Updated March 2017

  • In 2016, the federal government announced new interim guidelines for the environmental assessment of federally regulated pipeline developments. Under the new guidelines, upstream greenhouse gas emissions linked to projects under review will be evaluated.
  • The new federal Pipeline Safety Act took effect in June 2016. Under the act, liability is unlimited in cases of uncontrolled spills where the company is at fault. If the responsible company is unable to pay, clean-up costs will be recouped from other pipeline companies with approval from the government. Liability is capped at Cdn$1 billion for large pipelines if a company was neither at fault nor negligible.

Oil Pipelines

Figure 9.2

  • As shown in Figure 9.2 [Tableau], Alberta is serviced by four major export lines that provide the bulk of export capacity leaving the province.
  • The twinning of Kinder Morgan Canada’s Trans Mountain pipeline from Edmonton, Alberta, to Burnaby, British Columbia, and the replacement of Enbridge Inc.’s Line 3 to the U.S. Midwest received federal approval in November 2016, while the Enbridge Northern Gateway project was denied.
  • The Trans Mountain expansion project will add 93.8 thousand cubic metres per day (103 m3/d)—0.59 million barrels per day [106 bbl/d])─bringing total capacity to 141.4 103 m3/d (0.89 106 bbl/d). The anticipated in-service date is 2019.
  • The Enbridge Line 3 replacement, expected to start up in 2019, will add an additional 58.8 103 m3/d (0.37 106 bbl/d) of capacity, bringing total capacity to 120.8 103 m3/d (0.76 106 bbl/d). The U.S. segment of the pipeline is currently awaiting regulatory approval by the state of Michigan.
  • There are two proposed pipeline projects, TransCanada Corporation’s Energy East and Keystone XL projects, that would add 174.8 103 m3/d (1.1 106 bbl/d) and 131.9 103 m3/d (0.83 106 bbl/d), respectively, to current pipeline capacity.
  • TransCanada Keystone XL project was denied by the U.S. State Department in November 2015. However, TransCanada resubmitted its application in January 2017.
  • Alberta exports will begin to reach pipeline capacity limits by 2021 based on the oil removal forecasts in this report and on existing pipeline export capacity. However, with the addition of one or both of the federally approved pipelines, there would be sufficient pipeline capacity for the remainder of the forecast period. If these pipelines are delayed or not developed, current rail capacity will be sufficient to accommodate the additional production for the forecast period.
  • TransCanada’s Heartland pipeline would link Edmonton and Hardisty and will be revisited when more supportive market conditions emerge. The pipeline as proposed has an initial capacity of 95.3 103 m3/d (0.6 106 bbl/d), and TransCanada anticipates that the pipeline could ultimately transport up to 143.0 103 m3/d (0.9 106 bbl/d) of oil.
  • TransCanada is developing the Grand Rapids project as part of a joint venture with Brion Energy Corporation. The project consists of two pipelines between Fort McMurray and the Edmonton area: one for diluent and the other for diluted bitumen. The diluent supply pipeline is expected to begin service in 2017 but will initially transport diluted bitumen until the other pipeline is complete. Construction of the diluted bitumen pipeline has been delayed in response to current market conditions and will be revisited when more supportive market conditions emerge. The Grand Rapids pipeline system has an ultimate design capacity of 143.0 103 m3/d (0.90 106 bbl/d) of diluted bitumen and 52.4 103 m3/d (0.33 106 bbl/d) of diluent.
  • Enbridge is expanding the existing Athabasca pipeline by twinning it and adding an additional 127.1 103 m3/d (0.80 106 bbl/d) of capacity. The expected in-service date is 2017.
  • Table 9.1 [HTML] and Table 9.2 [HTML] list Alberta’s intraprovincial and removal pipelines. Table 9.3 [HTML] lists selected North American pipeline system developments.

Table 9.1
Table 9.2

Table 9.3

Natural Gas Liquids Pipelines

  • Demand for condensate has been exceeding Alberta’s supply since 2004, and Alberta now relies on condensate imports to meet diluent demand.
  • The Vantage pipeline was commissioned in June 2014 and delivers ethane from North Dakota to Alberta. In early 2015, plans were announced to expand the capacity to 10.8 103 m3/d (68.4 103 bbl/d); the expanded pipeline was put into service in the third quarter of 2016.
  • Pembina Pipeline Corporation’s Phase III Expansion project involves the construction of four pipelines from Fox Creek to the Edmonton area with a total capacity of 159.0 103 m3/d (1.0 106 bbl/d) and would transport ethanes plus, propanes plus, condensates, and crude oil. The anticipated in-service date is 2017.
  • Alberta diluent demand is expected to increase in conjunction with growing oil sands production. Table 9.6 [HTML] lists new pipeline projects that have been proposed to provide diluent for bitumen and heavy oil blending.

Figure 9.3

  • Figure 9.3 [Tableau] shows Alberta’s ethane gathering and delivery systems.

Table 9.4

Table 9.5

Table 9.6

Natural Gas Pipelines

Figure 9.4

  • Figure 9.4 [Tableau] illustrates major gas pipeline systems in Canada and major export points for Alberta’s natural gas.
  • Exports of Alberta natural gas to the United States have been on the decline over the past several years, while imports of natural gas to Canada from the United States, primarily a result of increasing U.S. shale gas production, have been increasing and backing western Canadian gas out of eastern Canadian markets.
  • In addition, the Rocky Express Zone 3 pipeline, which was placed into service in 2016 and transports Marcellus natural gas production, competes with western Canadian production in the U.S. Midwest markets.
  • Given the relatively close proximity of U.S. shale gas production to southern Ontario markets, new pipeline projects have been proposed, such as the South to North (SoNo), NEXUS, and Rover Gas Transmission projects, that would carry natural gas sourced from the Marcellus shale to hubs connected to Ontario markets. The proposed projects are listed in Table 9.9 [HTML].

Table 9.9

  • TransCanada is expanding the NOVA Gas Transmission Ltd. (NGTL) system. The expansion involves multiple projects that would add 76 106 m3/d (2.7 billion cubic feet per day) of natural gas transportation service in response to growth in unconventional natural gas supplies in northwestern Alberta and northeastern British Columbia. All facilities are expected to be in service in 2017.
  • TransCanada is moving forwards with the Saddle West project, which is aimed at adding an additional 10 106 m3/d (355 million cubic feet per day) to the NGTL system. The project is intended to address increased transportation needs for natural gas from the Montney, Duvernay, and Deep Basin Formations. The project is scheduled to begin construction in 2018.
  • TransCanada has also announced the Eastern Mainline project, which would transport gas from Markham Ontario to Iroquois Ontario. The project is scheduled to be in service in 2019, pending approval.
  • Table 9.7 [HTML] and Table 9.8 [HTML] list Alberta’s natural gas intraprovincial and removal and import pipelines, respectively.

Table 9.7

Table 9.8