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Based in Calgary as BMO Capital Markets’ oil and gas analyst for Canada, Mark Leggett shares his home province with what’s called Canada’s “trillion-barrel tar pit.” Alberta’s oil sand deposits reportedly contain about 1.7 trillion barrels of bitumen in-place, comparable in magnitude to the world’s total proven reserves of conventional petroleum and second in volume only to Saudi Arabia. The catch? It costs up to $25 per barrel to extract oil from oil sands, compared to $2 to produce Saudi crude—numbers that don’t work well with oil at $50 a barrel. In this exclusive interview with The Energy Report, Mark talks about oil sands plays and how today’s oil prices affect them. He says that may not yet have bottomed out, but longer term he sees restored demand growth that will cause prices to climb again.

At that point, oil sands production may nudge peak oil’s day further into the future. Global oil consumption stands at about 87 million barrels per day, a figure that—despite recent demand destruction in North America and Europe—will climb as ascendant economies in India and China increase their appetites for oil. Peak oil theorists argue that production of conventional crude is already maxed out, meaning imminent shortages and sharper price spikes; more optimistic experts believe that peak oil’s day—when production of conventional crude reaches its pinnacle—won’t dawn for 20 to 30 years.

The Energy Report: Oil sands seem to be a big Canadian opportunity, particularly in Alberta.

Mark Leggett: It’s certainly topical in terms of what oil price those projects need to move them forward. In this economy, and with today’s oil prices, we’ve seen a lot of companies scale back their spending on it. This speaks to the supply response side of the equation. Right now, we’re seeing demand destruction that’s bringing down all the commodities (including oil).

The concern in the medium to long term is (when we do work our way through this trough) will there be sufficient supply to meet that, or will oil prices just run back up to where they were before? In other words, if demand picks up, what amount of supply will have come off the table because of uneconomic price deck?

TER: How far down do you think oil will go? Are we approaching a bottom here?

ML: It looks like it’s hopefully more than the 80/20 rule. I would say that we’re approaching the bottom, but I think we’re going to go into the 40s first. OPEC scheduled another meeting for the end of November in Cairo to reassess the current oil demand and supply fundamentals. The last cut didn’t really do much in terms of supporting oil prices, but the market probably expects a cut, and the speed at which they’re moving speaks to the amount of demand destruction they may be seeing.

TER: Is this demand destruction perceived or real?

ML: It is real. The U.S. gasoline demand is down year-over-year. Given pump prices over $4, I think we maybe have found that inflection point where the consumer just couldn’t stomach that price at the pump and so we’ve seen actual demand destruction there. European demand is down as well as Japanese; so really the OECD demand destruction seems to be getting confirmed by the various members. What the crude oil bulls were looking for was the non-OECD country demand growth to offset that demand destruction.

That’s becoming a concern now because China seems to be softening, and questions remain whether it will be hard landing for them. We have had a little bit of time since the Beijing Olympics, because they built up diesel and distillate inventory to ensure that the lights stayed on during the Olympics. That has now transpired, but I have read articles that electricity demand contracted in China in October so that speaks to softening demand there, too. That is probably why crude oil prices have fallen even lower than what people thought they would.

TER: Do you have any statistics on automotive consumption of oil-based products compared to other usage? If it’s 50% or 60%, that’s one thing, but if it is 25%, demand destruction from less driving shouldn’t have much impact. In other words, what does the price at the gas pump really mean in terms of consumption?

ML: I believe gasoline represents about 50%. That’s from a North American perspective in terms of what refiners are set up to produce. It’s basically a gasoline refining producing system here, which is not necessarily the case elsewhere in the world. What we saw last year and into this year is the “dieselization” of the vehicle fleet in Europe and also strong diesel demand for power generation in South America and, most importantly, in China.

So, demand destruction is very North American-oriented for the gasoline part of the story. But when you look at the data, you see that diesel exports were rising for U.S. refiners because that’s where the strong margin was. Diesel demand, the distillate demand, underpinned strong crude oil prices in the first half of the year. That’s what the refiners were chasing for positive margins, not gasoline. So that was different than the prior year, when it was gasoline-driven. This year it’s been a diesel story, but now we see the European economies going into recession and Chinese diesel demand appears to be softening. That was the one pillar that was supporting strong oil prices; when that started to shake, crude oil prices came down.

TER: Other than the OPEC meeting and reducing production, what else are you looking for to signal that the price of oil is at the bottom and will start to turn?

ML: That’s a great question. The lowest breakeven price I’ve seen from anybody in the world, whether it’s accurate or not, is $30 a barrel. Eventually, a time may come when oil can’t go any lower because nobody can afford to produce it. That would be the ultimate low, but I’m reading that only Saudi Arabia can produce at those levels. Nobody else can. We’re talking about oil sands projects as being a very big piece of the incremental supply picture in the medium term on a global basis, but $80 to $100 oil is required on those projects.

TER: Given the rate of consumption and growth, especially in the BRIC countries, various people are saying that we won’t be able to produce enough oil to meet the demand. Choose your year—2020, 2030, 2050—we will not be able to produce enough oil even if demand continues to slow elsewhere. When those phenomena intersect, we’ll need new oil production to supplement old or ultimately won’t be able to meet demand.

ML: It’s not a stretch at all to say that. Based on a bit of old data—from 2005 I believe—vehicle ownership per thousand people in China was the equivalent of 1917 vehicle ownership in the United States. What that fact highlighted was the ownership growth profile in China is in its infancy. If China just goes to Eastern European standards, it would add an incremental 12 million barrels a day of production to demand, which would take us closer to 100 million barrels a day in global demand if we assume a normal demand environment of roughly 88 million. With demand destruction underway, now it’s coming back down closer to 86 but it’s still in the ballpark. The point, though, is that demand in the long term is fairly visible but the global supply picture of 100 million barrels a day is not as visible. That’s going to be a challenge because you are in constant decline unless you have oil sands. Oil sands is the only project that does not decline.

TER: How does oil produced from oil sands differ from free-flowing crude that comes from oil wells? And why would those reserves not decline?

ML: Basically, a conventional oil pool holds a certain amount of liquid and you erect a well that acts like a straw and you drain oil out of the pool. Eventually, this empties the pool. With oil sands, you mine for the thick, heavy substance called bitumen. It’s basically oil within the sands. At Fort McMurray (Alberta), all the companies have set up the mining processes to get the oil out of the sands. It goes through a number of manufacturing processes. Without going into all the many details, you’re digging up the ground or tar sands, putting that into a process, and extracting a barrel of oil at the end of it.

The Athabasca deposit in northeastern Alberta contains the largest reservoir of crude bitumen in the world and is largest of three major oil sands deposits in Alberta. So it’s an area laden with oil sands. There are better quality reserves in some regions than others, and all the top-quality leases have been acquired. Canadian Natural Resource’s Project Horizon’s first barrel of production there is imminent. But it’s very, very capital intensive because of what it takes to extract that barrel of oil.

TER: That’s why it would take $80 to $100 a barrel to justify it. But why would oil sands be an inexhaustible resource?

ML: “Inexhaustible” may overstate it, but any given area can have a 50-year reserve life. You literally shovel and fill up your trucks and drive the trucks to have the oil sands processed, you have a constant source of supply. You work one phase, maybe 100,000 barrels a day, mining enough bitumen to supply the process for X number of years. Then you move on to the next phase.

TER: Output from that process would represent what level of production relative to the 87 million barrels that are being produced worldwide today?

ML: If all the projects now on the drawing boards were to come on stream between now and 2015, the growth profile that people see is in the order of magnitude of going from nearly three million barrels a day now to five million barrels a day—so adding two million barrels a day of incremental production.

Another huge project that is a good light oil play is the Kazakhstan offshore Caspian Sea Kashagan project. That is an extremely complex play; drilling through a salt dome that’s one kilometer thick to get to the oil. And that’s been delayed year upon year due to cost increases. That project has been delayed now from 2008 out to 2013. So whether you’re mining tar sands at Fort McMurray, which is very capital intensive, or executing a very technically challenging job in the Caspian Sea, it is capital intensive. High prices are needed.

One thing that is consistent throughout the industry, oil is never brought on earlier than expected or cheaper than expected. It is always delayed and more expensive, which speaks to higher price requirements to generate a return on capital.

TER: Given these more expensive production techniques—the tar sands or the Caspian Sea, which requires $80 to $100 oil—why wouldn’t the oil cartel just keep the price in the $70 range? It’s cheap for them to pump it out of the ground and it keeps these other projects from going in.

ML: There have been comments in various industry articles that the $70 to $90 range is something that OPEC is comfortable with. Given their economics, certain countries are comfortable with that, but it also depends on OPEC’s own internal needs for crude oil going forward. That was something new to the whole crude oil demand picture—the Middle East was seeing some refinery growth and increased internal consumption as well. Looking at the supply in the rest of the world, they decided the $90 a barrel made sense but, at the same time, the fact that they’re using more and more of it may push the price higher.

I think right now we’re seeing these ridiculously low prices because of the lack of capital. If you do not have the capital to expand these expensive projects, it’s a lot easier to take crude down than to push it up. If the capital gridlock is unlocked and reasonable terms are being announced and companies can start bringing their projects back to the board for approval and restore capital spending to prior expectations, that would speak to a more visible supply response further down the road—but we have incurred a delay. With that being said, I think it will go hand in hand with better demand as well, which would provide an overall positive sentiment to it all.

TER: It’s kind of a catch-22. Until the demand returns, the price is going to be relatively low, and capital markets are not going to come back that quickly. So they’re going to look for something with a more guaranteed return.

ML: My own personal view is that the whole supply response supports the long-term price. I agree and I understand; I get it, but that’s not going to happen in the near term. That’s kind of putting the cart in front of the horse; we need the demand first or else the supply doesn’t matter.

TER: One of the companies you follow is NuVista Energy Ltd. (NVA.TO) (NUVSF.PK)

ML: Very disciplined, strong balance sheet. The Board is a very, very strong disciplined team. NuVista is in Saskatchewan and Alberta, but they’re trying to take advantage of what’s going on in Alberta because of all the capital that’s been allocated out of the province given higher royalties. So they decided to target a particular area called Wapiti, and they’ve built out a land base there of 110,000 net acres, and they’re targeting a natural gas resource play. And land prices came down because of the royalty announcement in Alberta, so they got their land for a lower price deck.

When we were in the natural gas trough last winter, they were maybe the only company that had access to capital to get a transaction completed. They did a private equity deal with Ontario Teachers Pension Fund, and it was of the view that NuVista was the cream of the crop in terms of a trustworthy, disciplined management team. What they needed to add to their business model was more of these resource plays, longer-life assets, and the Wapiti play is just that. It gives them some internal growth potential, and if they have the multiple to get M&A done, they will also look at that.

TER: So they’re currently producing natural gas, and the Wapiti is an expansion for them?

ML: Natural gas in Alberta and Saskatchewan, and Wapiti is an area within Alberta. It’s a pretty small part of the company right now that represents its growth profile.

TER: One of the companies that intrigues Rick Rule is Oilsands Quest Inc. (AMEX:BQI).

ML: I’ve just heard of them because they’re located in Saskatchewan, which in the good times had everything going for it—the Bakken light oil play, Potash Corporation and Cameco with its uranium play. Then Oilsands Quest came to the table with maybe an oil sands play. Don’t know if it’s real or not yet, though.

TER: That darn province has it all.

ML: It seems to. But they’re a hard working bunch, so they deserve it.

TER: Any other companies you can comment on for us?

ML: In the general sell-off in terms of the companies, it’s difficult to time the bottom, but the type of stock to pick away at on a disciplined basis throughout the bottoming is Suncor. You’ve got to move up the level of quality and go for the bigger companies. Suncor Energy (NYSE:SU) (SU.TO) is a very, very strong company that is oil sands pure play. It’s been around for a number of years and has real production.

Suncorp is the best operator, and has scaled back capital spending in response to current markets. But it’s these kinds of companies that at some point do reach a bottom, and speculation would be that they can’t stay down so low forever; otherwise someone would maybe take a look at them.

TER: When you were on TV, on BNN, when was it that you did that interview?

ML: It seems like every day is a week long now, so it’s feels longer ago that it really was. It was probably only three weeks ago, but it feels like a three months.

TER: At any rate, you mentioned Husky Energy (TSX:HSE) and Oilexco Inc. (TSX:OIL).

ML: Oilexco has become very topical, and we actually went to a neutral rating on that after they reported Q3, because their lead banker, Royal Bank of Scotland, is having an enormous amount of trouble over in the UK. Oilexco had a $200 million line due January 31. The Royal Bank of Scotland extended 70% of that out into Q4 of next year, so that was good from that standpoint. But crude oil prices are so low it overrides getting the credit extension.

TER: Scary for shareholders, that’s for sure.

ML: Yeah, the stock has fallen off more. We’ll see what happens. It’s a great example of a very successful team that just got caught in the crosshairs of a very violent market.

TER: What about Husky?

ML: More of a stable business. Husky has a low breakeven price on their East Coast offshore production of light oil. They do have some oil sands exposure, and actually went into partnership on U.S. refineries with BP. So they’re more of a stable company that will for sure survive this difficult time.

TER: Do you cover just Canadian companies? How does that work at BMO?

ML: Yes, I just cover the Canadian intermediate and junior groups.

TER: Can you tell investors who may be looking to get into oil companies the value of an oil sands play vis-à-vis the value of, say, light crude? It sounds as if oil sands has a pretty darned expensive extraction process versus light crude, which is more along the lines of putting the straw into the big pool under the ground.

ML: Absolutely. That’s why all the conventional light oil plays were chased first. It’s just cheaper and easier. A big part of the cost component for oil sands is labor. Is it possible for labor to come down very hard to bring down the breakeven prices on oil sands? Probably, but for how long would be the question. Would it be maybe a temporary setback for two years, after which labor prices would just go right back up? No matter who you spoke to around the globe prior to the current credit crisis, they consistently reference tight labor markets.

I guess in terms of the oil sands players themselves, companies that did not have a project off the ground yet will not get it off the ground. For instance, UTS Energy Corp. (TSX:UTS), which is a partner in the Fort Hills project north of Fort McMurray, just issued a press release saying that it would be a multiple billion-dollar project, and they don’t have access to capital to be able to fund it now.

Oilsands Quest? A company like that is very interesting when we’re in the $100 per barrel oil price environment. But now if you do not have an asset base with a real cash flow platform, you’re not going to get from Point A to Point B because you need the capital. So I guess I would segregate the oil sands producers from those that have production and those that just have a project on paper. And then if you have oil players that can hit oil wells at lower breakeven prices—EOG has a very good Bakken play in North Dakota—that kind of play can make money at lower breakeven prices and is not as capital-intensive.

So in this environment right now, picking one over the other, I would say you could go with a Suncor, the top performer within that oil sands play. That being said, though, they’re both having troubles right now. I would suspect that if you’re buying an oil investment, you’re taking the view that prices will recover at some point. And if that means that the demand is coming back into the picture, the oil sands will be needed and revalued and there would be good appreciation there for companies with assets that are producing. So the Bakken and the oil sands both make sense for different reasons.

TER: Has Oilsands been pushed down further because of the production costs than a play like Bakken? Or have they been equally decimated by the market in general?

ML: No, I would say the oil sands companies that don’t have a good-sized scale of operations already producing have been hit a lot harder because of their inability to access capital. The Bakken players have been hurt, but they haven’t been killed.

TER: So what kind of movement in oil prices do you see in the near term?

ML: Likely testing the downside. OPEC meetings in the near term are likely the only catalysts to potentially provide support for crude oil prices.

Oil and gas analyst Mark Leggett joined BMO Capital Markets as an integrated oils associate in 2002. He was promoted to analyst in 2004. Based in Calgary, he covers Canada’s intermediate and junior oil and gas producers. A Chartered Financial Analyst (CFA), Mark previously gained twelve years’ industry primarily at Canadian Natural Resources. An oil and natural gas company that produced about 1,400 barrels of oil a day and had market capitalization of about $1 million in 1989, it has since grown to production exceeding 565,000 barrels per day and an enterprise value of approximately $30 billion. Its first delivery of light, sweet synthetic crude from Project Horizon is targeted for late in the fourth quarter 2008, with startup capacity pegged at 70,000 barrels per day, moving up to 110,000 barrels per day late in the first quarter of 2009. Future phases will see production of 232,000 - 250,000 barrels daily, followed in due course by an expansion to 500,000 barrels. As work continues on Phase 1, future expansions to the project are in the design and engineering stages. The University of Calgary awarded Mark his Bachelor’s of Commerce degree in finance in 1990.

Courtesy: The Energy Report
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