So what are oil sands? Oil sands is very low quality crude oil with an API gravity less than 10. Sweet crude is around 35 to 40 API, condensate 50 API, so the higher the number the better the quality and the lighter the product; the lower the quality the more carbon there is in it and the less quality the product is. So, generally oil sands have a low API, the quality of oil sands also varies across the basin and it ranges from about 10 API to 7 API going west to east.
There are three main deposits: Athabasca, which is mainly mining, UTS; Cold Lake -Exxon or Imperial are the very big producers using cyclic steam in situ and then Peace River, where Shell has a huge acreage and constantly talk about increasing that production significantly.

Canada is second in the world now on oil reserves. The term is not quite right because they are not called reserves yet; they are called contingent resources, because it’s a different rule set that the FCC adopts. The minute that changes I imagine the value of all of the assets up here will rocket up.

Right now they believe we can produce about 175 billion barrels. About 5 billion have been produced so far, just to put it in the context, and we’ve been at it 30 years.

Canada is now singularly the largest exporter of hydrocarbons to the US. If you ask the majority of the people in New York City on the street, which country it was they would say Saudi or Iraq or Iran or some other place that they are scared of. The growth from Canada is going to be pretty substantial going forward. That amount of exports is in terms of millions of barrels a day, so it’s 1.6 million. The oil sands growth over the next 10 years is conservatively estimated between 3.5 and 5 million barrels a day. This is pretty profound, however in view of the US demand for production; this amount will not meet the future growth needs of the US.

Types Of Recovery
There are two types of recovery methods: in situ and mining. The challenges are similar. Environmental sustainability over the next 50 years is going to be the most important consideration in the oil sands and there are three features to that concern: one is the use of water, there will be a premium in the use of water and we are going to have to use less of it, so further research into using water in less pervasive ways, such as using water for extraction, will be necessary. The concern is CO2 emissions and emissions generally. It’s pretty clear to me with the sort of profit margins people are making right now out of oil sands that there will be a significant pressure to sequester CO2. It’s a good idea as it presents business opportunities, however I believe the clever companies will go ahead of that instruction.

The last one is natural gas usage. For every barrel of synthetic crude oil you make out of bitumen, you typically need about .7 of an M or 700 standard cubic feet of gas to make it. Some of it is required for energy, but the vast majority is required as a hydrogen source for lightening the barrel and increasing yield. So, if you assume a 10 US dollar for MCF for 50 years, that’s a huge amount of money. Just in the Fort Hills Project, let’s assume for the sake of argument that Fort Hills is three billion barrels, that means we need 2.1 TCF of gas out of the field life. To me it is clearly ridiculous to think that we are going to use all the natural gas that is coming out of Canada and then some for the oil sands, to take a clean product to make a dirty product. So there is going to be a lot of focus on gasification, natural gas substitution and coal gasification. Coal gasification because Alberta has an enormous amount of coal overlaying all of these structures.

The other challenge is workforce. I am a believer in the workforce arriving, there are a lot of people that would love to come to Canada and there is a lot of people unemployed with the right skills in the world, like in Eastern Europe and interestingly even in Ontario and the Midwest.

And then of course, you have a lot of pressure groups which are very powerful in Canada and you have to pay a lot of attention to their concerns and particularly to the First Nations. Those are some of the challenges.

Steam Assisted Gravity Drainage
SAGD should actually say In Situ, in situ is relatively new and we are learning about it now and that’s the area of growth. The idea here is that there is a difference in risk profile in an in situ project, in my opinion, than there is in mining. That isn’t to say they’re bad, I’m just saying it’s different and you need to just be aware of that.

These are the different types of in situ. I don’t intend to go through all of them; I’m just going to list the in situ recovery techniques showing that there are many different types.

The one that’s had the most production thus far is Cyclic Steam and the best example of that is Cold Lake. Imperial Oil produced about 110 thousand barrels a day. You pump in steam into one well, leave it to soak and then you produce the oil from the same well and then you pump in steam again, all from one well. SAGD is the same idea and process except you use two wells, where you pump in the steam continuously and use a second well to produce the oil.

THAI
Another example is THAI and is one you’ll hear a bit about. A company called Petrobank is looking at that at Whitesands. Basically sub surface combustion and in that combustion you get some sort of elevation of the quality of the product. Again, there is a whole bunch of issues there in terms of heterogeneity in the reservoir and how you control the burn front, however if it works that company is going to be worth a fortune.

Mining
Basically, before you get at the lands to start mining you have to drain the lands. That’s a pretty extensive exercise and that happens probably a year or so before you actually get to removing the overburden and then you go in and start removing the over burden, which could be anywhere from one or two meters down to 40 meters, depending on where you are and what sort of reservoir you have. And then you have oil sands formations, they say typically 40 to 60; the range is pretty well anywhere now from 20 to 80 meters. 20 meters is appearing more attractive in areas that have low overburden environments.

Economics
I would argue there is essentially no exploration risk in mining, there is execution risk; and there is capital cost risk and the capital cost risk in mining and in situ is the same: it’s 70% in the upgrader. You need an upgrader for both products. You should not be confused by people saying in situ doesn’t have the capital intensity, it does. It just doesn’t have it sometimes in the same place. Where it really wins is in the long term operating cost if in situ worked well. If you can mitigate the use of natural gas like Opti Nexen are by gasifying, then you end up with essentially free energy from your reservoir to come back into your reservoir and you would just use your yield a little bit. So, it’s quite a clever way of doing it.

In situ
In situ—much bigger resources, so it is going to be of importance. A little bit of a production risk, I would argue. In that it is a well driven sub surface technique. Not as much as perhaps as drilling in the Gulf of Mexico at 15,000 feet. What is interesting are the alternatives that some of these companies are spending a lot of money on land up here. Which is what I think is driving the land price. If you looked at for example Shell, they are spending a lot of money up here. They have been very active in the Gulf of Mexico. Drilled one well in deep water, probably 40 to 50 million dollars. Probably looking for a target of around 100 to 200 million barrels, with a success rate of 1 in 10. Up here you can spend 50 million dollars and you can buy one of the best leases, or historically you have been able to, and that could have 500 to a billion barrels on it. As you can see, there are very different risk profiles involved in this. And with higher commodity prices, the operating costs around 20 dollars a barrel Canadian; you can see it really becomes a hugely attractive proposition.

Pipelines
We need some more pipelines. That is one of the biggest unanswered questions. There are lots of people competing. Kinder Morgan bought Terasen specifically for that opportunity set, which turned out to be one of the biggest transactions last year in the patch.

Enbridge is talking about putting a twin line called the Alberta Clipper. You’ll see a proposal coming forward to take product directly to the Texas coast by a company called Altex. What you are going to see I believe is the larger integrated oil companies that have refining capacity in the US, will take as much bitumen out of Alberta as they can, and they will upgrade it in the front end of their refineries. Exxon is already saying that, Husky is thinking about that as is EnCana. The companies that are not integrated like that will upgrade it in Alberta and there is going to be two different types again.