Devon Energy Corp (NYSE:DVN)
UBS Global Oil and Gas Conference Call
May 21, 2014 11:00 AM ET
David A. Hager – Chief Operating Officer
William A. Featherston – UBS Securities LLC
William A. Featherston – UBS Securities LLC
Okay. We’re going to move on to our next presentation. I’m pleased to introduce from Devon Energy are Dave Hager, who is Chief Operating Officer. Dave?
David A. Hager
Thanks, Bill. Good morning, everyone. It’s pleasure to be with you today at UBS Conference. Of course, I’m obligated to say the actual – I’m going to give you some forward-looking estimates and the actual results may differ and the details can be found in our SEC filings.
Before I get going here, I would like to do one thing want to introduce somebody to you, many of you who know already, we have Howard Thill has joined the Devon Company here organization as the Head of our Communications and Investor Relations Group, so Howard, if you want to standup a real quick. Howard has a longtime career with Marathon. Many of you know him from there. He is going to be taking Vince White place, who has been with Devon for many, many years. And Vince has finally decided to actually retire, I believe and he is going to do that mid-summer, and we’re really glad to have Howard on Board.
So with that, let’s move into the presentation. Lot of exciting things have been going on here at Devon in the past year or so. And we have – we feel really successfully transformed the company. We are now focused on five core areas within the company, three of which are more oily oriented, those would be the heavy oil up in Canada, the Permian, and then the Eagle Ford, which we have recently acquired through our GeoSouthern transaction.
Then we also have two liquids-rich areas that are generating very strong cash flows currently, and they have significant natural gas optionality, those would be our Anadarko Basin assets and our Barnett Shale assets.
Then finally, we have two emerging areas within the company. Areas that we’re currently drilling, they have the potential to grow into the scale of a core area, but we’re still in the appraisals and early development stages in those areas and those were in the Mississippian Woodford and in the Rockies.
In addition to that, we have a very strong midstream presence. We’ve recently done a transaction that generate a new company along with Crosstex named EnLink, very proud of that transaction. And our value in that transaction is currently about $7.5 billion at current market prices.
So when you put it all together, this is a platform that has significant scale in each of our core areas and provides a platform from which we can grow particularly on the oil side significantly for many years in the future. And I will show you some more details around that.
If you look at some of the highlights of what we talked about at our first quarter call a couple weeks ago, start off very strong oil production growth year-over-year on our go-forward asset base. You can see that U.S. oil production grew 56% year-over-year. This was really driven primarily to the growth in the Permian Basin particularly in the Delaware Basin, as well as we got one-month benefit of the Eagle Ford production acquired through our GeoSouthern transaction. So commensurate with the oil production growth, we’re also obviously seeing very strong growth in our operating margins, so very similar growth there, 54% growth year-over-year on our operating margins.
Another significant point I think is, there have been some question marks, okay, you’ve got this Eagle Ford transaction, what next? What after that, after you drill up that inventory? I think we went a long way in the first quarter call and we’ve been talking about how we are – how our internal inventory is growing as well.
We added 5,000 risk locations to the inventory in the description that we described over the on the first quarter call. The bulk of those locations were added in the Delaware Basin, particularly in the Bone Springs, but also the addition of our Eagle Ford, Cana and Cana oil of new completion technique, as well as in the Rockies, Powder River Basin and specifically the Parkman, where we added, we now say we have a 1,000 locations in the Rockies, 700 of which are in the Parkman.
So we are with our new asset base have a platform from which we can grow for many years and the depth of our inventory that we will describe it in each of these core areas continues to grow. As part of this transaction also, our transformation really is, we have monetized our Canadian natural gas position very attractive prices, and then we have some additional monetizations on the U.S. side they were in the process of working on.
We did have an acquisition where we acquired 50,000 acres in the Cana-Woodford Play. We split an acquisition 50-50 with Cimarex of the QEP interest, and that was really driven by the improved results we are seeing there with revised completion techniques. I will give you a little bit more detail on that later on in the call, but all are really exciting first quarter.
This slide simply highlights where we stand in the divestment process. If you look at we divested a Canadian conventional for about seven times or 2013 EBITDA. So we’re not only transforming the company, we’re transforming the company in a value adding lay, in other words, we are able to sell this asset at a multiple that exceeds our overall multiple as a company.
So we’re very pleased with that transaction. We divested all of it and one single transaction that closed on April 1, and now we’re in the process of marketing our other non-core U.S. assets. We’re actually this month starting the actual marketing efforts of that, but we had a lot of early interest, it’s too early to say for sure how we’ll workout, but I think we’re very optimistic that we’ll have a successful completion of this process by the end of the year as well and which is the bottom of the slide there are the some of the metrics associated with the ongoing non-core assets in the U.S.
So where does that leave us as a company looking into 2014 capital spend overall, you can see we’re going to spend on the order of $4.8 billion to $5.2 billion on our go-forward asset base, it would be about $5 billion to $5.4 billion in total, including a little over $200 million we will be spending on the non-core properties this year. Over 70% of the capital is being spent in our three primary oil growth areas. That would be the heavy oil in Canada, the Permian Basin, and the Eagle Ford. Those are generating outstanding returns and are going to allow us to significantly grow our oil production going on to the future – into the future. Additionally, when you look at it as a company as we’ve expanded our margins, it is going to allow us to spend these amount of dollars and live within cash flow.
So the bottom line and I’ll get to us more in the future slides, but we have now a platform from which we can sustainably grow for many years, grow our oil production by 20% or more per year. Our BOE is on a 6:1 basis in mid-single-digits and more of a value basis 20:1 conversion rate around 10%, and all of while live in within cash flow. So as we grow our oil, we will be growing our margins and so the cash flow will actually expand significantly more than just our BOE production growth rate.
So this shows some of the results we anticipate for 2014. This is going to be a year of significant growth of our U.S. oil production. You can see over a 70% growth rate on U.S. oil production that is being driven as I described similarly for the first quarter by the growth in the Permian. Also having the Eagle Ford asset for 10 months this year, we closed that transaction at the end of February and to a lesser degree of our growth in the Mississippian production.
This is the year that’s pretty flat overall for Canada. Our Jackfish 1 and Jackfish 2 projects are essentially fully online at stabilized production rates at this point, a little bit of ramp up in Jackfish 2 as we bring out a new pad, but not a lot of growth this year. That will change as we move into 2015. We’re going to have Jackfish 3 coming online, and so next year we will start to see growth out of Canada once again with the third place of Jackfish.
And described on the right side of the slide there and again is the BOE production that we anticipate this year with the – on the 6:1 conversion rate of about 10% and about online 20:1 conversion rate about 20% is higher this year than described it will be over a multiyear period, because we’re getting to one-time kick up of the benefit of the Eagle Ford transaction. Even though it was making about 53,000 barrels a day or so when we acquired as we get that benefit this year and we’ll continue to grow significantly in future years as well, which allow us to have that overall growth rate I described before.
And this gives you a little bit of idea, again, what we think we can deliver going into 2015. We do see greater than 20% oil growth in the 2015 as we continue to grow production in the Eagle Ford, the Permian, Jackfish 3, as I described starts to come online. We also anticipate that’s not on the oil side, but more on the liquids rich side that we will have increased activity levels at Cana. This is a result of the improved completion techniques we’ve had or now allowing Cana to compete very well for capital within our portfolio. And so we do anticipate putting more rigs back to work towards the end of 2014 going into the 2015 at our Cana field and the Anadarko Basin. And, again, we’re growing our highest margin products, so the margins will be significantly expanding going into the future and it allow us to comfortably fund our capital demands and live within cash flow.
It’s important to keep in mind that if you look back a few years, about go back five years or so, when I joined the company, we were probably between 67% and 70% natural gas production. And now as we’ve transformed the company by the end of 2014, we will be almost 40% oil production, about 20% NGL production, and about 40% natural gas production. So a significant transformation of the company into higher margin products, and we’re not only transforming the percentages, but I think this slide highlights very well that we are a very large oil producer to start with.
So it’s not just a percentage number we will talk about it from an absolute basis, if you look at it on a combined basis compared to our other North America onshore pure-play peers or you just look at the U.S. side of it. You can see that we are a large producer of oil.
So let’s go in a little bit more detail on the individual asset areas, we’ll start off here at the Permian basin. We have about $1.3 million acres across both the Midland and the Delaware Basin side. We are significantly growing our production if you see over 20% growth in oil again in 2014. We’ll spend about $1.5 billion in capital and total across the Permian Basin drilling about 350 wells.
And this gives you an idea, we have make sure it happen there equals value, I can say that equals value would be a number greater than 20%. So and – the kind of growth we’ve had in the past, we’re going continue in the future, and we’ll continue to have over 20% of growth as the previous slide showed in 2014.
Focusing more specifically on the Delaware Basin side of the Permian Basin, this is an area where we’re generating outstanding returns. We have right now about 12 rigs working in Southeast New Mexico and Eddy and Lea counties primarily drilling Bone Springs opportunities or it’s going to drill about a 150 wells there this year, probably about 130 or so of those are going to be Bone Springs wells. We will also have a few Delaware wells sprinkled in. And you can see we’ve had some recent good results in a Delaware, we’ve been consistently exceeding our type curve on the Bone Springs wells.
We have drilled one Wolfcamp well down in Ward County, it was a very successful well. There has been a lot of attention on the Wolfcamp recently in the Delaware Basin. The reason we’re focused on the Bone Spring is simply is better economics. It is shower, similar EURs, and lower cost. And so we are very content to take advantage of our Bone Springs opportunity right now. We will participate in some wells. We’ll let industry to do a lot of the derisking of the Wolfcamp. And then we’ll take advantage of it at the appropriate time. But we still have a very large Bone Spring inventory left and that’s why we’re focused there.
And this slide shows what kind of opportunities that we do have left in the Delaware Basin. Prior to the first quarter call, we had described a total of about 2,200 locations in the Delaware Basin, 1,600 of those were in the Bone Spring and frankly we’re growing that from 350 at the beginning of the year up to 1,600, and then about 600 at the Delaware Sands. What we did that allowed us to describe that increase at the first quarter call were really two things. One is, we have done a lot more appraisal drilling across that entire acreage position that I showed on the previous slide.
And then second frankly, we just took the time to step back and do a more full resource assessment then we had previously across to our entire acreage position. And when we did that full resource assessment, we were able to increase the Delaware Basin inventory from what we described previously at 2,200 locations to over 5,000 locations with the biggest increase coming in the Bone Springs where we increased that undrilled inventory to – from 1,600 to 3,500 locations.
We also have opportunity in the Delaware Sands, we previously been drilling. We’re starting to describe the linered locations, other industry players have been drilling linered wells right next to our acreage work, again, focus on we think at the highest returns in the Bone Spring, but we certainly have those opportunities as well. And in the Wolfcamp it causes early on in the exploration and appraisal phase, we have that potential, we described that on the previous slide. We aren’t listing any risked undrilled locations at this point until we get more data and more fully define it.
So I characterize this inventory that we are describing here as a wrist location inventory, it could go up, it could go down a little bit. But I think it adds significantly to the story at Devon that shown we have a lot of opportunities beyond those that we’ve been previously describing and there is a lot of life beyond the Eagle Ford assets.
Well, this is an overview of the Eagle Ford assets. We acquired, we closed this transaction at the end of February. We’re currently producing around 64,000 barrels per day as net about 82,000 acres, about 52,000 of those acres are located in DeWitt county, about 30,000 in Lavaca County. We are in a process of, we have about 230 wells in total that will drill this year across the acreage position. About 200 of those will be in DeWitt County with a 50/50 partnership with BHP.
And about 30 wells will be over in Lavaca County, where we have the bulk of the acreage 100%. There is a small portion of it that we have other industry partners on. But this is really the heart of the heart of the Eagle Ford. This is the best part of the Eagle Ford and that’s why we wanted to do this transaction is, my personal history in the industry is that when you’re in the best part of the areas, good fields get better, and we’re already starting to see that.
When you’re in good areas, good things tend to happen, the other corollary I find also be true. If you’re in not very good areas bad things tend to happen, but that’s not what we’re focused on. We’re on the good part of this and we’re already starting to see some potential improvement beyond even the assumptions that we made in the acquisition.
We like this opportunity, because we considered a low-risk development opportunity. There was about a 175 drilling units have already been established in the Eagle Ford and DeWitt County, which is where we put over 90% of the value. And so it’s really a matter of drilling out those drilling units, their downspacing has already started on sands. We have an idea of what the impact of downspacing will be. The spacing is anywhere from 40 to 80 acres across these dependent on specifically where you are located, where the acreage is located in DeWitt County, our average is about 60-acre spacing.
And so, we’re in the process of just drilling out these existing units. We have about 1,200 and total about 900 locations in DeWitt County. And we preliminarily put 300 locations on Lavaca County. But I can show you what’s happening in Lavaca County is surprising us to the upside. So we will be growing production significantly on this asset or anticipating somewhere in the 65,000 to 70,000 BOE per day range in Q2, growing to an average of 80 to 85 in the second half of the year, and then next year, it should be significantly above 100,000 BOE per day.
Talking a little more about Lavaca County, when we acquired this, we placed over 90% of the value from an internal standpoint on DeWitt County. We didn’t put as much value on Lavaca County initially, maybe that was 32,000 of the 82,000 acres. What we’re finding is the results aren’t quite as good as DeWitt County, but there are a lot better than we originally anticipated.
And so the – some of the recent completions that have been made in Lavaca County or showing in the lower Eagle Ford, which is the same zone we’re completing in DeWitt County are shown in kind of the turquoise blue color there, outstanding wells. And then we also are starting to see some potential anyway in the upper Eagle Ford. And some people called us the Lower Austin Chalks, some called at the Upper Eagle Ford, it’s a same zone as marketing. But it’s a – that’s why we want to call it, but it’s – but we have seen some interesting initial IPs in there.
We still need to understand we need to get more production history to see how are these wells going to hold up? And second, are they make sure that they are not access with the fracs going up from the lower Eagle Ford. We don’t think they are, but we need more production history to see that. We have map, this is a very discrete mappable interval analogs. We have mapped just not only across to our Lavaca County acreage, but also across to our DeWitt County acreage. And then we can tell you from a geological perspective, it is present across the entire DeWitt County acreage. We haven’t drilled any wells into it, and we’re not sure that is economic until we understand the decline rates are a little bit more. But I know some of the other industry players have been talking about successful wells out there in this.
And so, this is an upside, so if you look at what’s happening on this acquisition beyond our original assumptions, I say really three things. One is improved results out of Lavaca. Two, some Upper Eagle Ford potential, and then third, we are also experimenting with a lot of completion techniques right now. Don’t have anything to announce officially, but I’m confident again, we’re in a good part of a field as we continue to improve our completion efficiencies, there is a chance that we can move that EURs beyond what we assumed in the acquisition. So really, really good news overall in the – on the Eagle Ford side.
SAGD developments I said we have two projects online right now. These are low risk, low F&D type projects, long-term type projects from a very high quality reservoir Jackfish 1, Jackfish 2 are currently online. And then Jackfish 3 will have first team in Q3 of 2014 and first production by the end of the year. The plant is essentially complete, where over 50% of the commissioning work is currently done, everything is proceeding on time, on budget on Jackfish 3.
And so you can see we actually have a great runtime also on Jackfish 1 and Jackfish 2. The theoretical plant capacity on that as we assume for many years is 35,000 barrels a day. We actually produced from Jackfish 1, 37,000 barrels a day in Q1 as we are doing some additional efficiencies on the plant side and also down hold it may allow us to produce a little bit more than 35,000 barrels a day.
So that’s proceeding along very well. And so then we’ll essentially be ramped up to full production on Jackfish 3 project by late 2015, going into 2016. And when you do that, we’ve been putting a lot of capital into these programs. Now, we’re going to start seeing the benefit of this. And this is what we’re affectionately calling our well of cash that we’re going to start realizing from these Jackfish projects.
So making the assumptions that are shown relative to pricing at the bottom of the page there as well as the assumption of $300 million of maintenance capital on an annualized basis, that’s taken out of these numbers. You can see that we can be generating free cash flow from the combined 3 Jackfish projects of around $1 billion a year for a longtime, which we can either deploy back into Pike, where we see the four to five Jackfish projects, part of this obviously not all, but a little bit of a back into Pike or other activities whether it would be funding the other E&P activity, share repurchases et cetera.
Just talking briefly about our Mississippian-Woodford and Rockies opportunities, these are our two emerging plays. In summary in the Mississippian-Woodford, we have 8 rigs working. We’re seeing quite a bit of variability, but on average results that meet our type curve expectations. We know we have some areas there going to the full development, we’re just apprising right now to determine how much of this acreage will go to full development.
And in the Rockies, we have about 150,000 acres in Powder River Basin. We have historically been appraising this entire 150,000 acre position. We’re now in our position, we’re going to go into full development in the Parkman formation for parts of this acreage. I think you do that you’ll see us be driving well cost down, increasing the EURs, and really driving the economics as we go into a full development mode on part of this acreage.
And this is part of the description that we laid out, again, the increased inventory in the Powder River Basin what we say now we have 1,000 plus locations, 700 or more of those are in the Parkman, and in the additional ones in the Frontier and the Turner.
Our two liquids rich areas in Western Oklahoma, Anadarko Basin and including the Granite Wash Shale in the Panhandle, Texas. And in the Barnett Shale, great areas, our rig activity is down this year relative to previous years because of our desire to live within cash flow. They just didn’t compete for capital quite as well as our other oil areas, but still great areas with a lot of development opportunities we have to go. They’re throwing off over $1 billion in cash flow combined in 2014, and we will have about two rigs working in each of those areas currently and drilling about – total of about 200 wells, we start with higher rig activity in both of them.
I think one of the more exciting things though particularly is the acquisition we just did of QEP acreage in the Cana area. We acquired 50,000 net acres, increasing our position overall to about 300,000 acres. The reason we did as you might question, with your decreased activity why are you buying acreage in area of decreasing activity just because some of the wells we completed in Q4 of 2014 – Q4 of 2013 and Q1 of 2014, we have an improved completion design went from about 10 to 20 frac stages £6 million of sand about 70% more sand, increased the per cluster from 24 to 48 a lot more sand and the results from that have been outstanding.
And so, on the basis of that plus some remedial action that we took on some existing wells doing some asset jobs out there, we see the economics in Cana dramatically improving where this opportunity is now going to compete for capital very well within our portfolio. I anticipate we’ll be putting rigs to work back out there towards the end of 2014 or early 2015 or work with Cimarex. We work very closely in this field, took the other half of this acquisition from QEP, work with them exactly on what that rig activity will look like, but it’s a really exciting opportunity.
And having said all of this, we’re a very disciplined company. And we have a disciplined approach to capital allocation. We don’t chase production growth in and of itself, we chase value and we’re very focused on returns. And so, we invest in the highest quality E&P projects across to our portfolio, and you can also see that we have returned capital to shareholders consistently over the past decade or so by reducing our net share count about 20% and annual increasing our dividend by 23% all of while be in a very strong investment grade credit rating.
And our debt has increased some, obviously associated with the GeoSouthern transaction, about $6 billion. We got in about $2.7 billion net after foreign exchange and taxes from the Canadian conventional transaction. We’ll receive additional proceeds from the onshore U.S. asset sales, and we have a lot of financial flexibility beyond that to fund growth or either fund growth share or repurchase or whatever looks best on the long-term, where the Bill Featherston Camp here, the cash flow for that adjusted share is the key long-term metric to focus on, and that is our – this is not a perfect metric, but this is our primary metric that we focus on.
We also did a transaction as I said around EnLink setting up a new midstream company, we think a very innovative transaction. We combined our assets with Crosstex. We have a 70% interest in the General Partner, 52% interest in the limited partner. And this is really a way that we can highlight the value of our midstream assets while still maintaining operational control of our midstream business. We contributed the assets about $4.8 billion, look at the current market price of those around $7.5 billion.
And we really like the growth prospects for EnLink as well going into the future. They have drop downs they can do from the GP into the limited partnership, that’s still possible and then here is highlights one additional asset that we have in our portfolio, this is our access pipeline that services our heavy oil production up in Canada. It takes diluent up to the field and takes the combination of diluent and bitumen back from the field.
And we have invested about $1 billion for our net 50% interest in these pipelines. We have 50% along with MEG Energy has the other 50%. We invested about $1 billion. You might want to look at the EnLink Investor Day that they had a week ago Monday. They’ve given potential cash flows from this fair numbers, but give you an idea for what kind of numbers you maybe, I’ll get for cash flow number they show for the access pipeline was around $150 million on annual cash flow then you can apply what are the multiple you want to see what potential value that might have.
So in summary, why own Devon? We’ve done a significant transformation of the company. We’re very happy with where we are, we’re very happy with the asset base. We are focused on returns first, our inventory, we’re describing is much deeper I think and what we’ve described previously. And we have visible low risk production growth, while living within cash flow for many years while we will maintain a strong balance sheet while doing that.
So with that, I’ll wrap it up. Bill, do we have anytime for questions?
William A. Featherston – UBS Securities LLC
Yeah, we have time for questions. Maybe I will start off with the Eagle Ford given the improved operating results that you are seeing, how should we think about the longer-term development of the asset. I think you talked about 150,000 barrels a day of peak production should we think about the potential of raising that peak or would you take to 150 and hold that for plateau longer. And also to the extent that most of the DeWitt County acreage is operated by BHP, how much are you able to affect decisions on the development of the asset?
David A. Hager
Yes. Well, I think it’s too early to announce our revision to our production forecast at this point. We are happy with the results, but we really need to see more results out of Lavaca County and perhaps the upper Eagle Ford before we could be definitive enough to increase our guidance. But we’re certainly encouraged to the upside with the preliminary well results at this point.
As far as relationship with BHP is very, very positive, we work with them. They have been very open from a technical perspective to our input. We have active partner meetings on more than one per week I can tell you. They are very focused on delivering the best value they can from the asset just as we are. We have introduced some new ideas to them. I think we’re learning some from them as well. So I could describe them a very cooperative relationship. We do operate the production side, they operate the drilling and completion. We operate the production, so we have to have a very tight communication, and so far I think it’s been very, very positive.
William A. Featherston – UBS Securities LLC
Any other questions for Devon?
Maybe a quick one on EnLink, obviously if we adjust Devon’s enterprise value for EnLink, you could argue that the E&P assets are being valued at a pretty low multiple. If you chose to try to close that arbitrage, how much could you take down your percentage taken EnLink and still have very strong board representation at EnLink, there are numbers…?
David A. Hager
Well, from a – yes, from a contractual standpoint, we could go below 50%. I think you might argue from a philosophical standpoint whether that’s the right thing to do. But we think that as long as you stayed above 50% on the GP that you would philosophically stay aligned with where you should be.
Now we have no current plans to do that. Obviously we are aware of the option and what you are describing Bill, we understand that very well that there is the – if you look at where you can either look at it the way you describe it or you can look at it if we are trading a little below on market multiple, you are getting a lot of that value for free. You can describe it either way.
So we are aware of that. We are certainly seen and looking and see what options are out there, but right now we like our investment. We think it’s going to continue to grow, but it’s – I think just part of our fiduciary duty to understand what options maybe available out there.
William A. Featherston – UBS Securities LLC
Are there other questions for Dave? All right, if not, please join me in thanking Devon.
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