Natural Gas Statistics Cannada

Oil and Gas Journal (OGJ) reports that Canada had 57.9 trillion cubic feet (Tcf) of proven natural gas reserves in January 2009. The country produced 6.6 Tcf of natural gas in 2007, while consuming 3.3 Tcf. Canada is the second largest producer of natural gas in the Western Hemisphere, after the United States. Canada is also an important source of the U.S. natural gas supply; in 2008, it exported 3.6 Tcf of natural gas to the United States, representing 16 percent of U.S. natural gas consumption and 90 percent of total U.S. natural gas imports that year. Most Canadian natural gas exports enter the United States 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 will likely center on coal bed methane (CBM) and shale gas deposits in the WCSB, Arctic frontier natural gas deposits, the Deep Basin area, and offshore natural gas fields.

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, 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 possible 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. Another promising area of future development is the Utica shale in Quebec.

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. The federal panel charged with evaluating the environmental and social impact of the project planned to release its final report by the end of 2009.

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.

Canadian natural gas companies have begun to explore the construction of LNG receiving terminals as a way to deal with perceived future supply shortfalls. Natural gas companies either could sell re-gasified LNG on the domestic market or re-export it to the United States. One project has already come onstream and several others are in various stages of the development process (see table). Some projects have also been suspended due to changing market factors. In addition, there has also been one LNG liquefaction terminal proposed, which would allow Canada to export LNG to the world market.

Proposed LNG Receiving Terminals in Canada
Name	Location	Status	Initial Capacity
Canaport LNG	New Brunswick	Operating	1.0 Bcf/d
Maple LNG	Nova Scotia	Pending Initial Construction	1.0 Bcf/d
Grassy Point	Newfoundland	Suspended
Texada Island	British Colombia	Pending Regulatory Review	500 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 initial operations at its 1.2-Bcf/d terminal in June 2009. The terminal was the first operating LNG receiving terminal in the country. The Canaport project will provide natural gas for Irving Oil’s refinery in St. John and local power plants. The project also has a connection to the Maritimes & Northeast Pipeline, facilitating potential exports to the United States.

Netherlands-based 4Gas is developing 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 initial environmental approval. According to 4Gas, the project would have an initial send-out capacity of 1.0 Bcf/d.

Newfoundland LNG has proposed to build an LNG receiving terminal at Grassy Point in Placentia Bay. In 2008, the project received environmental approval from the Canadian government. According to media accounts, the project was suspended in June 2009.

WestPac Terminals has proposed the construction of an LNG terminal at Texada Island, with initial send-out capacity of 500 MMcf/d. The project would also include an integrated, gas-fired power plant. According to media reports, the project is still seeking regulatory approval.

Petro-Canada and TransCanada Pipelines proposed to build a 500-MMcf/d LNG receiving terminal at Gros Cacouna, on the St. Lawrence River. The project was suspended indefinitely in late 2008. 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. According to media sources, the project has received all regulatory approvals and is seeking LNG suppliers. 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.

In late 2008, Kitimat LNG announced that it would shelf its planned LNG receiving terminal and would instead develop an LNG export terminal on the proposed site. The project would have a production capacity of 5 million metric tons per year and include a 300-mile natural gas pipeline to provide source gas for the terminal