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Are reports of Canada's oil sands demise greatly exaggerated?

Canada is looking to boost oil sands output by 2020, in spite of the major political and environmental challenges

Despite expectations that the world's third-largest oil reserves had become a sunset industry, Canadian firms have announced plans for new expansion projects that, if built, would add more than 0.5m new barrels a day by the end of the decade. 

Homegrown oil producers continue to consolidate and plot ambitious growth even as international majors such as Shell and BP clamour for the exits—and even as environmental, economic and regulatory issues rumble on surrounding climate change and new pipeline construction. 

While it's clear that the days of wholesale expansion are over, future years will be marked by continuous operations of existing facilities and spotty, but regular, incremental additions. 

Production surge

According to the Alberta Energy Regulator (AER) total production of synthetic crude oil and bitumen rose 12% in 2017 (a year after the Fort McMurray wildfires) to 2.8m b/d and is expected to climb another 5% this year. The AER expects production to top 3.8m b/d by 2027. 

Fully 85% of oil sands was produced as raw bitumen in 2017, a proportion which will gradually fall to 57% as higher-value upgraders are built to process it into lighter grades. 

Even more is on the way. Stalwart Canadian Natural Resources (CNR) in August announced plans to incrementally expand its Horizon oil sands mine by 100,000 b/d by 2019. The facility is already producing 200,000 b/d, which was up 37% in 2017. 

On 31 August, CNR doubled down again by acquiring French giant Total's undeveloped Joslyn oil sands leases for C$275m ($208.73m). With permit approvals in hand, the project could be producing another 220,000 b/d by the end of the decade. 

For the first time in Canadian history, fully 80% of oil sands production is in domestic hands.

Following its acquisition of Shell's oil sands late last year, CNR produced more than 400,000 b/d of oil sands in Q3 and is well on track to double that figure within the next five years. 

Likewise, Vancouver-based mining giant Teck Resources has filed applications for its 260,000-b/d Frontier project, located 110 kilometres (68 miles) north of Fort McMurray. Public hearings are scheduled to start later this autumn. 

Teck is already a partner with Suncor Energy in the Fort Hills mine, which hit a milestone of 100,000 b/d last month as it ramps up to full capacity in excess of 200,000 b/d. In 2017, Suncor received regulatory approvals for three new unsanctioned projects at Lewis and Meadow Creek which, if approved, would add another 280,000 b/d after 2025. 

Even the Chinese National Offshore Oil Company (Cnooc)rumoured to be planning a sale of its Nexen subsidiaryannounced a C$400m ($303.61m), 26,000-b/d expansion of its Long Lake operation. 

Confronting growth constraints  

It all comes at a period when Canada's petroleum industry, and the oil sands sector in particular, is staring down seemingly insurmountable hurdles that are adding to uncertainty and reducing investment. The federal government's Statistics Canada agency expects oil sands spending to fall by 20% this year to C$10.2bn ($7.74bn), which would be the lowest level in 15 years.

Much of the drop can be attributed to projects such as the Fort Hills mine that have been completed and are still being commissioned. But the numbers also speak to an uncertain fiscal environment as new projects are put on the back burner. Further, the Canadian Imperial Bank of Commerce has warned of a "competitiveness gap" with the US on issues such as corporate taxation and environmental policies. 

But even more than taxes and greenhouse gas emissions, the first and foremost concern is the cost of production. It's no secret that oil sands are some of the most expensive, marginal barrels on earth, depending on how they're produced and whether they're upgraded into synthetic crude or peddled as raw bitumen. 

For the first time in Canadian history, fully 80% of oil sands production is in domestic hands. 

Apart from huge up-front capital outlays, project economics are extremely sensitive to fluctuating global oil prices, exacerbated by long planning and construction lead times. Analysts suggest new greenfield projects would need sustained oil prices in excess of $50-60 a barrel to be viable over the longer term just to break even. 

Producers are increasingly banking on new technology to bridge the gap. In making its expansion announcement, CNR touted a new production process that would eliminate fine tailings ponds and chop costs by $3 a barrel, or more than 10%. Its initial capital cost estimates are in the range of $30,000 per flowing barrel of capacity, which is a third of the $100,000 pfb for a typical oil sands project. 

TMX set-back 

All this is in addition to the increasingly tricky logistical issues of getting the crude to market. On 30 August, Canada's Supreme Court overturned approvals for the Trans Mountain pipeline expansion (TMX) to Vancouver. It was a crippling blow for producers who're counting on nearly 1m b/d of incremental capacity that would have opened new overseas markets and reduced the country's reliance on the US as the sole outlet for its crude. 

The importance of TMX was reinforced by a US federal court decision to upend the Keystone XL environmental review. All told, existing pipeline constraints have opened up wide price discounts to international benchmarks such as West Texas Intermediate (WTI) and Brent that are costing Canadian producers some $15-20bn annually. On any given day, a barrel of Canadian bitumen sells for $25 a barrelor 30% less than the WTI selling price. 

Source: Statistics Canada

This in turn prompted the federal government to buy TMX outright for C$4.5bn ($3.42bn), citing it as a vital national interesta deal which was approved by Kinder Morgan shareholders just minutes before the Supreme Court ruling. The purchase price doesn't include the C$7.5bn ($5.69bn) price tag for the expansion. 

Prime minister Justin Trudeau has vowed to get the line built one way or the other, but assuming it has to start from scratch it could easily be 36-48 months before it's in service.

The Supreme Court decision also had devastating repercussions for the government's climate-change policies as well. The government of Alberta, where the oil sands are located, pulled out of the national plan in protest. Alberta premier Rachel Motley complained it "isn't worth the paper it's written on" in justifying the move. Alberta had previously imposed hard emissions caps on oil sands producers and it's not clear if those targets are now in doubt, adding another layer of uncertainty. 

Flight of the majors

The only thing that's certain is that the business case for a new oil sands project is becoming less certain by the day. Little wonder that major producers such as Shell, BP, Marathon, ConocoPhillips, Equinor (previously Statoil) and Total have headed for greener pastures. 

Ironically, that's left Canadian companies in the driver's seat as they consolidate the sector. Since 2017, three Canadian firms—CNR, Cenovus Energy and Athabasca Oilsands—have spent a combined C$31bn to buy out their mostlyAmerican rivals and partners. 

For the first time in Canadian history, fully 80% of oil sands production is in domestic hands. It's a far cry from the days of the National Energy Programme in the 1980s, when onerous government policies strove for a minimum of 51% Canadian ownership. The M&A markets seem to have solved that problem on their own.

What's left is for the home team to divide the spoils. The future of this enormous resource depends on sound government policies and sustainable development decisions even as Canada makes a shift away from fossil fuels to renewables and solar. 

How the oil sands will fit into this brave new world order is still very much in flux. It may well be a sunset industry, but the sun hasn't set just yet.

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