As the sun dips below a grain stubble horizon, the flares flicker into view, a dozen tongues of flame licking against a pink sky.
The flares are natural gas being burned off in the rush for a far more valuable resource – oil. Shining in the gathering dusk, they are industrial glimmers of a changed future for a nation whose long-faltering dreams of energy independence are being revived.
Oil is pouring out of North Dakota. In September, some 728,000 barrels a day flowed, up a startling 57 per cent from the year before. And it’s not just here: Similar fields in Texas and elsewhere are seeing similarly fast rises in oil output, prompting a near-euphoric re-examination of what’s ahead for a country that has long relied heavily on imported oil to fill its gas tanks and keep its economic engine running.
Now, as hundreds of drilling rigs employ technological advances to extract rich reserves of previously untapped energy, the oil renaissance is triggering some startling forecasts.
The International Energy Agency predicted this week that the U.S. is set to become the largest oil-producing nation on earth, more prolific even than Saudi Arabia. One day, the IEA said, the U.S. could drive away most foreign imports.
What, then, does the future hold for the country that today delivers the largest share of those imports? Some 27 per cent of all barrels that cross U.S. borders come from Canada, and a belief in unfettered access to an insatiably oil-hungry U.S. market has been a central underlying assumption of the great energy expansion under way in Alberta.
Canada already produces far more oil than it needs. Any flaws in that assumption about U.S. demand will have a profound effect on Canada’s oil sands, where companies are spending a billion dollars a week to build production destined for export – virtually all U.S. bound.
At stake is the growth of an industry that keeps Western Canada’s economy vibrant, producing boatloads of well-paying jobs, welcome spinoff effects and government revenue. Already, amid weaker oil prices, some oil companies have contemplated deferring or cancelling projects, and just this week the Alberta government backed away from a goal to balance its budget.
“Canada has a real problem,” said Al Monaco, chief executive officer of Enbridge Inc., the pipeline company that has long been the prime mover of Canada’s oil. Combine rising U.S. oil output with declining consumption and the lack of other markets for Canada, and “none of that bodes well for prices if you’re a producer – nor if you’re a government that has royalties at play. Nor if you’re the federal government for tax revenue.”
The greatest vulnerability, he said, lies in the northeastern corner of Alberta, the Fort McMurray area that not long ago looked a lot like North Dakota, a nascent boom town that stoked – and continues to stoke – great economic hopes for Canada. But, Mr. Monaco warned, “if you’re in the oil sands and you are the marginal production because you’re the highest cost, this is a big factor. These are big issues.” He is not, however, worried. Enbridge believes it can be the solution by building new pipelines to bring Canadian oil to new markets, both abroad and in U.S. states not served by current pipelines. But it’s hard to find a new pipeline proposal – to the West Coast, to the Gulf Coast, to the East Coast – that is not wrangling with severe political and social skepticism.
And if opponents succeed in stopping or slowing those projects, the outlook is grim: Prices for Canadian oil “will get pushed down to the point that production stops growing,” says Chris Micsak, an oil analyst with Bentek, an international energy forecasting and analysis firm.
So the North Dakota flares are a flickering glimpse of an uncertain future. It’s one that is already arriving. Alberta’s primary export pipeline system is already turning away oil, in part because North Dakota crude is shouldering its way in, prompting some Canadian companies to employ unusual alternatives, including trucking oil into the U.S.
Larger shifts are under way, too. The refining complex in the U.S. Gulf Coast, with its huge capacity to process heavy crude, has long been viewed as virtually the only market the oil sands will ever need. But refiners are already working to cater their operations to light barrels like those found in the giant Bakken field that is fuelling North Dakota’s growth.
And there are signs that corporate spending is shifting. Producers like Suncor Energy Inc. are scaling back growth expectations as they work to shake out excess costs. And as U.S. oil shoulders in on the pipeline network, Canadian oil is backing up and prices are soft. In the third quarter, Connacher Oil and Gas Ltd. sold its oil sands crude for just $38.12 a barrel.
Against a backdrop that also includes lingering concerns about the environmental impact of Alberta’s oil industry, some companies are contemplating an exit. Marathon Oil Corp. has publicly mused about pulling out of the oil sands, even as it chases the thick profits in not only North Dakota, but a series of similar “tight oil” fields across the U.S. Between 2011 and 2012, Marathon expects its onshore U.S. production to rocket up 90 per cent. The company recently highlighted one “monster well” that shot to surface 6,275 barrels of oil equivalent in one day, and said that in Texas, the Eagle Ford field alone “is a company maker.”
That has Marathon looking at whether it can cash out its 20-per-cent stake in the Athabasca Oil Sands project, one of the most expensive ever built on a per-barrel basis, to “reinvest that in profitable growth” elsewhere – in places like the Bakken, which, as they say in North Dakota, is rockin’.
Money is pouring in. So many workers have flocked here that it can take three hours to check out at the local Wal-Mart, and half an hour to get through a 700-metre line of cars waiting on a left-hand turn. They are building an energy future for the U.S. that was unimaginable – to the industry on both sides of the border – even a few years ago.
“As I tell my employees, you’re sitting through history in the state of North Dakota,” says Terry Kovacevich, who leads Marathon’s operations in the state.
A PIPELINE BUILDING SPREE
Not far from Stanley, N.D., a brand new Enbridge pipe curves out of the ground, untarnished steel painted white and coated with ice crystals that glint in the sun. The pipe is empty, but not for long. Early next year, the first barrels of North Dakota crude will flow through, pushed along by a pair of 3,500-horsepower electric pumps.
A few hundred kilometres from here, in Manitoba, those barrels will drop into an existing pipeline, the Enbridge Mainline, that has long connected Alberta’s oil fields with refineries in the U.S. Midwest. For years, the Mainline has been the backbone of Canadian oil exports. It was built to carry Canadian product to market. But North Dakota stands geographically between Alberta and those markets – and increasingly, Bakken barrels merging onto the system are creating traffic jams for Canadian barrels.
Some 235,000 barrels a day of Bakken crude now run through a pair of Enbridge pipelines that connect to the Mainline. That brilliant new pipe near Stanley will help boost the total volume to 395,000 in 2013. By 2016, Enbridge expects to complete construction on Sandpiper, a new $2-billion pipeline that will scoop up another 225,000 barrels a day from North Dakota.
The flood of U.S. crude is already having a substantial impact. This November, Enbridge pipelines are under apportionment, the industry term for the rationing that takes place when the pipes can’t carry any more oil.
For Canadian oil producers, the market has responded ruthlessly. Though oil is a commodity, prices vary widely. The global benchmark, Brent crude, currently fetches about $109 (U.S.) a barrel. The U.S. benchmark, West Texas intermediate, stands at just $86 or so because of the continental surplus, driven in part by North Dakota. And with Canadian oil even more backed up, prices north of the border are even weaker.
December sales of Canadian heavy crude are trading a full $30 beneath the benchmark North American oil price. On average, 2013 futures prices show a $24.25 discount.
Numerous companies are now hauling oil on trains to get around the pipeline logjam. Tundra Energy Marketing Ltd. has taken it a step further. It’s now loading small volumes of Canadian oil on trucks and sending them south.
“We’re trucking crude to Stampede [N.D.] from Canada so we can get it on rail cars to move it to refineries,” said president Bryan Lankester. “It’s crazy,” he said. But “Canadian crude is moving into the U.S. because of Enbridge’s issues with apportionment in Canada.”
He believes the pain is unlikely to be short-lived. Pipelines take time to build, and the deluge of oil keeps coming: The Bakken is expected to hit nearly a million barrels a day in coming years, while forecasts have Canada delivering an extra million barrels a day between 2012 and 2018. There is a “huge discount on Canadian crude,” Mr. Lankester says. He adds: “there’s going to be more of these disparities over the coming years.”
A glance at the big numbers might prompt questions about how Canada could possibly be concerned about U.S. market access. In 2011, according to the BP Statistical Review of World Energy, the U.S. consumed 18.8 million barrels a day. It produced 7.8 million a day. The gap has long been filled with imports, and even the giddiest of optimists don’t see that gap closing any time soon, if ever. Bentek sees U.S. production rising to 11.6 million a day by 2022. The International Energy Agency pegs it at 11.1 million.
That leaves a sizable percentage of American cars and trucks that will still need foreign oil to burn – and many believe a healthy chunk of that foreign energy will come from a Canada rapidly growing to meet the need. The IEA expects oil sands output to double by 2025, while Bentek sees Canada pumping 90 per cent more barrels by 2022.
“When you put it together – the oil sands, it’s all needed,” says Eric Newell, the retired chief executive of Syncrude Canada Ltd.
Then consider the makeup of the U.S. refining industry, which has spent vast sums to re-tool refineries to suck up huge volumes of Fort McMurray’s heavy crude. Refinery upgrades set to take effect by mid-2013 will add 310,000 barrels a day of thirst for heavy oil in the U.S. Midwest. At the same time, Gulf Coast refineries operate best with 3.4 million barrels a day of heavy crude – today, with declining supplies from Mexico and Venezuela, they are a million short. That alone is a major market, not to mention the likelihood that many of those refineries would, if given the choice, ditch South and Latin American product for Canadian.
Canadian Natural Resources Ltd., which compiled the heavy oil refining numbers, has used them to argue that the days of the deep discount are almost over. In fact, “we are bullish on heavy oil pricing in the near, mid and long term,” president Steve Laut said last week.
Yet for Canada, what one hand lunges at, the other turns away. Refinery demand is not fixed, and it is surprisingly simple for refineries to gear back toward light oil. It cost BP PLC $3.8-billion to retrofit its Whiting, Ind., refinery to run more heavy oil. Valero Energy Corp. is now installing a unit, called a flash tower, at its Three River, Tex., refinery to boost its ability to process very light oil from the Eagle Ford play. That retrofit costs in the “tens of millions” of dollars, said Valero spokesman Bill Day. It’s such a cheap upgrade, the company is contemplating where else it can do the same.
“We’re looking at it at our Corpus Christi and Houston refineries,” Mr. Day said.
Such modifications could “certainly” change how much heavy crude Gulf Coast refiners seek out in coming years, said Roger Ihne, a Houston-based refining market specialist at Deloitte & Touche. And though any change would stand to hurt Mexico and Venezuela long before it hurts Canada, it’s clear that change is afoot.
“They’re going to do everything possible to lighten up that crude run,” Mr. Ihne said.
A TECHNOLOGY BOOST
“Go ahead and open the well,” Nathan McKelroy, a service supervisor with Nabors Drilling, says in a low voice, speaking into a black headset.
A moment later: “Ready with all the chemicals?”
Then: “Let’s do it, man.” One by one, he calls for power to 10 pumps. A few steps from him, inside a narrow mobile command trailer parked a kilometre from the Canadian border, two technicians flick at a pair of touch screens.
The roar is immediate, from the trucks parked just outside the trailer that produce a rush of diesel power. The thunder grows as each pump, in turn, spools up to pump water, chemicals and 23 tonnes of sand 2.5 kilometres below the earth. A flat-screen panel in front of Mr. McKelroy shows the wellhead pressure leap upward just under 5,000 pounds per square inch. Deep underground, the pressure is fracturing the earth. This is the 21st frack of 32. It will last roughly 45 minutes. Then it will be repeated again, and again, and again, each frack taking another 23 tonnes of sand and triggering another chest-rumbling display of horsepower.
A decade ago, industry technology wasn’t advanced enough to economically extract the oil here, trapped in rock that feels like sidewalk concrete. But when this operation is done, it will race to the surface, liberated by the cracks fractured into the rock. This well, called Aldag, belongs to Crescent Point Energy Corp., which names its U.S. wells after Saskatchewan Roughriders. Not far from here, another well pumped out 2,500 barrels of oil in one day – unusually high for the area, but an unmistakable sign that great riches lie beneath.
Part of the Bakken’s potency lies in its size. Its best rock underlies an area the size of Switzerland. It will take some 40,000 wells to fully develop, or nearly two decades at today’s frenetic pace. But much of what has made North Dakota such an energy powerhouse lies in how breakneck advances have massively expanded what can be wrung from the rock. When Bakken development began in earnest in 2006, companies employed a single fracture per well, a technique people now call “the Hail Mary frack.” Today, in some cases, they use 40 fracks.
In 2008, Marathon estimated it would pull 350,000 barrels from an average North Dakota well. Now, it expects 550,000: a 55 per cent increase in just four years. Crescent Point has seen a one-third increase in just two years.
Some are skeptical, saying hopes for North Dakota continuing its rocket ride are pinned, in part, on a belief that older wells will diminish more slowly than is likely. Yet more advances are likely. Companies today expect to pull 5 to 10 per cent of the oil out of the ground. They’ve already begun lab experiments using underground injections of carbon dioxide and surfactants to see if they can wring out more. “If you look at where we were six years ago to where we are at today, it’s hard for me to see there’s not more out there to improve,” says Mr. Kovacevich, with Marathon.
Then there’s the money. Bakken oil is so light it can be poured into old diesel engines unrefined. That makes it valuable: Some companies have reported profits of $50 a barrel.
But what makes North Dakota rich could have the opposite effect on Canada. Fat margins provide ample cash for Bakken producers to outbid Canadian producers for pipeline space. They also mean North Dakota can keep drilling and pumping long after the oil sands is brought to its knees. “Tight oil plays do well in $40, $50 [a barrel oil price] range,” says Phani Gadde, an oil analyst with Wood Mackenzie. At that level, most Canadian oil sands projects bleed red.
For Canada, the best insurance may be to reduce its vulnerability to oil prices, perhaps dramatically. “We may have to think about how do we get the cost of getting the oil out of the ground down by $10 or $20, because that’s probably what you need to stay competitive in the long run,” says Leo de Bever, chief executive of Alberta Investment Management Corp., which oversees $70-billion of the province’s money. That’s a tall order for companies whose current operating costs run between $35 and $45.
The easier option is simply to open wide the spigots. The hurdles that Canada faces are many, but leaping them is technically simple: Build more pipelines. There is no shortage of options. TransCanada Corp.’s Keystone XL and East Coast Pipeline Project. Enbridge’s Flanagan South, Seaway expansion and Northern Gateway. Kinder Morgan’s Trans Mountain expansion. Together, these projects stand to carry over 2.5 million barrels a day of oil to markets that want it. If they are built, Canada will have so many paths to market that North Dakota will be little more than an after-thought for more than a decade. And even if they’re not all built, the sudden advent of rail transport also holds promise.
“If a reasonable set of investments and decisions are made, those rational decisions will mean that it all works out,” says Skip York, another oil researcher with Wood Mackenzie.
The Canadian oil patch, then, sees little for despair in the flames lighting up the North Dakota country-side. Yet there is no denying that they are also warning flares. After all, the same fracking technology now plumbing North Dakota rocks has also brought forth a torrent of U.S. natural gas, leaving an industry that was once Alberta’s bedrock in tatters.
“Canada historically provided the U.S. market with approximately 15 per cent of its natural gas – and we’ve already found that’s dropped off by about half, and it’s going to go to zero,” said Bernard Roth, a Calgary partner in the energy regulatory practice for Fraser Milner Casgrain LLP. “The same thing is replicating itself now with respect to oil. ... It’s an extremely serious risk to the Canadian oil patch.”
With files from reporter Shawn McCarthy in Ottawa.Report Typo/Error