Good morning, ladies and gentlemen, and welcome to the First Quarter 2013 Matador Resources Company Earnings Conference Call. My name is Kathy 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 the conference. (Operator Instructions) As a reminder, this conference is being recorded for replay purposes, and the replay will be available through Friday, May 31, 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 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. Please refer to the forward-looking statements in the Company’s earnings release for more information. I’d now like to turn the call over to Joe Foran, Chairman, President, and CEO. You may proceed.

Thank you, Kathy, and good morning to everyone. First, thanks to all of you for participating in our first quarter 2013 earnings conference call. I would like to introduce everyone from Matador joining me this morning on the call. We have David Lancaster, Executive Vice President and Chief Operating Officer; Matt Hairford, Executive Vice President of Operations; David Nicklin, Executive Director of Exploration; Ryan London, Vice President and General Manager; and Brad Robinson, Vice President and Chief Technology Officer. We are very pleased with obviously with our first quarter 2013 operating and financial results and feel we’re off to a strong start in 2013, and have increased our guidance accordingly. Much credit is due to our staff and our Board, who have done an excellent job, finding ways to drill better wells for less money and to make use of technology. like many others in the industry, we are seeing the very positive effects of improvements in frac design and operating practices. In the first quarter of 2013, our oil production was 460,000 barrels, which was a year-over-year increase of 130% from 200,000 barrels in the first quarter of 2012 and a sequential increase of 8% from 426,000 barrels in the fourth quarter of 2012. It is important to remember that this increase was not generated by adding a bunch of new wells, because the last well we’ve added was on at the very first of February of this year. It’s just simply that the wells have sustained themselves longer and show increased productivity as a result of these fracs and operating practices, and the reduced chokes. More particularly, our average daily production for the quarter increased from a guidance rate of 4,000 barrels to over 5,100 barrels of oil per day and 34.7 MMcf of gas, 34.7 million cubic…

Thank you. (Operator Instructions) First question is from Ben Wyatt of Stephens. Your line is now open sir. Ben Wyatt – Stephens Inc.: Good morning, guys.

Good morning, Ben.

Good morning. Ben Wyatt – Stephens Inc.: Hey, Joe, I know you guys have been changing completion techniques kind of on your fourth revision, so to speak. Just curious if there’s going to be any changes on the next round of Eagle Ford wells. Maybe, just give us a little color on that, from that perspective?

I’m going to turn the question to Ryan London, who is the head of our completions program, Ryan?

Yeah, Ben. We made mention I think last quarter that we’ve honed in on two things that seem to make the most difference, and that’s fluid volume and proppant. We’ve continued to do that. We’ve emphasized that since the last quarter, increasing our fluid volumes by about 20% on a stage-by-stage basis and likewise with the proppant. Ben Wyatt – Stephens Inc.: Got you. And I guess just moving over to the Permian, you guys are going to go drill a few test wells here. Do you guys just envision kind of maybe when you will let us know about those results, a timeframe there? And then will we get that on all three at the same time? Or what are you guys thinking on that front?

Ben. That’s a good question. It’s hard to say, but most likely, the way we’ve done in the past to just save those results until we can turn out all three results. but we may even drill a fourth well, just depending how the program unfolds. But my expectancy at this point would be just to announce them all together rather than try to do it one at a time. Ben Wyatt – Stephens Inc.: Very good. Good quarter, Joe, and that’s it for me. Thanks a lot.

Well, thanks, Ben. We really appreciate you.

Thank you. The next question comes Neal Dingmann of SunTrust. Your line is open sir. Neal Dingmann – SunTrust Robinson Humphrey: Good morning, guys. Good quarter. Joe, just a question on this Lea and Eddy County acreage that you added. What’s the size? How quick could you start to drill something over there?

Well, we’re drilling that right now. We’re drilling some of the acreage that we’ve acquired right now. and then the additional acreage we required in March and April are right in those same areas. So it’s just, it’d be very easily, it just depends on the best order to do so. and I’d turn to David Nicklin to give an assessment of our exploration idea out there.

Yeah Neal, we’re focusing on both the Bone Spring. That has got, as you are probably aware, there are several zones within the Bone Spring, that’s the Avalon at the top, there is first Bone Spring, second Bone Spring, third Bone Spring and in addition to that we have the Wolfcamp as well underneath and there are several zones in the Wolfcamp, several other operators have published previously. And we feel that our acreage is very well positioned, very closely spaced and close to some very significant results that other operators have already published. So we’re excited about evaluating all of those zones.

Did that answer your question Neal? Neal Dingmann – SunTrust Robinson Humphrey: That was perfect, Joe. And then just one other moving over back to the Eagle Ford. What’s your thoughts, Joe, on going after I know some guys talk about kind of an upper Eagle Ford as well as drilling some Pearsall? Just wanted to see what your new guidance thoughts are of different formations that you might have in the Eagle Ford?

Neal that’s something we are looking at very closely these other formations and we’re also doing a seismic program over in the area of our Glasscock/ZLS out there on the West side. but let me turn this to Nicklin to give you more detail. David?

Yeah, Neal. we are continuing to evaluate a lot of the results of some of the wells that are being drilled in and around, say, around and close to our Western side of our Eagle Ford play. there are some excellent results in the Buda Southwest of the Glasscock Ranch by couple of different operators. there’s also some very interesting Pearsall production just north of our Martin Ranch acreage, and as Joe has alluded to, the 3-D seismic is being shot over Glasscock as we speak, and we should have results of that later this year. I am reluctant to drill until I have got that data; but I am very optimistic about the potential for 2014. Neal Dingmann – SunTrust Robinson Humphrey: Well, Joe, it sounds like a lot of upcoming activity. Look forward to seeing the results.

Thank you, Neal. Appreciate it.

Thank you. The next question comes from the line of Scott Hanold, RBC Capital Markets. Please go ahead. Scott Hanold – RBC Capital Markets: Thanks. Good morning.

Hi, Scott.

Hey, Scott, how are you? Scott Hanold – RBC Capital Markets: Very good. So looking at the Eagle Ford activity in the second quarter, it looks like you have got seven wells you plan on putting online. Can you talk a little bit about the timing of when those will be kind of brought onto production and how, I guess, volumes will kind of ebb and flow a little bit with that?

Scott, you’re cutting out a little bit, so if we don’t answer your question precisely, just let us know, but I’m going to let David Lancaster speak on the timing of that and bringing these wells on. We expect to bring them on in the second quarter, but you’re going to get some unevenness simply by the timing, whether you’re on for 30 days, is it going to look different than if you are on for 15 days, but David would you add to that?

I think what I would tell you Scott is, I mean, as you know we hadn’t, we did four wells in the first quarter and we put the last one on in early February. And then we had these two three-well pads ongoing. The one on our Cowey lease, the wells have now been – have been fractured, so the completion operations are completed. And we are in the process of drilling out the plugs, so I don't think it will be more than a few more days until we have those wells to get into flow back, and then we’ve frac-ed one of the wells on the Martin Ranch lease of the four that are coming on in the quarter. And the next three are scheduled to be frac-ed here very quickly, and so I would think that around the first in June or so that it’s reasonable to think that we’ll have those four wells beginning to come back. And the other thing that will be helpful is that we’ve had some of the neighboring wells shut in, in both places while we’ve gotten these pads, these wells drilled and frac-ed, and so it will be good to get that production turned back on as well. So as far as timing through this, sort of, the first half of the quarter, we haven't had a lot of new production come on and that will tend to come on more now in the last five or so weeks of the quarter. Scott Hanold – RBC Capital Markets: Okay, okay. So we've got a lot of flush stuff coming around midyear. Okay. Fair enough. And then moving over to the Permian a little bit, can you give us a little bit of color on that acquisition and your view on your ability to kind of pick up more acreage? It seems you have been fairly successful in getting a few nice packages put together. Are you dealing with private land owners? And kind of what prices are you paying there?

Scott, one thing while we are talking about New Mexico, I want to be sure when we talk about drilling the three wells or four wells over the year. They’re first wells on each of these leases, so it’s not pad drilling though, it’s going to separate parts of our acreage. Our acreage is really centered around, right now, what we call the Ranger area up and we’re drilling the first Ranger well. And then down there in Texas in Loving County on the Wolf acreage, and then the third main area has been the Indian Draw area. And we may add a well in Indian Draw, just depending on timing and a whole bunch of factors. And so those are three main areas. We’ve enable to add in each of those areas, and we’re doing all the above. I mean some are – we are working in, we’ve bought some acreage in state leases and federal leases, we’ve made leases with fee owners, we have purchased some leases from others on fee acreage and state acreage. The Wolf deal was a deal between an operator and us, and we expect to make other deals with other operators. So that is really kind of all the above, and we are trying to be careful about the cost. We like these areas very much and – but we’re also trying to be sure that we are buying them as competitively as we can. And so far our costs have been down there in the low thousands. Scott Hanold – RBC Capital Markets: Okay. Okay, very good. So then I would assume that the CapEx increase that you all kind of had was relative to these recent purchases?

That’s right Scott is that we put in a little capital increase really to take care the fact that we are having to assess buying some leases and we see more potential for that this year, and want to – again reiterate that we’re still very actively looking and buying leases in the Eagle Ford or the Haynesville. And so when the opportunity arises in any of those areas we see this is a good time to add to those positions. Scott Hanold – RBC Capital Markets: Okay, that’s great. Thanks guys.

Thank you, Scott.

Thank you, Scott.

Thank you. The next question comes from the line of Ipsit Mohanty, Canaccord. Your line is now open. Ipsit Mohanty – Canaccord Genuity: Morning, Joe and team.

Morning, Ipsit.

Good morning, Ipsit. Ipsit Mohanty – Canaccord Genuity: Hey, kind of segway into from Scott's question about Delaware. Let me take a step back and bunch a couple into one, which is, what was the rationale behind going into Delaware in the first place? I mean, this is, as we know, this is not the most matured of plays yet. It is a complex, complicated play with multiple stacks. And at the same time this didn't come with existing production or proved reserves or anything like that. As I understand, this was pure acreage that you’ve gone into. And so, if you could talk a little bit about why Delaware, and then the second part to that is, as you go on to acreage could you just briefly, quickly talk about what is your process going to be from here to September? And then finally, why the delay till September? Is there anything beyond some extensive testing that you will be doing? Thanks.

Well, that’s a lot Ipsit, I hope I could remember it all. Ipsit Mohanty – Canaccord Genuity: Sorry about that.

Lot, but is that (inaudible).

We do guys jump in. The primary, when we sell low Matador we were the, Matador was the 15th largest producer approximately out there at Southeastern of Mexico, so it’s an area that we know well from previous vertical drilling in the old days and we do say a lot of promise of taking a lot of this technology that’s been developed in the industry to drill horizontal as improved fracking, operational techniques can’t have application out there, because when you look at it, it has not been as extensively drilled with horizontals that other areas of the country have been. The economics on that that we looked out extensively feel that can be very comparable to the Eagle Ford and when we looked at it, it’s had a range per zone, per zone, I want to emphasize that, between 300,000 Boe to 600,000 Boe. Now that’s a big range, but the fact is you got three and four zones to look at over there. So it’s a very, very active petroleum system that has a lot to yield without, a lot of this current technology that’s showing itself very effectively in a number good place. And we have a lot of previous knowledge when you look around our staff, the amount of experience that they have. In the Permian, it’s an actual place to grow. We’re certainly not say we’re not will be active in the Eagle Ford, we plan to be there for many years, but we think this is a good area to expand, it gives us the second oil leg to our portfolio. But let me turn it back – I’m looking around the room to see if David or Brad or David Nicklin we be all would like to – did I overlook

David Nicklin is nodding his head

Yes, I would just like to say that that we have Joe is absolutely right about the historical perspective here. Matador has a wonderful database in the Delaware Basin and we’ve been able to use that, we’ve done a lot of work extensively over the years. We’ve looked at the Delaware Basin for quite sometime and what has been the turning the point is really to realization that we can apply a lot of the technologies and things that we’ve learned in South Texas in the Eagle Ford play and in the Haynesville play. We can apply those very effectively in the Delaware, and we believe in the Delaware Basin. And so it makes a lot of sense for us to not only leverage our expertise but also leverage this great database we have.

I might just add, this is Matt Hairford by the way. I might just add, looking back to the South Texas on the Eagle Ford, a vast majority of the acreage will be held by production. And as we develop this acreage the frac evolution is significantly valuable. So while we certainly are not leaving South Texas, we do feel as though as we learn to frac these wells better and better. It’s going to improve the EUR. So, therefore, we’re not in a great rush to go drill up real fast. Ipsit Mohanty – Canaccord Genuity, Inc.: Wonderful. And anything else to read into the delay till September than just more of testing?

No I don’t think. This is David Lancaster. I was going to say with regard to your question on process, I think actually the scheduling is running right at what our expectations were. The first well that we’re drilling is a vertical well and we’re going to take extensive log data, probably cut a whole core in certain part of the Wolfcamp interval. And we’re going to spend our time studying that and looking at where we want to complete that well and how we want to. We’re going to move down to a second well in Lea County and then a third well on our Wolf prospect in Loving County. And in all those cases that we’re looking to sort of drill pilot holes and get a good set of base logs and those things just taken a little longer than they will of course once we get into development mode. So there is really nothing to be read into that other than we just want to take our time on these, first of all, there are important to us out there. Ipsit Mohanty – Canaccord Genuity, Inc.: Great. And then given your division of, I mean, your division of midyear proved reserves, they’ve kind of stayed the same in a while. But you’ve also talked about borrowing base re-determination sometime in the end of the second quarter. Is there a timeline for that? Is there a particular month that you are going to?

Well, I hope that the banks will be able to complete their process this month and that’s something that we’ll be able to announce by the end of the month. I am optimistic that will happen, can’t promise, but having spoken to the banks, I think there is every reason to think that they will get through the process this month for us. Ipsit Mohanty – Canaccord Genuity, Inc.: Wonderful. I will leave it at that. Thank you, guys.

Thank you, Ipsit.

Thank you.

Thank you for your question. The next question comes from Stephen Shepherd of Simmons. Stephen P. Shepherd – Simmons & Co.: Good morning, guys.

Please go ahead.

Hi, Stephen. Good morning. Stephen P. Shepherd – Simmons & Co.: Can you remind me what the specific terms of your crude oil sales agreements are in the Eagle Ford? And what I mean by that is, do you have a specific percentage of the oil that’s sold on fixed-price contracts? Where is it sold at? Just trying to get some detail behind the agreements that you may have worked out there.

This is Gregg Krug, and no, we’ve got, most of our gas is sold, most of our crude, I am sorry, is sold, it NYMEX plus or minus the roll, less trucking plus, but we get the LLS, WTI differential, so that’s, and those are usually on month-to-month basis. Stephen P. Shepherd – Simmons & Co.: And what is that trucking differential?

There is a range there. It’s anywhere from $7.25 to, I think our highest is like $8.50. So I think a good average would be around $8. Stephen P. Shepherd – Simmons & Co.: So, I guess, following on to that, of your reported liquids volume, how much of that would you call condensate, if any? And what I mean by that would be just be 45 degree API or higher as the divider line. And how much of that would be NGLs, if applicable?

So I think we can certainly answer that none of it is NGLs, because our NGLs are captured as natural gas. The gas transfers before the liquids are extracted, so none of it is NGLs. And then with regard to how much of it is condensate versus crude, do you have a good number on that, Gregg?

Not really, as far as the NGLs that we are showing.

Let me take a stab at it then. I think that in the first quarter, Steven, the stuff that was higher-gravity condensate was probably coming – probably was coming from one of our wells on our Cowey lease, one of the wells – couple of wells on our lube lease. And so I would estimate that that would have been on the order of 600 or 700 maybe barrels per day of the 5000. So that’s probably on the order of, lets say, 15%, I don’t I’ve miss it much with that number. Everything we have to the West really doesn’t fall into that category. And even some of our step to the East when you're on like our Sickenius, Danysh, Pawalek tracks and all, that still not in that light API kind of category. So I think that’s a pretty good number.

Right, David. I think that’s the last time we – it’s a little obscure question, but the last time we look at is over 85% of our oil was black oil. And then you had that there in the East or in the about that 15% level from those wells. But we are a two-stream reporter, so the NGL service and uplift are gas price. Does that answer you question Steve? Stephen P. Shepherd – Simmons & Co.: It did. And there's one more if I can. Can I get an update on well costs by areas? Is there any change to your thinking that the Tier 1 stuff is kind of the $8 million in development mode, and the Tier 2s may be at $6 million? Any update there?

Well, I think, this is Matt again, I think as we characterize this the wells to the West, we think are still in the $67 million range and we have seen about 10% decrease or reduction on the drilling side and we’ve got some of the major service providers are cutting their costs, cutting their pricing by 10%, 15% sometimes 20%. So we’re seeing that in both the drilling and the completion side. And as Ryan mentioned on the completion side, we’re putting some of that back into adding value to the wells by increasing the size of frac job. So as we walk from West, East, we’ll go 67 on the west and we get into the on the East side, the higher – deeper higher pressure wells that there will be eight to nine and in the what we consider the wells we have to run the higher stream they still run in well be nine to 10.

And the other thing, Steve, I’d like to emphasize on the wells in the Far East they need a separately increased cost is the proppant and the extra string of casing. But I think you’re confused by (inaudible) ones in the West Tier 2 and ones in the East Tier 1, we don’t like them like that. The Tier 1s can be in other areas but ones in the West have very comparable rates of return to what’s in the East because the cost are less and the recoveries are a little higher in the East. So those are very, very comparable and I wouldn’t characterize them Tier 2, Tier 1 in that fashion. I think there is a little confusion when we write Tier 1, Tier 2 that involves rate of return. Stephen P. Shepherd – Simmons & Co.: Okay. Thanks for your answers. I appreciate it.

Thank you.

Thank you, Steve

Thank you for your question. The next question comes from the line of Mike Scialla of Stifel. Please go ahead. Mike Scialla – Stifel Nicolaus: Good morning, Joe.

Hey, Mike. How are you doing? Mike Scialla – Stifel Nicolaus: Fine, thanks. Last quarter you had mentioned you were planning to do some 40-acre tests in the Eagle Ford. Just wanted to see if your thoughts have changed at all, based on what you’re seeing in the play and maybe what you’re seeing from other industry players in the Eagle Ford?

That’s a good question. Mike and it’s timely, because we’re currently testing that. For details, let me call upon Ryan.

Yeah. We’ve seen a lot of operators testing 40-acre spacing and even tighter. And I think we’ve mentioned last time we are going to test that ourselves and we’ve already drilled one of our 40-acre wells and we’re in the process of drilling another one, and one of those 40-acre wells were actually in the process of fracing right now. So regardless of the apparent success, other operators had we are going to prove to ourselves, this is the right move and we’re excited and encouraged what we’ve seen so far, but we early waiting into results from our current tests. Mike Scialla – Stifel Nicolaus: That’s great. And then I was going to ask on the, you said you were contemplating a three-rig program beginning in September. I assume that is contingent upon success in the Permian. And just trying to kind of get a sense for what that could mean. If you do keep a rig running over there, would that maybe add $25 million to $30 million to the budget? Am I thinking about that correctly?

Yes, Mike. That’s right. David Lancaster has the specifics on that. I think Don is not here, but it’s certainly success in the Permian and pricing outlook is still favorable and that everything is coming together, we can secure a rig, and the cost outlook is right. So you have those kind of macro factors. But on the specific if we did it, David, would you comment on that?

Yes sir Hi, Mike. It's David. I think that $20 million $30 million is about the right number for the additional CapEx, a lot would depend Mike on the specific locations that we drilled, obviously in some of the sections out there in New Mexico. We have all or almost all of the entire section in others, so we would have less of the section and so might have a 40% or 50% working interest in some of those wells. So that would have some impact on the amount of CapEx that we expended. But you’d probably be looking at two or three additional wells. And so I’d think 2013 is probably in the ballpark, might be even lower if we were kind of half interest on some of those wells. Mike Scialla – Stifel Nicolaus: That helps. thanks.

That answers Mike? Mike Scialla – Stifel Nicolaus: It does thanks.

Okay, good.

Thank you for your question. Sir, you have no questions at this (Operator Instructions)

Are there any other questions?

We have another question from the line of Mike Scialla of Stifel. Please go ahead Mike. Mike Scialla – Stifel Nicolaus: Yes, just I guess a couple more. In the Permian, just trying to understand, you mentioned you added that acreage. From the last update it looks like the gross acreage number actually went down while the net went up. Are you changing your…

Yeah, I think can… Mike Scialla – Stifel Nicolaus: Go ahead.

Yes let’s explain that Mike. The gross amount of acreage that we have in West Texas and New Mexico is about 30,000 gross and a little over 20,000 net, all right. We have one lease that’s kind of up on the Central platform that we don’t particularly think as perspective for the plays that we’re talking about here and it’s probably something that we are not going to drill. So to try to give you a little more specifics on what we feel about our acreage, the actual perspective then is on the order of about 23,000 gross and about 18,000 net. So that’s the only distinction there. So we’ve actually added essentially 5,000 gross and 5,000 net since the time of our last release in April about a month ago when we talked about buying that acreage.

Yeah, we are underscoring. That’s on the Central basin platform. So it is in the Delaware. So we didn’t include it. Mike Scialla – Stifel Nicolaus: Got it. Thanks. And then, it does look like, and, David, you talked about it a little bit in terms of the timing of the wells, but it looks like you were planning on having three of those online in late April; and now it sounded more like you’re going to have all six or seven come on toward late May or early June. Did you change anything in the way you are developing those wells? Or has something else caused that delay?

No, really. What it was, was one of our frac dates got pushed about a couple weeks. And so, just due to the timing of the frac date, it’s really the only thing that impacted the dates that those come online. Mike Scialla – Stifel Nicolaus: Okay. Great. Nice quarter, guys. Thanks.

Thank you, Mike.

Thanks, Mike.

Are there any other questions?

No further questions. Thank you, ladies and gentlemen…

Wait, Kathy. Before you sign them off, I have a couple of closing remarks, is that I want to leave you all with that. I want to thank you all for your questions today and to tell you that we appreciate it and also just to say that the way we evaluate Matador, there is I think three or four important catalyst or factors to consider on increasing value, first is it was noted that we are doing the 40-acre testing and if that goes through most all of our Eagle Ford acreage we think that make a big difference, second we are pleased to continue to see gas prices strengthen and it was, as they do so that makes a big difference in our gas position in Northwest Louisiana, particularly, in the Haynesville. And just to give you a feel for that is that as you move from the values we are carrying on our gas, from just $3 to $4 it basically triples that in rough terms. And similarly, as it moves from $4 to $5, it triples the value. So we are carrying in our last investor presentation, if you look at those pie charts, a little under $25 million. And in rough terms as you hit $4 and if you start to include the PUDs with that and like it starts moving it towards the $70 million, tripling that to the $75 million dollar level. And similarly if you move the price from $4 to $5 you will triple it to the over $200 million which of course would have a substantial impact, we just got to like to see process and I tried not to predict them, so if I do, I am always wrong, but it’s encouraging to seem him headed in the right…

Ladies and gentlemen, thank you for your participation today. This concludes the program.