Derek Aylesworth - CFO
Baytex Energy Corp. (BTE) Bank of America Merrill Lynch Global Energy Conference November 21, 2013 4:20 PM ET
Derek Aylesworth, Chief Financial Officer with Baytex Energy for joining us today. It's all over to you Derek.
Thanks Steven. Thanks to BOA for having us here and especially thanks for getting me out of Calgary, I think it's minus 20 down there. Please take a moment to review our advisory on forward-looking statements. Just as an introduction to Baytex, the investment highlights, why you might want to consider an investment with Baytex are we really focus on delivering organic oil growth, we're focused on delivering production per share growth. We have some projects and inventory that allow us to deliver that growth at absolutely sector leading capital efficiency. We pay a meaningful dividend and we're focused on that dividend as a way to de-risk total returns to shareholders and we see that as a competitive differentiator for our company.
Our balance sheet is in great shape, and that allows us to continue to ride through some rough patches in the commodity cycle and deliver what we want to deliver. At a high level our corporate profile, we trade on the Toronto and the New York Stock Exchanges, about $6.2 billion enterprise value. We do pay a dividend that today translates into about 6.1% yield. At the end of last year we had 290 million barrels of reserves booked on a 2P basis, 93% of that is oil and liquids. About 800 million barrels of contingent resource over and above that $292 million barrel resource book.
Our budget for 2013 is to deliver between 57,500 and 58,000 BOE per day of daily production, 90% of that is oil and liquids. Our END capital budget to deliver that production level $550 million.
To orient you, the three main operating areas where Baytex does its business are the Peace River oil sands in North Central Alberta, the Lloydminster area heavy oil area which straddles the Alberta Saskatchewan border and the Bakken/Three Forks in North Dakota. We are very, very much a heavy oil focused player with about 75% of our current production being heavy oil, further 14% light and a modest swivel being natural gas. In terms of cash generating capacity and operating income generation, virtually all of our operating income comes from our oil and liquids developments.
I'll spend a brief moment on history, and history is really only relevant because I hope it gives you some flavor for our ability to keep doing what we've done in the past. We have delivered an 8% compound annual growth rate in our production volumes since 2007, during that same timeframe we've delivered a 12% CAGR in our reserve bookings.
In addition to the sort of 19 million barrels of 2P reserves booked, it's one of the highlights for even that translates at our current production rate to about a 14.5 year reserve life index, if you add in the continued resource that we've got above and beyond that we've got a very, very material amount of running room currently identified on our existing land base.
Moving to the key projects that make up our company, probably the most important one in terms of current production and current identified potential is the Peace River oil sands. We have 306 net sections of Baytex owned oil sand leases. Oil sand leases are important to highlight because oil sand leases have a different tenure than more typical petroleum and natural gas resources in Alberta. They have a longer tenure and they have a preferential royalty agreement, so they're very advantageous to have this kind of a lease. We're currently producing about 25,000 barrels a day of oil in the Peace River area with 2P reserves at the end of last year about 64 million barrels.
In addition to cold development, we're just beginning to scratch the surface of a thermal development opportunity at Peace River. We're producing about 600 barrels a day with 46 million barrels of 2P reserves booked on a thermal basis.
This picture shows you what we're doing on a cold producing basis - cold simply meaning production without the aid of thermal stimulation, what we do is we drill relatively shallow vertical wells down about 600 meters into the Bluesky, as the Bluesky is the producing sand in this area. At 600 meters down we go vertically or horizontally and drill about another mile long for whole -- mile long horizontal producers and we drill it in this pitchfork fashion that you see in this picture. What that does is it allows us to get about eight to 10 producing legs all collecting production in a single vertical producing well bore, that allows us to share the cost of the vertical wellbore with a producing, minimizes the capital cost of the well [Audio Gap], collecting all of that production at a single point at the surface minimizes operating costs and it also minimizes surface and environmental disturbance.
The economics for this play, the way we're developing it are amongst the best in North America. We are spending about $2.5 to $3.5 million to drill, complete and equip these wells and for that expenditure we're getting IP rates, certainly the IP rates are between 307 barrels a day and ultimate recoverables of between 275,000 and 550,000 barrels of reserves. That translates to a capital efficiency of between $5,000 and $9,000 of [floating day] barrel or reserves added at a $6-$9 E&D cost, truly a top decile cost metrics in the industry.
When we're producing cold because the Bluesky pay zone, the oil gets more viscous the deeper you get into the reservoir replacing our cold producers only in the top third of the reservoir. Because of that well placement, we're only recovering between 5% and 7% of the original oil in place and that leaves behind a very-very large target for secondary and tertiary recovery which leads us into our thermal development plans.
At Peace River we are planning to develop the part of the reservoir that will not flow cold with cyclic steam. Cyclic steam is simply drilling a single well bore, injecting steam into that well bore and letting it soak for a period of time to heat up the reservoir and then producing back out from that same well bore. When we develop this we're doing a module so several wells connected to a single steam generating facility and the strategy is to inject steam in the first well, let it soak, move the injection into the next well and by the time you’ve cycled through all of the wells in the module it's time to go back and re-inject in the first.
The capital cost for a 15 well module and steaming facilities we estimate to be in the neighborhood of $55 million. When we move to thermal development we take that coal recovery up from 5-7% to about 30% based on our reservoir simulations. A 15 well module will ramp up gradually over time and we believe we'll plateau at around 2,000 barrels per day for about a four to a five year plateau.
Recoveries for that 15 well module are about 7.5 million barrels. That translates again to a very-very low capital cost, finding and development cost in the range of $8.50 per barrel.
This is a sketch of what we're currently doing on a thermal basis. The black lines here show you the first 10 well modules that we have started and that's where the current 600 barrels a day of production is coming from. The red lines show you the next module, the 15 well modules, we've already got those largely drilled out and we expect to steam those beginning in 2014.
The next area I'd like to speak to is the Lloyd-Minster heavy oil area. Lloyd-Minster is really the bread and butter or the historic background for Baytex. It's largely a holed flat area, we don't see that this will grow materially, we're currently doing about 19,000 barrels a day of heavy oil production, but today we have identified about a five to a six year drilling inventory. It's a bit of a tired anecdote if you've heard me talk before but I joined Baytex eight years ago and eight years ago we had a five year drilling inventory, and today we still have that same. So this is an area that kind of keeps on giving and giving and we think that this will be a real cash cow for us and allow us to fund the growth in Peace River and other areas.
Cost metrics in the Lloyd area are very-very compelling as well. We do develop some of this area using vertical wells. A vertical well in the Lloyd area quite often intercepts multiple pay zones. If you produced the most prolific first plug it and move to the next and recomplete the next zone. Those recompletions add production reserves at very-very low costs. Finding and development costs in the Lloyd area using vertical development were about 11.25 per barrel.
We’ve just started to branch out and use horizontal development in the Lloyd area. The Lloyd area historically wasn’t thought to be very conducive for horizontal because a lot of the pay zones are quite thin. With the improvements in horizontal drilling technologies we now can place horizontal wells in an area as thin as a two meter pay zone and we’ve been able to do that quite successfully so far this year, adding reserves there at about 13.50 per barrel and about $12,000 of flowing day barrel.
The last area I would like to talk about is the Bakken-Three Forks in North Dakota. The Bakken is the smallest of our core areas; currently we're producing about 3,400 barrels per day with 2P reserves in the neighborhood of 34 million barrels of reserves at the end of 2012. We are in, what I would consider a good area of the Bakken but not the tier 1 area of the Bakken. We're primarily in the Divide County. Our well cost in this area are about $6.8 million to drill complete and equip for initial production rates of about 420 barrels per day and reserves of about 420,000 barrels. Finding and development costs about $16 a barrel
The reason that the North Dakota project is in our portfolio, was a number of different things. We are heavy oil focused producer and we’re very confident about the future of heavy oil pricing but North Dakota does give us a commodity price diversification and also is an area where there is a very material amount of resource in the ground. Technology has been improving quite rapidly in this area. So it is a combination of exposure to improving technology and improvement in commodity prices the Bakken has the potential to move up the scale on our economic return rankings.
This slide is just a picture of the way we develop, again horizontal development. Our drilling performance has dramatically improved since we first got into the Bakken 33 days with our original drilling requirements were now down to about 19.5 days for a well and that’s obviously improving our drilling metrics here, cost metrics. You know the slide that was put together by one of the competitors to [indiscernible]. And what they have done is they ranked IRRs for all of the resource plays in North America, whether they are oil, gas or liquids. And what this is showing you is at the single highest rate of return project in all of North America is our Peace River Cold project.
Number three is the Lloydminster vertical and number seven is the Lloydminster horizontal opportunity. For Baytex, about 80% of our capital budget is going into those three plays, so 80% of the money we spend is going into three of the seven best high rate of return plays in all of North America. The fact that we got the opportunity to invest in this kind of inventory is what’s allowing Baytex to grow its production, fund its dividend and maintain a strong balance sheet without having to resort to equity issuance, and largely live within cash flow as we build out our business.
I am going to talk a little bit about the Canadian Heavy oil market because it's quite a topical thing right now. You’re probably aware that Western Canadian select, the Canadian Heavy Oil benchmark is selling at quite weak pricing in the fourth quarter. We’re expecting the Q4 WCS pricing will be in the neighborhood of a discount of 40% to WTI. The Q3 differential was about a 16.5% differential. So what’s caused that widening of the differential? It’s a number of things. Typically in Q4 you would expect the differentials widen as a result of normal refinery turnarounds. This year that was exacerbated as the Enbridge line partially had some shutdowns as they’ve added a pumping capacity to feed the Flanagan pipeline that’s coming on in 2014.
When you had the lack of transportation capacity meeting the lack of demand from the refinery turnarounds, there was broadly an expectation of wider distant Q4. We then got a further bit of a kick in the teeth when the Citgo refinery had a very major fire. Citgo has gone down for about five months. We expect that to come back up late Q1, maybe early Q2, but when that fire occurred, a lot of the barrels that western Canadian producers thought they had sold were put back in their hands because of the [forced measure of Citgo] and a number of barrels had to be sold in distressed environment and that’s what caused a spike up in Q4 differentials.
There is a number of things on the horizon that we think will not only mitigate the Q4 spread but speak very-very well for the long term outlook for heavy oil dips. The first obviously Citgo is coming back up. Second is Enbridge is finishing up with its expansion plans, and once those are done in Flanagan South, allows us to get all the way to the Gulf Coast on the Enbridge mainline and utilizing the south leg of keystone excel, that should start up mid-June. There is an incremental 580,000 barrels a day of transportation capacity that will allow Canadian producers to get to the Gulf Coast market.
We're also expecting that the BP Whiting refinery which is just commissioning the largest heavy oil Coker in the world should be coming up at the beginning of Q1. So incremental 250,000 barrels a day of heavy demand in the Pad 2 refining region that’s already accessible by pipeline out of Western Canada.
And finally the rail capacity that’s coming out of Western Canada is coming very rapidly and the volume is surprising to the upside. We think that the combination of all of those factors will take us back to a more normalized differential environment and I don’t think that I would say that we’re expecting the Q3 this environment to be the norm for the long term but that with the combination of those things that I’ve mentioned volatility for the differentials will be tamped down and the absolute pricing should improve.
How much? This slide shows you historic plot of the differentials between Western Canadian Select and Maya. Maya is the Mexican blend of heavy and in terms of quality it’s a very, very similar quality of crude to Western Canadian Select. When your transportation adjusts the cost of getting WCS to the Gulf Coast, which is the primary market for Maya, you can see that up till mid-2010 early 2011 WCS and Maya traded very much in lock step and they should because there is no quality reason for them to trade at anything other than a similar price.
As transportation takeaway capacity got more scarce, you started to see that spread widen out quite a bit. And as we get these transportation solutions presenting themselves, we believe that WCS and Maya will come back together. Today there is about a $25 a barrel spread between WCS and Maya after transportation adjustment. Any of these kind of pricing arbitrages will close like we buy meeting in the middle somewhere. So if you call that $25 meeting in the middle a $12 improvement for Baytex as selling price on it heavy consider that our corporate netback is about $35 a barrel an incremental $12 revenue on a $35 netback has a very, very material cash flow improvement potential for Baytex as these transportation issues resolve themselves.
I spoke a little bit about rail capacity and rail capacity is worth spending a little bit more time on especially in the United States while we’re talking in Miami. There is a number of investors that we talk to that kind of hang their hat on WCS improving when Keystone XL is built and that pipeline is available for us to utilize. Certainly the Western Canadian oil and gas industry would like XL to be built. We don’t believe it’s absolutely necessary right now largely because of the quantum of barrels moving on rail.
What this slide is showing you is the North Dakota rail experience plotted against where we are in Canada. So the dark line is North Dakota. From the first barrel that moved out of North Dakota to 40 months later they went from zero to 700,000 barrels a day of North Dakota rail movement. If you time normalize those in the first 25 months, Canada has got up to about 200,000 barrels a day of rail, we’re basically on the North Dakota curve. We can specifically identify rail loading facilities that are being built and are being commissioned such that by the end of 2013 we expect that there is going to be 400,000 barrels a day of rail capacity out of Western Canada. If you go forward to the end of next year that could be between 800,000 and 900,000 barrels a day of rail capacity. That’s more volume than was expected to be able to move on XL. The market has responded to this pricing arbitrage by building rail takeaway capacity and we will be able to get to market in a meaningful way, and I believe that WCS and Maya arbitrage will close.
That said in an environment where the current differential is perhaps wide what is Baytex doing about it? Baytex is a regular and consistent hedger when we see opportunities to protect ourselves from volatility we take them. On a WTI wide for Q4 of 2013 we’re 67% hedged at just under $100 per barrel. On the differential side we’re just under 50% hedged at a differential of about $17 per barrel. So we’re quite well protected from this relatively unexpected or exaggerated blowout in Q4. We’re protected by using a number of different tools on the differential side. About 53% of our volumes move to market by rail. Of that 53-30% of those volumes are sold on a fixed term differentials; so in other words WTI minus ex dollars taking away the WCS exposure.
Some of those rail volumes are sold on a WCS pricing basis. But we do have incremental hedge on some term rail or term pipeline transactions that we have done. So from a hedging perspective we’ve taken care of ourselves and protected ourselves against the current volatility.
I mentioned earlier the balance sheet strength of the company. On a debt to FFO measure, we ended the third quarter at about 1.3 times debt to FFO. U. S. E&P investors are probably used to seeing a much more levered balance sheet. We’re comfortable with this more conservative balance sheet, it doesn’t leave us exposed to commodity price variants in any which way and does it give us lots of ability to use our balance sheet to take advantage of acquisition opportunity should they present themselves. We do have a $850 million credit facility; we’ve only drawn about 180 million of that, so $600 million of undrawn credit facility at the end of the third quarter.
The long range plan for Baytex is to deliver 6% BOE CAGR in terms of production growth over the next five years, that BOE CAGR is actually about 8% oil CAGR, our natural gas is in decline and we're not applying much of our capital to natural gas opportunities. As I said virtually all of our cash flow comes from oil, so that 8% CAGR we believe over the next five years will translate to at least an 8% cash flow generating capacity growth.
On a funds from operations perspective when we built this long range plan, we built it on a $90 WTI assumption and a long term 20% WCS differential assumption. On those commodity prices in 2012 we realized about 500 million of cash flow; our LRP was just shy of $1 billion of cash flow in 2017. So the combination of an improving WCS environment and production growth we think will lead to very material cash flow growth as well.
So that leads to the summary slide why would you consider investing in Baytex? We truly believe that we have a superior asset base. We have the opportunity to deploy our capital into the highest rate of return projects in North America. The sector leading capital efficiency means our investments are high rate of return. We got a lot of identified and available investment opportunity and we defined it quite well in our long range plan. We're very, very committed to our dividend, over $1.5 billion have been distributed to our shareholders as dividends over the last nine years and we intend to when it's prudent grow our dividend as our business continues to grow.
We have been able to do what we plan to do and execute our business plan very effectively over the last seven or eight years, the team that delivered that is still in place and we believe that we're able to continue to do that going forward.
And lastly as the kicker, differentials we believe are going to improve, I think there is a growing acceptance that that's the case I think the market tends to pay for that when they see it rather than when they expect to see it.
So with that I know I have gone through that quite quickly and the clock is giving me lots of time, so if there are any questions I am happy to take them.
Thank you Derek, we’ll open the floor to questions and I'll start off. How long after first steam can we expect to see peak productions from your Cliffdale commercial project?
Yes the Cliffdale thermal project as I mentioned our CSS, our modeling would suggest that from first steam to peak or plateau it is slow buildup, should be should be three to four years. The reason that it's a relatively slow buildup, the rock is quite consolidated. So there is -- in other words there is not much physical space in the rock to inject steam. So the way that you buildup productive capacity is you initially put the wells on cold production, extract some oil, that oil extraction creates some voidage or empty space to inject steam. After some modest cold production you do your first mini cycle of steam injection. And those mini cycles will heat the reservoir up to a degree but not materially to get your peak levels of production. So through a period of several cycles of these smaller injections that will ultimately grow larger as there is more and more voidage created the reservoir itself gets hotter and hotter over time and that's what allows you to ramp up production to that peak, but it is a slow ramp.
Once we do reach peak production, we believe we can hold ourselves flat for four to five years before we go into decline.
Now will the company consider accelerating development of your geothermal projects or are you going to wait to see results from your first commercial projects?
It's a good question, thanks for asking me. It brought something to mind that I didn't mentioned earlier. Before I tackle that question, when we look at thermal and our portfolio, we look at thermal as a strategic advantage that Baytex has. When we have got these high rate of return projects to invest on a core basis and have the ability to grow our production as rapidly as we have been, that would mean implicitly that we're bringing on more and more high decline productions. So in other words the steepest production decline on any cold well is its first year. So if you stack up more and more cold production you are going to have a higher and higher corporate decline rate. Because we're married to the dividend model, if you don't do anything to mitigate your corporate decline rates, your capital requirements to offset decline will grow and grow and your ability to grow your dividend is more and more challenged.
If we bring in thermal production which is more modest decline into the portfolio, it helps offset that steep cold decline and enables us to execute our business plan more readily with a more modest capital program. As it relates to the Cliffdale project, when we get our second 15 well module up -- our second module the first is 10, our second is 15. But when you get the second module up and running and we're taking steam next year, our plan is basically to stop and watch what happens with Cliffdale. We think that we probably would like to see a couple of years of production results to confirm our comfort level with our modeling. But what that has also meant is that in order to execute our thermal decline management strategy, we are also proceeding with a SAGD project at the Cold Lake area.
We have a defined Gemini project in the Cold Lake area. We are running the pilot, we drilled the two pilot wells this year and we’ll start steaming next year. And assuming that that pilot goes well that will probably advance in advance of the next Cliffdale project.
So moving along to North Dakota, now given the relatively small size higher cost structure, do you even consider selling it?
North Dakota sits a place in our portfolio and I think that today if we look at what that is doing for us it’s giving us the highest netback barrels that we produced because of the higher quality of oil. It’s giving us access to a lot of resource in plays. So today we like what we’ve got. In terms of looking at it as a potential sale candidate, any of those plays like the North Dakota Bakken are optimized in value when the lands that you have are completely held by production.
We expect to have the bulk of the lands that we care about in North Dakota held by production end of next year, mid-2015 something like that. So I would suggest that we’re not looking to sell North Dakota but if we were the earliest we would really be considering it as 2015 because there is value to be created by executing our plan.
Actually turning that question around I was actually going to ask if you think that North Dakota could be like a growth area for you.
North Dakota is a growth area for us. Today it’s a relatively modest growth area. This year we’ve probably added in the neighborhood of about 800 barrels a day of gross production so relatively modest growth. When we move forward in our long range plan North Dakota does become a more meaningful contributor to our long term light oil growth.
And given the oil differential or the price differential between WTI and what you get at Bakken, what would you say is like a minimum that you had to require to keep growing or basically I am talking breakeven prices for you?
Sure, looking at breakeven prices there is probably obviously a bunch of different levels that you look at. Operating cost in North Dakota are higher than our corporate average operating cost in North Dakota probably in the range of $18 a barrel. So to not shut-in you need to be at $18 a barrel, we’re not shutting in anytime soon. To meet cost of capital rates of return which we consider to be in the range of a 10% cost of capital for Baytex, we probably look at about a $75 WTI price for North Dakota delivers cost of capital rates of return before it competes with the balance of our portfolio you need a high realized price.
Well, thank you very much for joining us Derek.
Thanks Steven. Thanks very much everyone. Bye-bye.
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