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Lack of pipeline threatening Canadian oil industry

Canada’s oil sands need new pipelines to new markets

A build-up of oil-sands production without sufficient pipeline capacity to take all the new oil to consumers threatens the long-term viability of the developments, believes Alberta’s government.

The province’s premier, Alison Redford, summed up the problem in a catch-phrase called the “bitumen bubble”, which has caught on in a general public concerned for the future viability of oil-sands exports.

Her theory, shared by some analysts, is that rising output from the oil sands will by 2016 eclipse the pipeline capacity that links the projects with refiners. This would drive down the price of Canada’s oil, which would be heavily discounted against higher quality or more accessible oil closer to the markets. Rising oil output in the Bakken and other new plays in the US, still the oil sands’ only market, may make the situation worse.

Some believe the trend is already under way. Last December, Canadian bitumen was selling at $42.50 beneath the price of a barrel of WTI. Redford reckons the pipeline problem will cost her government C$6 billion ($5.91bn) in the next fiscal year. A long-term depression in the price of oil-sands crude would also be a threat to the developments’ profitability.

This makes Alberta’s – and Canada’s – quest to open new export routes to the US and Asia critical. Brian Ferguson, chief executive of Cenovus Energy, a large oil-sands producer, told Petroleum Economist that the biggest challenge facing Canadian oil firms is to find new outlets for fast-growing production. Previously, the biggest threat to oil-sands economics was the break-even price. Producers struggled to keep costs low, and projects like Fort Hills have been continually deferred amid successive price crashes, starting in 1986, and again in 1999 when global oil prices fell to $10 per barrel.

Now Ferguson insists the issue is access to markets. Canada relies on the US for 98% of its exports. But without new pipelines to the US, Asia (through British Columbia), and the east coast of Canada, enormous reserves of oil sands might remain trapped in a shrinking North American market.

But how worried should oil-sands producers be? Since opening up that record differential last year, the price discount of Canadian bitumen to WTI has shrunk back to around 20%, its historical level. Some grades of synthetic crude oil derived from bitumen continue to trade at or above WTI. Volatile oil prices aren’t responsible for Alberta’s fiscal woes, say Redford’s opponents; her government’s mismanagement of the economy is. 

An oil-sands cocktail

Oil sands crude is not a consistent product and comes in several grades, ranging from sour 8º API bitumen to 32º API synthetic crude. Often, heavier bitumen is diluted with NGLs and synthetic oil (or both) to make a cocktail known as dil-bit, which trades under the banner Western Canadian Select (WCS).

Each of the various grades is priced according to its quality, with synthetic sweet the most prized because it is a ready substitute for light conventional oil.

Though Canadian prices are based on WTI, the market for heavy oil has historically been a small one. Most of the major producers, including Husky Energy, Imperial Oil, and Cenovus have maintained refineries in the US to ensure outlets for their production.

These refineries are in the US Midwest (PADD II), however, and it is quickly being overwhelmed with Canadian crude.

According to Canada’s National Energy Board (NEB), Alberta’s producers sent 550,000 b/d of oil to PADD II last year, a region which provided only 480,000 b/d of coking capacity to handle the heavy crude, according to the US Energy Information Administration (EIA).

By contrast, the Gulf Coast (PADD III) region has 2m b/d of coking capacity and received just 107,000 b/d of Canadian crude in February.

That discrepancy is the simplest explanation for Redford’s “bitumen bubble”. Without access to the Gulf, the oil sands will overwhelm Midwest refineries as supplies rise by 1.7m b/d in the next 10 years. The glut could be disastrous for the oil sands’ growth plans.

Fortunately for Alberta, this is not imminent. This year, ConocoPhillips, BP and Marathon will add another 300,000 b/d of heavy conversion capacity in Ohio, Indiana and Illinois, largely to facilitate their own heavy-oil projects in Alberta.

ConocoPhillips is developing the Christina Lake project with Cenovus. BP is in a refining and production venture with Husky. Marathon is a 20% partner in Shell’s Athabasca Oil Sands Project.

This provides breathing room, but pipelines will become a choke point after 2016. Russ Girling, chief executive of pipeline firm TransCanada, which is hoping to build the 850,000 b/d Keystone XL pipeline to the Gulf, told Petroleum Economist at least half a dozen similar-sized pipelines would be needed to move Canada’s oil to market in the coming decades.

“That oil is going to get out of the ground,” he said. “Somebody is going to figure out how to get it there (the Gulf Coast) with or without XL.”

North America’s changing supply

Despite this looming glut, Canada continues to market its oil with some aplomb. Its market share in the US is still rising, even as American imports fall to decade lows. In 2012 it supplied about a third of US imports, largely at the expense of Mexico and Venezuela. In 2012, Mexican exports to the US fell below 1m b/d for the first time since 1994. In the same period, Canadian imports have tripled, to 2.95m b/d last year.

The worry, though, is that this pace of growth can’t be sustained, especially as US production keeps rising.

Not all oil-sands producers see this as a risk. Canadian Natural Resources’s (CNRL) president Steve Laut sees a cheapening of oil-sands output as an opportunity to expand market share. Unlike its competitors, CNRL doesn’t own downstream refineries and sells its production direct to refiners under 30-day rotating contracts. Integrated refiners enjoy a cost advantage because they can buy their own cheap feedstock and capture higher refining margins, but CNRL is completely at the whims of the physical market.

It has a lot at stake in a volatile and changing business environment. On top of 133,000 b/d of conventional heavy-oil production, it also operates the 100,000 b/d Horizon mine, 70 km north of Fort McMurray, which is being expanded to 250,000 b/d.

Laut notes that comparable Mexican heavy crudes trade at a premium to WTI in the key Gulf Coast refining hub, strengthening demand for Canadian substitutes. According to the EIA landed costs of Mayan crude were about $106.36 per barrel in February compared with $62.30/b for Canadian Bow River Blend.

Unlike WCS, Bow River is a posted price used by Imperial Oil for its Canadian refineries and those owned in the US by ExxonMobil (Imperial’s owner).

Rather than a cost to his business, Laut sees the disparity between Canadian, Mexican and US prices as an opportunity to undercut other suppliers. He remains bullish on the longer term – provided the pipelines get built. Then producers will regain the upper hand. “We’ve always thought it was better to own the reserves than the refineries and be the low cost producer”, he said.

Others producers are more cautious. In March, Canada’s largest oil-sands producer, Suncor Energy, cancelled the $11.8bn Voyageur upgrader, which was to process 200,000 b/d of mined oil sands in a joint venture with Total. Construction began in 2008 but was abruptly halted during the financial crisis. It sat partially complete for five more years before internal studies determined the economics didn’t justify the cost.

Suncor president Steve Williams told Petroleum Economist the decision to cancel Voyageur was reinforced by developments in the US, especially the Bakken, which came on “faster than anyone could have imagined... nobody, including us, saw it coming”.

Suncor’s synthetic crude is almost identical in quality to Bakken’s light sweet oil but Williams is wary of stacking his higher-cost upgraded product against low-cost US supply.

He’s still optimistic, though. Bakken oil will eventually be shifted to the US’ east and west coasts, he believes, leaving the Midwest refineries to the Canadians. He’s also confident KXL or some acceptable alternative will eventually be built, allowing oil-sands production to flow south to the Gulf. As a back-up, Suncor could reconfigure or expand its own existing refineries in Ontario and Colorado to run the extra heavy crude.

Even the International Energy Agency (IEA) acknowledged the risks to Canadian producers “may not be as daunting as they appear” in its recent Medium Term Oil Market Report. It credited companies like Suncor with “flexibility and ingenuity in coming up with new transport links to bring production to market and in tweaking refineries and petrochemical plants to handle the new feedstock”.

But it also carried a warning: “The impact of logistical bottlenecks on prices may already have played a role in Total and Suncor’s decision to cancel their Voyageur oil sands upgrader in Canada, and have no doubt triggered reviews of many other capital expenditure projects. Deep discounts for bottlenecked Canadian grades are an obvious downside for Alberta project economics at current oil prices.” 

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