Where does Canada rank in the global oilpatch?

There are two ways to look at Canada’s oil wealth, found mostly in Alberta’s oilsands deposits.

One is to be amazed that we’re sitting on more than 170 billion barrels of oil — an immense resource by any yardstick.

The other is to question what it all means.

Will it have an impact on the global supply of oil, are we going to be able to sell it in the future, and how does the rest of the world view us — and our oil?

In other words, what’s our place in the world of petroleum?

Oil is found just about everywhere on the planet. While conventional crude oil has been the only game for a century, only in the past two decades has squeezing heavy oil from the Athabasca sands become a commercial money-maker.

But now the new technologies of horizontal drilling and fracturing rock to unlock previously impossible-to-recover oil have changed the game again, and shale oil plays have become profitable in just a few years.

While there are an estimated 250 billion barrels of bitumen in the world, there are about 350 billion barrels of shale oil, much of it in Russia, the U.S. and China.

Of course, these unconventional supplies join the already abundant supplies of inexpensive-to-produce light, medium and heavy crudes from states such as Saudi Arabia, Russia, Iran and Nigeria, which form the baseline for global prices.

So while Alberta’s bitumen is being produced in ever-increasing amounts — now about two million barrels per day — it is all for domestic use, or shipped by pipeline to our only customer, the U.S.


With more than 75 million barrels of oil produced in the world every day, the Alberta oilsands constitute a very small part of the big supply picture.

But Alberta’s oilsands production could rise to more than five million barrels by 2030, while global oil demand — and price increases — are likely to be flat.

Meanwhile, our biggest customer is in the middle of its own shale oil boom, with production in the U.S. jumping by 3.2 million barrels per day (MBPD) since 2009.

America still imports about eight million barrels of oil daily, with Canada supplying one-quarter of that by pipeline.

And as oilsands production rises, increasing our share of the U.S. market will be a top priority — which means tough competition with foreign oil.

While oil in tankers can obtain a world seaborne price that is now more than $100 a barrel, the cost to produce that oil ranges widely.

In the big, well-known conventional fields of the Middle East, production costs can be only a few dollars per barrel. And with pipelines and tankers close by, that equals a virtual cash cow for Gulf nations.


But while this is the present, the future looks much different — and more expensive.

New production will come not only from the Athabasca sands, but also the carbonates — zones adjacent to the oilsands where oil is trapped in pockets of solid rock rather than sand.

Carbonates are the new frontier for Canadian industry, which is still perfecting more efficient methods of extraction from the underground steam-assisted gravity drainage (SAGD) projects that were leading edge less than a decade ago.

But also consider the coasts off Brazil and West Africa, with their ultra-deep deposits in the so-called “pre-salt” layers — oil and natural gas that lie below a 2,000-metre layer of ancient salt, which in turn lies about 2,000 metres below the surface of the seabed in areas of the ocean which are between 2,000 and 3,000 metres deep.

Huge deposits sitting around 7,000 metres, at the limit of offshore drilling technology, are extremely expensive to tap.

Venezuela also has large deposits of very heavy oil on the same scale as Alberta’s deposits.

And there are large deposits of shale oil in Russia and the Arctic which require horizontal drilling and fracking in remote locations and inhospitable environments.

All these examples point to the fact that future oil will cost a lot to produce, and world prices will have to be high enough to support them.

Predictions suggest a gradual decline in the world oil price over the next several years to the $90-per barrel range, about $10 below current prices.


The oil price is set in the marketplace, where demand and production meet. The U.S. demand is the world’s largest, at 18.6 MBPD, but they are now producing about 11 MBPD of crude thanks to rapidly growing shale oil production. And their overall demand is heading lower, largely thanks to more fuel-efficient vehicles.

In 2013, the U.S. will surpass Saudi Arabia as the world’s top oil producer with 12.1 MBPD, a number which includes natural gas condensates and biofuels.

However, while the U.S. is producing oil at full speed, the Saudis have locked in several million barrels per day of production to help maintain world supply at a level that won’t see prices drop.

In the past, such an “oversupply” has pushed prices to under $50 a barrel, a level that would bust the budgets of many oil-producing countries which rely on oil sales for most of their revenue.


When prices dropped in 2008, Alberta went into a recession of sorts, with all major oilsands projects shelved.

While major companies look at the long term and ignore short-term oil price drops, their immediate reaction is naturally to curtail spending — especially on expensive oilsands projects.

Some Alberta projects are vulnerable to low oil prices — new mines are expensive, for example, especially when bitumen upgraders are attached to them. But Imperial’s new Kearl, and the Fort Hills mine just approved by Suncor/Total/Teck, show certain projects remain economically viable.

Most SAGD projects are reasonably safe from low prices, but a future of $50 oil would likely curtail even these projects.

According to global energy research and consulting firm Wood Mackenzie, the vast majority of oilsands projects set to start by 2015 will be economically attractive despite low prices.

The firm forecasts non-upgraded bitumen production will grow by 540,000 barrels per day between now and 2015, with 72 per cent of that output coming from the 29 projects already underway that have a break-even price below $60 US per barrel.

“What our analysis shows is that point-forward economics for the vast majority of oilsands projects planned to start up between now and 2015 are attractive,” said Mark Oberstoetter, an upstream research analyst for Wood Mackenzie.

But with the North Dakota’s Bakken fields booming and production expected to nearly double to 1.3 million barrels a day in 2015, that oil becomes a competitor to Alberta crudes.

And the most productive areas in the Bakken require a price of just $50 a barrel to break even.

Large firms have many projects in their portfolios, and the option of producing oil for such low prices could lead to the delay of some high-cost oilsands projects, Wood Mackenzie concluded.

A year ago, the so-called “bitumen bubble” — blamed on pipeline congestion and a glut of heavy oil at terminals in Cushing, Okla. — was cited to justify provincial cuts in the spring budget, when bitumen was about $45 per barrel. The government considered it as a contributing factor in a shortfall of about $3.6 billion in non-renewable resource revenue in 2012.

It took until July before bitumen passed $85 per barrel. It’s now back to around $65 per barrel, while Western Canada Select (WCS) — the benchmark blend that includes bitumen — hovers around $73 at the Hardisty terminal and the benchmark West Texas Intermediate (WTI) is about $96.

That $30-a-barrel spread is again a sign of both pipeline congestion and the stronger U.S. dollar versus Canadian loonie, since oil is traded in U.S. dollars.


While Alberta producers await new pipelines to the West and East Coasts, the U.S. remains our only market.

Some oil has landed in California — where refineries that handle very heavy Bakersfield crudes can also handle the Alberta heavy crudes — or Washington state refineries, which are designed to handle the lighter grades.

But most is headed to upgraders in the Midwest, and along the Gulf of Mexico.

Pipeline connections to the Midwest are good. But the target for much U.S. and Canadian oil that is routed through the Midwest is Cushing, Okla. Until earlier this year, when new pipelines opened, there was insufficient capacity between those terminals and the Gulf Coast refineries.

While the glut has largely diminished, Alberta’s new challenge will be selling heavy crude on the Gulf Coast.

Alberta producers are counting on pushing out foreign suppliers of heavy oil when large amounts of oilsands crude start hitting the region.

But they will face stiff competition, and may not even be welcome at some upgrading refineries.

That’s the opinion of Robert Johnston, director of global energy for the Eurasia Group. Johnston said imported heavy oil is currently processed at facilities that have a capacity for 4.71 MBPD. One-third of those refineries — representing 1.44 million barrels per day of capacity — have relationships with national oil companies from Saudi Arabia, Mexico, Venezuela and Brazil. And oil producers from those nations have few options outside the Gulf Coast.

“They will price their heavy crude to maintain their market share,” Johnston told the Journal.

“Those refiners will likely have a higher bar for switching from imported heavy (oil) to Canadian (diluted bitumen). Other fully independent refiners will likely seek the best price.”

And ownership stakes by foreign national oil firms in certain refineries would suggest that Alberta crude will not be welcomed.

“We know the coking (a process to remove heavy components from crude) capacity on the Gulf Coast and the oil demand, but I think we need to be more critical in terms of how that penetration (by Alberta crude) will actually take place,” he said.

“So this just reinforces the point that the East and West Coasts are critical for Alberta’s oil.”

He added things have changed in the U.S. because of their rapidly increasing oil production.

“It used to be the U.S. would take all that Canada wanted to sell, but it is not that way anymore. There is less urgency in the U.S. on the pipeline front.”


So while some Alberta crude is reaching the Gulf Coast through other pipelines and rail connections, the bigger problem for Alberta — and indeed other global oil producers — is that the soaring U.S. oil production will allow the world’s largest oil consumer to become an oil-exporting nation within three years.

The U.S. now exports about one million barrels of gasoline and diesel to largely Latin American markets each day, but has never exported crude oil.

Just back from a tour of Asian oil customers, Greg Stringham believes the world outside North America is very interested in Alberta — because of its natural resources, and the culture of innovation that is part of the industry here.

“We have a place on their map, and they can’t not consider us,” said the vice-president of the Canadian Association of Petroleum Producers.

“The firms (both public and state-owned) will have operations in many countries, but it all comes back to what we have here — and the technology we have developed.

“We are innovative and good at developing and applying new technology. We are good at dealing with the tough challenges, and I think we underestimate ourselves.”

Asian countries — huge economies like Korea and Japan have no oil, while China has very little — have always depended on oil from the Middle East. But they need alternatives, which is why Russia and China have signed a recent natural gas deal, why Australia’s natural gas is finding a ready market, and why oil development off Mozambique is closely watched.

“They need a diversity of sources, which is why Canada rates so highly as a reliable potential supplier,” said Stringham.

And this is also why they are so frustrated with us — a resource-rich country that has a problem getting pipelines approved.

Perhaps it is because we have had it so easy, exporting all our oil to one customer by pipeline, he suggested.

“We have developed our economy to be so intertwined with the U.S., and that has been beneficial to us,” Stringham said. “But over the past few years we have been thrust into the global market on all fronts — not just oil and gas, but also forestry, manufacturing, chemicals.

“Canada is maturing beyond the North America market and is facing the global market with all its up and downs. Different infrastructure and political dynamics are required.”

Selling oil and gas to the world is more than marketing.

“We have got to establish our performance on the industrial, as well as the social and environmental side of things. … Canada can not only be a global economy, but also a world leader in those areas.”

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