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Baytex Energy Trust (NYSE:BTE)

Bank of America Merrill Lynch Global Energy Conference

November 14, 2012 11:00 AM ET

Executives

Derek Aylesworth – CFO

Analysts

Peter Ogden – Bank of America/Merrill Lynch

Peter Ogden – Bank of America/Merrill Lynch

Next up on the agenda is Baytex Energy. They are a Western Canadian Mid-cap yield focused E&P with heavy oil operations across Western Canada. We have Derek Aylesworth, CFO.

Derek Aylesworth

Thanks Peter and thanks for showing us this morning. Please do take some time to review our advisory on forward-looking statement. Just to orient you a little bit on the investment thesis for Baytex. We have been very consistent with this message and we will continue to be consistent with this message. Our business model is to execute a growth and income business model to deliver a meaningful income stream by a dividend and to deliver organic production growth largely within area of cash flow over time.

We are focused on capital efficiency and when you go through the portfolio slides here, you’ll see that historically we’ve been able to add reserves at very, very modest capital costs and I’ll talk a bit about our forward projects trying to give some insight on to how we’re going to be able to maintain that our performance going forward. We are technically focused. We do have a lot of internally identified and captured inventory in our portfolio already and we do have a very conservative balance sheet that’s going to allow us to fund back the future growth.

So a bit of corporate background orient. Baytex is listed on the Toronto and the New York Stock Exchanges. Today we have an enterprise value of about CAD$6 billion. Our current dividend is CAD$0.22 per share per month which translates to a yield of about 5.3%. Since inception we have paid out a total of CAD$1.4 billion of total dividend in distributions. So when I talk about balance sheet later in the program, the improvements in our balance sheet has not come from being a cash retention vehicle. We have paid out a very, very meaningful dividend stream over the life of the business.

Where do we operate? The vast majority of Baytex’s production is the three provinces in Western Canada; Alberta, BC, and Saskatchewan. As Peter mentioned, we’re very, very well known as a heavy oil producer. The single most significant lever of our production in our in our year-end reserves are heavy oil and that has some competitive advantages and I’ll speak to when we get to our capital spending history.

Historical performance, I’ll spend a little bit of time talking about where we’ve been. History is just added – history and maybe not necessary indicative of where we’re going to go but it should give you some comfort that what we’ve done in the past, we’ll be able to do again going forward. Over the last number of years, we’ve been able to increase production at about an 8% compound annual growth rate on a boe/d basis. As I showed you earlier, the majority of our production is oil and liquids. We’re focused on oil and liquids growth. And when you exclude the natural gas portion of our portfolio, it’s actually grown our production at about 11% CAGR over the same timeframe.

We’re not focusing virtually any effort on natural gas activity in the current natural gas pricing environment. 87% of our current production is oil and liquids. Our current guidance is to average 54,000 boe a day in 2012. We just did released our Q3 results yesterday. Q3 production was 54,381 boe/d which was the highest level of production in history of the company.

Despite a bit of a busy slide, but it’s an important slide to understand the history of Baytex and our capital efficiencies. What this slide is showing you is the result of every dollar that we’ve spent in E&D activity whether it’s internal organic drilling or whether its acquisitions. It shows you the cost that we have historically generated to add barrels and reserves to our reserve book. I we use the long-term average which is a dollar cost weighted average, since inception we’ve added reserves at CAD$9.50 per barrel excluding FDCs and about CAD$14.40 per barrel including future development costs.

Those are very, very low finding and development costs probably top quartile, possible top decile in the Western Canadian basin. The reason that we’ve been able to add reserves at such a relatively low costs is largely the heavy oil focus. Heavy oil is typically found at shallow or depth, so you’re not drilling as far as to access the resource. In a lot of our traditional Lloydminster heavy oil areas, heavy oil is found in multiple stack resources. So one vertical well will intercept multiple pay zones, typically you’ll produce the most prolific first plugged and move to the next most prolific. That re-completion moving to the next zone does add reserves at a relatively low cost typically at between CAD$1 and CAD$4 a barrel. So very, very low cost reserve additions.

The other part of the information on this slide that’s worth noting is the recycle ratio. And recycle ratio is a profitability proxy that’s used in the oil industry or any extractive industry and it’s really just the netbacks that we receive per barrels or selling price minus royalties and OpEx divided by the finding and development costs or in other words, for every dollar you put in the ground, how many dollars you get back out. Our recycle ratio over the life of our business has been 2.9 times before FDCs, 1.9 times including FDCs. But on pre-FDC basis, the industry as a whole in Western Canada has had a recycle ratio of about 1.5. So by this measure, we’ve been almost twice as profitable as the Western Canadian basin as a whole.

Again, largely because of that lower finding and development costs that comes with heavy oil. The last bit of information that I’d add on this slide, speaks to the sustainability of the business model. As I said, we strive to overtime, deliver our production growth and pay our dividend largely within cash flow. Since we started our business, we’ve spent 54% of our internally generated funds from operations on E&D drilling. By spending that much, we’ve replaced 173% of our production. So as you know, most companies in our industry will spend more than all of their cash flow just to stay flat. We’ve actually been able to grow our reserve book spending about half of our cash flow. Very, very good indications of profitability of our business.

Reserves and contingent resource, at the end of last year we had 252 million barrels of reserve booked on a proved plus probable basis. We’ve added reserves every year in the history of the company. 10% compound annual growth rate to our reserve book, so very consistently grown on our reserve story. 13 year Reserve Life Index at the end of year at our guidance levels, 92% of those reserves are oil and liquids. In addition to the reserve bookings that we have, we have some contingent resource that’s been booked by our reserve engineers.

If you’re not familiar with the phrase under the Canadian reserve booking rules contingent resource is a separate category of resource evaluation and a resource is something that our reserve engineers believe has the same technical degree of confidence as being recovered as a reserve, but has some non-technical contingency that needs to be removed before those barrels having moved from resource to reserves. Examples of those contingencies would be things like, do you have a market in your pipeline in the areas, do you have regulatory approval, do you have company Board approval to spend the funds to access those resources?

But from a technical recovery perspective, it should be the same level of contingent as there is in the reserves. On the best case the 50% probability case, in addition to the 252 million barrels of reserves, we have another 733 million barrels of contingent resource. So when I mentioned earlier that we got lots of identified captured drilling opportunities, we have the capacity to up to triple our reserve bookings over time as we continue to exploit our existing captured resource base.

In terms of valuation, the valuation at the end of last year using our reserve engineers’ price specs, the value of our reserves on a proved plus probable basis was CAD$4.3 billion, and extra CAD$4.9 billion for the contingent resource. Total value identified on the 50% probability case, that’s just under CAD$10 billion. I only highlight that because that’s a good indication that our CAD$6 billion enterprise value as the market is getting us today is well supported by already captured and identified projects in our inventory.

Heavy oil assets that I am going to speak to a little bit. The Seal area is the single asset that’s most unanimous with Baytex. This is a map of the Seal area. It’s in the Peace River oil sands in the North Central Alberta. The Peace River oil sands, I’d like to distinguish those from Fort McMurray, oil sands because at Peace River, all of the development is institute, Fort McMurray is largely a mining operation. The mining operations are good operations but they are much more capital intensive. You need to do a mega project to develop the Fort McMurray oil sands. At Peace River, this is basically conventional development, this institute most of our production today is cold, i.e., no thermal stimulation, very significant opportunity to develop.

Incremental resource using thermal development going forward, but it’s a much, much more manageable and scalable development opportunity. Our lands are shown here in yellow. At the time that we did this map we had about 290 sections of a 100% total land. We just announced with our third quarter results that we added to that land acquisition just after the quarter adding about 30 additional sections of land. The blow up on the right side on the map, to the left side of the map rather shows you where our current development is taking place.

To highlight for you what’s happening on this map, the red stars are stratigraphic tests so non-producing cold holes, the black lines are Maya along horizontal producers and they’re all cold. The red lines are Maya along thermal producers. So just orient you with where we are doing our operations. It shows you the build out of our operations Seal. We first acquired our position at Seal in 1999 just through government lease auctions. We spent about CAD$25 million acquiring our 105 section core land base at Seal. And I highlight that because one of the reason we’ve been successful is we’ve been an early mover on this play. The CAD$25 million that we acquired with our – spend to acquire our original land position compares to a couple of other transaction that some of our peers in the group had done.

Shell acquired a competitor company called Blackhawk in the area. It had a comparable land base to what we had at the time. They paid CAD$1.8 billion to acquire Blackhawk. CIC, the China Investment Corp signed farmed into Penn West land base. Penn West had a larger land base than we do, we think it was not as high quality as our land base but the farming transaction implied a value of again CAD$1.8 billion for Penn West lands in this area. So what we acquired for CAD$25 million comparative transactions, a third-party transactions are valued similar land bases, that’s significantly more value.

We started our first production in Seal in 2005. We went on a standing start of no production to about 21,000 barrels a day at the end of the third quarter. Cost metrics at Seal using primary development are outstanding, literally amongst that best place in the world certainly amongst the best place in North America. CapEx for an 8-well multilateral well is about CAD$2.1 million to drill complete and equipped well. For that we’re getting initial production rates are between 400 and 500 barrels a day and ultimate recoverable in the neighborhood of 450,000 barrels per day.

That translates to a finding and development costs of about CAD$4.50 per barrel. If you compare that to our historic cost of around CAD$14 [ph] for including FDC, this shows you that we’re able to add reserves at this play on cold at very, very low cost metrics. This is the single largest future development play in our portfolio. So going forward, that speaks well for our ability to maintain that corporate low finding and development costs. OpEx is extremely low. We’ve averaged about $3.80 per barrel for an operating cost on this play largely because the wells are quite prolific, and as I’m going to speak in a minute the multi-layers allow concentration of well in a single surface delivery point to again minimized operating costs.

The multilaterals that we’ve been using at Seal on cold, we think are an innovation that’s probably initiated with Baytex. Occasional Seal is about 20 meters thick as the Bluesky sands, the oil is more viscous, the deeper you get into the reservoir. So we’ve been facing our cold producers in the top third of the pay zone. We initially started with single lateral horizontals, then started to branch out to multi and in this slide shows you the cost improvement by going to the multilaterals. Initial one laterals were about CAD$1.1 million for initial rates of about 150 barrels a day, eight laterals are the metrics that I spoke to earlier. In the third quarter most of our horizontals were 13 laterals.

So the reason that this is much more cost efficient, all of the horizontal producing laterals are sharing one vertical well, the cost of the one vertical well. So its minimizing the cost that way, this is a very, very cost effective and again I’ll show some technological enhancement that Baytex has been able to apply to this already very, very prolific play.

A lot of the future development that Seal is going to be thermal. As I mentioned cold production, the cold wells are going in the top third of the reservoir. In due course, when we’ve exhausted cold production in the top third, they’ll go back unlike they put thermal producers in the bottom two-thirds to extract the reserves that’s been left behind. There are parts of our land base that are not amendable to cold, i.e., the oil is too viscous, low on cold so we’re going to go directly to thermal development in those areas.

What we’ve landed on for Seal is to use cyclic steam or Huff and Puff and simply if you inject steam into a well bore that the steam soaks, heat up the reservoir for a period of time and turn around and produce back out from that same well bore, then you’ll re-inject steam at a later date, so you’ll have a soft peaks and declines, peaks and declines from a individual well. Our modeling suggests that in this reservoir we could probably have between 10 and 15 cycles per well which implies a 10 to 15 year life of each well. So very, very long reserve life, very long productive life for this kind of development.

In cold production, recoverable we think will be between 5% and 7% of the original oil that’s in place. When we move to thermal we believe that that recovery rate jumps up to about 30%. So a very, very meaningful increase and amount of oil that’s going to come out of the ground when we move to a thermal development. Cost metrics, obviously thermal is a more expensive technique than cold but the cost metrics compares very favorably to our historic corporate averages. We believe that the optimal way to develop using thermal is to do a 15-well defined project. And 15 wells serviced by one steam generated facility. The magic of 15 is that because you’re not constantly injecting steam into an individual well as you cycle through the 15 wells, by the time you’ve gone through them all is time to go back to the first one and steam it again.

So 15 wells keeps the steam generating facility busy, virtually all the time optimizes that capital investment in the steam generating facility. Cost estimates today for a 15-well module including steam developments and water source and fuel source is about CAD$55 million. Our estimates suggests that also that recoverable spun a 15 well module in the neighborhood of 7.5 million barrels of reserves. That translates to a finding and development costs of about CAD$10 to CAD$12 a barrel. Again compares very favorable to our historic average.

Peak rates for a 15-well module, we think are in the neighborhood of about 2,000 barrels a day. That peak rate will be achieved probably in year four or five. OpEx obviously because you’re burning natural gas to create steam and you have the steam facilities to manage, OpEx is higher for thermal. Our current estimates are about CAD$14 a barrel for OpEx for a thermal project. Our current corporate OpEx is about CAD$12 barrel so it’s modestly more expensive than our current corporate average but it doesn’t going to be a step change for Baytex in terms of cost metrics.

And this is just a map of our thermal development to-date. The black lines show you the first 10-well module that we’ve already drilled. We’ve steamed most of these wells. The bolded black line is the pilot well, the initial well that we did our first physical test on. The red is the second 15-well module that we’re in the process of getting regulatory approval for. We’re hopeful to have that project approved by the end of this year and we would be drilling those wells early next year assuming we get approval in time to do that.

The reason I highlighted the bold line there is to show you on the next slide, how the pilot has responded. And I’ll speaking quite a bit of detail to the information on this slide but the high level is this pilot well has performed the way that we expected it to. It’s delivering the production and accepting steam in the reservoir the way we expected that it would. So a very, very good first physical test. We’re very early days in the thermal development here but what we’re seeing so far is the way we expect to see things occur.

So what this is showing you is the production from that single well where we initially drilled and then added steam. The brown lines are showing you initial cold production and we did put this well on cold production for a period of time to create some voidage. The rock is very dense, you need to extract some oil to have some physical place to inject the steam. So this would not be a commercial producer using cold that you can see relatively low rates. But that cold production does create voidage then you have your first steam injection, we had a response of 250 barrels a day and that comes off.

We would consider these first two or three cycles, mini cycles and those mini cycles are themselves designed to create additional voidage, so that when we get into the more robust development we have a longer production period. So the first three cycles you are seeing better, better production, more importantly you were seeing much, much better accepted by the reservoir of steam injectant, the reservoirs are therefore more steep in the reservoir and by the time we come to our fourth cycles, we’re seeing a less steep decline from the production.

When we get to a 10 or 15-well module as a whole, even 10 or 15-well behaving like this and that’s start to a pattern that I talked about. So as a collection of well, the peak rate for the 15 wells would be in that 2,000 barrels a day that I mentioned earlier. Seal reserves recognition. This slide just shows you the build out of reserves. Really what it’s designed to show you is a couple of things. That Seal reserves are very meaningful to the company. At the end of last year, we had a 102 sections of reserves out of our 252 sections – 252 million barrels, that’s about 40% of our reserve book is at Seal on a proved plus probable basis.

The other thing that I want to highlight for you is as I mentioned including our recent acquisitions, we’ve got about 305 sections of 100% owned land. We had reserves booked on only 36 sections of those lands. We only have thermal reserves booked on two out of those 300 sections of land. So again the message is we’re very, very early days with Seal. We believe there is lots of development and resource booking to come and that we’re very, very encouraged with what we’re seeing both on the cold production side and on our thermal pilot side.

The next area that I am going to talk about is the Lloydminster heavy oil area. The Lloydminster is the traditional bread and butter of Baytex. It’s that multi stacked heavy oil reservoir that I talked about when I talked about introduction to the company. The Greater Lloyd is very non-homogenous area and I think that we’ve grouped this is as the Lloyd area. It basically is our heavy oil operation other than Seal. So when you look at technical development of the Lloyd area, Lloyd is a very desperate area. So in some areas we’ll develop with single verticals that intercept multiple pay zones. In some areas we use horizontal wells.

We used SAGD in other parts of the Lloyd area, we use cold injection. The message is that we apply the appropriate technology to each reservoir as is appropriate for that particular development. Today we’re producing just under 20,000 barrels a day at Lloyd. It’s a kind of a cash cow for us. We don’t see that there is a lots of growth opportunities but it’s an area that got the opportunity to stay flat, we think for the foreseeable future. We today have along seven years of identified growing inventory at Lloyd, when I joined the company eight years ago we had five years of drilling inventory. So just by the nature of this resource we tend to build out as we go along and drill and the inventory expands.

This is a cash cow for us, very, very meaning cash contributor and the historic core of the company. This slide just speaks it at the multi stack reservoir that I mentioned earlier and you can just see how single vertical intercept multiple delivery zones. Capital efficiencies are very, very good at Lloyd. We’ve been adding production at about CAD$11,000 per barrel – not per barrel, per day of production of finding and development costs historically around CAD$12 a barrel.

We recently announced the acquisition of some lands in the Cold Lake area. The reason that we did this transaction was a number of things. First of all, it’s the right scale of the kind of transaction that Baytex likes to do. It was a CAD$120 million for 46 sections of 100% owned land, a relatively modest cost. The previous owner had made the discovery, had made some delineation drilling and quite clearly identified a producing area. And have gone through the regulatory approval process.

There is approval in place for us to move to development of a up to 10,000 barrels a day SAGD development. We think the optimal development is in the neighborhood of a 5,000 barrel a day project, so that’s the level that we’re targeting for development. What attracted us to this was the low decline nature of SAGD production. Once SAGD project is built, it essentially stays flat for very, very long period of time. We believe that this project will stay flat for between 10 and 12 years once the production is – that 5,000 barrels a day production level is maintained or achieved.

It’s attractive to us today, the corporate decline rates for Baytex is about 28%. So if we stop drilling today, our decline or approximate fall off by 28% a year. When we got relatively aggressive plans, i.e., we plan to be able to grow our company at about 8% per year for the foreseeable future, a decline rate can increase. You’re bringing on more and more production with higher flush production. So as the decline rate increases and we have as a corporate vision that we want to live within cash flow to deliver growth and income, your ability to do that is more challenge to the higher decline rate. When you inject some low decline production, such as is offered by SAGD or cyclic steam, you mitigate your corporate decline rates and you’re able to on a portfolio basis continue to deliver the growth and income model that is the Baytex mantra. So this fit into long-term plans very, very nicely.

Cost metrics were very good. We booked – we’re able to book 43.7 million barrels of proved plus probable reserves at the time of acquisition, so very, very good cost metrics. It’s proximal to some other operations that we have. So from an operating perspective it’s easy for us to manage. We do have SAGD already in our portfolio. We’re capable of building and operating a SAGD project. So a good scale, fits strategically and nice sized project for Baytex.

This is a slide that one of the competitors that BofA [ph] put together. And what this is doing is showing that investment banks you of the profitability of the different resource placed throughout North America. So they’ve taken every resource play in North America with oil natural gas, liquids, combined and ranked them on a profitability index ratio. So net present value of investment divided by this initial investment. What that work shows you is that by their view the single best most profitable project in all of North America is Seal Cold. Number three is the Lloydminster heavy oil and I believe number six is the Lloydminster heavy vertical. So number three is Lloyd horizontals, number six is Lloydminster verticals.

Three of the top six players in North America are in that three key place in our portfolio. Having a high rate of return projects is what allows us to continue to grow our production and fund a dividend at relatively modest levels of expenditure and live within our cash flow to deliverables of those good things. This is the key differentiate for Baytex. We have the best projects in our portfolio.

Light oil projects, we are very, very much a heavy oil player, but we do have some light oil in our portfolio as well. The key play is the North Dakota market. Today we’re producing a relatively low level in Bakken because it’s an early play for us, we’re doing about 2,000 barrels a day. We’ve got a very, very meaningful land position. In addition to the reserves that we have at the Bakken we also have about CAD$66 million – 66 million barrels of contingent resource at the Bakken, so again the ability to expand our footprint in that play.

And this is just a map of where we are. We’re west of the Nesson Anticline and Nesson Anticline is worth noting because that’s typically what’s seen as the divider between the very, very premium parts of the Bakken and the good but not so premium parts. Our position in the Bakken is good but not the 1,000 and 3,000 barrel a day, IP rates that you might hear from some of our competitors. Our IP rates today are around 440 barrels a day, capital cost to drilling complete for us about CAD$7.5 million per well.

So we are making a very, very good return here. It’s a smaller part of our portfolio but we’re very, very happy to have this in terms of resource booking potential and high netback barrels of production in our portfolio. Hedging, if you hear from the last presentation, MEG talked a little bit about heavy oil differentials and the improvement that’s likely to occur as pipelines are built out in North America. We are also believers in that thesis, we think that there is fairly bright line that comes middle of 2014 when some combination of Keystone XL or the Enbridge Mainline Expansion coupled with Flanagan South is in place and Canadian balling are hitting the Gulf Coast in a very, very meaningful way.

There is going to be a very significant closure of the current arbitrage between Maya which is the Mexican heavy that’s delivered into the Gulf Coast and Western Canadian select. Those two qualities of crude are very, very similar in terms of the quality characteristics. But today Maya because it’s a water born crude, it could go anywhere in the world but it won’t, we’re expecting a premium to WTI, where at this moment in time WCS is selling at about a CAD$25 discount to WTI. So a CAD$30 pricing arbitrage closed by someone else building pipeline.

In Western Canada the WCS differential has been reasonably volatile this year. The reason it’s been so volatile has been there is sufficient pipeline takeaway capacity and sufficient refining demand within the current reach of Canadian producers as long as everything is working fine. But if there is a pipeline upset or a refinery goes down for a turnaround, there is some market dislocation and there is periodic spikes to the differential. That’s what you’re seeing right now. The spot differential today is about CAD$25 for WCS as I mentioned, it was as tight as about CAD$9 a barrel in September and October.

There is a couple of identifiable things that have caused the current lining of differentials, i.e., the Marathon refinery went down to heavy oil turnaround, BP Whiting has gone down, between those two when they come back on, there is an incremental 330,000 barrels a day and heavy demand, that’s again a reachable by existing pipelines. We think that when those come back on, there is going to be a very, very tightening of the differential in the near-term, that’s going to be more durable when those pipelines that I mentioned earlier are built.

In the meantime, a stock got measure has evolved in a very meaningful way which is rail, so lot of volume moving out of North Dakota and Western Canada by rail to market. The real arbitrage seems to work at about differential of about CAD$14 a barrel, in other words as long as the differential is wider than CAD$14 a barrel there is a profit for rail providers to coming and taking product out. You’re going to see rail coming back into Western Canada meaningfully very, very quickly.

What this slide shows you is one of the ways that Baytex has been dealing with that volatile differential. We do hedge. So we hedge both our WTI, our differentials as well as our natural gas pricing and foreign exchange. Today we’ve covered for about 23% of our 2013 WTI and about 32% of our differential for next year. As I mentioned earlier, our balance sheet is very, very robust. At the end of the third quarter about a 0.8 times debt to cash flow. Our CAD$700 million credit facility is virtually complete, we’ve undrawn. We’ve got CAD$100 million drawn on that line so not much debt. Lots of liquidity.

Our nearest maturity (inaudible) and our bank loan has got a three year term, after that we got a couple of bonds outstanding that has about nine year maturity. So no liquidity issues at all. In summary, I think what I’d like to try and leave you with is the basics, business model is to deliver growth and income, we have an identified inventory that allows us to just go and execute that program. Our balance sheets are very strong. It’s going to allow us to fund that. And we have our core product is in a pricing environment where the fundamentals are improving over the next couple of years and there is opportunity for very, very meaningful improvement to our cash flow by the macro issues taking care of themselves i.e., pipeline built for us to get to market.

So I think things are going well for Baytex, as I mentioned Q3 results were great. Best production in the history of the company. Cash flow was the highest level this year, things are going very, very well. So having to take some questions, I think I still got seven minutes and 14 seconds.

Peter Ogden – Bank of America/Merrill Lynch

Okay, we’ll open up the floor to question.

Question-and-Answer Session

Unidentified Analyst

Did you – there was a deal announced (inaudible) last night.

Derek Aylesworth

Yes.

Unidentified Analyst

Did you guys take a look at that property that’s first question. Second question is there something geologically that’s you so far superior to that of (inaudible)?

Derek Aylesworth

The first question as far that transaction goes, no, we didn’t take a look at that deal and to be pretty frank, it was a surprise to me this morning that happened. I did read the press release, and it didn’t disclosed very much. I don’t really have much of a reaction to the transaction. I suspect that it was mostly consolidating in some way in better proximal to where are we operating but I don’t have much commentary on that.

In terms of the difference in the geology, I would say as I mentioned earlier when I talked about the build out of the multilaterals that really is something that Baytex pioneered. Multi-legs are not unique but to go to the extent that we’ve been able to go up to 13 legs is not done by any other producer at the moment. So I would say that. One of the differentiators for us, we’ve been more aggressive with pushing the technology envelop there but I think 13 legs probably is about where we can install. It has been difficult to turn the corner on the end of that pitch work. I’ll say we were also quicker to recognize the difference in the viscosity gradient in the pay zone and the fact that we focused on that upper third would give you better results.

I understand that some of the other operators were initially placing their wells deeper into the reservoir, I understand they’ve also now moved to that top third and they are starting to get similar results to what we have. So (inaudible).

Peter Ogden – Bank of America/Merrill Lynch

Derek, question for me. I mean how do you think about your adjusted payout ratio going forward into 2013 and by that I mean do you manage your CapEx to get a 100% adjusted payout ratio or alternatively I guess what kind of oil price do you need to cover your dividend net of drift plus your CapEx?

Derek Aylesworth

Sure. I think the way to answer that question was when I talk about delivering growth and income largely within cash flow, we are actually not married to the idea that that needs to be annual event. We talk about that as our long-term business strategy and certainly the priorities for us are maintaining our dividend and maintaining our productive capacity up and growing our productive capacity.

So in periods of time where the commodity price is dislocating and might suggest that there is a tax shortfall to being self funding within any particular year, we will look at whether or not we think that dislocation is in our view a temporary thing. We’ll look at our balance sheet capacity and we’ll make a decision on whether or not they want to proceed to execute our plans and perhaps outspend that particular calendar year’s cash flow. We haven’t yet had a budget for 2013. We’re going to do that in front of our Board of Directors early December and we will announce that shortly thereafter, but myself I don’t think there is any need to live within cash flow absolutely given the strength of Baytex’s balance sheet.

Again at a 0.8 times debt to cash flow we’re under levered. We are very comfortable with any kind of a leverage that’s a below 2 times debt to cash flow, not that we would run it up but if we went to that 2 times debt to cash flow we have about CAD$700 million or CAD$800 million of incremental debt capacity. Our total capital budget last year was CAD$400 million. Our total dividend net of drift is about CAD$220 million. So that gives you a sense of how much flexibility we’ve got before we would be concerned of our leverage levels. So I think that answers your question, Peter.

Peter Ogden – Bank of America/Merrill Lynch

Perfect. All right, well thanks very much for your attendance.

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