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Irina Slav

Irina Slav

Irina is a writer for Oilprice.com with over a decade of experience writing on the oil and gas industry.

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Alberta’s Price-Correcting Plan Backfires

When Alberta’s government announced obligatory oil production cuts last December, it was a desperate attempt to arrest a price slide of the local crude benchmark that had led to discounts of over US$50 a barrel compared to WTI. Now, the discount is less than US$10, and not everybody is happy about it.

Albertan producers are already pressured by insufficient pipeline capacity as the Trans Mountain expansion projects gets bogged down in lawsuits and lack of investor interest, and as Line 3’s expansion was delayed for six months. Now, they are also feeling the pressure of costly oil-by-rail transport.

Oil-by-rail has emerged as the only viable alternative to pipelines for local oil producers. In fact, last November the government of Canada’s oil province announced it was buying more oil trains. These have a total capacity of 120,000 bpd and will cost Alberta US$264 million (C$330 million). The trains should reach their full capacity later this year and help to reduce the discount of Western Canadian Select to West Texas Intermediate by about US$3 (C$4) per barrel. Right now, however, a smaller discount is the opposite of what the industry may need, according to some.

Bloomberg’s Robert Tuttle recently wrote how Canadian crude became from too cheap to too expensive in a matter of months after the production cuts were announced. Now, WCS needs to be US$15 cheaper than Mexico’s Maya heavy to be competitive for Houston refiners, according to IHS Markit director of crude oil markets in North America, who spoke to Tuttle.

“It now appears that the government may have overshot slightly,” Kevin Birn said. “The market is always going to be more complicated than people anticipate.” Related: What’s Keeping Oil From Rallying To $75?

Indeed, the market is more complicated than that. In addition to pipeline capacity shortages and costly oil-by-rail, now traders are shunning long-term crude oil contracts for Canadian crude because of the uncertainty surrounding production in the short term.

“I won’t take any forward positions in Canada right now. Everyone is wondering what the government is going to do ... one announcement can ruin your year,” one trading source told Reuters earlier this month. This is a problem for the industry because the only way producers can lock in forward oil prices is through contracts for later delivery. With that option reduced, both producers and refiners in Canada and the United States have become more vulnerable to unfavorable price swings.

But the complication may eventually work in Albertan producers’ favor. The global supply of heavy crude is falling thanks to U.S. sanctions against Venezuela, which have reduced the flow of Venezuelan heavy to Gulf Coast refineries to zero. It is also falling thanks to the latest OPEC production cuts: the cartel’s biggest producers are cutting their heavy oil production and not their light crude output.

Demand for heavy crude, meanwhile, is steady. Some expect it to rise substantially in the coming months as refiners prepare for the new IMO sulfur emission rules due to come into effect next year. To produce low-sulfur bunkering fuel, they need heavy crude, and not just the light sweet oil from the shale patch.

So, it’s tough to be in Alberta oil right now, but if demand for heavy crude remains healthy, it will make the North American market a sellers’ market. In a sellers’ market, Canadian crude will be a lot more competitive with the Mexican grade. This should relieve some of the load, at least temporarily.

By Irina Slav for Oilprice.com

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