Oil and Gas Journal (OGJ) reports that Canada had 57.9 trillion cubic feet (Tcf) of proven natural gas reserves in January 2008. The country produced 6.5 Tcf of natural gas in 2006, while consuming 3.3 Tcf. The country is the second largest producer of natural gas in the Western Hemisphere, after the United States. Canada is an important source of the U.S. natural gas supply. In 2006, it exported 3.6 Tcf of natural gas to the United States, representing 86 percent of total U.S. natural gas imports that year. Most Canadian natural gas exports enter the U.S. through pipelines in Idaho, Montana, North Dakota, and Minnesota.

Like the oil industry, Canada’s natural gas production is concentrated in the WCSB, particularly in Alberta. Even though there have been some new conventional natural gas finds in the WCSB, many analysts predict that conventional natural gas production in the WCSB has reached its zenith. Future natural gas production could center on coal bed methane (CBM) deposits in the WCSB, Arctic frontier natural gas deposits, the Deep Basin area, and offshore natural gas fields.

The WCSB includes most of Alberta and parts of British Columbia, Saskatchewan, and Manitoba. Natural gas production in the WCSB grew rapidly in the 1990s, increasing over 60 percent during the decade. Alberta contains around 80 percent of Canada’s total natural gas production. Additional production in the WCSB has begun to move away from Alberta towards new discoveries in British Columbia. There is also a small amount of natural gas production in the portion of the WCSB in Saskatchewan and Manitoba.

The Scotian Basin, off the coast of Nova Scotia, is the center of natural gas production on the Atlantic coast. 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).

Offshore oil operators in Newfoundland predict that they could also produce sizable natural gas volumes from their reserves. The Hibernia and White Rose fields contain a combined 4 Tcf in recoverable natural gas reserves. Though there is no current natural gas production at either site, but both ExxonMobil (Hibernia) and Husky Energy (White Rose) have stated that they could commence natural gas production in the future. The offshore basins in British Colombia contain an estimated 43.4 Tcf of total natural gas reserves, though the previously-mentioned federal moratorium on drilling prevents any production activity in the area.

The Mackenzie Delta, located in the Northwest Territories, holds an estimated 5-6 Tcf of recoverable natural gas reserves. Natural gas from the region could begin flowing to southern markets, if natural gas companies can complete the Mackenzie Gas Pipeline on schedule (see below). There are three large, proven natural gas fields in the Mackenzie Delta: Imperial Oil’s Taglu field (3 Tcf); ConocoPhillips’ Parsons Lake field (1.8 Tcf); and the joint Shell Canada-ExxonMobil Niglintgak field (1 Tcf).

CBM production is still in its infancy in Canada, with the first wells drilled only in 1997. There is a strong belief that CBM production will eventually replace some of the decline in conventional natural gas production. According to the Alberta Geological Service, there could be as much as 500 Tcf of CBM gas in place in Alberta alone. Shale gas is another potential source of unconventional natural gas production in Canada that is still in the early stages of development: according to industry sources, the Montney shale formation in British Columbia could contain 50 Tcf of shale gas.

Canada has continued to produce natural gas faster than it replenishes its reserves. Canada’s production/reserves ratio (the number of years of proven reserves remaining at existing production levels) has declined from 35 years in 1985 to 9 years in 2006. Along with falling production, demand for natural gas is expected to rise, driven by the oil sands industry and the power sector. According to Ziff Energy Group, natural gas demand by the oil sands industry could rise from 1 Bcf/d in 2007 to 2.8 Bcf/d in 2015. The combination of falling production and rising domestic consumption could impact Canadian natural gas exports to the United States: according to Ziff Energy Group, Canadian natural gas exports to the U.S. could fall to 5 Bcf/d by 2015, versus 9.9 Bcf/d in 2007.

TransCanada Pipelines is the largest operator of natural gas pipelines in Canada. Its 25,600-mile network transports the bulk of Canada’s natural gas production. Important parts of the TransCanada network include the 13,900-mile, 10.6-Bcf/d Alberta System, the 120-mile, 0.9-Bcf/d British Columbia System, the 8,900-mile, 7.2-Bcf/d Canadian Mainline, and the 600-mile, 3.0-Bcf/d Foothills System.

A consortium of natural gas companies, led by Imperial Oil, plan to build the Mackenzie Valley natural gas pipeline. The 760-mile, 1.2-Bcf/d pipeline would carry natural gas from inside the Arctic Circle to northern Alberta, where it would flow into the existing natural gas transportation system; there would also be a parallel pipeline to carry NGLs. Cost estimates have increased to a $17 billion, with a potential in-service date of 2014.

Canada’s natural gas pipeline system is highly interconnected with the United States. The 1,300-mile, 1.9-Bcf/d Gas Transmission Northwest pipeline runs from the British Columbia-Idaho border to the Oregon-California border, connecting TransCanada’s western Canadian network to the U.S. domestic market. The 2,000-mile, 2.4-Bcf/d Great Lakes Gas Transmission pipeline runs from Emerson, Manitoba to St. Clair, Ontario, servicing Minnesota, Wisconsin, and Michigan. Running from the New York-Canada border to Long Island, the 400-mile, 0.9-Bcf/d Iroquois Gas Transmission System pipeline serves natural gas distribution networks in New York State. The 280-mile, 0.2-Bcf/d Portland Natural Gas Transmission System distributes natural gas from Quebec to greater New England. The 780-mile, 650-MMcf/d Maritimes and Northeast Pipeline transports natural gas from Canada’s Atlantic natural gas fields to Dracut, Massachusetts, where it interfaces with the U.S. domestic network.

Alliance Pipeline Limited, a partnership of Enbridge and the Fort Chicago Energy Partners income fund, operates the 970-mile, 1.3-Bcf/d Alliance pipeline from Gordondale, Alberta to the Saskatchewan-Montana border. Its U.S.-based partner company operates the U.S. portion of the pipeline, which runs 890 miles into Illinois.

To compensate for reduced domestic production, Canadian natural gas companies have begun to explore the construction of liquefied natural gas (LNG) receiving terminals. Natural gas companies either could sell re-gasified LNG on the domestic market or re-export it to the United States. In total, there are seven LNG regasification projects in Canada at various stages of development, including one in Nova Scotia, one in New Brunswick two in British Columbia, and three in Quebec,. These projects represent a combined 4.9 Bcf/d of regasification capacity, though the Canaport LNG project is the only one under construction.

Proposed LNG Receiving Terminals in Canada
Name	Location	Status	Initial Capacity
Maple LNG	Nova Scotia	Pending Initial Construction	1.0 Bcf/d
Bear Head LNG	Nova Scotia	Cancelled	1.0 Bcf/d
Canaport LNG	New Brunswick	Under Construction	1.0 Bcf/d
Grassy Point	Newfoundland	Pending Regulatory Review
Kitimat LNG	British Colombia	Pending Initial Construction	600 MMcf/d
Prince Rupert	British Colombia	Pending Regulatory Review	300 MMcf/d
Gros Cacouna	Quebec	Suspended	500 MMcf/d
Rabaska LNG	Quebec	Pending Initial Construction	500 MMcf/d
Grande-Anse	Quebec	Proposed	1.0 Bcf/d

In New Brunswick, Canaport LNG, a consortium of Irving Oil and Repsol-YPF, began construction of a 1 Bcf/d LNG terminal at Canaport in September 2005, with estimated costs of the project at $750 million. The Canaport project will provide natural gas for Irving Oil’s refinery in St. John and local power plants. However, the project will also feature a connection to the Maritimes & Northeast Pipeline, facilitating exports to the United States. Canaport LNG estimates the project onstream in late 2008.

In 2006, a consortium led by Netherlands-based 4Gas purchased the Maple LNG project, a planned LNG terminal in Nova Scotia. The Maple LNG terminal could feed domestic customers or export natural gas to the United States through the Maritimes & Northeast Pipeline. The project has received environmental approval and is now reportedly seeking suppliers. According to 4Gas, the project could come onstream in 2010, with an initial send-out capacity of 1.0 Bcf/d. Keltic Petrochemicals plans to develop an adjacent petrochemicals plant.

Newfoundland LNG has proposed to build an LNG receiving terminal at Grassy Point in Placentia Bay. The project is reportedly still in the regulatory process.

WestPac Terminals has proposed the construction of an LNG terminal at Prince Rupert, with initial send-out capacity of 300 MMcf/d. The company has reportedly secured financing for preliminary engineering and environmental review of the project. Galveston LNG received approval from federal and provincial authorities in early 2007 to build its LNG terminal in Kitimat. According to media reports, the company is still searching for LNG suppliers for the project.

Petro-Canada and TransCanada Pipelines proposed to build a 500-MMcf/d LNG receiving terminal at Gros Cacouna, on the St. Lawrence River. According to industry sources, the project has been suspended, due to an inability to secure LNG supplies. A consortium of Enbridge, Gas Metro, and Gaz de France has proposed another project in the province, the Rabaska LNG terminal. Located in Levis, the Rabaska LNG project would have an initial send-out capacity of 500 MMcf/d with a potential in-service date of 2010. This project is now reportedly seeking supply contracts. Finally, Energia Grande-Anse has proposed to build an LNG receiving terminal along the Saguenay River in Quebec. That project is still in the preliminary stages of development.