Natural Gas in Canada | The Canadian Encyclopedia


Natural Gas in Canada

Natural gas ranks among the fastest-growing energy sources in Canada and is seen by many in the energy industry as a game-changer, a comparatively clean, low-cost and versatile fuel. It can directly generate power and heat and can be chemically altered to produce a wide range of useful commodity chemicals. It burns cleaner and more efficiently than other fossil fuels, releasing significantly fewer harmful pollutants into the atmosphere. Natural gas is colorless, odourless, shapeless, lighter than air and contains a mixture of several hydrocarbon gases, which are organic compounds consisting of some combination of hydrogen and carbon molecules.

The primary consumers of natural gas are the industrial (54.1 per cent), residential (26.6 per cent) and commercial sectors (19.3 per cent). Canada is the fifth largest natural gas producer after the United States, Russia, Iran and Qatar. Currently, all of Canada’s natural gas exports go to the United States through a network of pipelines, making Canada the largest foreign source of US natural gas imports. At the end of 2016, Canada had 76.7 trillion cubic feet of proven natural gas reserves and had produced 152 billion cubic metres of natural gas that year. It is forecasted that global natural gas consumption will double by 2035.

Visual representation of the components of raw natural gas
Components of raw natural gas
(© Canadian Centre for Energy Information, 2013)

What Is Natural Gas?

Natural gas is the cleanest-burning primary (i.e., unconverted) fossil fuel, a hydrocarbon made up of the elements hydrogen and carbon, plus impurities. The composition of natural gas varies depending on the type, location, geology and depth of the reservoir from which it is extracted. Typical raw natural gas is mainly methane, with decreasing quantities of ethane, propane, butane, pentane and heavier hydrocarbons (also known as condensate). Furthermore, natural gas can also contain non-hydrocarbon gases such as carbon dioxide, hydrogen sulphide, nitrogen, oxygen and mercaptans (e.g., methanethiol, ethanethiol), as well as water and traces of rare gases such as helium and argon.

Visual representation of the components of raw natural gas

Natural gas components
Created using data from V. Chandra, Fundamentals of Natural Gas: An International Perspective, Tulsa Oklahoma: Penn Well Corporation, 2006. 

Methane usually accounts for 65–95 per cent of the total volume produced. If natural gas contains more than 95 per cent methane, it is called lean gas and will produce few liquids when brought from underground to the surface. Natural gas containing less than 95 per cent methane and more than 5 per cent heavier hydrocarbon molecules is called rich gas. Methane is the lightest hydrocarbon component in natural gas because it is the simplest, containing the fewest number of carbon atoms. However, it produces less energy when it burns than heavier components such as ethane and liquefied petroleum gases (LPGs).

Where Is Natural Gas Found in Canada?

A map of Canadian gas and oil fields   

Locations of natural gas and oil found in Canada. Red represents gas fields and green represents oil fields.

(Courtesy International Petroleum Encyclopedia 2010, ed. Joseph Hilyard, PennWell Corporation, 2010)
A map of Canadian gas and oil fields

Locations of natural gas and oil found in Canada. Red represents gas fields and green represents oil fields.

(Courtesy International Petroleum Encyclopedia 2010, ed. Joseph Hilyard, PennWell Corporation, 2010)
A map of Canadian gas and oil fields

Locations of natural gas and oil found in Canada. Red represents gas fields and green represents oil fields.

(Courtesy International Petroleum Encyclopedia 2010, ed. Joseph Hilyard, PennWell Corporation, 2010)
A map of Canadian gas and oil fields

Locations of natural gas and oil found in Canada. Red represents gas fields and green represents oil fields.

(Courtesy International Petroleum Encyclopedia 2010, ed. Joseph Hilyard, PennWell Corporation, 2010)

Natural gas production is concentrated in the Western Canadian Sedimentary Basin (WCSB), with the highest production in Alberta and British Columbia. In 2016, these provinces accounted for 67.1 per cent and 30 per cent of total Canadian production, respectively.

Natural gas production by region in 2016


Natural gas production in 2016 (million cubic metres at 101.325 kilopascals and 15°C)



British Columbia




East Coast Offshore


Eastern Canada


North West Territories


Canada Total


Conventional and Unconventional Natural Gas

The energy industry has focused more on “unconventional” natural gas supplies as the conventional sources of natural gas in Canada have become more depleted. Conventional and unconventional natural gas are essentially of the same quality and composition. The main factor differentiating the two sources is location. As noted by industry executive and author Vivek Chandra, conventional gas is generally relatively difficult to find but easy to produce, while unconventional gas is easy to find but relatively difficult to produce.

Unconventional natural gas is found in previously inaccessible places such as shale and coalbeds. Advances in exploration and drilling techniques since the late 20th century have opened a new era in the exploitation of natural gas (see also Fracking).

When the term unconventional gas was coined, it referred to the rock type and geological setting of the gas reservoir rather than the gas itself. Unconventional gas now refers to a reservoir that presents more operational and economic obstacles than a conventional reservoir. Collectively, shale gas, tight gas sands and coalbed methane (CBM) are called “commercialized unconventional natural gas resources.” Gas hydrate reservoir is another type of unconventional natural gas. Canada has massive gas-hydrate resources that remain untapped because production is both complicated and expensive.

Schematic representation of the geology of natural gas resources
Schematic representation of the geology of natural gas resources
(Source: National Energy Board [2011], modified from energy information administration and United States geological survey.)

Despite the fact that new conventional natural gas reservoirs are still being discovered in the WCSB, conventional natural gas production in the basin reached its peak around 2005–06. The future of natural gas production in Canada could therefore centre only on unconventional deposits in the WCSB, as well as on offshore conventional fields. In the Arctic, Nova Scotia and Newfoundland and Labrador, most production comes from offshore reserves. Basins offshore from British Columbia contain large natural gas reserves, but no large-scale exploratory projects have yet been undertaken to produce natural gas from beneath the sea on the Pacific Coast.

History of Natural Gas in Canada

Humans used natural gas as early as 1000 BCE in ancient Greece, India, Persia and China. In the late 18th century, natural gas produced from coal was commercialized in Britain and used to light streets and houses (see Coal Gasification). In the early 19th century, North American cities adopted the same technology. Coal gas lit the streets of Montreal by 1836 and Toronto by 1841.

The first natural gas discovery on Canadian soil occurred near Moncton, New Brunswick, during oil drilling operations in 1859. This was followed by discoveries in Southwestern Ontario (1866) and near Medicine Hat, Alberta (1883).

The major boom in natural gas use in Canada occurred after the Second World War, when engineering advances allowed the construction of reliable and safe long-distance pipelines to transport natural gas. Until the late 1950s, most Canadian cities did not have natural gas distribution networks due to the absence of such pipelines.

Timeline: Canadian Natural Gas Industry




Coal gas lit the streets of Montreal.


Coal gas lit the streets of Toronto.


First Canadian natural gas pipeline built in Quebec.


Natural gas was discovered in New Brunswick and flared as a waste product.


Natural gas was discovered in Southwestern Ontario. At the time, it was considered a waste product and either vented or flared.


First natural gas discovery in Alberta: at Langevin, near Medicine Hat, a crew working for the Canadian Pacific Railway (CPR) accidentally found natural gas while drilling a water well.


Eugene Coste (a.k.a., “the father of natural gas in Canada”) successfully drilled for natural gas in Essex County, Ontario, to supply nearby communities. He then began pipelining produced natural gas to Windsor, Ontario, and across the border to the United States.


Medicine Hat leaders borrowed a CPR water rig to drill for natural gas after another accidental discovery outside the town by the CPR crew. Medicine Hat began to use natural gas for its cooking, heating and lighting needs.


As Ontario’s natural gas supply declined, the provincial government moved to protect consumers and banned Coste’s exports to the United States.

First commercialized gas field developed at Medicine Hat.


English writer Rudyard Kipling visited Medicine Hat and described it as having “all hell for a basement.”


Coste moved west with a bold plan to supply all the towns of southern Alberta with natural gas. He drilled along CPR rights-of-way and eventually found a huge reservoir at Bow Island in eastern Alberta that became known as “Old Glory.”


A 275 km gas pipeline was built from Bow Island to Calgary by Coste’s Canadian Western Natural Gas (Now ATCO).


The first natural-gas condensate reservoir (called the Dingman #1 well) was discovered in Turner Valley, Alberta (see Turner Valley Gas Plant).


Edmonton connected to a natural gas supply upon the completion of a 130 km pipeline from Viking, Alberta.


A natural gas condensate reservoir was discovered in the Mississippian formation at Turner Valley, Alberta.


The Alberta Petroleum and Natural Gas Conservation Board was formed by the Social Credit government. It significantly reduced natural gas flaring.


A major sour gas reservoir was discovered at Jumping Pound in the foothills west of Calgary.


The Leduc #1 well was discovered near Leduc, Alberta by Imperial Oil (see Striking Oil in Leduc: The Beginning of Alberta's Oil Boom).


The first commercial natural gas well in the Peace River Country of British Columbia was drilled.


The Bonnie Glen gas field was discovered near Leduc, Alberta.


The very first sulphur recovery plant was built at Jumping Pound in the foothills west of Calgary.

The Homeglen-Rimbey and Westerose gas fields were discovered near Leduc, Alberta.

The Dunvegan gas field was discovered around Debolt, Alberta.


The Westerose South and Wimborne natural gas fields were discovered near Leduc, Alberta.

The Harmattan East gas field was discovered near Rundle, Alberta.


The Windfall natural gas field was discovered near Leduc, Alberta.


The Waterton gas field was discovered near Rundle, Alberta.


Westcoast Transmission Company exported natural gas to US markets via Vancouver for the first time.

First natural gas exported from Western to Eastern Canada by TransCanada Pipelines.

TransCanada Pipelines Ltd.’s Alberta system, known as NOVA Gas Transmission Ltd. or NGTL, begins operations.


Opening of the TransCanada natural gas pipeline from Alberta to Ontario.

The Slave Point gas field was discovered at Clarke Lake, British Columbia.

The Wildcat Hills gas field was discovered near Rundle, Alberta.

The Carstairs gas field was discovered around Elkton, Alberta.


The Brazeau River gas field was discovered around Elkton, Alberta.


The Edson gas field was discovered around Elkton, Alberta.


Canada’s first offshore natural gas field was discovered near Sable Island, Nova Scotia.

The Strachan gas field was discovered around Leduc, Alberta.


Panarctic drilling resulted in the first major discovery in the Canadian Arctic: Drake Point natural gas field, on the Sabine Peninsula of Melville Island.

Ricinus West gas field discovered near Leduc, Alberta.


The Parsons Lake gas field was discovered in the southern Mackenzie Delta.


Discovery of the Elmworth gas field in Alberta, the first reservoir where deep drilling was used.


Foothills Pipe Lines Ltd. begins transporting natural gas from central Alberta to the US border.


Alberta’s Amoco Dome Brazeau River 13-12-48-12 W5M well blew out, emitting hydrogen sulphide gas and condensate at rates up to 283 x 103 cubic metres per day until it was brought under control more than two months later. The blowout created a stink across the province.

The “Pre-build” pipeline originating in Caroline, Alberta, is completed, transporting natural gas from Western Canada.


Discovery of the Caroline Swan Hills natural gas field.


Production began at Newfoundland and Labrador’s Hibernia offshore oil and gas field, discovered 18 years earlier in 1979.


The major Ladyfern Slave Point natural gas field was discovered in British Columbia.

Canada produces a record amount of sulphur (a byproduct of sour natural gas and sour oil facilities): 8,397,572 tonnes that year.


Production begins at the first Canadian offshore natural gas development near Sable Island, Nova Scotia.

The Alliance Pipeline starts transporting natural gas from Northeastern British Columbia and Northeastern Alberta to Illinois, USA.


Canadian natural gas production hit a record high at 179,216 million cubic metres for the year.


An industry/government consortium carries out an experimental gas hydrate project at Mallik in the Mackenzie Delta, Northwest Territories.

Founding of the Canadian Society for Unconventional Gas.

East Coast offshore natural gas production hit a record high of 5,209 million cubic metres for the year.


A record number of natural gas wells (2,287) were completed in Saskatchewan.


A company now called Canaport LNG (a partnership between Repsol and Irving Oil) received its permit to operate the LNG terminal in Saint John, New Brunswick.


A record number of natural gas wells were completed in Alberta (13,268 wells that year) and British Columbia (1,049 wells).

White Rose, a Newfoundland and Labrador offshore oil and gas field, was developed using a floating production, storage and offloading vessel (SeaRose FPSO).


Production of ethane hit a record high in Alberta at 14.9 million cubic metres for the year.


Construction of the first Canadian LNG regasification terminal (Canaport LNG) is commissioned, with a planned capacity of 1.2 billion cubic feet per day.


The first shipment of LNG was imported by Canaport LNG.


Substantial drop in natural gas wells completed in Saskatchewan. Only three wells were completed that year, compared to more than a thousand per year for most of the previous decade.


Natural gas production hit a record high in British Columbia, with 47,130 million cubic metres for the year.

Canada’s ethane production hit a record high with 15,177,071 cubic metres produced for the year.

How Is Natural Gas Produced?

Once a natural gas well is drilled and completed successfully, it is ready to produce fluids. In principle, natural gas production methodology is a function of the production stage in the life of the particular reservoir, as well as gas reservoir type. Gaseous hydrocarbons can be produced from two main conventional sources:

  1. Gas can be found in association with oil. Almost all oil reservoirs can produce some natural gas, which is brought to the surface with oil and then separated at appropriate surface facilities.
  2. Gas can be produced from reservoirs that primarily contain gas. Such reservoirs tend to be considerably deeper and hotter than oil reservoirs.

Natural gas can also be produced from unconventional sources, such as coalbed methane (CBM), tight gas and shale gas.

Short-distance pipelines connect wells to central processing facilities. Raw natural gas processing plants produce pipeline-quality natural gas for distribution to residential, commercial and industrial such as electricity sectors as fuel intake. They also segregate a number of natural gas components and sell them separately as a petrochemical, refinery and oil sands feed-stocks.

The processing raw natural gas into pipeline-quality natural gas can be quite complex and usually involves several processes. The type and extent of processing depend on the composition of the raw natural gas and the specifications of consumers. Typically, any natural gas processing facility is equipped with purification, separation and liquefaction units.

Diagram illustrating the role of a gas processing plant
(created by Arash Ostovar)


Purification is the removal of impurities (valuable or not), such as water, carbon dioxide, hydrogen sulfide, helium, nitrogen, mercury and solids (such as sand, clay, wax and asphaltenes). Impurities can hinder the transportation, storage and use of gas as an industrial or residential fuel. For example, carbon dioxide and hydrogen sulfide, known as acid gases, are highly corrosive compounds that must be removed before further processing to prevent corrosion. Hydrogen sulfide is also poisonous and must be removed for safety reasons. Natural-gas market specifications dictate the quantities of each of these compounds permitted (whether by law, regulation or corporate policy) in the processed product.

Water removal (dehydration) is an essential function of any natural gas processing facility, not only to prevent corrosion, but also to prevent the formation of hydrates (ice-like compounds of hydrocarbons and water) in natural gas systems. Hydrates can block and damage processing units as well as pipelines.

Separation and Liquefaction

The main purpose of separation and liquefaction is to increase the energy density of the gas for storage or transportation. The amount of liquefied petroleum gas (LPG) and natural gas liquid (NGL) extracted from the natural gas stream before transportation depends on pipeline specifications. Condensates (heavier hydrocarbons), LPG and NGL can be recovered as liquids in the processing units and sold separately.

Upstream, Midstream and Downstream Production

The natural gas production industry can be divided into three categories of activity: upstream, midstream and downstream. In Canada, upstream gas-industry companies carry out exploration, drilling and production of raw natural gas. Some upstream companies also own and operate gathering pipelines (which carry raw natural gas from production wells to central process facilities) and field processing facilities.

Midstream companies operate gathering pipelines, natural gas processing plants (which remove impurities) and natural gas storage facilities in addition to producing NGL and LPG. Purified natural gas is transported by pipeline from processing plants to transmission pipelines or local distribution companies in consuming areas.

Downstream companies distribute natural gas through transmission pipelines and distribution companies. Eventually, local distribution companies distribute natural gas to their consumers through extensive networks of local distribution pipelines.

Graph showing Canadian marketed gas production 1947-2016

Created using data from the Statistical Handbook for Canada’s Upstream Petroleum Industry, Canada’s Oil and Natural Gas Producers Technical Report, 2017.

Graph showing Canada’s natural gas production by region in 2016

Created using data from the Statistical Handbook for Canada’s Upstream Petroleum Industry, Canada’s Oil and Natural Gas Producers Technical Report, 2017.

Graph showing natural gas production by region 1947–2016

Created using data from the Statistical Handbook for Canada’s Upstream Petroleum Industry, Canada’s Oil and Natural Gas Producers Technical Report, 2017.

How Is Natural Gas Transported in Canada?

After production, the greatest challenges are transporting and storing natural gas between production fields and consumers. While transportation networks provide a crucial link between producers and consumers, storage facilities maintain the efficiency and reliability of the natural gas transmission and distribution system.

There are four major natural gas transport technologies used in different contexts depending on distance to gas-consuming market as well as the gas field production rate. Pipeline and compressed natural gas (CNG) transport technologies rely on natural gas compression. Liquid natural gas technology relies on conversion of natural gas to liquid form via deep refrigeration. Gas-to-liquids (GTL) relies on the conversion of natural gas to liquid products via chemical reactions. Pipeline and liquefied natural gas (LNG) are the most established technologies and the main ones used to transport natural gas from producers to consumers.

Graph showing production volume versus distance to market framework for gas technologies

Created using data from M. J. Economides, D. A. Wood and S. Mokhatab, “Technology options for securing markets for remote gas,” in Proceedings of 87th Annual Convention of the Gas Processors Association, 2008.

Did you know?
Natural gas liquid (NGL) refers to the product of a natural gas facility. This is not to be confused with liquefied natural gas (LNG), a method of transporting natural gas by converting it to its liquid form through deep refrigeration.

At gas processing plants, NGLs are separated from raw natural gas. The product — primarily methane — is transported by pipeline or LNG tanker to gas markets. The least expensive and most common technology is overland pipeline. Underwater pipelines are viable but very expensive, typically costing as much as 10 times more than overland pipelines of equivalent length.

Since 1853, when the first Canadian natural gas pipeline was built in Quebec, extensive pipeline networks have been developed to carry natural gas, NGL and LPG. Currently, Canada has one of the world’s largest natural gas pipeline networks. According to Statistics Canada, this network included 89,071 km of gas transport pipelines and 243,500 km of gas distribution pipelines in 2015.

When a pipeline is not economically feasible, LNG is the best alternative for natural gas transport. While many in the energy industry consider LNG “technologically proven” (i.e., viable due to technological advances over the past few decades) and safe, it requires relatively costly investments in shipping and receiving terminals. Additionally, LNG liquefaction, transportation and regasification consumes a massive amount of energy. Canada has no LNG export terminal, though it has been importing LNG through the Canaport LNG regasification terminal at Saint John, New Brunswick since 2008.

A map of regulated natural gas pipelines in Canada
(Source: “Canada’s Pipeline Transportation System,” National Energy Board Library and Publication Services, 2016)
Map showing supply and disposition of Canadian natural gas in 2015
(Source: “Canada’s Pipeline Transportation System,” National Energy Board Library and Publication Services, 2016)

Importing and Exporting Natural Gas

Despite the fact that Canada is the fifth-largest natural gas producer in the world, it still imports natural gas. All of these imports enter the country in Eastern Canada via an extensive network of pipelines and the LNG terminal in Saint John. All of Canada’s natural gas exports go to the United States, making Canada the US’s largest foreign source of natural gas.

Over the period from 2015 to 2040, natural gas supplies are expected to become more abundant and the industry more versatile as technology unlocks resources that were previously considered too costly to produce. North American producers expect to grow and to help establish the continent as a natural gas exporter, with Asia Pacific and Europe as their primary markets (these regions account for about 90 per cent of global natural gas imports). Canada’s natural gas reserves are vast enough to dominate the domestic supply of primary energy for many decades to come.

In several years, the United States is expected to transform from a net importer to a net exporter of natural gas as its production grows. The US will come to rely less on natural gas imported from Canada — a shift that will negatively impact Canadian natural gas producers.

Map showing major trade-based movements of natural gas in 2016

Trade flows worldwide are in billion cubic meters. Created using data from the BP Statistical Review of World Energy, BP, June 2017 (66th edition).

How Is Natural Gas Stored?

Storing natural gas helps producers balance supply and demand and respond to peaks in demand throughout the year. Natural gas consumption fluctuates significantly between summer and winter: demand in residential and commercial sectors can peak six times higher in winter, when natural gas is used most for heating. It is therefore stored in the warmer summer months for use in the cooler winter months. There are two uses for natural gas storage facilities: a) daily or inter-day swing to meet shorter-term peak load requirements; and b) seasonal swing to meet a longer-term base load requirement.

Alberta is the largest natural gas producer in Canada and is also where most of the country’s natural gas storage is located. Alberta producers manage storage facilities and tap them to supply the nation’s pipelines. This is because storing the fuel close to its source is the most efficient and economical option. In Eastern Canada, local distribution companies and large consumers store natural gas to meet winter demand. These facilities are concentrated in Southwestern Ontario.

Graph showing Canadian monthly natural gas storage trend
Created using data from Canadian Gas Association, “Natural Gas Storage,” CGA bulletin, 2016.
<Graph showing natural gas storage capacity by province

Created using data from Canadian Gas Association, “Natural Gas Storage,” CGA bulletin, 2016.

Projected Growth of Natural Gas

There is an explicit relationship for any nation between per capita energy consumption and wealth. A sustainable energy supply is essential to global economic development and that of individual countries, including Canada (see also Economy). In the 19th and early 20th centuries, coal was the dominant fuel, but after the Second World War, coal progressively lost it share to oil. In the same way, natural gas’s share of the energy mix has been growing since the late 1970s. Collectively, these fossil fuels made up more than 85 percent of the world’s primary energy market in 2015. They have held roughly this share since 1965.

In contrast, nuclear, hydro and renewables (e.g., wind, solar, geothermal, biomass and biofuels) play a far smaller role. The BP Energy Outlook 2017 Edition projects that fossil fuels will remain the dominant sources of energy, even though half the growth in energy supplies over the next 20 years will be from renewables, nuclear and hydroelectric power. The same source projects that fossil fuels will account for more than 75 per cent of total energy supplies in 2035.

Chart showing primary energy consumption by fuel and shares of primary

Primary energy consumption by fuel and shares of primary energy. *Renewables includes wind, solar, geothermal, biomass and biofuels.

(Source: BP Energy Outlook 2017 Edition, BP, 2017)

Trends in energy investment, consumption and the development of new technologies suggest that natural gas is the fastest-growing fuel, with its share in primary energy projected to overtake coal to be the second-largest fuel source by 2035.

The natural gas industry in Canada faces the possibility that the United States — currently Canada’s only export partner for natural gas — could transform in the coming years from a net importer to a net exporter of natural gas. If this were to happen, the US would likely purchase Canadian natural gas at a discount, convert it to LNG and make a large profit from it.

Advantages and Challenges

Fossil fuels store and deliver large quantities of energy more effectively and consistently than current alternative energies. Reducing greenhouse gas emissions and air pollution have nevertheless become increasingly important. As the cleanest burning of all fossil fuels, natural gas holds the promise of cleaner energy. Thus, it offers more environmentally friendly options than other fossil fuels.

Carbon dioxide (CO2) produced in the combustion of fossil fuels makes up a large proportion of the total volume of emissions. Combustion of natural gas emits 44 per cent less CO2 than coal and 29 per cent less than oil per billion Btu of energy. Natural gas combustion also releases a negligible amount of un-combusted methane into the atmosphere compared to other fossil fuels.

Another environmental concern is acid rain caused by nitrogen oxides and sulphur dioxide. Replacing coal with natural gas in power plants can reduce nitrogen oxide emissions by 80 per cent and virtually eliminate sulphur dioxide emissions. Natural gas also produces relatively low levels of particulate matter, which, along with nitrogen oxide, is a main component of air pollution from fossil fuel combustion.

However, even though natural gas is more environmentally friendly than other fossil fuels, it still contributes to greenhouse gas emissions (see Climate Change) and is a non-renewable source of energy. It therefore draws some of the same criticisms as more carbon-heavy fossil fuels, albeit to a lesser degree.


Condensate: A mixture composed mainly of pentanes and heavier hydrocarbons recovered as a liquid from field separators, scrubbers or other gathering facilities before the gas is processed in a plant.

Distribution pipelines: Networks of pipes that deliver natural gas to homes, business and industries.

Feeder pipelines: Networks of pipes that transport natural gas, NGL and LPG from natural gas processing and storage facilities to transmission pipelines. They are mainly located in Western Canada.

Fossil fuels: Naturally occurring fuels such as coal, oil and gas formed beneath Earth’s surface. Over millions of years, plants and animals have decomposed into organic chemical compounds, called hydrocarbons, that make up these fuels.

Gas hydrates: Ice-like crystals composed of natural gas molecules that glue themselves inside symmetrical cages of water molecules.

Gas volumes: Gas volumes are typically measured in multiples of cubic meters (m3) or cubic feet (ft3). Gas reserves are expressed in trillion cubic feet (Tcf). Gas volume consumed or produced is often expressed in million cubic feet per day (MMcfd), Mcfd (thousand cubic feet per day) or billion cubic feet (Bcf).

Gathering pipelines: Networks of pipes that move raw natural gas from wellheads to natural gas processing facilities. They are mainly located in Western Canada.

Liquefied natural gas (LNG): The light hydrocarbon portion of natural gas, predominately methane, which has been liquefied at or below -160°C and occupies 1/600 of its original volume.

Liquefied petroleum gases (LPG): Liquefied petroleum gases consist primarily of the hydrocarbon components propane or butanes, or a combination, which is maintained in a liquid state under pressure within the confining vessel.

Natural Gas Liquids (NGL): Natural gas liquids are those hydrocarbon components recovered from raw natural gas as liquids by processing through extraction plants or recovered from field separators, scrubbers or other gathering facilities. These liquids include the hydrocarbon components ethane, propane, butanes and pentanes plus, or a combination.

Raw natural gas: The lighter hydrocarbon and associated non-hydrocarbon substances occurring naturally in an underground reservoir, which under atmospheric conditions is essentially a gas, but which may contain liquids.

Sour gas: Natural gas containing H2S and other sulphur compounds.

Sulphur: A yellow, non-metallic chemical element. In its elemental state, it exists in both crystalline and amorphous forms. In many gas streams, sulphur may be found as volatile sulphur compounds, such as hydrogen sulfide, sulphur oxides, mercaptans and carbonyl sulfide. Reduction of the concentration of these gaseous sulphur compounds is often necessary for corrosion control and health and safety reasons.

Sweet gas: Defined as natural gas without H2S and sulphur compounds.

Transmission pipelines: Networks of pipes that transport natural gas within provinces, across provincial borders or to the United States.