Natural Gas & LNG Market

  CME Group / NYMEX Natural Gas (Henry Hub) Futures

  Natural Gas Exchange (NGX) Settlement Prices

  Energy Information Administration, U.S. Natural Gas Storage Report (Weekly)

  Energy Information Administration, Short-Term Energy Outlook

Natural gas is primarily methane (approximately 97% by volume), which is an odorless, gaseous compound composed of one carbon atom and four hydrogen atoms (CH₄).

Natural gas formed from terrestrial and marine organisms and marine algae plankton remains that settled at the bottom of isolated (from marine currents), inland ocean basins and were then buried millions of years ago beneath the Earth's surface. This thick layer of organic material was buried beneath mud, sediment and soil, which itself was then buried and eventually solidified into rock. The pressure and heat exerted by the rock on this organic matter results in the low- or non-oxygen anaerobic decay of organic material, which can become reservoirs of coal (and bitumen), oil (petroleum), and natural gas as long as the prerequisite geologic conditions are in place (the greater the depth and the higher the temperature the more the likelihood that gas will develop rather than petroleum). Similarly, the mixture of this insoluble organic matter (kerogen) in sediment rock also leads to the formation of oil and gas shale, again as the result of the existing geologic conditions. Once formed, the gas tended to migrate toward the surface and will collect in locations such as the undersides of domes of impermeable stone. Directly below the impermeable layer is the natural gas, which forms a gas cap; oil is below the gas and under the oil is the saline water of the primeval oceans. Because of the variety of subsurface conditions the composition of the gas differs from one gas reservoir to another.

Natural gas is extracted as a product from subsurface gas reservoirs. Natural gas is also extracted from associated gas reservoirs as a by-product of crude oil extraction operations, which means that the gas is present in a crude oil reservoir, either separate from or in solution with the oil. Condensate(s) / Natural gas liquids (NGLs) are heavier hydrocarbons such as ethane (C₂H₆), propane (C₃H₈), butane (C₄H₁₀), isobutane and natural gasoline, which are found in a gaseous state under the conditions of pressure and temperature found in the reservoir, but which changes to liquid state or phase once at the surface and are extracted and separated from the natural gas stream and are used as petrochemical feedstocks, home heating fuels and in refinery blending.

An additional source of methane is from Methane Hydrates. Methane hydrates are solid deposits composed of isolated cages of water molecules that contain molecules of methane. The solids can be found deep underground in polar regions and in ocean sediments of the outer continental margin throughout the world.

Natural gas is also produced from coalbeds. Coalbed gas is simply natural gas (methane) extracted from certain coal seams.

Sour gas is natural gas that contains not only methane (and some long-chain hydrocarbons), but also H₂S (Hydrogn Sulfide) and/or CO₂ (Carbon Dioxide). Mercaptans, organic sulfur compounds in the form R–S–H, are usually also present. The tubing, pipes and pumps for sour gas must be made of special metal, since H₂S, CO₂, and mercaptans are corrosive. These compounds must be removed before the gas can be sold thus their presence in approximately 40% of the world's untapped fields creates obstacles to developing these sources, with the greatest concentration of sour gas fields being in Middle East and Central Asia (sour gas is also found in Europe, Africa, North and South America)

In the past 2 decades gas supplies have increased substantially due to:

Technological advances in seismic imaging and field assessment capabilities.

Technological advances in deep subsurface / seabed drilling capabilities (terrestrial and offshore).

The development of unconventional gas from tight sands, coal beds, and shale (technological advances in horizontal drilling and hydraulic fracturing techniques; most of the supply increase in unconventional gas has been from the increase in U.S. natural gas reserves; outside the United States there has been almost no exploration of shale resources, and correspondingly little is known about the resource potential in other countries).

Technological advances in deep offshore pipe-laying capabilities.

The development of long distance pipeline infarstructure and interconnections.

The development of natural gas liquefaction infrastructure (liquefaction and regasification) and transport (LNG tankers) capabilities.

These technological advancements and capital investments resulted in declines in exploration and production costs, and increased market accessibility, that has made natural gas price competitive with other energy sources.

Since 1980, proven world natural gas reserves have grown at an annual average of 3.4% (compared with 2.4% for oil). (Source: World Energy Council; 2007 Survey of Energy Resources; page 146)

Seismic surveys utilizing a vibration source at the earth’s surface are used to identify subsurface characteristics and locate subsurface geologic conditions that may indicate the presence of gas or gas / oil reservoirs. The initial survey is to identify subsurface geological structures that have the ability to trap and contain oil and gas in recoverable quantities. The seismic waves take longer to travel through some kinds of rock strata than others. The waves are reflected by the interfaces between geological layers, like echoes. Geophones, which work similarly to microphones, pick up the vibrations and convert them into electrical impulses. These signals are analyzed by special computer programs that generate 3D images of the subsurface.

Based on the seismic data it may be determined that a reservoir with substantial reserves is in an accessible position and there is sufficient confidence that a test well should be drilled. On land, a mobile derrick on a truck is brought in and placed in position. When drilling is performed offshore the floating platform must be positioned over the site (usually aided by GPS). A well is purposefully drilled to progressively narrow as it increases in depth. To prevent the well from caving in, it is cased with steel tube, section by section, and insulated from the surrounding rock with cement. Drilling efficiency is increased by using a mud system composed of a mixture of clean, freshwater as the base, bentonite (sodium montmorillonite, a clay-based drilling lubricant) as the viscosifier and polymers (synthetic) to transport drilled spoil, reduce friction, reduce drilling torque and stabilize the bore hole. The mud is constantly circulated during the boring process and the rock fragments brought back to the surface are constantly analyzed to determine the nature of the subsurface formation. If the test drilling (and additional test drillings) determines that there is a gas reservoir of sufficient size, quality and pressure then a production well will be drilled.

Working oil / gas well and natural gas wells bring gas to the surface. Natural gas that is present within crude oil reservoirs must first be separated and filtered from the oil. The natural gas may also be vented or returned to the field to maintain reservoir pressure or to be extracted at a later date. If the infrastructure is in place then the gas is transferred from the producing fields to a gas processing plant by a series of pipelines (gathering lines) where associated by-products such as butane and propane are separated from the methane. Processed natural gas is then move moved from the processing plant (injected into main trunk international, interstate or intrastate pipelines) to locations where gas companies collect it in huge above or underground storage tanks, or underground, in old gas wells or caverns to have it ready for consumers or resale. See Transmission & Distribution below.

Natural gas reservoirs are located all over the world. However, the economic viability of the reservoir is a question of location and accessibility.

Convert Cubic Feet / Cubic Meters

(Solve for either variable by entering a value in one box; Enter numbers without commas)

Convert Cubic Feet / Btus

(Solve for either variable by entering a value in one box; Enter numbers without commas)

Convert Cubic Feet / Therms

(Solve for either variable by entering a value in one box; Enter numbers without commas)

In its World Energy Outlook 2008, the International Energy Agency (IEA) indicates that proven reserves amount to approximately 180 trillion cubic metres (tcm) at the end of 2007, equal to 60 years of supply at current (production) rates." (World Energy Outlook 2008, International Energy Agency; Executive Summary page 8). The report goes on to further indicate that "56% of those reserves are found in just 3 countries: Russia, Iran and Qatar." Other major producers include the United States, Canada, Algeria, the United Kingdom, Norway, Libya, Trinidad & Tobago, Venezuela, Mexico.

Similarly, the BP Statistical Review of World Energy June 2009, indicates that total reserves stood at 185.02 trillion cubic metres (6535 tcf) at the year-end (2008), an increase of 7.97 tcm relative to the year end-2007 figure.

Nations with the largest proven reserves (year-end 2008) included:
1. Russia (43.3 tcm / 23.4% of World Total Reserves)
2. Iran (29.61 tcm / 16.0%)
3. Qatar (25.46 tcm / 13.9%)
4. Turkmenistan (7.94 tcm / 4.3%)
5. Saudi Arabia (7.5 / 4.1%)
6. United States (6.73 tcm / 3.6%)
7. UAE (6.43 tcm / 3.5%)
8. Nigeria (5.22 tcm / 2.9%)
9. Venezuela (4.94 tcm / 2.6%)
10. Algeria (4.50 tcm / 2.4%)
11. Indonesia (3.18 tcm / 1.7%)
12. Iraq (3.17 tcm / 1.7%)
13. Norway (2.91 tcm / 1.6%)
14. Australia (2.51 tcm / 1.4%)
15. Kazakhstan (1.82 tcm / 1.0%)
Source: BP Statistical Review of World Energy June 2009, Natural Gas, Proved Reseves, p. 22   (.pdf format)

Nations with the largest gas production (year-end 2008) included:
1. Russia (601.7 Bcm / 19.6% of World Total Production)
2. United States (582.2 Bcm / 19.3%)
3. Canada (175.2 Bcm / 5.7%)
4. Iran (116.3 Bcm / 3.9%)
5. Norway (99.2 Bcm / 3.2%)
6. Algeria (86.5 Bcm / 2.8%)
7. Saudi Arabia (78.1 Bcm / 2.5%)
8. Qatar (76.6 Bcm / 2.5%)
9. Indonesia (69.7 Bcm / 2.3%)
10. United Kingdom (69.6 Bcm / 2.3%)
Source: BP Statistical Review of World Energy June 2009, Natural Gas, Production, p. 24   (.pdf format)

Abu Dhabi

In Abu Dhabi, there are 2 companies directly involved in natural gas industry: Abu Dhabi Gas Industries Company Ltd. (GASCO), and Abu Dhabi Gas Liquefaction Company Ltd. (ADGAS). GASCO was founded in 1978 to process the associated gas of Abu Dhabi's onshore gas and then pump it to Al-Ruwais Gas Liquefaction Plant where it is fractionated and exported. ADGAS was established in 1973 and started producing and exporting liquefied gas in 1977. The company's Das Island plant is capable of processing both associated gas and direct extraction gas from Abu Dhabi's offshore fields.

Algeria

Algeria has a large natural gas reservoir located in the north, central interior of the country at Hassi R'Mel with proven reserves of approximately 4.73 tcm. Algeria is the second largest supplier of gas to Europe after Russia and Norway and one of the largest LNG exporters in the world.

Australia

LNG supplies for shipment to the United States is being developed at the Greater Gorgon gas fields located off the northwest coast of Australia (just northwest of Barrow Island). The estimated reserves at the Gorgon / Jansz gas fields are 40 trillion cubic feet. Other natural gas projects in Australia include Wheatstones, Ichthys, Scarborough and QCLNG.

  Google Map Location of Gorgon Gas Field

Austria

Most of Austria’s natural gas is located in the Vienna Basin. There are producing fields in Lower Austria, Vienna and Upper Austria, at depths of between 1,500 feet (500 meters) and 18,000 feet (6,000 meters). All the gas fields are named after the districts where they are located. The largest ones in Lower Austria are: Matzen, Schönkirchen, Zwerndorf, Höflein, Mühlberg, Wildendürnbach, Aderklaa, Breitenlee, Fischamend, Roseldorf and Teufelsgraben. In Upper Austria they are: Haidach, Schwanenstadt, Lauterbach and Voitsdorf. The main field in Salzburg is Nussdorf.

Bangladesh

Gas fields in Bangladesh include:

Haripur Gas Field

Rashidpur Gas Field

Chatak Gas Field

Beanibazar Gas Field

Kailashtilla Gas Field

Brazil

In Brazil, natural gas is found in Campos Basin (Rio de Janeiro State) and in Santos Basin (São Paulo State). Additional associated gas is found in the Urucu and Juruá oilfields (Amazonas).

Denmark

Denmark has several offshore oil fileds in the North sea (Danish Sector) and associated gas is produced at the Syd Arne platform and the gas is exported through a subsea pipeline to Jutland (Nybro). Associated gas is also produced at Gyda platform (UGT Cluster) and the gas is exported to Germany via the Ekofisk centre and the Gassled system.

Indonesia

The Senoro-Donggi gas field is located near the island of Sulawesi. Most of Indonesia's natural gas production results in LNG shipments to Japan (approximately 70% of annual production). Indonesia was once the largest exporter of LNG but has become second to Qatar.

Iran

Iran added an estimated 43 trillion cubic feet (a 5% increase over 2008) in proved reserves during 2009.

One of the largest natural gas fields in the world, the South Pars Gas Field (which is also an active petroleum pumping area), is located in the Persian Gulf, approximately 60 miles off the coast of Assaluyeh in southern Iran (an area of approximately 1,300 square kilometers in size; The other part of the field, in Qatari waters, is known as North Field). The field, with estimated reserves of 13 trillion cubic meters (tcm), is owned and operated by the National Iranian Oil Company (NIOC) and production is targeted at Asian and European markets. Iran has an estimated 26 tcm of natural gas reserves in total (the second largest in the world; the Oil and Gas Journal, estimates Iran's gas reserves at 974 trillion cubic feet / tcf), accounting for approximately 16% to 19% of world reserves. Additional major gas fields in Iran include North Pars, Tabnak, and Kangan-Nar.

  Google Map Location of Assaluyeh / South Pars Gas Field

Kazakhstan

Kazakhstan holds significant proved reserves but the country experienced a decrease of 15 trillion cubic feet in reserves in 2009.

Kuwait

In 2006, natural gas was discovered in the deep Jurassic reservoirs at Rahiya, Mutriba, Um Niga and other fields in Kuwait.

Nigeria

Nigeria is one of the top ten nations with substantial proved reserves the greatest potential to increase both reserves and production based on its local geology.

Norway

The Ekofisk, Eldfisk and Embla oil and gas fields are located in the Ekofisk area off the southern coast of Norway (North Sea sector). The fileds are located in water depths of 70 to 75 meters. Ekofisk was the first Norwegian offshore field to begin production. It is tied to Teesside in the United Kingdom and Emden in Germany by the Norpipe pipelines for oil and gas respectively.

The Ormen Lange gas field located approximately 75 miles off the western coast of Norway is one of the largest gas fields in the Norwegian Sea. The infrastructure for the project was developed and installed by StatoilHydro and the production is operated by Shell (the field was discovered in 1997 and commenced production in October 2007). The field has been developed with sea-floor installations at depths of between 800 and 1,100 meters (there are no above surface installations), combined with an onshore plant at Nyhamna in Aukra municipality in Norway, for processing and exporting the gas to the United Kingdom. After full completion of all facilities the field is projecte to produce produce 70 million cubic meters per day; recoverable reserves are estimated at 397 Bcm.

Following processing at the onshore facility in Aukra, the gas will be exported through the 750 mile (1,200 kilometer) long Langeled pipeline, to the reception center in Easington on the east coast of the United Kingdom. The gas can also be transported via the riser platform on the Sleipner field in the North Sea to customers on the European continent.

  Google Map Location of Ormen Lange Gas Field / Nyhamna Processing Plant

In June 2009, Shell Oil indicated that it had identified a field named Gro that may hold 10 to 100 Bcm. Additional Norwegian fields include Kvitebjoern and Oseberg.

Norway's oil company, StatoilHydro, also operates the offshore Snoehvit LNG plant near Hammerfest in the Barents Sea (above the Arctic Circle). The gas is pumped from the sea floor to the island of Muolkot (Melkoya) through one of the longest pipelines in the world (approximately 90 miles). However, since the decline of energy prices during 2008 / 2009 (production commenced in 2007), and also due to cost overruns during the construction process and start-up, the operation is less profitable than had been projected. Secondly, there is the environmental concerns related to operating in a remote wilderness region.

  Google Map Location of Snoehvit / Melkoya Processing Plant

Qatar

Qatar has the third largest known deposit reserves of natural gas in the the world (25.46 trillion cubic meters / 899.3 trillion cubic feet / approximately 13.9% of total world reserves). The nation's natuaral gas deposits are located off the northeast shore in the Gulf of Arabia, and the region is referred to as the North Field (approximately 6,000 sq km and an area that Qatar shares with Iran). The North Field was first discovered in 1971 and Qatargas was established in 1984 to develop the offshore natural gas deposits.

The Ras Laffan 3 and the Qatargas 3 LNG train projects will produce and process LNG for delivery to the Golden Pass LNG regasification terminal under construction near Sabine Pass, Texas, Port Arthur ship channel (scheduled to be completed in mid-2010), which is owned by Qatar Petroleum (70%), ExxonMobil (17.6%) and ConocoPhillips (12.4%). The new world class Q-Flex LNG vessels will be providing the LNG transport, which carry approximately 45% more LNG than existing LNG vessels.

Ras Laffan Industrial City (RLC) is located on the northeast coast of Qatar, approximately located 50 miles / 80 kms north east of Doha. ExxonMobil, Shell, Dolphin Energy, Qatargas and RasGas LNG all have production facilities located here, which are centered around the North Field gas deposits. RasGas currently operates five LNG trains with 20.7 million metric tons per annum (mtpa) of production capacity. Qatargas and RasGas combined were originally scheduled to produce approximately 77 million metric tons of LNG per annum by 2010. There are also 2 gas to liquids production facilities (produces low-sulphur diesel) located in RLC, ORYX GTL, a joint venture between Qatar Petroleum (51%) and Sasol of South Africa (49%), and Pearl GTL, a joint venture between Qatar Petroleum and Shell (the first train is scheduled to commence operations in 2010). RLC also operates a deep-water port capable of accommodating the largest LNG, VLCCs and heavy cargo/dry cargo vessels as well as supply vessels.   www.raslaffan.com.qa/

  Google Map Location of North Field / Ras Laffan Industrial City

Russia

Russia has the largest known deposit reserves of natural gas in the the world (43.3 trillion cubic meters / 1,529.2 trillion cubic feet / approximately 23.4% of total world reserves).

The largest natural gas company in the world is Gazprom in Russia based on its existing pipeline network and control of approximately 23% of the world's supply. Gazprom is the largest supplier of natural gas to the European Union (and has no alternative customers to European demand). The International Energy Agency estimates that Gazprom by 2020 will need new gas fields capable of producing about 300 bcm annually, or half the company's total capacity, if it is to meet demand. The IEA also estimates that Gazprom is investing less than 60% of the $22 billion in annual capital expenditures required to bring those new fields on line in time. The company presently operates the large Yuzhno-Russkoye field in central Russia, and in 2007 the company purchased the Kovykta field located in Siberia from TNK-BP (BP, Alfa Group, Access Industries, Renova Group; However, this field is located in a region where Winter temperatures can be decline to well below zero for long periods of time and the development of the field and the necessary infrastructure is coming at a point in time where steel and heavy equipment prices have increased substantially).

Developing new sources of natural gas is a priority for Gazprom, given that production at its three largest fields (Yamburg, Urengoy, and Medvezh’ye) is in decline.

Russia’s Yamal Peninsula in northwestern Siberia has ample natural gas resources and should provide a major increase in Russian production over the long term. In 2008, state-owned Gazprom began construction of a trunk pipeline to connect Bovanenkovo field, the largest on the Yamal peninsula, to existing pipeline infrastructure. Also in 2008, Gazprom drilled the first production well in the Bovanenkovo field. Gazprom intends to increase production from the Yamal peninsula to 12.7 trillion cubic feet by 2030, both to meet domestic demand for natural gas and to double the size of its exports from current levels.

Two other major natural gas projects also are underway in Russia: one to develop the resources around Sakhalin Island on the country’s east coast and another to develop the Shtokman field, off its western Arctic coast. The Sakhalin-1 project began supplying modest amounts of natural gas to domestic consumers in 2007. Production volumes from the first development phase are limited, however, until all the parties involved can agree on how the natural gas should be exported. Production from the second development phase will be exported as LNG, beginning in the first half of 2009, with supplies from the Sakhalin-2 LNG facility expected to reach its total capacity of 9.6 million metric tons in 2010. The Shtokman natural gas and condensate field in the Barents Sea is officially scheduled to begin producing 840 billion cubic feet of natural gas in 2013 (shipped via pipeline), with additional supplies for LNG anticipated beginning in 2014. That schedule may, however, prove to be overly ambitious.

Saudi Arabia

Early in January 2009, Saudi Aramco announced the loaction of several new fields: Jaouf-II (300 km northwest of Dhahran), Ramthan-IX (400 km northwest of Dhahran), Nayashin-I (460 km northwest of Dhahran), Jareed-101 (130km north of Dhahran) and Khorsaniya-114 (138km north of Dhahran ). New exploration is centered within the Rub' al Khali desert region (also sometimes referred to as the Empty Quarter).

  Google Map Location of Rub' al-Khali desert region

Trinidad and Tobago

Natural gas fields are located offshore of the southeast and north coasts of Trinidad. The Atlantic LNG facility located at Port Fortin is used to liquefy natural gas for export primarily to markets in the United States and Spain.

Turkmenistan

The largest natural gas field is located at South Iolotan (sometimes spelled Yolotan-Osman), which has an estimated 4 trillion and 14 trillion cubic metres of gas. However, the nation does not have a well-developed internal gas transmission pipeline infrastructure and gas exports are primarily piped through Russia. It is estimated that Turkmenistan possesses the fouth-largest natural gas reserve in the world.

United States

The U.S. natural gas system encompasses hundreds of thousands of wells, hundreds of processing facilities, and over a million miles of transmission and distribution pipeline.

As of December 31, 2008, estimated proved reserves of dry natural gas in the United States were 244,656 billion cubic feet / Bcf (Source: Energy Information Administration). Just about all of the natural gas produced within the United States is also consumed domestically. Most new exploration for natural gas in the United States is concentrated in the state of Texas. In 2006, a record 31,687 natural gas wells were drilled in the United States.   tonto.eia.doe.gov/dnav/ng/ng_enr_dry_dcu_NUS_a.htm

Another promising onshore source has come from unconventional gas. Unconventional gas is from underground shale structures. For instance, one of the largest locations within the United States is the Marcelus Shale formation, which extends from West Virgina to southern / western New York. The area is now considered a viable exploration investment option due to recent advances in horizontal drilling technology and recent natural gas price increases. Other similar undeground shale structures include the Barnett shale in northern Texas and the Haynesville shale along the Texas and Louisiana border.

In its World Energy Outlook 2008, the International Energy Agency (IEA) indicates that unconventional gas resources are substantial, "amounting perhaps to over 900 tcm, with 25% in the United States and Canada combined". (World Energy Outlook 2008, International Energy Agency; Executive Summary page 8)
www.worldenergyoutlook.org/docs/weo2008/WEO2008_es_english.pdf   (.pdf format)

The Energy Information Administration reports that onshore production of natural gas in the United States reached 17.2 tcf in 2007, increasing 4.3% over the previous year. The increase in onshore production occurred as the number of rigs drilling natural gas prospects peaked and then leveled off after a slight decline, ending an upward trend that began in mid-2002. The leveling-off occurred largely in the last quarter of the year, when weekly rig counts were below levels observed in the summer and at times below those of the same time the previous year.

The EIA also indicates that Total U.S. proved reserves of dry natural gas rose by 6.9 trillion cubic feet (Tcf) from 2007 to 2008. That increase was on top of production of 20.5 Tcf and reflects another strong year of net proved reserve additions of natural gas in the United States (natural gas proved reserves are now at their highest level since EIA began reporting them in 1977). Total natural gas discoveries of 29.5 Tcf represented the sixth consecutive yearly increase. Discoveries include discoveries of new fields, identification of new reservoirs in fields discovered in prior years, and extensions (reserve additions that result from the extension of previously discovered reservoirs). In 2008, 90% of total discoveries came from extensions of existing fields. In 2008, new field discoveries totaled 1.2 Tcf and new reservoir discoveries in previously discovered fields totaled 1.6 Tcf, showing fairly large percentage increases over 2007, but accounted for less than 10% of total discoveries.

The EIA Short-Term Energy Outlook projects that total U.S. marketed natural gas production is expected to increase by 2.9% in 2008 and by 0.3 percent in 2009. New deepwater supply infrastructure, which came online at the end of 2007, is expected to drive growth of 5.8% in the Gulf of Mexico in 2008. In addition, production from the Lower-48 onshore region is expected to increase by 2.5% in 2008 led by the development of unconventional supply sources.   www.eia.doe.gov/emeu/steo/pub/contents.html

According to Baker Hughes, In., the weekly average number of rigs drilling for natural gas was 1,466 in 2007, which was about 94 rigs more on average per week than in 2006. The U.S. gas rig count peaked at 1,606 rigs for the week ended September 12, 2008 (out of total of 2,031 rigs in operation), and then hit a low of 665 in the week ending July 17, 2009 (out of a total of 876 rigs, a 57% decline in total rigs in operation) in response to a building supply and the decline of wellhead natural gas prices. The number of rigs has increased since that point but only by several dozen, primarily horizontal rigs.   investor.shareholder.com/bhi/rig_counts/rc_index.cfm

In July 2007, the Independence Hub production platform in the Gulf of Mexico, located on Mississippi Canyon block 920 approximately 123 miles southeast of Biloxi, Mississippi, came online, operating at the greatest water depth in the world with the world’s largest production capacity. The facility, which is primarily owned by Enterprise Products Partners, LP, is designed to produce 1 Bcf per day of natural gas from 10 anchor fields (eight of which are operated by Anadarko, who operates the facility with approximately 61% of the throughput capacity) at a water depth of 8,000 feet (2,400 meters). The Independence Hub underscores the importance of deepwater prospects in the domestic natural gas production, as a record number of drilling rigs operated in the Gulf of Mexico’s deep water in 2007, despite the decline in overall offshore drilling.

In addition to proved natural gas reserves, there are large volumes of natural gas classified as undiscovered recoverable resources. Those resources are expected to exist because the geologic settings are favorable. Over half of all onshore undiscovered gas resources are located in the Alaska and Gulf Coast regions. Over one-third of all undiscovered gas resources are estimated to be in Federal offshore areas, primarily near Alaska, in the Gulf of Mexico, and along the Atlantic Coast.

Natural Gas Companies (Public & Private Sector)

For LNG transport please see the International Trade & Shipping page.

Most of the gas fields are located in countries, and regions within those countries, where the largest consumers of the gas are not located. Thus, the gas must be transported over long distances. The most economical method of transporting natural gas is by pipeline. Gas pipelines are usually located under ground or run along the sea bed. In arctic regions the pipelines are laid above ground on stilts due to the permafrost.

Within metropolitan and suburban areas a local distribution company (LDC) provides natural gas to commercial and residential customers (end-users or the point where the gas is finally burnt and consumed). LDCs contract for gas supplies and for interstate pipeline transportation to bring natural gas to their own "city gates," where they deliver gas by their own distribution pipelines.

Because natural gas is colorless, odorless and tasteless, mercaptan (a chemical that has a sulfur like odor) is added before distribution, to give it a distinct unpleasant odor. This serves as a safety device by allowing it to be detected in the atmosphere, in cases where leaks occur.

Brazil Gas Pipeline Interconnection Grid

The Bolivia-Brasil pipeline is 3,150 km long, with 557 km in Bolivia and 2,593 km in Brazil. The project was developed through two different companies: Gas Transboliviano (GTB), which owns and operates the assets in Bolivia, and Transportadora Brasileira Gasoduto Bolivia Brasil (TBG), which owns and operates the Brazilian portion of the pipeline.

United Kingdom Gas Pipeline Interconnection Grid

The Rough storage facility located off the east coast of the United Kingdom near Easington, and the Easington Terminal, is owned and operated by Centrica, a sucessor company from the breakup of British Gas. The facility is the largest gas storage facility in Western Europe (natural gas is pumped to a cavern beneath the seafloor, which can hold approximately 100 Bcf).

The Bacton Interconnector, located on the east coast of the United Kingdom, connects to North Sea Norwegian offshore suppliers.

National Grid operates 82,000 miles of distribution pipelines, approximately 1/4 of U.K. distribution.

Norway Gas Pipeline Interconnection Grid

The Gassled joint venture, with Gassco as its operator:

Europe Gas Pipeline Interconnection Grid

OMV Gas Transit Pipeline Systems in Austria operates the Trans-Austria-Gaspipeline (TAG), Hungaria-Austria gas pipelines (HAG), March-Baumgarten gas pipelines (MAB), Penta West gas pipelines (PW), South-East pipeline (SOL), Kittsee-Petrzalka-Gaspipeline (KIP), South-East-Gaspipeline (SOL), Primary Grid System (PVS) and the West-Austria-Gaspipeline (WAG). The March-Baumgarten station is an entry point for Russian-supplied gas.

The Baku-Erzurum pipeline transports gas from the Azerbijan Caspian Sea region to Turkey. There is a proposal to extend the pipeline from Erzurum in Turkey to Europe (the NNabucco pipeline). The competing pipeline is the proposed South Stream pipeline, which will transport gas from Beregovaya in Russia underneath the Black Sea to Europe.

U.S. Gas Pipeline Interconnection Grid

The United States has one of the most extensive interstate / intrastate pipeline grids in the world, which is actually a series of interconnections between various independent pipeline operators. The system extends from the gas producing basins in the the Gulf Coast, the Southwest, and Canada to metropolitan delevery points. Once gas is injected into the interstate pipeline system it can no longer be differentiated. A Shipper usually contracts with the pipeline operator for specific receipt point(s) and delivery point(s) for a specific quantity of gas. Thus, gas entering the system usually must meet a minimum quality criteria:

The Henry Hub is the largest centralized point for natural gas delivery in the United States. The "Henry Hub" is actually the Henry Gas Processing Plant (owned and operated by Sabine Pipe Line, LLC, which is owned by Texaco) located in the town of Erath in Vermillion Parish, Louisiana. The Henry Hub interconnects nine interstate and four intrastate pipelines, which includes the:

In the United states, many natural gas marketers use the Henry Hub as a physical contract delivery point. Becasue of the role that the Henry Hub plays as a physical delivery location (the pipelines that interconnect at the Henry Hub provide access to natural gas markets in the Midwest, Northeast, Southeast, and Gulf Coast regions of the United States) is has become the price benchmark for spot trades (physical market) of natural gas and represents the most actively traded point for U.S. natural gas markets (futures market).

In 2007, at least 50 natural gas pipeline projects were completed in the Lower 48 States, 4 more than were completed in 2006. These projects added close to 1,674 miles of pipeline and more than 14.9 Bcf per day of new capacity to the national natural gas pipeline grid, continuing the expansion cycle that started in 2005. The cost of this 2007 expansion activity was approximately $4.2 billion, compared with $2.3 billion expended in 2006 on 46 projects that added 1,600 miles of new pipeline and 12.7 Bcf per day of new capacity to the grid.

Thirty-six of the 50 projects completed in 2007 involved expansion of the interstate natural gas pipeline network, while the remainder improved capacity and transportation service on intrastate natural gas pipelines or new large-scale header (gathering lateral) systems designed to transport new natural gas production from expanding natural gas fields. In fact, out of the 14 non-interstate natural gas pipeline projects completed during the year, about one-half involved adding new transportation capacity from developing production areas or constructing new intrastate pipeline sections to interconnect new production with the interstate pipeline network. Such projects were common in the expanding natural gas production areas of the western sections of Wyoming and Colorado and in the Barnett shale formation of northeast Texas.

The largest natural pipeline project completed in 2007, the 1.2 Bcf per day, 172-mile Centerpoint Energy Company’s Perryville expansion project, was constructed principally to link the expanding natural gas production flowing on Texas intrastate pipeline systems to the interstate system of natural gas pipelines found in northern Louisiana. The second-largest pipeline project completed is the Tenneco Deepwater Link Project at 1 Bcf per day, which connects the Independence Trail deepwater offshore gathering system and the Tennessee Gas Pipeline. In the Rocky Mountain area of western Colorado, the 0.75 Bcf per day Rockies Express West (Enterga) was completed in 2007. This is the third largest natural gas pipeline project in 2007 and the first stage of the planned continental Rockies Express Pipeline system, which will eventually transport Wyoming/Colorado natural gas to the northeastern United States markets. The second stage of the Rockies Express system, from eastern Colorado to eastern Missouri, will be placed in full service in mid-2008 (portions located in Colorado and Kansas were placed in service in early 2008).

Natural gas pipeline construction activity in 2007 also included the installation of the first pipeline since 1972 designed to transport LNG from an import facility, the Excelerate Energy LLC’s Northeast Gateway LNG terminal, located 10 miles offshore from Gloucester, Massachusetts, which is about 50 miles northeast of the existing Everett LNG terminal located onshore. During the year, a segment of the North Baja Pipeline system was modified to allow for future LNG-sourced natural gas from import facilities located on the northwest coast of Baja California to be delivered to customers located in the United States. Previously, the pipeline segment could transport natural gas only from the United States to Mexico.

In the State of Texas, the Railroad Commission has primary regulatory jurisdiction over oil and natural gas industry, pipeline transporters, natural gas & hazardous liquid pipeline industry, natural gas utilities, the LP-gas industry.

Alliance Pipeline

Alliance Pipeline system operates a 210 mile (Canada) / 886.41 mile (U.S.) pipeline system from British Columbia and northwestern Alberta through Saskatchewan, North Dakota, Minnesota, and Iowa to its terminus in Illinois (connects to ANR, Midwestern, NGPL, Nicor, Peoples, Vector).

El Paso Corporation owns/operates the:

Tennessee Gas Pipeline operates a 14,200 mile pipeline system from the Mexican border to Canada (supplies from Gulf of Mexico, Texas, Appalachia, and Canada) and serves markets across the Midwest and mid-Atlantic regions, including major metropolitan centers such as Chicago, New York, and Boston.

Kinder Morgan Energy Partners LP owns/operates the:

Rockies Express (REX) pipeline system operates a 1,679 mile, 36-inch / 42-inch diameter pipeline system from Meeker (Rio Blanco County), Colorado to Clarington (Monroe County), Ohio. Co-owners include Sempra Energy and ConocoPhillips. The system consists of REX-Entrega, REX-West and REX-East.

TransColorado Gas Transmission

Trailblazer Pipeline

KM Interstate Gas Transmission, LLC

KM Wattenberg Transmission, LLC

KMI Casper

KM Texas Pipeline

KM Tejas Gas Pipeline, LP

KM South Texas Pipeline, LP

KM Ship Channel Pipeline, LP

KM Border Pipeline, LP

KM North Texas Pipeline, LLC

Horizon Pipeline Company, LLC

KM Mexico Pipeline

Panhandle Energy owns/operates the:

Panhandle Eastern Pipe Line Company operates a 6,500 mile pipeline system with access to diverse supply sources and can deliver 2.8 Bcf/d of natural gas to Midwest and East Coast markets.

Florida Gas Transmission Company, LLC operates a 5,000 mile pipeline from the Gulf coast to Florida.

Trunkline Gas Company operates a 3,500-mile pipeline system with access to Gulf Coast supply sources which can deliver 1.5 Bcf/d of natural gas to Midwest and East Coast markets.

Sea Robin Pipeline Company includes about 450 miles of interstate pipeline reaching into the Gulf Coast deepwater supplies. It stretches from the Ship Shoal area in the central Gulf of Mexico to the East Cameron area in the western Gulf. Sea Robin Pipeline Company is capable of delivering 1.0 Bcf per day to a variety of onshore national and regional markets.

Spectra Energy Transmission owns/operates the:

Algonquin Gas Transmission operates a 1,100 mile pipeline system in New England capable of delivering 1.9 Bcf per day. Algonquin connects to Texas Eastern and Maritimes & Northeast.

Texas Eastern Transmission operates a 9,040 mile pipeline system from the Gulf Coast to Northeast United States capable of delivering 6.2 Bcf per day.

East Tennessee Natural Gas operates a 1,432 mile pipeline system in Southeast United States capable of delivering 1.3 Bcf per day.

TC PipeLines, LP owns/operates

Northern Border Pipeline operates a 1,249 mile interstate pipeline system linking the Western Canadian Sedimentary Basin and the United States Williston Basin to markets in the midwestern United States. (ONEOK Partners, LP)

Tuscarora Gas Transmission Company operates a 240-mile interstate pipeline system, which originates at an interconnection point with TransCanada’s GTN System near Malin, Oregon, and runs southeast through northeastern California and northwestern Nevada, and is capable of providing 190 Mcf per day.

Great Lakes Gas Transmission LP operates a 2,115-mile pipeline system from the Minnesota-Manitoba border at Emerson to the Michigan-Ontario border at St. Clair, and is capable of providing 2.5 Bcf per day.

TransCanada owns/operates:

Alberta System operates a 14,601 mile pipeline system capable of providing 11.1 Bcf per day.

Canadian Mainline operates a 9,292 mile pipeline system from Alberta’s eastern border to Montreal and is capable of providing 8.1 Bcf per day.

Williams owns/operates the:

Northwest Pipeline consists of a 3,900 mile pipeline system from Northwest New Mexico to Seattle and Portland.

Transcontinental Gas Pipeline consists of a 10,500 mile pipeline system from Houston, TX / Gulf od Mexico to Atlanta, MidAtlantic region and New York City.

Gulfstream Pipeline consists of a 581 mile pipeline system from Mississippi / Gulf of Mexico to Tampa / Florida markets.

Williams also operates 8,500 miles of gas gathering lines.

Planned Pipelines (U.S. & International)

AES Ocean Express is a planned natural gas pipeline project for southeastern Florida   www.aesoceanexpress.com/home.asp

ConocoPhillips and BP proposed in April 2008 (ConocoPhillips had actually first approached the public and state authorities of Alaska in November 2007), to begin the planning of a natural gas pipeline (the Denali Project) from the Prudhoe Bay / North Slope area of Alaska, across Canada to a connection within the lower 48 states (tentatively indicated as the Chicago area) and would include connections for Anchorage, Alaska, and the tar sands extraction projects in Alberta, Canada. In Spring of 2008 both ConocoPhillips and BP (and Exxon Mobil who is also a local producer) appeared to be more flexible on the issue of the precondition for the State to first negotiate fiscal terms of royalties and taxes for potential shippers. TransCanada also insists that it will have to be part of any project that crosses Canadian territory.   www.gov.state.ak.us/agia/

Gulf Crossing is a planned 353-mile, 42-inch diameter interstate natural gas pipeline that will begin near Sherman, Texas and end near Tallulah, Louisiana   www.gulfcrossing.com/

MEDGAZ is a planned submarine natural gas pipeline between Algeria and Spain   www.medgaz.com/.

Natural Gas Transmission & Distribution Companies (Public & Private Sector)

Natural Gas Storage Companies (Public & Private Sector)

Local Gas Distribution Companies (Public & Private Sector)

Natural Gas Marketers (Public & Private Sector)

In the United States, market deregulation created the conditions that a commercial or residential consumer can purchase natural gas directly from a supplier through one's existing current utility, which will deliver the gas to one's home or business and continue to provide repair, maintenance and emergency services (no physical modifications are required because the Marketer delivers gas through the same transmission and distribution system owned and operated by one's current utility). After 1 or 2 billing cycles, one will see the Marketer's name on the natural gas bill but will continue to receive the bill from their current utility. The Marketer simply supplies one's utility with the specific amount of natural gas at the contracted price. Deregulated states include Connecticut, Florida, Georgia, Illinois, Indiana, Kentucky, Massachusetts, Maryland, Michigan, New Jersey, New York, Ohio, Pennsylvania and Texas. In Canada, the provinces of Ontario and British Columbia are deregulated.

World demand for gas has risen at a rate of nearly 3% per year for the past thirty years, making natural gas the fossil energy with the strongest growth. The share of gas in global energy supply expanded from 16% in 1971 to 21% in 2004, and the International Energy Agency forecasts continuing growth, to reach a share of 23% by 2030. In its World Energy Outlook 2006, the International Energy Agency (IEA) indicates that "gas resources are more than sufficient to meet projected increases in (global) demand to 2030." The World Energy Council indicates that "the volume of proven gas reserves more than doubled over the period, from about 77 tcm in 1980 to some 177 tcm in 2006, growing at a roughly linear rate over time in the range of 4 tcm/yr. The life duration of proved reserves, as a ratio to current consumption, is in excess of 56 years." (Source: World Energy Council; 2007 Survey of Energy Resources; page 147)

Consumption / Demand is measured in:

Natural gas usage includes:

Residential Sector

Cooking

Hot water

Heating

Air conditioning

Industrial Sector

Cogeneration (simultaneous production of steam and electricity)

Steam production

Fuel for industrial boilers

Waste treatment / incineration

Metal preheating

Process heat for cement production

Feedstock for fertilizer / chemical production

Drying and dehumidification

Electricity Generation

Combined heat and power plants

Nations with the largest gas consumption (year-end 2008) included:
1. United States (667.2 Bcm / 22.0% of World Total Consumption)
2. Russia (420.2 Bcm / 13.9% )
3. Iran (117.6 Bcm / 3.9%)
4. Canada (100.0 Bcm / 3.3%)
5. United Kingdom (93.9 Bcm / 3.1%)
6. Japan (93.7 Bcm / 3.1%)
7. Germany (82.0 Bcm / 2.7%)
8. China (80.7 Bcm / 2.7%)
9. Saudi Arabia (78.1 Bcm / 2.6%)
10. Italy (77.7 Bcm / 2.6%)
11. Ukraine (59.7 Bcm / 2.0%)
Source: BP Statistical Review of World Energy 2009, Natural Gas, Consumption, p. 27   (.pdf format)

United States

As a source of energy, natural gas plays a major role in the United States' energy profile, where it already accounts for approximately 26% of total energy consumption. Its market share is likely to expand because of the favorable competitive position of gas in relation to other fuels, and the tightening environmental standards for fuel combustion. Industrial users, electric utilities, and gas producers and pipelines together account for 61.8% of the market; commercial and residential users combined are 37.8%. Total consumption increases during the Winter months as additional gas is used for residential and commercal property heating (during the Winter months residential consumption will exceed either commercial or industrial consumption; Conversely, electrical power generation consumption increases substantially during the Summer months).

Overall, the Energy Information Administration reported that U.S. natural gas demand fell 1.9% in 2006 to 21.8 trillion cubic feet (tcm) but then increased by 6.2% in 2007 to 23.0 tcm. Significant increases occurred in all end-use sectors except the industrial sector, where consumption increased by a modest 2.1%. The residential sector consumed 8.2% more natural gas in 2007 than in 2006, while the electric power and commercial consumed 9.9% and 6.1%, respectively, more than in 2006.

  Energy Information Administration, U.S. Natural Gas Consumption by End Use (Monthly)

The United States does not produce sufficient amounts of natural gas to meet domestic demand and imports natural gas (by pipeline) from Canada and Mexico, and in the form of LNG primarily from Trinidad & tobago. The Energy Information Administration reports that In 2007, net natural gas imports to the United States reached a record high of 3,729 Bcf, an increase of about 267 Bcf, or 7.7%, over the previous year. Increases in both pipeline imports from Canada and LNG imports from overseas contributed to the increase. The volume of natural gas imports in 2007 continued to equal about 16% of total U.S. natural gas consumption, a ratio that has remained relatively stable during the past 9 years.

LNG imports during the year came from six source countries, compared with just four in 2006. Deliveries from Trinidad and Tobago, which is still the leading exporter of LNG to the United States, totaled 451 Bcf, about 61 Bcf more than in the previous year.

  Energy Information Administration, U.S. Natural Gas Imports by Country (Monthly)

The EIA Short-Term Energy Outlook projects that growth in total natural gas consumption is expected to slow from 6.4% in 2007 to 0.7% in 2008 and 0.8% in 2009 (Total U.S. Natural Gas Consumption Growth). In 2009 total natural gas consumption is expected to reach a record 23.4 trillion cubic feet. Natural gas consumption in the electric power sector, which makes up about 30 percent of total natural gas consumption, grew by over 10 percent in 2007 but is expected to decline slightly in 2008 because of the projected milder summer temperatures. Natural gas consumption in the industrial sector is also projected to decline by 0.2 percent in 2008 because of slowing economic growth.

Imports of liquefied natural gas (LNG) are projected to be about 770 billion cubic feet (Bcf) for 2008, or about the same amount imported in 2007. Trinidad and Tobago is expected to remain the primary source of U.S. LNG imports through the forecast period. New liquefaction capacity under construction in Qatar and recent startups in Equatorial Guinea, Nigeria, and Norway are expected to boost the global supply of LNG and contribute to an increase in LNG shipments to the United States later this year and in 2009. Next year, volumes are projected to total 995 Bcf.   www.eia.doe.gov/emeu/steo/pub/contents.html

Europe

Germany has very little natural gas fields, either onshore or offshore, and approximately 85% of gas requirements are sourced from imports. Approximately 50 % of imports are from West European sources (Norway, the Netherlands, Denmark, the United Kingdom), and the balance is imported from Russia. Overall, the nation has a combined natural gas storage capability of approximately 70 days supply, thus the Germany domiciled companies can purchase gas during the Summer months at the lower seasonal prices and then hold onto the supply until Winter when consumer heating demand increases.

The United Kingdom has a combined natural gas storage capability of approximately 14 days supply, thus U.K. domiciled companies must pay spot prices for gas during the higher priced Winter months.

The largest supplier of natural gas to Eurpoe is Gazprom (Russia).

The Western Libyan Gas Project provides gas to Europe from Melitah, Libya, to Sicily, Italy.

In order to diversify gas supplies, the European Union is underwriting the construction of the Nabucco natural gas pipeline, which is intended to carry up to 31 billion cubic meters (bcm) of gas per year from Central Asia (primarily the Shah Deniz gas field in Azerbaijan) through Turkey, Bulgaria, Romania and Hungary to a hub in Austria.

A second potential supply source is the MEDGAZ offshore pipeline directly from Beni Saf, Algeria to Almeria, Spain, which provides supply without requiring transit through third countries. MEDGAZ is a consortium of five international companies: Sonatrach, CEPSA, Iberdrola, Endesa and Gaz de France and is scheduled for completion in mid-2009.

United States Gas Pricing

  EIA - Average Price of Natural Gas Delivered to U. S. Consumers, 1967-2000

  ICE Day Ahead Natural Gas Price Report

The price for natural gas has continued to increase over the past several years due to so many corporations and residences converting to natural gas from oil as a power and heating source and most new residential and commercial property construction in the United States has gas equipment installed as the fuel source of choice. Most natural gas supplied to and consumed in the United States are from domestic sources and from Canada. Thus, the North American natural gas market tends to have its own demand, supply and pricing dynamics that is separate from the international natural gas market. However, U.S. natural gas production has peaked and the nation is becoming more reliant upon imported supplies (in the United States, the San Juan Basin in New Mexico and Colorado is the largest producing on-shore domestic natural gas field and the Barnett Shale region in northern Texas is the second largest producing on-shore domestic natural gas field). Secondly, shipments from Canada have declined due to drilling and logistical transport problems. The delivery of natural gas requires a substantial investment in pipeline delivery and storage infrastructure and it is expensive to transport supplies between regions.

In the United States, there is a wellhead price, which represents a price paid to producers for gas "upstream" from the Henry Hub and reflects transactions all over the continental United States. The Energy Information Administration (EIA) reports an average wellhead price for natural gas in its Natural Gas Monthly publication, however the prices are collected from various producers around the country and are not "real time". The Henry Hub spot gas price is the amount paid to producers for natural gas sales contracted for next day delivery and title transfer at the Henry Hub (physically removed and downstreamed, net of the transportation cost to move the gas from the wellhead to the Henry Hub). There is also the NYMEX Henry Hub Natural Gas futures contract price (for physical delivery at a later date). The 2 Henry Hub price quotes are used as the surrogate price data in the U.S. due to the inability to compile wellhead prices in a timely manner.

The EIA Short-Term Energy Outlook indicates / projects that The Henry Hub spot price averaged $8.76 per Mcf in February 2008, $0.51 per Mcf more than the average January spot price. Cold weather so far in the first quarter has kept pressure on prices, which are expected to decline as space heating demand begins to wane in April. On an annual basis, the Henry Hub spot price is expected to average about $8.18 per Mcf in 2008 and $7.95 per Mcf in 2009.   www.eia.doe.gov/emeu/steo/pub/contents.html

The price of natural gas is effected by:

Production - how many rigs drilling for gas and how much new gas is being found.

LNG Imports - LNG shipments costs more than domestic sources of natural gas delivered by pipeline.

Seasonal demand - residential demand increases substantially in Winter. Conversely, warmer-than-normal summer weather and increased air conditioner usage can result in higher electric power generation requirements and greater demand for natural gas as the fuel source used to operate electric power turbines.

Weekly storage / inventory build up - how much gas is ready for transmission to end-users.

High Refined Petroleum Products Prices - Some large-volume customers (primarily industrial consumers and electricity generators) can switch between natural gas and other fuels, such as petroleum products, depending on the prices of each. As a result of this interrelation between fuel markets, when oil prices rise, there is a shift in demand to natural gas drives prices upward.

Hurricanes - in the United States, natural gas wells and delivery infrastructure in the Gulf of Mexico can be affected by hurricanes, which has caused major service disruptions and production shut-ins, resulting in an increase in the prices of natural gas.

Weather which effects pipelines functioning - sub-freezing weather can affect pipeline infrastructure.

Terrorism threat - there is sometimes a premium added to natural gas prices in response to the belief on and imminent threat.

Residential consumer natural gas prices incorporate both the wellhead price (the actual cost of the commodity) and transmission and distribution costs to move the gas by pipeline from where it is produced to the customer’s local gas company (often referred to the City Gate Price; The citygate is a point or measuring station at which a distributing gas utility receives gas from a natural gas pipeline company or transmission system), and to bring the gas from the local gas company (LDC / Local Distributing Company) to the customer's property. The ratio of both expenses changes annually in response to movements in the underlying commodity price. Residential consumers and small commercial properties are charged per thousand cubic feet (Mcf), per hundred cubic feet (Ccf), which is usually measured by individual metered usage, and then are billed in therms (energy content, which can be used to compare the price with oil heat; see below).

Residential natural gas prices in the United States reached a record high of $16.66 per thousand cubic feet in September, 2005, after Hurricanes Katrina and Rita shut down operations along the U.S. Gulf Coast. After production was restored the average residential price decreased by Spring 2006. Overall, the Energy Information Administration reports that the recent average U.S. natural gas wellhead price increased from $6.02 per thousand cubic feet (mcf) in 4th Qtr. 2006 to $6.38 per mcf in the 4th Quarter 2007. Natural gas prices have generally declined over the past one and one-half years and this is only the second time that they have increased relative to the year-earlier quarter since the second quarter of 2006.

  Energy Information Administration, U.S. Natural Gas Prices (Previous Months)

  Energy Information Administration, U.S. Natural Gas Prices (Annual)

In the United States, the industry has gone through a metamorphosis since the enactment of the Natural Gas Policy Act of 1978, changing from an almost totally regulated industry, to one that today largely operates as a free market. The New York Mercantile Exchange launched the natural gas futures contract in April 1990; in that short time Volume and open interest have grown steadily and the contract has evolved to the point at which ever-increasing numbers of cash market transactions are based on futures prices.

In April 2006 NYMEX announced a 10-year agreement with the Chicago Mercantile Exchange (CME), moving several NYMEX energy contracts, including the natural gas futures contracts to Globex, the CME’s electronic trading platform. Overall, electronic trading on the Globex for NYMEX futures has been quite successful. In October 2006, NYMEX reported that the daily trading volume on the Globex for natural gas futures reached 54,213. By February 2007, the number had more than doubled to 137,562 natural gas contracts and subsequently increased to a record high of 158,525 on December 14, 2007.

Industry participation in the natural gas futures market has broadened steadily and comprises a wide cross-section of the industry from producers to end-users. Continual legislation concerning air pollution control should contribute to the market's further growth.

United Kingdom Gas Pricing

UK gas producers operate offshore rigs in about 100 fields, almost all located in the North Sea and the Irish Sea. Shippers and, to a lesser extent, suppliers purchase gas from these offshore producers (and in much smaller quantities from onshore producers). They can take title to the gas either at the onshore coastal reception terminal (the beach terminal), where the gas is referred to as "beach gas", or at the National Balancing Point (NBP). In the UK, gas is denominated in pence per therm (a therm is equivalent to 100 cubic feet of gas).

European Gas Pricing

The 2 main physical gas hubs on the continent are the Eurohub in the Bunde/Oude/Emden region of Germany and the Zeebrügge Hub, located at the site of the continental end of the UK-Belgium interconnector and an LNG terminal. There are also “virtual hubs” (markets primarily used to correct short-term imbalances between demand and supply under long-term contracts). These include NBP (National Balancing Point) mentioned above in the Uinted Kingdom section, PSV (Punto Scambio Virtuale) in Italy, PEGs (Points d’échanges) in France and the Title Transfer Facility (TTF) in the Netherlands. Gas is continuously traded and priced at the physical hubs and the virtual hubs.

Canada Gas Pricing

Alberta’s gas trading price (the AECO “C” spot price) is derived from activity at the Alberta Hub trading point

For LNG transport please see the International Trade & Shipping page.

Generally, LNG is measured in metric tons / tonnes when it is a liquid, and in cubic feet when it is in its gaseous state.

Liquefied natural gas (LNG) liquefaction plant / maritime transportation and storage infrastructure are usually set up to transport natural gas from producing regions to consumer centers when pipeline construction is difficult or even unfeasible for technical, geographic or economic reasons.

LNG is natural gas vapor that is super-cooled (minus 260°F / minus 162°C) and then condenses into a liquid form for transport in large maritime tanker vessels. Once the LNG is brought to a marine terminal the LNG is warmed (regasification) and the gas vapor is pumped into holding tanks connected to a pipeline network.

The sequential arrangement of facilities and equipment used to first convert natural gas to liquid are called a "train".

The largest exporters of LNG are Qatar, Indonesia and Algeria.

LNG production facilities are located in:

Algeria, Arzew

Australia, Withnell Bay

Brunei, Lamut

Indonesia, Arun

Indonesia, Badak

Malaysia, Bintulu

Nigeria, Bonny Island

Oman, Muscat

Qatar, Ras Laffan

Trinidad, Port Fortin

UAE, Abu Dhabi

Egypt

Ras Laffan Liquefied Natural Gas Company Limited (RasGas) is situated on the North East coast of Qatar (one of the world's largest offshore recoverable non-associated natural gas fields). It was established by Emiri Decree in 1993. Currently, RasGas is owned by Qatar General Petroleum Corporation (QGPC), Mobil QM Gas Inc., ltochu Corporation and Nissho Iwai Corporation.

Trinidad and Tobago exports reached a record-high level with a recent expansion of liquefaction capacity in the country. The Atlantic LNG facility, located in Port Fortin, expanded its liquefaction capacity in 2005 to 15 million tons per year (720 Bcf). The liquefaction facility now has four operational trains, the newest of which is the largest in the world with the capacity to liquefy 5.2 million tons per year (240 Bcf). Trinidad & Tobago is the largest supplier of LNG to the United States accounting for approximately 75% of shipments to the U.S. in 2007.

The nation of Australia produces natural gas from the North West Shelf field and has a multi-year contract to provide natural gas to China. In addition, Australia resolved boundary issues with East Timor with regard to the development of the Sunrise fields in the Timor Sea.

With the recent improvement of relations and the lifting of sanctions, natural gas exploration in the Sitre Basin and the Murzuq Basin have been opened up in cooperation with the Libyan National Oil Corporation.

U.S. LNG Receiving & Regasification (Import) Terminals

The largest LNG import terminal in the United States is the Trunkline LNG Lake Charles Terminal in Lake Charles, La., operated by Trunkline LNG Company, LLC (Panhandle Energy). The facility is connected to the 4,100 mile pipeline system operated by Trunkline Gas Company, LLC (Panhandle Energy), which extends from the Gulf Coast to Michigan.

A total of 5 LNG import terminals operated in the continental United States during 2007. The Trunkline LNG terminal in Lake Charles, LA, received the largest volume of any U.S. terminal with receipts totaling 252 Bcf. The facility owned by Suez Energy North America, Inc., in Everett, Massachusetts, received the second biggest volume at 184 Bcf. El Paso Corporation’s Southern LNG facility on Elba Island, Georgia, received 170 Bcf in 2007, while Dominion’s Cove Point LNG facility on the Chesapeake Bay in Maryland, received 148 Bcf. Excelerate Energy’s Gulf Gateway port offshore Gulf of Mexico received 17 Bcf.

Non-U.S. LNG Receiving & Regasification (Import) Terminals

In India, the Dahej Receiving and Regasification Terminal and the Kochi (Kerala) Receiving and Regasification Terminal are owned and operated by Petronet LNG Ltd.

At Porto Levante, Italy Veneto Region / northern Italy), the very first offshore (approximately 9 miles) Gravity Based Structure (GBS) for unloading, storing and regasifying LNG was put into service during 2009. The facility is owned by Exxon Mobil Italiana Gas, Qatar Petroleum (Qatar Terminal Limited / QTL) and Edison. The floating concrete structure houses two LNG tanks, and includes a regasification plant and facilities for mooring and unloading LNG vessels. The facility is capable of delivering 8 billion cubic meters of natural gas per year (775 million cubic feet per day), or approximately 10% of Italy’s current natural gas requirements. The company indicates that 80% of the terminal's capacity will be utilized by Edison for a period of 25 years, to regasify LNG imported from Qatar’s North Field, as part of a supply agreement with RasGas II (train 4). The remaining 20% is open for third party access. FMC Technologies SA designed the offloading system.

Planned Deep Water / Offshore Receiving Ports

There is some anticipation that LNG (Liquified Natural Gas) can increasingly be shipped to the United States in order to increase supply sources, however LNG presents its own set of transport and logistical problems. Without additional supply development it is anticipated that the United States will eventually experience a gas shortgage that would further drive up domestic prices. However, part of the problem to expand supply in the United States is the inability to locate and construct onshore LNG terminals that are not near population centers. U.S. regulators have approved the development of a major delivery port in the Gulf of Mexico.

Calypso LNG LLC   www.suezenergyna.com/ourcompanies/lngna-calypso.shtml

Crown Landing   www.bpcrownlanding.com/

Freeport LNG Terminal   www.cheniere.com/LNG_terminals/freeport_lng.shtml

Golden Pass LNG Terminal   www.goldenpasslng.com/

Neptune LNG LLC   www.suezenergyna.com/ourcompanies/lngna-neptune.shtml

Sabine Pass LNG Terminal   www.cheniere.com/LNG_terminals/sabine_pass_lng.shtml

LNG Companies (Public & Private Sector)

LNG Receiving & Regasification (Import) Terminals

Methane (CH₄) itself is actually defined as a non-carbon dioxide (non-CO₂) greenhouse gas. These gases trap more heat within the atmosphere than CO₂ per unit weight and methane remains in the atmosphere for approximately 9-15 years. In the United States, the largest source of methane emissions actuallly come from the decomposition of wastes in landfills, ruminant digestion and manure management associated with domestic livestock, than natural gas and oil systems, and coal mining. All natural gas industry sectors, including gas production, processing, transmission, and distribution emit methane to the atmosphere to varying degrees. Methane emissions are generally process-related, with normal operations, routine maintenance, and system upsets being the primary contributors.

Why is burning natural gas as a fuel source "cleaner" than other fossil fuels? Burning one molecule of methane in the presence of oxygen releases one molecule of CO₂ (carbon dioxide) and two molecules of H₂O (water). Methane may produce less carbon dioxide for each unit of heat released compared to petroleum-dervied fuels but it is still a significant source of greenhouse gas emissions.

In the United States there have been problems related to the recently developed technology of hydraulic fracturing. In hydraulic fracturing, drilling is in a horizontal direction into shale beds and high pressure water and chemicals are used in the fracturing operations in order to allow the gas to move (and eventually be pumped out). The accusations are that escaping methane and hydraulic fracturing fluids have contaminated drinking water located near natural gas exploration drilling by seeping into wells. A second issue is regarding the proper disposal of wastewater produced during the hydraulic fracturing operations: when it is collected it is usually pumped into the local, municipal wastewater system.

In the United States:

Gas wells are not regulated with the exception of authorizing and monitoring access to Federally-owned and state-owned land.

Natural gas gathering pipelines are regulated in some states.

Interstate pipelines, both the construction of interstate natural gas pipelines and transportation of natural gas in interstate commerce, are regulated by the Federal Energy Regulatory Commission (FERC) as per the Natural Gas Act (NGA), the Natural Gas Policy Act (NGPA), the Outer Continental Shelf Lands Act (OCSLA), the Natural Gas Wellhead Decontrol Act and the Energy Policy Act (EPAct).

The Office of Pipeline Safety (OPS), within the U.S. Department of Transportation, Pipeline and Hazardous Materials Safety Administration (PHMSA), has overall regulatory responsibility for natural gas pipelines under its jurisdiction in the United States. Minimum pipeline safety standards are defined under the U.S. Code of Federal Regulations (CFR), Title 49, Parts 190-199.

Local gas distribution companies are regulated by states.

In the United States, Most U.S. homes are heated with either furnaces or boilers.

There are 3 common types of gas furnaces: conventional warm air, induced draft, and condensing for hot air heating and then there are also gas-fired boilers for hot water heating systems.

In order to do a resonable comparison one must consider:

Merely comparing national prices for each fuel commodity is inaccurate as is just comparing bills, which includes delivery / distribution charges, service charges, state surcharges, franchise taxes and so on.

Natural gas, a hydrocarbon, is usually purchased in amounts of hundreds of cubic feet (Ccf) by most consumers.

U.S. Average Price 2007 (Source: U.S. Dept. of Energy):

Please Note. The comparison can never be entirely accurate because there are 3 uncontrollable factors that must be considered when converting a volume of natural gas to an energy basis: altitude, temperature and energy. The volume of a gas varies according to pressure and temperature in accordance with the Ideal Gas Law. Generally, a given volume of gas will increase to a larger volume under less pressure. Similarly, a given volume of gas will increase to a larger volume under higher temperature. A standard cubic foot of gas at sea level meter conditions contains a different number of gas molecules than a cubic foot at a higher altitude (the higher the altitude, the lower the pressure and less gas molecues). The same observation can be determined at various temperature levels (the higher the temperature the less gas molecues). Thus, altitude and temperature have an affect on volume and hence on the amount of energy delivered. With regard to the actual "energy" in the gas, although gas processing units are very exact and there are strict requirements regarding the condition of the gas prior to injection into the interstate pipeline transmission grid, different sources of gas delivered to different parts of the transmission system contain variations in energy content.

Unfortunately, the Energy Infomation Agency (Department of Energy) has not completed a more recent Residential Energy Consumption Survey since 2001. Some of the key information from the survey indicates that, on average, a household in New England consumed 72.1 million Btus annually for main space heating. Similarly, a household in the Middle Atlantic States consumed 60.5 million Btus annually for main space heating; households in the South Atlantic region consumed 26.0 million Btus; households in the Midwest consumed 67.2 million Btus; households in the Pacific coastal region consumed 25.4 Btus and households in the Western Mountain region consumed 41.4 million Btus. Thus, using the same Btus consumption for New England in 2001 but applying 2007 prices and a 78% AFUE, a household in New England may have spent as much as $1,266 to heat with gas or $1,726 to heat with No. 2 heating oil.   www.eia.doe.gov/emeu/recs/recs2001/detailcetbls.html#space

Compressed Natural Gas (CNG) is proposed as an alternative to refined gasoline as a transportation fuel. CNG is also promoted a cleaner alternative fuel compared to petroleum-derived fuels. The key issue is that automobiles must have engines (new manufacture or converted) capable of utilizing CNG as the fuel source. Another consideration is that many traditional gasoline stations already have a natural gas connection for heating the the building on the property thus it would not be difficult to install CNG compressors / dispensers. Similarly, many U.S. residences are heated by natural gas thus a compressor unit could also be installed in the garge or on the property so that owner could also refuel the vehicle overnight.

Presently, the Honda Civic GX is the only CNG-capable automobile produced in the United States.

Alberta Energy, Government of Alberta   www.energy.gov.ab.ca/

Alberta Utilities Commission (AUC)   www.auc.ab.ca/

Assaluyeh Gas Processing   www.assaluyeh.com/

Canadian Energy Pipeline Association (CEPA)   www.cepa.com/

Energy Information Administration (EIA), Natural Gas Consumption Data   tonto.eia.doe.gov/dnav/ng/ng_cons_top.asp
EIA, International Natural Gas Production   www.eia.doe.gov/emeu/international/gasproduction.html
EIA, International Natural Gas and Liquefied Natural Gas (LNG) Imports and Exports   www.eia.doe.gov/emeu/international/gastrade.html

INNOGATE (Interstate Oil and Gas Transport to Europe)   www.inogate.org/

Interstate Natural Gas Association of America (INGAA)   www.ingaa.org/

Natural Gas Supply Association (NGSA)   www.ngsa.org/

National Energy Board of Canada   www.neb.gc.ca/

National Pipeline Mapping System (NPMS)   www.npms.phmsa.dot.gov/

NGX (National Gas Exchange / Canada)   www.ngx.com/

Office of Fossil Energy (DOE)   www.fe.doe.gov/

Railroad Commission of Texas   www.rrc.state.tx.us/

U.S. Department of Energy (DOE)   www.energy.gov/

U.S. Department of Transportation (DOT), Pipeline and Hazardous Materials Safety Administration (PHMSA)   www.phmsa.dot.gov/

U.S. Environmental Agency (EPA), Natural Gas STAR Program   www.epa.gov/gasstar/index.htm

U.S. Federal Energy Regulatory Commission (FERC), Gas Industry   www.ferc.gov/industries/gas.asp
FERC, Liquefied Natural Gas (LNG) Industry   www.ferc.gov/industries/lng.asp