Good day, ladies and gentlemen, and welcome to the Second Quarter 2014 Matador Resources Company Earnings Conference Call. My name is Jackie, and I’ll be your operator for today. At this time, all participants are in a listen-only mode and 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 on the Company’s website through Friday, August 29, 2014 as discussed in the company’s earnings release issued yesterday. Some of the presenters today will refer in certain non-GAAP financial measures regularly used by Matador Resources in measuring the company’s financial performance. Reconciliation of such non-GAAP financial measures with the compatible 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. 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 annual release, its most recent Annual Report on Form 10-K and any subsequent quarterly report on Form 10-Q. I’d now like to turn the call over to Mr. Joe Foran, Chairman and CEO. Please proceed?

Thank you, Jackie, and good morning to everyone on the line. And thank you for participating in our second quarter 2014 earnings conference call. We appreciate your time and interest very much. The highlights are longer than usual because we’re reporting both for the quarter and the first six months of the year, both of which returned record results. No one at Matador takes these results for granted as we all know, all this does not happen without great work by our board and staff, and I wish to take a moment to thank and congratulate all the various teams within Matador that have contributed to these record results into our people in the field. Financially, we achieved record results in a number of areas including quarterly oil and gas revenues of $99.1 million, a year-over-year increase of 70% from $58.2 million reported in the second quarter of last year, and a sequential increase of 25% from $78.9 million reported in the first quarter of 2014. Quarterly adjusted EBITDA of $69.5 million, a year-over-year increase of 70% from $40.8 million reported for the second quarter of 2013, and a sequential increase of 23% from $56.3 million reported in the first quarter of 2014. For the six months ended June 30, 2014, we had oil and gas, natural gas revenues of $178 million. All revenue of $142 million. Natural gas revenues of $36 million, and adjusted EBITDA of $125.8 million. In addition, we have provided charts in the news release highlighting various aspects of our growth on a sequential six-month basis with our earnings press release issued yesterday after market close. And we hope you’ll take a look at that graph, because it shows you how steady our graph has been over these last three or four years. And to put…

Thank you. (Operator Instructions) And your first question comes from the line of Neal Dingmann with SunTrust. Please proceed. Neal D. Dingmann – SunTrust Robinson Humphrey: Good morning, gentlemen, nice quarter. Joe, for you as a team, just wondering with the change now in rigs that you have in the Eagle Ford, you mentioned I know and you highlighted in your press release, some of the early cost savings, will you continue to see more of those, I guess with these walk-in rigs in different completion drilling savings. I guess my question really is, is there additional savings we should forecast in there and are there more rigs that you need to swap out?

Neal, on every rig we drill or every well we drill, the rigs are trying to find all the different way to save money. A lot of this is just little bit here and little bit there. But there is more room in the Permian than in the Eagle Ford, but we’re still not giving up saving money in both places. The Eagle Ford has been around longer, so you’ve gotten some of the low hanging fruit, but there’s still ways to do better. And I’d like to turn it over to Billy Goodwin, our Head of Drilling for a little further explanation. Billy?

All right, Joe. Yes we’re continuing to see improvements, some of the wells in the different areas in the Eagle Ford. We’re moving the walking rigs into the previous wells, offset wells were drilled with the conventional top rigs where we were skidding from well to well, and of course, our batch drilling has helped us improve our costs and drilling times and we’re still seeing those types of improvements. We have mechanical engineers and chemical engineers on staff that are working to look at the different tools and all, and coupled with the new technology. The rigs we’re still seeing improvements out there, and like I said, improving on times and cost.

Neal, something else has been impressive to me is that our Group with this mechanical engineers, several of them are a bit specialists, and they have really improved our bit technology, and how much time we’ve saved, that we attribute to the bits for example. In addition, Billy has done a fantastic job continuing to upgrade our rigs and the oldest rig we have right now is a 2009 rig, and even from there, from 2009 and forward, the rig technology is really advanced, and Billy has really stayed up there with it, and made sure, and today the next rig we receive will be specially built for us so that we can have both a drilling operation and a completion operation going on at the same time on the same location. Neal D. Dingmann – SunTrust Robinson Humphrey: Okay. And one just follow-up Joe, if I could, just on the Permian, you’re certainly making big progress there. I know it seems like – I think you’ve got at least a couple of A wells, and I think your most recent well talking about going after the Wolfcamp B. So the two rigs running, will you do some multi-stack laterals or just wondering how you’re going to – because you have so much potential with all, obviously the different formations, so if you could give me an idea of, I know the last one I mentioned is going to be a Wolfcamp B. I think that you talked about the Pickard State 18, number 2H. I’m just wondering as you go forward, how you will tackle the various formations?

Well, there is a lot of work being put into that right now among our staff teams, and our Permian teams, but this year, we said at the very beginning, we are going to be dedicated to the delineation and the exploration of our acreage in the Permian Basin, and we’ve been doing just that. We’ve drilled six wells out there. They’re producing from five different formations and they are on all parts of our acreage from Wolf to Rustler Breaks to Ranger and the northern part of that, almost touching in our Twin Lakes area. So, we’ve been doing that. On the Pickard there’s another one of the importance of the Pickard is that is the same location, and you drilled a second Bone Spring sand and we also drilled down to the Wolfcamp D. The Wolfcamp D is important to remember that it is the organically rich part of the Wolfcamp. It is the source rock for much of the Wolfcamp production in the Permian Basin, and in the Twin Lakes area. So, we’re just really pleased to have that flowing, and showing that, that is producible too. There’s still a lot of work to be done throughout our acreage on determining which formation is good, better, best, and even within a formation like Wolfcamp D, there’s a number of strikers, it’s reminiscent of the Bakken in that you may have several zones to work with there. So there is a lot of work ahead in determining that, but let me turn it around to Ryan or Matt or David to add anything. Ryan?

Yeah, Neil. I’ll add one thing there is an important distinction between how we optimize or move towards efficiency in the Eagle Ford and the Permian. Joe mentioned earlier that the rigs and Billy mentioned too that these rigs were purpose-built for simultaneous operations. And what we’ll be able to do in the Permian Basin is from a single location drill, multiple different horizons, which means because of – how we’re attacking this by formation. We can actually frac a well while we are drilling on the same location. Whereas in the Eagle Ford, you can’t do that simply because of the interference between the drilling and the fracking. So a different kind of efficiency optimization here, but something we’re really looking forward to, and will be implementing in the coming years. Neal D. Dingmann – SunTrust Robinson Humphrey: Okay, great, thanks guys.

One last thing Neal. Neal D. Dingmann – SunTrust Robinson Humphrey: Yeah.

Dave Nicklin want to say something.

Yeah, Neal. It’s David here, and I just wanted to mention, we have a pretty deliberate process where we’re by which we evaluate and rank the different drilling opportunities that present themselves to us. And part of that is also we do a pretty careful evaluation of a lot of what peer companies are doing as well in and around our acreage. And of course, a lot of these zones have been penetrated in the past by wells that we’re drilling to quite significantly deeper horizons.

So the well logs from those wells are very helpful to us in our ranking and evaluation of these zones. So we’ll be conducting this and continuing with this as the year goes by and as we continue to gather our own data.

That was Ryan London, our team leader for the Permian and David Nicklin, our Head of Exploration. Neal D. Dingmann – SunTrust Robinson Humphrey: All right, thanks, Joe.

All right. Thanks, Neal.

And your next question comes from the line of Ipsit Mohanty with GMP Securities. Please proceed.

Good morning, everyone. This is Chris filling in for Ipsit, today. Just wanted to ask a little bit about the Martin Ranch 40-acre test. You mentioned in the release that you might see western interference as you go towards areas where there is untouched reservoirs, just curious when we might see some results from those areas?

All right. Chris, it’s probably easier just turn it directly to Ryan London.

Yeah, Chris. That section is starting now. When we started our 40-acre campaign in the Eagle Ford, we wanted to start immediately drilling near the older wells, because it’s better to drill sooner or rather than later, near the offsets. And so, what we’ve experienced over the last year or so is exactly that drilling next to these old wells. And during we drilled right offset to our oldest well on the Ranch, and that one turned out to be a good well. It experienced more interference than the other wells. And so we have a good handle on how much interference we’re going to experience based on the vintage of the wells. As we move forward to the Martin Ranch, we’ll be drilling in Virgin Rock. So everything there will be 40-acre from the start, and we expect it will have some of the best 40-acre results moving forward in the Eagle Ford starting now.

Chris, this is Matt. I’ll just add to that too, the really encouraging advantage we’ve got on those wells are the cost reductions that we’ve seen since we’ve been drilling out there. We’ve gone back into these areas and drilled infill wells for much cheaper, and with Ryan and his team, with the evolution of the frac design, the wells are actually very economic. So it’s ended up being a really good deal for us.

That was Matt Hairford, our President and what he means it’s not cheaper in quality, it’s just the cost have now in some of those areas approached $6 million, which is 40% less than what the first well was drilled in that area.

Thanks, guys. And on the Pickard State well, that’s of course close to the Ranger Well, which and you saw it came on a little bit lower rate, but it cleaned up very nicely and picked up oil rate especially quite a bit, is that something you think, you might see in the Pickard as well?

Yeah. That’s a good observation. You really won’t know what the Pickard 2 will do until it’s put on artificial lift, just like the Ranger 33; and the Ranger 33 was just kind of so-so, and that artificial lift made a difference in that, you’ve got a great well. Some of those wells when they’re flowing that much of oil, where 80% to 90% oil that column, it’s just much heavier than something that is 50/50 oil and gas. So when you get up to 90%, the column is heavier, and then these artificial lift to help produce, and they help enough, tell you what it has. And I think in the case of the Ranger 33, it was like 50 days before it had began to show what it could do, and since then, I think, Brad Robinson, our Head of Reservoir Engineering, has raised the EUR on that a couple of times, but Brad let me, I don’t want to put words in your mouth, so I want you...

I agree, Joe, that was an important point about the clean-up. These normally pressured reservoirs do require a little longer to clean up the frac water, and so in the case of Ranger 33, it took about 50 days as Joe said, before it reached its peak rate of around 600 barrels a day. And so we expect the Pickard #1 to do the same thing. And the encouraging thing is, it’s already flowing 400 barrels or 500 barrels a day naturally. So we’re really excited to see what we’ll do on artificial lift.

I think, Bill, there you’re referring to the #1. I think your question was – he was also talking about the #2. Right?

Right.

And we think we’ll see similar kinds of things in the #2.

Yes.

That answer your questions?

Absolutely. Thanks a lot guys.

Thanks.

Good observation.

And your next question comes from the line of Scott Hanold with RBC Capital Markets. Please proceed. Scott Hanold – RBC Capital Markets: Thanks. Hey, good morning, guys.

Hey, Scott, how are you? Scott Hanold – RBC Capital Markets: Good, good. Thanks for asking. Just if I could follow-up kind of on that same line of question on that Wolfcamp D test, you all kind of mentioned you had some encouraging results. Can you give us a sense – I know this is – this Wolfcamp D is oil deeper tests, what you’re generally seeing right now in GOR and API of the crude. Do you have an update or at least sort of an assessment of what that could be?

Yeah. Hi, Scott. It’s David. Yeah, the well is making 85%, 90% oil. GOR is about 1,000 more or less and it’s producing about 40 degree to 42 degree API oil. Scott Hanold – RBC Capital Markets: Okay, okay. That’s good, thanks. And as a follow-up question here on use of another rig in the Permian, potentially even of course into 2015. When you look at your acreage position, I mean, it’s a pretty big footprint when you think about like the need to like HPP down to kind of a lowest prospective zone, how much of that needs to go on, or are you pretty good said from in terms of like the existing production from lower formations?

Scott, it’s a great question, and that’s one of the things we’re working through right now it’s the rig schedule, and it’s a calculus of having some well results, and where is the real value out there and where you’re acreage is. And it’s a high-class problem that we’ve drilled all over our acreage, and we’ve had to say, it’s in all the areas. So you haven’t struck out somewhere where you said we eliminate that acreage. So it’s a high-class problem. One of the big advantages of being out here is unlike in the Eagle Ford where you had few causes that if you didn’t drill down to it and produce it, you can lose it, and here so much of the acreage is in government leases. And on the state and federal leases, one well holds the whole track and holds all zones throughout the track. So if you drill even a shallow well, you hold the deep on a government lease. And so, you just have much more operator friendly leases at here than you do in the Eagle Ford or even in the Midland Basin. Scott Hanold – RBC Capital Markets: Okay, that’s exactly what I was getting at. So you do have a lot of government and federal leases that allow you to kind of dictate your own drilling plan?

Yes.

You know Scott, this is David, I would just add to what Joe said, look our teams and I certainly will complement Ryan London here and Jeff Sutter who is working with him have done a tremendous amount of work already in terms of looking at how we’re going to need to approach our acreage over the next several years, in order to be sure that we effectively get everything held. But I think that they put together a very fine plan and schedule for us and we are going to be executing on that in the beginning of 2015. And it will change a little bit here and there, but I think we’re very much on top of what we’re going to need to be doing and how we’re not going to need to work in order to hold our acreage position at here.

And Scott, this is Matt, and to answer your question, we do have a mixed bag out there. We’ve got as Joe said we’ve got a lot of state and federal leases. We do have a lot of acreage that is held by production currently and then what David has said the schedule contemplates all those things as well as continue our delineation phase so.

One other thing, Scott, is our acreage is about a third state, about a third federal and the third fee and on the fee leases, very few of them have any depth severance, so you’ve got a drill it up by peroration unit, but once you’ve drilled it in that proration unit you hold all rights above and below. So that’s what I mean by being more operator friendly.

Okay, Scott. One more thing on top of that, almost every lease we have, still has a fresh primary terms left on and many of them also have two-year extensions on the leases that we can activate too. So like Matt said all of that is contemplated and realized in the drill schedule. And we have of a variety of different ways that we can go as we evolve through the exploration phase in the delineation phase, but there is many iterations to come on drill schedule.

And Scott internally, we’re working out schedules right now contemplating going out four, five years if necessary on these leases to make it work, but then you’ve got a figure in, which area adds to the most value, it will concentrate on that too, but the shares been delineation and exploration; in next year we’ll get into more intense development.

Okay, thank you. Thank you very much.

And your next question comes from the line of Irene Haas with Wunderlich Securities. Please proceed. Irene Haas – Wunderlich Securities: Hey, good morning guys. My question has to do with, you’ve got four sandboxes and thus far, it’s almost like every well you’ve drilled and each of the sandbox look promising. So, it seems like Dorothy White or Wolf prospect probably going to go to development, so that’s going to eat up one rig. And so is it logical to expect you to part one rig in the Norton part and then the other one around Rustler Breaks area. I see that you’ve got a few more locations staked in the Norton part close to Pintail and Cimarron are those double target, say second Bone Spring and Wolfcamp D type target. Can you give us a little color on that?

Thanks, Irene. It’s too early to get into where we’re going to park rigs other than – thank you Rob to loving area is the further store launch and is ready for rig to be put there and kept there. The other areas, we’re still evaluating because on virtually every – on everywhere we’ve drilled so far there is secondary targets that look very promising in the Loving County, Dorothy White and Norton Schaub, there is a Bone Spring, it looks they don’t probably need to be tested over in Rustler Breaks. We drilled a Wolfcamp B test there, but you also have Bone Springs in that area, it’s very promising, Delaware up there in the Ranger area on the Pickard lease alone. You’re going to have now a second Bone Spring and a Wolfcamp B in just about a mile away you’re going to have the Jim Rolfe which is producing from the third Bone Spring. So we’re, it’s probably too early just where we want to put these rigs and we’ve also got to work sure we intend not to get over our skis and get too far ahead of ourselves because as we bring on these rigs, we also want to make sure we maintain the quality of staff that we currently have and that we don’t want to hire just a bunch of bodies. We want to continue to hire these people who are really interested in building the company and trying to get a little better every day. David, now he will be taking up there on the plans.

No. So I think those actually a good explanation of it all, Yes the other thing I might say is we are – I think you said that we were producing it form the third Bone Spring we just actually drilling that – but just wanted to clear that up, but otherwise. No, I think that was very good.

Irene. We’ll get that to use when we feel comfortable with it. Irene Haas – Wunderlich Securities: Yeah. And the Pintail and Cimarron permits are those – there is also dual target sort of a second Bone Spring in Wolfcamp D type wells you looking for.

Well specifically the Cimarron is a prime third Bone Spring target, the pintail it’s got any variety of different Bone Springs of Wolfcamp horizons, those where we’re permitting quite a few areas right now in anticipation of the outcomes of lot of these wells, but more than anything else is just to in preparation for having a full skill development mode.

Irene it’s David here. We continue to be very pleased and impressed with the way that several different formations in this area. I don’t think there’s any one of these areas out there where we don’t have multiple horizons. And it’s just a very interesting geological challenge to rank the order that we’re going to do these in. Irene Haas – Wunderlich Securities: That’s right and going on these sort of kind of multiband’s type ideas and multizones, this EOG’s Avalon Leonard play kind of expand to U.S. area or it’s little further on south.

Joe, will you take that Joe?

Yeah Irene, there is some Avalon production up in the northern part of the Delaware Basin as well, the ranger area, there are a number of wells that produced oil and we’ve actually produced oil in our original test wells from the ranger 12 from the Avalon zone as well. So we are currently mapping that because along the eastern flank of the basin, we get quite a mixed bag of lithologies and the Avalon comes and goes. So it requires careful mapping and we’re doing that right now. But we’re obviously very, very pleased for EOG and the results of that turning in where they are.

Hey Irene, this is David Lancaster I might also just mention that, we do have a little bit of acreage in and around that area ourselves and we’re actually going to be participating in a well with the EOG coming up here pretty quickly. That’s a third Bone Spring test and I think we also anticipate that we may, we may also be invited to participate in – one or more of their Avalon wells going forward. So that’s a nice opportunity for us to be able to see what’s going on and look a little bit closer in those areas. Irene Haas – Wunderlich Securities: That’s right. It’s a – these are shallow wells so it will go cheaper. That’s right. Thank you.

That’s fair, thank you.

Thank you, Irene.

And your next question comes from the line of David Daoud with Jefferies. Please proceed. David Daoud – Jefferies & Co.: Hey, good morning guys.

Hi guys.

Hi guys. We are good. David Daoud – Jefferies & Co.: So just want to go back to I guess the Eagle Ford completion design. I think in the release you guys have mentioned a generation-7 design and the most recent – it just has generation-6, so just wanted to I guess get an idea of what exactly has changed from generation-6 and generation-7. The more propane tighter cluster spacing, tighter stage spacing, all the above maybe, could you just add a little bit more color to that?

Yeah, Dave. This is Ryan. Our generation-7 design. We’ve kept our cluster spacing, our profit per foot and our fluid per foot, the same as our generation-6 design. What we have changed is a little bit harder to depict graphically. But what we’ve done is we’ve tried to really focus on making it more appropriate for down spaced wells. So, what we’ve done is we have changed the size of the perforation holes, the number of holes, we’ve changed the viscosity of the fluid and the injection rate. It is a little harder to show graphically and it may not mean as much to when listening but to completion engineering it’s a pretty dramatic change. So, what we’re trying to do is ensure a more uniform diversion of fluid into the perforation, so we get a more uniform fracture pattern. And so, we’ve only been pumping this job for about two months now. So our results, we don’t have any long-term results. Our long-term results are going to be more evident – the results will be more evident if the impact long term be considering it’s an issue with interference of the other wells. So far the generation-7s have actually turned out very well. We bumped them on our Danish wells and our Northcut wells and the IPs in those wells were very good from the get-go.

Dave, this is Matt. I’ll just kind of add to that Ryan has said about the clusters the profit in the fluid volume staying the same. We are a kind of determined through our testing and looking back at these wells, but that’s pretty close to what we think is optimal. So we’re moving on down the road, we want to proceed. There will be a generation-7, 8, 9, 10, this thing will continue to evolve, but as we continue to figure out which of these parameters that we can optimize, we can start working on the next set. David Daoud – Jefferies & Co.: Gotcha. Thanks guys, that’s helpful. Just want to move over to the Permian, I know you’re still obviously an exploration phase, but could you maybe just comment on what turmoil costs are and I guess how you see them moving its development mode obviously I am surely decline from where they are now. But if you could just maybe speak a little bit to that and even what the current completion design is in the Permian I know you’ve been pumping larger jobs from the get-go, so do you think there is room for more improvement on Permian completion designs as well.

Dave, this is Matt, and just to try to start off here – we don’t see things in the Permian completely dissimilar to what we see in the Eagle Ford as far as there being arranged. We’re talking about Second Bone Spring wells and we’re talking about Wolfcamp D wells, so the depths vary. So in the Eagle Ford, we were looking at maybe $6 million to $7 million up to $10 million to $11 million well cost across. So the Permian is probably $8 million to $9 million to maybe $9 million to $11 million or so almost well cost. As we continue to work in the Permian, those costs will come down from what we’re doing now. We’ve seen such a drastic improvement in the Eagle Ford from the drilling times going from 18 days or 19 days down to 8 days or 9 days, and we’re going to see those same type of improvements in the Permian. Additionally, we are pumping larger frac jobs and I’ll ask Ryan to address that here in just a moment. But we could reduce those well costs but it’s as with the Eagle Ford, we’re going to figure out what’s going to make us the most money there. So we’ll be optimizing those completions and knocking days off the drilling times.

Yeah. And Dave, I will just add a little bit more toward Matt said about the costs and – like he said we could detract $1 million or $2 million off of our well costs, right away if we want to cut our completion down and have like lot of other Permian operators, but we still firmly believe that the bigger frac jobs have an impact on the well and they’re getting more than pay for themselves. And so our designs in the Permian across the board are larger. It’s hard for us to characterize exactly what they are, because we have so many different formations and so many different depths whereas the Eagle Ford is basically one formation of variety of depths. We broke out our branding of our frac design to a generation in one Wolfcamp, generation one more Bone Spring, those right now as you said they are very much larger than lot of the other operators. And what we’re already seeing is that we can expand our perforation clusters a little bit farther apart. This is simply just due to some of the horizons we land in, have a little bit higher permeability streaks and so we’ll able to trim down on the cost of our frac jobs. And we feel like, get the same stimulation overall.

Dave, it’s also important why you’re on this subject to cost, I think about production numbers, is that a big part. We think our success in the Eagle Ford and now here is attributable to the gas lift its we are now installing, most of the time as we run the pop into the ground, and that’s made a big difference, we think is really accelerated our recoveries in the Eagle Ford and even into the Permian is really improved the PV-10, but something that we’re proud of and particularly Bill McMahon, the Head of our Production and Facilities is the reduction in LOE and I’d like for Bill to able to talk about what they’ve accomplished there, Bill?

You know, Dave, a couple quarters ago, we talked to you about – that we would see a reduction as we went across because we had some fixed costs that were set in there and production would start coming to us and that’s exactly what we’ve seen across the board. And all we’re seeing is variable cost increases as we go down on the total and – but the dollar per BOE cost continues to drive down because our fixed costs are set across the board. And we were able to take those advantages that we’ve had there and the people that we’ve already trained, which we’ve got a tremendous staff out in the field. And we’re able to take that group and move them to, out to the Permian and expand out there. And so we’ve already got people that are trained, that understand our gas lift and how we’ve done it and how we want to do it. And like Brad mentioned a little bit ago, when he talked about a lot of these normal pressured reservoirs and like Joe just mentioned, we run right in with tubing with gas lifts out right after. And so, we’re ready when those wells come on with normal – the normal pressure as they start to go down and we start hitting them with gas lift, just like similar to what we did in the Eagle Ford. And we’re seeing tremendous results, we’ve done that in the Ranger 33. And we expect the same things when we only do the Pickard. We haven’t done those in the Dorothy White and the Norton Schaub obviously those are over pressured areas. But yeah, we just had tremendous success and I think we’ll see the same thing as we move towards the Permian.

The deal on that deal is that last year the lift cost about this time last year was $11 – over $11 – approximately $11.12 and in this past quarter, it was $8.34, but that was a one-time thing. For the past three quarters, they’ve been in that $8 range. So as your production ramps up that becomes an important contributor because that’s 100% goes to the bottom line that’s not something you have to share with the royalty owner. So we’re pleased on that and hope to keep that on that track. David Daoud – Jefferies & Co.: Great, thanks Joe, and thanks everyone. That’s all I had. Nice quarter. Thanks guys.

Thanks Dave.

And your next question comes from the line of Brian Corales with Howard Weil. Please proceed. Brian Corales – Howard Weil Inc.: Good morning, guys.

Hey, Brian.

Brian. Brian Corales – Howard Weil Inc.: Most of my questions have been answered, but I think on the last call, Joe, you all talked about drilling a vertical test in Twin Lakes and I’ll was kind of – if you can provide a little bit more information. I do not know if you all started drilling that, is that later in this year?

That will be later, David Lancaster.

Yeah. Hi, Brian, it’s David. We had planned to drill a vertical test in Twin Lakes toward the end of the year and we’re still looking at that. But frankly, given the way the schedule is kind of unfolded and some additional acreage that we’ve – that we’ve taken on this year, it might also be that we pushed out into the first part of next year. So we’re kind of working through that right now, but it may slide a few months. Brian Corales – Howard Weil Inc.: Okay. And may be a follow-on on that, obviously, you’ve kind of very quietly grown, your acreage position in the Permian very significantly. You don’t really have any lease issues there, I’m assuming, especially now at Twin Lakes, but how fast, I mean adding two rigs next year, is that to – growth going too fast for you all? When do you think you can kind of really push on the accelerator?

Brian, that’s just hard to say. It’s a little early to be making that call. We’ve certainly looked at a case where we add more rigs and we’ve looked in cases where we even slowed down from where we are, a lot of it depends on the staffing because we just don’t want to grow too fast without having the people who embrace the culture who are technically qualified and fit our system. So we’ve been very fortunate, to date, we’ve added 30 or 40 people this year, but I want to be sure that we maintain the quality. Another big factor is just the timing, because right now, it’s a high-class problem, it’s close to an abundance of riches. In that, we drilled effectively six wells and they’re all productive and really better than expected. And so we need to sort that out and continue to watch production. The Loving County is the furthest along, so that was an easy one to say let’s put a rig down there. But if we want to go all out and just drill, you put two down there right now. But you have the staff considerations and you have the delineation and the exploration, which we will resolve to do this year, which takes a little discipline, because you drill a well like a ranger or wrestler breaks in and you say let’s put Avalon that fear or the Pickard. And so we are really trying to manage that and to get it right. Also with these rigs, we’re getting especially built rigs and you want to be sure you’re getting good crews on them. And that takes a little training in and out itself and is a sales staff, I mean there’s just a lot of calculations and the funding. We are in a volatile time, you’re not exactly sure the direction or process are going to take or how much stabilization they have, and you hate to commit to a rig contract unless you’re sure you’ve got – we feel we have a place for it, but we want to be sure the economics remain attractive to our shareholders. So, give us a few months, Brian. By next quarter, we should have a clear idea of it, and you can trust that we’re thinking about this every day.

I think it’s safe to say it’s a fully integrated approach to putting the schedule together that includes capital, it includes human resources, it includes how fast we’re going to drill wells, and it also includes our notion of profitable growth at a measured pace. I mean, we’re not going to get out of worst, at least. We’re going to make sure we get it done right. The hiring, Joe is talking about is very critical to that. And the hires we made this year have been good hires, and we’re going to continue to hire good people. We’re not about filling boxes. We’re going to find the best people to continue our success. Brian Corales – Howard Weil Inc.: Good. Thanks guys.

Thanks, Brian.

Brian, does that answer your question. I’ll just like to make, okay. I presume it did, but if not, get back in the queue and we’ll be happy to give more detail on it.

And your next question comes from the line of Ben Wyatt with Stephens. Please proceed. Ben Wyatt – Stephens Inc.: Hi, good morning guys.

Hey, Ben.

Hi Ben. Ben Wyatt – Stephens Inc.: Just a quick question on hop over to the Haynesville, you guys have laid out kind of a plan for 2014 on what you want to do or participate in over there. Just thinking about how you guys are thinking about 2015, I mean with your marketing agreement, midstream agreement, the NRIs you’ve over there? I would imagine you guys would want to participate as much as possible, but just curious if you can give us any color or maybe what Haynesville looks like in 2015?

Hi, Ben. It’s David Lancaster. Sure. I think we’ve talked about the fact that Chesapeake is talking about drilling a total of 30 wells on that property – 30 gross wells, 6.3 net wells to Matador. And it looks like to us that they’ll probably get 19 or 20 of those wells drilled and on production by the end of the year. So, there will still be another 10 or 11 or so, but that we have to go in the early part of 2015 and if in fact they elect to do all those wells, which we certainly think that they will. It’s our intention to participate in those. So I think you could see this program, really kind of kicked off in the second quarter. They’re drilling ahead, we’re going to see the first wells start to come on now later in the third quarter. But it’s going to be primarily the fourth quarter and into the first quarter of next year before we see the majority of these wells get on and contributing to our production. And I think then you’ll see that make an impact obviously on our 2015 forecasted numbers, but as of now, we think they will execute this program and it’s our intention to participate with them in it.

Yeah. Ben, I think you’re serious. They’ve got four rigs out there and while we’ve only seen the first lot of day with the first two wells and don’t expect a lot more to come on till the end of the quarter or into the fourth quarter. The first two have come on a 12-million a day, which is about 3.5 million net to us a day at 7500 pounds. So those are tremendous wells and we’re eager for them to get started, but realistically don’t think it will happen until the end of September or sometime into October. Ben Wyatt – Stephens Inc.: Got you. I appreciate it. And then maybe just one more hopping back to the Permian. I believe lateral links to be kind of in the 4500 foot laterals so far is that kind of the plan as you guys kind of de-risk the acreage? And when you kind of see revision kind of laterals lengthening out there in West Texas?

Ben, this is Ryan. Most of the lateral links right now have just been basically the geometry of the section township range format in the New Mexico. In the Texas area, where we don’t have that restriction, those will be a variety of links and we’ll be pushing them to 6000 feet and 7000 feet regularly. Going forward, you may see something like in the Haynesville where you drill the cross-section lines and you get extended linked lateral and then in New Mexico section format. But I think for the near future, we will probably be kind of in that 5,000 foot territory. Ben Wyatt – Stephens Inc.: That’s very good. Hey, keep up the good work, guys. I appreciate it.

Hey, thanks, Ben.

Thanks, Ben.

Thanks, Ben.

And your next question comes from the line of John Nelson with Citigroup. Please proceed. John Nelson – Citigroup Global Markets Inc.: Good morning and congratulations on the quarter.

Thanks, John. John Nelson – Citigroup Global Markets Inc.: I apologize if any of this was covered in the prepared remarks, but getting back to, not to beat the Permian activity acceleration with the dead horse, but can you talk I guess, maybe come out another way, can you talk about the lead time you think you need to have in order to secure an additional rig and have any of those procurement activities started? Then I guess just listened to the call, it actually sounds like internal staff, maybe in your eyes is also a pretty significant bottlenecks, maybe if you could just marry those two and if you think sort of the internal staffing is may be the driver more so than the ability to procure rig?

Well, John, I wouldn’t call the staffing the bottleneck. I mean it’s a continuous process and we are – you can always use good people usually an engineer, good engineer can always pay for himself with additional planning and a geologist the same – the same way. We’ve got work form to do, the work is getting done, but you – with the kind of growth when you’re growing 15% a year as we have been for the past three years, it looks like it’s going to continue for the – for the foreseeable future. You’re always in the market meeting good people and (indiscernible). So we’ve got plenty of room to add. There is not a bottleneck and that we’ve already added 30 people so far this year and we’re delighted by. I mean, a real good example of this is, we hired a couple of mechanical engineers, that – normally we hire Petroleum, but these mechanical engineers are bid specialists and that they have really added to our knowledge here, one was a chemical engineer and between them is really helped that several issues like bid design, mud systems and they’ve really added to the toolbox. So that’s been – that’s been great and there’s been just good work all around. So I don’t call it a bottleneck, but it is something that you consider. As far as procuring the rigs go, Billy, we’ve developed a great relationship with Patterson. Patterson has done us a very good job and they’ve been very proactive with Billy and asking us what – what do we think our rig needs are going to be, and have worked with us. And in particular the next rig we gave, it might be the one after that if we desire are especially built for…

You hit on a – we have a very good relationship with Patterson, it’s a very open dialog to the point where they call Billy and say, hey, we’re building these number of rigs, these are the schedules, there are when these rigs are going to be available. If you guys are interested in one, let us know, we’ll put your name on it. And in further to that, once we get to the point where we know we want to build one of these simultaneous operations rigs, we go down there. We go to the yard, we help them design, we get input from them. Obviously, they’re working with other operators. It’s just a very healthy open relationship with them. So, I mean, as far as procuring the rigs, I think we’re -- we’re in a good spot there. John Nelson – Citigroup Global Markets Inc.: And Matt, is that – is that schedule about six months to nine months out now or sort of any...

It’s in a time range, John. There is – there is a lot of demand for new builds. But to Joe’s point drills point about our oldest rig being six years old, it’s not like we’re – we’re out there with antiquated equipment doing what we’re doing right now, but there is a wait list. And like I said, they’re calling us weekly and saying, hey, here’s where we’re out of the schedule and we may have someone drop out, are you guys interested in that? And so, we’ve got a lot of optionality there. John Nelson – Citigroup Global Markets Inc.: That’s – that’s really helpful. And then, I guess just maybe also coming out the other end, I imagine as the rig dedicated to the Wolf area goes into development mode, you’ll sort of realize synergies and days to drill so. I mean, maybe just on the two rigs that you have running now. Any thoughts on what the number of gross wells they could sort of put on in ‘15 just from those two, sort of big range, any thoughts?

John, I think you hit on very important point there, and in fact in our Loving County acreage from the first well to the third well, they’ve marked 20 days of the drill times, so, and they’re going to continue to get better. We’re using managed pressure drilling down in that area, which is saving time, saving money getting those wells drill faster. We started using rotary steerable in the curve, which is taking from several days to less than a day. So those improvements will continue where we’ll ultimately get, I can’t tell you. I mean is it going to be the eight-day wells we’re drilling in the Eagle Ford. Now, we’re not going to do that, but we are going to significantly tap those drill times down. John Nelson – Citigroup Global Markets Inc.: Fair enough. And just my last question, I think the release talked about Howard County well coming before year-end. Just any more color on that timing? Do you expect the completion actually happening in ‘14 or is it just the spud, and then also what formation do you guys expect to target?

Yeah, John, this is Ryan. Our Howard County well, we are going to be targeting to Wolfcamp B and we do expect to have that well on before the end of the year, probably about a month, month and a half before the end of the year. We’ll have probably the frac completed and start our flow back. John Nelson – Citigroup Global Markets Inc.: Right, perfect. Congrats on the quarter guys.

Thanks, John.

And your next question comes from the line of (indiscernible). Please proceed.

Good morning guys.

Hey, David. How are you?

I’m good, how are you?

Good.

My question, so you guys have obviously been very leading edge when it comes to involving your completion especially in the Eagle Ford and now you’re starting to hear a lot of your competitors talk about increasing their sand loading, one in particular talking about doubling it relatively overnight. So I guess the two-part question is, A, are you seeing any tightness in the profit market specifically that has any concern and then B, what can you do it get ahead of that as a lot of your competitors start to kind of copy your completion recipe?

Well, I’m going to turn it over to Ryan in just a second, but basically the only tightness in services we’ve really encountered is sand. It’s one of the reasons why we have – have had a close relationship with slumber and the other large frac companies to help in that regard, which has alleviated it. But our experience is the loss of supply and demand work and where there’s tightness today, they’ll be in abundance in the very near future as people work to meet that demand.

Yeah, hi, David. The sand problem it’s basically manifested in the Eagle Ford just due to a shortage of sand, but also a shortage of truck drivers. It sometimes it’s perceived as its sand, it’s not always. I think one of the bigger companies have done a good job of securing good sand supplies, they’ve been a little bit behind on securing enough truck drivers to hold that sand around. We probably have the same issue out in the Permian Basin and like you said I think lot of the people are ending up on their frac design. Though it is something that we’re paying attention to and it’s something that as Jo said, our relationship with Schlumberger certainly helps us there. As we cultivate our relationship with Schlumberger in the Permian Basin, we feel like that that’s going to help us out, and we’re going to have a different challenge next month and next year that we’re going to have to tackle. And so it’s an ever evolving process of trying to get better and work with Schlumberger and evolve the frac designs.

Okay, that’s great color. Thank you guys very much.

Thanks, David.

And your next question comes from the line of Jeff Grampp with Northland Capital Markets. Please proceed. Jeff Grampp – Northland Capital Markets: Good morning, guys. Thanks for squeezing me in.

Hey, Jeff. How are you? Jeff Grampp – Northland Capital Markets: Good. Thanks. Hey, just a question and I know you guys are working hard to get this out and everyone’s excited to get it, but on the Permian location count, obviously nothing in the press release here is – what’s kind of the timing on when we could get have an updated location count given all the progress you guys have made out there?

Jeff, it’s a difficult one because just sort of now if we put out a number we want to be sure we don’t have to ever backtrack from that number. The date that I would point to most on your best deal is, we’ll probably have an Analyst Day in the middle of January this year and certainly would have something that dated by then. Earlier than that, it would be hard to say. And again, if it gets back to that high-class problem is, you drill a location adversely I think all of the locations we drilled have secondary zones or even a third zone that looked almost as good as the zone that we’re in. So, we’re right now, we’re only putting one location, one well in each location, even though there may be two or three zones that could go there. So we’re not over that hurdle yet because we’re still in that delineation and exploration phase, but it’s a bucket full. I can tell you because you look at the different zones we drilled across that acreage and realize there is in each case, there is a second one and the Pickard is the first one where we tried two horizontals from the same pad and so it’s quite exciting for us. And, because the leases are so friendly that you don’t have to worry about debt severance for the most part and you don’t have to worry about few causes for the most part, you’re able to fashion a drilling plan that gives you a lot of flexibility. So that’s one of our top priorities is put in priority on our acreage and saying this is prime country and then second concentrating our acreage putting it together in the nice blocks, if we can, and then continuing to delineate and explore these various horizons. And so working on that and the earliest I would care to say that, an update would be in January in our Analyst Day. Prior to that, may be we get a little better handle on it, but we need a little – still a little more time. David, what?

No, sir. I would have answered it the exact the same way. So I know that we will have an update by the end and if we feel confident in putting out something incremental in between, we’ll consider that. But Mike just said, I think we’re excited to be continuing testing all these various horizons and benches. And even though we’ve gotten, we’re working on our fifth one now and I know we’ve got a couple more scheduled before the end of the year. So I think, Jeff, we’ll just be able to have a much better idea on all of that and have a much better number to share once we get through this program of exploration and delineation that we’ve been sort of methodically going through this year. Jeff Grampp – Northland Capital Markets: Okay, perfect. Yeah, looking forward to it. Other things that one -- quick one in here. On EURs in the Permian, I think you guys had mentioned that, I think on the Ranger Well, you guys keep pumping that up with some longer-term performance now on some of these earlier wells. Can you guys give us any kind of sense for what you’re thinking on some of these earlier wells in terms of EURs, either internally or what these were booked out on your mid-year report?

Yeah, it’s David. It’s really -- that’s really been nice. It’s also always fun to pump in a little bit. And it’s not just a Ranger, it’s also the Dorothy White and Rustler Breaks, the three wells that we have in the history on, of course three different formations, three different areas and all three have been pumped in a couple of times, but for the numbers, I will turn it over to Brad, so you’d be sure to have it right.

That’s right, Joe. We are continuing to be very pleased with the results from those first three wells and we have increased the reserves on all three since the original estimate. As far as the numbers go, of course, it varies from area to area because you have a higher oil content, say for example, in Ranger than you do in the Dorothy White in the Rustler Breaks area, but what we’re looking at probably greater than 500 NBOE up in Ranger, which was the area you mentioned with the oil content in the 80 plus percent down in the Dorothy White. We’re continuing to increase those reserves. We think we’re going to exceed 750 NBOE easily and those wells in that area have about 65% oil over in the Rustler Breaks area. We’re somewhere in the 500 or better NBOE range. The oil content and that area is around 45% to 50%. For the Wolfcamp, I think it was mentioned earlier today that we expect some second Bone Springs in that area and that’s a very oily zone, probably in the 80% oil concentration area and those wells – based on some of the offset wells are going to easily be in the 400 to 500 NBOE range. Jeff Grampp – Northland Capital Markets: You might mention Brad, in the Rustler Breaks, for example, we elected to go down to the Wolfcamp B, because Atlanta itself is successful more to a play concept, but saying those pranks, there is a couple of nearby wells, once you name those and make it easier for them to...

Okay. The second most range wells that are near our acreage are some – one well that Concho drills called their – they named it a really scary well and I think it’s really scary, because it’s probably better than what anybody expected. And in Murban’s drill, the couple of second bone springs wells. The Malaga 30 wells, which are also Second Bone Springs and we’re watching those carefully. Those are fairly new wells, but we have some insight into that because one of our partners over there also owns some interest in those wells. So we’re getting some early entail, but they’re looking really good. Both of those have (indiscernible) over 1,000 barrels of oil per day from the Second Bone Springs. Jeff Grampp – Northland Capital Markets: Are you just talking BO there, not...

That’s BO...

All right. And another thing, David is that the B factor that we’re using on this is a very conservative 1.2, others are using a little more optimistic B factor, but that’s why I think it’s – we’re standing behind the numbers that Brad said, but it’s more likely they’ll go up than down as we get a little more history.

That’s all right. Jeff Grampp – Northland Capital Markets: Okay. Great, thanks for color guys. Great, well.

Hi, thanks.

And your next question comes from the line of Irene Haas. Please proceed. Irene Haas – Wunderlich Securities: Yeah. Just a follow-up question. I’m little interested in your Wolf prospect rounded by some pretty classy name you got in Anadarko, Energen Shale and Apache close by, I’m just kind of curious what are they after, are they – they are going for the Bone Spring or Wolfcamp A or Concho certainly it’s a lot of activity from some big boys.

That’s a good observation this time we’ve built two Irene, Ryan has your response.

Hey Irene we’ve been watching Apache in particular they have been drilling right near our leases, and they’ve put wells with down spacing tests in a variety of different formations, specifically the second Bone Spring stacked on top of the a upper Wolfcamp and a middle Wolfcamp. And so we’ve been watching what they’re doing. They’ve tapped into something that we’ve actually got on our targets, which is a Wolfcamp test in a different bench as well and we’re hoping to have that test done before the end of the year. But, but you’re exactly right -- that territory lends itself to much more than just the Wolfcamp A to expand, which we’re after a variety of different targets. Irene Haas – Wunderlich Securities: Hey, thanks.

Hey, thanks Irene. Really appreciate your knowledge of that area.

And your next question comes from the line of Mike Breard with Hodges Capital. Please proceed. Mike Breard – Hodges Capital: Joe, I was going to ask about Howard County, but instead I’ll ask about the transportation of your oil and gas in the Permian, are you making progress on contract for there.

Yes, that’s also part of our midstream effort it built, [Macman] (ph) is looking into and we’re out there in the Permian. There is a lot of (indiscernible), there needs to be newly infrastructure that’s come at the end. It looks like there’s some opportunities in that. So Bill’s been looking into that and we’re likely to add some gathering system probably first in the Wolf area to help give us more optionality on the gas that we’re producing there and perhaps even the oil. Gregg, on the transportation, some of the – add to that for Mike, this is Gregg Krug, our Head of Marketing.

Hi Mike. Yeah. As far as the transportation, as Joe alluded to, there is a lot of old infrastructure out there and it lends itself to opportunities for midstream activity and that’s exactly what we’re doing, we’re looking at on the gas side as well as the crude side and we think there’s a good opportunity for us out there to not only lower our rates, but also as well as have prime service as well. So that’s very attractive to us.

That answer your question, Mike.

Yeah, thanks.

All right. Appreciate your question and we are thinking about our takeaways and our transportation every day too and we’ve hired some – a couple of people specifically to dedicate themselves to that transportation, salt water disposal, all those related midstream type issues and I think it’s starting to come together pretty well.

And with that, this ends the Q&A portion of this morning.. I would now like to turn the call over to management for any closing remarks.

Well, again, I’d like to thank everyone for their interest, questions and participation. I’d like to include in my final remarks, again we enclosed a graph that shows our progress since the second half of 2011. It’s been fairly steady across the six-month period and we see these trends continuing on. The other thing, I like to stress is what under the hood, so to speak, it’s not visible, but is important and adding to this is the good staff work, the improvements in our drilling equipment and practices, the steady improvement, little things like LOE, the marketing that Gregg has done and everything, are paying off. A couple of things, I’m delighted to have the chance to do, all of you asking questions to know our Chief Operating Officer, David Lancaster. And David Lancaster learned yesterday that he was being named as a distinguished graduate at the Texas A&M Petroleum Engineering School, only 1.5% of the graduates or so honored. So we are pleased to have him receive that, just as we were last year, Brad Robinson, named Engineer of the Year by the local SPE. And one of our geologist received best paper award. So these are great things and they are well deserved, and for all the capital and technology that it takes in this business, it still comes down to people and I want to express my appreciation to the staff for all their extra work and late nights and to the Board for their support of getting these people together. And, so it’s really pretty exciting for us. Now they have the Permian start to be proved up in a way and for the Eagle Ford, still to be working now. And, Ryan alluded to this, I don’t want to lose sight of the good work in the Eagle Ford, the lease in the Northcut wells with this most recent frac have really exceeded expectations and are really delivering the rights and that combines lower cost has made a difference. So for the Eagle Ford team, I didn’t want them to get neglected as old shoes so to speak because they’re really doing some good this year as we get the Permian delineated. So I just wanted to conclude with that. Thank you again. We look forward to visiting with you all. And if you have follow-up, we will make ourselves available.

Ladies and gentlemen, that concludes today’s conference. Thank you for your participation. You may now disconnect and have a great day.