Good morning, ladies and gentlemen, and welcome to the Second Quarter 2013 Matador Resources Company Earnings Conference Call. My name is Clinton and I will be your 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 this conference. (Operator Instructions) As a reminder, this conference is being recorded for replay purposes, and the replay will be available through Friday, August 30, 2013, as discussed and described in the Company’s earnings release issued yesterday. 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 with the comparable financial measures calculated in accordance with GAAP are contained at the end of the Company’s earnings release. As a reminder, certain statements included in the morning’s presentation maybe forward-looking and reflect the company’s current expectations or forecast, 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. It's most recent annual report for 10-K and any subsequent reports on Form 10-Q. Thank you, sir. I would like to turn the call over to Joe Foran, Chairman, President and CEO. You may now proceed.

Thank you, operator and good morning to everyone on the line and thank you for participating on our second quarter 2013 earnings conference call. We appreciate your time and interest very much. The second quarter of 2013 was a good one for us and this year it's coming together very nicely for us in many ways. First, I want to begin by emphasizing the importance of our Eagle Ford drilling program to these favorable results and distress our encouragement not only at the continued progress we're experiencing with our frac decisions, our drilling times and our production technique, but also to mentioned our encouragement at the early result from down spacing from 80 acres to 40 to 50 acres on a couple of our leases. Our staff and our Board have worked very hard together studying the Eagle Ford and have done solid work to consistently finding ways to drill better wells in this area for less money. As a result, the Eagle Ford continues to be the heart of our operations, 80% of our capital is being invested here and virtually all of our present oil production comes from the Eagle Ford. As such the Eagle Ford will continue to be the primary engine for our growth going forward for the immediate term. Second I would like to highlight some of our financial results of the second quarter of 2013, but one thing I just want to call your attention in our results when we talk about down-spacing on those results those are given in terms of barrels of oil and not BOE and just so there is no confusion I wanted to be sure the point that out. Also that for your record that’s 90% oil or better and these are fairly short laterals about 4,000 feet, and…

Thank you. Ladies and gentlemen, due to the time constraint, we ask that you limit yourself to one question and one follow-up. (Operator Instructions) The first question comes from the line of Neal Dingmann of SunTrust. Please go ahead.

First question, just, obviously the Eagle Ford that you guys have been highly successful and I look at and you certainly now with the facility have a great liquidity position, just wanted your thoughts about considering in the second rig and increasing the activity anytime soon in the Eagle Ford or you will maintain the pace for a while?

Thanks, Neal. We're returning to two rigs in the Eagle Ford but I think it's important to note that we're drilling these wells considerably faster and the rig that’s coming back is in advanced rig that’s going to help us drill them a little bit faster and I would like to for some detail and color on this turns our Head of Drilling, Billy Goodwin and Billy, just give him a little feeling on, I am impressed with the new features of this rig.

Thank you. As Joe mentioned, we're picking up 1,500 horse power rig to surface drill at Eagle Ford wells. This is going to be a walking rig. So we're really excited about that because we expect that to lower cost and additional 10% for drilling these wells. We expect to achieve this through drilling the wells faster by moving the rigs quicker and also improve drilling efficiencies. We’ll be able to drill the wells of that without laying down drill path and change in our [DHA] components and this will allow us to batch drill our surface [levels] and our production levels and this will save us time and money with equipment, service and transportation cost. And as we move forward, we expect to see continued gains.

Thank you, Billy, Neal did that answer your question?

Yes sir that was great and just one follow-up I could, you obviously now you’ve got a pretty significant position that Delaware Basin so I am just wondering, given that I don’t want to say its real spread out but given the Southeast, New Mexico and the West Texas area one or (inaudible) for you or one of the guys are in the team here and sort of the way that you will go by tackling and sort of we know what you trying to delineate the whole thing, there are certain core areas that you’ve already identified, I am just trying to get a hand on this and kind of how you tackle this area?

Well, I think it’s still little early to predict exactly how we will develop each of these. We are drilling the first test in each of these main areas, we will evaluate that and from there we’ll work out program that’s what we tend to do. So by the end of the year, we should have that, we planned to do Analyst Day in the fall that will provide more detail exactly how we will go about developing our Delaware assets.

Thank you. The next question comes from the line of Ben Wyatt of [SCD]. Please go ahead.

Question, Joe just real quick on the down spacing, I wonder if you guys could give us a little color on where you guys will tackle down spacing next and really what’s kind of driving that is it the rock, what kind of variables you might do guys choose, here that you will go after next?

I can take that Joe. Hi Ben, this is David Lancaster. I think, where we’re going to tackle it next is after drilling the wells there in the Karnes County on the Sickenius. We have property right close by if we’re that we call Danysh/Pawelek that’s the name of the leases and that’s the next place that we plan to work on that side of the play and then of course in LaSalle County, we will be continuing to work out at down spacing on our Martin Ranch property and also our North Cut property which is just left to that. We have plans to drill down space well there too. So that will all be happening now over the course of the remainder of the year and into the early part of next year. And I think the second part of your question with regard to why I think where, what are the features just really has to do with I think our improving understanding of the rock and of the, how these wells are drained and also how we believe we’re able to frac them a little more densely and perhaps not may be on achieving quite the link, so way from the wellbore but a lot more concentration around the wellbore which I think is really improving the drainage efficiency around each of these down space wells. And so far that seems to be working well for us. And so I think we're going to continue to work on that going forward. Ryan, do you want to add anything to that?

No, I think that's well put. I think everything we have done on the reservoir engineering side suggest that this is an appropriate move to go down to 40 acre spacing. But as if the case with everything true estimate is always in the production results and as you might have read all of our results so far suggest that 40 acre is working. And so our approach is always been that we are going to move into this slowly and that's what we're doing, but I think you'll see more and more of this throughout the rest of this year and into 2014.

And Ben just following on what both of them said is that we are doing this on a lease-by-lease basis. So we don't want to over promise. So what we've seen it on the leases we done, we've been very encouraged by what Ryan and David reported that it seems to be you just have to, this is kind of busting at the rock and as you do that, the 40 acres to 50 acres will be in appropriate spacing.

Got you. Thanks for that color guys. I guess just as a follow-up as well, I wonder if you guys could talk just a little bit about maybe with the (Inaudible) oil production been where it is. How much of that would you say is attributable to maybe the new gas lift if any or is it just strong oil performance on just the order way you're doing with the artificial lift, if you guys can maybe just talk a little bit about that?

Sure Ben. This is Matt Hairford, we've got, I think that the actual number is 19 wells that we are gas lifting at present and somewhere around almost 3,000 barrels growth that we are actually lifting from those 19 wells. So the gas lift has really been a great benefit to us, particularly when the wells get close to the end of their flowing period, but also as we frac offset wells, we found that when we install gas lift in the producing wells next to a newly fraced well that we get to low back a lot faster and get those original producing wells back to their normal production rate a lot faster.

Good quarter. Keep up the good work.

The next question comes from the line of Irene Haas of Wunderlich Securities.

It’s really great to see some of the gas reserves moving back on the book, so I would like to have some guidance on the cost structure including they have some improvement in G&A which is related to the scope and also how should we kind of look at the tax rate, DD&A, is it proper to kind of see – use what we have seen in this quarter and projects forward? And my second question has to do with some color on your Ranger and Wolf prospect, when could we expect some results because both of those wells are located in very, very hot seat codes, and that’s all I have for you today?

Irene, it’s David, how are you? Yeah, so to answer your first question, with regard to cost and DD&A, clearly as you are aware and as pointed out the fact that we were able to put some of our Haynesville gas reserves back on the book this time did result in an improvement in our DD&A rates. And I would say that Irene that going forward as we continue to drill oil than gas wells in the mix that we will probably continue to creep up a little bit on the DD&A side from here. This is probably a good kind of number and then as we add additional oil reserves, that will probably continue to creep back up again, but somewhere between where we are now and where we were in the first quarter is probably where we will sort of average for the rest of the year. Did that get your question answer there on that?

And how about G&A?

G&A, I think will continue to do well on, as our production increases. I think we will continue to have economies of scale and this was a good G&A quarter for us and it may increase a bit from what it is in the next couple of quarters, but I look forward to continue to do well on a per Boe basis because we just expect our Boes to grow.

Right, and tax rate?

Tax rate, okay? So we had a no effective tax rate this go around or no deferred tax because as we mentioned in the release, we maintained deferred -- valuation allowance against the use of our net deferred tax assets. My expectation is if in the next quarter for example, if there is not an impairment which I don’t expect at this point that there would be that we would have sufficient net income to offset the majority of the remaining valuation allowance, which is about 6.7. In fact, we will probably use that. So I would anticipate a small amount of tax in the third quarter. And then if everything goes as expected in the fourth quarter, we would probably return to something more in the 35% range by the fourth quarter.

Great thank you.

And then your other question was on the Permian, so we expect results (inaudible). Do you want to take that Brad?

This is Brad Robinson. We are post drilling Ranger 33 right now. We hope to have it completed by at the end of this month, first part of September, somewhere in there. We are in a process of testing a zone right now on our Ranger 12 well. We hope to have some results from that, plus there is three to four other, sounds we were going to test by again end of the third quarter, first part of fourth quarter this year, and we’ll let you know what those results are.

Irene?

Yeah, and Wolf?

All right, Wolf is the next well we are going to drill when we get finished at Ranger 33, and again should have some results by the end of the third quarter, first part of the fourth quarter;

And Wolf is an area where Energen and Anadarko have recently announced some tests so we have high hopes for that area too.

Great, good luck.

The next question comes from the line Scott Hanold of RBC Capital Markets. Please go ahead.

I thought I just maybe have one question or two on the Permian, you guys done a pretty job of adding bolt-on acreage. It seems like every month for the last several months. Is that a trend we should expect to continue to see from you all, I mean, when I step back and look at Matador what is sort of a kind of good acreage position that allows you to sort of have enough inventory but not too much where you feel pushed?

Scott, that’s a really good question and then that’s something that we discuss and consider virtually every day what is the right size on the inventory. We feel we have been fortune in New Mexico, because we’ve been able to acquire this acreage fairly steadily for the past year and the prices we’ve been paying, we felt have been pretty reasonable in that $1,500 to $2,000 range. So we haven’t set a specific target, we’ve – our land group I think has done a very good job of stretching our land dollar out there and putting together some deals and they’ve been in areas where if someone said are the right in zip codes, so as those opportunities present themselves, we intend to consider to take advantage of them. But we’re not through time to lease in the Eagle Ford either and we all now look for deals there as well that will fit in with our present acreage position. Is that summarized it fairly well?

Joe, I think it does. We continue to see new opportunities every month and team is doing a great job at evaluating those quickly. And I’d just say when we find the right opportunities we will try to make run at them.

And so Scott and we're drilling to say in one or particular of those test areas, we may accelerate our efforts there. So we'll intense a lot of factors, but we're looking at it every day, but I think that in general they push it anticipate that we're looking to build our acreage in all three of our main areas in the Permian, in the Eagle Ford and in the Haynesville all three areas.

Okay. Understood. Those great guys.

The next question comes from the line of Ipsit Mohanty of Canaccord Genuity.

Good morning guys. This is [Chris Marsh] showing in for Ipsit today. We were just curious what did you guys hearing either federal, either sales or from other operators in the [PSL]?

David Nicklin would you?

Yeah, sure Joe. Yes, what we're hearing so far in general is a little bit on the disappointing side, but there was recently a well drilled by Black Brush, the [India] tanks field in Frio County which is just east of Glasscock branch and that was quite an encouraging result at least on initial past with some 570 barrels a day, I believe at 53 API crude together with 3.4 million cubic feet of gas and that it had quite a good flowing pressure on a fairly small choke, I think 17/64 choke. So that's probably the best result we've seen for some time the most encouraging result and the other encouraging thing about that it is some on trend with our Glascock branch acreage. But apart from that we think most people have been focusing certainly in our area more on the Eagle Ford and Buda actually. So we don’t have too much new news on the PSL at this point other than that.

David, I would add in that we are currently shooting our acquiring 3D Seismic over our Glasscock to really interest us in on the Buda and Eagle Ford I think that will help in both of those areas. Dan Hughe is having success, in the Buda we’re on trend with that that trend coming up from the Southwest and we like our Eagle Ford results in the area southeast of the Glasscock. So it’s kind of been something with three points converging on the Glasscock and is very much in our future plans for 2014.

Yeah, if I could just add one thing to that, we kind of think that the Austin Chalk production in many areas is a proxy for the best Buda production, I think that’s a performance that we can answer in the areas Joe is referring to being drilled by Dan Hughes, Sage, Crimson and that’s about five miles to the Southwest. Even some of those good wells or just two or three miles from the Southwest corner of the Glasscock Ranch area, and the 3D Seismic survey we think will be a shooting portion of the shooting pace and acquisition pace on our Glasscock Ranch should be finish this month. So we're on track to get data to interpret later this fall.

Thank you. The next question comes from the line of [Steven Shepherd] with Siemens & Company. Please go ahead.

In the press release you had mentioned that the early wells in the Delaware are going to cost more than you had anticipated cost and development. I was just wondering if there is any early guidance you can give us on what these first couple of wells might end up costing and then by how much you all think you might be able to reduce that figure going forward as you move in to development mode presumably.

Steven, this is Matt again. Maybe I'll address that question second part first. Our target goals we got in the Delaware Basin range from $7 million to $9 million. I am not dissimilar to what we got in the Eagle Ford. With that being said; as we did in the Eagle Ford on these first wells; we are spending some extra money, investing extra money in drilling and pouring [potted] holes, gathering a lot of log data, a lot of rock data that we will use going forward. So these initial wells will be substantially more than the risk, but we fully anticipate a curve similar to what we had in the Eagle Ford as we start drilling developed wells.

And Steve, that [firm] was basically in 2013 we lowered the cost basically a third across the board and we're achieving in another 20% to 30% this year. So it's hard to put the exact number on it because at first we just want to be sure we got the right data. We found that’s been useful to get across. So I would like to in size we are, our practice is not to short change the data because we are long-term players and we don’t want to just save a little money of the short run, and lose out on the long-term planning. So I never try to put too much in the what the initial wells cost, it’s really important what information we get out there to test up your later drilling program.

Now that makes sense. Thanks for the clarification and I guess my follow-up would be so over to Eagle Ford, you had mentioned earlier in your prepared remarks that the addition of that walking rig could potentially lower well cost even further and I just want to check in and see what your current well cost in Eagle Ford are running at and what are your expectations are moving forward regarding how you might be able to improve on those as well drop here?

Ryan why don’t you take this. Go ahead Ryan.

It’s Ryan London. ,Yeah just an update on our well cost in the Eagle Ford as you probably know we’ve always kind of look at the Eagle Ford as Eagle Ford West and Eagle Ford East and however east is kind of broke up in two parts, so if you go over to the west, our well cost are in the $6 million to $7 million range kind of probably closer to $6 million and $7 million. In the middle of our acreage kind of our Eagle Ford, the western portion of our Eagle Ford east, we have cut cost pretty significantly over there, earlier in past we were drilling those wells between $8 million and $9 million, we got those down between $7 million and $8 million actually a little close to $7 million. And on our far east side its always the deeper, the harder the third stream casing and the premium profit those are still in the $9 million and $10 million range.

I think with the Billy and now you expect to even improve, aren’t Ryan?

Absolutely, I mean just Billy keeps continuing to drills those well even faster and faster and we are having a hard time keeping up but he is going to cut those cost 10% we probably did below even those estimates but we are kind of, we’re going to wait and see exactly how much before we throw out a number but we think 10% vis-à-vis doable.

Thank you. The next question comes from the line of Mike Scialla at Stifel. Please go ahead.

Looking at your production guidance, it looks like you’re anticipating some decline in the fourth quarter, is that right, and is it possible for you to just say how many wells you plan to bring on in the third and fourth quarter it looks like you’ve got some plus production right now just trying to realize you’re sticking with your guidance but trying to adjust for the quarter, if possible?

Mike, it’s a very fair question. The decline will be attributable to some timing and some pad drilling because we’re going back to our Martin Ranch and we’re going to drill a number of wells in sequence there and when we do, we have [steady] and then we will frac one and after another but hold off (inaudible) because the simultaneous fracing to bring in much, it’s hard to put a precise number on that but we do expect some decline due to that timing and the pad drilling but as far as your next question that you’re asking and I am going to let David Lancaster take it. David?

Okay, hi Mike, it’s David. Yeah I think that in the third quarter that I would estimate we will put four or five Eagle Ford wells on production, probably have one towards the end of the quarter, just depends on when we get the frac done. I think we'll when probably could six or eight on production likely in the fourth quarter. But the fact is given what Joe just said and what you heard about us using the walking rig and all drilling 4 rigs at a chunk or at a time. Those are probably going to get on right towards the end of the year. So I don't know that they are going to do a lot to enhance fourth quarter production which is how we would start projecting it might go down a little bit relative to the third quarter. Right now, we're going to face where we've got, we have none of our wells currently shut in. So everything is producing, we'll probably in the fourth quarter we have another 10%, 15% of the production steady at various time throughout the quarter. And so when we do that, that just causes our production to go down a little bit on a quarter-by-quarter basis. But I will say, I think that the way we look at here Matador is not so much quarter-to-quarter, but just in bigger time chunk. And if you look at things sort of even on a six months window, you can pretty well see us increasing 20% or 25% each six months and we think we'll be 50% to 65% better this year than we were last year. So, I think everything continues to head in the right direction, it just that, it just it's a little lumpy, when we just have to look at it on such short time windows and a lot of that is really just the timing of our operations and when we get things done. But, I think we couldn't be happier with if you look at it little wider time window just how things are progressing for us over the last couple of years

Yeah, and I think operationally, that makes absolute things to us to do this pad drilling to drill four, five wells at a time come back in fracing and experience have that told us that not only that save us money but it’s better for the wells.

I appreciate that help so I was just trying to get a sense of how lumpy it was going to be I guess over the next six months, but that’s very helpful. And I wanted to ask on the down spacing, you’re obviously encouraged by the early results you’ve seen some results from competitors as well? Based on all that data you’ve looked at, is it too early to say or can you say at this point what do you think [EURs] might be relative to wells based on wider spacing you’re looking at that. You think some degradation or do you think there is any reason to believe that you might get similar EURs to what you’re getting on the wider spacing?

This is Brad Robinson. We’re really encouraged by the results, no doubt about it. And talking to our reserve of auditors and drawing on lot of their experience, they haven’t seen too much degradation and some of the other clients they do – they did encourage us to apply a little bit of depletion factor to our reserves, so following their lead we did however at this point, we’re not sure we’re going to need to do that going forward but at least for the time being we are applying a little bit of a depletion factor and all to see how well they hold up, we are encouraged so far.

Mike, I would echo with Brad says, I think that’s exactly what we’ve done and I got to say I think they all look good, the ones (inaudible) in particular are just kind of they blow out good I think. So I am not sure there is going to be any degradation there at all. Not really sure there will be a modern Range but it is a little early. We are still just 30, 60 days in to this. So we'll probably be able to answer that question a little better the next time we talk.

And I will say one more thing, we put our generation pipe frac on all this 40 acre, 50 acres test and right now with the generation 5 frac, I think the down space wells are outperforming, even some of the 80 acre and 160 acre wells that were done with prior versions of the frac design. So I think whatever effects you see due to if any of the down spacing have been more than overcome by just the better frac.

Mike. Does that answer your question? And now I would like to underscore what David said about the -- you've been in the business, say, 90 days, it comes up as timing plays a much bigger role. We like the year-over-year but at least on a six months, I think gives a more comparable view but we do the quarter because that’s expected too, but I think if you look at it from a longer period, we like that on this down spacing too. That’s why we're reluctant to go at too much. So we have time to accumulate little more data, but at this point, it looks good.

The next question comes from the line of David Amoss of Howard Weil.

In the Delaware Basin, it sounds like you got a couple of vertical pilot holes and a bunch of data out of those, can you talk about what you seen so far in terms of zone thickness and reservoir characteristics and then how you are making that decision especially on the first well about how to place that lateral?

David Nicklin would want to take this one.

Okay Joe. David, we’ve been very pleased with what we found in the (inaudible) logs and both the sizeable cost and whole cost that we collect it. They have been -- the results have been extremely consistent with our regional mapping of the nearby producing wells. And we it’s obviously, it’s too early to say the results of our wells yet, because we haven’t completed the testing. But I will say that we are, we have consistent thickness, consistent across the permeability that’s how it appears to at this point. So far so good, we are cautiously optimistic.

Okay. Thanks.

I was just going to say does that answer the question, David?

Yeah, I appreciate that. And then just as a follow-up, I mean the second well, you’ve putting the lateral in the second Bone Spring, how did you decide on that target and what's your well design look like?

I’ll take that first and then if Brad wants to coming afterwards that will be fine. David, the second Bone Spring was selected on the basis of offsetting wells drilled by [Koncho]. The series of wells that called strata wells have penetrated mainly the second by the spring, one of those wells is in the third Bone Spring. We see very comparable results on the wire line logs between our 33 wells, the 34 pilot and the strata wells. So we decided we were actually – it was a difficult decision because we do have multiple zones there within the second Bone Spring, but we elected to stay pretty much in the middle of the second Bone Spring consistent with better producing strata wells. Brad, would you like to add to that?

That’s right, David. The basis for deciding on the second Bone Springs were based on the Koncho wells to the west of it, their strategy at well, before the initial wells out there and continues to be probably the single best second Bone Springs horizontal and all of Lea County. Today that well has accumulated 330,000 barrels of oil and that’s roughly in 21 months and last check it was still flowing several hundred barrels a day out of the second Bone Spring. So that has always been our primary target for that well.

Great, thank you. Congratulations on a good quarter.

(Operator Instructions). Ladies and gentlemen, we have no further questions. This ends the Q&A portion of this morning's conference call. I would now like to hand the call over to management for any closing remarks.

No, I don't have any other remarks. I thank that the questions have been good. We appreciate the questions and the interest and our thought. They were very good questions. We appreciate everybody's time and interest and we look forward to the next time we can report. We are very excited about what's going on and pleased to have this time with you and look forward to seeing you soon we hope. And with that, we'll sign off. Thanks.

Thank you. Ladies and gentlemen, thank you for your participation in today's call. This concludes the program. Good day.