Why Alberta oil will be California-bound

But Asia rises as potential market for Trans Mountain crude: analysts

Oil tankers, like this one at Burnaby’s Westridge Marine Terminal, will likely be heading primarily to California | Submitted

Alberta Premier Rachel Notley was in B.C. last week meeting with select media outlets in an effort to sell British Columbians on the Trans Mountain pipeline expansion.

The $6.8 billion project is needed, she has said, to open Alberta oil exports to new markets, particularly Asia. But critics say the 13 shippers and oil producers that signed take-or-pay contracts (in which a company either takes product from the supplier or pays a penalty) for the pipeline expansion don’t have any customers in Asia yet, and, even if they did, they would get no better price there for their oil.

Getting social licence from B.C. may be a moot point, one economist argues, if low oil prices and a carbon-constrained world mean the economics for new pipelines no longer work.

Former CIBC economist Jeff Rubin has said new pipelines don’t make economic sense anymore because if Canada and other countries live up to their commitments to reduce greenhouse gases, the world’s oil consumption will shrink by 25% within the next 25 years.

That’s in stark contradiction to U.S. Energy Information
Administration (EIA) projections of a 21 million barrel per day increase in petroleum production between 2020 and 2040, and the International Energy Agency (IEA), which forecasts: “Global oil demand continues to grow until 2040, mostly because of the lack of easy alternatives to oil in road freight, aviation and petrochemicals.”

Even if the Trans Mountain expansion does give Alberta oil producers access to Asian markets, they won’t get any more for their oil there than they do in the U.S. and would, in fact, get less, according to Rubin.

Robyn Allan, former senior economist for BC Central Credit Union, agreed, saying the U.S. pays more than China does for the type of heavy crude that comes out of Alberta.

The oil produced in the oilsands has lately sold at a US$15 per barrel discount compared with West Texas Intermediate, which last week was selling for about US$51 per barrel.

Western Canadian Select – the heavy crude produced in Alberta – is discounted not because Canada is a captive customer of the U.S., Allan said, but because it is a lower grade of oil that requires additional refining, which adds to the cost. She said China pays less for these heavy crudes than the U.S. does.

The Trans Mountain expansion would increase the pipeline’s capacity by 690,000 barrels per day (bpd) through a new twinned line.

According to Allan’s analysis of the Trans Mountain business case, most of the additional oil that would flow through the expanded pipeline would still be going to the U.S. – specifically California – not Asia.

“Markets for Canada’s crude oil in Asia do not exist and have not been developed despite serious regulatory and commercial efforts to do so,” she wrote in an economic analysis commissioned by the Tsleil-Waututh Nation.

So what are Trans Mountain proponents talking about when they insist the expansion is needed to get Alberta oil to foreign markets, unless they consider California a foreign market?

Travis Whalen, an energy analyst for S&P Global Platts, agreed that the biggest new market would be California, not Asia, at least initially.

“A lot of that is going to be going to the U.S. but a lot of that is going to be seeking global oil prices in tidewater,” he said.

Most of the oil produced in Alberta goes to U.S. refineries on the Gulf Coast by pipeline. California is an isolated region not served by major pipelines. Its refineries, which are set up to process heavy crudes like the kind produced in Alberta, bring oil in by tanker from other countries and by rail from Canada.

An expanded Trans Mountain pipeline would allow more oil from Alberta to move to California by tanker, which is much cheaper than rail. And that would raise the price of oil for Alberta producers, Whalen said.

“There will absolutely be a price lift,” he said.

As for future markets, most of the new refining capacity in the world today is being built in Asia.

A recent analysis by Gaffney, Cline & Associates predicts that new Asian refineries will add six million barrels of oil per day between now and 2018, with China accounting for 55% of that new capacity and India 24%.

Afolabi Ogunnaike, a Wood Mackenzie oil analyst, recently told Business in Vancouver that up to 50% of the oil from the Trans Mountain could eventually go to Asian refineries.

But developing new markets for oil doesn’t happen overnight. Refiners need to test new supplies before signing long-term contracts.

Whalen said he expects that once Trans Mountain is expanded, “sample shipments” will start moving to Asia for testing.

When the Trans Mountain expansion started the regulatory review process in December 2013, oil was selling for US$100 per barrel. By early 2015, prices were halved to US$50 per barrel, later sinking below US$30 per barrel. Today, the price hovers around US$50 per barrel.

How low can oil go before a new pipeline becomes uneconomic? That’s not something pipeline operators can answer; rather, it’s a question for oil producers, Whalen said.

Just as railways aren’t affected by grain prices, pipeline operators aren’t much affected by oil prices. They get paid to move product on a volume basis, regardless of the price producers are getting. They have take-or-pay contracts and get paid even when a company doesn’t use the capacity it paid for.

Sustained low oil prices could curb new oilsands production, but so far that isn’t happening. New oilsands operations continue to be built in Alberta.

S&P Global Platts projects Alberta’s oilsands will expand by more than one million bpd by 2021 – from 2.6 million bpd this year to 3.72 million bpd. That’s equivalent to the capacity of the Energy East pipeline.

Even if the building of new oilsands projects ground to a sudden halt, existing oilsands operations may have 20 or 30 years more life left in them, and can continue to produce even when oil prices are low.

“The operating costs for existing facilities are significantly low,” Whalen said. “Many of them are less than $10 per barrel. As long as the price is above the operating cost, it makes sense to produce.”