Matador Resources Company (MTDR) Q1 2015 Earnings Report, Transcript and Summary

Good morning, ladies and gentlemen. And welcome to the First Quarter 2015 Matador Resources Company’s Earnings Conference Call. My name is Sammy, and I’ll be serving as the operator for today. At this time, all participants are in a listen-only mode. We will facilitate a question-and-answer session at the end of the company’s remarks. As a reminder, this conference is being recorded for replay purposes and the replay will be available on the company’s website through Sunday, May 31, 2015, as discussed in the company’s earnings press release issued yesterday. I will now turn the call over to Mr. Mac Schmitz, Senior Financial Analyst for Matador, who also manages the company’s Investor Relations. Mr. Schmitz, you may proceed.

Thank you, Sam. Good morning, everybody, and thank you for joining us for Matador’s first quarter 2015 earnings conference call. Some of the presenters today will reference certain non-GAAP financial measures regularly used by Matador Resources in measuring the company’s financial performance. Reconciliations of such non-GAAP financial measures will be -- with comparable financial measures calculated in accordance with GAAP are contained at the end of the company’s earnings press release. As a reminder, certain statements included in this morning’s presentation maybe forward-looking and reflect the company’s current expectations or forecasts of future events based on the information that is now available. Actual results and future events could differ materially from those anticipated in such statements. Additional information concerning factors that could cause actual results to differ materially is contained in the company’s earnings release, its most recent annual report on Form 10-K and any subsequent quarterly reports on Form 10-Q. I would now like to turn the call over to Mr. Joe Foran, our Chairman and Chief Executive Officer. Joe?

Thank you, Mac, and good morning, everyone on the line, and thank you for participating in today's call. We appreciate your time and interest in Matador very much and look forward to your questions. I would like to -- and answer them, I am going to call upon at various time senior members of our operating staff who have joined me to this call and they include, Matt Hairford, our President; David Lancaster, our Executive Vice President and Chief Operating Officer and Chief Financial Officer; Craig Adams, Executive Vice President, Land and Legal; Ryan London, Executive Vice President and General Manager; Brad Robinson, Vice President of Reservoir Engineering and Chief Technology Officer; Van Singleton, Executive Vice President of Land; Billy Goodwin, Vice President of Drilling; Gregg Krug, Vice President of Marketing; and in our Roswell office, Trent Green, our Vice President of Production. In this call, I would like to emphasize three key points. First is Matador's growth. At the time of our IPO we were producing 400 barrels of oil per day and this past quarter, we averaged over 11,000 barrels a day and all this growth has been achieved without stress in the balance sheet and we have maintained our net debt to trailing 12-month adjusted EBITDA, so that has never exceeded 1.8, it is currently 1.2. Second is our production continues to meet -- exceed our expectations and for the first time in our history, we produce more than 2 million BOEs in a single quarter, recording production of 2.1 BOEs this quarter. And our most recent wells continued to pleased us very much not only from a volume and production point of view, but also in the cost reduction that have been achieved by vendors working with us, as well as the operating efficiencies that our staff has been achieving. And the third thing is the -- is what I mentioned on operating cost that they are down. We originally thought this year 15% to 20%, they are more in the 30% to 40% range and a combination of vendor -- adjustments by vendors working with us and cutting down the number of days on wells and complete them better and then our gas lift system on production. So I wanted to know those, as well as maintain our progress we are continued to make on midstream. And with that, I am pleased to announce that we've increased our full year 2015 oil production guidance from 4.0 million to 4.2 million to 4.1 million to 4.3 million barrels and while affirming our other full year guidance, but we'd got you to the more likely to beat to the higher end of that production range. So, with that, let me turn to the operator and start taking the calls.

Thank you. [Operator Instructions] Our first question comes from Scott Hanold of RBC Capital Markets. Your line is now open.

Thanks. Good morning.

Hi, Scott. How are you?

Hi, Scott.

Fine. Thanks. Great quarter. Just was wondering you all have had some pretty good success with your initial drilling campaign in the Permian Basin and the results that you have seen in addition to industry, obviously point to a lot of potential in the layers of the cake because I think you discussed before? As you start to think about moving toward development, what is the plan, is there specific zones that look like they are going to be attacked first or do you consider this to be a more development of all of the zones together can you just give us a sense?

Ryan, would you take it please.

Sure, Joe. Scott, what we think in terms of development, it depends on the area, but in our Wolf area, I think, in terms of what we can develop all at one time would be the Wolfcamp. The Wolfcamp X with we spend a lot of time developing so far and how it relates with the Wolfcamp A. And the Third Bone Spring, like we said before we are trying to optimize the development program there. Certainly the program you will see over the next two, three years there, we will focus on those horizons. We do have Bone Spring and some upper Bone Spring formations that we want to test, but those will be independent of that. So our primary focus down there will be the patterns representing to the Wolfcamp. When you move to Rustler Breaks, I think it’s the similar story, I think we are going to be focusing on the Wolfcamp and how it interacts with the different benches in the B, the X, and the Y stand up there and the third, Bone Spring. And of course we will be picking off a specific Second Bone Spring than First Bone Spring horizons mixed in with those. And certainly with the capabilities of our rig doing simultaneous operations, we can do that without really interrupting our Wolfcamp campaign. Up in the Ranger area, our focus is on the Bone Spring. We will be developing Second and Third Bone Spring. We will be looking at some other targets like Avalon and Brushy Canyon, but I think, most of those will be much more surgical in nature and how we approach those. Does that answer your questions, Scott?

Yeah. Yeah. It did.

I would -- yeah, Scott, I would add, let me, if you, Ryan, as we were talking in the preparation, we drilled what 18 wells out there?

18 total wells and of those 18 wells, we drilled into eight different horizons. And we do have plans this year to drill in two more horizons before the year is out. So we are in testing different horizon mode but we are kind of focusing, tending to try and focus some of development programs toward some of those deeper horizons, specifically the Wolfcamp.

So Scott, you can end up with at least 10 different producing horizons by the end of the year. Matt, David, did I leave anything? Because I think your questions are really good one.

Scott, this is Matt. I think Ryan has done a really good job. And I think the other thing and you know it’s a long time that the thing we will do since we’ll keep our eyes wide open as we go through this process and drill these different zones and figure out, that’s the time what makes the most sense and that’s where we’ll focus our development efforts.

One other thing, Scott, part of the effort as you know us is that we’re trying to decide now what we believe is the most likely an optimal spacing. So some of the test that we’re doing is to test the what would I think is the most efficient spacing patterns before going into full development. The other thing is the engineering and geology has been working very closely across this one to determine the good, better, best of these zone. And including the CD effects of using micro-seismic to help evaluate results with larger similar fracking as well as 3D seismic in picking some of the locations. So there is a lot of good work there. We’re kind of, I would, say pass the exploratory or getting to the end of, I think, the delineation. And in certain parts, it’s going to be ready for development, more intense development by the end of the year, including at least one place where we’re doing a stack well with three different horizons.

One more thing, Scott, on the purpose of that strategy to focus on the deeper horizons, it’s something that we learned in the Eagle Ford that if we go and we drill a well, we have a much better outcome on the program, if we go in and we offset that well sooner rather than later. So our strategy is to focus on that instead of testing all the different horizons and making our development program include all those horizons. We want to focus on the deeper horizons. It’s just something we’ve learned in the Eagle Ford and also in the Haynesville. I think a lot of other operators feel the same way. It’s just a much better program to just march from one side of your lease to the other side as soon as you can.

Okay, appreciate that. Thanks. And as my follow-up, a little bit on CapEx spend and well costs, you hinted in your press release that it seems like you are running under the 350 budget but you are obviously leaving a little bit of room for that rig, third rig possibly coming in. How much are you running below that and is that efficiency or service cost reduction because looking at that Cimarron well for $5.3 million, that surprised me, that’s a low number. Can you give us a little color there?

Yeah. Hi Scott, it’s David. So I think we ran around $10 million under the budget in the first quarter. And like we put in the release, we expect to continue to bring wells in for a little less than what we had budgeted because as we mentioned we made those forecast on, sort of, 15% to 20% cost reductions and we have seen better cost reductions. The other thing, of course, that we mentioned in the release is that our drilling guys are really doing an excellent job of beginning to drill these wells much faster and much more efficiently. So I think not only the two new rigs that we have but also just the things they are learning about drilling those wells, I believe, we mentioned in the release that the last well they drilled at the Wolf area was 23 days from spud to TD compared to little over 40 is what we have been averaging. And that’s even better than the goals that we have set and budgeted by going into the year. So I mean, they deserve a lot of credit for how quickly that they are beginning to improve and how much progress they are making in getting our drilling times down and that has a big, that has a big impact. I mean, if you save 20 days on something that maybe $75,000 a day spread rate, you’re talking about the 1.5 million on the well. So that’s a great savings. And so I think we will continue as we go through the year but as they get more efficient too, as we mentioned, we’ll probably drill extra well two or three that we had budgeted. And if we bring the other rig on, that will cost a little more money too. So I think we were just reluctant to reduce the CapEx budget at this point. It just felt like it was better, just kind of leave it where was.

And underscore what David is saying is that when you bring on a rig in the Permian where you have built more often than not, we’ll have less than 100% because you’ve partners, you got a force pull, you are under joint operating agreement. So it’s not like the Eagle Ford where we had 100% when we bought a rig on, we had 100% of those CapEx. In the Permian, it’s going to vary most of the time between 50% and 75%. There will be a few 100% in the interest wells but bulk of them will be in that range, 50% to 75%. So you make some adjustment on the expected rig cost. Matt?

Yeah. Scott, I just wanted to restate what David has said. And I think it’s an important point for us to think about, we as all operators are enjoying cost reductions from the service companies. That’s a great thing for us. I think the more important thing and the most important thing for us is these operational efficiencies that David is talking about. When you are out there drilling wells and half the time you were four, five months ago, that’s stays with you even when whole process revamp, service company process go up. Those efficiencies are still there and they are probably at least to me more meaningful than in service company cost reduction. So these new rigs that we built brought out there that we put high pressure circulating systems on. That’s allowing us to now daze off these wells in $50,000, $75,000 a day. Those will stick with us. If you think about this time last year that same $50,000 or $75,000 a day was $75,000 to $100,000. Great job for the guys on the operation side.

And to add to that, as we go into full scale development, we are drilling more and more batch wells. We’ve drilled -- the Billy Burt pair was a batch style drilled pair, the current Johnson’s, we’re drilling our batch now. And then we’re going to be drilling more stack wells too where we drilled in batch mode but in this case particularly where we stack several different formation on top of each of other. We’ll drill three of those this year. And so going into batch mode, we are estimating over $500,000 in savings per well. So it’s a big deal moving into development mode for cost cutting as well, which has really nothing to do with service cost reduction. Again, that’s just efficiencies.

Appreciate that all. Thanks guys.

Thank you, Scott. Good questions.

Our next question comes from Neal Dingmann of SunTrust. Your line is now opened.

Good morning, guys. Joe, just wondering, I know you guys look at a lot of factors of how you think about when it comes to adding that third rig in the Permian. Is it cost, is it -- obviously the rebound in oil, is it efficiencies, is it a certain economic number that you are looking for? I am just thinking when you go to add that third one or perhaps bring a rig back in the Eagle Ford how you, Matt, David, Craig and the guys think about this?

Well, I think you did a good job, Neal actually naming the things that we think about is that I don’t know if I have months to add to that. But the way, Matador makes decisions is we are very collaborative and we like to get in as a Group Executive Committee to look at this from different perspective. One, from the operations teams out there and second from Matt and his drilling groups and Billy’s drilling groups and the land situation and with David on, where does this fit into our expected capital expenditure so. It’s all of those things built in, as well as the direction that we think prices are going. And we don’t have any crystal ball but there is just kind of a felling is that it is behind us and that the pricing outlook is better today than it was three months ago. So, we’ve gotten some additional acreage with the HEYCO that we think is in some of the best parts of New Mexico. And we’ve been pleasantly surprised by the number of different zones that have performed so strongly that and you maybe in an area where these stack pays are -- may offer even further savings. So it’s pretty intriguing and we are looking at from different points and we will find it. And I know our geoscience teams have been really working hard to helping to find the zones and seeing what difference some technology can make on them, both from the directional drilling, the permeability, the micro size, the 3D. So they are doing core. It’s just some real good work as you often hear me say it’s not one thing that’s making the difference. It’s just a whole bunch of little things and are some really good execution by our staff. But I thought you did a real good job, Neal, on your questions and I will need help later on but Matt wants to add.

Neal, you’ve heard us talk about pace and I think it’s very important component to this. One of the things that we learned in Eagle Ford that you always improve as you go along and so just what we’ve been talking about the cost reductions and Ryan, I’m sure will elaborate on the completion designs. But our saying is profitable growth at a measured pace. So the thing we didn’t want to do is jump out here in the Permian with a bunch of rigs and drill a bunch of wells, not knowing exactly how to drill and/or complete those wells. So, we feel now that we are moving more in that direction and we are ready to move more into the development phase.

Joe, what about looking at adding an Eagle Ford versus -- I know you have all of this upside in the Delaware, is it more about differentials these days that obviously we think that Delaware appears to be a bit better than generally in the Eagle Ford or how do you think about activity one play versus the other?

Well, we really like the Eagle Ford. It’s not on the differentials. I don’t think that’s a very minor consideration. The main reason out there and the focus on the Permian is that with prices where they were, if we can put everybody on that project then we can get up the learning curve, underscoring what Matt jus said about the right pace is that if you didn’t have the bulk of the technical staff working on that, you’d need to slowdown that pace. We are getting up the learning curve a little faster because of the concentration and it’s very important because if you drill some wells now and then six months you learn a better way to drill or some other technology, you hit your head and say why did we drill those so quickly. So there is that right pace and getting all of our people at one-time gets the focus right. But we are looking, hopefully that circumstances will suggest to be acting again in the Eagle Ford in 2016. So, we are very open to acquiring and are in the process of acquiring some additional acreage there to build up our inventory. We feel we’ve got 250 or so wells to drill over there with welcome deals if some people have expiring acreage that they would like for us to be interested in and then when it’s time to put a fourth rig, we might put it there rather than in the Permian. But the Eagle Ford has been very good in the last wells that we’ve drilled, the Bishop-Brogan line and Billy’s group did a fantastic job. As we have said earlier this year, we drilled -- the last eight wells we drilled, we are budgeted for basically $6 million, we drilled them for $5 million and they come in for twice the rate that we expected. So, we’d be eager to get back here but that acreage is HBP. So there isn’t the time factor on that and it gives us some chance to really focus on New Mexico and try to bring our knowledge there up to the level to that we’ve got in Eagle Ford. Anything else?

Okay. Go ahead. Sorry guys.

I was just going add to what Joe said. We focus so much on our Bishop-Brogan wells in the Eagle Ford because they turned out so well but lost in all of that is we drilled a couple of Martin Ranch well. And I checked the production on those yesterday and they have been averaging 4,500 barrels a day for the last month, flowing at over 2,000 psi and we still have the whole north part of Martin Ranch to develop. So, we’ve got a lot of good locations left there and as Joe said, we are really high on the Eagle Ford still.

And just to add to those Martin Ranch wells, those are 5,000 foot laterals drilled $4 million, $5 million as well.

That’s right.

There is lots of good things to say about a lot of the Eagle Ford in the last six months.

Thanks, guys.

Hey. Thank you, Neal. Good questions. And for all of you listening in, we know there is lot of companies reporting today. I know that you all have a choice, so we really appreciate those of you who are choosing to listen to us and it really means a lot to us and please know that we thank you.

Thank you. And our next question comes from Irene Haas of Wunderlich. Your line is now opened.

Yes. Hey, good morning. I have questions actually pretty much along the same line, I mean certainly to drill a well in the Ranger area for $5.3 million is spectacular. But the Bone Spring doesn’t seem to need a lot of frac. So let's talk about Wolf prospect where you probably have the most history and understanding that you’re still kind of working with various permutations. Can you walk me through sort of your well drilling and development costs as you kind of go through this broad process, and just any trends coming out? I mean understanding that there has been a lot of compression of drilling time as well, just a little more color on maybe using Wolf as an example.

Sure, Irene. This is Ryan again. The wells we drilled at Wolf, one of the last wells we drilled on our Billy Burt, our field estimated costs at this point are well below the range we’ve given there, it’s in the -- field estimated cost is $7.5 million to $8 million range right now on normalized basis. So we are seeing costs come down pretty significantly. And finally, we are starting to get some wells, some full costs reported on some of the wells since we’ve gotten a lot our related service cost reductions. I think our frac cost right now -- our total completion cost is around $400 to $450 per completed lateral foot. And Billy, I will turn it over to you on the costs we have seen on the drilling side.

And how you did it?

Right. Yes, Irene, it’s using these new rigs, the new technology getting out there, and also like was mentioned earlier, the crews getting used to using that new technology and then they are figuring out how to use the 7500 psi pumps that Matt talked about. Those keep from limiting us on our pressure and the BHA components we use, we can use the higher torque down hole motors, we can use the higher pressure down hole motors. We are able to get up and run about 6000 psi instead of what we’re limited to about 4000 psi. And things like that keep us from drilling 800 foot days and get us on out where we were 1500, 2000 foot a day. And that starts cutting days off of the wells and that then you are cutting off $50,000, $60,000, $70,000 a day and that’s a big deal. We are also seeing an improvement on the service cost and all and that’s about half of the savings you’re seeing. And we’re seeing approaching like from the earlier wells, we are saving a couple million dollars now. And now we are down to $1 million and some of the different equipment that we are using here were batch drilling these wells just like we did in the Eagle Ford. And that’s helping us cut a lot of the time off. Along with that, the newer rigs have telescoping flow lines that help us as we move to the next well to get rigged up and get going quicker. We can stop this, okay, we’ve got mud gas separators installed on the rig and these keep us from running up $10,000, $20,000, $30,000 in cost depending on how many wells you have, because it takes a lot of time the rig equipment up and down. You have roustabout crews that have to come in, you have lines, you have to lay. It takes a lot of time and gets in the way of a critical time there. It costs a lot of money to do that. So we went ahead and figured out what’s the separator we’re going to need for the gas we’re going to be seeing and had these rigs custom built for that reason. And also some of the things as you move around the Delaware basin, it can be a little unfriendly and you have water flows, you have losses, you need to drill with pneumatic pressure drilling, you have to run casing under pressure, the wells are trying to talk to you and flow at you and go the other way which leads to the well flowing at you. And as you find the different problems in these different areas and figure out how to manage them. And just that experience it cuts a lot of days off the well and that’s what we are finding and those are a lot of the things we are doing. And like I say, we are cutting off $1 million, $2 million of wells when we started out.

Hey, Billy why don’t you remind everyone how many days it took you to drill your last Wolf well and your last Rustler Breaks well?

Yes. Good point, Ryan. In the Rustle Breaks, we’ve cut down, our goal was 18 days. We drilled down, went down to 13 days. So we really kicked that and we’re already identifying places we can cut down even more days. The Wolf well where we’re targeting getting down from 45 days, our average was to 35 days. We just drilled one down in 20, 30 days. And once again we have already found places we can improve on that as well. So the future is bright.

Irene, this is Matt. I will just -- Billy is talking about all of this stuff and it truly is a number of things. He is talking about the technology on the rig and these high pressure circulating systems and really what that allows us to do is use a lot of different down hole equipment and for example bit. We can run different style bits. And we’ve talked about the bits that we used in the north to drill this [chart] [ph] five days in one single hole section. So the guys they have a lot of more latitude with the bit designs they can use and how hard they can run on these bits and how effective they can make them bit because the number of hours you run on the bit is very relative to how effective that bit is the entire time it’s in the hole. So we got -- we mentioned our two drilling engineers that were bit design engineers once a upon a time and they have been very advantageous for us to get that bit together as well as all the drilling team. So this is really fantastic to go from 43 days to 23 days just in a few months is unbelievable. We talked a lot in the Eagle Ford about taking wells from 18 to 19 days down to eight or nine days. We would look at Billy and we would just tell them we got to do that. And again interesting note is on the most recent well taking about these bits in these rigs we drilled over 2000 lateral in a single day.

Billy and his group, they don’t get the notice because I don’t have the well right what a lot of people pick up, but it is jus phenomenal what Billy and his staff had done and we are all in all around him on some of their work. So we put him on a pedestal around here and we sing for he is a jolly good fellow when they bring him these days like this.

Well, that really sounds great. And congratulations. And wish you continued success in this process. And I was wondering with that much innovation going on and compression of drilling time, are you making actually sort of offsetting the difference in the drop of commodity prices at this point?

Irene, that’s a real good question. And I can’t say because the commodity price had been fixed for very long. It bounced down there to the 40s and now it’s up to the 50s and it’s touched over above 60s. So that’s been too much of a moving target to get real fixed. But the real encouragement, we’re often asked why don’t we just put up all the rigs and not do any drill for a while? Well, you got to stay drilling to stay active in learning about these innovations and experimenting because when you achieve some of these innovations to cut down the time, that’s very sustainable cuts that will stay with you when prices go up and so you got to keep moving ahead. So we can’t equate it on a rough rule of thumb and this is a rule of thumb number Irene is that every dollar you save on the cost side is call like every hundred thousand that you save on the cost side like $3 uplift. We tried to provide some information on that in one of our charts just to show because you deduct cost is a 100% and topline growth with reserves I take out that 25% royalty cost. So we are very proud and as you see back to this statement we say around here just a whole bunch of little things that Billy and his group are doing with Matt, and they have put together -- they take a lot of pride in their work and we just really appreciate what they do.

Okay. Thank you.

Thank you, Irene.

Thank you. And our next question comes from Brian Corales of Howard Weil. Your line is now open.

Good morning. Joe, I think you talked about a stacked development. I am assuming multiple horizons on the same path. Did I hear that correctly? Is that something you’re testing right now?

Yes, Brian.

Could you elaborate maybe in terms of what is that the Wolf area I’m assuming and then what zones you’re testing?

Actually it’s not the Wolf area, it’s Rustler Breaks. But Ryan, is one that’s come up with this with several of our technical advisors and it’s I think pretty exciting. Ryan, do you want to elaborate?

Sure. Brian, where we’re currently doing a stack is in the Rustler Breaks as Joe mentioned on our Tiger lease. We recently drilled the Tiger, Wolfcamp B well. And since that time, we had the rig staple it and drill the Second Bone Spring horizon. The rig just finished up drilling that well and now it’s going to drill in the Wolfcamp X stand. And so in that one location, that one surface location we will have three horizons stacked on top of each other. Now the goals going forward for the rest of the year are to do a couple of more stack tests, one will be in our Jackson trust acreage where we’ll be likely will drill a Delaware and a Second Bone Spring stack. And then back in our Wolf area, we will drill another stack where we will try and integrate another Wolfcamp A, Wolfcamp X and Second Bone Spring test on the stack. And the good thing about these stacks is these rigs are -- like we said before, designed just for this type of operations so we will save quite a bit of money and we’ll be able to prove up the concept of this stack place.

And I’m assuming I guess this is going to -- should it be successful, this is going to be kind of development going forward, is that a fair assumption?

I think so. We’re right now on our Tiger. The Second Bone Spring, we’ve always kind of considered that bird in hand, the Bone Spring in this specific area of Rustler Breaks is very prolific, so we feel very confident in the outcome of that test. And then of course, we recently drilled the Guitar well in Rustler Breaks in the Wolfcamp X stand. And I think everyone is familiar with how that one turned out, but it was over a 1,000 BOE per day and it came in at really strong pressure. So that’s going to be part of our development going forward and that is the target that we have going on right now with the rig at our Tiger location.

Okay. That’s helpful. And then one just final question. So assume the third rig does come in the back half of the year, one will be in development of the Wolf. Can we assume one will be in development of Rustler Breaks with another rig maybe floating around to some of the other prospect areas?

That’s the strategy. Brian, we will have one Wolf in development, one at Rustlers Breaks development and the other one will predominately be in Northern portion of the base in drilling in our Ranger and Arrowhead areas where we just added 18,000 acres of HEYCO property. So it will be up there targeting the Second, Third Bone Spring at horizon.

That’s perfect. Thanks, guys.

Hey, thanks, Brian. Thanks for the question.

Thank you. And our next question comes from Mike Scialla of Stifel. Your line is now open.

Hi. Good morning, guys. Just wanted to follow up on Irene's question. Ryan, you had mentioned in terms of well costs in the Wolf area, you gave the example on a normalized basis I guess $7.5 million to $8 million now for a typical Wolfcamp well. I think in your last presentation you were saying $9 million to $10 million. Can we anticipate that with your next presentation you will update those costs for all of the horizons? And is that kind of the right percentage maybe 15% or so that we should anticipate those well cost numbers will go down for each one of those areas?

Hi, Mike. Yes. I think that is what we’ve been -- we actually have been saying that pointing to the range that we provide in investor presentation and saying that we put those numbers together at the end of the year, at the end of '14 and since that time we’ve seen additional cost reduction. And so I think we’re trying to stay pretty consistent in what we’re telling people that I think 10% to 15% beyond what we’re showing on the low side of the rang is something that we can achieve. We are reluctant to come out and provide a new range just yet because we just got this costing on these wells. As far as the repeatability, we’re confident we can do it, but it’s just going to take a few more wells before we exactly know where every thing is going to found a place.

Mike, this is Matt. One thing to keep in mind particularly at Wolf and in Texas, actually is that a lot of these laterals maybe -- we may have some 4,500 of laterals on some, wells we may have some that are 6,500 or better, so there still will be a range of cost in there that’s not going to be within 2%.

And Mike, just to add some more. As Matt just said, we did just drill those Billy Burt wells, both of them were over 5,000. The 202 was right around 5,800 feet in lateral length and the 203 is over 7,400 in lateral length. So especially in our Wolf A, we’ll have a variety of different lateral links. And so, we try and talk in terms of normalized numbers and that the number I gave was the normalized number.

Got it. Thanks. And I realize you have only drilled 18 wells in the basin so far, but some pretty good success obviously. Looking at the same slides you have got your inventory expectations for each one of these horizons, how has that changed? I guess I am looking at like in particular the third Bone Spring I think your first effort there was one of the few wells that wasn't so hot, that Jim Rolfe well, but now you have followed up with this Cimarron well that seems to be a very nice well. How has your thinking changed in terms of the inventory and maybe could you speak to did you do anything differently like with this Cimarron well in terms of how you completed it or is it more a function of geology?

Mike, I think that’s more a function of geology. Our Jim Rolfe well was we were trying to test the basically the extent of the Third Bone Spring as you move north into the basin. There is very little well control on the north side of that that really constraint where the zero line is for production in that area. We’ve always been very confident with Cimarron was right in the heart of this stable fairway of Third Bone Spring production. I think, we have -- we continue to get a stronger and stronger hand on exactly where these Bone Spring wells are going to be productive whether or not. As we’ve mentioned before, there are much more geologically controlled and so much more surgical in nature. But no, there was no difference in the completion really on the two wells. What we think is -- what we think matters, we basically fix that number on the volume of proppant per fracture when we show you how much of sand we pumped it, it is going to look a little difficult because we changed the spacing on the clusters. This is generation two design in the Cimarron whereas the Jim Rolfe was generation one. But we really feel like that was much more geologically controlled than frac controlled. We feel like both the frac should have done an adequate job of generating a really good well. I think just the Jim Rolfe was out of the fairway.

Mike, the Jim Rolfe was important too as part of the delineation process brand in particular has been played that, although it came on low right, it stayed pretty steady and we were also encouraged, it help setup some drilling towards our Twin Lakes area. Brad, you want to elaborate.

Yeah. Thank you, Joe. Of course, that area, we’ve been testing the lower Wolfcamp and that was actually a well that we had targeted for the Wolfcamp and we were drilling down to the Third Bone Springs and we saw some real good indications of hydrocarbon. So we decided to test the Third Bone Springs, as Ryan said, got to push the northern end of that fairway. But we’re really were excited about the Wolfcamp and the potential we saw there and how that extrapolates up into out Twin Lakes acreage. This was the northern most test -- this area the Wolfcamp, they show that its gio pressure there and which we -- we knew it was in the southern part of the banks and now we’ve tested it all the way up into the Ranger area and we believe that will extend up into the Twin Lakes acreage when we get ready to test the Wolfcamp D up in that area. So we are really encouraged by that area. We -- the well actually produced quite a bit of oil early on. We haven’t exactly found the best way to start officially lift that well, but our production department is evaluating that now.

Okay. And then in terms of I just kind of snuck two questions in one, I guess, but your thoughts on the drilling inventory? It sounds like from everything you said that's probably expanding from what you’ve presented thus far?

In terms of the third Bone Spring nothing is going to change in our Ranger area. All the Wolf’s that we would consider prospective up there, we still think that we have the inventory number correct. Down in our Wolf area and Rustler Breaks number, we are still yet to test the Third Bone Spring and how it relates to any of our Wolfcamp X and Y and A targets, that’s where we’ll -- the inventory could grow overtime, as we understand spacing a little bit more in the Rustler Breaks and the Wolf area.

And Mike, this is David. Hi. Just to mention, the numbers that we had put out were prior to having then the HEYCO acquisition. So our teams are working very actively right now to see how many locations we may have on that acreage, of course, we have an idea with the acquisition. But they are going back and doing a more consistent evaluation of that acreage the way we’ve done all of ours to determine the number of locations. And so I think that certainly is going to expand that number and that's probably some will be coming out with by midyear or so.

Okay. That's helpful. Thank you, guys.

Thanks Mike.

Thank you. Our next question comes from Jeff Grampp of Northland Capital Markets. Your line is now opened.

Good morning, guys.

Hi Jeff.

Hey Jeff.

Just another question on the inventory side of things, we’ve been seeing some pretty encouraging things from some other Delaware operators regarding potential multiple landing zones within a single Bone Spring zone? I know you guys had some success in that regard on the Wolfcamp side of things, but wondering, if you see a similar upside on multi-bench, I guess, prospectivity within a single Bone Spring zone on your acreage?

Hi, Jeff. It’s David. And actually -- we’ve actually done that on our Ranger payer. We have the original Ranger 33 which was completed in an upper bench of the Second Bone Spring. And then we’ve just recently drilled a second well that is completed in a lower bench of the -- of that same Second Bone Spring. Those wells are essentially offsetting each other and we still -- we didn’t -- we hadn’t -- had a chance to get that well flowed back in us to release the results on it. But just to say that, I think, its performing very similar so far to what our initial Second Bone Spring well did there in the Ranger 33. We decided to put it on gas lift earlier. You may remember that that one took us probably 60 days to really get cleaned up after the fracture treatment to begin with and they really started to pop once we put it on gas lift. So we begin that earlier here like we had done on the Pickard wells to the north and so far the well seems to be responding well to that. And I would say it’s kind of tracking above where the original Ranger well was. So hopefully, we can release the results of that in a subsequent operations update. But just to point out that is one place where we've already looked at that and tried testing in it. I don’t know, Matt, if you have something, you wanted to add there?

Yeah. I think, we are definitely exploring the option of multiple landing zones within a single Bone Spring target. And I think David accurately appraise the Ranger test that’s really, really kind of a first step to that. But we’ll continue looking at that in the future. And I think as we keep going and keep collecting data with each well we drilled, we’ll get a better understanding of it and I think you will see some refinement when the program was done.

That speaker was Ned Frost and this is Ned’s first press conference. Ned is the one of the team leaders for the Permian. He is a PSC geologist from University of Texas and he has worked very closely with Josh Sudderth, the other team leader and Ryan and helped to identify these 10 producing horizons. And we feel his work and the work of his group has contributed mightily to the good results that we are getting out there. So. Ned, thank you very much and welcome. And after today the analysts don’t have to be nice to you on the questions. They can ask them as tough as they want now that you are experienced.

It is just today we ask the nice ones. I guess just one follow-up on the leasing side of things both, I guess in the Permian and Eagle Ford and maybe in the Haynesville opportunities there, what’s kind of the leasing landscape like today and is that something where you guys are still continuing to bolt on across your various areas?

Jeff, the simple answer is yes. We really opened all opportunities in all of those areas and would really appreciate doing bolt-on opportunities or other, because we think all three are great areas. The Haynesville wells are coming in 9 billion to 10 billion cubic feet per well. They put them on-line. They stay there. The costs have continued to improve. We still like that area very much. Eagle ford, I’ve already mentioned that and in the Permian and other areas, Van Singleton our Head of Land is here. Van, what do you see?

Joe, I think the point I would make is that we are seeing -- even though we're seeing a lot of good results in certain areas, we are seeing prices maintain a steady hold within a range that we’ve seen for some time. And we are still seeing a good amount of deal flow that really hasn’t dried up. And we are continuing to see good opportunities that are bolt-on through acreage that we currently have which just add to the operational efficiencies that Billy and Ryan and Matt were talking about earlier. So, so far so good and we are keeping our ear to the ground for more opportunities and certainly, anyone on the call that might know of something, please let us know.

All right. Perfect. Great color, guys. Thanks.

Hey. Thanks, Jeff.

Thank you. And our next question comes from Ben Wyatt of Stephens. Your line is now opened.

Hey. Good morning guys.

Hey Ben.

Guys just maybe one quick question on just your philosophy around the way you manage chokes out in the Permian. Maybe if you can just touch on how those differ if they do from prospect to prospect, is that something you guys have really dialed into or is it something you are still tweaking and maybe how that can affect maybe the shape of the curve or even EURs as you do tweak your chokes?

Hey Ben. This is Ryan. It’s a good question. I am glad you ask, because I think we are lot more conservative in how we manage our chokes than a lot of the other operators in the neighbourhood. You'll see a lot of choke sizes in the mid to high 30s as you look at some of the IPs and at the long-term test in the basin. But we’ve taken similar approach that we’ve had in the Eagle Ford where we really believe in trying to manage one whole pressure. Right now, our practice is to move to a 24 and a 26 size choke, that is basically what -- where we get that number from is really looking at a surface flowing pressure and understanding the pressure or the stress that’s being applied to the proppant down hole for each area. The stress in the Permian basin is much lower than it is in Eagle ford, so we can get away with a little higher choke size here. The Bone Springs is mostly a 0.7 and the Wolfcamp is typically at 0.8, which when you multiply that by the two vertical depth you get a number that is within the crush limits of the white sand. So, we feel good that the 24 and 26 is the appropriate for a first step that. We do feel like this is going to evolve overtime. Once we get significant long-term production data, which we are starting to get, we can evolve our choke management and I think you’ll see that. We’ve already been taking a look at some of the long-term production of the wells and we’re seeing that maybe one turn less is the right number. So, I think that there is some room for improvement just on our practices for choke management.

Very good. Thanks, Ryan. And one more housekeeping.

Ben, before you get to the next one, Brad waving his hand. He would like to add something.

Okay. Ben, I’m sorry. I should have spoke up a minute sooner but I just wanted to add to what Ryan was saying because, we really think we are seeing an improvement in our reserves and the results of this choke management program. The wells while maybe starting out, we are holding them at little lower absolute flow rate, oil rate, and gas rate. They do -- I think part of your question was the decline rate. They decline slower. So overall in the first year or two, actually recovering more oil, more gas. We know it’s improving our rate of return and we are seeing anywhere, I think from 10% to 15% increase in reserves, maybe even higher than that in some areas. So it is clearly a correlation between well performance and our choke management program. So it is having an impact on the bottom line.

Trent, do you have anything to add. Trent Green in Roswell?

No. I think the topic has been covered quite well on our choke management and our productivity. I’ll agree with Brad from a reserves perspective. We’re seeing a longer life and a lower decline on these wells. So compared to our competitors and offsets out there, I think we are doing a better job, yes sir.

Trent is head of production. Ben? I’m sorry to interrupt you but just wanted to complete that.

You bet. I appreciate all that, guys. And then maybe just one more and sorry if you guys addressed this earlier. I missed the first part of the call but LOE in 1Q was better than expected and you guys gave a laundry list of why that was a lower number. But just curious going forward should we see that migrate maybe back towards kind of the $7.25 per BOE number you guys have guided to or are there enough good things happening where LOE stays lower than you guys initially thought?

Yeah. Hi, Ben, it is David. First of all thank you for asking that question and noticing it because I think you’ll something that we were particularly pleased about in this quarter. I usually say one quarter doesn’t a trend make. So I think we’re going to watch it. If it takes back up a little bit, it might not surprise me. But that said, I think the most of the things that we pointed out, in terms of just some improvements that we’ve made, service cost being a little better, little higher, gas mix with some of the Haynesville wells that have very low operating cost and the fact, that we did have in the past year particularly there were a number of time where we would frac and offset Eagle Ford well. And perhaps I have to do some kind of clean out or clean up of the offsetting well that we’re not doing right now. So for all those reason, I’m optimistic, that’s going to hang in there. But again I will be happy, if we hit our 7.25 goal for the year so. But I’ll be even better if we can keep it down in the 6.25 below obviously.

Ben, one of the things that we try to keep in perspective on the cost savings and we’re really pleased that we were getting reductions in all our categories for our unit cost production with the exception of G&A. But good part of that was non-cash related to compensation, stock-based compensation with the rise in the price of our stock, that naturally went up and that’s a high-class problem. And the other part was about the dollar per unit was related to the non-recurring due diligence on the HEYCO transaction. So I think on an overall basis, we will continue to -- we expect and plan and how to continue to improve for the remainder of the year. On a total basis, this is very important because we have determined that $1 million costs saving on the wells equals roughly or approximate and increase in the rate of return of 15% to 20% or in the alternative of the equivalent of $6 to $7 rise in the oil price. So these numbers are important. You are not going to build the company just with cost saving. But they should be balanced with the topline growth that Ryan and his group are achieving.

Very good. Guys, I appreciate the time and keep up the good work.

Well, thanks, Ben. We appreciate it and appreciate your kind remarks to the Dallas Business Journal.

You bet. Thanks.

Thank you. Ladies and gentlemen, this ends the Q&A portion of this morning’s conference call. I would like to turn the call over back to management for any closing remarks.

Thank you, Operator. Thank you everybody for their interest. The questions, I thought were very thoughtful and we appreciate them and everybody’s participation. The group here is working hard on in all phases. I think we’re making progress, still a lot of work to do, always room for improvement. We have our challenges ahead of us but we feel good about the plans and progress, and we like our chances going forward. So if there is any follow-up, please let us know. We’re always available to you and really appreciate your support and interest. And thanks again to the staff because these result didn’t happen. There has been a lot of individual effort and extra effort. And on behalf of everybody on the operating committee, we’d really like to thank all that extra effort in recognize it. Good job group. Thank you.

Thank you. Ladies and gentlemen, thank you for your participation in today’s call. This does conclude today’s program. You may all disconnect. Everyone have a wonderful day.