Natural Gas Facts

What is natural gas?

One fuel, many uses

Natural gas is one of Canada’s most important forms of energy, an essential part of our daily lives and a pillar of our economy. Its use makes economic, environmental and technological sense.

Versatility is the hallmark of natural gas. In Canada, it is now the leading source of heat for homes and businesses, and continues to be adopted by more and more homebuilders and enterprises each year. High-efficiency furnaces, water heaters, clothes dryers, stoves, fireplaces, barbecues, heat pumps and integrated heating-cooling devices also operate on natural gas. The use of natural gas to generate electricity is one of the fastest growing uses of this fuel.

Natural gas is a naturally occurring petroleum. Petroleum is the general term for solid, liquid or gaseous hydrocarbons. Hydrocarbons are a class of organic compounds consisting of only carbon and hydrogen — the basis of crude oil, natural gas and coal.

Natural gas is mostly methane (CH4), although it can occur in nature as a mixture with other hydrocarbons such as ethane (C2H6), propane (C3H8), butane (C4H10) and pentane (C5H12) and with other substances such as carbon dioxide, nitrogen, sulphur compounds and/or helium. Methane remains in a gaseous state at relatively low pressures, while ethane, propane, butane and pentane condense into liquids at different but relatively low temperatures and pressures. These condensed gases are known as natural gas liquids (NGLs). Natural gas containing more than one per cent hydrogen sulphide is known as sour gas and must be processed to remove the hydrogen sulphide before it can be used. Processing also removes most of the NGLs, condensate and non-energy components such that pipeline-ready natural gas is more than 95 per cent methane.

How is natural gas used?

Many factors contribute to the widespread use of natural gas as a fuel source. It is clean, efficient, convenient, safe, abundant and economical. Natural gas is an energy source for

Economic contribution of natural gas

Canada’s natural gas sector continues to expand, offering prospects for industrial development and increased government revenues. Together with the oil sector, it provides an estimated 750,000 direct and indirect jobs for Canadians. As well, the oil and gas industry invested $50 billion in 2007.

Since the federal and provincial governments hold most of the rights to minerals in Canada, oil and gas production companies must pay those governments an owner’s “royalty” as well as fees for land rentals and land sale bonuses. In 2007, this amounted to $24 billion.

Royalties are a significant source of revenue for provincial and territorial governments. This is particularly true in Alberta and British Columbia, the two largest natural gas producers, and in the Atlantic Provinces. Natural gas exploration and production are also on the rise in the Yukon Territory and the Northwest Territories. Additional reserves have been found in the Arctic Islands, most of which are now part of the territory of Nunavut.
The development of new gas supplies is important because demand is growing due to population growth and the resulting demand for natural gas as a source of energy. Demand is also increasing since gas has become the fuel of choice for generating electrical power. Not only is it highly efficient and cleaner than other energy sources, it is relatively easy to receive regulatory approval to build small gas-powered generating facilities around cities and towns.

How is natural gas formed?

There are two theories as to how natural gas is formed. The most widely accepted theory, the biogenic theory, maintains that natural gas formation begins with photosynthesis, where plants use energy from the sun to convert carbon dioxide and water into oxygen and carbohydrates. The remains of these plants and the animal forms that consume them are buried by sediment and as the sediment load increases, heat and pressure from burial converts the carbohydrates into hydrocarbons. Natural gas formation takes place in source rocks, usually fine-grained black shales. Continued pressure from burial forces the natural gas to migrate from source rocks into more porous and permeable rock such as sandstone and limestone, which, if overlain by impermeable strata such as shale, form reservoirs that contain the gas.

The other theory of natural gas formation, the abiogenic theory, speculates that hydrocarbons were trapped inside the earth as it formed and are migrating to the surface.
There are several types of traps.

In a reservoir containing more than one fluid, natural gas overlies oil which overlies water because of density stratification.

How is natural gas found?

Initially oil and natural gas exploration was as simple as locating surface seeps or places where oil and gas had been discovered accidentally while digging or drilling for water.

Today, exploration begins, in a previously undeveloped sedimentary basin, with aerial surveys to identify potential petroleum basins. Through satellite or airborne surveys, data regarding magnetic fields, gravity and radiation are collected and analyzed. As well, aerial photography and outcrop surveys are conducted. All of this data is used to confirm the presence of potential source, reservoir and cap rocks.
If available, a review of existing information is conducted, which may include academic and government studies in addition to well data.

Once the prospectivity of an area has been established, the next step is to run a seismic survey. Seismic is a relatively accurate and cost-effective way of modeling the earth’s subsurface. The seismic method involves transmitting acoustic energy into the earth and recording the energy reflected back from subsurface geological boundaries. The source of the acoustic energy can be dynamite detonated in a shallow drill hole, or vibrations generated by vibroseis trucks or, in the case of offshore seismic, by air guns towed behind a ship. The returning energy is collected by a series of geophones, or listening devices. By measuring the two-way travel time of the acoustic energy, a reasonable model of the subsurface can be defined. There are two primary types of seismic surveys – two-dimensional (2-D) and three-dimensional (3-D).

2-D seismic surveys

With 2-D seismic, the geophones are arranged linearly at regular intervals with the energy source points arranged along the same line at greater intervals. The resulting data is displayed as a two-dimensional vertical cross-section of the earth directly beneath the line.

3-D seismic surveys

With 3-D seismic, the survey is laid out as a grid, often with receiver lines running perpendicular to the energy source lines. The resulting data is displayed as a three-dimensional cube from which can be derived planes or cross-sections at almost any angle. 3-D surveys over the same area shot at different times form a 4-D survey that measures changes in reservoir fluids and is used in development activities.

If structures are identified that fit economic criteria established by the exploration company, wildcat wells are drilled. Information needed to evaluate the structure is obtained from cuttings or chip samples brought to surface by drilling mud, cores cut through prospective layers, and from wire line logs run after the well is drilled which measure permeability, porosity and fluid composition. Logging can also be conducted continuously while drilling using mud pulse and measurement-while-drilling technology. Drill stem tests actually sample the fluids from selected prospective strata. The final series of tests conducted on a well are flow tests, which measure the flow rate in barrels per day (bbls/d) for oil and thousands of cubic feet per day (Mcf/d) for natural gas. If all tests indicate an economical well, the next stage is to complete or ready the well for production.

Where is natural gas found?

Natural gas reserves are found in sedimentary basins throughout the world. They are classified as recoverable, probable, proved and established reserves.

How is natural gas produced?

Completing a well

The first step in completing a gas well is to install casing, tubular steel pipe that lines the hole to prevent water and rock from entering the wellbore and ensures control of the production. The casing is sealed against the side of the well by cement pumped down the inside of the casing and up the outside, between the casing and the wellbore. Production tubing is then hung inside the casing and kept in place by inflatable rubber packers. The production tubing is connected to the wellhead, a device that contains valves and chokes which control production rates.

The next step in completing a gas well is to perforate the casing so gas can flow into the production tubing. This is accomplished by lowering a perforating gun, a device with many explosive charges that fire metal rods through the casing and into the producing reservoir.

Gas reservoirs are usually under sufficient pressure to flow to surface. Where the wellhead pressure is less than pipeline pressure, compression may be required to increase the wellhead pressure.

Some wells may require stimulation either as part of the completion process or later on in the life of the well. Stimulation includes two processes. In acidizing a well, acids, such as hydrochloric acid in carbonate reservoirs and hydrofluoric acid in sandstone reservoirs, are pumped into the producing reservoir under pressure to dissolve reservoir rock and increase the number and size of channels carrying gas to the wellbore. Another type of stimulation is fracturing, where fluids such as water or carbon dioxide are pumped into the reservoir at sufficient pressure to fracture the rock. To prevent the fractures from closing, proppant is then introduced into the reservoir. Proppant comprises sand, ceramic beads or resin coated material that acts to prop open the new fractures and enhance gas flow to the wellbore.

Developing a natural gas field

Generally, more than one well is required to produce the recoverable gas from a reservoir. Gas wells in Canada are regularly spaced to conserve resources. In Alberta, the spacing is one gas well per section with the well drilled in the centre of the section. A section of land is roughly 256 acres.

Once the gas is brought to the surface, gathering systems bring it from individual wells to processing plants. Processed natural gas consists almost entirely of methane; however, natural gas in its unprocessed state consists of methane; NGLs such as ethane, propane and butane; pentanes, water, hydrogen sulphide and other gases such as carbon dioxide and nitrogen. Most of these components are removed from the natural gas either at processing facilities at the gas field or at straddle plants located on pipeline systems. The hydrogen sulphide is extracted in the form of elemental sulphur and is used in the manufacture of fertilizers and other products. The NGLs are sold separately for use as diluent in heavy oil processing, as feedstock for petrochemical plants or as fuel.

How is natural gas transported?

Approximately 95 per cent of Canada’s crude oil and natural gas is transported by pipeline. Canada’s pipeline network totals approximately 540,000 kilometres and comprises everything from thin plastic gathering lines to steel conduits more than one metre in diameter. In gas pipelines, pumps compress the natural gas up to 100 times atmospheric pressure to move the gas at speeds up to 40 kilometres per hour. Gas is carried from producing areas in British Columbia, Alberta and Saskatchewan to distribution systems throughout Canada and the United States. As well, pipelines on the east coast of Canada carry gas from offshore reservoirs to consumers in the Maritimes and northeast United States.

How is Natural Gas Marketed?

Natural gas pricing is based on supply and demand. Supply is dependent upon production, which in turn depends upon the natural decline of producing gas reservoirs and the amount of gas from newly developed reservoirs being brought on stream. Pipeline capacity is also a factor that affects supply. Because residential heating is a large market for natural gas, seasonal temperatures have a significant impact on pricing. As well, the prices of competing energy sources such as oil, coal and electricity affect pricing of natural gas.

The evolution of regulation

Natural gas regulations cover production, export and pricing of this commodity. Regulation began in Western Canada. In 1938, the Alberta government became the first jurisdiction in the country to establish a regulatory body for the crude oil and natural gas industry. Called the Natural Resources Conservation Board (now known as the Energy Resources Conservation Board (ERCB)), its regulations did not take effect until after the Second World War because of wartime need for Turner Valley petroleum.

In 1948, Alberta appointed a Natural Gas Commission to determine how much natural gas was surplus to Alberta’s needs. After much debate, the Commission said the province might be justified in refusing gas export licenses until the province had secured a 50-year supply for its own use. Alberta then gave authority to the Alberta Oil and Gas Conservation Board to decide what levels of reserves were necessary for energy security and to use that information to regulate exports. The Board set 25-year inventories (“reserves”) of gas as a pre-requisite for obtaining export licenses.

Price regulation

Prior to 1985, federal and provincial regulators were involved in establishing natural gas prices and in deciding how much gas could be exported. Regulators must still approve export licenses, but a 1985 agreement between the federal government and the producing provinces determined that the market should set prices. This agreement on natural gas markets and prices enables the National Energy Board (NEB), a federal regulatory body, to allow the free market system to determine prices.

The NEB’s application of this policy provides producers with sufficient incentive to ensure adequate supplies of gas and yields the best possible price for consumers. However, provincial authorities ensure that local distribution companies pass their natural gas costs on to consumers without marking them up, and that they buy gas prudently on behalf of consumers.

Production regulation

Today, the ERCB regulates exploration, production, processing, transmission and distribution of natural gas within Alberta. In addition, the ERCB and Alberta Environment jointly manage environmental matters related to the industry. In most other provinces, public utility and energy boards like British Columbia’s Oil and Gas Commission and the Ontario Energy Board oversee local distribution companies while provincial energy ministries or other governmental agencies oversee exploration and production.

In Canada’s territories and offshore areas, the NEB is the main regulatory authority. Established in 1959, the Board consults with other federal, provincial, territorial or local authorities. The NEB also regulates the construction and operation of interprovincial and international pipelines, tolls and tariffs of pipelines under its jurisdiction and the import and export of natural gas. In addition, the Canada-Nova Scotia Offshore Petroleum Board (C-NSOPB) regulates exploration and development off Nova Scotia, while the Canada-Newfoundland Offshore Petroleum Board (C-NOPB) provides a similar function for Canada’s most easterly offshore reaches.

Competitive pricing and greater choice

The change to market-determined pricing of natural gas created greater competition, especially in the 1990s. The most striking example of this change comes from Ontario where 40 per cent of the province’s gas customers (residential, commercial, industrial and institutional) now obtain their supplies through direct purchases from agents, brokers and marketers.

Competition in the gas industry has also been aided by legislation such as Ontario’s Energy Competition Act (1998), which laid the foundation for competition in the electricity market. The Act established that the Ontario Energy Board would regulate electricity distribution and transmission, the monopolistic components of the industry. In effect, this legislation has had a profound impact on energy marketing. It encouraged the creation of companies that offer their customers one-stop shopping for natural gas and electricity, and thereby changed the way conventional energy companies do business.

The idea behind such deregulation is simple. If competition increases at the retail level, residential and commercial energy consumers will benefit through competitive prices and services and greater choice. This approach illustrates a major trend in North America: there is more competition for the energy consumer’s dollar as increasingly sophisticated companies begin marketing energy (not just natural gas) to consumers. As the Ontario example suggests, much of this competition reflects a commitment by provincial governments to eliminate a portion of the monopoly power over markets historically held by utilities.

The continental natural gas marketplace

Because an intricate network of pipelines makes it quite easy to ship natural gas from buyer to buyer, natural gas is a widely-traded commodity in North American markets. Those markets are becoming increasingly more integrated as gas supplies from several large producing regions compete with each other for buyers. Consequently, the commodity price of natural gas (before transportation costs) is essentially the same everywhere in North America.

Price differences still exist to some degree, reflecting the fact that certain fixed costs vary by region. Costs related to production, shipment by pipeline, storage, distribution, and consumer taxes can all make a difference. Pipeline transportation is a significant cost for natural gas – much more than for liquids such as oil and gasoline.

How is natural gas distributed?

Natural gas is delivered to Canadian consumers by provincially regulated utilities called local distribution companies. These companies construct, own and operate the pipelines that carry the gas from the city gate to the end user. They charge only for the cost of delivery and do not profit from the gas they deliver.

Local distribution companies operate more than 237,000 kilometres of pipelines in Canada. Rural Alberta gas co-operatives operate another 66,000 kilometres. These pipelines range from high-pressure main distribution lines up to 61 centimetres in diameter to low-pressure, 2.5-centimetre steel or plastic tubing used in residential service lines.

Natural gas timeline




The Chinese use crude bamboo pipelines to harness natural gas from surface seeps to light temples and distill seawater.


French explorers witness indigenous people igniting surface seeps near Lake Erie.


William Hart digs first actual natural gas well near Fredonia, New York. The well was dug 27 feet into a creek to harvest gas seeping to the surface. The gas was piped through hollow logs to Fredonia to fuel street lamps.


“Colonel” Edwin Drake completes the first oil well drilled in North America. Natural gas from the well is piped five and one half miles to Titusville Pennsylvania.

Natural gas is discovered in New Brunswick.


Natural gas is found in southwestern Ontario.


A Canadian Pacific Railway crew discovers natural gas near Medicine Hat while drilling for water.


Robert Bunsen invents the Bunsen burner, the first device to mix and burn natural gas and air in the proper proportions for safe, controlled heating and cooking.


Eugene Coste begins drilling natural gas wells in Essex County, Ontario.


Coste drills a successful natural gas well near Niagara Falls, Ontario and ships natural gas to Buffalo, New York.

The Village of Medicine Hat begins drilling natural gas wells to supply fuel for cooking, heating and lighting.


Coste exports Essex County natural gas to Detroit, Michigan


The first commercial gas field is discovered in Medicine Hat, Alberta.

The Ontario government bans the export of natural gas.


Coste moves to Western Canada to explore for and develop natural gas fields in southern Alberta. Natural gas is discovered at Cessford, Alberta and Suffield, Alberta


Coste makes a significant natural gas discovery at Bow Island, Alberta.


Coste builds a 270-kilometre pipeline from Bow Island to Calgary, Alberta and replaces coal gas with natural gas.


The City of Edmonton switches to natural gas sourced from a field near Viking, Alberta.


Natural gas is discovered in Alberta at Westerose South (1954), Elmworth (1955), Crossfield (1956), Brazeau River and Waterton (1959) and in British Columbia at Clarke Lake (1959).


TransCanada completes gas pipeline from Alberta to Ontario and Quebec.


Natural gas is discovered in Alberta at Kaybob South (1961), Edson (1962) and in British Columbia at Yoyo (1962) and Sierra (1965). Shell discovers gas off Sable Island, Nova Scotia in 1967.


Imperial Oil discovers Taglu gas field in McKenzie Delta (1971). Other discoveries are made at Parsons Lake North in the Mackenzie Delta/Beaufort Sea area of Canada’s Northwest Territories and at Thebaud, offshore Nova Scotia (1972), at Cranburg, Alberta (1974) and at Venture, offshore Nova Scotia (1979).


Natural gas is discovered at Parsons Lake North in the Mackenzie Delta/Beaufort Sea area of Canada’s Northwest Territories, and at Thebaud, offshore Nova Scotia.


The National Energy Program is announced in Canada.


Natural gas is discovered at Issungnak in the Mackenzie Delta/Beaufort Sea area of Canada’s Northwest Territories (1980), and in Alberta at Hamburg, Slave Point (1983) and at Caroline (1986).


The federal government and producing provinces sign The Western Accord, committing to deregulation in the natural gas industry.


On November 1, deregulation of natural gas pricing and marketing takes effect.


Natural gas is discovered at Sable Island, Nova Scotia (1995) and at Fort Liard, Northwest Territories (1997).

2000 and on

Natural gas is discovered in British Columbia at Ladyfern (2000) and at Greater Sierra and Monkman (2002).

Natural Gas Pricing in Canada

The Canadian and U.S. natural gas markets form an integrated network comprising thousands of kilometres of pipelines that transport large volumes of natural gas over long distances, from producing areas to consumers. Any changes in transportation costs, infrastructure constraints or weather in one region, in addition to having significant local impacts, can also have effects on other regions. Examples of this include price increases due to hurricanes in the Gulf of Mexico impacting natural gas production and pipeline disruptions impacting natural gas deliveries.

Figure 1 summarizes the production, consumption, exports and imports of natural gas in 2006.
Natural gas production is fairly consistent year round, but demand usually peaks in the winter because of increased heating needs. Natural gas storage near the markets helps to better manage supply and demand during seasonal fluctuations. Storage allows production levels and pipeline volumes to remain fairly constant and respond effectively to sudden changes in demand. Acting as a buffer between production and consumption, storage reduces transportation costs. In Canada, the majority of natural gas storage is split between Ontario and Alberta.

The natural gas industry reaches its customers through local distribution companies (LDCs). They receive gas from pipelines and deliver it to customers’ homes, offices and businesses, within a franchise area. The LDCs are regulated by provincial regulatory boards or commissions. In some cases the LDC is directly owned by the provincial governments.

The Canadian industry

Natural gas represents approximately one quarter of all energy consumed in Canada. In 2006 alone, consumption amounted to 226 million cubic metres per day (8.0 billion cubic feet per day). The main uses include space heating of residential and commercial buildings, process heating in the industrial sector, generating electricity. Components of natural gas are also used as non-energy raw materials processed by the petrochemical industry.

Natural gas production mostly comes from areas following the continental divide, from the Gulf of Mexico to the Northwest Territories. Canada produced about 25 per cent of the combined natural gas production of Canada and the U.S. in 2006. Almost 98 per cent of Canadian natural gas is produced from the Western Canada Sedimentary Basin (WCSB). Alberta is the largest producer with roughly 77 per cent while British Columbia and Saskatchewan contribute roughly 16 and 4 per cent, respectively, of the total from the WCSB.

About 47 per cent of Canadian production is consumed within Canada. The remainder is exported to the United States. Natural gas exports in 2006 supplied about 16.5 per cent of estimated U.S. consumption. The U.S. central/midwest and northeast regions historically receive the greatest portion of Canadian exports. Approximately 26.4 million cubic metres per day (0.9 billion cubic feet per day) of natural gas was imported into Ontario from the U.S. in 2006.


Three components make up the bulk of the price of natural gas services: the cost of the natural gas (known as the commodity cost), the pipeline transportation cost and the distribution cost. Transportation and distribution costs are usually regulated by government agencies and have little variation over time. A large part of the final cost to consumers is the commodity cost; however, consumer’s located great distances from producing areas may pay larger transportation costs. Because the commodity cost follows market prices it is usually more volatile.

There are many trading and pricing points for natural gas in North America. The Henry Hub is one such point primarily because it lies at the junction of numerous pipelines in Louisiana and is the pricing point for natural gas traded on the New York Mercantile Exchange (NYMEX). Many natural gas market transactions (contracts and pricing) in North America are based on the price at Henry Hub.

The AECO-C hub in southeast Alberta and the Dawn hub in Ontario are the main Canadian pricing points, again because they are points where natural gas delivery, storage, and trading converge.

Commodity Cost

The Ontario Energy Board, Alberta, British Columbia, Saskatchewan and the federal government signed “The Agreement on Natural Gas Markets and Prices,” in 1985. This agreement essentially deregulated the price of the natural gas commodity and allowed end-users to purchase natural gas directly from producers.

Consequently, the commodity cost for natural gas is negotiated on the market. At any given day and time, the commodity cost will vary depending on various contract terms including volume being traded, delivery date, and length of contract. As with any other commodity, the price will increase or decrease depending on supply and demand conditions. Prices usually increase in winter when demand, driven by the impact of cold weather, is greater while summer sees demand and price decrease given the much lower requirements for heating purposes.

Natural gas well drilling and completions and natural gas available in storage are the two main factors influencing supply. Demand is usually affected by factors such as level of economic activity, weather, and cost and availability of substitutes such as fuel oil. However, weather is the largest single factor affecting natural gas demand and is also the most difficult to predict.

Provincial energy regulations require that the commodity price charged to customers by a local distribution company be equal to their cost of acquiring the natural gas supplies and not include any mark-up. Each provincial regulator establishes the rules over the management of final cost to consumers including how to deal with commodity price volatility, use and structure of long term fixed price purchase contracts, the use of hedging or deferral accounts, adjustments for weather, and other cost elements.

Natural gas is an attractive fuel in the power generation market because of it low emissions profile relative to other fossil fuels (such as coal), its flexibility and availability on an as needed basis by pipeline, and the low capital cost.

Figure 2 shows the volatility of natural gas prices in recent years. Since 2001, North American natural gas supply growth has not kept pace with growth in demand, contributing to high and volatile prices. Because some consumers can switch between natural gas and fuel oil, an increase in crude oil prices will generally result in an increase in the price of natural gas. In general natural gas trades towards the lower end of the fuel oil price range, bounded at the bottom by residual fuel oil (RFO), and at the top by distillate fuel oil.

Typically, the commodity price accounts for between 49 per cent and 76 per cent of a residential gas bill, depending on proximity to the source of gas. For example, in Alberta, the commodity charge is about 76 per cent of the bill, however, in Quebec, the commodity charge makes up 49 per cent of the bill.

Pipeline transportation costs

Pipeline transportation or transmission costs basically cover the tolls and tariffs for using pipelines from the producing basins in Western Canada and offshore to local distribution systems. Interprovincial and international pipeline transportation is regulated by the National Energy Board (NEB). Public hearings and/or negotiations between pipeline companies and shippers determine the tolls and tariffs.

The NEB must approve these negotiated settlements after it concludes the tolls are just and reasonable and that there is no undue discrimination in services. Pipeline transportation costs are usually stable from year to year but they vary significantly depending on distance from the supply source.

Distribution costs

Distribution costs cover the delivery of natural gas through the local distribution company network to the consumer. Distribution charges would usually encompass maintenance and operation costs of the distribution systems, customer service costs, gas measurement and gas storage costs, and the cost of financing for the LDC either from the bond market or through the equity markets (return on equity).

Provincial regulators hold hearings to oversee the various charges to ensure that customer’s rates charged by local distribution companies are just and reasonable. Distribution rates are usually set once a year and remain relatively stable from year to year.


While the physical development of natural gas storage facilities is regulated, the price charged for natural gas storage in Canada may or may not be regulated depending on the specific regulatory decisions at the provincial level.

Today, natural gas storage rates in Alberta are not regulated, and providers negotiate rates with their customers on a contract-by-contract basis. An exception to this is the carbon facility owned by ATCO Gas. Independent storage providers, such as ATCO, negotiate with customers on a contract-by-contract basis. ATCO Gas prices its storage at cost-of-service rates to its utility customers and the utilities are able to charge cost-based rates to their customers. Utilities can market any additional capacities at market-based rates.
Reflecting a recent OEB decision some natural gas storage rates in Ontario are regulated by the Ontario Energy Board.

The utility companies, (Enbridge Gas Distribution Inc. and Union Gas Limited) price the certain heritage storage capacity at cost-of-service rates while newly developed and so-called ex-franchise storage capacity over and above their utility customer needs is priced based on competitive market dynamics.
Natural gas storage in British Columbia is not regulated, so all available storage capacity is marketed at market-based rates.

In Saskatchewan, natural gas storage is wholly-owned by a subsidiary of the Provincial Crown. Storage rates are not formally regulated but rates are based on cost-of-service.