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Long-term outlook

Broadly speaking, Canadian conventional oil production (via standard deep drilling) peaked in the mid-1970s, but East Coast offshore basins being exploited in Atlantic Canada did not peak until 2007 and are still producing at relatively high rates. Production from the Alberta oil sands, which include the Athabasca, Cold Lake and Peace River deposits, is still in its early stages and the province's established bitumen resources are expected to last for generations into the future. The Alberta Energy Regulator estimated in 2016 that the province has 165 billion barrels of established reserves - 19% that can be recovered by mining, and 81% that is quantified as being recoverable via in situ techniques. At the 2014 production rate of 366,300 cubic metres per day (2.3 Mbbl/d), they would last for about 375 years. The AER projects that bitumen production will increase to 641,800 cubic metres per day (4.0 Mbbl/d) by 2024, but at that rate they would still last for about 213 years. Because of the enormous size of the known oil sands deposits, economic, labor, environmental, and government policy considerations are the constraints on production rather than finding new deposits.

In addition, the Alberta Energy Regulator has recently identified over 67 billion cubic metres (420 Gbbl) of unconventional shale oil resources in the province. This volume is larger than the province's oil sands resources, and if developed would give Canada the largest crude oil reserves in the world. However, due to the recent nature of the discoveries there are not yet any plans to develop them.

Major sectors

Petroleum Pipeline Systems An overview of an oil pipeline system from the wellhead to downstream consumers

There are three components of the Canadian petroleum industry: upstream, midstream and downstream.

Midstream

The midstream sector involves the transportation, storage, and wholesale marketing of crude or refined petroleum products and natural gas. Canada has a large network of pipelines - over 840,000 km - that transport crude oil and natural gas across the country. There are four main pipeline groups: gathering, feeder, transmission, and distribution pipelines. Gathering pipelines transport crude oil and natural gas from wells drilled in the subsurface to oil batteries or natural gas processing facilities. The majority of these pipelines are found in petroleum producing areas in Western Canada. Feeder pipelines move crude oil, natural gas, and natural gas liquids (NGLs) from the batteries, processing facilities, and storage tanks to the long-distance portion of the transportation system: transmission pipelines. These are the major carriers of crude oil, natural gas, and NGLs within provinces and across provincial or international borders, where the products are either sent to refineries or exported to other markets. Finally, distribution pipelines are the conduit for delivering natural gas to downstream customers, such as local utilities, and then further distributed to homes and businesses. If pipelines are near capacity or non-existent in certain areas, crude oil is then transported over land by rail or truck, or over water by marine vessels.

The midstream operations are often taken to include some elements of the upstream and downstream sectors. For example, the midstream sector may include natural gas processing plants which purify the raw natural gas as well as removing and producing elemental sulfur and natural gas liquids (NGL) as finished end-products. Midstream service providers in Canada refer to Barge companies, Railroad companies, Trucking and hauling companies, Pipeline transport companies, Logistics and technology companies, Transloading companies and Terminal developers and operators. Development of the massive oil sand reserves in Alberta would be facilitated by enhancing the North American pipeline network which would transport dilbit to refineries or export facilities.

Export capacity

Total Canadian crude oil production, most of which is coming from the Western Canada Sedimentary Basin (WCSB), is forecast to increase from 3.85 million barrels per day (b/d) in 2016 to 5.12 million b/d by 2030. Supply from the Alberta oil sands accounts for most of the growth and is expected to increase from 1.3 million b/d in 2016 to 3.7 million b/d in 2030. Bitumen from the oil sands requires blending with a diluent in order to decrease its viscosity and density so that it can easily flow through pipelines. The addition of diluent will add an estimated 200,000 b/d to the total volumes of crude oil in Canada, for a total of 1.5 million extra barrels per day requiring the creation of additional transport capacity to markets. The current takeaway capacity in Western Canada is tight, as oil producers are beginning to outpace the movement of their products.

Pipeline capacity measurements are complex and subject to variability. They depend on a number of factors, such as the type of product being transported, the products it is mixed with, pressure reductions, maintenance, and pipeline configurations. The major oil pipelines exiting Western Canada have a design transport capacity of 4.0 million b/d. In 2016, however, the pipeline capacity was estimated at 3.9 million b/d, and in 2017 the Canadian Association of Petroleum Producers (CAPP) estimated the pipeline capacity to be 3.3 million b/d. The lack of available pipeline capacity for petroleum forces oil producers to look to alternative transport methods, such as rail.

Crude-by-rail shipments are expected to increase as existing pipelines reach capacity and proposed pipelines experience approval delays. The rail loading capacity for crude in Western Canada is close to 1.2 million b/d, although this varies depending on several factors including the length of the unit trains, size and type of railcars used, and the types of crude oil loaded. Other studies, however, estimate the current rail loading capacity in Western Canada to be 754,000 b/d. The International Energy Agency (IEA) forecasts that crude-by-rail exports will increase from 150,000 b/d in late 2017 to 390,000 b/d in 2019, which is much greater than the record high of 179,000 b/d in 2014. The IEA also warns that rail shipments could reach as high as 590,000 b/d in 2019 unless producers store their produced crude during peak months. The oil industry in the WCSB may need to continue to rely on rail in the forecastable future, as no major new pipeline capacity is expected to be available before 2019. The capacity - to a certain extent - is there, but producers must be willing to pay a premium to move crude by rail.

Getting to tidewater

Canada's oil sands are landlocked and it is crucial to the petroleum industry that transportation of petroleum products keep pace with production. Because of limited transport capacity to Canada's west coast, oil sands petroleum products suffer huge losses on price differentials. Canada's largest commercial heavy oil stream - Western Canadian Select (WCS) - cannot access international prices such as Louisiana Light Sweet crude (LLS) or Mexico's Maya crude oil, due to tidewater restraints. The Alberta government (and to some extent, the Canadian government) is losing $4 billion to $30 billion in tax and royalty revenues because WCS is discounted so heavily against West Texas Intermediate (WTI) while Maya crude oil, a similar product close to tidewater, is reaching peak prices. Calgary-based Canada West Foundation warned in April 2013, that Alberta is "running up against a [pipeline capacity] wall around 2016, when we will have barrels of oil we can’t move."

Preferred access ports include the US Gulf ports via the Keystone XL pipeline to the south, the BC Pacific coast in Kitimat via the Enbridge Northern Gateway Pipelines, and the Trans Mountain line to Vancouver. Frustrated by delays in getting approval for Keystone XL, Northern Gateway, and the expansion of the existing Trans Mountain line to Vancouver, Alberta has intensified exploration of northern projects, such as building a pipeline to the northern hamlet of Tuktoyatuk near the Beaufort Sea, "to help the province get its oil to tidewater, making it available for export to overseas markets." Under Prime Minister Stephen Harper, the Canadian government spent $9 million by May, 2012, and $16.5 million by May, 2013, to promote Keystone XL. In the United States, Democrats are concerned that Keystone XL would simply facilitate getting Alberta oil sands products to tidewater for export to China and other countries via the American Gulf Coast of Mexico.

In 2013, Generating for Seven Generations (G7G) and AECOM received $1.8 million in funding from Alberta Energy to study the feasibility of building a railway from northern Alberta to the Port of Valdez, Alaska. The proposed 2,440-km railway would be capable of transporting 1 million to 1.5 million b/d of bitumen and petroleum products, as well as other commodities, to tidewater (avoiding the tanker ban along British Columbia's northern coast). The last leg of the route - Delta Junction through the coastal mountain range to Valdez - was not deemed economically feasible by rail; an alternative, however, may be the transfer of products to the underutilized Trans Alaska Pipeline System (TAPS) to Valdez.

Pipeline versus rail debate

The public debate surrounding the trade-offs between pipeline and rail transportation has been developing over the past decade as the amount of crude oil transported by rail has increased. It was invigorated in 2013 after the deadly Lac-Mégantic disaster in Quebec when a freight train derailed and spilled 5.56 million litres of crude oil, which resulted in explosions and fires that destroyed much of the town's core. That same year, a train carrying propane and crude derailed near Gainford, Alberta, resulting in two explosions but no injuries or fatalities. These rail accidents, among other examples, have raised concerns that the regulation of rail transport is inadequate for large-scale crude oil shipments. Pipeline failures also occur, for instance, in 2015 a Nexen pipeline ruptured and leaked 5 million litres of crude oil over approximately 16,000 m² at the company's Long Lake oilsands facility south of Fort McMurray. Although both pipeline and rail transportation are generally quite safe, neither mode is without risk. Numerous studies, however, indicate that pipelines are safer, based on the number of occurrences (accidents and incidents) weighed against the quantity of product transported. Between 2004 and 2015, the likelihood of rail accidents in Canada was 2.6 times greater than for pipelines per thousand barrels of oil equivalents (Mboe). Natural gas products were 4.8 times more likely to have a rail occurrence when compared to similar commodities transported by pipelines. Critics question if pipelines carrying diluted bitumen from Alberta's oil sands are more likely to corrode and cause incidents, but evidence shows the risk of corrosion being no different than that of other crude oils.

Costs

A 2017 study by the National Bureau of Economic Research found that contrary to popular belief, the sum of air pollution and greenhouse gas (GHG) emissions costs is substantially larger than accidents and spill costs for both pipelines and rail. For crude oil transported from the North Dakota Bakken Formation, air pollution and greenhouse gas emission costs are substantially larger for rail compared to pipeline. For pipelines and rail, the Pipeline and Hazardous Materials Safety Administration's (PHMSA) central estimate of spill and accident costs is US$62 and US$381 per million-barrel miles transported, respectively. Total GHG and air pollution costs are 8 times higher than accident and spills costs for pipelines (US$531 vs US$62) and 3 times higher for rail (US$1015 vs US$381).

Finally, transporting oil and gas by rail is generally more expensive for producers than transporting it by pipeline. On average, it costs between US$10-$15 per barrel to transport oil and gas by rail compared to $5 a barrel for pipeline. In 2012,16 million barrels of oil were exported to USA by rail. By 2014, that number increased to 59 million barrels. Although quantities decreased to 48 million in 2017, the competitive advantages offered by rail, particularly its access to remote regions as well as lack of regulatory and social challenges compared with building new pipelines, will likely make it a viable transportation method for years to come. Both forms of transportation play a role in moving oil efficiently, but each has its unique trade-offs in terms of the benefits it offers.

Impact of oil sands and pipeline development on Indigenous groups

Pipeline development poses significant risks to the cultural, social, and economic way of life of Canada’s Indigenous populations.  Historically, many Indigenous groups have opposed pipeline development for two primary reasons: 1) the inherent environmental risks associated with transporting harmful oil and gas products, and 2) failure by the federal government to properly consider and mitigate Indigenous groups’ concerns regarding resource development on their lands.  For instance, many Indigenous groups rely heavily on local wildlife and vegetation for their survival. Increased oil production in Canada requires greater oil transport through their traditional lands, which poses serious threats to the survival and traditional way of life of Indigenous groups, as well as the safety and preservation of the surrounding ecosystems.  As well, First Nation's in Alberta have called particular attention to adverse health impacts related to oil sands emissions, asserting that the water quality testing for specific chemicals (heavy metals) has been insufficient.

Aside from environmental concerns, many Indigenous groups have pushed back against pipeline development due to inadequate consultation processes by the federal government.  As per Section 35 of the Canadian Constitution Act Indigenous peoples in Canada are guaranteed the right to be meaningfully consulted with and accommodated when the Crown is contemplating resource development on their lands - see Duty to Consult.  Through a series of Supreme Court of Canada rulings and political protests from Indigenous peoples (see Haida Nation v. British Columbia [Minister of Forests], Taku River Tlingit First Nation v British Columbia, and Tsilhqot’in Nation v British Columbia), among others, the courts have attempted to further define the Crown’s consultation responsibilities and give legal recognition to Indigenous traditional territory and rights regarding resource development.

Contrarily, oil sands development also presents many positive impacts and opportunities for Indigenous groups, particularly in Western Canada. In fact, over the past two decades, First Nations participation in the energy sector has increased dramatically, from employment and business opportunities to project approval processes and environmental evaluation. Increased Indigenous participation has been encouraged by numerous collaboration agreements with industry, typically in the form of impact benefit agreements (IBAs), which provide not only employment and business ventures, but also job training and community benefits. Enhanced participation in the energy sector has empowered many Indigenous groups to push for wider involvement by negotiating ownership stakes in proposed pipelines and bitumen storage projects. Perhaps the best example of such partnering in Alberta is the agreement between Suncor and Fort McKay and Mikisew Cree First Nations.  The two First Nations acquired a 49% ownership in Suncor’s East Tank Farm Development with shares valued at about $500 million making it the largest business investment to date by a First Nation entity in Canada.

Support for resource development and desire for direct involvement is further illustrated by the First Nations’ led $17-billion Eagle Spirit Energy Holding Ltd. pipeline and energy corridor between Alberta and the northern B.C. coast (with a back-up plan to site its terminal in Alaska to get around the tanker ban in B.C.). The project has secured support from 35 First Nations along the proposed route; the bands are entitled to at least 35% ownership in exchange for the land use.

Regulatory agencies in Canada

See also Energy policy of Canada

The jurisdiction over the petroleum industry in Canada, which includes energy policies regulating the petroleum industry, is shared between the federal and provincial and territorial governments. Provincial governments have jurisdiction over the exploration, development, conservation, and management of non-renewable resources such as petroleum products. Federal jurisdiction in energy is primarily concerned with regulation of inter-provincial and international trade (which included pipelines) and commerce, and the management of non-renewable resources such as petroleum products on federal lands.

Natural Resources Canada (NRCan)

Oil and Gas Policy and Regulatory Affairs Division (Oil and Gas Division) of Natural Resources Canada (NRCan) provides an annual review of and summaries of trending of crude oil, natural gas and petroleum product industry in Canada and the United States (US)

National Energy Board

The petroleum industry is also regulated by the National Energy Board (NEB), an independent federal regulatory agency. The NEB regulates inter-provincial and international oil and gas pipelines and power lines; the export and import of natural gas under long-term licenses and short-term orders, oil exports under long-term licenses and short-term orders (no applications for long-term exports have been filed in recent years), and frontier lands and offshore areas not covered by provincial/federal management agreements.

In 1985, the federal government and the provincial governments in Alberta, British Columbia and Saskatchewan agreed to deregulate the prices of crude oil and natural gas. Offshore oil Atlantic Canada is administered under joint federal and provincial responsibility in Nova Scotia and Newfoundland and Labrador.

Provincial regulatory agencies

There were few regulations in the early years of the petroleum industry. In Turner Valley, Alberta for example, where the first significant field of petroleum was found in 1914, it was common to extract a small amount of petroleum liquids by flaring off about 90% of the natural gas. According to a 2001 report that amount of gas that would have been worth billions. In 1938 the Alberta provincial government responded to the conspicuous and wasteful burning of natural gas. By the time crude oil was discovered in the Turner Valley field, in 1930, most of the free gas cap had been flared off. The Alberta Petroleum and Natural Gas Conservation Board (today known as the Energy Resources Conservation Board) was established in 1931 to initiate conservation measures but by that time the Depression caused a waning of interest in petroleum production in Turner Valley which was revived from 1939-1945.