Natural gas fell to 3.02 USD/MMBtu on September 5, 2025, down 1.65% from the previous day. Over the past month, Natural gas's price has fallen 1.74%, but it is still 32.90% higher than a year ago, according to trading on a contract for difference (CFD) that tracks the benchmark market for this commodity. Natural gas - values, historical data, forecasts and news - updated on September of 2025.

Natural gas prices are the highest in the residential sector. In 2024, U.S. households paid 14.59 U.S. dollars per 1,000 cubic feet, down from an all-time high of over 15.2 U.S. dollars per 1,000 cubic feet. Overall, U.S. residential natural gas prices have increased nearly tenfold since 1975. Commercial natural gas costs were second-highest, while prices in the electric power sector were the lowest, at around three U.S. dollars on average. Prices for the industrial and electric power customers tend to be close to the wholesale electricity price. The growing natural gas market U.S. natural gas consumption has increased more than any other fuel after the U.S. oil boom of the 2010s. Petroleum consumption has been more variable, and use of coal has significantly decreased. Today, natural gas is used extensively for electric power generation, with it having overtaken coal as the primary electricity generating source. This is despite coal prices being a lot less volatile and generally lower than natural gas. Future of natural gas on the global stage Natural gas is also an important energy source worldwide. It has been the second-largest source of electricity generation since the 2000s and has slowly narrowed the gap to coal, the world's main power source. In 2024, natural gas-powered turbines the world over generated 6,890 terawatt-hours of electricity.

Winter natural gas prices in the United States are forecast to see a notable increase in 2022/23. U.S. consumers are expected to pay an average of 15.95 U.S. dollars per thousand cubic feet of natural gas. This would mean an increase of over two U.S. dollars and comes in the wake of many countries and regions currently embattled in an energy supply shortage.

Hawaii was the state with the highest price of natural gas for industry in 2024, standing at 28.35 U.S. dollars per thousand cubic feet. This was more than double the price in Massachusetts, which ranked second. Meanwhile, the average natural gas price for industry in the U.S. stood at 3.93 U.S. dollars per thousand cubic feet in 2024.

In 2024, the industrial natural gas price in the United States was 3.93 U.S. dollars per thousand cubic feet. This was a decrease compared to the previous year. In 2008, the U.S. price of natural gas for industry peaked at 9.65 U.S. dollars per thousand cubic feet as a result of the Great Recession. Despite the increase in natural gas prices for the industry sector in recent years, natural gas prices for other sectors were much higher. Regional price variations across U.S. hubs Natural gas prices can vary significantly across different regions of the United States. In 2024, the Waha trading hub in the Permian basin recorded the lowest spot prices due to its proximity to productive oil and gas wells and limited pipeline capacity. Meanwhile, the Henry Hub, which serves as the U.S. natural gas benchmark, averaged 2.2 U.S. dollars per million British thermal units in 2024. Looking ahead, forecasts suggest that Henry Hub prices could more than double by 2026, driven by increased demand. Industry natural gas prices around the world Switzerland has some of the highest natural gas prices for the industrial sector. U.S. prices are especially low in comparison to European countries, which rely on imports. U.S. industrial natural gas consumers paid around one fourth of the price paid by Swiss consumers.

Graph and download economic data for Global price of Natural gas, EU (PNGASEUUSDM) from Jan 1990 to Jun 2025 about EU, gas, World, Europe, and price.

In 2024, the price of natural gas in Europe reached 11 constant U.S. dollars per million British thermal units, compared with 2.2 U.S. dollars in the U.S. This was a notable decrease compared to the previous year, which had seen a steep increase in prices due to an energy supply shortage exacerbated by the Russia-Ukraine war. Since 1980, natural gas prices have typically been higher in Europe than in the United States and are expected to remain so for the coming two years. This is due to the U.S. being a significantly larger natural gas producer than Europe. What is natural gas and why is it gaining ground in the energy market? Natural gas is commonly burned in power plants with combustion turbines that generate electricity or used as a heating fuel. Given the fact that the world’s energy demand continues to grow, natural gas was seen by some industry leaders as an acceptable "bridge-fuel" to overcome the use of more emission-intensive energy sources such as coal. Subsequently, natural gas has become the main fuel for electricity generation in the U.S., while the global gas power generation share has reached over 22 percent. How domestic production shapes U.S. natural gas prices The combination of hydraulic fracturing (“fracking”) and horizontal drilling can be regarded as one of the oil and gas industry’s biggest breakthroughs in decades, with the U.S. being the largest beneficiary. This technology has helped the industry release unprecedented quantities of gas from deposits, mainly shale and tar sands that were previously thought either inaccessible or uneconomic. It is forecast that U.S. shale gas production could reach 36 trillion cubic feet in 2050, up from 1.77 trillion cubic feet in 2000.

View monthly updates and historical trends for Alaska Natural Gas Commercial Price. Source: Energy Information Administration. Track economic data with YC…

The average monthly price for natural gas in the United States amounted to **** nominal U.S. dollars per million British thermal units (Btu) in July 2025. By contrast, natural gas prices in Europe were about three times higher than those in the U.S. Prices in Europe tend to be notably higher than those in the U.S. as the latter benefits from being a major hydrocarbon producer. Europe's import reliance European prices for natural gas rose most notable throughout the second half of 2021 and much of 2022, peaking at over ** U.S. dollars per million Btu in August 2022. The sharp rise was due to supply chain issues and economic strain following the COVID-19 pandemic, which was further exacerbated by Russia’s invasion of Ukraine in early 2022. As a result of the war, many countries began looking for alternative sources, and Russian pipeline gas imports to the European Union declined as a result. Meanwhile, LNG was a great beneficiary, with LNG demand in Europe rising by more than ** percent between 2021 and 2023. How domestic natural gas production shapes prices As intimated, the United States’ position among the leaders of worldwide natural gas production is one of the main reasons for why prices for this commodity are so low across the country. In 2024, the U.S. produced more than ************ cubic meters of natural gas, which allays domestic demand and allows for far lower purchasing prices.

Working gas held in storage facilities in the United States increased by 55 billion cubic feet in the week ending August 29 of 2025 . This dataset provides the latest reported value for - United States Natural Gas Stocks Change - plus previous releases, historical high and low, short-term forecast and long-term prediction, economic calendar, survey consensus and news.

Residential natural gas prices in the United States amounted to 4.52 U.S. dollars per thousand cubic feet in 2021, up from 4.17 dollars per thousand cubic feet in the year prior. In 2019, figures reached the lowest price since the turn of the century, with a peak of 5.69 U.S. dollars recorded in 1985.

Global liquefied natural gas prices have shown less volatility in 2024 and 2025 than the years prior, with the benchmark price reaching ***** U.S. dollars per million metric British thermal units in July 2025. This figure represents an increase from the same period a year earlier. The global LNG benchmark, which is largely influenced by Asian market trading, particularly Indonesian LNG in Japan, serves as a key indicator for the industry's pricing trends. Natural gas prices become less volatile The Asian LNG market experienced less turbulence in 2024 compared to the previous year, with price volatility dropping to ** percent. This relative stability followed an exceptionally volatile 2022, when LNG demand surged due to sanctions on Russian imports. The global natural gas price index, which encompasses European, Japanese, and American markets, stood at ****** index points in July 2025, showing a slight decrease that month. This trend is also reflected in overall lower crude oil price indices. Landed prices vis-à-vis export prices Due to its geographical location, Japan is exclusively reliant on LNG trading for its natural gas supply. As such, Japan's landed LNG spot price is often higher than for other markets, reaching approximately ***** U.S. dollars per million British thermal units in January 2024. By comparison, the world's largest LNG exporter, the United States, has seen its LNG export prices decrease to **** U.S. dollars per thousand cubic feet in 2024, down from **** U.S. dollars the previous year.

Household prices for natural gas in the United States reached 14.59 U.S. dollars per thousand cubic feet in 2024. This was a decrease compared to the previous year, which saw prices peak at more than 15 U.S. dollars. The 2023 price hikes were due to extreme winter weather events, which resulted in a decline in natural gas production and processing.

During the past decade, the worldwide demand for energy has continued toincrease at a rapid rate. Natural gas has emerged as a primary source of US energy. Thetechnically recoverable natural gas resources in the United States have increased fromapproximately 1,400 trillion cubic feet (Tcf) to approximately 2,100 trillion cubic feet(Tcf) in 2010. The recent declines in gas prices have created short-term uncertainties andincreased the risk of developing natural gas fields, rendering a substantial portion of thisresource uneconomical at current gas prices.

In May 2025, the monthly average LNG export price stood at 7.42 U.S. dollars per 1,000 cubic feet. This was a decrease compared to the previous month but higher than prices a year prior. In June 2022, a fire at the Freeport LNG export terminal impacted export capacities, pushing up prices in the months following. Natural gas prices and those for LNG specifically increased in the spring of 2022 following the Russia-Ukraine war as many European countries looked for suppliers outside Russia. The annual LNG export price from the United States stood at 6.41 U.S. dollars per 1,000 cubic feet in 2024.

South Australia (SA) has a long history of petroleum exploration, extending back to 1866, when the first well was dug in the search for oil. The discovery of Permian gas in the Cooper Basin in 1963 was the first commercial discovery of... South Australia (SA) has a long history of petroleum exploration, extending back to 1866, when the first well was dug in the search for oil. The discovery of Permian gas in the Cooper Basin in 1963 was the first commercial discovery of hydrocarbons in SA. By 1969 Cooper Basin gas was being piped 790 km to Adelaide for sale. Apart from the Cooper Basin region, SA is only lightly explored for petroleum. Large areas of SA's sedimentary basins offer significant oil and gas potential. Several of these areas have proven mature source rocks in association with suitable reservoir rocks in sequences ranging in age from Neoproterozoic to Mesozoic. Petroleum provides the majority of the State's primary energy needs. A major use of petroleum is to provide electricity, of which about half is generated from gas. Two thirds of all the gas and most of the liquid petroleum are supplied from the SA portion of the Cooper and Eromanga Basins. Average daily production in 1996 was 373 million cubic feet (10.6 million m3) of sales gas, 1 575 kL (9 900 barrels) of crude oil, 1 100 kL (6 900 bbl) of condensate and 993 tonnes (11 500 bbl) of liquefied petroleum gas (LPG). A small amount of gas (about 2.5 PJ/year) is produced from the Otway Basin in the South-East of the State. Carbon dioxide is produced in the South-East from the Caroline 1 well where production in 1996 was 27 112 tonnes. Existing contracts with the Cooper Basin Producers supply the State's needs in full until 2004 and partial needs to 2013 and those of New South Wales (NSW) until 2006. The AGL contract quantities are less than full requirement from 2001 -2006. Forecast gas demand is set to rise in the medium term with industrial and commercial expansion. South Australia supports the Commonwealth initiative to introduce a competitive market for gas commencing in 1997. Restrictions on interstate trade are being removed, right of access to gas transmission and reticulation systems provided and direct negotiations between gas producers and consumers facilitated. There are 3 740 km of pipelines in place transporting Cooper-Eromanga Basin petroleum to the South Australian and NSW markets. On the 30 June 1995, the SA Government sold the Moomba-Adelaide and Katnook gas pipeline systems to Tenneco Gas Australia (now Epic Energy). The Cooper Basin Producers own the liquids pipeline (LPG/condensate/ oil) from Moomba to Port Bonython. Port Bonython, located on Spencer Gulf near Whyalla, has a 2.4 km jetty built to accommodate tankers up to 100 000 tonnes with a draught of up to 20 m. Petroleum exploration and development in SA are administered under the Petroleum Act, 1940 (onshore) and the Petroleum (Submerged Lands) Act, 1967 of the Commonwealth and 1982 of SA (offshore). Undercurrent legislation, (which is currently under review) unlicensed onshore acreage is open at any time to application whereas vacant offshore areas are only open to application after gazettal. Maximum areas are large - up to 26 000 km2 onshore and 400 blocks (1 block = 5 x 5 minutes) offshore. Initial terms are five years onshore and six years offshore. Competing applications are assessed having regard to the most effective work program. When a commercial discovery is made within an exploration licence, there is a right to a production licence over the discovery area. Production licences are issued for 21 years and are renewable. Pipeline licences are for the same period. In SA, the Crown retains ownership of petroleum in the ground. Ownership of petroleum transfers to a licensee upon recovery, and in return the State levies a royalty at the rate of 10% of the value of petroleum recovered at the wellhead. The Australian and SA royalty and company tax system is competitive with other systems worldwide. A free market exists for oil, condensate and LPG. Ex-Moomba plant natural gas prices from the Cooper Basin are currently of the order of S2.41/GJ (approximately $2.55/Mcf). In 1986 the Government determined that it was necessary to consider the principle of multiple land use to reconcile as and where appropriate, any conflict between the aims of conservation, Aboriginal land rights, agricultural interests and exploration for and development of subsurface petroleum and mineral resources. A Regional Reserve classification under the National Parks and Wildlife Act (NPWA) has been created specifically for the purpose of conservation while at the same time permitting the utilisation of the petroleum and other resources of the reserve. With the full co-operation of Santos and partners, the Innamincka Regional Reserve now covers much of the productive area of the Cooper Basin. Following passage of the Commonwealth Native Title Act, effective from 1 January 1994, petroleum exploration and production licences continue to be issued over land over which Native Title Rights have been extinguished on the advice of the Crown Solicitor. In 1995 a 'safety net' clause was introduced into the Petroleum Act under which a licencee may seek an agreement with the Minister for a first right to any licence which may be terminated due to no fault of the licensee. Extensive databases of petroleum information are held by the Department of Mines and Energy South Australia (MESA) and are readily available and accessible to the public and private sector in digital and hardcopy format. All basic technical data obtained by a licensee in an exploration licence are placed on open file: two years after acquisition onshore and offshore, two years after data were furnished. For production licences onshore, basic data are released five years after acquisition; offshore, one year after data were furnished. The Department provides a 'one stop shop' for the industry and is ready and able to quickly provide data and expert advice to the explorer. A digital database is also available (PEPS-SA) which contains details of all wells drilled, seismic surveys, production statistics etc.

The economics and physical feasibility of hydraulic fractured completions in the Patchawarra and Tirrawarra tight gas sands of Big Lake Field were evaluated using engineering/geologic design considerations and computer simulation to yield... The economics and physical feasibility of hydraulic fractured completions in the Patchawarra and Tirrawarra tight gas sands of Big Lake Field were evaluated using engineering/geologic design considerations and computer simulation to yield predictions of flow results under a range of treatment volumes. The analysis is based on design studies only, as just one well in the field (Big Lake 4) has so far been hydraulic fracture treated in the subject zone, and to date has not been tested for an extended period. Computer simulation models were generated for five separate layers in the Patchawarra interval and one layer in the Tirrawarra interval. Well performance was evaluated at two locations (Big Lake 1 and Big Lake 3), based on the reservoir layer properties within these wells known from electric logs, limited cores and drill stem tests obtained in four wells on the field. The study results indicate that hydraulically fractured treatments are a practical completion method for significantly increasing flow rates from the zones, but that the completion interval and treatment design will need to be carefully tailored because of the high reservoir temperature (325-360 degrees F.) and the presence of interbedded, low compressive strength coals. The model economic analysis results using a $0.60/MCF gas price indicated a range of optimum treatment volumes from 50,000 to 300,000 gallons. The optimum treatment volume appears to be primarily a function of gas pore volume to be drained, and the well location, with the net enhanced production present value profit being strongly a function of the permeability multiplied by thickness product. The impact of the areal and interval rock characteristics variations on the treatment design and economic outcome are great enough that a field testing programme needs to be undertaken in two or more locations to evaluate the probable economics of the overall field development. Detailed coring and logging during drilling and complete pre- and post-fracture engineering evaluation by pressure transient production testing will be mandatory.

Non-assisted flares are a significant fraction of the flares in use today, but there are few studies at real-world conditions. The current work presents a novel indoor testing facility for characterizing non-assisted flares including the effects of crosswind. Multiple flare designs were tested using flare gas flow rates from 1.8 to 113 thousand standard cubic feet per day (MSCFD) with natural gas and propane at crosswind speeds from 0 to 13.1 miles per hour (MPH). Combustion efficiency (CE) and destruction removal efficiency of methane (DRECH4) were determined for all operating conditions. CE > 98% was observed for low crosswind conditions for all flare geometries; however, the 3-in. pipe flare underperformed (CE < 96.5%) for natural gas at higher wind speeds and lower flare gas flow rates (e.g., 6.8 MSCFD and >4.6 MPH). Engineered burners significantly improved performance. The results are discussed in the context of EPA assumptions, prior pipe flare wind-tunnel studies, and proposed scaling relations.

The dataset is a collection of reservoir and production data for the Wolfcamp Shale Formation in the Delaware Basin, a key sub-basin of the Permian Basin, covering the year 2016 on a daily basis. The Wolfcamp Shale is an unconventional hydrocarbon reservoir, consisting of organic-rich mudstone interbedded with carbonates and siltstone, making it a prime target for hydraulic fracturing. The formation is known for its ultralow permeability (0.01 - 0.1 µD), requiring extensive stimulation techniques to enhance oil and gas recovery. The reservoir is located at depths ranging from 8,000 to 10,000 feet, with high pressure (4,500 - 7,500 psi) and elevated temperatures (220 - 250°F). It contains significant hydrocarbons in place, with an estimated 50 billion barrels of original oil in place (OIP) and 450 trillion cubic feet (TCF) of gas in place (GIP). The dataset includes key petrophysical and geomechanical properties, such as porosity (6-12%), total organic carbon (TOC: 3-6%), clay content (20-40%), brittleness index, fracture toughness, and stress distribution, all of which influence fracture propagation and hydrocarbon production. The presence of natural fractures varies across the formation, localized in more brittle zones, while faulting is common, with normal and strike-slip faults impacting stress distribution. The dataset also captures production metrics, including oil production rates (500-5,000 bbl/day), gas production rates (1,000-15,000 MCF/day), water production, water cut (10-80%), and gas-oil ratio (GOR: 800-3,000 SCF/STB), providing insights into well performance and fluid movement. Additionally, injection data from hydraulic fracturing operations, such as injection rates (500-3,000 bbl/day) and fracture conductivity (10-200 mD-ft), are included to assess stimulation effectiveness. The geomechanical stress regime is predominantly normal to strike-slip, and hydraulic fracturing is essential due to the tight nature of the rock.