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Alberta’s oil on the cusp of new era as export routes emerge

The oil sands’ pipeline bottleneck is starting to ease. But cost inflation remains a problem

Environmentalists opposing Keystone XL (KXL) thought if they stopped the pipeline they would kill off the oil sands. Instead, the opposite is happening. Thanks to the delay in getting the pipeline approved, alternative export routes out of the oil sands are emerging. By 2020, the takeaway capacity from Alberta could more than double, underpinning steady growth in output from the play.

This will have implications for oil markets beyond North America. Alberta’s land-locked oil sands, already the biggest single supplier to US, will offer another source of oil for import-needy countries in Europe and Asia. Meanwhile, when the US government signs off on KXL - possibly before the mid-term elections later this year - Alberta’s producers will also have the original market they wanted, in the US Gulf Coast. The discount that has long plagued Canadian bitumen sales will steadily erode, giving producers more confidence to invest upstream.

Oil trade in the Atlantic basin will feel some of the impact of this. Energy East, TransCanada’s C$12 billion ($10.8bn) plan to pipe 1.1 million barrels a day (b/d) of Alberta oil to Quebec and the New Brunswick, will displace about 700,000 b/d presently imported into eastern Canada, and then some. TransCanada filed an application for the project with federal regulators in early March. No one expects it to be turned down and the pipeline should be on stream by 2018.

Enbridge’s project to reverse the flow of Line 9b, which presently sends oil from Montreal to Ontario, and expand Line 9, which is connected to it, will allow for another 300,000 b/d of crude to reach refineries in Quebec, which mainly process foreign crude. With the expansion and reversal, Bakken oil will reach them instead, freeing pipeline capacity for oil sands crude elsewhere. It is another chunk of supply that will loosen the Atlantic basin market.

The oil that reaches Canada’s east coast could go in several directions. Turkey, Greece and other European importers will have the option to import heavy Canadian oil, which will be a new rival for crudes exported out of the Persian Gulf. Opec producers have long ignored the rise of Canadian oil output, but that will have to change.

India is another target for oil sands producers. In November, Husky Energy shipped 1m barrels of crude to Indian Oil Corporation. The cargo came from Husky’s White Rose field, offshore Newfoundland. But it has blazed a path for future oil sands deliveries. Asim Ghosh, Husky’s chief executive, said that when Energy East comes on line, India will become a “cost competitive destination for Canadian crude”.

But Canadian oil arriving in the country’s east could also stay on the continent. Aside from meeting Canada’s own need for products, refineries in the US northeast are potential consumers, says Greg Stringham, vice president of oil sands and markets at the Canadian Association of Petroleum Producers (Capp). Tankers could also ship the oil to the US Gulf Coast. Batching the oil shipped east would allow different grades to reach different-spec refineries. Several oil sands producers, including Suncor Energy and Cenovus Energy, have already booked capacity on the line.

Solving the bottleneck

Eastern Energy’s progress comes thanks to KXL’s delay. Oil sands producers, backed by the Canadian and Alberta governments, have lobbied hard for US approval of KXL because they considered it critical to future production growth. Without it, feared oil sands producers, existing pipeline capacity to take output into the US would be insufficient to meet incremental output. Canada’s oil sands produce 2m b/d now, but Capp expects production to hit 3.2m b/d by 2020, taking total Canadian production to 4.9m b/d. Existing pipeline capacity is now about 3.6m b/d, against total output of around 3.4m b/d.

This meagre spare capacity has already begun to depress the price of Canadian bitumen. Last year, for example, as Imperial Energy’s Kearl project came on stream and Cenovus and Suncor projects ramped up, the discount for Alberta’s bitumen has hit highs of $40 a barrel - a problem for investors in the oil sands and for the province’s treasury.

The rest of this year is expected to remain tight, according to Stringham. But it will be a lot less troubling for the oil sands than it could have been. Rail has stepped in. By the end of last year, says Capp, trains were handling 200,000 b/d of western Canadian oil. Within a year, capacity could rise to as much as 400,000 b/d. An 18-month backlog of orders for new cars suggests availability will growth still further after that. Some forecasts see as much as 1m b/d of rail capacity within a few years.

There’s more. KXL’s progress looks more likely now than it has in years. A US State Department report in January offered no real environmental grounds for blocking the pipeline (although opponents continue to press the White House to block it, and some deal on Canadian climate change targets could yet be attached to the pipeline’s approval). A Nebraska judge’s recent ruling that the state’s governor did not have the authority to green light the pipe’s construction is considered a temporary block. Russ Girling, TransCanada’s chief executive, reckons its will be “the next pipeline to be built”. Perhaps decisively, several Democrats who back the KXL’s progress are up for re-election to Congress in November’s mid-term elections. Some executives in Calgary believe President Obama’s fear of losing key seats in the Senate - and, therefore, any control over Congress in his final two years in the White House - will see him approve the project before the congressional elections. Construction of the infrastructure would take 18 months after approval, meaning KXL could be on line by 2016. In the meantime, TransCanada may build rail hubs to allow shipments of oil along the route even earlier.

More capacity to Canada’s west coast is also in store. Enbridge’s Northern Gateway project to pipe 525,000 b/d to Kitimat, in British Columbia (BC), is gathering momentum after several troubled years. The country’s National Energy Board (NEB) endorsed the proposal in December. Federal backing is likely to come this summer. Opposition to the pipeline in BC could disrupt the schedule, but 2018 now seems a viable target for start up. In the meantime, expansion of Kinder Morgan’s Trans Mountain link to Vancouver will offer another 590,000 b/d of capacity. The company filed an application with the NEB in December. “They did everything the right way,” says one executive in Calgary, referring to Kinder Morgan’s consultations with interest groups in BC. Not everyone says the same about Enbridge and its rival pipeline. Kinder Morgan’s C$5.4bn expansion should be complete by the end of 2017.

Enbridge is also working on its two-phased Clipper pipeline expansion project in Alberta. Clipper’s capacity now is 450,000 b/d, but another 120,000 b/d should be on line this year, followed by 230,000 b/d more by the beginning of 2016. Enbridge has other expansions under way, too, including to the Southern Access pipeline in the US. In March, it announced a $7bn project to replace its Line 3 between Alberta and Wisconsin by 2017, which will almost double its capacity to 760,000 b/d. Those midstream improvements will also bolster western Canadian and US evacuation capacity.

All told, as much as 3.145m b/d of available pipeline capacity could come on stream in the next three to five years, excluding rail. The end of midstream tightness will mark a new era for oil sands producers, which will know their oil can reach both the Atlantic and Pacific coasts, and from there Asia and Europe, as well as the prized market of the US Gulf.

Lurking cost inflation

Removing the pipeline capacity barrier should spur more upstream development. But how much growth is possible? Capp’s Stringham reckons 200,000 b/d of added production per year is viable, yielding 3.2m b/d in 2020 and 4.2m b/d five years later. Opec’s World Oil Outlook suggests a slightly lower number.

The list of projects either under construction or with provincial approval and proposed start-up dates in the next six to 11 years, however, implies much more rapid growth is possible. Petroleum Policy Intelligence (PPI), an energy consultancy, says output capacity could in theory reach 4m to 4.5m b/d in that timeframe.

But such a number, suggests PPI, will depend on the market and the projects’ ability to manage costs. Although Calgary executives say they have grown more confident in the durability of oil prices, inflation in upstream spending remains a worry. A recent comparison of production costs across 50 North American plays by Scotiabank, a Canadian bank, offered some encouragement for oil sands producers. Production from steam-assisted gravity drainage (Sag-d) projects in the oil sands needs a WTI price of $63.50/b to give producers a 9% after-tax return on investment. Sag-d accounts for almost half of oil sands output, with mining still making up the bulk. But 75% of new output in the next six years will come from Sag-d, says Scotia. Mining projects, meanwhile, offer the same yield within a range of $60-65/b. US tight oil projects in the Bakken and Eagle Ford are both more costly, says Scotiabank.

It may not stay that way, though, if oil sands producers rush to take advantage of new takeaway capacity. Input costs are one source of inflation, although any drop in the oil price would help lower some of them. Labour shortages are a bigger problem, and the so-called sticky-wage effect makes it tricky to cut salaries in leaner times. Alberta’s unemployment rate is already low - in Canada, only neighbouring Saskatchewan’s is lower. Adding new pipeline capacity, as well as upgraded projects near Edmonton, will put more strain on labour. The biggest test could come if liquefied natural gas export projects planned for BC’s coast get the go-ahead. That would see more infrastructure developments - and more upstream projects in the Montney and Horn River tight gas plays - drawing from the same small pool of skilled labour. “That’s a lot of welders that we’re going to need,” says one Calgary executive.

Investment is already pouring into the sector. Barclays, a bank, forecasts that spending in Canada’s oil patch will reach $43bn this year, 3% more than in 2013. But that could rise. Few of the oil sands projects brought on line in the recent past have kept their budgets under control. Northwest Upgrading, building one of the plants near Edmonton to convert bitumen into synthetic oil, recently said the cost of its plant had increased by half, to $8.5bn. The first phase of Imperial Energy’s Kearl project, which began operating last year, will now cost C$12.9bn, or $5bn more than the original budget. It is also struggling to reach full capacity of 110,000 b/d, producing about half that now. (Capacity by 2020 is supposed to reach 345,000 b/d.)

Other Sag-d projects have also found it difficult to reach nameplate capacity. Nexen’s Long Lake development has faced problems with steam, keeping output well shy of its 72,000 b/d nameplate capacity. Husky’s Sunrise project, says Andrew Leach, a professor at the University of Alberta, offers another example. It was sanctioned to cost C$25,000 per flowing barrel of oil, but the first phase, due on stream this year at 60,000 b/d, will cost almost double per flowing barrel.

Leach reckons those kinds of cost pressures could mean production growth in the oil sands disappoints over the next few years. Output forecasts from a decade ago assumed the oil sands would be producing about 3.5m b/d by now, he points out. Yet despite a long period of high oil prices those targets haven’t been met.

The next 18 months will give everyone an idea about what to expect. A dozen or so projects are due on stream by the end of 2015, for capacity of around 720,000 b/d, according to Ernst & Young, a firm of accountants. As the oil sand’s pipeline problem starts to fade during that period, producers will have every reason to get their projects up and running. To make Alberta’s oil a truly global commodity over the longer term, however, developers need to find a way to get their costs under control.

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