March 2017, Vol. 244, No. 3


Watching North America’s Pipeline Renaissance

By Nicholas Newman, UK Contributing Editor

This could be a good year for oil and gas pipeline project approvals in North America. The new administrations in Canada and the United States have given permission to proceed for long-delayed oil and gas pipeline schemes that improve capacity to move crude and gas from their source to markets.

In the U.S., perhaps least contentious, is the US$3 billion, 200-mile Atlantic Sunrise natural gas pipeline expansion in the Northeast. Bigger and more in the public eye, are TransCanada’s Keystone XL pipeline and the completion of the US$3.8 billion Dakota Access pipeline.

In Canada, there is Kinder Morgan’s Trans Mountain CN$ 6.8 billion line and Enbridge’s CN$7.5 billion Line 3 expansion project designed to carry 760,000-bpd of both light and heavy oil. Similarly, across the border, Enbridge plans a US$6.2 billion replacement project for its Line 3 pipeline running from Neche in ND to Superior, WI.

Research group, IHS Markit estimates that 9,679 miles of crude oil pipelines were constructed in the U.S. in 2014. For 2017, the researchers forecast large projects, including completion of the Dakota Access, pipe will account for 4,175 of construction.

Canadian Projects

In November 2016, Canadian Prime Minister Justin Trudeau allowed the go-ahead for two major oil export pipelines. The first is the CN$7.5 billion, 1,660-km Enbridge Line 3 replacement and expansion project, which will almost double capacity of light and heavy oil from Hardisty, Alberta through Saskatchewan and Manitoba to a terminal on the western tip of Lake Superior, WI for distribution to markets including refineries in the Chicago area (Figure 1).

Figure 1: Source: Enbridge
Figure 1: Source: Enbridge

The second is the 490,000-bpd expansion to Kinder Morgan’s existing Trans Mountain export pipe, which carries Alberta oil from Edmonton to an export terminal port in Burnaby, BC for shipment to China, Japan, South Korea and Taiwan. In reality, this is an expansion of an existing 300,000-bpd pipeline linking Strathcona County (near Edmonton) via a 1,150-km pipeline to Burnaby, BC (Figure 2).

Figure 2: Source: Transmountain
Figure 2: Source: Trans Mountain

At the same time, Trudeau canceled proposals for the long-delayed CN$7.9 billion Northern Gateway pipeline, which was intended to transport crude oil from Alberta to a new marine terminal at Kitimat, on Canada’s Pacific Coast. Still under consideration but facing a serious delay, is TransCanada’s CN$12 billion Energy East proposal, which would be designed to shift Alberta oil to refineries on Canada’s Atlantic margin for processing to serve Eastern Canadian markets and for onward export to Europe and New England markets (Figure 3).

Figure 3: Source: TransCanada
Figure 3: Source: TransCanada

U.S. Projects

In his first few days in office, President Trump greenlighted two pipeline projects that dominated headlines. The first is for the 1,179-mile U.S. section of TransCanada’s US$5.4 billion Keystone XL Pipeline, designed to export oil from Bindloss, Alberta to Steele City, NB where a connection to an existing pipe will deliver the oil to Gulf Coast refineries. It could carry as much as 830,000 bpd (Figure 4).

Figure 4: Source: NPR
Figure 4: Source: NPR

The second is the 1,172-mile Dakota Access Pipeline, which will carry between 470,000-570,000 bpd of North Dakota’s northwest Bakken shale oil in a straight line through South Dakota and Iowa, ending at a tank farm near Patoka, IL. With 87% already constructed in November 2016, its completion is expected by June. (Figure 5).

Figure 5: Source: VOA
Figure 5: Source: VOA

Are These Necessary?

The question that both pipeline developers and their bankers need to ask is whether such additional pipeline capacity is commercially viable in the short and medium term. In the U.S., a burst of pipe construction in 2014-15 to accommodate booming shale oil and gas output was followed by a collapse in prices, a subsequent downturn in output and many pipelines suffering from excess capacity. On the other side of the border, in contrast, existing pipeline congestion has meant Western Canada oil producers have endured discounts of over CN$30 a barrel to internationally traded Brent.

Nevertheless, the question of timing remains. Is now the right time to invest, given that oil prices are fluctuating at $56 a barrel? Are these projects bankable? Cheap oil, booming U.S. production running at about 9 MMbpd, may reduce the need for imported crude from Western Canada. Similarly, oil prices below $60 a barrel raise the question of the viability of Canada’s reserves of heavy oil sands.


Professor Thomas Gunton, director of Resource and Environmental Planning at Simon Fraser University, British Columbia, predicts, “If all the total proposed pipeline network plans are completed by 2025, there could  be 51% extra pipeline capacity than needed to export crude oil production from Western Canada.”

Supporting this view, Clark Williams Derry, director of Energy Finance at the Sightline Institute in Seattle, a progressive-leaning think tank, estimates that “such proposed pipeline capacity is unlikely to be filled in the short term.”

However, the Canadian Association of Petroleum Producers (CAPP) has claimed that “new major oil pipelines are urgently needed” to deliver oil safely and reliably to world markets. CAPP said Canada’s oil pipeline system can only transport 4 MMbpd, and last year conveyed 3.98 MMbpd.

CAPP forecasters expect oil sands production growth to add 850,000 bpd by 2021. This means the existing pipeline capacity will prove insufficient to meet future needs. Time will tell which of these views prevail in practice. However, project developers also have to factor in other considerations. A case in point is that of the Trans Mountain project.

As Ali Hounsell, a spokeswoman for Kinder Morgan, developer of the Trans Mountain pipeline, said, “Kinder Morgan signed 15- and 20-year contracts with shippers in 2012. Regardless of whether Keystone XL gets back on track, Kinder Morgan will move ahead with the Trans Mountain project.”

North America

Likewise, there are mixed views on capacity south of the Canadian border. According to experts from the U.S. Energy Information Administration and the North Dakota Pipeline Authority (NDPA), the current depressed output in the Bakken shale oil region of North Dakota will be insufficient to fill the Dakota Access Pipeline (DAP).

The Bakken shale fields produce about 1 MMbpd, an amount expected to decline during 2017. The region’s existing pipelines and refineries can now handle 851,000 bpd. This means, in effect, that once completed the Dakota Access Pipeline may create 300,000 bpd of spare capacity. This spare capacity is unlikely to be used by oilfield producers located along the southern half of its route, since they already have access to existing pipeline and rail-export capacity.

Given this scenario, might it make better economic sense to let the market recover before completion of Keystone XL? Might it not also be wise for Alberta’s oil sands producers to use railcars to freight oil to North Dakota for shipment on the Dakota Access Pipeline? The Trans Mountain expansion and the Enbridge Line 3 replacement projects raise off-take capacity from Western Canada and could be in competition with the Keystone XL pipeline.


Getting approvals for new major pipelines have proved increasingly difficult in the last years of the previous administration. However, the new administration’s America First Energy Plan has boosted confidence and improved the business environment for U.S. oil and gas producers, and pipeline construction developers.

Should a border-adjusted tax system come into being, however, it would tax imports of Canadian crude and raise prices above U.S. supplies, thereby throwing the economics of the Keystone XL project into doubt.


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