Figure 1. Geological Formations Bearing Natural Gas
Natural gas is a naturally occurring fossil fuel consisting primarily of methane and small amounts of impurities such as carbon dioxide. It may also contain heavier liquids (also known as natural gas liquids) that can be processed into valuable byproducts including ethane, propane, butane and pentane. As illustrated in the above graphic, natural gas is found in several different types of geologic formations. Historically, natural gas has been conventionally extracted from large reservoirs and often produced in conjunction with oil. Technological advances in the areas of horizontal drilling and hydraulic fracturing have made it easier and cheaper to obtain gas from smaller unconventional sources including non-porous sand (tight sands), coal seams (coal bed methane) and most recently from very fine grained sedimentary rock called shale (shale gas), known in the industry as shale plays.
Shale gas extraction differs significantly from the conventional extraction methods. Wells are drilled vertically and then turned horizontally to run within shale formations. A slurry of sand, water, and chemicals, together referred to as hydraulic fluid, is then injected into the well to increase pressure and break apart the shale so that the gas is released. This technique is known as hydraulic fracturing or “fracking.”
Initial assessments of 48 shale gas basins in 32 countries suggest that shale gas resources, which have recently provided a major boost to U.S. natural gas production, are also available in other world regions. Initial indications from a 2011 study  reported 5,760 Tcf of technically recoverable shale gas resources in 32 foreign countries, compared with 862 Tcf in the United States.
Figure 2. Global Natural Gas Basins
Natural gas is used extensively in the United States, for generating electricity, for space and water heating in residential and commercial buildings, and as industrial feedstock , providing the base ingredient for such varied products as plastic, fertilizer, anti-freeze and fabrics.
Figure 3. U.S. Natural Gas Consumption by Sector
In the residential sector, almost 95 percent of natural gas is used for space and water heating, with cooking and clothes drying making up the remainder. In the commercial sector, space and water heating comprise the majority of natural gas use (62 percent), but other uses – including cogeneration (the use of natural gas to generate electricity and useful heat), also known as combined heat and power – compose one-third of natural gas usage. Bulk chemicals and refining account for more than one-third of all natural gas consumption in energy industries.
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Compared to other fossil fuels, natural gas is considered relatively “clean” because when it is burned it releases fewer harmful pollutants . Compared to coal or oil, natural gas combustion releases smaller quantities of particulate matter, nitrogen oxides, and sulfur dioxide. The combustion of natural gas also emits about half as much carbon dioxide as coal . However, methane itself is a potent GHG, more than 20 times more powerful in terms of its heat-trapping ability than CO2, though it is shorter lived in the atmosphere. Sources of methane emissions  include landfills and coal mines as well as digestion by cows and other ruminant animals. Emissions from equipment leaks, process venting and disposal of waste gas streams are known as fugitive emissions.
Table 1: Fossil Fuel Emissions Levels (Pounds per Billion Btu of Energy Input)
Source: U.S. Energy Information Administration, Natural Gas Issues and Trends (1998)
Currently, natural gas-related emissions account for about 22 percent of total U.S. greenhouse gas emissions, 84 percent of which are CO2 from natural gas combustion, 14 percent comes from fugitive methane releases, and the remaining 2 percent from CO2 from flaring natural gas during field production and CO2 removal during natural gas processing. Globally, natural gas combustion accounted for 19.9 percent of the world’s CO2 emissions in 2009.
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Since 1999, U.S. proved reserves of natural gas have increased every year, driven mostly by shale gas advancements. As a result, in 2011  the United States had the fourth largest proved reserves of natural gas in the world, at 482 Tcf. Russia had the largest reserves at 1,680 Tcf, followed by Iran at 1045.7 Tcf, and Qatar at 895.8 Tcf.
In 2010, the EIA estimated that the technically recoverable resource of U.S. shale gas was 827 Tcf. In 2011, this was revised down  to 482 Tcf (out of an average remaining U.S. resource base of approximately 2,543 Tcf). The decline mostly reflects changes in the assessment for the Marcellus shale (see Figure 4), from 410 Tcf to 141 Tcf, based on better data provided from the rapid growth in drilling in the Marcellus over the past two years. MIT’s mean projection  estimates recoverable shale gas resources at 650 Tcf out of a resource base of 2,100 Tcf. These estimates represent nearly 90 years of domestic demand at current consumption levels of about 24.1 Tcf per year.
Total domestic dry natural gas production in 2011 was 23.0 Tcf. This figure represents the remainder from a total gross withdrawal of 28.6 Tcf  of product, after venting and flaring, removal of non-hydrocarbon gases such as CO2, removal of natural gas liquids and other losses. From 2006 to 2010, shale gas production grew at an annual rate of 48 percent . Natural gas is produced in 32 states and in the Gulf of Mexico. According to the EIA, Texas, the Gulf of Mexico, Wyoming, Louisiana, Oklahoma, Colorado and New Mexico account for 80.8 percent of U.S. production in 2010. The geography of U.S. natural gas production is changing with an increasing percentage of production coming from other states like Pennsylvania and Arkansas.
Development of fracking technology has created the present boom in natural gas production. This technology was initially funded in the 1970s through the U.S. Department of Energy and with more than 20 years of federal tax credits (1980 – 2002) .
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Figure 4. U.S. Shale Plays
The U.S. natural gas pipeline network is a highly integrated transmission and distribution grid that can transport natural gas to and from nearly any location in the contiguous 48 states. Interstate and intrastate pipelines deliver natural gas to local distribution companies, directly to some large industrial end users and electricity generators, and to interconnections with other pipelines. The network consists of more than 210 pipeline systems with nearly 306,000 miles of pipe , and 1,400 compressor stations that maintain network pressure and assure continuous forward movement of supplies. To support the seasonal peaking demand of natural gas, there are 400 underground natural gas storage facilities  in the pipeline network for additional winter heating demand. There are three types of underground storage facilities : depleted natural gas or oil fields, aquifers and salt caverns. Additionally, there are 49 locations where natural gas can be imported or exported at the Canadian and Mexican borders. In response to earlier expectations of natural gas import needs, there are eight liquefied natural gas (LNG) import facilities  in the United States, which are now underused. With the recent increase in natural gas production, the U.S. Federal Energy Regulatory Commission (FERC)  authorized one export terminal at Sabine Pass, LA in 2012 (which is expected to begin operations before 2017), and others are in various stages of the application process.
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Natural gas consumption made up a little more than 22 percent of total global energy  use in 2008. The EIA estimated that world natural gas demand climbed to 112.9 Tcf in 2010, up 7.3 percent from 2009. This growth overshadows the 4 percent drop in natural gas demand experienced in 2009. According to the International Energy Agency, electric power generation remains the main driver behind global natural gas demand growth; use in this sector is estimated to have increased by 5 percent in 2010.
Natural gas use constituted about 25 percent of total U.S. primary energy consumption  in 2010. Total U.S. natural gas consumption  grew from 23.3 Tcf in 2000 to 24.1 Tcf in 2010. A decline in annual consumption in the industrial sector during this period was more than offset by growth in the electric power sector, which grew at an annual average rate of 3.5 percent.
Figure 5. U.S. Natural Gas Consumption by Sector, 2000 – 2010 (Tcf)
In 2010, natural gas fueled 23.9 percent of total U.S. electricity generation. From 2000 to 2010, natural gas electricity generation grew at a faster rate than total electricity generation (5.1 percent per year versus 0.8 percent per year). This growth can be attributed to a number of factors, including low natural gas prices in the early part of the decade. Additionally, gas-fired plants are relatively easy to construct, have lower emissions compared to other fossil fuels, and have lower capital costs and shorter construction times compared to coal power plants. More information about natural gas fired electricity generation can be found on the Center’s Natural Gas Techbook page.
The market for natural gas is similar to other commodities. Generally, when demand goes up, producers respond with increased exploration, drilling and production. However, significant supply increases do not happen overnight. It takes time to study the geology, acquire leases, drill wells and connect to pipelines (or build new pipelines). This expansion can take many months or years. As a result, there is often a lag in bringing new supply to market, which can cause price volatility and spikes. Conversely, oversupply (or expectations of low price), result in less exploration. Even with a lower price, many producers are reluctant to halt extraction due to the geologic characteristics of wells that make it difficult to stop and restart production. In addition, since gas is often produced along with oil or natural gas liquids, stopping the flow of natural gas means stopping the flow of oil and natural gas liquids, which may not make financial sense. Another market driver is that gas is often sold on a contractual basis, and a producer may be legally bound to produce a specific quantity of natural gas.
Natural gas markets across the world are segmented, that is, natural gas pipeline systems connect distinct regions of the world, for example, the United States is connected to Canada and Mexico while the United Kingdom is connected to the North Sea and Europe. Natural gas prices are determined within these regional markets based on the available regional supply and demand patterns. A general upward trend in world natural gas prices began in the early 2000s as demand for the product began to exceed supply. Following the global recession of 2008 – 2009 a fairly wide spread in world natural gas prices developed (Figure 6).
Figure 6: World Natural Gas Prices (USD/MMBtu)
Prices in the U.S. and Canadian markets have plummeted due to the abundant supply of North American shale gas. Asian markets have seen higher gas prices due to increasing demand in China, South Korea and Japan. Europe has also seen higher prices as a result of increased demand as well as periodic Russian supply disruptions from 2005 – 2009.
Supply and demand responses, the seasonal nature of demand (residential winter heating or summer cooling through increased electric power generation requirements), or cold weather and hurricane-driven supply disruptions, have all contributed to natural gas price volatility in the United States in the last decade (Figure 7). In 2001, several years of declining productive capacity and increasing demand resulted in a sharp winter price spike. Prices spiked again in 2005 in the wake of hurricanes Rita and Katrina, which temporarily curtailed supplies from the Gulf of Mexico. Prices remained high relative to historic norms, peaking along with other energy commodities in 2008. Since then, average annual wellhead prices  in the U.S. have gone down. Two factors – an abundance of shale gas and the slow pace of economic recovery following the recession – have contributed to sustained low prices.
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Figure 7: U.S. Natural Gas Monthly Average Wellhead Prices (USD/MMBtu)
While most of the world’s gas supply is transported regionally via pipeline, global gas trade has accelerated with the growing use of liquefied natural gas. To maximize the quantity of natural gas that can be transported, the gas is liquefied at an export facility. First, the liquefaction process involves the removal of certain components, such as dust, acid gases, helium, water, and heavy hydrocarbons. Then, the natural gas is condensed into a liquid by cooling it to approximately -162°C (-260 °F). Liquefied natural gas takes up 1/600th the volume of natural gas in the gaseous state. Once liquefied, the LNG can be transported by tanker and regasified for use in other markets at an LNG import terminal. Between 2005 and 2010, the liquefied natural gas market grew by more than 50 percent  and it now accounts for 30.5 percent of global gas trade . Global gas liquefaction capacity increased by almost 40 percent  over just the past two years (Qatar completed an 80 bcf facility in 2011), and is expected to increase by an additional one-third over the next five years.
With surplus domestic supply and substantially higher prices in other regional markets, several U.S. companies have applied to the relevant agencies for permission to export liquefied natural gas with Houston-based Cheniere Energy being the first company to win approval for its Sabine Pass facility in 2012.
Prospects for U.S. liquefied natural gas exports depend significantly on the cost-competitiveness of U.S. liquefaction projects relative to those at other locations. Over much of the last decade, lower supply expectations and higher, volatile prices prompted new investments in U.S. natural gas import and storage infrastructure. Since 2000, North America’s import capacity has expanded from approximately 2.3 Bcf/day to 22.7 Bcf/day, around 35 percent of the United States’ average daily requirement. Yet as of 2009, U.S. consumption of imported liquefied natural gas was 1.2 Bcf/day , leaving most of this capacity unused. The ability to use and repurpose existing U.S. import infrastructure—pipelines, processing plants, storage and loading facilities—will help reduce total costs relative to new facilities. While liquefied natural gas makes up a small portion of U.S. imports, it is important in other parts of the world. The majority of the gas trade in the Asia Pacific region is in the form of LNG imports to Japan, South Korea, and Taiwan from other Asia Pacific countries, Australia, and the Middle East (Figure 8).
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Figure 8: Major International Natural Gas Trade Flows (Billion Cubic Meters)
Source: BP Energy Statistics 2011 
According to the EIA’s International Energy Outlook , natural gas is expected to be the world’s fastest growing fossil fuel, with consumption increasing at an average rate of 1.6 percent per year to 2035. Growth in natural gas is expected to occur in every region and is most concentrated in developing countries, where demand increases nearly three times as fast as in developed countries.
In the United States, shale gas production is expected to more than double over the next 20 years (Figure 9), and production of natural gas is expected to exceed consumption early into the next decade. As a consequence, the EIA in its 2012 Annual Energy Outlook Reference Scenario  expects U.S. natural gas prices to remain below $5/MMBtu through at least 2020.
Figure 9. U.S. Natural Gas Production, 1990 – 2035 (Tcf)
EIA’s International Energy Outlook 2011  projects world natural gas liquefaction capacity to nearly double from 2009 to 2035 , and the United States is expected to become a net exporter of LNG in 2016.
The forecast of an abundance of domestic natural gas, coupled with recent regulatory actions taken by the U.S. Environmental Protection Agency (EPA) with regard to the electric power sector (Mercury rule , Cross-State Air Pollution Rule , and New Source Performance Standard  for CO2 from new power plants) have led to natural gas becoming the dominant choice for planned electricity generating capacity. Moreover, the abundance of natural gas has somewhat mitigated industrial concerns about using the fuel as a feedstock to manufacture products such as plastics and fertilizers.
The rapid growth of shale gas has also increased scrutiny of the potential environmental and health effects of hydraulic fracturing. As a result, several states have taken action either to regulate hydraulic fracturing or to issue a temporary moratorium while they explore the issue further. In addition to state action, the U.S. Department of Interior proposed new rules for regulating natural gas drilling on federal lands in 2012, and the EPA has undertaken a Hydraulic Fracturing Study Plan  to study the relationship between hydraulic fracturing and drinking water.
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