According to the Oil and Gas Journal (OGJ), Canada had 178 billion barrels of proven oil reserves as of January 2009, second only to Saudi Arabia. The bulk of these reserves (over 95 percent) are oil sands deposits in Alberta, which are more difficult to extract and process than conventional crude oil. Canada is a net exporter of oil, with 2008 net exports of 1.0 million bbl/d. Almost all of the countries exports flow to the United States, and it is consistently the top supplier of U.S. oil imports.

Canada’s oil production (including all liquids) was 3.35 million bbl/d in 2008, down 0.07 million bbl/d from 2007. Despite the drop last year, Canada’s oil production has steadily risen over the past decade, as new oil sands and offshore projects have come on-stream to replace aging, mature fields. Overall, EIA expects that oil sands production will increase even further in coming years and more than offset the decline in Canada’s conventional crude oil production: according to the July 2009 Short-Term Energy Outlook, EIA expects Canadian oil production to increase to 3.41 million bbl/d in 2009 and 3.48 million bbl/d in 2010. Canada consumed an estimated 2.32 million bbl/d of oil in 2008. The country sends over 99 percent of its oil exports to the U.S., and it is consistently the top source of U.S. oil imports.

Canada has a privatized oil sector that has witnessed consolidation in recent years. Large oil producers in the country include Imperial Oil, EnCana, Talisman Energy, Suncor, EOG Resources, Husky Energy, and Apache Canada. Much of the regulation of the oil industry occurs at the provincial level. In 2009, Suncor and Petro-Canada announced that they would merge, creating the largest oil producer in the country, as well as one of the largest producers of natural gas.

Canada’s oil sands producers have attracted increasing attention from foreign oil companies, especially Asian companies seeking to satisfy growing demand in their countries and secure equity oil stakes. In July 2006, state-run Korea National Oil Corporation (KNOC) purchased the BlackGold bitumen deposit from Newmont for $250 million; BlackGold contains an estimated 250 million barrels of crude oil, and KNOC plans to bring 35,000 bbl/d of production onstream at the site by 2010. In 2005, China’s Sinopec (through its Canadian subsidiary) purchased a 40 percent stake in Northern Lights, an oil sands project currently under development by Total; in 2009, Sinopec purchased an additional 10 percent stake in the project. In 2007, the Chinese National Petroleum company (CNPC) won exploration rights for a 260-acre tract in Alberta. The China National Offshore Oil Corporation (CNOOC) holds a stake in MEG Energy, which operates the Christina Lake project.

Canadian oil production comes mainly from three sources: the Western Canada Sedimentary Basin (WCSB); the oil sands deposits of northern Alberta; and offshore fields in the Atlantic Ocean. Alberta contains the largest share of Canada’s oil production, as it holds the majority of oil sands deposits and the bulk of the WCSB. According to Statistics Canada, Alberta represented 68 percent of Canada’s national oil production in 2008.

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 supplant conventional sources as the focus of future oil production in western Canada. Conventional crude oil production in the WCSB represented around 39 percent of Canada’s total crude oil production in 2008, down from about 65 percent in 1999.

Oil sands contain deposits of bitumen, a heavy, viscous type of crude oil. There are two methods currently used to extract bitumen from the ground: open pit mining and in situ (“in place”). Open pit mining resembles conventional mining techniques and is effective in extracting oil sands deposits near the surface. However, the bulk (80 percent) of Canada’s estimated oil sands deposits 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 heat and separate bitumen from the surrounding sands, causing it to pool closer to the surface. The bitumen is then pumped from these pools using horizontal drain wells. 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 some of the bitumen into “synthetic crude,” a relatively light, sweet form of crude oil that can be sold to a traditional oil refinery. Some of the bitumen is also sold in raw form, marketed to specialized refineries with deep conversion capacity. Some oil sands projects have integrated upgrading capacity, while others must send their raw bitumen production to another facility.

In 2008, oil sands production represented approximately half of Canada’s total crude oil production. 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. Most of the oil sands development to-date has focused on the Athabasca deposit.

The largest oil sands projects in the Athabasca area utilize open-pit mining. The Syncrude Project, operated by Canadian Oil Sands Limited, produced 290,000 bbl/d of synthetic crude oil in 2008. Suncor operates another large open-pit mining project in Alberta, which produced 228,000 bbl/d of crude oil in 2008. Finally, the Athabasca Oil Sands Project (AOSP), operated by Shell Canada, began production in 2002 and currently has a capacity of 155,000 bbl/d of raw bitumen. AOSP utilizes a facility adjacent to Shell’s Scotford refinery to upgrade raw bitumen produced by the project. In early 2009, Canadian Natural Resources Limited (CNRL) brought the first phase of its Horizon project online, which includes a surface mining project and integrated upgrader, producing 110,000 bbl/d of synthetic crude oil.

The in situ oil sands projects in the Athabasca area are generally smaller and more numerous than their mining counterparts. In 2004, Suncor began operations at its Firebag project, which utilizes an in situ technology called steam-assisted gravity drainage (SAGD). Other SAGD projects include Petro-Canada’s MacKay River and Dover; and EnCana’s Foster Creek and Christina Lake. In late 2008, Nexen brought its Long Lakein situ project onstream, with production expected to ramp up to 60,000 bbl/d by the middle of 2010.

Outside of the Athabasca deposit, the largest oil sands project is Imperial Oil’s Cold Lakein situ facility, with a capacity of 150,000 bbl/d. Also in the Cold Lake area, CNRL operates Primrose, while Husky operates the Tucker project. In the Peace River deposit, Shell Canada operates Cadotte Lake (11,000 bbl/d).

The combination of falling oil prices, unavailability of financing, and uncertainty about future world oil demand forced delays to several oil sands projects in late 2008. In October 2008, Petro-Canada delayed a final decision to proceed with the first stage (bitumen mining) of its Fort Hills Project and placed the second stage (bitumen upgrader) of the project on indefinite hold. Royal Dutch Shell also postponed an expansion of its oil sands project, while Suncor announced that it would reduce capital spending in 2009 by more than one-third. Some projects were still moving forward, however: in May 2009, Imperial Oil announced that it would proceed with the $8-billion first phase of its Kearl mining project, expected to come online in 2012 with production capacity of 100,000 bbl/d.

As an unconventional source of crude oil, oil sands present additional challenges compared to conventional oil production. In general, oil sands projects are more costly than conventional crude oil projects, and analysts estimate that the production of synthetic crude is only economically viable with relatively 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 and develop alternative means of in situ extraction, any increase in natural gas prices or sharp reduction in natural gas supply would have important repercussions for the oil sands industry.

Even considering these concerns, most forecasts of world oil markets estimate that Canadian oil sands will become an increasingly important component of world oil supply. EIA’s International Energy Outlook 2009 (IEO) estimates that Canadian oil sands operators could produce 4.2 million bbl/d by 2030. Based on growth in oil sands production, Canada is expected to be an important source of growth in oil production from countries outside of the Organization of the Petroleum Exporting Countries (OPEC).

Canada has three oil projects off its Atlantic coastline, all located in the Jeanne d’Arc Basin: Hibernia (135,000 bbl/d, PetroCanada), Terra Nova (116,000 bbl/d, PetroCanada), and White Rose (117,000 bbl/d, Husky). The basin has seen an increase in investment plans in recent years, with both White Rose and Hibernia announcing plans to expand production by incorporating satellite fields. Outside of the Jeanne d’Arc Basin, StatoilHydro announced in 2009 that it had discovered commercial quantities of crude oil at its Mizzen field in the Flemish Pass basin. In 2009, ExxonMobil submitted its proposed Hebron project for regulatory approval, which could come onstream as soon as 2017 and reach a peak production rate of 176,000 bbl/d. 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.

Off the Pacific coast, industry experts believe that there could be sizable oil and natural gas reserves. However, there has been no production to date there, because of a federal ban on offshore oil activities in the Pacific Ocean.

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. 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. New oil sands projects expected to come onstream in the coming years will likely necessitate an expansion of this network.

Canada has extensive oil pipeline connections with the United States. Enbridge maintains connections between major Canadian cities and Chicago, integrating the Canadian and U.S. components of its network. Enbridge also operates Spearhead, a 650-mile pipeline with a capacity of 125,000-bbl/d that links Chicago with Cushing, Oklahoma.

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.

Any increase in oil sands production will require additional pipeline capacity to take that production to world markets. Along with expanding existing trunk lines, companies have proposed several new pipeline projects that would better link Alberta with the U.S. Gulf Coast, allowing oil sands producers greater access to the large concentration of refineries there:

Enbridge has also floated plans for the construction of the 720-mile, 400,000-bbl/d Gateway pipeline from Edmonton to Kitimat, a deepwater port in British Columbia capable of supporting very large crude carriers (VLCC). The Gateway pipeline would facilitate the export of oil sands to Asia or California. Kinder Morgan has discussed plans to build a similar pipeline or upgrade the capacity of the TMPL.

Enbridge has proposed construction of the Southern Lights pipeline, which would transport 180,000 bbl/d of light hydrocarbons from Chicago to Edmonton. Oil sands operators in Alberta rely on these hydrocarbons to dilute bitumen so that it can flow through pipelines. Currently, the largest source of diluents comes from natural gas liquids; however the prospects of declining Canadian natural gas production mean that Alberta could face a diluents crunch without additional supplies.

In 2008, Canada exported 2.5 million bbl/d of crude oil and refined products to the U.S., the single-largest source of U.S. oil imports and representing almost all of Canada’s total oil exports. The largest share of U.S.-bound Canadian oil exports go to the Midwest (PAD District II), followed by the Rocky Mountains (PAD District IV). The bulk of Canadian exports to the U.S. have traditionally gone to PAD Districts II and IV, because these areas are well connected to Alberta by oil pipelines and not well served by coastal import terminals.

Even though Canada is a net oil exporter, it imports sizable quantities of crude oil and refined products. According to the International Energy Agency (IEA), Canada imported around 1.2 million bbl/d of crude oil and refined products in 2008. Canada’s major population centers in the eastern part of the country are not well connected to its principle production facilities in the western interior, meaning that it is often easier to import oil along the coastlines rather than transport it domestically. Most oil imports come from Algeria (crude oil), Norway (crude oil) and the U.S. (refined products).

OGJ reported that Canada had 18 refineries in 2009, with total crude distillation capacity of 2.03 million bbl/d. By comparison, Canada consumed approximately 2.3 million bbl/d of refined products in 2008. 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 437,400 bbl/d, whereas Ontario and Quebec have a combined 919,600 bbl/d of refining capacity.

In January 2007, Irving Oil initiated the environmental review process for the construction of the 300,000 bbl/d Eider Rock refinery in Saint John, New Brunswick. The facility would occupy land near the company’s existing refinery and the LNG terminal it jointly owns with Repsol YPF. In July 2009, Irving Oil announced that it would not move forward with the project, because of industry and global economic conditions.