Canadian Oil Sands' CEO Discusses 2013 Budget (Transcript)

Nov.30.12 | About: Canadian Oil (COSWF)

Canadian Oil Sands Limited (OTCQX:COSWF) Guidance Call November 30, 2012 10:00 AM ET

Executives

Siren Fisekci - Vice President, Investor and Corporate Relations

Marcel Coutu - President and Chief Executive Officer

Ryan Kubik - Chief Financial Officer

Darren Hardy - Senior Vice President, Operations

Robert Dawson - Vice President, Finance

Analysts

Brian Dutton - Credit Suisse

Chad Friess - UBS

Kurt Wulff - McDep Associates

David McColl - Morningstar

Jeffrey Schwarz - Metropolitan Capital

Rob Plexman - NCP Northland Capital Partners

Operator

Good morning ladies and gentlemen. Thank you for standing by. Welcome to Canadian Oil Sands 2013 Budget Conference Call. (Operator Instructions) As a reminder this conference call is being broadcast live on the internet and recorded. I would now like to turn the conference call over to Siren Fisekci, VP, Investor and Corporate Relations. Please go ahead Ms. Fisekci.

Siren Fisekci

Thank you. Good morning and welcome to Canadian Oil Sands conference call to discuss our 2013 budget. With me today are Marcel Coutu, President and CEO; Ryan Kubik, CFO; Darren Hardy, Senior VP, Operations; and Rob Dawson, VP, Finance.

Before we begin I will note that today we will be discussing our expectations regarding 2013 production, operating expenses and capital expenditure, our future plans and other forward-looking information. The forward-looking information to be discussed on today's call is based on various assumptions and involves risks and uncertainties, so actually results may differ materially from those anticipated by Canadian Oil Sands and described in the forward-looking information. For a description of the risk factors and assumptions underlying the forward-looking information, please refer to the cautionary advisories in our press release and guidance document, both issued on November 29, as well as our third quarter 2012 report and our annual information form which are available on SEDAR and our website.

Certain financial measures referred to in today's comments are not prescribed by Canadian Generally Accepted Accounting Principles. For a description of the financial measures, please see our November 29 press release and guidance document and our third quarter 2012 report. All figures are in Canadian dollars and are net to Canadian Oil Sands unless otherwise indicated.

I will now turn the call over to Marcel.

Marcel Coutu

Thanks very much Siren. In terms of an agenda today, I will review some of the operational highlights of our budget release, then Ryan will review the financial guidance and we will close by providing a view beyond 2013 after which we will turn the call over to questions.

In late 2010, we announced a major multiyear capital investment program directed at supporting strong, stable, long-life production, achieving operational efficiencies and improving environmental performance. This program is progressing on plan and we expect it to be largely complete by the end of 2014. In 2013, we expect that about 63% of our capital budget will be directed towards major projects, including regular maintenance of business expenditures we expect to invest about $1.3 billion at Syncrude in 2013.

More specifically then, $570 million is earmarked for mine train relocations and replacements. This investment supports reclamation work and robust production rates at Syncrude over the next 10 to 20 years. At our Mildred Lake Mine, we are over 35% complete on the construction of two new mine trains. This is the largest project and it remains on budget and on schedule for a target in-service date of Q4 2014. These new mine trains will be the most advanced in the industry incorporating new wet crushing technology and 10% to 20% larger capacity than our previous facilities and Mildred Lake. This should provide further flexibility in our mining operations, improve bitumen recovery, and lower maintenance requirements.

At the Aurora North Mine, where we have newer equipment, we are moving two mine trains. This project is about 50% complete and we expect it to be finished in the first quarter of 2014. Secondly, we plan to invest $266 million in Tailings Management infrastructure. We are building a composite tails or CT plant at the Aurora North Mine, where mature fine tails or MFT, and I apologize for the acronyms, are mixed with gypsum and coarse tailing sand to transform the MFT into a solid material suitable for reclamation.

A similar plant has been operating at the Mildred Lake Mine for over a decade and the plan has always been to construct a CT plant at Aurora North. However, we needed to have accumulated sufficient inventories of MFT to process. After ten years of operations at Aurora North, we are now at that stage. This project is over two-thirds complete and on track for an in-service date of Q4 2013. In order to meet our requirements under the Alberta Government’s new Directive 74 Tailings Regulation, we are also investing in new technology to accelerate the reclamation of tailings.

We will construct a centrifuge plant at our Mildred Lake Mine to process tailings at a total estimated cost of $1.9 billion gross to Syncrude. Syncrude has successfully piloted this technology with a commercial scale demonstration plant operating on our site. Construction of the centrifuge tailings management project began late this year and is scheduled to be in service in the first half of 2015. Finally, we expect to spend close to $400 million on regular maintenance of business in 2013.

We are very pleased with the progress on our major capital projects. Importantly, we remain comfortably on schedule and on budget. Under the management service agreement with Imperial Oil and Syncrude, ExxonMobil provides the project management expertise and their proprietary [mcaps] process to all of Syncrude’s major projects. Looking forward, we are confident in ExxonMobil’s cost estimates and schedules for these projects. They are based on detailed assessment of the underlying work including advanced engineering design and execution plans, calibrated with actual local and global cost data.

Now in terms of our expectations for Syncrude operations in 2013, our production outlook for the year is 39 million to 42 million barrels net to Canadian Oil Sands. The single point production estimate then is 40.4 million barrels, an increase of about 3% over our 2012 production estimates. Our outlook includes one Coker turnaround in the second half of 2013. We continue to believe that there are production gains to be achieved at the current Syncrude facility. Under the management service agreement with Imperial Oil, Syncrude has developed reliability improvement plans for each business area of the facility based on ExxonMobil’s global reliability management system.

Improvements realized to date include reduced slurry system failures and fewer bitumen furnace tube leaks, as well as 36 months run lengths on two Cokers, up from an average for all three Cokers of 28 months. A significant improvement. We have also made modifications to some units to reduce solids content in the feed going to the upgrader. These solids were causing unplanned downtime and contributed to significant loss in production over the last few years. We believe the improvements achieved to date establish a stronger basis for higher, more stable production rates going forward.

Syncrude’s capacity utilization is similar or better than that of our peers. So what we are talking about is gradually improving. Such that we clearly achieved industry leading utilization rates. Improving utilization rates continues to provide our best growth economics. The benefits largely going directly to our bottom line with minimal investment. As well, operating expenses have become more predictable enabling us to meet the total operating cost target on average that we have provided to the market in the last three years.

Our analysis indicates that Syncrude on average is the lowest cost producer of light, sweet, synthetic oil from the oil sands. For 2013, we are anticipating operating expenses of around $1.5 billion or about $37 per barrel. As you know, per barrel operating cost are significantly affected by production volumes because of the fixed cost nature of our business, our anticipated 2013 operating costs are very similar to the levels we have demonstrated over the last several years. And it’s important to note that this is the cost to produce a fully upgrade sweet, crude oil barrel generating much higher margins than bitumen or other medium heavy or sour blends, which is a competitive advantage that we continue to enjoy.

With that I will turn the call over to Ryan to review the financial highlights.

Ryan Kubik

Thanks, Marcel. I will run through the highlights and for further details, I will point it to our 2013 guidance document available on our website. In 2013, sales net of crude oil purchases and transportation expense are estimated to total about $3.2 billion based on an $85 WTI oil price, a $5 per barrel discount to WTI, and our 40.4 million barrel production target. At an $80 per barrel realized oil price assumption, cash flow from operations is estimated at just over $1 billion or $2.16 per share. A portion of this cash flow will be directed to funding our 2013 capital program.

We take a multiyear view of our finance plan and had prepared for this major capital projects program by building cash on our balance sheet. In addition to the cash generated in our business, we expect to have about $1.5 billion of cash at the end of this year. These funds will be used to support our capital program and our dividends. At $0.35 per share per quarter, our dividend would amount to $680 million for the year. In 2013, we also planned to repay $300 million of debt maturing in August.

Our finance plan does anticipate net debt levels rising to about $1.3 billion dollars at the end of 2013, and $1.5 billion to $2 billion by 2014 which reflects us drawing down on our cash balances and retaining the debt that we have already termed out. At those levels, we would continue to have a strong balance sheet which remains a key objective for us.

The 2013 budget includes $350 million of current taxes. We do see the 2013 levels as relatively high and anticipate reductions in future years as we begin to apply the tax deductions related to our 2010 to 2014 capital program. Under the rules of use, these deductions cannot be applied until two years after spend, so we will see those take effect in 2014. We are aiming to maintain a quarterly dividend, up $0.35 per share in 2013 based on our 2013 budget assumptions. Our core strategy continues to be providing our investors with long-term oil price exposure while paying a relatively high portion of our cash flow to our investors as dividends. And because we don’t hedge our oil production, changes in oil prices could have a material impact on our plans.

We do, however, take a long-term view of our finance plan to avoid making short term adjustments to the dividend. I expect that some of you might have specific modeling questions so I would ask that you hold off on those questions until after the call, at which time both our IR and finance teams will be available to walk you through the details.

Marcel Coutu

Thank you, Ryan. In closing, Canadian Oil Sands is confident as we enter 2013 as we are actually ahead of where we plan to be at year-end 2012. We have a very strong balance sheet with the capacity to support our capital program and dividends. Our roughly 7% yield represents one of the best opportunities to receive rent on a long-term oil investment. Our current value in the market is well below replacement cost for the Syncrude asset. Syncrude continues to demonstrate solid production rates and we will progress our reliability initiatives to increase capacity utilization.

Our major projects are progressing on plan and we expect to be largely complete on two of the four projects by the end of 2013. Those being the Aurora North Mine train relocations and the tailings management projects. Syncrude’s superior legacy lease position provides us with many opportunities to optimize value. You will recall that late this year we announced our intention to extend the Mildred Lake Mine. The now called MLX project will be without a doubt in my mind the most economic new incremental mining production to come on-stream in the next ten years because it benefits from existing infrastructure.

MLX will further leverage the investment we are making in the construction of the new mine trains at Mildred Lake. The scope of the MLX project, primarily involves the construction of a bridge and extension of roads and power lines. Once complete, we will be able to utilize the new mine trains as well as the existing extraction and utilities plans to process this new ore body, resulting in both enhanced economics and a reduced environmental footprint.

Spending on MLX is not anticipated to begin until later this decade, providing our investors with several years of potentially significant free cash flow expansion beyond 2014 once capital spending on these major projects are complete.

Now with that I will turn the call back over to the operator for questions. Thank you.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from the line of Brian Dutton from Credit Suisse. Your line is open.

Brian Dutton - Credit Suisse

Your annual and notional quarterly guidance implies you have lower confidence in Syncrude's operations for 2013 than at this time last year for 2012. So why last year were you expecting some quarters to average as high as 340,000 barrels a day whereas this year you're only looking for a max of around 315,000 barrels a day in any quarter?

Marcel Coutu

Well, I guess Brian we did not exactly hit our annual numbers last year as you know as we come into the end of this year on aggregate. So I would say that generally speaking, we are trying to build yet a little bit more conservative approach in the plan and close in on what appears to be confident production levels from Syncrude. The other thing is that last year we had a couple of cycles of turnarounds as you know, one planned, one unplanned, and that creates building of inventory. So you do get a bit more volatility from quarter-to-quarter as we produce inventories that collect between those turnarounds.

Brian Dutton - Credit Suisse

So on the -- I guess really the design capacity, is it really 350,000 barrels a day?

Marcel Coutu

Well, that’s yet to be seen, Brian. We had seen stream days that get right up to that 375 a day and to get to 350 or whatever the average number is going to be over whatever period of time you want to pick, and I think the market necessarily picks a 12 month fiscal period, it all depends on how long we can get these stream days to string together for an average rate. Obviously, the average rate has been closure to 300,000 barrels a day than 350. But we continue to point to significant upside there, 15% to 20% more that can be achieved as we perfect this operation.

I think the difficulty, Brian, is that nobody in the industry has done it. And if you go back and you look at what all the projects were designed to do without re-rating any of them, you will see that that utilization rate is in the 80% to 85% rate and that’s about where we are and in fact we are probably at the higher end, some are below the 80% rate when you look at multiple years of production. So we are looking to break new ground against what the engineering design has been at Syncrude and these design standards if you will, with the reliability expectations that were put into them when our project or other projects were built, puts in a position and the challenge of the question that you pose while we get to 350.

The only thing I can tell you there Brian is that before UE1 was built and Syncrude had run some 20-25 years with the two original fluid Cokers, that operation actually managed to get through design capacity before we built UE1. So I think the potential is there. There are many refineries around the world who have demonstrated that. The complexity of this business is that we also have to manage the feedstock which is in close matching capacity and upsets in one area will slow down the other area. So we have to get that chain of events working well and that that’s again an industry challenge that we are looking to overcome and we have a lot of resources going into that and continue.

We will not re-rate this project, if you will, until we are not convinced that it can't be achieved.

Brian Dutton - Credit Suisse

I guess last question then, do you think is the root problem of the reliability more in the upgrader or in the bitumen delivery?

Marcel Coutu

I would categorize the areas as three, not just two. There is the bitumen -- there is the mining which creates a slurry that goes to a second intermediary area which is extraction where we separate the sand from the bitumen and the other solids. And then there is the upgrading as you put it. Historically, the upgrading has been the most complex and difficult. With ExxonMobil’s expertise and help they have dramatically improved the production of the upgrader. The challenges that we are tackling today is reducing the amount of solids that feed brings to the upgrader and causes erosional problems and historic downtimes that I mentioned in my notes.

On the mining side it is really a question of productivity obviously, but that can be fixed in the short-term with more equipment. So really that is not the bottleneck. So the greater bottleneck at this moment I would say is that mid-area of extraction as the upgrader has worked better that is an area that has surfaced as more challenging than it has been historically in large part because it had to step up its pace.

Operator

Your next question comes from the line of Chad Friess from UBS. Your line is open.

Chad Friess - UBS

Wanted to dig into synthetic crude pricing a bit. I see you've set your 2013 expectation at a $5 discount to WTI. And I assume that's related to the midstream and downstream tightness, but I'm interested in your thoughts on how the market for synthetic is changing with all the light oil coming on-stream in North America. And whether you think that discount will persist or even widen.

Marcel Coutu

Good question. And it’s an area that we probably have the least science behind our prediction. So we have tried to be conservative. In the last two years, we have averaged a discount in 2011 of minus $1 and a premium of plus $7 in the following year. So we are in a situation where we are still forecasting discounts but the product for us has priced out relatively close to WTI. The bigger discount of course is the discount between WTI and Brent which is over $20 but that’s not your question.

There is more light oil coming into the refinery market in North America, there is no doubt about that. There is another 1 million-1.5 million of light oil coming from tight reservoirs. We expect that to continue to grow. The most aggressive forecast I think are for another $3 million or $4 million barrels by the end of the decade and that needs to find a refinery market. That oil is finding a lot of its markets through rail in large part because it comes from areas that were not big production before and they are not piped so rail has worked better for them.

Refineries are looking to accept this oil. It’s easier to process. I think that’s clear. So I think that we will continue to have discount for light product which ours is one of and we will find refineries that will take our product that is why we have put down this average $5 discount against what has been really a close to par pricing for a product up to this point. And it’s not to underestimate what the volatility of that was to get there, we have seen discounts and premiums of $15 a barrel in the last two years and we do expect that volatility to continue.

But as Cushing gets piped out to the Gulf Coast with Seaway and Keystone, and that should happen within the next two years, it will open up markets for all of the light oil to find a better home that’s closer to Brent/global pricing. And therefore notwithstanding what the differentials might be, that should push WTI up quite dramatically and close the gap on that $20 that the entire North American oil market would benefit briefly from in the next couple of years.

Chad Friess - UBS

Absolutely. And do you expect to see more or less usage of synthetic as a blend for bitumen transportation?

Marcel Coutu

That has continued to be the trend and as SAGD production continues to grow, synthetic tends to be more and more the diluent of choice largely because the condensate material which is the best diluent obviously is fully utilized at this point and until pipelines are built to bring condensate in from further locations, synthetic will be a very competitive alternative. So that is another very good market for us. Synthetic buyers for diluent of course have to pay the same thing as a refinery does. It’s just a shame that it has to get blended after we put so much work into it to create it, but we are getting our full price for it.

Operator

Your next question comes from the line of Kurt Wulff from McDep. Your line is open.

Kurt Wulff - McDep Associates

For the benefit of some of us here in the U.S. can you give us your interpretation of the pipeline politics in Canada. Like it would be nice if Canadians could export their oil through British Columbia or through Quebec.

Marcel Coutu

You are trying to get me into trouble.

Kurt Wulff - McDep Associates

No, no. I know you're a diplomatic guy.

Marcel Coutu

I am kidding, Kurt. We have a few pipeline options on the docket. They are into their regulatory processes as we speak. I will start from the east coast which I personally would assume should be the easiest process because of the very strong logic. We have East Coast refineries that are importing 700,000 barrels a day from the Atlantic and paying a Brent based price. We just talked about what the differentials are to North American prices. So the industry is looking to reverse Line 9 which goes from Sarnia to Quebec City.

My understanding is that regulatory approvals are pretty much complete regarding a leg to Toronto and we are underway with the same process with Quebec. We actually had a first minister’s conference on the east coast only a few weeks ago that I think gave very initial support, very strong initial support for the reversal of that line, recognizing that we don’t need any new right of way, we don’t need any land disturbance for construction of pipe. We are already seeing oil vessels coming in with product so all we are doing is reversing that process which has been proven to work very well through the last several decades.

So I think the East Coast is a very good outlet for western crude. It serves our country well, as well as the economics of consumers. Unfortunately, we are only talking about 150,000 to 200,000 barrels a day so I don’t want to overplay that but certainly that might see some room for expansion as well once we are through the first stage. The other two major projects going out the west coast are TMX which is Kinder Morgan proposal and Northern Gateway which is the Enbridge proposal, both in 700,000-800,000 barrel per day type of capacity. So that would give the industry great market access for quite a number of years of forward growth here. If and when, and I would say more practically when we can get those constructed.

Those are in the consultation process with stakeholders. That includes all players, governments, aboriginals, NGOs. That process is being done on a scheduled basis so it does have a timetable to it which I think is a very constructive change that the federal government has supported. And therefore the regulatory decisions on those I think should be available to us well before the end of the decade. I won't put an exact date on that but....

Kurt Wulff - McDep Associates

Before when?

Marcel Coutu

Well, I look around the table here a little bit. We could see some decisions coming out of there by maybe 2017. Theoretically it could be sooner but I am trying to be a bit more practical. Construction, Kurt, can be really quick. It depends on the construction spreads you put down to have these projects go ahead. So it is a very important project for Canadians. Canadians want to understand it. I think the public needs to get a chance to appreciate the economic benefits of what this does for the country. I think they all start with a fair skepticism of the environmental risks and I certainly don’t blame them for that. I think the industry starts there as well but it’s fair to say that the industry is probably ahead of the public in the understanding of this since we are the ones designing it.

But I think as it plays through, our national regulator here will make a call regarding a net benefit to Canadians on these pipes and at this point I would say it’s certainly an extremely strong economic case for Canadians across the country, not just Western Alberta because Western Canada or Alberta relies a great deal on Canadian manufacturing across the country to product this oil and of course there is all the GDP that generates and balance of payments. So all of this information needs to be digested, needs to go through the regulatory process and I am optimistic as to what the outcome is going to be. I just kind of keep my fingers crossed that for everybody’s sake that we don’t true up more time than we need to to do that.

And of course, you know, things can intervene such as politics and otherwise as we have seen south of the border. And there is not just the Keystone initiative there, there is certainly projects from Enbridge to take more capacity all the way down to the Gulf Coast. So the solutions are all into the regulators now and once those processes are done, and some of them I think are extremely close like Keystone construction will begin. And again I think construction will be fast tracked with more rather than fewer construction spreads to open up capacity and dissipate these differentials.

Operator

(Operator Instructions) And your next question comes from the line of David McColl from Morningstar. Your line is open.

David McColl - Morningstar

Just kind of wonder if we can put a bit of a crystal ball on here and take a look ahead. There's the talk about the replacement and relocation of the mining trains and the state of the art nature of these things and the benefits that could accrue to Syncrude and by extension Canadian Oil Sands. I'm just wondering if you have any I guess thoughts on what that could mean for operating costs. Are we looking at a 1% reduction, maybe a 5% reduction relative to where we are today? Thank you.

Marcel Coutu

Let me give you a way to think about it. And our challenge is inflation in large part and we work to offset inflation and with the equipment that we are putting in place we are creating some efficiencies but we are not professing with any great deal that that will have a major impact on lowering production cost. But between the work that we have been doing in leveling production cost to date, I would like to think that production cost could remain at this sort of $35 to $38 level per barrel. What we have going for us however is that I also see in this crystal ball that you asked me to look into, a gradual production growth creep. And when you start factoring that in on a dollar per barrel basis, that could take your production per unit down to something perhaps in the range of $30 to $35 a barrel depending on how successful we are in generating greater production through greater reliability.

So I guess the best news out of this is that we are not seeing rampant runaway escalation in operating cost which we did experience for two or three years and I would say that that came to an end two years ago. And now it’s a matter of being more stable. The other thing that we will continue to improve on is yield. And yield is how many finished upgraded barrels do you get from the refinery units that we have from the bitumen that we put in. Currently that runs at about 85%-86% but if you can get 1%,2%,3% more out of that which we continue to work on, you do the math on that and you will see material impact on production rates again with no incremental cost and therefore that denominator effect again working towards something in the direction of lower per dollars per barrel.

Operator

Your next question comes from the line of Jeffrey Schwarz from Metropolitan Capital. Your line is open

Jeffrey Schwarz - Metropolitan Capital

Just wanted to ask about maintenance CapEx. I've seen some creep up over the last couple of years and wonder if you can give perhaps some guidance or guesstimate on what you think is a fair level of maintenance CapEx to use going forward?

Marcel Coutu

Yeah, we certainly have our sort of summary line to that but let me turn it over to Ryan -- not Ryan but Darren to give you a bit of color on that.

Darren Hardy

So as we go through and as we have stated before, our estimate of regular maintenance of business expenditures for 2013 is about $10 per barrel. And we see that it will go up and down, it will vary a little bit from that. But as we look forward, as we get through these large capital projects that we have going on right now, that the lumpiness as we kind of refer to it, it averages out to $10 and it kind of goes away and we think that that is a reasonable estimate for what we will see going forward.

Marcel Coutu

I guess the only other comment I would make is that the $10 a barrel has some growth capacity not growth from $10 but we are currently we are closer to $8 a barrel in terms of that sustaining capital portion. So we continue to work something that may range at plus/minus $1 or $2 around the $10 as a reasonable estimate.

Operator

Your next question comes from the line of Rob Plexman from Northland Capital. Your line is open.

Rob Plexman - NCP Northland Capital Partners

I think you said it's 2018 when spending for the MLX starts to ramp up. How about the Aurora South expansion, does that come after MLX?

Marcel Coutu

Aurora South would necessarily come after MLX, Rob. We don’t want to stack major capital programs and currently we want to complete this one before we start MLX. Actually there is no rush to start MLX because it has to come in behind the exhaustion of the North Mine because it needs to feed its bitumen into the upgrader. We are not building paraffinic frost treatment to allow that mine to sell bitumen or diluted bitumen into the market. So the timing of that will be such that it comes on stream in around 2022 to replace the North Mine volumes.

Aurora South would necessarily come after that, Rob. And we have done a lot of work on Aurora South and we continue to look at the scope of what that project will be. We continue to look at the new technologies that we might apply there and the more time that we have to work these new technologies, the better that project will be both in terms of what it can deliver and what it might cost to put in. So it is a project that is beginning to look like a next decade project in fairness. But it is on the table, it is a great resource and it is in certainty the next mine that we will be opening up when it comes to very large scale production units. And as you know we were looking at 200,000 barrels day with 2 mining trains as a concept that we are pursuing.

Operator

And Mr. Coutu, there are no further questions at this time, please continue.

Marcel Coutu

All right. Thank you, Sarah. I don’t have a whole lot more to add so I would like to thank you for being here today. But I will sort of throw some color on to what the current market conditions are for Canadian oil sands. I mentioned in my prepared remarks that we are trading well below our replacement cost and I do appreciate that this sustaining capital program is creating an overhand on the stock. But I get this question and it relates a lot to where Rob Plexman was coming from, when do we get back to growth. And my point there is that we are in growth mode albeit much smaller scale but with very little investment. Therefore the economics of what we are doing to the bottom line are far more meaningful from a return on equity standpoint.

And when push comes to shove, when oil prices are in the range of what we are seeing today, we can afford to pay a pretty healthy dividend and if somebody is really looking for growth and looking at alternatives across the market, if they were to reinvest that dividend into Canadian Oil Sands, they are basically buying production of light, sweet synthetic at a price of about $80,000 per flowing barrel. If you take a look at what people are spending to build bitumen production, probably closer to $100,000 per barrel. So you can actually buy not only bitumen production but sweet synthetic production and get the resource along for free at $80,000 per flowing barrel today and create your own growth by just reinvesting the dividend.

So I will leave you with that thought when you think about Canadian Oil Sands in the context of today's trading dynamics. Thanks very much everybody.

Operator

And this concludes today's conference call, you may now disconnect.

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