Energy profile of Canada
|
Introduction
Canada is the United States’ most important trading partner, with over $450 billion worth of goods, services, investments, and financial transfers exchanged between the two countries in 2004. Canada and the U.S. also enjoy an interdependent energy relationship, trading oil, natural gas, coal, and electricity. Canada has experienced sustained economic growth during the past several years; its real gross domestic product (GDP) grew at a rate of 2.9 percent in 2005, the same as in 2004. Continuing economic recovery in the United States and higher prices for Canada’s natural resource exports have driven Canada’s economic growth in recent years.
Canada has considerable natural resources and is therefore one of the world’s largest producers of energy. In 2003, Canada produced 18.4 quadrillion British thermal units (Btu) of total energy, the fifth-largest amount in the world. Of this total, Canada consumed 13.5 quadrillion Btu in 2003. Since 1980, Canada’s total energy production has increased by 80 percent, while its total energy consumption has increased only by 40 percent. Almost all of Canada’s energy exports go to the United States, making it the largest foreign source U.S. energy imports.
Oil
Canada’s total oil production (including all liquids) was 3.1 million barrels per day (bbl/d) in 2005, while the country consumed 2.3 million bbl/d that year. The country's oil production has been increasing since 1999, as new oil sands and offshore projects have come on-stream to replace aging fields in the western provinces. Overall, analysts predict that oil sands production will increase significantly in coming years and offset the decline in Canada’s conventional crude oil production.
According to Oil and Gas Journal (OGJ), Canada had a reported 178.8 billion barrels of proven oil reserves as of January 2006, second only to Saudi Arabia. However, the bulk of these reserves (over 95%) are oil sands deposits in Alberta. The inclusion of oil sands in official reserve estimates is not without controversy, because oil sands are much more difficult to extract and process than conventional crude oil.
Canada sends over 99 percent of its crude oil exports to the U.S., and it is one of the most important sources of U.S. oil imports. During the first eleven months of 2005, Canada exported 1.6 million bbl/d of crude oil to the U.S., the single-largest source of U.S. crude oil imports. Canada also sent some 520,000 bbl/d petroleum products to the U.S. during this period, the most from a single country. The largest share of U.S.-bound Canadian oil exports go to the Midwest (PAD District II), with smaller amounts heading to the Rocky Mountains (PAD District IV) and the East Coast (PAD District I).
Sector Organization
Canada has a privatized oil sector that has witnessed considerable consolidation in recent years. The largest integrated operator in the country is Imperial Oil, majority owned by ExxonMobil. In 2002, Alberta Energy Company and PanCanadian Energy merged to create EnCana, Canada’s largest independent upstream operator. Other significant oil producers in Canada include Talisman Energy, Suncor, EOG Resources, Husky Energy, and Apache Canada. U.S. companies maintain a sizable presence in the Canadian oil industry.
The Canadian government formed Petro-Canada in 1975 in an effort to reduce the dominance of U.S. companies in Canada’s oil industry. The company received considerable initial resources from the Canadian government in its early years, though critics accused Petro-Canada of inefficiently deploying those resources and interfering with the operations of private companies. In 1991, the Canadian government began to privatize Petro-Canada, and in late 2004, the government sold its remaining 20 percent stake in the company.
Exploration and Production
Canadian oil production comes mainly from three different sources: the Western Canada Sedimentary Basin; the oil sands deposits of northern Alberta; and offshore fields.
Western Canada Sedimentary Basin (WCSB)
The WCSB, underlying most of Alberta and parts of British Columbia, Saskatchewan, Manitoba and the Northwest Territories, has been the main source of Canadian oil production for the past 50 years. The age of many of the fields, though, has led to a steady decline in conventional oil production in the WCSB. Analysts predict that oil sands will completely supplant conventional sources as the focus of future oil production in western Canada.
Oil Sands
Oil sands contain deposits of bitumen, a heavy, viscous oil. There are two methods currently used to extract bitumen from the ground: open-pit mining and in situ (Latin for “in place”). Open-pit mining resembles conventional mining techniques and is effective in extracting oil sands deposits near the surface. However, the bulk of Canada’s estimated oil sands deposits (80 percent) are too deep below the surface to use open-pit mining. The second method, in situ can reach these deeper deposits. In situ extraction involves the use of steam to separate bitumen from the surrounding sands and lift it to collection pools near the surface. To date, Canadian oil sands producers have employed each method almost equally, but future production will likely shift to emphasize in situ extraction. Once extracted, oil sands producers must add lighter hydrocarbons to the bitumen to allow it to flow through pipelines. Upgraders then process the bitumen into “synthetic crude.” Some oil sands projects have integrated upgrading capacity, while others must send their raw bitumen production to another facility.
The Athabasca oil sands deposit, in northern Alberta, is one of largest oil sands deposits in the world. There are also sizable oil sands deposits on Melville Island in the Canadian Arctic, and two smaller deposits in northern Alberta near Cold Lake and Peace River.
All of the largest oil sands projects in the Athabasca area utilize open-pit mining. The Syncrude Project, operated by Canadian Oil Sands Limited, produced 280,000 bbl/d in 2004. The Suncor’s project has a total production capacity of 280,000 bbl/d, though a fire in 2005 caused a prolonged shutdown of the operation, with 2005 production averaging only 171,000 bbl/d. The Athabasca Oil Sands Project (AOSP), operated by Shell Canada, began production in 2002 and currently has a capacity of 155,000 bbl/d. AOSP suffered from a fire in January 2003 that shut production down for three months.
The in situ oil sands projects in the Athabasca area are smaller than their mining counterparts. In 2004, Suncor began operations at its Firebag project, which utilizes a relatively new in situ technology called steam-assisted gravity drainage (SAGD). Firebag had a production capacity of 35,000 bbl/d in 2005. Other SAGD projects include Petro-Canada’s MacKay River (30,000 bbl/d) and Dover (1,400 bbl/d); EnCana’s Foster Creek (40,000 bbl/d), and Christina Lake (10,000 bbl/d); and Nexen’s Athabasca (1,300 bbl/d) and Long Lake (2,500 bbl/d). Petro-Canada’s Dover facility also contains a demonstration project of a new in situ technology called vapor extraction (VAPEX). VAPEX utilizes solvents, such as butane, to extract raw bitumen, rather than steam, which could allow significant cost savings for in situ operators.
The Athabasca deposit is also the focus of most planned expansions of the oil sands industry. Major projects scheduled for start-up in 2006-2007 include ConocoPhillips’ Surmount (25,000 bbl/d) and Total’s Joslyn (10,000 bbl/d). Petro-Canada plans to bring 50,000 bb/d of mining capacity online by 2009 at its Fort Hills oil sands project In February 2005, Canadian Natural Resources Limited (CNRL) decided to pursue its $11 billion Horizon project, which could produce 212,000 bbl/d by 2012.
Outside of the Athabasca deposit, the largest oil sands project is Imperial Oil’s Cold Lake in situ facility, with a capacity of 140,000 bbl/d. Also in the Cold Lake area, CNRL operates Primrose (50,000 bbl/d), while Husky plans to bring its 30,000-bbl/d Tucker project online in 2006. In the Peace River deposit, Shell Canada operates Cadotte Lake (11,000 bbl/d).
Despite the considerable excitement surrounding the development of Canada’s oil sands reserves, there are still several difficulties that could impede the future development of the industry. Analysts predict that the production of synthetic crude from oil sands is only economically viable with synthetic crude prices in the $30 per barrel range. While further advances in oil sands technology could reduce production costs, it is likely that economical synthetic oil production will continue to be dependent upon high crude oil prices. Second, the oil sands industry is heavily reliant upon water and natural gas, which is necessary in both the extraction of bitumen from oil sands and the upgrading of bitumen to synthetic oil. Even though there have been some efforts to reduce this dependence on natural gas, any increase in natural gas prices or sharp reduction in natural gas supply would have critical repercussions for the oil sands industry. Finally, there have been reports that the oil sands boom is creating a labor shortage in Alberta’s oil industry, especially in Fort McMurray. This has led to an escalation in labor costs and construction delays due to a lack of available workers.
In light of these concerns, most forecasts of world oil markets estimate that Canadian oil sands will become an increasingly important component of world oil supply. The Energy Information Administration's International Energy Outlook (IEO) estimates that Canadian oil sands operators will produce 3.5 million bbl/d of synthetic crude by 2025.
Offshore
Canada has three oil projects off its Atlantic coastline, all located in the Jeanne d’Arc Basin: Hibernia, Terra Nova, and White Rose. First discovered in 1979, the Hibernia field produced 204,000 bbl/d of crude oil in 2004. Production at Terra Nova began in 2002 and averaged 110,000 bbl/d in 2004; in June 2005, Petro-Canada, the majority owner of the field, sought regulatory approval to expand production at the field to the Far East reservoir, which contains an additional 40 million barrels of recoverable oil. Finally, Husky Energy brought the White Rose field onstream in late 2005, where production will eventually reach 90,000 bbl/d.
There is also exploration activity in the Orphan Basin, located in the deep waters north of the Jeanne d’Arc Basin. However, operators at the Atlantic oil fields must contend with harsh natural conditions, including rough seas, seasonal icebergs, and extreme temperatures. These factors increase the difficulty and costs of oil production in the region.
Industry experts believe that the Pacific coast off British Columbia also contains significant oil reserves. However, there has been no production to date on the Pacific coast because of a federal ban on offshore oil activities in the Pacific Ocean. The provincial government of British Columbia has continually lobbied to lift this ban, hoping to begin production by 2010.
Pipelines
Domestic System
An extensive pipeline system transports western Canadian oil to domestic and U.S. markets. There are two major oil pipeline operators in Canada: Enbridge Pipelines and Kinder Morgan Canada (formerly Terasen). Enbridge operates a 9,000-mile network of pipelines and terminals, delivering oil from Edmonton, Alberta, to eastern Canada and the U.S. Great Lakes region. Kinder Morgan operates the Trans Mountain Pipe Line (TMPL), which delivers oil mainly from Alberta west to refineries and terminals in the Vancouver, British Columbia area.
The expansion of Alberta’s oil sands industry has necessitated the construction of several new pipelines to transport diluted bitumen and synthetic crude to downstream facilities in the Edmonton area. In 1999, Enbridge completed construction of its 920-mile, 570,000-bbl/d Athabasca pipeline, which links Suncor’s oil sands operations to Enbridge’s terminal in Hardisty, Alberta. Kinder Morgan operates the 280-mile, 260,000-bbl/d Corridor pipeline linking oil sands production near Muskag River to an upgrader facility at the Shell oil refinery in Scotford, Alberta. In August 2005, Kinder Morgan began preliminary engineering work on doubling the capacity of Corridor system by 2009. Both companies plan to link other oil sands projects as the come on-stream.
Export Pipelines
Canada has extensive oil pipeline connections with the United States. Enbridge maintains connections between major Canadian cities and Chicago, seamlessly integrating the Canadian and U.S. components of its network. Enbridge also operates Spearhead, a 650-mile pipeline with a capacity of 300,000-bbl/d that originally carried oil from Cushing, Oklahoma to Chicago. Enbridge received regulatory approval in late 2004 to reverse the flow of the pipeline, allowing it to export oil from Canada deep into the U.S. market. Kinder Morgan exports oil to the U.S. through an extension of the TMPL that reaches northern Washington. It also operates Express, a 790-mile, 170,000-bbl/d pipeline that links Hardisty, Alberta and Casper, Wyoming; from Casper, the company’s 930-mile, 120,000-bbl/d Platte pipeline runs to Wood River, Illinois.
Enbridge has sought regulatory approval for the construction of its 720-mile, 400,000-bbl/d Gateway pipeline from Edmonton to either Kitimat or Prince Rupert, both deepwater ports in British Columbia capable of supporting very large crude carriers (VLCC). The Gateway pipeline would facilitate the export of oil sands to Asia and California. Enbridge stated that it could complete the $2 billion project by 2009, and in April 2005, PetroChina committed to purchasing at least half of the capacity of the Gateway pipeline. Kinder Morgan has discussed plans to build a similar pipeline and upgrade the capacity of the TMPL.
Refining
OGJ reported that Canada had 2.0 million bbl/d of crude oil refining capacity in January 2006. While Alberta contains most of Canada’s crude oil production, a large portion of its refining capacity resides in the more-populated eastern part of the country. Alberta has four refineries, with total capacity of 447,400 bbl/d, whereas Ontario and Quebec have a combined eight refineries. According to Natural Resources Canada, the largest single refinery in the country is Irving Oil’s 280,000 bbl/d St. John plant in New Brunswick.
Natural Gas
Oil and Gas Journal (OGJ) reports that Canada had 56.6 trillion cubic feet (Tcf) of proven natural gas reserves in January 2006. The country produced 6.5 Tcf of natural gas in 2003, while consuming 3.2 Tcf. Canada is an important source of the U.S. natural gas supply. During the first 11 months of 2005, it exported some 3.9 Tcf of natural gas to the United States, representing 85 percent of total U.S. natural gas imports during that period. Most Canadian natural gas exports enter the U.S. through pipelines in Idaho, Montana, North Dakota, and Minnesota.
Exploration and Production
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 should center on coal bed methane (CBM) deposits in the WCSB, Arctic frontier natural gas deposits, the Deep Basin area, and natural gas fields off the Atlantic and Pacific coasts.
Western Canada Sedimentary Basin
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. Production has since leveled at 16.6 billion cubic feet per day (Bcf/d) in 2004, of which some 80 percent occurred in Alberta. High natural gas prices in recent years have motivated increased drilling activity in the WCSB, even though average returns from each well have declined.
Production in the WCSB has begun to move away from Alberta towards new discoveries in British Columbia. In 2004, natural gas production in the portion of the WCSB in British Columbia was about 2.6 Bcf/d, up from 1.9 Bcf/d in 1996. There is also a small amount of natural gas production in the portion of the WCSB in Saskatchewan and Manitoba.
The Deep Basin area has the potential to offset some declines in production from the WCSB. Analysts estimated that the Deep Basin contains at least 15 Tcf of recoverable natural gas reserves. In late 2005, Shell Canada brought its Tay River discovery onstream at a rate of 50 million cubic feet per day (Mmcf/d).
Offshore
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) plan to commence natural gas production in the near future.
As mentioned before, the British Columbia government hopes to lift the moratorium on offshore drilling in the Pacific Ocean, giving access to an estimated 43.4 Tcf of total natural gas reserves believed to exist off its coastline.
Arctic
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 by 2010, 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); In 2005, Devon Energy received preliminary environmental approval to begin an exploratory drilling program in the Beaufort Sea, which would be the first such drilling since 1989.
Liquefied Natural Gas
In order 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 two in Nova Scotia, two in British Columbia, two in Quebec, and one in New Brunswick. These projects represent a combined 4.9 Bcf/d of regasification capacity. While not without controversy, the Canadian LNG terminals have not met with the same level of resistance from local residents and environmentalists that similar facilities in the U.S. have faced.
In Nova Scotia, U.S.-based Anadarko is building the Bear Head LNG regasification terminal near Port Hawkesbury, which will have an initial send-out capacity of 1 Bcf/d. Anadarko plans to bring the facility online by 2008, but, as of February 2005, it had not yet secured a supply of LNG for the project. Also in Nova Scotia, Keltic Petrochemicals, in conjunction with Netherlands-based Petroplus, has proposed a 1 Bcf/d LNG receiving terminal at Goldsboro, which would feed natural gas to a petrochemical plant and the distribution grid.
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 completion slated for 2008. In British Columbia, two companies, WestPac Terminals and Galveston LNG, have proposed LNG receiving terminals at Prince Rupert (300 Mmcf/d) and Kitimat (600 Mmcf/d), respectively.
In Quebec, Petro-Canada and TransCanada Pipelines planned to build a 500-Mmcf/d LNG receiving terminal at Gros Cacouna, in the St. Lawrence River. In 2004, Petro-Canada began talks with Russia’s Gazprom to feed the Gros Cacouna terminal from Gazprom’s planned Shtokman field. Petro-Canada expects to begin construction of the project in 2007. Also in Quebec, a consortium of Enbridge, Gas Metro, and Gaz de France have filed a preliminary environmental study for their Rabaska LNG terminal, which they would build at Levis with an initial capacity of around 500 Mmcf/d.
Unconventional Natural Gas Sources
Coal bed methane (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 the decline in conventional natural gas production. In 2004, CBM production was at 100 Mmcf/d, with predictions that it could average over 1,400 Mmcf/d by 2010. Analysts estimated that Canada has 500 Tcf of recoverable CBM deposits, concentrated in British Columbia and Alberta.
Pipelines
Domestic System
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.
Mackenzie Gas Project
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 natural gas liquids (NGLs). Canada’s National Energy Board (NEB) scheduled a series of public hearings on the project for 2006, where it would consider the economic and environmental impacts of the project. If the project attains regulatory approval, construction of the system would likely last four years and cost some C$6 billion.
Alaskan Pipeline
Supporters of the Mackenzie pipeline also worry about the completion of a rival natural gas pipeline from Alaska’s North Slope to the United States. The 3,400-mile, 4.6-Bcf/d Alaskan pipeline would likely not enter service until 2012. The U.S. Congress approved US$18 billion in loan guarantees in late 2004 for the US$20 billion project. There are some legal questions concerning who will construct and operate the Canadian portion of the pipeline, which have delayed completion of the project. As a result, there has been talk of expanding LNG export capacity in Alaska as an alternative to the pipeline.
Export Pipelines
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 to Illinois.
Coal
Canada holds an estimated 7.3 billion short tons of recoverable coal reserves. Coal production in the country has declined steadily in recent years. The country produced 68.5 million short tons (Mmst) in 2003, down from a peak of 86.7 Mmst in 1997. Coal production is concentrated in the western part of the country, with Alberta containing about half of total coal production. The largest coal producer in Canada is Luscar Limited, which controls over half of the market. In contrast to Canadian coal production, coal consumption has increased over the past decade, reaching 69.4 Mmst in 2003. The bulk of consumption fuels electricity generation, with the remainder used in the production of steel or as primary consumption at industrial facilities.
Canada exports over half its coal production, mostly to Asia, with the rest going chiefly to Europe and Latin America. These exports are overwhelmingly coking coal. On the other hand, Canada imports some thermal and coking coal, mostly from the United States.
Electricity
Canada had 115 gigawatts of installed electricity generating capacity in 2003. The country produced 566.3 billion kilowatt-hours (Bkwh) of electric power in 2003 while consuming 520.9 Bkwh. Some 59 percent of Canada’s electricity generation comes from hydroelectricity, followed by conventional thermal (27 percent), nuclear (12 percent), and other renewables (2 percent).
Canada and the United States have an extensive electricity trade, and the electricity networks of the two countries are heavily integrated. In 2003, Canada exported 33.0 Bkwh of electricity to the United States while importing 22.5 Bkwh. While Canadian electricity exports to the U.S. in 2003 increased from 2002, the trend in recent years has seen exports to the U.S. decline, while imports have increased. Due to the increasing interdependence of the networks in both countries, a dependency made clear during the 2003 Northeast blackout, there have been greater efforts to increase cooperation and coordination between Canada and the U.S. A bilateral commission is planning the formation of the Electric Reliability Organization, an intergovernmental organization that would monitor network reliability, settle trans-border disputes, and formulate common industry standards.
Sector Organization
Canada’s provinces hold most responsibility for regulating the electricity industry. Province-owned utility companies dominate generation, transmission, and distribution activities. The three largest such companies are Ontario Power Generation, Hydro-Quebec, and B.C. Hydro. There are some privately owned firms, and most provinces allow open access to the electricity grid, but they are marginal to the overall market.
There have been efforts to restructure the Canadian energy sector, with an eventual aim to privatize the industry. Alberta began deregulation in 2001, followed by Ontario in 2002. However, in both places, electricity prices surged following initial deregulation efforts, causing the provinces to initiate price caps on residential utility rates. Both provinces have plans to remove these caps in the near future. Privatization of province-owned utility companies has also stalled, facing pressure from organized labor and consumer groups.
Hydroelectricity
Canada is the world’s largest producer of hydroelectricity, generating over 332.5 billion kilowatt-hours (Bkwh) from the source in 2003. Quebec’s La Grande plant is one of the world’s largest hydroelectric facilities, with an installed capacity of 15,000 megawatts (MW). Quebec has the largest share of Canada’s hydroelectric production, followed by British Columbia. It is estimated that Canada still has 180,000 MW of hydroelectricity potential remaining, though only 34,000 MW is currently deemed economically feasible.
Conventional Thermal
The large majority of Canada's conventional thermal electricity generation comes from coal, representing about three-quarters of such production. There are efforts in many provinces to convert thermal generation capacity to natural gas, in order to reduce pollution and help meet Canada’s requirements under the Kyoto Protocol to cut carbon dioxide emissions (see below). In 2004, the government of Ontario announced plans to convert over 7,000 megawatts (MW) of coal-fired generating capacity to natural gas. On the other hand, competing demands for natural gas, especially from oil sands producers, and dwindling domestic reserves could hinder the large-scale transition from coal to natural gas.
Nuclear
Ontario contains the vast majority of Canada’s nuclear energy capacity. Canada’s nuclear energy production peaked in 1994 at 102.4 billion kilowatt-hours (Bkwh) and has since declined, as new construction has not replaced mothballed reactors. Recently, though, there has been renewed interest in nuclear energy, spurred by desires to comply with Canada’s Kyoto obligations. In late 2005, Ontario Power Generation (OPG) completed the restart of its Pickering A Unit 1 reactor, representing 500 MW of installed generating capacity.
Other Renewables
Estimates maintain that Canada has some 28,000 megawatts (MW) of wind power potential, spread throughout the country, with current installed capacity of 370 MW. The largest wind project in Canada is Le Nordais, on the shores of the St. Lawrence River in Quebec, with an installed capacity of 100 MW. Quebec is positioning itself as the leader of Canada’s nascent wind industry: Hydro-Quebec, the province-owned electric utility, has signed future contracts for an estimated 1,000 MW of wind generation capacity.
Environment
Canada's energy abundance has encouraged the development of a highly energy-intensive economy based on natural resource extraction and processing. Total Canadian oil production, for example, increased from 1.8 million barrels per day (bbl/d) in 1984 to an estimated 3.1 million bbl/d in 2003. Canada’s growth in oil output, particularly recently, can be attributed to the development of oil sands in Western Canada, as well as to large oil projects off the coast of Newfoundland. Oil sands projects are large, use considerable amounts of energy, particularly natural gas, and release both gaseous and particulate emissions into the atmosphere. Although the oil sands processes have become more efficient and have reduced greenhouse gas (GHG) emissions per unit of production, an increase in output could lead to an increase in total emissions. Other environmental challenges associated with oil sands processing are disposing of tailings, wastewater management, and land reclamation.
Canada is the world’s third largest natural gas producer and second largest natural gas exporter. According to Environment Canada (EC), a branch of the Canadian government, about half of all homes in Canada use natural gas as the main source for heating. Natural gas also is used extensively by the electricity generation, industrial and commercial sectors. Oil and natural gas exploration is impacting coastal communities from the Beaufort Sea region to waters off Cape Breton and Prince Edward Island.
Heavy reliance on energy-intensive industries could make it more difficult for Canada to meet its environmental commitments, particularly on climate change. Despite protests from Canadian industries and provincial governments, the Canadian House of Commons on December 17, 2002, ratified the Kyoto Protocol, committing the country to reducing greenhouse gas emissions 5.2% below 1990 levels during the period 2008-2012. The loudest protests came from Alberta’s oil sands producers, who worried that the Protocol would hurt the economics of their operations. In July 2003, former Prime Minister Chrétien attempted to quell their worries by promising safeguards to the Canadian oil industry to limit the economic impact of the Kyoto Protocol. Nonetheless, the Protocol remains controversial in Canada. Newly-appointed Prime Minister Paul Martin commented in December 2003 that Canada does not yet have a concrete plan for meeting its Kyoto commitments.
Besides close bilateral ties with the United States, Canada also works closely with Mexico. All three countries participate in the Commission for Environmental Cooperation (CEC), a tri-national organization established under the North American Agreement on Environmental Cooperation (NAAEC). The CEC addresses environmental concerns associated with increased trade in North America, such as air pollution and enforcement of environmental law. The Agreement complements the environmental provisions of the North American Free Trade Agreement (NAFTA).
Air Pollution
In a report from the NAFTA Commission for Environmental Cooperation, Ontario was the third-worst polluting state or province in both Canada and the United States in 2000 (see graph). In addition, Canadian toxic air emissions from plants and mills increased by 7% from 1998 to 2000 while those in the United States fell by 8% over the same period.
According to EC, air quality in Canada has improved in some areas while it has worsened in others. For example, ambient levels of nitrogen dioxide, sulfur dioxide and carbon monoxide dropped between 1990 and 2000 in urban areas, while emissions of volatile organic compounds from all sources did not improve. One main contributor to Canada’s air pollution is emissions generated from automobiles. EC reported that the transportation sector is responsible for 40% of nitrogen oxide and 25% of carbon dioxide emitted into Canada’s atmosphere. Between 1990 and 2000, automobile travel increased 9%, while fossil fuel consumption increased 21% over the same period. Moreover, EC pointed out that between 1990 and 2002 energy efficiency in the passenger transportation sector decreased 1.1%, reflecting a shift away from passenger cars towards larger vehicles, such as sport utility vehicles and minivans (see graph).
In February 2001, Environment Minister David Anderson announced the government’s 10-year Plan of Action for Cleaner Vehicles, Engines and Fuels. Some of the initiatives outlined in the plan include reducing the level of sulfur by 2006 in diesel fuel used by trucks and buses and getting automobile manufacturers to introduce low-emission vehicles in Canada for model years 2001-2003.
Canada also has undertaken measures to reduce cross-border air pollution. In December 2000, for example, Canada signed the Ozone Annex to the 1991 Canada–U.S. Air Quality Agreement to reduce the flow of air pollutants transcending the border. In June 2003, Canada and the United States deepened cooperation on reducing cross-border air pollution by agreeing to the Border Air Quality Strategy. The program supports three pilot projects: the Great Lakes Basin Airshed Management Framework; the Georgia Basin/Puget Sound International Airshed Strategy; and a study on the feasibility of emissions trading for NOx (nitrogen oxides) and SO2 (sulfur dioxide).
Energy Use and Carbon Emissions
In 2001, Canada ranked as the seventh-largest consumer of primary energy in the world, at 12.5 quadrillion Btu (quads). Between 1991 and 2001, Canada's total energy consumption increased 15%, while total consumption of fossil fuels rose 21% over the same period. The Canadian government attributes the country's high energy consumption to vast land distances in regards to transportation; a cold climate; an energy-intensive industrial base; relatively low energy prices; and a high standard of living.
In 2001, Canada was one of the world's leading carbon emitting countries, generating 156.2 million metric tons (mmt) of energy-related carbon emissions (2.5% of the world total). According to Canada’s Greenhouse Gas Inventory (CGGI), compiled by the Greenhouse Gas Division of Environment Canada, Canada’s GHG emissions decreased in 2001, the first year-on-year decrease since 1991. Nonetheless, emissions increased 18.5% between 1991-2001. The greatest contributions in 2001 were from the electricity and petroleum industries, which accounted for 38% for total national emissions, followed by the transportation sector with 25%, according to CGGI. Overall, the energy sector (including stationary and transportation combustion sources and energy used during the extraction of fossil fuels) accounted for over 80% of Canada’s total GHG emissions in 2001. Of the provinces, Alberta accounted for 31.2% of total GHG emissions, followed by Ontario (27.9%) and Quebec (12.5%).
Canada has started initiatives to reduce GHG emissions, namely the Climate Change Plan for Canada, announced in November 2002. The plan received a needed boost in August 2003, as the government committed $1 billion to measures outlined in the program.
Energy and Carbon Intensity
Canada is one of the most energy-intensive countries in the industrialized world. In 2001, the country's energy intensity (energy consumption per dollar of gross domestic product, GDP) stood at 15,029 Btu per $1995 in purchasing power parity (PPP), well above other Organization for Economic Co-operation and Development (OECD) countries. Canada's energy intensity has been declining over the past two decades, but remains high due to its energy-intensive industries.
Canada's carbon intensity, 0.19 metric tons of carbon per thousand $1995-PPP in 2001, was also the highest among industrialized economies. According to Environment Canada, Canada's higher carbon intensity in comparison to other OECD countries has been due to increased consumption of fossil fuels for electricity generation, increased energy consumption in the transportation sector, and growth in fossil fuel production (largely for export).
Per Capita Energy Consumption and Carbon Emissions
Canada's 2001 per capita energy consumption, 402.6 million Btu per person, was the highest in North America, above the U.S. level of 341.8 million Btu per person. Relative to other OECD countries, Canada's per capita energy consumption is considerably higher than France's (177.8 million Btu per person), the United Kingdom's (164.8 ), Germany's (174.3), Japan's (172.2), and Italy's (140.0).
Canada's 2001 per capita carbon emissions of 5.0 metric tons (mt) were below the U.S. level of 5.5 mt/person, but high relative to Germany (2.7), the United Kingdom (2.6), Japan (2.5), Italy (2.1) and France (1.8). Per capita carbon emissions, while decreasing slightly from their 1980 level of 5.2 mt/person, have remained fairly steady over the past two decades.
Renewable Energy
Renewable energy sources, such as hydroelectricity and wind power, are beginning to gain much attention as Canada moves forward in its efforts to reduce GHG emissions. In 2001, hydroelectric power accounted for 56% of the country's total electricity generated, followed by thermal (28.3%) and nuclear (13.0%). Other renewable energy sources, such as geothermal, solar, wind, wood, and waste, accounted for the remainder.
Although there are still plans to add some large-scale hydroelectric power in Canada, these projects are slowly giving way to smaller-scale projects. This shift in energy policy is partially due to environmental concerns, such as inundation of important ecological zones and the displacement of agricultural lands. Increased hydropower production has important implications for GHG emissions, since hydroelectricity does not release carbon dioxide.
Wind energy use is increasing in Canada, although it accounts for less than 1% of its electricity requirements. According to the Canadian Wind Energy Association (CWEA), Canada had about 205 megawatts (MW) of wind generation plant installed at the beginning of 2002, which grew to 323 MW, as of January 2004. CWEA believes that Canada can increase its wind generation capacity to 10,000 MW by 2010.
Outlook
According to the United States Energy Information Administration's International Energy Outlook 2003, Canadian energy consumption is expected to increase to 2025 at an average annual percent change of 1.3%, slightly less than projections for all of North America (1.7%) in the reference case projections. Canada's total energy consumption is projected to be 17.1 quadrillion Btus by 2025.
During the same projection period, Canadian natural gas consumption is expected to grow at a rate of 2.3%, nuclear energy at a rate of 0.6%, coal consumption will grow at an average annual rate of 0.2%, renewable at 1.1%. Canadian carbon emissions are expected to grow at an average annual rate of 1.2%.
Entering the 21st century, Canada is striving to be a leader in addressing environmental concerns. In 1999, the Canadian government illustrated its commitment to environmental protection with the release of a revised Canadian Environmental Protection Act (CEPA), which came into force on March 31, 2000. The new Act focuses on pollution abatement and prevention and authorizes enforcement officers to deal with polluters who break the laws. Furthermore, it provides a "right to sue" the federal government if they fail to enforce new CEPA rules.
Further Reading
- Atomic Energy of Canada Limited (AECL)
- Canadian Centre for Energy Information
- EIA: Country Information on Canada
- Energy Council of Canada
- Husky Energy
- Imperial Oil
- National Energy Board of Canada
|
Disclaimer: This article is taken wholly from, or contains information that was originally published by, the Energy Information Administration. Topic editors and authors for the Encyclopedia of Earth may have edited its content or added new information. The use of information from the Energy Information Administration should not be construed as support for or endorsement by that organization for any new information added by EoE personnel, or for any editing of the original content. |