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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 Formation |
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)
| Natural Gas Exploration & Production |
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.
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| Natural Gas Producers |
Natural gas reservoirs are located all over the world. However, the economic viability of the reservoir is a question of
location and accessibility.
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In its World Energy Outlook 2009 (Executive Summary), the International Energy Agency (IEA) indicates that proven reserves amount to approximately 180 trillion cubic metres / Tcm (6,356.6 Tcf) at the end of 2008 (similar to 2007), equal to 60 years of supply at current production rates. (World Energy Outlook 2009, International Energy Agency; Executive Summary page 13). 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. "The long-term global recoverable gas resource base is estimated at more than 850 tcm," which of 45% will come from unconventional gas resources. http://www.iea.org/Textbase/npsum/weo2009sum.pdf (.pdf format)
The U.S. Department of Energy, Energy Information Administration (EIA), indicates indicates that total world reserves were 6,254.364 Trillion Cubic Feet / Tcf (177.1 Trillion Cubic Metres / Tcm) at the year-end 2009 www.eia.gov/cfapps/ipdbproject/IEDIndex3.cfm?tid=3&pid=3&aid=6.
The BP Statistical Review of World Energy June 2010, indicates that total world natural gas reserves were 6,621 Trillion Cubic Feet / Tcf (187.5 Trillion Cubic Metres / Tcm) at the year-end 2009, an increase of 89 Tcf relative to the year-end 2008 figure. Proved reserves have grown in the past 20 years, increased from 122.40 Tcm in 1989 to 187.49 Tcm in 2009. The Middle East still accounts for the greatest amount of proved reserves: 40.6% of total natural gas reserves in 2009, follwed by Europe and Eurasia accounting for 33.7% of total natural gas reserves. BP Statistical Review of World Energy June 2010, p. 22
The BP Statistical Review of World Energy June 2010, indicates that total world natural gas production was 2,987 Bcm in 2009, a decline of 2.1% compared to 2008. The greatest increase in production has been within the People's Republic of China where production has increased in the past decade from 25.2 Bcm in 1999 to 85.2 Bcm in 2009.
Algeria has a large natural gas reservoir located in the north, central interior of the country at Hassi R'Mel (in Laghouat Province, and the Oued Mya area) with proven reserves of approximately 4.502 Tcm. The Hassi R'Mel field is the largest Natural gas deposit in Algeria, accounting for approximately 67% of the country's proved natural gas reserves. Other deposits are located at Hassi Messaoud, Alrar (in central Algeria, near the Libyan border), Gassi Touil (southeast of Ouargla), Rhourd en Nous (in the center of Algeria), and Ahnet Timimoun basin.
Google Map Location of Hassi R'Mel Gas Field
The In Amenas Gas Project consists of four fields: Tiguentourine, Hassi Farida, Ouan Taredet, and Hassi Ouan Abecheu.
Algeria is the second largest supplier of gas to Europe after Russia and Norway, and is one of the largest LNG exporters in the world. The Hassi R'Mel field is directly linked to Europe through the Maghreb–Europe Gas Pipeline (Hassi R'Mel to Spain via Morocco), Trans-Mediterranean (Hassi R'Mel to Sicily via Tunisia), Medgaz (Hassi R'Mel to Almería, Spain) and the proposed GALSI (Gasdotto Algeria Sardegna Italia; Hassi R'Mel to Sardinia and northern Italy) gas export pipelines supplying Southern Europe. Hassi R'Mel is also the planned termination point of the proposed Trans-Saharan gas pipeline (Nigeria to Algeria).
Sonatrach (Société Nationale pour la Recherche, la Production, le Transport, la Transformation, et la Commercialisation des Hydrocarbures s.p.a.) is an Algerian government-owned company that has oversight for exploration, development and production of natural gas in Alegeria.
The U.S. Department of Energy, Energy Information Administration (EIA) / Oil & Gas Journal, estimates Algeria's proven natural gas reserves as of December 31, 2009 at 159.0 Trillion Cubic Feet / Tcf.
Sonatrach www.sonatrach-dz.com/
MEDGAZ www.medgaz.com/
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
The U.S. Department of Energy, Energy Information Administration (EIA) / Oil & Gas Journal, estimates Australia's proven natural gas reserves as of December 31, 2009 at 30.0 Trillion Cubic Feet / Tcf.
Canada is the second largest producer of natural gas in the Western Hemisphere, after the United States, and the third largest in the world. The nation's conventional natural gas production is concentrated within the Western Canada Sedimentary Basin (WCSB), primarily in Alberta, which accounts for approximately 80% of Canada’s total natural gas production. There have been new onshore discoveries in British Columbia, Saskatchewan and Manitoba. The Western Canada Sedimentary Basin (WCSB) encompasses portions of southwestern Manitoba, southern Saskatchewan, Alberta, northeastern British Columbia and the southwest corner of the Northwest Territories (approximately 540,000 square miles / 1,400,000 square km).
Google Map Location of Western Canada Sedimentary Basin (WCSB)
Offshore natural gas exploration and production is located on the Atlantic coast and within the Arctic region of Canada. On the Atlantic coast, the Scotian Basin, located off the coast of Nova Scotia, has been a center of natural gas production for the past decade. The Sable Offshore Energy Project (SOEP), led by ExxonMobil and Shell Canada, began production in 1999. SOEP encompasses numerous offshore fields, with the Alma and South Venture fields the latest brought on-line. SOEP has a production capacity of 400 MMcf/d of natural gas and 20,000 bbl/d of natural gas liquids (NGLs). Within the Arctic region, the Mackenzie Delta, located in the Northwest Territories, holds an estimated 5 to 6 Trillion Cubic Feet / Tcf of recoverable natural gas reserves.
The National Energy Board (NEB) of Canada regulates the export of natural gas (and oil, natural gas liquids / NGLs, and electricity, and the import of natural gas). The NEB indicates that in 2008, "deliverability declined to roughly 447 106m3/d (15.8 Bcf/d) at year’s end, largely due to significantly reduced drilling activity in the second half of the year. 2009 saw that trend continue, as low gas prices and restricted access to capital for producers, especially junior producers in western Canada, led to levels of reduced drilling activity not seen since the 1990s." In addition, future production will steadily be shifting from conventional natrual gas deposits (presently 90% of the natural gas that is produced within Canada) to unconventional sources, including coalbed methane and shale gas.
TransCanada Pipelines is the largest operator of natural gas pipelines in Canada, with a pipeline network spanning approximately 25,600 miles.
The U.S. Department of Energy, Energy Information Administration (EIA) / Oil & Gas Journal, estimates Canada's proven natural gas reserves as of December 31, 2009 at 57.906 Trillion Cubic Feet / Tcf.
National Energy Board (NEB) - Energy Market Assessment (EMA) Short-term Canadian Natural Gas Deliverability, 2010–2012
www.neb-one.gc.ca/clf-nsi/rnrgynfmtn/nrgyrprt/ntrlgs/ntrlgsdlvrblty20102012/trlgsdlvrblty20102012-eng.pdf
Approximately 70% of the Indonesia’s natural gas reserves are located offshore, with the largest reserves found off Natuna Island, East Kalimantan, South Sumatra, and West Papua (also known as Irian Jaya). Most of Indonesia's natural gas production results in LNG shipments to Japan, South Korea, and Taiwan (Indonesia was once the world's largest exporter of LNG but has become second to Qatar). Indonesia also exports natural gas via pipeline to Singapore through the 400 mile / 654 km, 325-million cubic feet per day (MMcf/d) West Natuna Transportation System subsea pipeline from West Natuna to Singapore, and through a second natural gas connection to Singapore, the 293 mile / 468 km Grissik-Batam-Singapore pipeline; and to Malaysia’s Duyong platform 2 (approximately 50 MMcf/d). These pipelines are part of the planned Trans-ASEAN Gas Pipeline system, which is to connect Brunei, Cambodia, Indonesia, Laos, Myanmar, Philippines, Singapore, Thailand, Malaysia and Vietnam.
Google Map Location of the Natuna Islands
PT Pertamina (state-controlled) and six major international companies dominate Indonesia’s natural gas industry, accounting for more than 90% of the country’s natural gas production. The six companies are: Total, ExxonMobil, Vico (BP - Eni sPa joint venture), ConocoPhillips, BP, and Chevron. Natural gas transmission and distribution activities are carried out by the state-owned utility Perusahaan Gas Negara (PGN).
Indonesia produces LNG from two terminals: the Bontang facility in Badak, East Kalimantan and the Arun plant in North Sumatra.
The Senoro-Donggi gas field is located near the island of Sulawesi.
Tangguh LNG, located on the Bintuni Bay area of Irian Jaya / West Papua, Indonesia, is the third LNG hub in Indonesia. BP Indonesia is the operator (37.16% interest in the project) of Tangguh under a production sharing contract with BPMIGAS (Indonesia's regulatory body for oil and gas upstream activities). The gas fields located offchore in the Ceram Sea include Ubadari, Wos, Ofaweri, Wiriager Deep, Roabiba, and Vorwata. The field's reserves are estimated at 14.4 trillion cubic feet (Tcf).
Google Map Location of Bintuni Bay / Tangguh Field
The U.S. Department of Energy, Energy Information Administration (EIA) / Oil & Gas Journal, estimates Indonesia's proven natural gas reserves as of December 31, 2009 at 106.0 Trillion Cubic Feet / Tcf.
BP Indonesia Tangguh LNG Project www.bp.com/sectiongenericarticle.do?categoryId=9004779&contentId=7008759
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 Trillion Cubic Meters / 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
The U.S. Department of Energy, Energy Information Administration (EIA) / Oil & Gas Journal, estimates Iran's proven natural gas reserves as of December 31, 2009 at 991.60 Trillion Cubic Feet / Tcf.
In 2006, natural gas was discovered in the deep Jurassic reservoirs at Rahiya, Mutriba, Sabriyah, Umm Niga (northern Kuwait, and Kuwait's first major non-associated gas field) and other fields in Kuwait (most is associated gas). Natural gas is also located offshore at the Dorra field, however the development of the deposit is subject to the resolution of demarcation negotiations with Iran and Saudi Arabia. Kuwait produced approximately 449 billion Bcf of natural gas in 2008, most of which was consumed domestically in electricity generation, water desalination, and petrochemicals production.
Google Map Location of Sabriyah Oil Field / Associated Gas Field
Kuwait Oil Company (KOC) is a Kuwaiti government-owned company that has oversight for exploration, development and production of natural gas in Kuwait. In February 2010, the Kuwait Oil Company signed a five-year service contract with Royal Dutch Shell to develop the non-associated natural gas fields in northern Kuwait.
The U.S. Department of Energy, Energy Information Administration (EIA) / Oil & Gas Journal, estimates Kuwait'sproven natural gas reserves as of December 31, 2009 at 63.360 Trillion Cubic Feet / Tcf.
Kuwait Oil Company (KOC) www.kockw.com/
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. The natural gas deposits are primarily located offshore of the Niger River Delta in Gulf of Guinea, and is produced in association with crude oil production. Because many of Nigeria’s oil fields lack the infrastructure to produce and market associated natural gas, it is often flared: approximately 532 Bcf in 2008. The government of Nigeria has been working to end natural gas flaring for several years but the deadline to implement the policies and fine oil companies has been repeatedly postponed with some analysts pushing the date forward as far as 2012. In 2009, the Nigerian government developed a Gas Master Plan that would promote new gas-fired power plants to help reduce gas flaring and provide much-needed electricity generation.
In addition, oil and natural gas production and shipment have been affected over the past several years by militant groups in the Niger River Delta region (Rivers State, Bayelsa State) who claim that the crude oil is pumped from the region but the people who reside within the region receive very little economic benefit from the income the commodity produces and is received by the government (approximately 80% of total government revenues). Production has declined approximately 35% over the past few years to due militant attacks (destruction of infrastructure and the kidnapping foreign oil workers for ransom) that have resulted in the disruption of the operations of offshore oil rigs and transportation.
Google Map Location of Niger Delta Fields
A significant portion of Nigeria’s natural gas is processed into LNG. In 2009, Nigeria exported close to 500 Bcf of LNG. Of this, 13.3 Bcf went to the United States, providing 3% of total U.S. LNG imports (2% of Nigerian exports). Most of Nigeria’s LNG was exported to Europe (66%), mainly Spain (31%), France (15%) and Portugal (13%). Other export destinations include Asia (15%) and Mexico (16%). Nigerian LNG Exports were down close to 30% from 2008 volumes which can also be attributable to problems in the Niger Delta, specifically problems at the Soku gas processing facility.
Nigeria's main natural gas project is the Nigeria Liquefied Natural Gas (NLNG) facility on Bonny Island. Partners including NNPC, Shell, Total and Agip completed the first phase of the facility in September 1999. NLNG currently has six trains and a production capacity of 22 million tons per year (1.1 trillion cubic feet). A seventh train is under construction but this addition has been delayed until 2012.
Three additional LNG plants with a total of seven trains are expected to come online after 2012, these include OK LNG (4 trains), Brass LNG (2 trains), and Progress LNG (1 train). However, these are in varying stages of development and investment decisions will depend heavily on security, world LNG markets, and Nigerian efforts to expand the use of natural gas for domestic electricity generation.
In addition to LNG, Nigeria began exporting some of its natural gas via the West African Gas Pipeline (WAGP) in early 2010. The 420-mile pipeline carries natural gas from Nigeria to Ghana via Togo and Benin. Exports should reach initial capacity of 170 million cubic feet per day (MMcf/d) by the end of 2010 and plans are underway to expand capacity to as much as 450 MMcf/d and possibly extend the pipeline further west to Cote d’Ivoire.
Nigeria and Algeria continue to discuss the possibility of constructing the Trans-Saharan Gas Pipeline (TSGP). The 2,500-mile pipeline would carry natural gas from oil fields in Nigeria's Delta region to Algeria's Hassi R'Mel field and Beni Saf export terminal on the Mediterranean (see above). In 2009 the NNPC signed a memorandum of understanding (MoU) with Sonatrach, the Algerian national oil company in order to proceed with plans to develop the pipeline. Several national and international companies have shown interest in the US$ 12 billion project including Total and Gazprom.
The U.S. Department of Energy, Energy Information Administration (EIA) / Oil & Gas Journal, estimates Nigeria's proven natural gas reserves as of December 31, 2009 at 184.160 Trillion Cubic Feet / Tcf.
Nigeria LNG www.nlng.com/
Nigerian National Petroleum Corporation (NNPC) www.nnpc-nigeria.com/
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
The U.S. Department of Energy, Energy Information Administration (EIA) / Oil & Gas Journal, estimates Norway's proven natural gas reserves as of December 31, 2009 at 81.680 Trillion Cubic Feet / Tcf.
Natural gas deposits have been identified onshore in the Camisea gasfield in southern Peru and the area is presently under development. However, exploration and identification of deposits are located on land that belong to indigenous people of Peru and they are reluctant to have their land opened up to natural gas development. In May and June 2008, the President of Peru attempted to revise (by executive decree) that mandatory voting process where two thirds of the local indigenous community must approve the exploration and development project. The nation's Congress repealed the decrees. The issue is that the state may own the subsoil rights (oil, gas or mineral) but the indigenous people own the above ground title to the land. Thus, there needs to be close cooperation between the parties in order for a project to be approved and actually commence. However, some of these indigenous groups live in voluntary isolation, which makes it very difficult to obtain development rights.
Google Map Location of the Camisea Gasfield
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. Qatar is located too far away from European or Asian markets for pipeline delivery thus the gas extracted from Qatari fields is transported by marine tanker. The nation has 14 LNG plants that were developed in cooperation with private companies.
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 and/or low-sulphur jet fuel and/or lubricants) located in RLC, ORYX GTL, a joint venture between Qatar Petroleum (51%) and Sasol of South Africa (49%), and Pearl GTL (Gas To Liquids), 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
The nation is ruled by the Sheikh Hamad bin Khalifa Al-Thani, who has been in power since 1995, and the nation has been stable politically and socially. Qatar has not invested in large real estate projects compared to some of the other Gulf nations thus was not seriously affected by the 2008 / 2009 financial crisis.
The U.S. Department of Energy, Energy Information Administration (EIA) / Oil & Gas Journal, estimates Qatar's proven natural gas reserves as of December 31, 2009 at 891.945 Trillion Cubic Feet / Tcf.
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.
The U.S. Department of Energy, Energy Information Administration (EIA) / Oil & Gas Journal, estimates Russia's proven natural gas reserves as of December 31, 2009 at 1,680.0 Trillion Cubic Feet / Tcf.
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
The U.S. Department of Energy, Energy Information Administration (EIA) / Oil & Gas Journal, estimates Saudi Arabia's proven natural gas reserves as of December 31, 2009 at 258.47 Trillion Cubic Feet / Tcf.
Natural gas fields are located offshore of the southeast and north coasts of Trinidad. The Atlantic LNG facility located at Point Fortin is used to liquefy natural gas for export primarily to markets in the United States and Spain.
Google Map Location of Point Fortin
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 Point 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 U.S. Department of Energy, Energy Information Administration (EIA) / Oil & Gas Journal, estimates Trinidad's proven natural gas reserves as of December 31, 2009 at 18.770 Trillion Cubic Feet / Tcf.
Atlantic LNG Company of Trinidad and Tobago www.atlanticlng.com/
The UAE are a federation seven states situated in the southeast of the Arabian Peninsula on the Persian Gulf, bordering Oman and Saudi Arabia. The seven states, termed emirates, consist of Abu Dhabi, Ajman, Dubai, Fujairah, Ras al-Khaimah, Sharjah, and Umm al-Quwain. Each one of the emirates has a local (enclave) government and the UAE coordinates policy between the states through the UAE Supreme Council of Rulers and the office of the UAE Federal President. His Highness Sheikh Khalifa Bin Zayed Al Nahyan, Ruler of Abu Dhabi and Supreme Commander of the Armed Forces is the President of the UAE and His Highness Sheikh Mohammed Bin Rashid Al Maktoum, the Ruler of Dubai, is the Vice President and Prime Minister.
Google Map Location of the United Arab Emirates (UAE)
Most of the natural gas deposits in the UAE are located within Abu Dhabi, which accounts for approximately 198.5 Tcf. 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.
The EIA indicates that in 2008, the UAE produced 1.77 Tcf and consumed 2.1 Tcf of dry gas. The UAE became a net natural gas importer in 2007, as consumption has grown much faster than production. Domestic consumption is concentrated in electricity generation, water desalination, and petrochemicals production.
The U.S. Department of Energy, Energy Information Administration (EIA) / Oil & Gas Journal, estimates the UAE's proven natural gas reserves as of December 31, 2009 at 214.4 Trillion Cubic Feet / Tcf.
Adgas www.adgas.com/
Prior to 1947, associated gas (found during crude oil drilling) was vented and / or flared (burned off) as a useless byproduct. In 1947, the Railroad Commission of Texas brought suit in the Texas Supreme Court, Railroad Commission v. Shell Oil Co., 206 S.W.2d 235 (Tex. 1947), to prevent the wasteful flaring of casinghead gas, and natural gas was either reinjected below earth to maintain well pressure or was piped and stored, and natural gas production and consumption within the United States grew after that point. www.rrc.state.tx.us/about/history/chronological/chronhistory02.php
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.
Energy Information Administration - U.S. Dry Natural Gas Proved Reserves
Energy Information Administration - U.S. Crude Oil and Natural Gas Exploratory and Development Wells
As of December 31, 2008, estimated proven reserves of dry natural gas in the United States were 244,656 billion cubic feet / Bcf, an increase of 29.4% from 189,044 Bcf in 2003 (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, which saw the number of producing gas wells increase from 76,436 in 2007 to 87,556 in 2008.
Please Note: Under Securities and Exchange Commission (SEC) rules for determining reserves that have been in effect since 1982, operators assessed their 2008 reserves based on what they could produce with reasonable certainty at the market price on the last day of the year. Under updated SEC rules issued in 2008 that take effect in 2010, operators will instead use an average of first-day-of-the-month prices throughout the year, which is less sensitive to volatility in prices, in developing their reserves estimates.
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. However, U.S. natural gas resources are subject to federal government access restrictions.
| Top U.S. Gas Fields Ranked by 2008 Proved Reserves (billion cubic feet) | ||||
| Field Name | State | 2008 Estimated Production Volume | ||
| Newark East | Texas | 1625.2 | ||
| San Juan Basin | Colorado, New Mexico | 1285.3 | ||
| Pinedale | Wyoming | 385.0 | ||
| Prudhoe Bay | Alaska | 148.9 | ||
| Natural Buttes | Utah | 217.1 | ||
| Hugoton Gas Area | Kansas, Oklahoma, Texas | 355.9 | ||
| B-43 (Fayetteville Shale) | Arkansas | 275.8 | ||
| Jonah | Wyoming | 402.8 | ||
| Wattenberg | Colorado | 193.3 | ||
| Source: Energy Information Administration - Top 100 Oil and Gas Fields of 2008 (.pdf format) | ||||
Energy Information Administration - U.S. Shale Gas Production
The increase in onshore reserves 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 fracturing techniques, which allow unconventional gas deposits in shale to flow more freely to the surface, and natural gas price increases during 2008 (the average wellhead price was $8.07 and the average residential price was $13.68 in 2008), which made it viable / profitable to continue to explore (the improvement in drilling technology also reduced the cost to extract the unconventional gas). 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 2009 (Summary), the International Energy Agency (IEA) indicates that unconventional gas resources in the United States and Canada are substantial. The combination of the new drilling technology, which has increased productivity per well from unconventional sources, with the recent decline in demand related to the economic recession, means that North Amercian may develop "an acute glut of gas supply over the next few years". (World Energy Outlook 2009, International Energy Agency; Executive Summary, page 12) http://www.iea.org/Textbase/npsum/weo2009sum.pdf (.pdf format)
Energy Information Administration - U.S. Natural Gas Prices
The increase in the supply in natural gas, and the decline in demand related to U.S. recession that commenced in third quarter 2008, has resulted in a decline the wellhead price: the wellhead has price declined from a high of $11.322 in July 2008 to $2.92 per thousand cubic feet in August 2009, and the average wellhead price from April 2010 back six months to November 2009 was of $4.39 per thousand cubic feet. Similarly, the residential price declined from $20.68 in July 2008 to $10.31 per thousand cubic feet by December 2009.
The Henry Hub spot price averaged $4.80 per MMBtu in June 2010, $0.66 per MMBtu higher than the average spot price in May 2010. The EIA forecast price for the second half of 2010 averages $4.68 per MM Btu. The risk of hurricane outages and the projected reduction in drilling activity combine to strengthen prices through the year. A small decline in U.S. production alongside increased consumption leads to higher prices in 2011; the projected Henry Hub spot price averages $5.17 per MMBtu.
Energy Information Administration - Number of U.S. Producing Gas Wells
The number of producing gas wells in the United States has been increasing: from 393,327 in 2003 to 478,562 in 2008, with the growth occurring in the western states and Pennsylvania.
Energy Information Administration - Natural Gas Gross Withdrawals and Production
Marketed production of natural gas averaged almost 60 Bcf per day in 2009, or a total of 21.9 trillion cubic feet (Tcf) over the year. The Energy Information Administration Short-Term Energy Outlook expects total marketed natural gas production of 61.3 Bcf/day in 2010 (approximately 22.3 Tcf), an increase of 1.3 Bcf/day over 2009 levels. EIA projects a continuing decline in Gulf of Mexico production, which is offset by gains in onshore production. Forecast marketed production declines by 0.4 Bcf/day to 60.9 Bcf/day in 2011.
Projected lower 48 states onshore production increases by 2 Bcf/day (3.8 percent) in 2010 and 0.2 Bcf/d (0.3%) in 2011. According to Baker-Hughes, natural gas rig counts have climbed from under 670 in July 2009 to about 950 in April this year and have remained relatively stable since then.
Energy Information Administration - Gulf of Mexico Federal Offshore Natural Gas Production
NOAA: 2010 Atlantic Hurricane Season Outlook
The Energy Information Administration Short-Term Energy Outlook at June 2010 expects Federal Gulf of Mexico natural gas production falls by about 10% in both 2010 and 2011 as a result of hurricane outages, the announced offshore drilling moratorium, and the decline in active drilling rigs over the last 4 years. The estimated median outcome for hurricane outages from June through November is a cumulative 166 Bcf this year, compared with 19 Bcf in 2009 (2010 Outlook for Hurricane-Related Production Outages in the Gulf of Mexico). The offshore drilling moratorium is projected to reduce Gulf of Mexico production by an average of 0.05 Bcf/day for the last 6 months of 2010 and 0.25 Bcf/day for 2011.
Energy Information Administration - U.S. Weekly Natural Gas Storage Report
The Energy Information Administration Short-Term Energy Outlook at June 2010 indicates that working natural gas in storage was 2,684 Bcf. This is 27 Bcf below last year’s level and 287 Bcf higher than the 5-year (2005-2009) average.
Baker Hughes Rig Counts
According to Baker Hughes, Inc., 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 natural gas supply and the decline of wellhead natural gas prices. For the half year period ending June 25, 2010, Baker reports 958 gas rigs in operation, and increase of 26.2% from 759 gas rigs at December 31, 2009, and an increase of 44% from the low point in July 2009.
Venezuela has the the second largest proved natural gas reserves in the Western Hemisphere after the United States. Approximately 90% of Venezuela’s proved natural gas reserves are associated with crude oil deposits.
The greatest proportion of oil produced in Venezuela comes from the Orinoco Belt region (Orinoco River basin), which is located in the north central interior of the country. The type of crude oil located there is very heavy (less viscous than other crude sources), which requires substantial investment in technology and expertise to extract and to refine. Thus, this region was opened to the major oil companies who were provided with favorable concession and royalty terms and the country's oil company, PDVSA (Petróleos de Venezuela S.A.), operated as a neutral partner. In the past few years of the Chávez administration, PDVSA has become fully nationalized (it was actually nationalized in 1976 but operated as a private company in Venezuela), especially after the strike in 2003. A policy shift during the mid-2000s resulted in the situation that the majority of the oil revenue earned by PDVSA was no longer maintained by the company for further exploration and investment but is utilized by the government for various expenditures (i.e. the company is no longer thought of as an "oil company" but as the government's primary source of funding for the Bolivarian socialist agenda). PDVSA subsidizes the price of gasoline in Venezuela (where domestic consumption is increasing annually; the local gasoline price is approximately 12¢ per gallon) and has also distributed heavily discounted oil to several nations within the Caribbean Basin and Central America.
Google Map Location of Orinoco Belt Region
During 2007, the holdings of all private petroleum companies were nationalized under the majority control of PDVSA (minumum 60% control by PDVSA). The country pledged to compensate the companies at market rates but ExxonMobil and ConocoPhillips decided to exit the country rather than surrender their claim. Thus, it is unclear whether Venezuela will be be able to maintain production levels if there is little or no investment in infrastructure by the company itself and no investment from private companies (for instance, during 2007 PDVSA reported that there is a shortage of oil drilling rigs in the country for new well drilling and the maintenance of existing wells). Similarly, the Paraguaná Peninsual Amuay oil refinery complex (located on the northwest coast) needs substantial investment. Secondly, almost 20,000 persons were fired from PDVSA during the strike and this included many experienced managers and workers who have not been adequately replaced. It is unclear what the actual barrels per day oil production output is: PDVSA claims that production has returned to pre-strike levels and that it produces approximatley 3.3 million barrels per day, however the International Energy Agency (IEA), the Organization of Petroleum Exporting Countries (OPEC) and the U.S. Energy Information Agency (EIA) all publicly indicate that production is probably closer to 2.5 million barrels per day.
Enagas, the principal government agency charged with regulating the natural gas sector, indicates that the petroleum industry consumes over 70% of Venezuela’s natural gas production, with the largest share of that consumption in the form of re-injection to aid crude oil extraction.
In September 2008, Venezuela signed initial agreements to create three joint venture companies to pursue LNG projects along the northern coast of the country. Each project will consist of a separate liquefaction train at the Gran Mariscal de Ayacucho (Cigma) natural gas complex in Guiria. The first project would source gas from the offshore Plataforma Deltana, with exports estimated at 4.7 million tons per year (t/y). The second train would use natural gas from the Mariscal Sucre project, also exporting an estimated 4.7 million t/y. The third train would use natural gas from the Blanquilla-Tortuga fields. According to PDVSA, the total investment in the three projects could approach $20 billion, with first exports by 2013.
Unfortunately, in May 2010, the semi-submersible Aban Pearl platform sank while drilling in the Dragon 6 oil field of the Mariscal Sucre offshore natural gas project, which is located off the coast of Venezuela's Sucre state. The platform was in the process of drilling 16 exploratory gas wells.
The U.S. Department of Energy, Energy Information Administration (EIA) / Oil & Gas Journal, estimates Venezuela's proven natural gas reserves as of December 31, 2009 at approximately 176 Trillion Cubic Feet / Tcf.
Natural Gas Companies (Public & Private Sector)
| Natural Gas Transportation & Distribution |
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 2008, 4,400 miles of new pipeline was scheduled to be constructed. Natural gas drilling and production locations are shifting from the Gulf of Mexico to the western states or shale deposit regions (onshore production), and there is a need for new pipeline infrastructure. On the demand side, new building construction (residential and commercial) has been steadily shifting away from heating oil systems to natural gas. In addition, many new electricity palnts operate on natural gas thus there is also the necessity for distribution pipelines within population areas.
The construction of new natural gas pipelines in the United States has become controversial because the pipes are starting to be located closer to densely populated urban / suburban residential areas and there is the fear that high pressure pipelines will affect the safety of local inhabitants.
In the United States, the Department of Transportation oversees natural gas pipeline regulation and safety. 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.
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 the Hassi R'Mel field, Algeria and Spain www.medgaz.com/.
GALSI (Gasdotto Algeria Sardegna Italia) is a planned natural gas pipeline from Algeria to Sardinia, and northern Italy.
Ruby Pipeline is a planned 670-mile, 42-inch diameter interstate natural gas pipeline that will begin at the Opal Hub in Wyoming and terminating at interconnects near Malin, Oregon. Contracts for the pipe have been signed and pipeline construction companies have been selected. The Project will have an initial design capacity of up to 1.5 billion cubic feet per day (Bcf/d) and will traverse portions of four states: Wyoming, Utah, Nevada, and Oregon. The project would cross federally administered lands in all four states.
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.
| Natural Gas Consumers (Usage & Demand) |
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:
Energy Information Administration, U.S. Natural Gas Consumption by End Use (Monthly)
Natural gas consumption within the United States has steadily increased over the past 30 years as it increasingly became the heating fuel of choice for new residential and commercial real estate construction, and as the fuel source of choice for new electricity generating facilities. The top natural gas consuming States in 2008 were: Texas, California, Louisiana, New York, Illinois and Florida (Source: www.eia.gov/dnav/ng/ng_cons_sum_a_EPG0_VC0_mmcf_a.htm).
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). Total consumption in 2009 was 22,810,148 Million Cubic Feet / MMcf (a decline from 23,226,612 MMcf in 2008), of which the greatest amount, 6,887,907 MMcf, was by the electricity generating industry, followed by industrial users, 6,141,160 MMcf, and then residential consumers, 4,759,869 MMcf.
In June 2010, the Energy Information Administration (EIA) Short-Term Energy Outlook projects that growth in total
natural gas consumption will average 64.7 billion cubic feet per day (Bcf/d) and 64.8 Bcf/d in 2010 and 2011, respectively.
Estimated year-over-year consumption growth averaged 2.8 Bcf/d (4.3 percent) in the first half of 2010, with significant
increases in the electric power and industrial sectors. This growth is expected to continue at a slower pace in the second
half of the year with an increase of 1.5 Bcf/d (2.6 percent). EIA’s projected natural-gas-weighted industrial production
index (a measure of industrial activity in natural-gas-intensive industries) increases by 7.5 percent in 2010, leading to a
1.0 Bcf/d (5.9-percent) increase in natural gas consumption in the industrial sector.
Projected natural gas consumption is virtually flat in 2011. The projected 2.7% increase in the natural-gas-weighted
industrial production index and NOAA forecast of slightly colder weather next year (1.4 percent increase in heating
degree-days) contribute to consumption growth in the residential, commercial, and industrial sectors in 2011. However,
this growth is offset by a decline in natural gas consumption in the electric power sector because of the forecast increase
in natural gas prices relative to coal prices next year. www.eia.doe.gov/emeu/steo/pub/contents.html#Natural_Gas_Markets
Energy Information Administration, U.S. Natural Gas Imports by Country (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, Egypt and Qatar.
The Energy Information Administration Short-Term Energy Outlook forecasted imports of liquefied natural gas (LNG) average 1.37 Bcf/d in 2010, a downward revision of about 0.14 Bcf/d from last month. Projected imports increase to 1.52 Bcf/d in 2011. While imports are expected to grow, higher prices in European and Asian markets will likely divert LNG cargoes from the United States. EIA also forecasts gross pipeline imports of 8.8 Bcf/d in 2010, a decrease of about 2.9% from 2009. EIA expects gross pipeline imports of 8.2 Bcf/d in 2011.
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.
In July 2010, the International Energy Agency publicly indicated that China has supplanted the United States as the world's largest energy consumer. China's 2009 consumption of energy sources, ranging from oil and coal wind and solar power, was equal to 2.265 billion tons of oil equivalent, compared to 2.169 billion tons oil equivalent for the United States. As per the IEA statistics, China's energy consumption has more than doubled in less than a decade, from 1.107 billion equivalent tons in 2000. China's National Bureau of Statistics disagreed with the IEA's analysis, indicating that China's energy consumption last year was equal to 2.132 billion tons of oil equivalent.
The demand for natural gas in the People's Republic of China increased by 22% in the first half of 2010 compared to the previous six months of 2009. The nation's manufacturing sector and electricity generating sector are the two largest consumers of natural gas and demand has been met by increased LNG shipments from Asia and the Middle East.
| Natural Gas Pricing |
United States Gas Pricing
EIA - Average Price of Natural Gas Delivered to U. S. Consumers, 1967-2000
ICE Day Ahead Natural Gas Price Report
In the United States, the price for natural gas is determined by the domestic open market. Internationally, the price for natural gas is linked to crude oil import prices.
The price for natural gas in the United States 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
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).
| Breakdown of Natural Gas Price Paid by Residential Consumers During the Heating Season, 2002-2008 | ||||||
| 2002-03 | 2003-04 | 2004-05 | 2005-06 | 2006-07 | 2007-08 | |
| Transmission Price | 43% | 49% | 47% | 43% | 48% | 47% |
| Commodity Price | 57% | 51% | 53% | 57% | 52% | 53% |
| Source: Energy Information Administration | ||||||
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
| LNG (Liquified Natural Gas) |
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.
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.
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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
| Environmental Issues |
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 (Fracking). 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.
| Natural Gas Industry Regulation |
| Comparing Natural Gas / Oil Fuel Heating Costs |
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.
Heating oil, a petroleum hydrocarbon usually referred to No. 2 Fuel Oil, burns 400 times hotter than natural gas and
is purchased by the gallon by most consumers.
U.S. Average Price 2007 (Source: U.S. Dept. of Energy):
Next, convert both to a comparable cost of per one million Btus:
Next, account for the AFUE of the system (in this case we will use the minimum 78% for both systems and multiply the Btus per Therm and the Btus per Gallon by 78%)
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Convert Gas to Price per Million Btus |
Convert No.2 Oil to Price per Million Btus
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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
| CNG (Compressed Natural Gas) |
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.
| Natural Gas Industry and Commodity Market Information Sources |
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
