CALGARY, Alberta (Reuters) - Oil traders still grappling with an unprecedented pipeline bottleneck in the U.S. Midwest that roiled global energy markets last year should beware: Canada may be next.
The pipelines that carry crude from Alberta’s oil sands and the Bakken shale fields of North Dakota to U.S. refiners may run out of capacity as soon as 2015, some analysts now warn.
Fears that the export of Canadian crude will be constrained have risen recently as a result of pipeline project delays and the unyielding growth of North Dakota output. Any resulting glut could weaken Canadian oil prices, depress profits for producers like Suncor Energy Inc and Cenovus Energy Inc and choke growth in the largest source of U.S. imports.
A crisis could be avoided, though. Major pipeline operators like Enbridge Inc say they’re confident that an estimated 1 million barrels per day (bpd) of idle capacity on existing Canada-to-U.S. lines is more than enough for up to five years, sufficient time to complete new lines or add pumps.
That view is by no means unanimous.
“New capacity is needed by the 2014-2015 period or we’re really going to be squeezed,” said Steve Fekete, managing consultant at international oil consultancy Purvin & Gertz, which completed a major pipeline study last autumn.
“Tight oil out of North Dakota (is) rapidly increasing and could chew up capacity perhaps more quickly than our forecast,” he said, referring to the crude oil prised from shale by injections of water and chemicals.
Call it a “Cushing moment” for Canada, the world’s No. 6 oil producer — a dire scenario in which surplus crude would start to pile up in the storage tanks of Hardisty, Alberta, like the glut that developed in the U.S. oil crossroads of Cushing, Oklahoma, a year ago.
The possibility of a Canadian choke-point has arisen because of two recent, unexpected developments: The U.S. rejection of the Keystone XL project, the biggest trans-national pipeline expansion; and the stunning growth of North Dakota’s Bakken shale.
The government is also taking action. Canada is set to push forward new measures to cut approval times for major pipeline projects in order to speed the completion of proposed routes to the Pacific Ocean and refiners in Asia.
“At a certain point there will be an issue (with capacity),” Joe Oliver, Canada’s natural resources minister, said in an interview this week. “We remain optimistic that pipelines can be built in time to avoid ... the kind of problem they have in Cushing.”
Last year, the rapidly growing glut of crude trapped in the Midwest caught most of the industry unprepared, forcing traders and producers to use railways, barges and tank trunks to compensate for the lack of north-to-south pipelines. Most U.S. conduits were built to transport imported or Gulf Coast crude to the interior of the country, not the reverse.
Jitters over pipeline capacity are reflected in the cash market for spot Canadian crude. Earlier this month, the price for the synthetic crude created from oil sands bitumen tumbled after a car crash in Illinois shut down a major line south. Its discount to benchmark U.S. West Texas Intermediate futures was nearly doubled by the conduit’s closure for nearly a week, which trapped volumes in Western Canada.
There’s some indication that operators have taken note.
Enbridge is now looking at ways to ensure that a possible expansion of its network from North Dakota won’t congest its main Canada-to-U.S. trunk line, says Vern Yu, vice-president of business development.
“We’re going to make sure that where that crude ties into our system it doesn’t create a choke point. That’s what we’re scoping out right now,” he said in an interview. Details of the new Bakken project may be released in May, he added.
For the moment there is more than enough capacity in existing pipelines to compensate for most disruptions, even after a 20 percent rise in exports since 2010.
In all, Yu estimates that by using its latent capacity and reshaping what its pipelines carry, Enbridge could find space for an additional 1 million bpd of new production, more than enough to service an expanded 585,000 bpd Flanagan South project announced on Tuesday.
In 2011, Western Canada’s oil production totaled around 2.6 million barrels per day, with 1.58 million bpd coming from the oil sands and the remainder from conventional sources — still fitting comfortably within Canada’s available export pipeline space of around 3.6 million bpd.
However by 2015, oil sands output is expected to rise to 2.2 million bpd and, including conventional crude, total will reach about 3.55 million bpd, according to the Canadian Association of Petroleum Producers (CAPP’s) benchmark annual forecast issued last June.
“It’s something we’re watching very closely,” said Greg Stringham, vice-president of markets at CAPP. “We see tightness coming in 2014 and 2015.”
Canadian crude is only half the story.
Even if producers can get oil south of the border, booming output from North Dakota’s shale oil fields is increasingly flowing into the same trunk lines from Canada. It must then travel another 500 miles south to major Midwest refineries, intensifying congestion along that narrow but crucial stretch.
A C$180 million ($182 million) Bakken expansion project will take 145,000 barrels per day of crude from North Dakota by 2013, pushing Enbridge’s outbound capacity from the state to 350,000 barrels. A second such project is now being considered.
Canada now has three major pipelines taking conventional and oil sands crude into the Midwest. The largest is Enbridge Inc’s mainline system, which carried nearly 1.55 million bpd last year, shy of its design limit of 2.5 million bpd. It runs as far east as Sarnia, Ontario, and south to Cushing.
About 300,000 or 400,000 bpd of the spare capacity can be accessed immediately, says Yu. But it could take as much as a year or two in order to reach maximum output, which would require the installation of additional pumps.
“Our expectation is that capacity will be needed, depending on supply growth, anywhere between 2015 and 2017,” he added.
Two more pipelines that run from Alberta to Superior, Wisconsin, also offer additional space: the 450,000 Alberta Clipper pipeline, opened in 2010 and still running under capacity — though Enbridge does not disclose its utilization rates — and the 796,000 bpd Line 4, which now handles heavy oil from Alberta.
Yu says Enbridge could convert its 390,000 bpd Line 3 — which now runs light and synthetic crude, as well as natural gas condensates and some light sour crudes — to run heavy crude.
Other companies’ lines are effectively maxed out, including TransCanada Corp’s existing 591,000 Keystone oil line and Kinder Morgan Energy Partners’ 280,000 bpd Express-Platte system into southern Illinois.
Until about a year ago, a squeeze seemed unlikely. After years of environmental reviews, TransCanada’s $7 billion Keystone XL project seemed set to get approval to add as much as 830,000 barrels per day of new capacity by 2013.
But the project became mired in U.S. political infighting and opposition from environmental groups. In January, the Obama Administration denied the project its necessary State Department permit, forcing it to re-apply for approval.
Although TransCanada now has Obama’s blessing to move forward on building the line’s southern Cushing-to-Houston leg, it may have to wait until after the November presidential election to start work on the cross-border portion of the line, which it now hopes to complete only by 2015.
“There seems to be increasing support for the project in the U.S.,” said Paul Lechem, an analyst at CIBC World Markets. “We’ll see if it gets built on schedule, but it seems that things are starting to line up a little bit better there.”
Efforts to shift more oil to its Western ports — alleviating capacity fears and also reducing producers’ total dependence on the U.S. market — also face fierce resistance from environmentalists and aboriginal groups.
Regulators have extended lengthy public hearings into Enbridge’s 525,000 bpd Northern Gateway project due to the volume of complaints, while Kinder Morgan has yet to apply for regulatory approvals for plans to double the size of its existing 300,000 bpd Trans Mountain pipeline.
A larger question also looms: Will U.S. refiners be willing to buy all this thick, sulphurous crude?
BP Plc is modernizing its 405,000 bpd refinery at Whiting, Indiana, in order to boost its use of heavy Canadian crudes as a feedstock, while Marathon Petroleum Corp’s Michigan plant is in the midst of an overhaul to boost heavy crude intake by 13 percent to 120,000 bpd.
Beyond that, however, plans are limited. So instead, many want to move into new markets like the refining cluster on the U.S. gulf coast, the end point of Keystone XL and the Seaway pipeline that Enbridge and Enterprise Product Partners are reversing and expanding.
“We have capacity on our system but we can’t use all of it today because there aren’t downstream markets for all of it,” says Enbridge’s Yu. “By the end of this year we may have spare capacity but we won’t have markets for it.”
($1 = $0.99 Canadian)
Editing by Alden Bentley