Matador Resources Co (MTDR) 2015 Q1 法說會逐字稿

Good morning, ladies and gentlemen, and welcome to the first-quarter 2015 Matador Resources Company's earnings conference call. My name is Sami and I will be serving as the operator for today. (Operator Instructions). 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 may be 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 to 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 in answering them I'm going to call upon at various times senior members of our operating staff who have joined me for 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, the Executive Vice President of Land and Legal; Ryan London, the 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 then in 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 stressing the balance sheet and we have maintained our net debt to trailing 12 month adjusted EBITDA so that it has never exceeded 1.8; it is currently 1.2.

Second is our production continues to meet or exceed our expectations and for the first time in our history, we produced more than 2 million BOEs in a single quarter recording production of 2.1 BOEs this quarter.

And our most recent wells continue to please us very much, not only from a volume and production point of view but also in the cost reductions that have been achieved by vendors working with us as well as the operating efficiencies that our staff has been achieving.

The third thing is just what I mentioned on operating costs, 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 wanted to note those as well as mention our progress we are continuing to make on midstream.

And with that, I am pleased to announce that we have 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 would guide you to the more likely to be to the higher end of that production range.

So with that, let me turn to the operator and start taking the calls.

(Operator Instructions). Scott Hanold, RBC Capital Markets.

Thanks. Good morning. 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 as 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 a sense?

Ryan, would you take this please?

Sure, Joe. Scott, what we think in terms of development 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 which we've spent a lot of time developing so far and how it relates with the Wolfcamp A and the third Bone Spring. Like we have said before we're trying to optimize the development program there. Certainly the program you will see over the next two or three years there will focus on those horizons.

We do have Bone Springs and there are some upper Bone Spring formations that we will want to test but those will be independent of those so our primary focused down there will be the patterns pertaining to the Wolfcamp.

When you move to Rustler Breaks, I think it is a 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 sand up there and the third Bone Spring. And of course, we will be picketing off specific second Bone Spring and 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 first and second Bone Spring. We will be looking at some other targets like Avalon and Brushy Canyons. I think most of those will be much more surgical in nature in how we approach those. Does that answer your question, Scott?

Yes.

Scott, I would add, Ryan, as we were talking in preparation we drilled what, 18 wells out there?

18 total wells and of those 18 wells, we have 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 the development programs toward some of those deeper horizons, specifically the Wolfcamp.

So, Scott, you are going to 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 question is a really good one.

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

One other thing, Scott, part of the effort as you know us is that we are trying to decide now what we believe is the most likely and optimal spacing so some of the tests that we are doing is to test what might be the most efficient spacing patterns before going into full development.

The other thing is the engineering and the geology has been working very closely across discipline to determine the good, better, best of these zones and including to see the effects of using micro-seismic to help evaluate results with regards to some of the fracking as well as 3D seismic in picking some of the locations. So there's a lot of good work there.

We are kind of I would say past the exploratory, we are getting to the end of I think the delineation and in certain parts it is going to be ready for development, more intensive development by the end of the year including at least one place where we are doing a stack well with three different horizons.

One more thing, Scott, on the purpose of that strategy focused on the deeper horizons is something we learned in the Eagle Ford that if we go in when we drill a well we have a much better outcome on the program if we go in and we offset that will 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 of those horizons, we want to focus on the deeper horizons.

It is just something we have learned in the Eagle Ford and also in the Haynesville I think a lot of other operators feel the same way. It is 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. 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 is a low number. Can you give us a little color there?

Yes, hi, Scott. It is 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 forecasts 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 releases 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 these wells. I believe we mentioned in the release the last will they drilled at the Wolf area was 23 days from spud to TD compared to a little over 40 is what we had been averaging. And that is even better than the goals that we had set and budgeted going into the year.

So I mean they deserve a lot of credit for how quickly they are beginning to improve and how much progress they are making in getting our drilling times down and that has a big impact. If you save 20 days on something that may be $75,000 a day spread rate you are talking about $1.5 million on a well so that is great savings.

And so I think we are doing well, Scott, so far and I think that will continue as we go through the year. But as they get more efficient too as we mentioned, we will probably drill an extra well or two or three that we hadn't 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 to just leave it where it was.

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

Scott, I just wanted to restate what David had said and I think it is an important point for us to think about. As all operators are enjoying cost reductions from the service companies, that is 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 wills in half the time you were four or five months ago, that stays with you even when oil prices rebound, service company prices go up, those efficiencies are still there. And they are probably at least to me more meaningful than the service company cost reductions.

So these new rigs that we have built brought out there that we put the high-pressure circulating systems on, that is allowing us to knock days off of these wells and at $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 today was $75,000, $100,000. Great job for the guys on the operations side.

To add to that as we go into full-scale development, we are drilling more and more batch wells. We have drilled -- the Billy Burt pair was a batch style drilled pair, the current Johnson's we are drilling are batch style and then we are going to be drilling more stack wells to where we drill in batch mode but in this case vertically where we stack several different formations on top of each other. We will drill three of those this year.

And so going into batch mode, we are estimating over $500,000 in savings per well so it is a big deal moving into development mode for cost-cutting as well which has really nothing to do with service cost reductions, again that is just efficiencies.

I appreciate that all. Thanks, guys.

Neal Dingmann, SunTrust.

Good morning, guys. Joe, 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 they 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?

I think you did a good job Neal actually naming the things that we think about. I don't know if I have much to add to that but the way Matador makes decisions is we are very collaborative and we like to get in as a group, an executive committee, to look at this from different perspectives. One from the operations teams out there and second from Matt and his drilling groups and the Billy's drilling groups and the land situation and with David on where does this fit into our expected capital expenditures.

So it is 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 feeling is that the worst is behind us and that the pricing outlook is better today than it was three months ago. So we have gotten some additional acreage with HEYCO that we think is in some of the best parts of Mexico and we have been pleasantly surprised by the number of different zones that have performed so strongly that --. And you may be in an area where the stack pays are -- may offer even further savings. So it is pretty intriguing and we are looking at from different points and refining it and I know our [GS science] teams have been really working hard to help and define the zones and seeing what difference some technology can make on them both from directional drilling, the permit building, the micro size, the 3D. So they are doing core. It is just some real good work. As you often hear me say it is not one thing that is making the difference, it is just a whole bunch of little things and there is some really good execution by our staff.

But I thought you did a real good job, Neal, on your question and I will need help later on but Matt wanted to add.

Neal, you have heard us talk about pace and I think that is a very important component to this. One of the things that we learned in the Eagle Ford that you always improve as you go along and so just what we have been talking about the cost reductions and Ryan I am 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 the 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?

We really like the Eagle Ford. It is not on the differentials. I don't think -- that's is a very minor consideration. The main reason out there and the focus on the Permian is that with prices where they were we can put everybody on that project and we can get up the learning curve underscoring what Matt just said about the right pace is. That if you didn't have the bulk of the technical staff working on that, you would need to slow down that pace. We are getting up the learning curve a little faster because of the concentration and it is very important because if you drill some wells now and then in six months you learn better way to drill them 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 active again in the Eagle Ford in 2016. 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 have got 250 or so wells to drill over there. We'd welcome deals if some people have expiring acreage that they would like for us to be interested in and then when it is time to put a fourth rig, we might put it there rather than in the Permian.

But the Eagle Ford has been very good and the last wells that we drilled, the Bishop-Brogan line in Billy's group did a fantastic job. As we have said earlier this year, we drilled the last eight wells we drilled were budgeted for basically $6 million, we drilled them for $5 million and they have come in for twice the rate that we expected.

So we would be eager to get back there but that acreage is HBP so there isn't the time factor on that and that gives us a chance to really focus on New Mexico and try to bring our knowledge there up to the level that we have got in Eagle Ford. Anything else?

Go ahead. Sorry, guys.

I was just going to add to what Joe said. We focus so much on our Bishop-Brogan wells and the Eagle Ford because they turned out so well but lost in all of that is we drilled a couple of Martin Ranch wells and I checked the production on those yesterday and they have been averaging 4500 barrels a day for the last month, flowing at over 2000 psi and we still have the whole north part of Martin Ranch to develop. So we have 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 5000 foot laterals drilled four $5 million a well so there's lots of good things to say about a lot of the Eagle Ford in the last six months.

Thanks, guys.

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

Irene Haas, Wunderlich.

Good morning. I have questions actually pretty much along the same line, 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 are 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? 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.

This is Ryan again. The wells that we drilled at Wolf, one of the last wells that we drilled on our Billy Burt, our field estimated cost at this point are well below the range we have given. It is in the field estimated costs is in the $7.5 million to $8 million range right now on a 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 have gotten a lot of our related service cost reductions. I think our frac costs right now or 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, right. Yes, Irene, it is 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 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 we were limited to about 4000 psi and things like that keep us from drilling 800 foot days and get us on out where we are 1500, 2000 feet a day.

And that starts cutting days off of the wells and then you are cutting off $50,000, $60,000, $70,000, dollars a day and that is a big deal. We are also seeing improvements in the service costs and all and that is about half of the savings we are seeing in we are seeing approaching 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 we are batch drilling these wells just like we did in the Eagle Ford and that is 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 stump test (inaudible), we have got mud gas separators installed on the rig and these keep us from running up $10,000, $20,000 $30,000 in costs depending on how many wells you have because it takes a lot of time to 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 the critical time there. It costs a lot of money to do that.

So we went ahead and figured out what size separators we were going to need for the gas we were 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 if 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 or 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 cuts a lot of days off of the well and that is what we are finding. Those are a lot of the things that we are doing. Like I say, we are cutting off $1 million, $2 million a well from where 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?

Good point, Ryan. In the Rustler Breaks, we've cut down -- our goal was 18 days, we drilled that one down in 13 days so we really kicked that and we are already identifying places we cut down even more days. The Wolf well where we were targeting getting down from 45 days where our average was to 35 days, we just drilled one down in 23 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. When Billy is talking about all of this stuff, 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 downhole equipment. And for example bits, we can run different style bits and we've talked about the bits that we used in the north to drill this (inaudible) where could save five days in one single hole section.

So the guys have a lot 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 be because the number of hours you run on a bit is very relative to how effective that bit is the entire time it is in the hole.

So we have mentioned our two drill engineers that were bit design engineers once upon a time and they have been very advantageous for us to get that put together as well as all the drilling team. It is just 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 or 19 days down to eight or nine days. We would look at Billy and we would just tell him we have got to do that and they are getting it done.

I think also one other interesting note is on the most recent well talking about these bits in these rigs we drilled over 2000 lateral feet in one day if I'm not mistaken.

Billy and his group -- they don't get the notice because they don't have the well rates. The well rates is what a lot of people pick up but it is just phenomenal what Billy and his staff have done and we are all in awe 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 in these dates like this.

That really sounds great and congratulations and wish you continued success in this process.

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?

You know, Irene, that is a real good question and I can't say because the commodity price hasn't been fixed for very long. It bounced down there to the 40s and now it is up to the 50s and it has touched over above 60 so that has been too much of a moving target to get real fixed. But the real encouragement, we are often asked why don't we just put up all the rigs and not do any drilling for a while? Well you've got to stay drilling to stay active and learning about these innovations and experimenting because when you achieve some of these innovations and cut down the time, that is very sustainable cuts that will stay with you when prices go up. And so you've 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 kind of like every hundred thousand that you save on the cost side is like a $3 uplift. We tried to provide some information on that in one of our charts just to show because you deduct the cost is 100% and topline growth with reserves they take out that 25% royalty cost. So we are very proud and as you see back to this we 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.

Thank you.

Brian Corales, Howard Weil.

Joe, I think you talked about stacked development, I am assuming multiple horizons on the same pad. Did I hear that correctly? Is that something you are testing right now?

Yes, Brian.

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

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

Sure. Where we are currently doing a stack is in the Rustler Breaks as Joe mentioned on our Tiger lease. We recently drilled a Tiger Wolfcamp B well and since that time, we had the rig stay put and drill a second Bone Spring horizon. The rig just finished up drilling that well and now it is going to drill in the Wolfcamp X sand. And so in that one location that one surface location we will have three horizons stacked on top of one another.

Now the goal is 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 will 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.

The good thing about these stacks is these rigs are like we said before, designed just for this type of operation so we will save quite a bit of money and we will be able to prove up the concept of these stack plays.

And I am 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. Right now on our Tiger, the second Bone Spring we have always 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 sand and I think everyone is familiar with how that one turned out but it was over 1000 BOE per day and it came in at really strong pressure. So that is going to be part of our development going forward. That is the target that we have going on right now with the rig at our target location.

Okay, that is helpful. Just one final question. So assume a third rig does come in the back half of the year one will be in development in the Wolf, can we assume one will be in development at Rustler Breaks with another rig maybe floating around to some of the other prospect areas?

That is the strategy, Brian. We will have one in the Wolf in development, one in Rustler Breaks in development and the other one will predominantly be in the northern portion of the basin 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 and third Bone Spring horizons.

That is perfect. Thanks, guys.

Mike Scialla, Stifel.

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?

I think that is what we have basically been saying that pointing to the range that we provide investor presentation saying that we put those numbers together at the end of the year, at the end of 2014 and since that time we have seen additional cost reductions. And so I think we are trying to stay pretty consistent in what we are telling people that I think 10% to 15% and beyond what we are showing on the low side of that range is something that we can achieve. We are reluctant to come out and provide a new range just yet because we just got these costs in on these wells. As far as repeatability, we are confident we can do it but it is just going to take a few more wells before we exactly know where everything is what you fall into 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 -- we may have some 4500 foot laterals on some wells, we may have some that are 6500 or better so there still will be a range of costs in there that is not going to be within 2%.

Mike, just to add to more what Matt just said, we did just drill those Billy Burt wells, both of them were over 5000. The 202 was right around 5800 feet in lateral length and the 203 was over 7400 in lateral length. So especially in our Wolf area, we will have a variety of different lateral lengths and so we try and talk in terms of normalized numbers and the number I gave was the normalized number.

Got it, thanks. 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?

I think that is more a function of geology. Our Jim Rolfe well was we were trying to test basically the extent of the third Bone Spring as you move north into the basin. There is very little well control in the north side of that that really constrains where the zero line is for production in that area. We have always been very confident that Cimarron was right in the heart of the stable fairway of third Bone Spring production.

I think we continue to get a stronger and stronger hand on exactly where these Bone Spring wells are going to be productive and where they are not. As we have mentioned before, they 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 matters we have basically fixed that number on the volume of proppant per fracture when we show you how much sand we have [haunted], it is going to look a little different because we have changed up the spacing on the clusters. This is a generation 2 design in the Cimarron whereas the Jim Rolfe was a generation 1 but we really feel like it was much more geologically controlled than frac controlled. We feel like both the fracs should have done an adequate job of generating the 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. Brad in particular has been pleased although it came on low rate, it stay pretty steady and we were also encouraged and it helped set up some drilling towards our Twin Lakes area. Brad, do you want to elaborate?

Yes, thank you, Joe. Of course that area we have been testing the lower Wolfcamp and that was actually a well that we had targeted for the Wolfcamp when we were drilling down through the third Bone Springs and we saw some real good indications of hydrocarbon so we decided to test the third Bone Springs area as Ryan said to try to push the northern end of that fairway. But we are really excited about the Wolfcamp any potential we saw there and how that extrapolates up into our Twin Lakes acreage. This was the northernmost test, this area of the Wolfcamp has showed that its geo pressure there which we knew it was in the southern part of the basin and now we have tested it all of the way up into our Ranger area and we believe that will extend up into the Twin Lakes acreage when we get ready to test the Wolfcamp B up in that area.

So we are really encouraged by that area. The well has actually produced quite a bit of oil early on. We haven't exactly found the best way to artificially lift that well but our production department is evaluating that now.

Okay. I kind of snuck two questions into one but your thoughts on the drilling inventory, it sounds like from everything you have said it is probably expanding from what you have presented thus far.

In terms of the third Bone Spring, nothing is going to change in our Ranger area. All the wells that we have considered 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 is where the inventory could grow over time as we understand spacing a little bit more in the Rustler Breaks and in the Wolf area.

And Mike, this is David. Just to mention the numbers that we had put out were prior to having done 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 have done all of ours to determine the number of locations. And so I think that is certainly going to expand that number and that is probably something we will be coming out with by midyear.

Okay, that is helpful. Thank you, guys.

Jeff Grampp, Northland Capital Markets.

Good morning, guys. Just another question on the inventory side of things, 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 have 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?

Jeff, it is David. Actually we have actually done that on our Ranger pair. We had the original Ranger 33 which was completed in an upper bench of the second Bone Spring and then we have just recently drilled a second well that is completed in a lower bench of that same second Bone Spring. Those wells are essentially offsetting each other and we haven't had a chance to get that well flowed back enough to release the results on it but just to say that I think it is performing very similar so far to what our initial second Bone Spring 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 it really started to pop once we put it on gas lift. So we began that earlier here like we have done on the Pickard well to the north and so far the well seems to be responding well to that and I would say it is 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 have already looked at that in tried to testing it. I don't know, Ned, do you have something you wanted to add there?

Yes, I think we are definitely exploring the option of multiple landing zones within a single Bone Spring target. And I think David accurately appraised the Ranger test as really kind of a first step to that. But we will continue looking at that in the future and I think as we keep going and keep collecting data with each well we drill, we will get a better understanding of this and I think you will see some refinements in the program with time.

That speaker was Ned Frost and this is Ned's first press conference. Ned is one of the team leaders for the Permian. He is a PhD geologist from the University of Texas and he has worked very closely with Josh Sudderth, the other team leader and Ryan in helping 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 in the Permian and Eagle Ford and maybe in the Haynesville opportunities there, what is 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 are really open to all opportunities in all of those areas and we'd really appreciate doing bolt-on opportunities or other because we think all three are great areas. The Haynesville wells are coming in 9 billion, 10 billion cubic feet per well. They put them online, they stayed there, the costs have continued to improve. We still like that area very much. Eagle Ford, I have already mention that and in the Permian and other areas, Van Singleton, our Head of Land is here. Van, what are you seeing?

Joe, I think the point I would make is that we are seeing even though we are seeing a lot of good results in certain areas, we are seeing prices maintain a steady hold within a range that we have 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 to 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.

Perfect. Great color, guys. Thanks.

Ben Wyatt, Stephens.

Good morning, 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 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?

Ben, this is Ryan. That is a good question, I am glad you asked because I think we are more conservative in how we manage our chokes than a lot of the other operators in the neighborhood. You will see a lot of choke sizes in the mid- to high 30s as you look at some of the IPs and the long-term tests in the basin. But we have taken the similar approach that we had in the Eagle Ford where we really believe in trying to manage [downhole] pressure. Right now our practice is to move to a 24 and a 26 size choke. That is basically where we get that number from is really looking at the surface flowing pressure and understanding the pressure or the stress that is being applied to the proppant downhole for each area. The stress in the Permian basin is much lower than it is in the Eagle Ford so we can get away with a little higher choke size here.

The Bone Spring is mostly a 0.7 and the Wolfcamp is typically a 0.8 which when you multiply that by the true vertical depth you get a number that is within the crush limits of the white sand. So we feel good that the 24 and the 26 is appropriate for a first step. We do feel like this is going to evolve over time. Once we get a significant long-term production data which we are starting to get, we can evolve our choke management and I think you will see that.

We have already been taking a look at some of the long-term production of the wells and we are 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. One more housekeeping.

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

Ben, I am 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 as a result of this choke management program. The wells, while maybe starting out we are holding them at a little lower absolute flow rate, oil rate and gas rate, they do tend -- I think part of your question was the decline rate. They decline slower and so overall in the first year or two, we are actually recovering for oil a little more gas. We know it is 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 there is clearly a correlation between well performance and our choke management program. So it is having an impact on our bottom line.

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

No, I think the topics have been covered quite well on our choke management and our productivity. I will agree with Brad from a reserves perspective. We are 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 but I just wanted to complete that.

You bet. I appreciate all of 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 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?

Ben, it is David. First of all, thank you for asking that question and noticing it because I think it was something that we were particularly pleased about in this quarter. You know, I usually say one quarter doesn't a trend make. So I think we are going to watch it and if it ticks back up a little bit it might not surprise me. But that said, I think that most of the things that we pointed out in terms of just some improvements that we have made, service costs being a little better, a little higher gas mix with some of the Haynesville wells that have very low operating costs and the fact that we did have in the past year particularly, there were a number of times where we would frac an offset Eagle Ford well and perhaps have to do some kind of clean out or clean up of an offsetting well that we are not doing right now.

So for all of those reasons, I am optimistic that that is going to hang in there. But again, I will be happy if we hit our 7.25 goal for the year but it will be even better if we can keep it down into the 6.25 and below obviously.

Ben, one of the things that we try to keep in perspective on the cost savings and we are really pleased that we were getting reductions in all of our categories for our unit cost production with the exception of G&A, but a 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 is a high-class problem. And the other part was about $1 per unit was related to the nonrecurring due diligence on the HEYCO transaction.

So I think on an overall basis, we will continue to -- we expect and plan and hope to continue to improve for the remainder of the year.

On a total basis, this is very important because we have determined that a $1 million cost savings on the wells equals roughly or approximates an increase in the rate of return of 15% to 20% or in the alternative the equivalent of a $6 or $7 rise in the oil price. So these numbers are important. You are not going to build a company just with cost savings 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.

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 appreciated them and everybody's participation. The group here is working hard in all phases. I think we are 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 are always available to you and really appreciate your support and, interest, and thanks again to the staff because these results didn't happen, there has been a lot of individual effort and extra effort and on behalf of everybody on the operating committee, would really like to thank all that extra effort and recognize it. Good job, group.

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.