Grant Hofer – Barclays Capital
Okay, I think we’re going to get started. For those of you who don’t know me, my name is Grant Hofer. I am the midcap E&P Analyst here at Barclays. Very pleased to welcome Baytex Energy today. We have Derek Aylesworth who is the Chief Financial Officer. Derek has been with Baytex since 2005 when he joined as CFO. Prior to that he was with EnCana and I’ll pass it on to Derek.
Thanks Grant and thank you Barclays for having us. For those of you who were in the room before, ENI [ph] is quite a different company than we are. Earlier in my career I did work with ENI and it’s nice to see that they’re doing all right without me.
If you take a moment please do review our advisory on the forward looking statements. This slide just highlights the investment thesis behind Baytex. What we strive to do is execute what we call a growth and income model where we’re trying to deliver organic production reserve and dividend growth. We have a second lead in capital efficiency and that’s one of the key differentiators for our story. I'm going to go through the history of Baytex and some of our key projects and show you why we’re going to be able to maintain that a second-leading capital efficiency. We are very technically focused. We have a very, very large inventory of identified captured projects that we’re going to be able to exploit for the foreseeable future and with the strength of our balance sheet we have absolutely no financial constraint to executing our growth plans.
A bit of a background on our corporate securities. Baytex is listed on the Toronto and New York Stock Exchanges. We have a lot of liquidity in our issue. Current enterprise value is just shy of $6 billion Canadian. We do pay a dividend on a monthly basis, $0.22 per share per month. That translates to a yield of 5.7% based on today’s price. Since inception we have distributed about $1.4 billion of dividends and distributions. That’s an important number to keep in mind when we look at our balance sheet. We have materially improved the strength of our balance sheet while growing our asset base and paying a significant dividend. We have not been a cash retention vehicle. We do have a couple of outstanding senior unsecured debenture issues. So where do we operate. The vast majority of our businesses in the few western provinces in Canada, we do have a small but growing business unit in the North Dakota Bakken. We’re a heavy oil focused producer. 73% of our current production of heavy oil, 14% light oil and NGL and the balance about a sliver of natural gas production.
The vast majority of our reserves are oil and liquids and our production is weighted 60% to Alberta, 34% to Saskatchewan and the balance between BC and the U.S. I’ll spend a little bit of time talking about history and history is that, it’s what we have in the past and it’s maybe not super relevant for where we’re going but we think it's important to give you a sense of what we've been able to deliver in the past because I think it should give you some confidence on our ability to continue to deliver going forward. 2012 guidance is to average approximately 54,000 Boe per day of production. 87% of that is oil. That level of production would translate to about an 8% compound annual growth rate over the last number of years of Baytex’s existence.
We are oil focused. Virtually none of our drilling expenditures are going towards natural gas projects. So our oil and our liquids growth is accelerating faster than Boe per day growth. 46,900 barrels of oil and liquids is the oil and liquids contribution of a 54,000 Boe a day guidance. We’ve been growing our oil and liquids at an 11% cater over the same timeframe as the 8% Boe per day growth in the company as a whole.
This is quite a dizzy slide but it’s a very, very important slide to start to tell the story of our historic capital efficiencies. If you just look at the right-hand column our long-term averages for finding and development costs, including and excluding future development costs for the eight year period from 2004 to 2011, excluding FDCs we’ve added reserves at an average of $9.55 per Boe including FDCs $14.40. Those are top quartile numbers for the Western Canadian Basin and we’ve been able to add reserves at a relatively low-cost and obviously as a commodity producer that's critical when you don’t control the selling price of your goods.
Recycle ratio, if you don't use that metric, Recycle Ratio is simply operating net back per barrel divided by the finding and development costs or for every dollar you put in the ground how many dollars do you get back out, we've averaged 2.9 times over the life of the business. That’s about twice the recycle ratio for the Western Canadian Basin as a whole. So by this metric we’re about twice as profitable as the basin as a whole. The two bottom blocks of data are also important for understanding the income component of our model. Since inception we’ve spent 54% of our internally generated cash flow on E&P activity. By spending that 54% of cash flow we have replaced 173% of our production. So in other words, we have grown our reserve base spending just over half of our cash flow. If you follow the E&P space you know that’s a very, very rare achievement and I'm going to talk a little bit about why we've been able to do that.
This slide, although we talk about growth in production, this is a slide that talks about growth in production and reserves on a per-share basis. Because the dividend is a very material use of our cash flow, we thought it is more instructive to present growth per share on a dividend and debt adjusted basis because a lot of our peers don't pay that meaningful dividend that we do. On a dividend and debt adjusted CAGR, long term we’ve been able to grow reserves 15%, oil reserves 15%, total reserves 13%, oil production by 10% and total production by 8%, very, very positive numbers for a consistent long period of time.
Our reserve picture at the end of 2011, we had 252 million barrels of 2P reserves booked. That translates to a 13 year Reserve Life Index at our current production rates. 92% of those reserves are oil and liquids. In addition to the reserves we do have a significant amount of contingent resource identified and I’ll speak to those in a little bit more detail in a moment.
Reserve growth, on the oil side again is a 13% CAGR. Again, we’re focusing on oil growth rather than boe/d growth. Contingent resource, under the Canadian Reserve Booking Rules, there is a separate category of resource that’s over and above reserves, described as Contingent Resource. What Contingent Resource is, is something that our reserve engineers have a same degree of technical confidence that the oil is in the ground and can be recovered using today’s technologies as they do with our reserves, the difference being that with a contingent resource there is some non-technical contingency that needs to be listed before these barrels can be moved in the reserve category. Examples of those non-technical contingencies could be things like is there regulatory approval, is there a market idea of a pipeline to bring the product to market. Do you have company commitment to spend the funds.
In our case, our best estimate for contingent resource, the 50% probability case, is an additional 738 million barrels of reserve over and above the 252 million barrels of reserve booked. In terms of a net present value, at the end of last year on the price deck of our reserve engineers net present value of our reserve book was $4.8 billion, NPV [ph] the best case, 50%, probably a case of our contingent resource $4.9 billion. With a $6 billion enterprise value, our valuation is very well supported with already identified barrels in the ground.
Long range plan in terms of where we plan to go going forward, we’ve built up a long range plan and we’re in the process of refreshing that now. That last year’s long range plan, we went to our reserve engineers who are responsible for the individual areas that we operate in, ask them on a well by well basis to do a cost estimate, a production estimate, an operating cost estimate, we put that in a database and projected forward what we think we’re able to build our company out at. We imposed a self-imposed constraint of living within cash flow to fund the dividend, to fund the capital program. When you look at our balance sheet we can certainly outspend our internally generated cash flow should we choose to but for purposes of the LRP that was a constraint that we imposed. Living within that constraint we were able to grow our production at a compound 8% per year, at the same time that we’re paying our $0.22 per month dividend for the life of the plan for 5% years from 2011.
This is a slide of the various components of the production contribution from our LRP. The ledge that you see this contributing to the growth is the green growing ledge in the middle and that’s our Seal Thermal project and that’s a good segue into some of our heavy oil projects I’ll talk about where our growth is coming from.
Seal is the single project that people associate, most with Baytex. This map shows you our land position at Seal. Our lands are identified in yellow. The diagonal piece at the bottom here is a section of land that we call Reno. We acquired the Reno lands in 2011. The balance of our lands to the north and the center of the map are what we call our legacy lands. I only make that distinction because in the continued resource study that we have done, we had only commissioned Sproule to do a contingent resource study on our legacy lands so that significant land base at the bottom of the map has not yet been studied for contingent resource. There is potential to expand the resource base as we go forward and understand that land more deeply.
The blow up maps on the left hand side here show you where our current operations are. The red stars are strap tests, so non-producing core holes that have been drilled to give us some information on the depth of the reservoir or the oil in the reservoir and the producing characteristics of the rock. The horizontal lines, the black lines are cold producing wells and by cold producing wells we simply mean wells that have no thermal stimulation. They are just open hole, a mile long horizontal wells. The red are thermal production and I'm going to talk at some length about the difference between those two development techniques.
In aggregate we’ve got about 260 sections of 100% owned land. So 260 square miles of land that Baytex is the sole owner of. Our land position at Seal was developed through basically crown lease acquisitions other than the Reno acquisition earlier last year. For some context we were one of the early movers in this area. Our legacy lands, we acquired in aggregate for about $25 million. One of our competitors in the area, Penn West about a couple of years back farmed about half of their lands to CIC, trying an investment Corp that farm out transaction valued Penn West’s position at about $1.8 billion. They had a slightly larger land base. We think that ours was a better land base but it just gives you some context for one of the reasons that we’re very, very profitable in this year. We were in an early move to acquire lands at very, very low costs.
We started our drilling operations in 2005, went from basically a standing start to a point where today we’re producing almost 20,000 barrels a day of oil at Seal. Cost metrics at Seal are very, very impression on a cold basis. Today we’re doing most of our cold drilling on an eight lateral horizontal well and I have a diagram on the next slide to show you how it looks like. CapEx is about $2.1 million to drill, complete and equip a well. For that we’re getting initial production rates in the range of 400 to 500 barrels per day ultimate recoverables, just shy of 100,000 barrels per well. That translates to a finding and development cost of about $4.60 per barrel. Seal is the single largest development project that we’ve got and if you remember our historic FD&As [ph] of around $9.50 using cold technique we can add reserves here at about $4.60. So going forward we’ve got at least one project that’s been able to contribute, is going to be able to contribute future growth at very, very good metrics.
Recovery factors using cold are between 5% and 7% of the original oil in place leaving a very, very large target for secondary and tertiary development. We’re going to be moving to thermal development for those areas that are not amenable to cold quite quickly, those areas that we have started production on cold, we’ll come back and add thermal recovery once we’re finished with our coal development.
This slide just shows you a picture of that multi-leg cold well that I talked about. So the technique is you drill down vertically about 600 meters until you hit the sand, branch out and go vertically for about a mile and we go in this pitchfork design. The reason that we have moved to this original vertical wells with single legs to branch out and move into multi-leggers was simply a cost efficiency. The benefits of the cost efficiency are noted at the bottom of the slide. When we were doing single wells we were adding production at about $7,100 of flowing Boe [ph] barrel. Our average multi leggers today are adding production at around $5,000 flowing Boe [ph] barrel. So we’re adding efficiencies. There is less surface disturbance. You only have surface well pad with a multi leg or so. So this environmental disturbance also lowers OpEx because they have a concentration of production at a single delivery point on the surface.
This slide shows you the improvement initial production rates and ultimate recoverable by adding the legs. So in other words, for 13 legger we are getting 350% of the ultimate recoverable of the initial rates that we used to get with a single legger 250% of the ultimate recoverable compared to what we did with a single leg well.
For thermal development we have looked at a couple of different techniques for thermal development. We landed on (inaudible) Huff N' Puff. Obviously Huff N' Puff is simply a single well that you drill, again single-leg vertical well, inject steam into that well, let the steam soak and produce back out of the same wellbore. We believe that recoverable using (inaudible) will be in the neighborhood of 30%. So a significant uptick in ultimate recoverable from the cold production. In terms of cost metrics, we’re now working on a 15 well model. Our first commercial development was a Kerrobert Oil Project. Going forward we think we’ll be using a 15 well module. CapEx for a 15 well module is approximately $55 million. For that investment we think we’ll get from the 15 wells, a peak rate of about $2,024 barrels per day of production, ultimate recoverables about 7.5 million barrels.
So that $55 million to recover 7.5 million barrels of oil, we’re spending about $8 or $9 per barrel for FDCs, for Finding and Development Cost, again lower than our historic FDNA [ph] costs. Finding and Development Cost. Project economics using thermal rates returns in the neighborhood of 30%, PV [ph] came at about $70 million for that $55 million investment.
This slide is a picture of our current development at Cliffdale. The black blinds are the wells that have already been developed in our initial Kerrobert Oil Project. The red is a 15 well project, that’s our next step out that’s currently in regulatory approval process. We’re hoping to have approval in place that we can start to drill those wells by the end of the year.
The first well that we injected steam into in the Cliffdale projected is bolded and the next slide speaks to the results of that initial well. The brown lone here is cold production. So the oil reservoir here is quite tight. What we do to commence our steam project is put the well on cold production for a period of time so produce out some oil without the aid of steam. That cold production creates some voids, so empty space in the reservoir so that when we go back to inject steam there is a physical place for the steam to. The first cycle creates a modest level of production, by itself it creates more voyage [ph] and what you’re seeing is that over the second, third and fourth cycles we’re getting a better production response and more cumulative production.
The next slide maybe says the same story in a more clear fashion. By cycle we've been able to get more cumulative production earlier. We’ve been able to get more steam in the reservoir. So the first well in our thermal [ph] module is responding exactly as we expected to. It’s online with what our modeling would have suggested that it would be and you are seeing a better and better response as we go through with subsequent cycles.
In terms of reserve recognition at Seal, remember we have 252 million barrels of oil equivalent booked for the entire company. Of that 252, 120 million is booked at Seal and at Reno. We have reserves booked on total of 36 sections of our 263 sections of land. Of that 36 sections of land only two sections have thermal reserves. So two sections out of 263 sections have thermal reserve booked. We’re very, very much in the early days of building out our operations here at Seal.
In addition to our Seal heavy oil resource play, we do have what we consider the greater Lloydminster heavy oil area. It’s really the bread and butter of the historic development area for Baytex. The story with Lloydminster is traditional heavy oil. Heavy oil is typically at relatively shallow depths and when you drill a single vertical well you can intercept multiple pay zones. The multiple pay zones result in lower finding and development cost because you’ll produce out the most prolific zone first, plug it, move to the next zone and recomplete to produce from the next zone. Those recompletions have been historically able to add reserves at $1 or $2 or possibly $3 per barrel, very, very low cost recompletions and reserve adds. At Lloyd, we are currently producing about 20,000 barrels a day of heavy oil, yearend reserves of about 83 million barrels, our reserve life index about 11 years.
This slide speaks to that multiple pay zone concept that I talked about. We have been developing in the Lloyd area using a multiple of different techniques, vertical wells, horizontal wells, SAGD, foam injection; it’s not a very homogenous area. We use whatever technique is appropriate for the particular reservoir but we look at the Lloydminster area, as I said the cash cow for the company. We don’t expect it to grow materially but there is still unidentified seven years of drilling inventory in front of us. That drilling inventory has grown by about 75% over the last five years that I’ve been at Baytex.
Capital efficiency ratios are very, very good at Lloyd as well. We’ve been adding production at $11,000 of flowing Boe [ph] barrel and finding and development cost of around $12 a barrel. At $12 a barrel, FD&A [ph] cost, we’re getting about a three time recycle ratio at Lloyd based off of our first half $36 netbacks.
Heavy oil investment metrics, the cold development at our heavy oil portfolio delivery is absolutely incredible IRRs. At current WTI prices, the cold development at Seal is generating IRRs that are literally off the charts, 500% at (inaudible) WTI. At current WTI pricing we’re in the 200% to 300% IRR rates for Lloydminster.
This is a slide that was done by one of the competitors for Barclays and what they’ve done is they’ve looked at -- Scotia Bank is the other competitor here. What they’ve done is they’ve taken all of the resource plays in North America whether they’re gas, NGL or oil and ranked from all auto profitability index ratio. So net present value divided by initial investment. What their independent work did was identify that the single highest rate of return project at all of North America for resource plays is still cold. The number five play is the Lloydminster heavy oil. So two of the top five most profitable oil investment opportunities in all of North America as the two largest plays in our portfolio. Having high rates of return projects allows us to grow our business and to find a meaningful dividend and do so in a fairly sustainable fashion.
In addition to our heavy oil focus, we do have a couple of light oil plays in our portfolio to balance out our commodity price exposure. The Viking and the Bakken Three Forks in North Dakota, Bakken Three Forks is the larger of the two plays. In addition to the continued resource that CLS identified we do have continued resource identified at these plays as well. At the end of last year 76.9 million incremental barrels to our reserve booking was identified at Bakken and the Viking.
You may be aware that we did do a disposition of our non-operating position in the Bakken Three Forks in the second quarter of this year. We were approached on an unsolicited basis and received an offer which was I guess too good to refuse. We are not backing away from the Bakken but what we did do is we sold about 900 barrels a day of production for about $270 million, very, very, very big metrics. What we were left with was our operating position with that incremental cash that we’ve got in our James; we can continue to grow our production in the Bakken at the pace that we want to manage its growth. Light oil investment metrics, same side as the heavy oil, very, very good rates of return at current commodity prices.
Changing gears a little bit, obviously we are in a bit of a bulk commodity price environment, particularly as a Western Canadian producer, we do suffer some discounts to WTI for heavy oil. In terms of the level of discount that’s currently being received on WCS is today actually very, very good. I think yesterday we were trained in WCS at about a $11 discount to WTI. So very, very good pricing but it’s been a very volatile year. We’ve managed our pricing volatility by being an active hedger. Baytex has been an active hedger for the life of the business. Our risk management policy allows us to hedge up to 50% of our financial exposure on any particular variable for a period forward for 24 months from the date of the hedge. This slide shows you where we are for the balance of 2012. We have got 43% of our WTI exposure hedged and about 19% of our WCS exposure hedged. For 2013 we started pulling on our WTI and our WCS. In addition to the heavy oil differential hedges that are noted here, we have moving a very significant volume of our production by rail. Baytex has a bit of a unique advantage compared to some of our competitors in Western Canada in that we have an internally captive trucking division. We’ll remove a lot of our production from the well head to various delivery points by truck. That’s been an advantage for us in the past in that at different points in the year you get a better price depending on whether you’re selling into a light stream or into a heavy stream and by moving a product by truck rather than a fixed pipeline you can choose the high value delivery points to move your products too.
As it relates to rail, that trucking division has given us an advantage in that we can move our volumes to the rail delivery spurs very, very readily where a lot of our competitors that are pipeline connected cant. We are one of the early movers with contracts that we’re working on today, we think that we could have up to about 40% of our volumes moving by rail by the end of the year. That gives us an advantage both in terms of a pricing advantage and in terms of; to the extent that there are pipeline constraints we’re not going to be exposed to any potential volume shut ins because of an alternative delivery route.
In addition to the WTI and the WCS hedging we do cover our natural gas condensate FX and interest rate with hedge contracts. The balance sheet I alluded to this a little bit earlier, our balance sheet is very, very robust and getting better all the time. At the end of the second quarter we were at about a 0.8 times debt to cash flow, arguably that’s to me an unlevered balance sheet. We’ve got the opportunity to use our balance sheet to take advantage of opportunities that present themselves. I think there is lots of producers that are in much worse shape than we are and we may be able to pick some people’s pockets as assets are being disposed off to other people’s balance sheets.
This slide goes into probably too much detail on our credit metrics but the only thing I would say here is that effectively we’ve got investment grade credit metrics. We’re not an investment grade rated entity primarily because of our relatively small size and relatively focused geographic position. Our credit metrics are very, very strong. At the end of the second quarter we would note here that we had $300 million of undrawn bank line. Pro forma the receipt of the proceeds of disposition, we’ve actually got about $700 million of undrawn bank line. Lots and lots of room on our line.
So summary slide, I think what I want to leave you with, when you are looking at Baytex as an investment opportunity what you get with Baytex is a company that’s got a long history of successfully executing a growth and income model. You’ve got a company that’s already identified a very, very long runway of development inventory. We’ve got a lot of resource in the ground that’s identified. It just needs to be developed with capital applied to it. We’re moving into an application of a thermal technology that we’ve done in two pilots. We’re working on our second commercial development. We’re beginning to build out our capabilities and so far things are working as exactly as we would expect them to and you’ve got a company that’s a heavy oil producer and not withstanding today’s volatility we very, very much believe that when the U.S. pipeline system is built out things like the Keystone line are in place, heavy oil pricing is going to be in a very, very, very position. So the main product that we’re producing is looking for a price improvement in a not too distant future.
So I think we’re very, very well positioned and this would be the end of my formal presentation and I'm happy to take any questions if you might have some.
Yes, go ahead.
I think you mentioned that the five year plan envisions 8% production growth while there’s room to maintain the $0.22 monthly dividend. Is the intention to grow the dividend over time and anyway you can help us think about a potential growth rate.
Sure. So as it relates to our dividend, absolutely our long term objective is to be able to growing dividend. I think a growing dividend is the most tangible evidence of the profitable growth of the business. We have increased our dividend each year for the last three years. When we look at a dividend increase, a dividend increase is absolutely something that would like to pursue but it’s going to be contingent on commodity prices, it’s going to be contingent on continued operational execution and of course it’s the Board of Directors decision. That said I believe that dividend increases are where we want to go and the way that the business plan is built out with commodity price looking as strong as it is, no promises but that is where we want to go.
Thank you. The capital program efficiency slide, can you just speak to how you’re going to be able to maintain or improve on those metrics going forward/
Sure. The thing that I’d highlight for you there is two things. The capital efficiency is largely driven by the nature of the business and I think I tried to allude to that with the focus on heavy oil. Heavy oil is typically shallower depths. So as you are drilling to find heavy oil you’re not drilling as far. When you’re drilling through multiple pay zones you’re getting more reserve per well and a shorter well. So as long as you have the focus on heavy oil in Western Canada, you are likely to continue to see those relative to our peer group low capital numbers. In terms of ability to improve on those things going forward, we are always looking at technological improvement and at pointed things like the multi leg wells. Again first horizontal wells at Seal were single legs. We’ve experimented with multi legs now. We’re drilling 13 leg wells. The capital efficiency of doing the 13 leg wells is a couple of things. One is the single vertical drill is shared by 13 producers. So you push the limits of that to the limits that you think you can. When you look at other things like tertiary development with thermal we’re looking at different techniques all the time but I think the focus is when you continue to work in the heavy oil environment you are by nature of it, the resource is going to be a low cost operator from a capital perspective.
Derek, post the asset sale earlier this year, balance sheet is obviously quite clean. We have seen some recent M&A activity particularly in the Lloyd area and in your backyard. Where does Baytex fit today with respect to the M&A opportunities?
Yes, we obviously have added reserves and production in the past with M&A activity. We are not a company that’s requiring M&A to meet our growth objectives. When you look at that long range plan that I put in front of you all of that growth was organic. So we’re obviously always interested in opportunities to add value to the company when we’re looking for M&A opportunities, we’re looking for assets that fit within our operational expertise, that give us an opportunity to add production at comparable cost metrics but we’re not driven to do M&A activity just for the sake of getting a bigger company. In terms of balance sheet strength, what you might see us do is do some opportunistic acquisitions if opportunities present themselves. You may see us accelerate and outspend our cash flow for a period of time to get a leg up on that thermal development but M&A activity, we’re always looking for things but we’re not requiring an acquisition to meet our growth targets.
Maybe just extending on your last point there, recognizing that the economics between the thermal and the cold development are quite different. How do you balance those two, recognizing that thermal is the resource prize but economically driven more close to competing with cold.
When we look at our capital allocation, we’re looking at executing a business model and by that I mean we are trying to deliver production growth and maintain a dividend and largely do that with an internally generated cash flow. Different assets do different things for you as you manage your portfolio and when we look at thermal, one of the obvious benefits of thermal is that it’s a low decline source of production. So when you’ve built a thermal production and you’ve got a non-declining wedge in your portfolio your ability to maintain your productive rate as a corporation and offset corporate declines is that much easier. So it’s a portfolio management rather than necessarily optimizing internal rates of return. Growth and income is what we’re focusing Baytex on. We want to be able to put ourselves in a position to be able to afford a higher and growing dividend going forward.
Can you give us just you latest thoughts on heavy oil differentials and how you’re going to think they might trend the rest of the year, what might affect them one way or other?
Yes, so heavy oil differentials are impacted by the things that impact every commodity supply and demand and we also have the unique issue with heavy oil that we have transportation issues from time to time. As I mentioned earlier today the differential is very, very tight, about an $11 discount to WTI. The things that will likely impact us for the balance of the year are ongoing potential interruptions in the pipeline system if there is a downtime in one of the mainlines that impacts all of Western Canada. If things are working the way they are supposed there is a combination of incremental demand coming from some heavy oil conversions with the Marathon and BP Whiting refineries. At the same time there is some incremental volume potentially coming on from Imperial’s Curl [ph] project and I’d say for the balance of this year it’s really an issue of which comes first. Do those refineries get on stream or does Imperial’s Curl [ph] production come on stream. There is a potential for incremental volatility. Again, pipeline interruptions always create pricing volatility. As it relates to Baytex we think that the near term is not so much an issue and by that I mean we have hedged fairly significantly for the second half of this year from a WTI, WCS discount perspective. We just yesterday layered on some hedges at around 15%. So very, very good for the fourth quarter, in fact much, much better than they were for the first half. I think 23% was the average WCS differential for the first half of the year but there is a potential for between now and say mid 2014 for incremental volatility, incremental production volumes causing challenges for us. I think by the time we get Keystone online, you’re going to have a very, very positive pricing picture because we’re accessing the Gulf Coast, using the Maya to WCS pricing marker, Maya is the Mexican heavy oil blend. It’s a very similar quality to WCS. Today Maya is getting about $20 a barrel premium to WCS. When you transportation adjust that it’s probably about $10 to $12 premium. So there’s an arbitrage there that’s likely going to be closed when we get access to the Gulf Coast refining region. In the near term there is potential for volatility. Today WCS pricing is very, very good.
Grant Hofer – Barclays Capital
Great, well we better leave it there. Thanks very much Derek. Appreciate it.
Thanks very much. Thanks for your attention.
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