President Obama had to visit - with the promise that no new offshore leases will be signed in the area until the Deepwater Horizon explosion has been investigated - because, as we constantly hear, Canada is now the main oil supplier to the US, and has reserves greater than Saudi Arabia. In a stroke, the optimists get to deny both peak oil – or at least put it back a significant number of decades – and the US reliance on overseas imports. No Islamic revolutions in the Great White North, eh?
But do the facts support this rampant enthusiasm? I’d suggest not.
Here I’m going to focus on the Canadian oil sands. From the outset, I have to say that many oil companies are indeed reporting profits and rising share prices as a result of their oil sands investments, and Canada is the main US source of crude oil. The latest from the US Energy Information Administration (EIA) is that:
Canada remained the largest exporter of total petroleum in February, exportingBut the more you look into this, and the more you read between the lines, the more murky things become.
2.490 million barrels per day to the United States, which is a decrease from
last month (2.593 thousand barrels per day). The second largest exporter of
total petroleum was Mexico with 1.134 million barrels per day.
According to the US Dept of State website: “Canada is the single largest foreign supplier of energy to the US – providing 17 per cent of US oil imports and 18 per cent of US natural gas demand.” The remaining 83 per cent of oil imports, then, must come from elsewhere. Looking down the EIA list, the number two US supplier is Mexico, where oil has already peaked. Next up are, respectively, Venezuela, Nigeria, Saudi Arabia, Iraq, Columbia and Angola. Arguably not much energy security there.
Naturally, the optimists counter that we should expect rapidly increasing Canadian output, reducing dependency of basket cases like Venezuela.
And yes, there have been a lot of grand promises from Canada. From this December 2009 report by Tom Standing:
On November 3 Canadian Energy Research Institute (CERI) released a study thatBut anyone who looked into this at the time sounded warning bells – as Standing was. The essential questions, then as now, remain: what quality is this oil, and how much can be economically removed?
shows Alberta oil sands production soaring to 4.5 million b/d by 2030 and
growing toward a peak of 5.3 million b/d in 2041. Actual production in 2008 was
1.3 million b/d.
We’ve heard this song before. In 2005, the burr
under ASPO-USA’s saddle, Cambridge Energy Research Associates (CERA), issued a
similarly glowing projection that the productive capacity of Canadian oil sands
(more descriptively, tar sands) would grow from 1.18 million b/d in 2005, to 2.3
million b/d in 2010, 2.7 million in 2012, and a phenomenal 4.8 million in
We’ve long known about the low quality of the reserves. A November 2007 Money Week article, Are Canadian tar sands the answer to our oil needs?, argued that the historic term tar sands, is more accurate than more recent oil sands. Setting the scene, this states:
The Canadian tar sands are an extensive deposit of oil-rich bitumen (anotherExtracting oil from bitumen-rich deposits requires long lead times and large capital investments, but the major flaw is that it requires so much energy to extract it. Oil sands proponents argue that the area’s natural gas can be used in the process, but there’s just not enough of that. Back to Money Week:
word for tar) located in northern Alberta, Canada, with some extensions into
These sands consist of a mixture of crude
bitumen, which is a semisolid form of crude oil (aka tar, because the
hydrocarbons are more carbon and less hydrogen) that impregnates rocks that are
composed primarily of sand and clay. The bitumen is almost entirely immobile
within the rock matrix, and does not flow into a well bore like conventional
You have to, as the expression goes, “add energy” to
make bitumen flow and to extract the product. Add energy? And a whole lot more,
as we shall see. And there’s the rub.
Pipelines or no, the energy requirements of the projects planned for tar sandsThis is compounded by problems with water supply, as the extraction process requires one to two barrels of “makeup” water per barrel of product.
development already exceed the amount of available natural gas from the entire
Mackenzie River project. Virtually all estimates for natural gas usage in tar
sands operations by 2015, just 10 years hence, exceed the projections for
available amounts of natural gas. Something has got to give.
Overall, there is an extremely low level of energy returned for investment (EROI) for oil sands extraction, which is possibly five to ten per cent as efficient as that of conventional petroleum.
We knew this all along, but this did not slow the hype – or people’s need to believe in a new hope.
Ultimately, then, we need to know if Canada is delivering on its promise. How are things running after a few years and billions of dollars of investment? For all the news releases with headlines like Canadian oil sands producers pump out higher profit, we are beginning to see items containing the caveat that oil production from the area is falling way below what was anticipated. This is not to deny the importance of the oil revenue to the Canadian government, of course.
An April 2010 report in Canada’s Globe and Mail newspaper, Oil sands awash in excess pipeline capacity, looks at it from the perspective of the pipeline infrastructure – “Despite resurgent oil prices, new production isn’t coming on fast enough to fill up the pipelines” – before giving ominous news for investors that the output originally slated for 2011 is seven years away:
The energy industry’s ambitious growth projections back in 2008 were derailed byThis is toxic for investors, of course. This sobering reality check can be seen reflected in the April 29 announcement that Royal Dutch Shell Plc “has no plans to quickly expand its oil sands operations,” because of the cost of working in the region. According to Reuters:
a myriad of problems. The economic crisis wreaked havoc on the sector. Projects
faltered and timelines were extended. Technical issues, for instance, have so
far kept both Husky Energy’s Tucker Lake and Nexen Inc.’s Long Lake oil sands
projects far from their original production goals.
Starting in late 2008, fully 1.2 million barrels a day of future projects were deferred or cancelled in the oil sands, as soaring costs and tumbling crude prices scared
away investors. The economic recovery has brought some of that work back to
life, but even industry projections now show a sobering new reality. According
to the Canadian Association of Petroleum Producers, the volume of oil previously
expected by 2011, the first full year of operation for Alberta Clipper, will now
not likely flow until 2018 or later.
In an interview with the Globe and Mail's editorial board, Marvin Odum,However, it states that Imperial Oil Ltd, Total SA, Suncor Energy Inc and others are going ahead with planned projects. Shell, for its part, “would instead look to boost output from its existing operations, which could add another 30,000 to 80,000 bpd of production.”
president of Shell Oil Co, said the company was unlikely to launch a major
expansion of its 60 percent-owned Athabasca oil sands project because new
projects in the region, which contains the largest crude reserves outside the
Middle East, are too expensive.
Shell's chief executive, Peter Voser, has also said the company has no near-term plans to expand its oil sands project.
Shell has nearly completed a 100,000 barrel per day
expansion of the Athabasca project, which currently produces 155,000 bpd. The
costs of the project was last pegged at $14.3 billion ($14.2 billion), well
ahead of the original estimate of between C$10 billion and C$12.8
Rising costs and falling oil prices forced the delay or cancellation of about C$90 billion of oil sands projects during the recession. However the lower number of projects freed up skilled labor and improved productivity, lowering construction costs.
Meanwhile, an ongoing court case at St. Albert Provincial Court, Alberta, suggests the level of difficulty in extracting oil in this way – placing the environmental issues in terms of financial costs, through legal action. Syncrude faces charges relating to the deaths of more than 1,600 ducks on its Aurora settling basin. As reported in the April 29 Vancouver Sun newspaper:
Syncrude lawyer Robert White argued in court that federal and provincial charges(The case continues.)
related to the 2008 deaths of more than 1,600 ducks on its Aurora settling basin
should be dismissed because the oilsands company had a permit to operate the
tailings pond and requires it for the extraction of bitumen.
"If, therefore, Syncrude is guilty of this crime, the government is complicit and the
industry is doomed," White told Provincial Court Judge Ken Tjosvold.
White said the industry is "alarmed" by the charges because oilsands producers require settling basins to operate and won't know where they stand if Syncrude is convicted.
In addition to oil, these fields are held to be rich in natural gas – which has been promised both to regular North American consumers and the oil sands industry.
In April, the Canadian government published a report by the country’s National Energy Board, Short-term Canadian Natural Gas Deliverability 2010-2012, examining a decline in gas exports to the US. This states:
Financial markets in 2009 made it difficult for producers to raise capital.Of course, this does not comment on gas reserves, so much as the state of the industry as a whole. The problem here – and across the oil sands – is recouping investment. Again we are seeing producers with debt problems struggling to raise capital for future exploration and extraction ventures. (A cynic might observe that if oil sands extraction was running so hot then the domestic price of natural gas would be immaterial; there would be a ready market at source.)
Particularly for junior producers in western Canada, this meant that cash flow
was the only source of drilling capital for much of the year. Those markets have
since improved, but capital is still likely to be more difficult to access than
in 2007 and previous years. Producers that do raise capital have indicated
a preference towards paying down debt or buying existing production rather than
drilling. Relatively higher costs and longer distances to major gas markets have
decreased activity and production and the resulting deliverability in western
This is more than just an issue for investors and shareholders, because – just as we’ve seen with crude prices over the past two years – market turbulence can have surprisingly long-term effects on output. Dropping Canadian gas output could even lead to a future increase in the price of gas. Bill Powers, editor of Powers Energy Investor, writes: “I expect that the drop in Canadian imports will push natural gas prices into the double-digits by mid-2011 if not sooner.”
This is of particular concern to those that believe that the effects of peak oil – diminishing supplies and surging prices – will be felt sooner rather than later. Our economies are currently in such a perilous state, reeling under massive debt, that a sudden jump in the price of oil and gas could prove disastrous.
There may well be large reserves in the oil sands, as the optimists will doubtless go on reminding us – but, at the risk of being pessimistic, just who is going to pay to extract it in a freefalling economy? When we are paying high prices at the gasoline pump it may seem logical to expect the market will determine this, but then, how much of this money will be going into the coffers of the Western Oil companies? And even with increased profits, no-one can deny that oil sand schemes need massive injections of finance and require long lead times. And as it currently stands, the world has “rusting oil and gas infrastructure” – as Matt Simmons observes. It would be unrealistic to expect oil sands (pic below) outputs to surge, let alone live up to the hype, in a recession.