learned from Cleveland — the importance of correct material selection for cryogenic temperatures, the need for secondary containment, and the risks of LNG in densely populated areas — were incorporated into subsequent LNG facility design standards.

The development of gas safety regulations, pipeline integrity management programs, and emergency response procedures over the twentieth century has created a substantially safer gas industry. Modern gas distribution systems include automatic shutoff valves that isolate sections of the network in response to pressure anomalies, remote monitoring systems that detect pressure changes indicative of leaks, and regular pipeline inspection programs. Gas meters in consumer premises are designed to cut off supply automatically if a significant leak causes rapid pressure drop.

Synthetic Natural Gas and Biomethane

Synthetic natural gas (SNG) — methane produced by chemical processes rather than extracted from the ground — represents an alternative supply pathway that decouples gas supply from geological occurrence and can use a variety of feedstocks.

Coal gasification to produce SNG was commercialized at the Great Plains Synfuels Plant in North Dakota, which began operation in 1984 and continues to produce gas from lignite coal by gasification, methanation, and gas processing. The plant produces approximately approximately 170 million cubic feet of SNG per day, equivalent to approximately thirty percent of North Dakota's residential gas consumption. The plant was built as an energy security measure following the 1970s oil crises, subsidized by the federal government, and has operated commercially since the mid-1990s.

Biomethane — methane produced from biogas by upgrading (removing carbon dioxide and other impurities) — is a renewable gas that can substitute for natural gas in any application and can be injected into the natural gas grid. As described in the Biomass article, biogas is produced by anaerobic digestion of organic materials including food waste, agricultural residues, and sewage sludge. The upgrading of biogas to biomethane quality (greater than ninety-seven percent methane) requires carbon dioxide removal using pressure swing adsorption, water scrubbing, or amine absorption.

Sweden has developed the world's most extensive biomethane grid injection network, enabling gas from dozens of biogas plants to be upgraded and fed into the natural gas distribution system. The UK, Germany, France, and other European countries have active biomethane injection programs and have set targets for increasing the proportion of gas grid supply from renewable sources.

Power-to-gas technology — using surplus electricity from wind and solar power to produce hydrogen by electrolysis, and then converting the hydrogen to methane by combining it with carbon dioxide (the Sabatier reaction) — offers a pathway to store electrical energy as synthetic methane that can be fed into the gas grid and stored in gas storage infrastructure. The energy round-trip efficiency is modest (approximately twenty-five to thirty percent), but the very large storage capacity of the gas grid relative to battery storage makes power-to-gas attractive for very long-duration energy storage.

Natural Gas and Geopolitics in the 21st Century

The twenty-first century has been characterized by increasing use of natural gas as a geopolitical instrument — by exporting countries seeking to leverage supply dependency for political purposes, by importing countries seeking to reduce vulnerability through supply diversification, and by international institutions attempting to develop rules and norms for a fair, competitive global gas market.

Russia's use of gas supply control as a geopolitical instrument — through the Ukraine gas disputes of 2006 and 2009, the selective use of pipeline access and pricing in dealings with former Soviet states, and the ultimate weaponization of gas supply in 2022 — demonstrated both the power and the limits of energy coercion. The 2022 episode showed that while gas supply cutoffs can impose severe economic pain on importing countries in the short term, they also accelerate those countries' efforts to reduce dependency — potentially at the permanent cost of the exporting country's market position.

The United States' emergence as a major LNG exporter has transformed US energy geopolitics. American LNG gives European allies an alternative to Russian pipeline gas, enabling a harder line in diplomatic relations with Russia than was possible when European energy security depended on maintaining good relations with Moscow. The Biden administration's decision to accelerate LNG export approvals in response to the 2022 energy crisis in Europe was explicitly geopolitical, intended to help European allies reduce their Russian gas dependency.

The competition between Qatar and Australia for dominant positions in Asian LNG markets, the emergence of new African gas producers, and the development of eastern Mediterranean gas resources (primarily offshore Israel and Cyprus) are all reshaping the geography of gas supply and the balance of leverage between producers and consumers in ways that will have significant strategic implications for decades.