Pipelines

ST98

Updated March 2018

In 2017, the Government of Canada introduced Bill C-48, the Oil Tanker Moratorium Act, which if passed by government would ban oil tankers carrying roughly 90 000 barrels of crude oil or persistent oil products as cargo from stopping, loading, or unloading at ports in northern British Columbia. This moratorium supports the government’s Oceans Protection Plan, which could affect the amount of oil shipped on a pipeline to British Columbia.

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 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.

TransCanada Corporation’s (TransCanada’s) Keystone XL project received approval from the U.S. Department of State in March 2017 authorizing TransCanada to construct, connect, operate, and maintain pipeline facilities to export Canadian crude oil to the United States. In November, the Nebraska Public Service Commission rejected the company’s preferred route but approved an alternate path that will continue to run from Hardisty, Alberta, to Steele City, Nebraska, clearing the last regulatory hurdle. The proposed pipeline would add 131.9 thousand cubic metres per day (103 m3/d)—0.83 million barrels per day (106 bbl/d)—to current pipeline capacity.

TransCanada cancelled the proposed Energy East project in 2017 citing regulatory obstacles. This pipeline would have carried more than 158.9 103 m3/d (1.00 106 bbl/d) of crude oil and crude bitumen blended with diluent from Hardisty, Alberta, to Saint John, New Brunswick.

Enbridge Inc. (Enbridge) received approval from the U.S. Department of State in October 2017 to expand Line 67, also known as the Alberta Clipper, and ship as much as 127.1 103 m3/d (0.80 106 bbl/d) of oil from Hardisty, Alberta, to Superior, Wisconsin.

The Dakota Access Pipeline, a joint venture between Energy Transfer Partners and MarEn Bakken Company LLC, which runs through four states, was placed in service in June 2017, delivering 74.7 103 m3/d (0.47 106 bbl/d) of crude oil from North Dakota to Illinois.

Kinder Morgan’s Trans Mountain expansion project, running from Edmonton, Alberta, to Burnaby, British Columbia, will add 93.8 103 m3/d (0.59 106 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 project, 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.

TransCanada’s proposed Heartland pipeline would link Edmonton and Hardisty. The pipeline has an initial capacity of 95.3 103 m3/d (0.60 106 bbl/d), and TransCanada anticipates that the pipeline could ultimately transport up to 143.0 103 m3/d (0.90 106 bbl/d) of oil. The current regulatory approval licence expires in May 2019.

TransCanada is developing the Grand Rapids project as part of a joint venture with PetroChina Company Limited, formerly known as 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 began service in 2017. 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 expanded its existing Athabasca pipeline by twinning it and adding an additional 127.1 103 m3/d (0.80 106 bbl/d) of capacity in 2017.

Table 9.1 [HTML] and Table 9.2 [HTML] list Alberta’s intraprovincial and removal pipelines, respectively. Table 9.3 [HTML] lists selected North American pipeline system developments.

Table 9.1

Table 9.2

Table 9.3

Market Access

As indicated in Table 9.2 [HTML], the total takeaway capacity to move Alberta oil exports to outside markets is 671.0 103 m3/d (4.22 106 bbl/d). Taking into account Alberta’s marketable oil removals, estimated at 397.3 103 m3/d (2.50 106 bbl/d) in 2017, and considering other western Canadian production and U.S. receipt volumes, there is currently enough spare pipeline capacity in the system; however, given high utilization rates, temporary disruptions can result in pipeline apportionment. Alberta exports will begin to reach pipeline capacity limits in 2021 based on the oil removal forecasts in this report and on existing pipeline export capacity. With the addition of one or both of the federally approved export 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.

Alberta’s removal pipelines allow the province’s oil to be tied-in and transported to markets across North America, with smaller volumes reaching international markets. Refineries, which use oil as a feedstock to produce refined petroleum products, represent the demand centres for Alberta’s oil.

There are sixteen refineries located across Canada, eight located in eastern Canada and eight located in western Canada, with a combined processing capacity of 0.30 106 m3/d (1.9 106 bbl/d). The total processing capacity in the United States is over 2.8 106 m3/d (18 106 bbl/d), with refineries separated into five market regions based on the Petroleum Administration of Defense Districts (PADDs). The United States has the highest number of complex refineries (capable of processing heavier sour crudes) in the world.

Alberta’s oil is able to reach markets in Ontario and Quebec through Enbridge’s Mainline system. According to Statistics Canada, synthetic crude oil (SCO) processed at Ontario refineries represented, on average, over 60 per cent of the crude oil inputs in the first eight months of 2017, with crude bitumen representing on average over 15 per cent. With the completion of Enbridge’s Line 9 pipeline reversal project in 2015, western oil is able to reach refineries in Quebec. In the first eight months of 2017, the amount of SCO processed in Quebec represented on average over 40 per cent of the crude oil inputs, and crude bitumen represented on average just over 5 per cent. In order for western oil to reach refineries in the Atlantic provinces, western producers are limited to using higher-cost rail. However, western producers are disadvantaged in the Atlantic provinces because they must compete with international imports using lower-cost shipping.

With significant complex processing capacity, refineries in the United States are a major consumer of Alberta’s heavier crudes. Alberta’s heavy oil removals (nonupgraded bitumen and heavy conventional oil) represent over 60 per cent of Alberta’s total oil removals, with most going to markets in PADD 2 and PADD 3. On average, in the first eight months of 2017, Canadian oil represented about 98 per cent of PADD 2 total imports and about 12 per cent of PADD 3 imports. Given the close proximity of PADD 2 refineries to Alberta, oil producers receive the best price for selling their product in the PADD 2 market, followed by PADD 3.

With the recent approval of Keystone XL, TransCanada’s decision to cancel the Energy East pipeline was not unexpected. The Energy East pipeline system would have carried 158.9 103 m3/d (1.00 106 bbl/d) of oil, with receipt points in Alberta, Saskatchewan, and North Dakota, to refineries in eastern Canada and eventually to Saint John, New Brunswick. Given that most of the refinery processing capacity in eastern Canada is for lighter grades of oil, and with no announcements of any capital-intensive conversion projects, most of the oil processed would have been lighter grades. TransCanada’s Keystone XL northern pipeline portion, if constructed, will connect Alberta oil to the U.S. Gulf Coast (PADD 3), the largest complex refinery hub in the world, which also has access to tidewater.

The Trans Mountain pipeline system is the only crude oil pipeline to Canada’s west coast. From the coast, oil can be exported to PADD 5 refineries, the U.S. Gulf Coast, and to markets in Asia. The Trans Mountain expansion project will increase capacity by 93.8 103 m3/d (0.59 106 bbl/d), bringing total capacity to 141.4 103 m3/d (0.89 106 bbl/d). The expansion opens up opportunities for Alberta producers to export additional volumes and reach refineries in China and India. China and India are both considered emerging economies and represent a significant portion of current and future global crude oil demand, driven by demographics, strong plastics manufacturing, and transport demand. China’s market is attractive to Alberta crude producers because Chinese refineries can process heavier crudes with some refineries undergoing conversion projects for hydrocracking. China is also anticipated to become the world’s largest importer of crude oil within the next few years because its domestic oil production is declining, requiring increased imports to fill the supply gap. Imports are also anticipated to be supported by the Chinese government, which has been actively encouraging market diversification for energy security.

Natural Gas Liquids Pipelines

Demand for condensate has been exceeding Alberta’s supply since 2004, and Alberta now relies on condensate imports primarily from the United States from Southern Lights and Cochin pipelines to meet diluent demand.

In March 2016, Plains Midstream Canada ULC (PMC) acquired assets from Spectra Energy Corporation including a fractionation facility and a pipeline. The pipeline adds 2.5 103 m3/d (15.5 103 bbl/d) to PMC’s NGL infrastructure capacity, with first volumes reaching Manitoba in December 2017.

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 (68.40 103 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 (1.00 106 bbl/d). This system will transport ethane-plus, propane-plus, condensates, and crude oil, and was in service in 2017.

Alberta diluent demand is expected to increase in conjunction with growing oil sands production.

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

Figure 9.3

Table 9.4 [HTML] and Table 9.5 [HTML] list Alberta’s intraprovincial and interprovincial natural gas liquid (NGL) pipelines, respectively. Table 9.6 [HTML] lists selected Alberta NGL pipeline system developments.

Table 9.4

Table 9.5

Table 9.6

Natural Gas Pipelines

Figure 9.4

Figure 9.4 [Tableau] shows the major gas pipeline systems in Canada and major export points for Alberta’s natural gas.

TransCanada filed and notified the National Energy Board in October 2017 that it will no longer be proceeding with its Eastern Mainline applications. The project would have transported natural gas from Markham to Iroquois, Ontario.

Alliance Pipeline is considering a potential capacity expansion of 14.1 106 m3/d—500 million cubic feet per day (MMcf/d)—of new capacity to their liquids rich natural gas pipeline due to high demand for transportation service to the Chicago market hub. The projected in-service date is 2021.

The Rockies Express Pipeline (REX) Zone 3 bidirectional capacity enhancement project was completed and brought in service in 2017. REX Zone 3 can transport up to 73.3 106 m3/d—2.60 billion cubic feet per day (Bcf/d)—of Appalachian natural gas from Clarington, Ohio, to Mexico, Missouri.

Given the relative 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) and NEXUS. The proposed projects are listed in Table 9.9 [HTML].

Phase 1A of the Rover pipeline project was completed and put in service in 2017, which would carry natural gas sourced from the Marcellus and Utica shale to hubs connected to Ontario markets, backing western Canadian natural gas out of the eastern Canadian markets. The Rover pipeline project is expected to be in full service in 2018.

TransCanada is expanding the NOVA Gas Transmission Ltd. (NGTL) system. The expansion involves multiple projects that would add 76.1 106 m3/d (2.70 Bcf/d) of natural gas transportation service in response to growth in unconventional natural gas supplies in northwestern Alberta and northeastern British Columbia. Most of the facilities were completed and in service in 2017, with the exception of Boundary Lake spread 2 of the Northwest Mainline Loop, scheduled to be in service in 2018.

TransCanada is moving forward with the Saddle West project, which is aimed at adding an additional 10.0 106 m3/d (355 MMcf/d) 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 in service in 2019.

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

Table 9.9