Athlon Energy Inc. (NYSE:ATHL)
Q4 2013 Earnings Conference Call
February 26, 2014 10:30 a.m. ET
Robert C. Reeves – President & Chief Executive Officer
William B. D. Butler – Chief Financial Officer & Vice President
Will Green – Stephens Inc.
Scott Hanold – RBC Capital Markets
Michael Kelly – Global Hunter Securities
Jason Smith – Bank of America Merrill Lynch
Good day, ladies and gentlemen, and welcome to the Fourth Quarter 2013 Athlon Energy’s Earnings Conference Call. My name is Britney and I’ll be the operator for today. At this time, all participants are in listen-only mode. Later, we will conduct a question-and-answer session. (Operator Instructions)
As a reminder, today's conference call contains projections and other forward-looking statements within the meaning of the federal securities law. These statements are subject to risk and uncertainties that may cause actual risk to differ from those expressed or implied in these statements in Athlon's filings. The discussion on the conference call may include disclosure regarding non-GAAP financial measures. Reconciliations of any non-GAAP financial measures to the most directly comparable GAAP measures all are provided in yesterday’s news release that is posted to our website at www.athlonenergy.com.
I will now turn the call over to Bob Reeves, Athlon's Chairman, President and Chief Executive Officer. Please proceed.
Thanks, Britney. I’m very excited to report that we had excellent financial results in the fourth quarter and for the full year of 2013 and met all of our expectations despite two major ice storms that I think everyone is aware of in out the Midland basin that occurred in the second half of 2013. This is really a direct result of our people on the ground out there in our Midland office that really went above and beyond to get these wells back on and get electricity hooked back up, et cetera. So we’re very happy for those guys working hard to do that and we’re very grateful here in Fort Worth.
Since our IPO, we’ve really brought an excellent track record of outperformance to all our new shareholders and we’re very excited to continue those results. One of the things we plan to do is early in March which I guess March is next week, we’re going to put out new vertical PUD type curves as a result of this end of the year Cawley Gillespie reserve report for our three areas like we typically do, the Midland, Howard and Glasscock. We will put additional detail out there on horizontal type curves for Midland County where we’ve drilled those first two horizontal wells. We’re going to move those EURs up of course. And then we’ll have another look at our 3P reserves and our updated drilling inventory as a result of the yearend results.
So again we had a very good year in 2013 and we’re really looking forward to 2014. Just to recap, our fourth quarter production averaged 14,689 barrels of oil equivalent per day despite the ice storm that we talked about earlier, a 69% increase over 2012. Along with that, oil volumes grew at 83% year-over-year. We beat the IPO expectations for the fourth quarter by 1600 barrels a day and that’s despite this weather.
The production results translated directly into the financial results as you look at the EBITDA, the cash flow and EPS. And William will go through that later in the call. All of them were above the consensus estimates and again well above what we were expecting out of the gate at the IPO. We also disclosed our yearend proved reserves, the Cawley Gillespie did, and those were up almost 50% to 127 million barrels equivalent. We replaced over 10 times our production in 2013 and our funding development cost was excellent at $886 per BOE. Also in January we’re happy to announce we drilled our 350th vertical well across our properties. That’s a lot of drilling, but we still have over 5,000 locations to go on the vertical side. So we’re very excited to have that deep inventory.
We also started 2014 off with an excellent acquisition that we’re very proud of. It was 5600 net acres and 1750 barrels of oil equivalent per day at $88 million. We signed additional tag-along rights that came along with that acquisition and I’ll give you more details on that in just a second. Since the IPO, we’ve added 12,000 net acres. So where we stand today is 110,000 acres net to us across the northern end of the Midland basin. We’ve also put out some 2014 production outlooks. We’re planning to grow next year in the 60% to 70% range over 2013. That gets you to the 19,750 to 20,750 range that we’d given previously. I think at the IPO we were planning to average about 18,000 barrels a day so 12% to 15% increase over that. 85% of this production and 70% of our capital for 2014 is still associated with our low risk vertical drilling program. So we feel really good about our outlook because it’s anchored on this vertical drilling program.
But we do have the horizontals as well as everyone is aware of now. We’ve announced three of the highest producing Wolfcamp horizontal wells within our respective operating counties. Again we have 1,000 locations on the horizontal Wolfcamp side. When we look at the reserve report in just a minute, you’ll see that we did not book any horizontal PUDs attributable to the drilling results last year on the horizontals in the yearend 2013 report. So when you look at where we’re going and what we’re doing in the Midland basin, I’m really excited to have this combination of best-in-class vertical program which is still the key backbone to the company, but also have this immense horizontal potential.
So let me talk a little bit more about the year in proved reserves. As I said, they were up 50% to 127 million barrels a day. Our PV-10 pretax increased by 89% to $1.6 billion. Oil reserves totaled 71.2 million barrels. When you combine that with the NGLs, our liquids equaled 80% of our proved reserves. Our proved developed reserves were up 82% and now they equal 37% of our overall total proved reserves, which was an increase on a percentage basis to where we were in 2011. So more of our proved reserves are now sitting in the proved developed category.
We incurred just under $400 million in development CapEx in 2013 by drilling 171 operated vertical wells, plus the four horizontal wells. So again that equated to $8.86 per BOE on the F&D side. That compares very favorably to our three year average drill bit F&D which is $8.33 per BOE. So we have outstanding breakeven costs when you look at us on a full cycle basis. But let me give you a little bit more detail on the proved reserves. And again, we’ll put this in the updated presentation that we’ll put out in early March. But overall on a three phase basis, our vertical PUD type curved moved from 148 MBOE at the IPO to now the 168th MBOE and that’s average across all of our counties. But when you dig in to it a little bit deeper, you can see that Howard moved up which was previously 141 MBOE. Now it’s at 153 MBOE which is up 9%. So we’re happy there.
The Midland went from 208 to 236. Again that’s up 14%, very happy there. And then Glasscock was probably our biggest increase we’ve talked about with folks over the last four or five months that we thought it would increase and it did. It went from 118 MBOE to 140 MBOE which is almost a 20% increase. So we had increases across all three of our areas on type curves. When you dig in and look at the revisions, the revisions are mostly flat across that and I’d like to explain that a little bit. So the type curves that we just increased that I just talked about increased our overall reserves by about 7.2 million barrels. What we did take away from the revisions is we did take off about 6.5 million barrels associated with wells that were beyond the five years on our verticals. So the 7.2 million barrels from the type curves, but wells that we don’t plan to drill the next five years on the vertical took away 6.5 million barrels, but as we drilled deeper wells in our areas and down into the Strawn, and the Atoka and even the Mississippi, it added additional deep gas that came with those wells. So that was a positive 2.5 million barrels.
So when you put all that together, it adds up roughly to our revisions. But I just want to give a little bit more detail on that. I think a lot of the type curve refinements and increases was really a result of the guys really digging in deep on these laws and really refining the completion techniques across all these different zones on these vertical wells. Again we’re [perfing] and fracking 10 to 11 stages on most of these vertical wells. They treat each one of these zones a little differently with their completion techniques and they’ve really continued to refine that. I think what you’re going to see and what you’ve kind of seen already in these first three horizontal wells that we’ve disclosed is that refinement and that attention to detail and just the experience of drilling 350 of these wells is really going to translate well into when you start completing these horizontal wells. So I think that’s really made a difference.
Again we have not hooked any horizontal PUD wells this year. Obviously as we drill more horizontals in 2014, I believe we’re drilling 21 horizontal wells in 2014, there will be PUD adds next year associated with these horizontals. As I talk about the horizontals again, we’re putting out the new investor presentation in a week or so and one of the things that we feel really good about is Midland County where we drilled the first two wells. I see those horizontal Wolfcamp type curves going up in that particular area. So for the 5000 foot laterals over there, I see the type curves increasing to around the 600 MBOE range. I think previously we would put out somewhere around 500 MBOE and then on the medium length laterals is what we call the 7500 foot and those increased to just over 800 MBOE from 730 MBOE. So I think we feel really good about that.
And as I just go back to the acquisition briefly, the acquisition was in most of these areas that we’re talking about over there in the Midland County, Upton County area. We closed that acquisition on February 6. We added 250 gross vertical drilling locations and we added 44 gross horizontal Wolfcamp in A and B location. Since then we’ve had 770 net acres come to us and additional working interest associated with those acres for $8.7 million that are associated with tag-along rights. And that brings our total acreage to just over 6400 net acres for $97 million. But as I continue to talk about this Wolfcamp program, again the tight curves in Midland county, we’ve exceeded our initial expectations on those wells.
And the rates of returns for those two wells are well above 100%. So that first TXL well, we exceeded the type curve by about 130% and then the Davidson well, the second one which is our medium length lateral, we outperformed that type curve by 123%. And we disclosed the new 30 day rate for the Davidson well. We had put out the 20 day rate a little bit ago, but we just updated it so you have the full 30 day rate. So the full 30 day rate on that well was 1717 BOE per day and it’s 69% oil. And again we’re very proud of those first two wells and they really stack up well against any of the other horizontals out there in the basin.
As we look at this first Glasscock County well, obviously we’re very happy about this Wilkinson well. It was drilled to a medium -- as a medium length lateral as well. 30 stage hybrid completion, very similar to what we did over there in Midland County. What we did over there is we put a section together with half a section with Laredo. We pooled 960 acres to kind of form a JV. We operate it of course. And that’s why the working interest is a little lower at 58%. But you really get those accelerated rates of return so we can drill those 7500 foot laterals. So we’re happy to be a partner with Laredo and any other of our offset operators across the basin to drill these better, higher rate of return wells.
Again the 24 hour IP on that was 1734. It was 71% oil. It’s on gas lift. The 30 day rate was 1562 BOE per day. We see that as the highest 30 day IP of any of the Wolfcamp refining Wells on the east side of the basis on an adjusted per lateral foot or on a gross basis. We successfully drilled the second Glasscock well over there in the Wolfcamp A. That’s the Lawson 2703. It’s a medium length as well. We’ll complete it very similarly to the first one. In fact, we did complete it very similarly to the first one. It’s been producing for a few weeks. It’s on gas lift and we’re encouraged by the early results on that. We moved the rig after that up to Howard County and we drilled the Abel Well up there in Wolfcamp A. That was a lateral length at 8294 feet. It’s currently waiting on production. We should get that thing completed in the next week or two. We feel very encouraged about what’s going on up there in Howard County.
We had a new investor presentation out there a few weeks ago. Element Petroleum was kind enough to share their data with us on the SFH unit 23-1. So we plotted that against our type curve out there. And our type curve for the Howard County area and the Glasscock County area is 625 MBOE and that well stacks up very nicely against that type curve. In fact just above that. So we’ve very encouraged, but again we’re more encouraged and more excited about really what’s going on with our company as we look forward and we start drilling these Wolfcamp wells in Howard County and Glasscock County on the east side as well.
But we’ve looked across the northern end of the Midland basin on both sides, the west and the east side and really done some analysis on operators by county. And kind of what we see is that on the 30 day basis, operators are averaging about 625 to 750 BOE per day across the basin and that’s based on 68 horizontal wells. And I would just like to reiterate that that’s kind of what we see, whether you’re looking at Howard County or Glasscock or Andrews or Martin. Really anywhere other than Midland County we kind of see that 625 to 750 BOE per day over that first 30 days as kind of as a good well, very good type curve etc. So again our first three wells averaged 1500 barrels a day on the 30 day rate compared to kind of those average of 625 to 750. We certainly don’t expect to continue to 1500 barrel per day as well drill across all our acreage in the Midland basin, but we feel very good about that 625 to 750 range.
Going forward, here’s what we’re doing on the drilling. Again we’re drilling the second horizontal medium length Wolfcamp A in Howard. We’ll drill three total wells there in Howard County in the Wolfcamp A. And then we’re moving that rig down to Glasscock County to protect lease lines. And we have operators that are drilling rapidly in Glasscock County Wolfcamp wells. They’re drilling those not only in the Wolfcamp A, but they’re drilling those in the A, the B and the C and even the Cline. So we may end up drilling additional zones down there in Glasscock County as we protect those lease lines just kind of depending on where the offset operators are drilling. So we’ll give you more detail on that as we get that. So we’ll probably defer that Irion County those two wells that we’re planning to drill in Irion County to later this year. We plan to eventually get there, but right now we need to get some wells drilled down there in Glasscock County to offset those leases.
So one of the questions that we get on these horizontals wells is how are we able to drill these wells kind of top tier? Again I think it really goes back for our team in particular to the vertical experience. They’ve really drilled a lot of outstanding vertical wells in the basin and they’ve really refined these techniques. So I think again it goes back to targeting the right interval in these Wolfcamp wells when you’re drilling them. And then our drilling team has done an outstanding job of keeping the drill bit in the target across the whole lateral. And I really think that makes a big difference to the completion. And then fine tuning these completion designs from what we’ve learned off the verticals I think is really paying dividends for us. And then again, we ran some tracers in these first several horizontal wells, which is costing us little bit extra. But it’s really letting us know kind of where the production is coming from, whether it’s coming from the entire lateral length or close to the well bore out in the toe. So analyzing that data I think is really paying off for us as well.
So when you look at the fourth quarter, we ran the seven vertical rigs drilling those 46 vertical wells, two more than our budget. That was $118.8 million of CapEx. So we really continued to focus on the CapEx side, but the operating side, the LOE, it was $7.22, again another decrease for us in the quarter. And William will go through that more in a second. Again, looking forward to 2014, we are running 8 vertical rigs right now that we plan to drill 205 well with this year. We’re adding that second horizontal Wolfcamp well in the second quarter. That goes straight to Midland County where we’ll be drilling wells in Midland County for the foreseeable future. Our CapEx for 2014, just under $600 million, $595 million, another $20 million for leasing infrastructure, capital work overs, et cetera.
I think one of the interesting things about our 2014 budget is that of that $595 million, only 42% of that is going to HBP leases. And last year it was 85% of our budget. So you’re really got a less risky budget in 2014 with much higher rates of returns is what we’re predicting based on these new vertical type curves and these new horizontal type curves. So we’re excited about 2014 with the vertical well results, the horizontal well results. We continue to monitor activity across the whole basin. We’re watching the Spraberry, the Joe Mill, the Cline and even the Clearfork carefully on the horizontal side. So we would not be opposed to changing into one of these zones if it proves to be a higher rate of return to what we’re drilling in the Wolfcamp A or the Wolfcamp B in a particular area. And like I said, we’ll probably end up testing some of these zones later this year or early 2015 on our acreage as well simply because other operators are offsetting us doing that.
So with that I'll turn it over to William, let him talk a little bit deeper about the financial results and then I’ll get back on the call later after William is done.
Thanks, Bob. Let me just walk through the fourth quarter financial results and then the EPS adjustment first. Our adjusted EBITDA for the fourth quarter was $70.2 million. That compares to the IPO forecast of $65.5 million. When you look at all these on a BOE basis, it’s $51.92 in terms of EBITDA per barrel of oil equivalent for the fourth quarter. That’s up from $43.13 last year for the fourth quarter. The components that really make that up, the unhedged revenue was up almost $10, $9.96 per BOE from the fourth quarter. Production, ad valorem, and severance taxes were up $0.68 per BOE year-over-year, but really important to the equation was the direct LOE. That fell $2.33 per BOE from the fourth quarter of 2012. That’s a 24% reduction which is all the more impressive given the weather impacts that we had in the fourth quarter. When you look at the full year EBITDA for 2013, it came in at $224 million. That’s $20 million higher than we had anticipated at the IPO or 10% above our expectations there.
Discretionary cash flow for the quarter was $60.4 million and $190 million for the full year. Again that’s beating our fourth quarter and pre-IPO expectations.
Turning to the EPS, on a GAAP basis, we reported $23 million of net income for the fourth quarter that’s attributable to our common shareholders. That’s $0.27 per diluted share.
Net income, excluding certain items was $19.6 million, which is 46% year-over-year and that equates to $0.24 per share on a diluted basis. Some of the adjustment items on a pre-tax basis were a non-cash derivative gains of $4.1 million. We also had acquisition and other non-recurring costs of $231,000 and then the net tax effect of those was $1.4 million.
Turning now to the balance sheet and liquidity, our pro forma liquidity as of 12/31/2013 is right above $540 million. We closed out the year with $113 million in cash on hand and had no borrowings under our $525 million revolver. That was increased during the fourth quarter with our fall borrowing base redetermination from $320 million previously. So that number even includes the January acquisition of $97 million. So we think we’ve got ample liquidity for the drilling program Bob has laid out as well as for potential acquisitions. We do expect that borrowing base to increase substantially in our next redetermination in 2014. We expect this as a result of the outstanding results reflected in the yearend reserve report and this January acquisition. When you look at our debt ratios, the main one we focus on here is debt to EBITDA. If you look at our current quarter annualized of $70 million EBITDA that comes to $280 million. So you take into account our $500 million of notes outstanding in that net cash position, you’re talking about a debt to EBITDA of 1.7 times. We view that as very favorable.
Let’s turn a little bit to the hedging side. We have added additional oil swaps even since our January announcement a few weeks ago. So looking at 2014 for the first quarter, we’ve got WTI oil swaps hedged at 8600 barrels at 9270. When you look at the full year 2014, we’ve now hedged 9,400 barrels of oil per day at 9261. That’s about 70% to 80% of our estimated oil production. That’s in line with our corporate target, so we feel really good about those levels. Here are some of the hedges we’ve added since the January update. We are now hedged in 2015 and for the first half of the year at 4300 barrels of oil a day at 9129. In the back half of the year, we’ve still got room to hedge up a fair bit at 1300 barrels a day at 9318 for the second half. We do continue to monitor the Mid-Cushing differential and opportunities there to hedge.
So finally I want to add a little bit of color to the guidance that we’re reiterating from our January release. When you look at the first quarter, the production range is 16.2 to 16.8 MBOE per day. That represents 10% to 14% sequential growth over the fourth quarter and 63% to 70% growth over 2013. We do expect the production mix for the first quarter to be relatively in line with last quarter at 61% oil, 18% natural gas and 21% NGLs. For the first quarter, we’re looking for oil differentials to be wider versus the $3.92 off of NYMEX last quarter. The main components of that include $1.70 in transport fees that we incur and then the Mid-Cushing is the other main component of that and that’s average quarter today about $3.50 negative. So the all-in implied differential we expect to be in the $5 to $6 off of NYMEX WTI for the first quarter.
We do expect full year 2014 production as Bob said to be 19.75 to 20.75 MBOE per day and that’s 70% production growth outstanding. Our direct LOE per barrel for the year we expect to be in the 635 to 685 range. I would expect that to be at the high end for the first quarter of 2014. When you look at production, ad valorem and severance taxes, we still expect that to be in the 6.5% to 7% of well head revenue range. That’s consistent with recent quarters.
And then when you look at our recurring cash G&A, we’ve put out guidance of $3.20 to $3.50 per BOE. That does include normal course public company expenses. And again I think we’ll be at the high end of that range at the beginning of the year. We also expect our first quarter tax rate to be 37.5%. So that wraps up sort of the guidance. We do anticipate filling our 10-K next week, the week or March 3rd and they’ll have the rest of the details in there.
With that, I’ll turn it back over to Bob.
So Brittney, why don’t we go ahead and open up the lines to questions. I’m happy that everybody was on the phone today and I’d be happy to answer any questions that we have.
(Operator instructions). And your first question comes from the line of Will Green with Stephens. Please proceed, sir.
Will Green – Stephens Inc.
You kind of mentioned you’re watching the C Cline and Spraberry horizontally. Most of the stuff early on you guys are drilling is A and B. I guess what gets you over the fence in terms of wanting to go out and try Spraberry or Cline or C well? And just kind of take us through that process in decision making.
I think for us the thing that’s going to get us over the fence the quickest is the example in Glasscock County where we have folks directly offsetting our lease line in zones other than the Wolfcamp A. I think you really need to go ahead and drill those zones. It’s just prudent to do so in industry standards. So I think to the extent of that happening, it would be good for us because we’ll be drilling in different zones. We’ll get to see the rigs returns and the EURs on those different zones and makes decisions across the whole basin based on some of those results. So where we thought it would take longer to get to some of those things, it might be sooner rather than later now.
Will Green – Stephens Inc.
And how are you guys thinking about Howard County overall in the portfolio? I know you guys don’t really have a lot of your own well data to go on, but if you look at what element, what you guys showed us with element and how those wells are performing, I would assume it looks a little bit better than you guys had previously thought. I guess the question is if you can replicate a well like that or wells like that on a repeatable basis, how does that fight for capital versus your other areas if you can repeat something like that?
I think it fights for capital very well and obviously we did -- because of the blocking nature of that acreage over there, you can get into really some very efficient development there that further makes the return better. And one of the things you’re seeing with this team is the more wells that they drill in an area the better they get. They have a history of driving down capital costs and they have a history of refining these completions to increase rates of production that are translating into higher EUR. So we think it translates very well and very favorable with the rest of our portfolio. Again, we don’t think that a 30 day rate of 1500 barrels a day, which we did across the first three horizontals is going to hold up across all the acreage in the Midland basin. Certainly there will be our fair share of that. but again a 30 day rate which if you look at other operators and the other 68 or 75 wells out there in the northern Midland basin, I think a 625 to 750 30 day rate on a BOE is very good and excellent rates of return. So we’re really looking forward to it I would say.
And your next question comes from the line of Scott Hanold with RBC Capital Markets. Please proceed.
Scott Hanold – RBC Capital Markets
So with the stress you all have been having with the horizontal wells, what is it going to take for you guys to look at increasing net activity? I don’t know if that would cause just an incremental amount of spending or a reduction in vertical activity.
That’s a good question because we’ve got that question a lot recently. For 2015, as you look at the cash flows that we’re going to have in 2015, obviously it’s going to be much higher than 2014. Those incremental cash dollars that we’re seeing in 2015 are going to go into the horizontal drilling program. So in 2015 you’re going to see a natural ramp up in horizontal activity as a result of those extra cash flows. I think that continues to snowball as you drill these prolific horizontal results as you look into 2015 and 2016. So with an asset base that has been largely driven on 70% production growth based on vertical drilling wells and then adding that incremental horizontal activity from the excessive cash flows, I really think you’re looking forward to something that’s really unique and pretty exciting for a company our size. Again with no horizontal wells booked at the end of 2013, I think you can see that this upside that we talk about with our companies is going to move from the 3P type numbers into the 1P type numbers rather quickly. So we’ll look at adding additional activity later in 2014. We feel pretty good about our activity right now. But I think 2015 is going to be pretty exciting for us.
Scott Hanold – RBC Capital Markets
So I guess what drives the thought process of waiting a little bit more to 2015 is that you need the HBP stuff a little bit more. So you’re looking at verticals. They’re just too early in the horizontal development where you need more results, because I’d have to imagine just on a rate of return perspective, these horizontals have to be crushing the vertical well. So it seems logical to ramp the horizontal in lieu of vertical a little bit sooner than that.
Yeah. There’s a couple of things on that side as you dig into it a little deeper, Scott. The vertical rigs, we’ve spend a lot of time and effort to get these drilling costs down to the best in the basin. So our drilling costs on these vertical wells are really second to none. And when you’re talking about an overall portfolio of $600 million of drilling this year for a company our size, that’s pretty large. And we like the fact that a large percentage of that is very low risk in nature and our rates of returns have increased on that vertical side. So we’re trying to balance low risk with the higher risk just simply because horizontals are a little bit more complicated to drill and complete. And we just like to balance risk across the portfolio. A second thing on the vertical drilling is that we like to have a certain amount of our fleet in the vertical drilling fleet that is not 100% dedicated to HBP drilling because what you can do is when you do get opportunistic acquisitions, you can move some of that fleet to acquisitions that need to drill additional leases that need to be drilled because they need to be HBP. So what you have is a drilling rig, a drilling crew that immediately moves into an acquisition. You can HBP those leases. It’s accretive and you’re moving from a running start as opposed from a standstill. So there’s some strategy in that as well. So we like the overall risk. We like the overall opportunistic nature of it and we like the fact that all eight of those rigs are running at 100% efficiency. So that’s the way we look at it.
Scott Hanold – RBC Capital Markets
And one other question is, when you look at your outperformance, certainly kind of coming out of the box of since you went public, it seems like you’ve exceeded expectations. And when I look at 2014 guidance, is that based on -- what type curves is that based on/ is it going to be the ones that you all kind of lay out in the next week or two or is it going to be based on some of the prior type curves that occurred before?
No. 2014 is based on the new type curves on the vertical drilling program. But we do -- if you dig in deep to like our model and our guidance and stuff, we do risk the production volumes accordingly because as we talked about a little bit in the fourth quarter when we were explaining the weather and such, that we do try to take into account that some bad things do happen during the year, whether it’s weather, whether it’s services, whether it’s just -- it could be anything. And then just a normal part of everyday life in the oilfield is that wells go down. You’re not running at 100% of your wells pumping all the time. So you have downtime associated with wells. So we’re just trying to take all that into account and make a well-educated estimate of what we think our production will be for the year and we go from there. But we base it off the new type curves.
And your next question comes from the line of Mike Kelly with Global Hunter. Please proceed.
Michael Kelly – Global Hunter Securities
I was hoping to follow up on Will’s question on Howard County. Was really hoping you can frame for us finance guys really your confidence in the geology up there versus maybe Glasscock or Martin County. Look at your slide deck here and Slide 17 looks like you’ve got a pretty thick Wolfcamp section there. But just maybe in other kind of general terms, why you like this from a horizontal perspective you think is going to work. Thanks.
Yeah. We’ve drilled I think something like 170 wells in Howard County now on a vertical basis and we drilled basically all across our acreage position. We’ve got plenty of logs and more importantly, we’ve got plenty of work as far as just competing across these different zones. And so Wolfcamp A there looks really good, which is where we’re targeting it initially. It’s thick. It’s got the same geologic characteristics as we see down in Glasscock County. So we feel very good about Howard County. And to be frank, it drilled just like we thought it would. We landed it in a zone that we wanted to land it in. it drilled very nice and we’re excited about the results that should come out of Howard County in April. So when you look at all that data combined, it just looks to us very favorable.
Michael Kelly – Global Hunter Securities
And then on the heels of this $97 million bolt-on deal, I’d just like to get a sense of how you’re thinking about balancing spending going forward between opportunistic deals versus accelerating for organic growth given you’ve got a pretty stout inventory both vertical and horizontal now already with your ongoing position. Thanks.
So when we look at acquisitions and organic growth, it’s sort of a long term versus short term question I think. Obviously over the short term you’re always better plowing that capital into your highest rate of return type wells in your drilling inventory. But over a longer term period and trying to accomplish the goals that we’re trying to accomplish as a company, we want to continue to add inventories to our portfolio and increase the asset base. So we’re trying to expand our acreage footprint out in the basin. I think that one of the things we really believe that we were going to be one of the top tier operators out there as far as vertically. I think that you’re starting to see that we’re going to continue to do that on the horizontal side.
So we like the idea of getting additional acreage and applying that expertise across the basin. And we’ve said before, we’re staying in this basin and more specifically, we’re staying in the northern end of this basin, not too far north of course, but in the heart of the plays that we’re in right now. So we’ll be opportunistic on the acquisitions for the long term and we’ll continue to plow additional cash flows into the high rate of return drilling on the short side. And again, everything for us comes into balance as far as risk and overall portfolio rates of return. So that’s how we look at it.
(Operator instructions). And your next question comes from the line of Jason Smith - Bank of America Merrill Lynch. Please proceed.
Jason Smith – Bank of America Merrill Lynch
Just a quick question; as you defer drilling in Irion, are there any HBP issues there that force you to have to drill up your end or can you defer that further out if you decide to focus more on Howard and Glasscock and Midland?
That’s a great question, Jason. We’re 100% HBP down there. So we don’t need to drill horizontal wells for acreage reasons. We have legacy vertical wells down there that are holding the leases. So when we drill down there in the area, it’s really just -- it’s a want, not a need. So we could defer it further. But our plan is to eventually get down there and drill those wells and understand the geology and the EURs on that end of the basin as well.
Jason Smith – Bank of America Merrill Lynch
But is it fair to say you could potentially push that beyond 2014?
That’s fair to say.
Jason Smith – Bank of America Merrill Lynch
And then just on the Wilkinson well, given the partnership with Laredo, can you just remind us how much of your acreage is conducive to longer laterals and is the need for partnership just concentrated in Glasscock or do you have that in other parts of your acreage?
No. I think most all the acreage across the Midland basin, most -- there’s certainly areas where we can drill lots of 7500 foot laterals. In fact when you look at our horizontal inventory and you add up the shorts and the mediums and the longs, we even have some 10,000 foot, overall we average like -- our average length well is 7,200 feet in our inventory of 1,000 wells. So you do need to partner up in certain areas and you want to make sure that you get all of your acreage developed properly. So our feeling is it’s better to partner up early and get acreage where you need to drill the longer laterals upfront, because what could happen is if you end up having laterals go the other way away from you and somebody partners with somebody else, then you’re going to end up with stranded acreage potentially or the short laterals which are lower rates of return. They’re still excellent, but where we can we’d like to get a jumpstart on it and Laredo and us, we were able to get together and they understand the same thing, certainly from Laredo’s standpoint. They have plenty of 7500 foot length laterals to drill. But it just makes sense to partner up. And I think you’re going to see that across all the basin, whether it’s Midland County, Martin, Andrews, Glasscock, Howard, everywhere. That’s just going to be -- end up being the norm I think.
And that concludes the question-and-answer session. I will now turn the call back over to Bob for further remarks.
Thanks, Britney. Again, thanks everyone for taking time to get on the call. Those were excellent questions on the follow-up. I think a lot more questions that we can answer through the presentation, that will help next week as we get that out. And again Williams talking about the 10-K. it will be filed as well. So again thanks everyone for being on the call and we’re looking forward to 2014. Thanks.
Ladies and gentlemen, that concludes the presentation for today's conference. You may now all disconnect and have a wonderful day.
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