Natural gas prices are the highest in the residential sector. In 2023, U.S. households paid an all time high average of 15.2 U.S. dollars per 1,000 cubic feet. Commercial natural gas costs were second-highest, while prices in the electric power sector were the lowest, at around four U.S. dollars on average. Prices for the industrial and electric power customers tend to be close to the wholesale electricity price. All sectors saw a year-on-year increase in natural gas prices in 2022 due to the decline in U.S. natural gas production in the first quarter of 2022, which resulted in high withdrawals of natural gas from storage and an increase in average natural gas prices. The growing natural gas market In recent years, the average natural gas prices for all sectors have been increasing in the United States. In 2022, the residential sector witnessed an increase in natural gas prices higher than 2008, while natural gas prices for other sectors were still lower despite increases in average natural gas prices for those sectors. Meanwhile, consumption of natural gas has increased more than any other fuel type following the 2008 Recession. Petroleum consumption has been more variable, and use of coal has significantly decreased. The price of coal and crude oil had already been increasing since the early 2000s, and was further exacerbated by the financial crisis. Around the same time, the cost of natural gas dropped significantly, making it a more viable economic alternative compared to other fossil fuels. This decrease was in part the result of drastically increased production of shale gas as a result of hydraulic fracturing and other techniques.

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.

The state with the highest price of natural gas for industry in 2023 was Hawaii, standing at 28.4 U.S. dollars per thousand cubic feet, a decrease when compared to the previous year. During the same year, Texas had the lowest industrial natural gas price in the country, at 2.7 U.S. dollars per thousand cubic feet. Meanwhile, the average natural gas price for industry in the U.S. stood at 7.9 U.S. dollars per thousand cubic feet in 2022.

Household prices for natural gas in the United States reached 15.2 nominal U.S. dollars per thousand cubic feet in 2023, representing the highest price during the period in consideration. This was due to the the extreme winter weather events and freeze-offs in the United States which resulted in a decline in natural gas production.

In 2023, the industrial natural gas price in the United States was 4.59 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.

In 2023, the price of natural gas in Europe reached 13.1 constant U.S. dollars per million British thermal units, compared with 2.5 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 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 35 trillion cubic feet in 2050, up from 1.77 trillion cubic feet in 2000.

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.

This statistic gives a forecast of natural gas end use prices between 2015 and 2025 in the United States, by scenario. The average residential price of U.S. natural gas will be 11.19 U.S. dollars per million cubic feet over this period, according to the reference scenario. The reference scenario is a a business-as-usual trend estimate, given known technology and technological and demographic trends.

Consumption of natural gas in the United States amounted to 32.51 trillion cubic feet in 2021. This was a record high, up from 30.65 trillion cubic feet in 2020. Natural gas consumption increased consistently from 2009 to 2019, after over a decade of fluctuation from 1995 to 2008, before decreasing during the COVID-19 pandemic. High demand for natural gas Natural gas is a colorless, odorless fossil fuel that comes from underground rock formations. It is typically used in the United States to generate electricity and heat homes. The electric power sector is responsible for the largest share of natural gas consumption in the U.S., followed closely by the industrial sector. Consumption of natural gas by the electric power sector has doubled since 2005, but remained lower than industrial sector consumption until 2012. Fossil fuel consumption overall Natural gas has the second-highest rate of consumption in the United States following petroleum. After the 2008 Recession, consumption of natural gas has increased more than any other energy source. The use of coal, however, decreased significantly in the past decade as natural gas is seen as a lower-emission alternative and more cost-effective.

Permian production continues to be the engine growth for US onshore hydrocarbon production. Production of crude oil and natural gas has grown each year from 2013–2018 despite the oil and gas industry going through one of the worst downturns during that period. As in other unconventional shale plays, operators in the Permian Basin continue to drill longer laterals beyond 9,000 feet and some reaching as much as 3 miles. The general objective remains to increase the productivity of the new producing wells in a higher proportion with respect to the cost increase associated with these more complex wells. The Permian has also seen a clear trend for larger scale operations of key operators that increases the surface of continuous acreage and allows for more recovery. This has also driven the M&A activity in the Permian with companies like Chevron, Diamondback Energy, and Concho Resources looking to expand their Permian footprint to drive greater efficiency and lower production cost. The limitations to gas pipeline capacity that gave rise to flaring is also expected to ease during 2019–2020, with approximately 4 billion cubic feet of pipeline capacity expected to be added during these two years, giving further lift to Permian production. Read More

According to Cognitive Market Research, the global N Methyldiethanolamine - MDEA market size is USD 781.2 million in 2024 and will expand at a compound annual growth rate (CAGR) of 6.00% from 2024 to 2031.

North America holds the major market of more than 40% of the global revenue with a market size of USD 312.48 million in 2024 and will grow at a compound annual growth rate (CAGR) of 4.2% from 2024 to 2031.
Europe accounts for a share of over 30% of the global market size of USD 234.36 million.
Asia Pacific holds the market of around 23% of the global revenue with a market size of USD 179.68 million in 2024 and will grow at a compound annual growth rate (CAGR) of 8.0% from 2024 to 2031.
Latin America holds the market of more than 5% of the global revenue with a market size of USD 39.06 million in 2024 and will grow at a compound annual growth rate (CAGR) of 5.4% from 2024 to 2031.
Middle East and Africa holds the major market of around 2% of the global revenue with a market size of USD 15.62 million in 2024 and will grow at a compound annual growth rate (CAGR) of 5.7% from 2024 to 2031.
The oil industry holds the highest N Methyldiethanolamine - MDEA market revenue share in 2024.

Market Dynamics of N Methyldiethanolamine - MDEA Market

Key Drivers for N Methyldiethanolamine - MDEA Market

Increasing Demand for Natural Gas to Propel the Market Revenue Growth

The increasing demand for natural gas is estimated to propel the industry revenue growth over the forecast period. MDEA is widely used in natural gas processing plants for removing acidic gases like hydrogen sulfide (H2S) and carbon dioxide (CO2) from natural gas streams. With the growing global demand for natural gas as a cleaner alternative to other fossil fuels, the demand for MDEA in the gas treatment process is expected to rise. For instance, according to the U.S. Energy Information Administration, India's domestic natural gas output is expected to expand by 3.7% year on average, from 3.3 billion cubic feet per day in 2022 to 9.1 billion cubic feet per day in 2050.

(Source: https://www.eia.gov/todayinenergy/detail.php?id=61423#:~:text=We%20expect%20India's%20net%20natural,a%204.9%25%20average%20annual%20increase.&text=Note%3A%20LNG%3Dliquefied%20natural%20gas,to%20its%20natural%20gas%20imports)

Rising Demand in Textile, Paints and Medical Sector to Propel Market Growth

The explosive rise of major economies worldwide has led to the expansion of industries including textiles, paints, and medicine. Textiles, paints, and medical supplies are in greater demand due to population growth and rising living standards. MDEA is a good substitute for TEA esterquats and is frequently used as an active ingredient in fabric softeners. MDEA can be used in the paint industry to cationically modify acrylic polymer dispersions. MDEA is used to create silicone-based textile finishing agents, together with perfluoroalkyl polymers. Subsequently, MDEA is used in the medical field as a precursor for some active ingredients.

Restraint Factor for the N Methyldiethanolamine - MDEA Market

Fluctuation in Oil & Gas Prices to Limit the Sales

The oil and gas sector, which uses MDEA for gas sweetening, is a major source of demand for the substance. Demand for MDEA may decline when oil and gas companies scale back operations and investments when market conditions are poor. For instance, the COVID-19 pandemic caused oil prices to drop significantly, which affected the market for MDEA. During the projected period, this component could impede the growth of the global market for N-Methyl Diethanolamine (MDEA).

Impact of Covid-19 on the N Methyldiethanolamine - MDEA Market

The COVID-19 pandemic has had a significant impact on various industries, including the chemicals sector, which includes the market for N-Methyldiethanolamine (MDEA). The pandemic disrupted global supply chains, causing delays in the transportation of raw materials and finished products. This could have affected the availability of MDEA and other chemicals, leading to potential supply shortages or delays in project timelines for gas processing plants and other industrial facilities. Additionally, the pandemic led to changes in energy consumption patterns, with a decrease in demand for certain fuels like gasoline and jet fuel due to travel restrictions and reduced economic activity. While natural gas remained relatively resilient...

Alaska Gasline Development Corporation (AGDC), Exxon Mobil Corporation (XOM), BP Plc (BP), ConocoPhillips (COP) and TransCanada Corp. (TRP) are jointly undertaking the construction of LNG development in Alaska, the US.The project involves construction of various on-shore infrastructure supporting LNG production, processing and transport. The crude extracted from the gas field with an output capacity of 15 million to 18 million tonnes a year will be processed at the production facility will be transferred to gas treatment plant via pipelines followed by further processing at planned liquefaction facility and to storage and transport via terminal.It includes the construction of a liquefaction plant with a production capacity of up to as 900 billion cubic feet of gas per year, three 5.8MTPA LNG trains, three 160,000m3 LNG storage tanks and one-two jetties.It also includes the construction of a 93km, 0.762m diameter pipeline from the Point Thomson field to Prudhoe Bay, another 1,287km, 1.06m diameter gas pipeline with a capacity to export 3 to 3.5 billion cubic feet gas per day from Nikiski to Prudhoe Bay via Livengood which will facilitate building eight compressor stations of 30kHP each, a gas treatment plant, a liquefaction plant and, gas storage and export terminal.The gas treatment plant at this North Slope facility will purify, chill and compress gas from Point Thomson, Prudhoe and possibly other fields to prepare it for shipment to market. The three train plant will spread across approximately 101ha of land and require 300,000t of steel for construction. This will include 18 CO2-removal modules, eight compression modules, three chilling modules, a power plant, utilities and other buildings.The pipeline to Prince William Sound or Cook Inlet will be buried along most of the route, with trenching and pipe-laying work limited to winter when the frozen ground can support heavy equipment. The pipeline would be designed to move as much as 3.5bcf of gas a day and require up to 1.2 million tons of steel.The project will also include two storage tanks built at the liquefaction terminal, each capable of holding about 3.5 billion cubic feet of gas in the form of LNG.The project is one of the US government’s 50 priority infrastructure projects listed under the "Priority List: Emergency & National Security Projects" document.URS Corporation and Furgo have been appointed to undertake conceptual design and study works.On January 15, 2012, the state government and the development consortium released agreements that aligned their interests in principle and set the stage for the project's engineering, design and permitting.In October 2012, the project cost is estimated as US$65,000 million. In December 2012, feasibility studies for the project commenced.In October 2013, Nikiski area of Kenai Peninsula was selected as the location of the project.On April 20, 2014, the project secured approvals from the Alaska Legislature with major North Slope oil and gas producers and pipeline company TransCanada toward a partnership to develop the proposed Alaska LNG development.On July 21, 2014, Developers submitted an application to the U.S. Department of Energy for exporting liquefied natural gas through pipeline. Both the Energy Department and the Federal Energy Regulatory Commission have to approve LNG exports to more lucrative non-FTA areas like Asia and Europe.On September 10, 2014, XOM Submits Formal Request to Federal Energy Regulatory Commission (FERC). The company sought to begin the pre-file process for the project. It also makes way for the activity related to the environmental assessment necessary for the siting, design and allowance of construction for the proposed project.In November 2014, U.S. Department of Energy has given export approvals for the proposed project. Black & Veatch, Enalytica have been appointed as study consultants for the project.On February 12, 2015, Developers submitted draft environmental and socioeconomic reports for the project to US Federal Energy Regulatory Commission.On February 18, 2015, CH2M HILL Engineers was awarded Pre-FEED (Front End Engineering Design) contract for the LNG marine facilities.Land Acquisition is on to provide space for the liquefaction plant and marine terminal in Nikiski.As of November 2015, the project is in the early stages of assessing financial, technical feasibility and securing permits from various government agencies.In December 2015, Alaska Gasline Development Corporation (AGDC) has approved the 2016 work program for the project.On June 29, 2016, Senate Resources Committee project update hearing meeting was held.In January 2017, preliminary works of US$500 million development were concluded.On April 17, 2017, AGDC submitted planning applications to FERC. AGDC is in the process of preparing draft EIS for the project and slated for completion by second quarter of 2018. the final investment decision is expected to be completed by first quarter of 2019.Planning activities are underway. Read More

In November 2024, the monthly average LNG export price stood at 6.7 U.S. dollars per 1,000 cubic feet. This was a decrease compared to the previous month and lower 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 7.57 U.S. dollars per 1,000 cubic feet in 2023.

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.

This statistic shows the natural gas production costs in North America in 2015, comparing selected natural gas producing region. In that year, the Marcellus Horizontal (shale) field had the lowest natural gas production costs as compared to the other regions outlined above, at a cost of 2.77 Canadian dollars per thousand cubic feet.

Ashuganj Power Station Company Ltd. (APSCL) announced the project financing for the development of a gas-fired combined cycle power plant in Bangladesh in May 2012. The state-owned company signed a deal with a consortium from Sweden and Spain to set up a 450 Megawatt (MW) gas-fired combined cycle power plant. The financing has been provided through a credit facility with an interest rate of 3.3% per annum. The total cost of the project is estimated at $315m. According to the deal, the plant's gross production capacity will be 382.30 MW while the net output will be 373.312 MW. The plant will run at 56.81% efficiency using natural gas of 48.80 million cubic feet (MMcf) per day. The commercially proven capabilities of a combined cycle power plant, such as high efficiency, low emissions and a shorter construction time, will enable this facility to quickly add 450 MW to the country’s total installed capacity. The Ashuganj power station will be the country's second largest power generator and is expected to remove the demand and supply gap and end the power crisis in the country. Read More

According to Cognitive Market Research, the global Artificial Lift Market size will be USD 7.1 Billion in 2024. It will expand at a compound annual growth rate (CAGR) of 5.20% from 2024 to 2031. Market Dynamics of Artificial Lift Market

Key Drivers for Artificial Lift Market

Rising Shale Gas Demand Will Drive Market Growth -Shale gas is natural gas that is trapped within shale rock formations under the earth's surface. Shale gas reservoirs frequently generate both gas and liquids (condensate, water). ALS enables separate control of gas and liquid production, improving flow and preventing liquid loading, which can cut off gas output. For instance, in October 2023, the Energy Information Administration, a US-based government body, reported that US dry natural gas production grew by approximately 1.29 trillion cubic feet in 2023 compared to the previous year. As a result, the growing demand for shale gas is driving market expansion. Rising Oil Demand To Drive Market Growth

Key Restraints for Artificial Lift Market

Fluctuating oil prices impacting investment decisions. Environmental concerns and regulations affecting operations. Introduction of Artificial Lift Market

Artificial lift is a method of reducing bottomhole pressure (BHP) on a development in order to boost well productivity. To lower running pressure at the pump input, a positive-displacement downhole pump, such as a modern progressive cavity pump (PCP), can be employed. It can also be constructed using a downhole centrifugal pump, which could be a component of an electronic submersible pump (ESP) system. Gas lift can reduce bottom hole moving pressure while increasing flow rate by decreasing the thickness of the fluid in the tubes as gas is added to elevate the fluids. The artificial lift can be used to generate flow from a well that is not already flowing or to increase the flow from a well so that it flows at a faster pace. Many oil wells require artificial lift at some point in their life, and some gas wells benefit from artificial lift to remove liquids from the formation, allowing gas to travel more quickly.

Islandmagee Storage Ltd (IMSL) is undertaking the Gas Storage Facility Development in Northern Ireland, the UK.The project involves the construction of an underground facility with a storage volume of up to 500 million m3 (18 billion cubic feet) of natural gas located 1,500m beneath the ground with an injection capacity of 12 million m3 per day and the withdrawal capacity of 22 million m3 per day. It includes the construction of seven caverns with a total capacity of 500 million m3 located 1,400m below the Larne Lough. While each cavern having a capacity of 70 million m3, independently controlled through a sub-surface safety valve, gas plant, a leaching plant, a well pad and a seawater intake plant. It also includes the construction of a compression plant, a dehydration plant and metering equipment to be located adjacent to Ballylumford Power Station providing easy access to the main gas network.The leaching plant will feature seawater and brine pumping facilities such as leaching pumps, brine discharge pumps and brine tanks to be connected to the well pad through two pipelines. The well pad will include 110×45 m flat pad containing wellheads. The seven caverns will each include a wellhead in cellars below the ground level. The well pad will be connected to the gas plant and leaching plant through subsurface pipelines.The seawater intake plant to be located on the eastern shore of Islandmagee used to pump fresh water to the leaching plant and will be operational only during the construction phase.It also includes connecting pipelines that include a 450mm, 3,570m seawater intake pipeline from the inlet structure to the well pad via the seawater intake pumping station and the brine leaching plant building. A 450mm, 3,880m brine outfall pipeline between the well pad and the outfall discharge point via the seawater intake pumping station and 406mm, 725m gas pipeline between the well pad and the main gas plant facilities. A 3D seismic survey was undertaken across part of Larne Lough and northern Islandmagee to determine the viability of gas storage by the development partners in the fourth quarter of 2007.In March 2010, IMSL submitted a planning application to the Northern Ireland Planning Service by completing the Environmental Impact Assessment (EIA) on the project.RPS Consulting Engineers undertake an EIA and prepare an Environmental Statement. In October 2012, IMSL received permission for the development of above-ground facilities.In November 2011, Tesla-IMC International Ltd (Tesla-IMC) has completed the Vibroseis seismic studies within the IMSL's operated petroleum exploration license PL1/10 in Northern Ireland. The study covered a total of 275km of 2D seismic data in relation to the development.Fugro Seismic Imaging Ltd was appointed as the consultant to process the seismic data.In January 2012, IMSL entered into agreements with BP Gas Marketing Ltd (BPGM) regarding the appraisal of the IMSL development project in County Antrim, and the grant of an option to BPGM to acquire a 50.495% equity interest in the project.In May 2013, Islandmagee based contractor Graeme Barr Plant Hire was appointed as enabling contractor. R Elliott Associates Ltd has been appointed as civil engineer. In October 2013, the EU granted the status Project of Common Interest (PCI).In 2014, a draft marine license was approved by the Department of Environment for the offshore elements of the project. In January 2014, BPGM withdrew its equity interest from the project.In August 2014, IMSL submitted an initial application to the EU for a grant to support the drilling and evaluation of the Islandmagee-1 well.On May 19, 2015, IMSL commenced drilling works of Islandmagee 1 which is one out of five wells and completed the same on June 18, 2015.The project is being funded 50% by the EU under their Connecting Europe Facility. VSA Capital Ltd and Centrus Advisors LLP have been appointed as financial advisors.In March 2016, feasibility studies completed and secured a US$2m grant from the EU in May 2016, which is also co-financing the project.In June 2016, IMSL secured US$1.7m (50% of the Front End Engineering Design(FEED) cost) grant from the EU. On November 4, 2016, IMSL appointed two undisclosed FEED contractors for the above-ground facilities and the sub-surface elements of the project. The scope of work also includes a detailed plant design specification for the project, a detailed project plan and cost estimate.FEED contractors will provide a loan of up to US$1.2m to cover costs of the FEED work. The contractor loan combined with the expected EU grant will cover about 75% of the total costs of the FEED work.In April 2018, Costain was appointed as FEED contractor by InfraStrata for the surface elements.In May 2018, WSP has been appointed as FEED contractor.In October 2018, FEED works are nearing completion and InfraStrata is in the process of securing funds. Read More

Natural gas pipeline import prices from Mexico to the United States amounted to 11.1 U.S. dollars per thousand cubic feet in 2021. This was a the peak of the period in consideration and a nearly three-fold increase from the previous year. Meanwhile, imports from Canada stood at 3.71 U.S. dollars that year. Since 1985, figures fluctuated with an overall increase between 2005 and 2008. Natural gas import prices from Canada peaked in 2008 and 2005, at 8.58 U.S. dollars per thousand cubic feet and 8.46 U.S. dollars per thousand cubic feet, respectively.

Global liquefied natural gas prices have shown less volatility in 2024 and 2025 than the years prior, with the benchmark price reaching 14.72 U.S. dollars per million metric British thermal units in February 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 2023 compared to the previous year, with price volatility dropping to 75 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 207.9 index points in November 2024, showing an increase of nearly 20 points that month. This upward trend in natural gas prices contrasts with the comparatively lower crude oil price indices and follows greater heating demand in the winter months. 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 10.05 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 7.57 U.S. dollars per thousand cubic feet in 2023, down from 12.24 U.S. dollars the previous year.