Canadian Crude Closes the Gap

There have been plenty of headlines written about oil’s rise back to around $60 a barrel lately, but there’s another story unfolding north of the border that’s been largely ignored. That’s the startling jump in the price of Alberta crude, as measured by the Western Canada Select (WCS) price. Back on March 17, WCS was trading at US$29.71, according to oilprice.com.

But fast-forward to last Friday’s close, and WCS was perched at around US$51.09, a 72% surge in just over two months, according to data from the Petroleum Services Association of Canada. That’s nearly double the 37% gain notched by the US benchmark West Texas Intermediate (WTI) price in the same timespan.

The net result is a narrowing of the gap between the two blends to around US$9. That’s a stunning reversal from last year, when it averaged US$19.40, and late 2012, when it ballooned out beyond US$40.

Though it’s widely underreported, WCS is important because it accounts for most of Canada’s oil. It’s a blend of conventional heavy crude oil and bitumen–the thick, tar-like crude from the Alberta oil sands.

“If you are looking at the performance of a Canadian Natural Resources Ltd., or Cenovus Energy Inc., or Northern Blizzard Resources Inc., or Pengrowth Energy Corp., or Twin Butte Energy Ltd. or a host of others, a big part of their exposure will be to heavy crude,” National Bank of Canada head of commodities Tim Simard said in a May 4 Financial Post article.

The Deal on the Discount

WCS historically trades below WTI for two main reasons: It needs more refining and involves higher shipping costs. Those extra expenses eat into refiners’ margins, so they pay Canadian producers less per barrel.

That’s one piece of the puzzle. The other is the wild swings we’ve seen in the gap between WCS and WTI in recent years, and that’s been closely tied to market access—or lack thereof—for Canada’s crude.

Back in 2012, when producers up north were feeling the pinch of a $40 differential, their crude was being squeezed out of pipelines to key U.S. refineries by competition from booming U.S. shale regions.

At the same time, some of the refineries capable of handling Canada’s heavy crude were down for maintenance, including BP’s Whiting facility in Indiana, which was undergoing a US$4-billion refit to boost its oil sands intake. Whiting reopened in late 2013.

Add in the ongoing political fracas over TransCanada Corp.’s (TSX: TRP, NYSE: TRP) Keystone XL pipeline and other controversial conduits, such as Enbridge Inc.’s (TSX: ENB, NYSE: ENB) proposed Northern Gateway pipeline from Alberta to the British Columbia coast, and the result was a bitumen glut that handcuffed Canadian prices.

But nature abhors a vacuum, as the old saying goes, and railways and pipeline operators have leaped into the breach.

Capacity Boost 

As someone who lives a stone’s throw from a CN Rail line linking Central Canada to the West, I can attest to the sharp jump in the number of tanker cars riding the country’s rails in the last few years.

The latest figures from the National Energy Board back that up: They show that Canada’s crude exports by rail averaged 171,000 barrels a day in 2014, compared to just 46,000 back in 2012.

But the oil trains aren’t the only tool producers are using to get their product to market. New and expanded pipelines are playing a big role, too. Enbridge, for example, started up its 600,000-barrel-a-day Flanagan South pipeline last December, giving Canadian crude greater access to refineries on the U.S. Gulf Coast.

To get it there, the company first ships the oil to terminals in Illinois on its existing system–thereby circumventing the need for a presidential permit–where Flanagan South picks it up and takes it to the Cushing, Oklahoma, storage hub. From there, the diluted bitumen catches a ride on the recently beefed up 850,000-barrel-a-day Seaway system to the Gulf Coast.

In all, about 377,000 barrels of Canadian crude a day made its way to Gulf Coast refineries in January 2015, according to the U.S. Energy Information Administration, compared to just 100,000 barrels a couple of years ago.

At the same time, a general slowdown in oil drilling should clear some room for oil sands crude on existing lines.

“With production expected to be coming off through the spring due to oil prices, I expect that this will free up some of the space on the major trunk lines, which should be positive for differentials through the summer,” said Genscape analyst Carl Evans in an April 25 Calgary Herald article.

Producers Ante Up

To be sure, some of the rise in WCS prices is tied to seasonal factors, like the start of the summer driving season (forecast by AAA to see the highest fuel consumption since 2007) and increased demand for asphalt, a key use for oil sands crude, as road construction season kicks in.

And of course, we remain in a weak oil-price environment, with WTI down about 40% from year-ago levels. Nonetheless, Canadian producers can likely count on a price that tracks more closely to WTI in the near term, thanks to the new shipping options and refinery upgrades.

Producers, for their part, seem optimistic: They recently shelled out an average of US$978 an acre in offerings of oil sands rights through the end of April. That’s the most since 2007, according to a May 15 Financial Post article.

“Right now it makes a great deal of sense to go in and acquire rights in the oil sands,” said Trevor Newton, chairman of Strata Oil & Gas (OTC: SOIGF). “Let’s get this now while we can. We are going to get them cheaper.”

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