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

Thank you, Senath. Good morning everyone on the call and thank you for joining us for Matador's second quarter 2015 earnings conference call. Some of the presenters today will reference to 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 press release. As a reminder, certain statements included in this morning's presentation may be forward-looking and reflect the company's current expectations or forecasts of future events based on the information that is now available. Actual results and future events could differ materially from those anticipated in such statements. Additional information concerning factors that could cause actual results to differ materially is contained in the company's earnings release, its most recent Annual Report on Form 10-K and any subsequent quarterly reports on Form 10-Q. I would now like to turn the call over to Mr. Joe Foran, our Chairman and Chief Executive Officer. Joe?

Thank you, Mac, and good morning to everyone on the line, and thank you for participating in today's call. We appreciate your time and interest in Matador very much and we're pleased to give this report. I would like to first introduce the senior members of our operating staff joining me on this call, and who are standing by for any questions you may have. They are Matt Hairford, President; David Lancaster, Executive Vice President and Chief Financial Officer; Craig Adams, Executive Vice President of Land, Legal & Administration; Ryan London, Executive Vice President and Head of Completions and Prospect Teams; Brad Robinson, Vice President of Reservoir Engineering and Chief Technology Officer; Van Singleton, Executive Vice President of Land; Billy Goodwin, Vice President of Drilling; Gregg Krug, Vice President of Marketing; Trent Green, Vice President of Production; and Rob Macalik, Vice President and CAO. The second quarter of 2015 was full of milestones for us. And we are pleased with our achievements this past three months and six months. And I would like to emphasize three key points on this call before taking your questions. First, production is growing. It's been record production, and that not only were these the highest production numbers, but the 1.26 million barrels we produced for the past three months, it's exceeding our entire oil production for all of 2012, three years ago, the year we went public. As noted in the earnings release, we've increased our oil production guidance for the second time this year to our - to the better than expected performance of our wells. The second point, I would like to make is, this is profitable production with what we feel are outstanding rates to return for this time of low commodity prices. We're achieving even at $50, 20% to 50%…

Operator, I think we're ready for the questions now, please.

Operator? Operator, can you hear us?

I can hear us.

[Ph] Scarlett Hanold, can you hear us?

Thank you. [Operator Instructions] First question comes from the line of...

Operator, we can't hear you.

Neal Dingmann with SunTrust. Your line is now open.

Good morning, guys. Joe can you hear me all right?

All right, Neal Dingmann.

Can you hear me Joe?

Yes, we can hear you Neal. Come on.

Okay, okay. Thanks guys. Joe, just a first question, obviously you guys are having a lot of success with different formations, I guess, let's just sort of dive in at Ranger. My thought is, just for you or Mac or some of the guys, your thoughts on that Second Bone Springs. What are sort of the expectations here going forward? And then when I look at some of the acreage, a bit further north, do you consider that to be as perspective as some of the success you already had?

Ryan London is waving his hand, Neal. He'd like to take this one.

Sure, Neal. We've drilled several Second Bone Spring wells in our first collection of wells since we started in the Permian a couple of years back. And we've had pretty good results so far, especially in the Second Bone Spring. As you remember our Ranger number 1 and our Ranger number 2 HEYCO 1, all that turned out to be really good wells. And those are kind of in the northeastern portion of Lee County, and then beyond the Second Bone Spring we've drilled some Third Bone Spring wells too, here recently drilled our Cimarron well, and it came in around 800 barrels of oil per day. So we're really excited about the results we've seen so far, and certainly we're excited about what's to come considering we merge with HEYCO and they have a lot of acreage on the northern perimeter of the Delaware Basin. Ned, do you want to add anything about the Second Bone Spring potential. As you know the - our EUR estimates for the Bone Spring are in the 350 MBOE to 650 MBOE territory, and these are all very higher oil cuts to these are all 80%, 90% oil cuts, and we are actually putting the rig to work, our rig number 809 is destined to be Ranger Arrowhead rig, which is the two kind of northern quadrants of the Delaware Basin in New Mexico. So we are excited and we are going to be drilling most of our wells with that rig 809 in that area.

Yeah, and I'd just follow-up on what Ryan said. This is Ned Frost speaking, and I think we're very encouraged with the northern part of the Delaware Basin. It is a proven area for the Second Bone Spring and many of the Bone Spring sands. So I think we're continuing to view this as a fruitful area for us.

Neal, this is Matt, I just might add to the Bone Spring that Ryan is talking about is, is normally pressured and it does respond very well to our official lift, we've used both gas lift and ESP in this zone and the response is very favorable.

Are you still picking up last, just last follow-up, just is there bolt-on, is there more acreage in that price whenever you're still available?

Yes Neal, we think that we'll continue to pick-up acreage in that area, they are not, they're going to be huge chunks or large ranches that you have like in South Texas, but if you just stay after it, you'll steadily pick-up acreage at reasonable prices and we are confident that our position will continue to grow.

Makes sense. Thank you all. Great quarter.

Thanks, Neal.

Our next question comes from the line of Scott Hanold, with RBC Capital Markets. Your line is now open.

Thanks, good morning guys.

Hi, Scott.

Hi, Scott.

Hi, and just sticking obviously with the Permian since it's a key area for you guys right now, you've certainly indicated you want to make more of a move to the Wolfcamp, it appears going forward at least in the near term. Can you discuss what is kind of the diver of that concept and the potential kind of implications on your oil and gas mix when you look at your acreage position?

Hi Neal. I mean Scott, it's David, how are you this morning. Sure. I think that one of the real highlights for us actually of the first half of this year has been the success that we've had at the rest of rigs and particularly in the Wolfcamp. I mean we're - we continue to have very good success in at Wolf - drilling the Wolfcamp XY, they're at the top of the Wolfcamp interval but our scientists have done a great job of really sort of identifying and helping us to extend that play to the Northwest into Eddy County, they are in the Rustler Breaks area. And so we've drilled several very attractive Wolfcamp A and Wolfcamp B wells, clearly the third well was a very good well for us that was sort of the first one we had tried in the X, Y interval, they're at the top of the Wolfcamp and it was a very good well as you recall. The one we've recently reported is on the course that targeted 124 was the second test like that that we did and it was - as I recall in the 1,400 BOE per day IP range, of course the Wolfcamp B, we feel like that well is still tracking our million BOE type curve. So we've been really, really encouraged by the recent results that we've seen in the Wolfcamp there. And I think whom we refer to kind of emphasizing the Wolfcamp a little more, that's one area where we are doing so. So our mix of wells going forward this year, we'll focus more on the Wolfcamp and maybe a little less on the Bone Spring than what we would have projected early in the year. The other thing, the other part of your question with regard to the gas mix, I mean, actually I think we've been really pleased with what we've seen in that Wolfcamp X, Wolfcamp Y, because our wells there tend to be about 80% oil cut, which is as good as it's not even little better than up in - than in Wolf. So I think that that interval has also a very attractive oil cut, and so that's a lot of the rationale behind our decision there, Scott, but we are really extremely pleased and excited with the results that we are seeing there.

Hi, Scott, Ryan here, just our results have been very repeatable in our Wolfcamp wells, and if you look at the very first well we drilled on our Wolf area on our Dorothy White well, it was one of the best wells we have ever drilled as a company as we've gone in there, and started to develop in the Wolfcamp X and Wolfcamp Y. It's been - we've been able to repeat those results and drive the cost down, which further boosts the rate of return. And there is other - there is a variety of reasons why we are focusing on the Wolfcamp beyond that. I mean the Wolfcamp units were 320 acres. They hold from the Wolfcamp all the way to the surface whereas if you've drilled a Bone Spring well first, you wouldn't necessarily hold below the Bone Spring. Yeah, there is some land reasons why we are doing the Wolfcamp, but I think it's mostly dominated by just the wells. It's just turning out just phenomenal, and we are trying to move into a farming operation in our Wolf area, and we are pointing in that direction in our rest of acreage as well.

Scott, this is Matt. I just want to comment on what Ryan has said, there is something that we've been able to repeat over and over when we move into these development modes where we are able to go in, and really drive well costs and improve the completion designs on a particular interval, so I think what you've seen is a move in that direction as well where we're going to really capitalize on operational efficiencies and get in more into the development mode at the Wolfcamp.

That's all I got. I appreciate it, that's a good context, and I guess for my follow-up question - for 2016, Joe, can you provide a general framework of what you are all thinking at this point of time? And obviously, you guys are spending a little bit more CapEx, it looks like in part to prepare for 2016, but - you in the past discussed, potentially your fourth rig, and certainly oil prices aren't acting too favorable at this point, but can you give us a general framework for how you think about 2016 right now?

Yeah. Scott, it's the same way we looked at 2015, we're very rate of return driven, and we're not going to do something, we don't have that kind of - we don't have lease expirations that we got go real, and we don't have to do this. And we gave at a lot of thought on the CapEx, or whether to take this third rig and boost the CapEx. And of the CapEx, I think it's in the boost in CapEx, our third is about related to this rig, but a third is we're were achieving great cost savings and there is powerful opportunities from our midstream, so we've increased the investment there because we can see the returns. For example, on our saltwater disposal, we expect to save about $6 million this year, almost $0.70 a barrel, and when you are lowering your LOE cost, that's been a big portion of it. In addition, the leasing opportunities that we've seen, now that we've delineated a lot of these areas, we can see opportunity, and so as they've come along we've tried to take advantage there, but the boost in CapEx was something we gave a lot of thought to, and we just felt we had the balance sheet to do so. We had $53 million in cash, and we haven't gone into our commercial line of credit that we were in a position to do so, and the new technologies that we were achieving with our new rigs just led us to deal with it. The economics were so strong for it and it would allow us to continue to build the organization and gain expertise. One of the key points as we conferred on all of this was the fact that we had nine different horizons, and each…

Yeah, Joe. That - actually I think, you covered it very well, but the last little comment that you made there, I was just going to add before you did, which was, we are also Scott, I think, as we put in the release, this first rig - the rig is first drilling a three well pad there at Jackson Trust in northeast Loving, where actually we're focused on some of the shallower zones because, some of our peers have had some success with the Second Bone Spring, the Avalon even up into the rusty part of the Delaware. And, so we're looking at - we're looking at those, at those intervals as well, and again that could set us up very well for a real development opportunity there at Jackson Trust. So, I think, that the addition of the third rig was to help us do all of those things in preparation for 2016.

And, we felt lead to the 40. And, we've always tried to be prudent on the money and discipline, and it was the third - it was the third, and I'd say a lively discussion. But in the end, it was just the opportunities were too powerful just to turn away from arbitrarily because of price, because you never know. You've been making money today, 50 years we are, with our all in cost and some of our funding cost are down there in the $11 and $12 a year, reducing LOE, if you make money at 50, we'd feel very strongly they we'll do better as the year goes along. Because, we're continuing to make adjustments, and I still think process were more likely to go up than go down. Matt.

Yes, Scott. I think it just kind of speaks to what you hear us talk about a lot with the profitable growth at a measured pace. It just feels like the right pace for us. We've got the 90,000 acres out there, and as Joe and David said, we've got nine different intervals that we targeted already, so there are a lot of efficiencies that are gaining by continuing the momentum we have. We've been able to really reduce our costs and now we've got a much bigger pie to look at. So I think it makes sense for us to take those learning's and expand and put, have two of the rigs working on development type projects and with the small delineation component in as a third rig, that's pretty much in the delineation mode for the remainder of the year and into 2016.

Scott I'll be the one to finish this long answer to your question, I just wanted to - there were several wells we drilled this year with a specific intention to set up 2016. Just going down the list we have in the Jackson Trust, we are drilling the Avalon and the Brushy. But we also drilled a Second Bone Spring well in our Wolf area. We certainly brought online and [indiscernible] 400 BOE per day and which is right in line with where we expected that's going to get right in the range of our EURs miss for the Bone Spring, but it came in well below our estimated cost. Again, our Tiger, second Bone Spring well, again came online. It's done very nicely since it came online right in line with expectations and it came in again way below our lower estimate of our cost threshold for that area. And then the rig right now in Rustler Breaks is drilling on the Northern most tip of our acreage block on our Scott Walker well, as a part of our delineation program, and so this again adds this well, we get the resource back from this well has major implications for our drill schedule in 2016. So you can see that most of the wells we've drilled this year has been development wells, but we have tried to sprinkle in quite a few wells as test wells that will alter our schedule going forward throughout the next year.

I appreciate all the color guys. Thanks.

Our next question comes from the line of Irene Haas with Wunderlich Securities. Your line is now open.

Yeah, so if I might ask two questions. Firstly it's really your production profile. First half of next year, so we have a strong first half of 2015, second half a little lower understandably. So should we expect upswing during the first half of 2016? That's question number one. Question number two has to do with the Twin Lake area, I'm really excited that you're going to go in and drill vertical well. So I would like to know whether you are targeting Wolfcamp D and if yes, how many wells would it take for you to actually nail that trend because you guys are sort of like the first mover in that specific area?

Hi Irene. It's David. Good morning. I'll certainly take the first question. I think the answer to your question is, yes, we would expect an uptick in production early in 2016. Really that's probably when we're going to first see the impact of production from the third rig. Given that we've started with this three well batch at Jackson Trust, it will probably be maybe November before we actually have first production coming from that rig. So, even though we'll drill 5 wells or 6 wells probably by the end of the year, they will be completed towards the end of the year, some of them just right at the end of the year first of 2016. So I think that's when you'll start to see the first production from that come in and as a result our production should tick up. With regard to the second half of 2015 as you said that is understandable and I think that's right nothing different than what we've said all year along, except the fact that I think that we probably peaked out at about a 1,000 barrels a day higher than what we thought that we would see or that we reached to these current levels at 13.8 or so for this quarter, which was substantially better than we thought, and I think it reflects the success of the wells that we've seen in the first part of this year. But in the second quarter, we benefited from having some really strong wells that came on at the end of the first quarter and right at the beginning of the second quarter, including the 8 Bishop-Brogan wells that we drilled in the Eagle Ford. So as now we've scaled back from the five rigs to the two and now picking up the third, the third one really just doesn't have a lot of impact until 2016. So I think you've got it right in terms of how the profile was going to go. And then on your question on the vertical test in Twin Lakes, like everything else we do, we're trying to go about it methodically, and I'd just ask Brad and Ned to make their comments. Brad is the Head of Reservoir Engineering and Ned is our Head of Geoscience Group.

Yeah, hi, Irene, this is Ned Frost. I think we're - we need to encouraged by Twin Lakes, and as we mentioned we do have two wells that we planned here, we have - I think it's hard to know exactly what it will take to delineate that trend, but we have our [ph] olivine target which is in the Eastern part of Twin Lakes, and we plan to basically do a vertical well there to test the Wolfcamp B to collect data and get a sense of it there and then in the Western part of Twin Lakes, we have a Kemnitz well. So, really what we're seeing is we think we'll get to these in probably the fourth quarter of 2015 to the first quarter of 2016. And, really one of the things here is that, thus far when we collect data, we really are seeing pretty immediate returns on those science dollars. I mean, you can see it evidenced in Rustler Breaks, you can see it evidenced in Jackson Trust, and we continue to be quite optimistic with the opportunity there in Twin Lakes. And, as you did point out, we are kind of one of the first movers there, but we continue to be confident in what that prospect holds for us, and Brad do you have anything you want to add?

Yeah. I'll just add to what Ned was saying, Irene. We of course of always liked this area, it's a very, very productive area, having produced over 1.3 billion barrels of oil, the Penn Shale or Lower Wolfcamp B which is our primary target as Ned said, is the source rock, for a lot of that oil production that's in the shallower areas. And we do think, it's probably going to be two wells just to get to answer your question. The western part of our acreage, the Wolfcamp B or Penn Shale interval is over 800 feet thick, and its' a solid oil column. We've got multiple targets there. So it could take some additional wells to identify those multiple targets within the Penn Shale interval. We - that's an extension of the Pickard well, that we drilled and we're really pleased with the results from our Pickard well where we tested the Wolfcamp B, the whole area has - there been a lot of drill stem test, excuse me, open hole test that are conducted when people are drilled, and they've gotten an oil from the Penn Shale on for years from these drill stem test. So we know the intervals are productive of oil. We want to test it with modern technology, horizontal well, hydraulic - multiple hydraulic fractures and we think that it can be a substantial resource for us. So we're really excited about testing it.

So, Irene, just to elaborate a little more on what Brad said, our Pickard 2 well was drilled into the [ph] shaley component of the Wolfcamp D and the real purpose of collecting this core and more just rock data is to identify one of those zones that will be very similar to the Wolfcamp X sand. So in the Wolfcamp X sand in our Wolf area that is the zone that gives us a lot of deliverability that's charged by the shale and so that's what we're looking for up in the Twin Lakes area. If we can find that zone, we feel like that it has all - it's the recipes for success up in the Twin Lakes area. It's been the success down in the Wolf area and so that's what we're looking for. As far as the development for that Twin Lakes area, we think it's going to be very reminiscent of what you've seen in the Wolf area and the Rustler Breaks area. You start off with one well, you test the concept with that one well, you watch the results and then over time, you move into delineation into the development. So this is kind of the first step is drilling this vertical well and collecting the data.

And may I ask one more question, so in terms of frac design, will we kind of need to probably - is probably look more like what you guys are doing and will sort of in situ model rather than a Bone Springs type completion. So should we expect quite a bit of reliability and continuity because you're really dealing with a pretty massive shale with some probably better porosity in between?

It kind of depends on what we see from the core, I mean we'll get roughly data from the core, we'll get permeability data, but I would expect that you're going to see a kind of an in situ or micro coupled type frac design in this area. We put them in situ design on the Pickard Number 2. I mean, if we can find that Wolf CapEx extend equivalent up in the Twin Lakes area, then it be little bit closer to the micro club, but I can guarantee you it's going to have a lot of sand and a lot of fluid, and we're going to hit it with a lot of horsepower.

That's great. Thank you so much.

Thank you, Irene.

Our next question comes from the line Ben Wyatt with Stephens. Your line is now open.

Hi, good morning, guys.

Hi, Ben.

Hi, Ben.

Just have a quick question, may be around the Bone Springs. One, wanted to see if you guys could remind us may be on the spacing of stages in the Bone Springs, and then just curious based on kind of where the - where the spacing is now, and the permeability of that zone. Is there any chance that you could actually widen the stages there and lower well cost even more.

So Ben, this is Ryan. That's what we've done as we've moved from our Generation 1 design to our Generation 2 design. The first generation was 50 feet between clusters and we moved to 75 feet between clusters and the very - the purpose of that move was exactly how you described just to cut costs. We feel like we're overfracking at 50 feet, and we can keep the same effect with 75 foot spacing. We did keep the amount of sand to same per cluster, but since you've spaced it out to 75 feet instead of 50 feet. It just makes it - it makes it 1,300 pounds per foot. We are still hitting each track with the same amount.

Got it. Very good. And then may be just Matt on the - on the artificial lift. You mentioned kind of the ESP, will that be - will you guys kind of do that based on the zone with Bone Spring or will that go across the entire Delaware to all three different zones. How are you just kind of thinking about testing the different artificial lift on each well?

Yeah, Ben. That's a good question. And we are very favorable to gas lift where we think it's a very cost efficient way to lift high volumes of fluid both of water and oil. So, there is a component to the gas lift that we like a lot and then we can run the tubing during the initial installation in the well, run the gas with valves, and the well will flow for whatever time period that it is allowed to flow and then the gas lift out just fit in place and once the well starts needing a little help, we just started the gas [indiscernible] and started injecting gas down the backside. So it's very efficient way to get started. The ESP on the Third Bone Spring well that we ran up in the Ranger area has been very productive as well. So it's, I guess, our first test if you will on the ESP and there was some reasons for us doing that related to the prairie chicken season and things like that. But it is a good test for us. And ultimately, as you know, all these wells will go on broad lift, but it will be down getting to 100 barrel a day or 150 barrel a day range. But I would like to ask Trent Green, our VP of Production to add his thoughts as well.

Yeah. This is Trent. I echo what Matt says, the gas lift is our primary source of artificial lift and when we look at these wells, we - example of the Cimarron well and Ranger that we've talked about, the ESP is very good and from a reservoir perspective, we looked at it from a GOR certain types of artificial lift tend to be more applicable. We did try this in Cimarron and early results are doing very well, and we'll go next to artificial lift at some of our reservoir conditions dictate again gas lifting to be our best source at this point, and we're going with that except in a couple of cases where we're trying some others.

And then also - we've also run an ESP down in Loving County on the Wolf acreage on [indiscernible] wells, and it's early on but results were good for that as well.

Got it. And care to comment maybe on just what's the difference in cost would be when - if you go ESP versus gas-lift?

Yeah, Trent again. When we installed the gas-lift valves and tubing in the initial completion, there is about a $30,000 to $40,000 cost with that upfront. The ESP is more expensive than that, somewhere in neighborhood of $200,000 of the productivity and the flattening of the decline curve also with the ESP, we upfront load that those economics and we see that pay off very quickly on electric submersible as well.

Yeah.

And one of the advantages on the gas-lift is well as - is it's kind of an automated system. I mean, once you start injecting gas, it starts lifting up without valve, and as the well dictates, it will ultimately work its way down to the bottom of the valve. So, there are some advantages there as well. Just comparing the operating expense on the gas-lift is around $4,000 a month.

Yeah. $4,000 a month is correct, but 12K on the ESP due to the electricity.

Very good. Well, hey guys I appreciate it. Keep up the good work.

Thanks, Ben.

Our next question comes from the line of Brian Corales with Howard Weil. Your line is now open.

Good morning.

Hey, Brian.

I'm just - how are you Joe. I just have a follow-up kind of to Scott's question on 2016. I know, you gave a lot of detail, but it looks like the second half of the year, your run rate on the capital spend is about $80 million a quarter. Is that a fair estimate for quarterly CapEx next year?

Well, so to first answer your question, Brian. This is David. Yes, you're right on the run rate for the rest of this year, about $80 million a quarter is right. I think that - I think as far as what it will be for next year depends a little bit on, one, just what our level of activity is if we stay at the three rigs or if we would look to modify that in any way. And also I'm not certain at this point what we might look to do in terms of additional midstream investment or land or even non-operating opportunities, something we've had a few more of those even come our way. So, I think actually that if you - that will probably be the difference, but I think that we stay at three rigs and we had about the same level of spending in those other categories that that would be reasonable to assume.

Brian, this is Joe. And I'd like to emphasize is that, our base case is for the three rigs, and we're not going to four rigs unless we think we can make money or add value and achieve a desirable rate of return. And we'll just - what I do always try to suggest is we will view this very broadly, we don't look at it from the single variable, but we take a lot of different variables into account and circumstances what can we achieve with another rig, and what's the rate of return and how does the effect, what else we're doing, but this third rig we discussed it for a long time, but that was pretty easy to get to given the opportunities we have and what's the rate of return, the fourth rig - we'll look at that and if price of oil is $40 and we can't make money, we are not going there. And at the same time, if we're not making money, we can give up one of these three rigs, it's not like we have to use it. So we're trying to maintain our flexibility and change according to the times and to take advantage of the time. So that's why we tried to maintain the strong balance sheet. So we do have those options and I think David put it very right is that we're driven not for growth to say, but as Matt said trying to achieve profitable growth at a measured pace. So we're headed into this, and with the other thing that's worked for us is the rigs have added productivity and the staff on the rigs, on this third rig, we staffed it with the same people of one of our old rigs. So they got up and running from day one. And we've already moved it twice just in these first days and everything is working and clicking on it. So we may not need, we may go through with three rigs, what rigs could do a year ago with these rigs. They're just more productive and would invite any of you all out to see them because they are just remarkable with a better pump systems and Billy can tell you all the features, but they've got wide experienced people and great systems and we're confident that we're going to do. We'll approach dealing with three what once would have required four rigs. So Matt.

I think you summed it up well, Joe, it's been really fun to watch, you know when you go from 43 days on well to 23 days on the same type well, that's a big jump in productivity, and the rigs are built specifically for our purpose, and a lot of the features that we've added are unique, certainly to the basin, the basin has a rig fleet out there that's, for the most part older, a lot of people move in new rigs and that but we're really proud of the rigs that we put together and really proud of what they've done for us.

That answers your question. Does that help?

So that was very good, that's very helpful. And then, just one more, and with this three rig program that would sounds like, can you at least kind of keep production flat or can you potentially see growth if this, at your current productivity, and obviously it's likely to get better, but could you see production growth next year at this level of activity?

Yeah, hi Brian, this is David again. Yes, I think we would, we would see growth next year, even if we stay at three rigs.

All right guys. Thank you.

Thanks, Brian.

Our next question comes from the line of Mike Scialla with Stifel. Your line is now open.

Hey, good morning everybody.

Hi, Mike.

Joe, I think just answered by question on, but maybe just to investigate a little more into quite a length about the decision that the third rig, the focus on the rate of return and the opportunities that are in front of you, it sounds like if I heard you right, $40 is based on your current returns, it's just kind of a spot where you would actually slowdown and, would you drop one rig or do you have flexibility to get rid of even more if need be?

Well, Mike, that was an arbitrary number I put, there's normally 40 or 41 or 42 because again what I've tried to stress, we're not tied, we don't look at things from a single variable is because you've got to also look at productivity, your level of confidence of achieving further cost savings, your productivity increases, the way technology may help you achieve better fracs, it's a comprehensive look and you know how we meet as a group and we sit around here and discuss and that's what happened on the third rig is everybody work through their point of view it just came out. It was clearly the right thing to do for the long-term outlook for Matador and delineating and proving up its acreage while maintaining development operation. So there are just a lot of reasons to do that. And last in this past quarter, as you know, we raised 400 million in public debt and we did an offering that was successful and to get ourselves to where we have the flexibility to either add rig or drop a rig depending on what's best for the shareholder value of Matador. We don't have to do any drilling. On the other hand, we got the wherewithal to do - to take advantage of special opportunities that may arise and we're starting to see the deal flow increase where there are some real special opportunities for us. In addition, midstream is working very well for us. We can start to see the cost savings, the extra control that we have that's we're - we're not flaring any gas and all of our wells are hooked up at the top. There are some little bit flaring because of top-line issues but that's not us, that's a top-line that's having to…

Yeah. Great. It does, it did. I was just understanding the reasons and understanding and appreciate your thought process behind it, just kind of wanting to investigate the downside, the flexibility if oil prices were to head down, not to try and pin down a specific number, but...

No, in the same way on oil prices, you don't know, just look at what the price is today, but what is the outlook going forward, and what are the further productivity savings we'll get or the further cost savings and in drilling, and some delineation. What is the value of delineation? We've got nine horizons. We need to do some testing of those. So, I think we're trying to look at it in a way not for the short-term people. Many of our shareholders as you know have been with us for - since inception, and going back to First Matador, we've always tried to look what builds the long-term value, and builds up the company. We are building the kind of staff that can double the company in the short space of time, and our people here are getting better as they get more experience in the Delaware. David, you and Matt are pretty articulate, it's a pretty easy reason when we got to it.

Yeah, I think the long-term view is the most important thing. We would do have a very rich set of opportunities. So we need to determine how we're going to develop and the good news about lower oil prices are low service company prices. The good news about continuing around this rigs, and getting these operational efficiencies going, and those stick with you. So we we're - on a long-term approach was able to go in and Ron is able to tweak this frac designs at low cost of the rig. Look back and see what is it we need to change, what we want to change, how we're going to as we always say drill better wells for less money. So the long-term view I think is the most important thing there.

That's great.

Yeah.

Okay.

Just adding one...

Do you have follow-up?

Yeah, I wanted to ask that specific question, on Ranger that recent Second Bone Spring well, you drilled that in a lower bench you said in the earlier wells, I'm just wondering, do you think is that because you think there is maybe a separate reservoir there, that you can develop in a stack nature or is that because you're looking at that as maybe the optimum landing zone?

Hey, Mike, this is Ryan. I think there are several people around the table who can chime in on this, but I'll just start it, and when we drill the first Ranger well, we had a hard time to starting between those two zones and we can map those zones throughout the northern part of the basin. It's specifically - it's the B-sand and the C-sand, and most oil wells you will see are drilled into those two zones and when we did collect side walkways in our Ranger 1 well, we saw great porosity and oil saturation in both those zones. So, we always knew that the C was going to be a viable reservoir. And so this was the opportunity to offset the B-sand, which was the first well with this lower C-sand in the second well. Guys?

Yeah, I would just second what Ryan said, this is Ned Frost speaking. And again, I think there is a lot of opportunity within these formations that we talk about you know the Bone Spring, anyone of them has multiple zones that could be landed in and as Ryan alluded to, they both look good. So that was a good opportunity to go ahead and test the C-sand.

Yeah, I'll just add, there was actually a - the A-sand looks pretty good too, so we may have three targets there.

And do you think those could potentially be separate reservoirs?

Yes. They are spread out over 800 feet to 1,000 feet, roughly.

Got it. Great. That's all from me. Thank you.

Thanks, Mike.

Our next question comes from the line of David Amoss with IBERIA Capital Partners. Your line is now open.

Hey, good morning guys.

Hi, David.

You all have talked about the Avalon a couple of times today, but I kind of want to zero in on that, because one of your peers obviously put a bulls eye on your Jackson Trust acreage there, and said that, this is the core, the core of the Avalon. So just want to get your thinking about how to test that, the timing of testing, and then what that threshold maybe before the Avalon specifically becomes a development target, it's competing with what you're doing elsewhere?

So, I'll start, Ned, I'm sure you want to add to that. But this is David, David. The one of the three zones that we're testing initially of Jackson Trust is the Avalon. So, with one reason again for us to add this third rig was to have an opportunity to do this - this three well stack test at Jackson Trust where we were looking at the Bone Spring, the Avalon and the Brushy Canyon. So it is the - it is one of the targets, it is one that we're excited to test and see what the result will be and then we should know that I think by early in the fourth quarter. Ned, I'll let you add to the geologic part of the story there.

Yeah. The Avalon is one that we're always aware of as potential target in that side of the basin, and as you mentioned some of our competitors have really kind of put a bull’s eye on that. And our engineering and Geoscience team I think have done a great job of kid of parsing the results of the Avalon in that eastern part of the Delaware Basin. And really this is kind of the direct return on science dollars, when we drill the Jackson Trust initial well there, we took side walk in a log suite, really the Avalon looks quite favorable in that area. So I think the more that we drill in the basin, the more opportunities we see, it's going to be, as Joe had alluded to, and numerous other people have alluded to, we've tested nine horizons, with an Avalon test here and a Brushy Canyon test, we will have ramped that up to 11 horizons that we we've tested in the basin. And really kind of what we look to be going forward, but we're spending science dollars, is really seeing where each of those zones works. So they're not going to work perfectly in each one of our asset areas, but we're going to continue to really begin to burrow down and hone in on those best targets for each of our asset areas, but yeah, we're extremely optimistic about the Avalon test here in Loving County.

Okay, thanks. And second question just wanted to, it sounds like the commentary recently is much more optimistic on midstream opportunity at Rustler Breaks specifically. So just kind of wanted to get some details on what you plan to build there. The timing of that coming online, and maybe the initial cost maybe?

Yeah David, this is Matt. What we've got in place right now, we've got the salt water disposal facilities put together there in Loving County on the Wolf acreage. We're currently disposing of around 16,000 barrels a day, so that's up and running. We are in the mode to drill an additional salt water disposal well, maybe two there. So that's up and running the second and third disposal wells will be a change for us from going from exposing a most of natural water to those will be primarily third party water disposal, so that will be a go from a cost saving to a revenue generating mode. On the gas plant, we got 30 million, 35 million a day capacity that we will be operational sometime this month, later on this month, right now the facility is basically built going through the testing phase and we hope to be operational by the end of the month. And we spent pretty much on budget for 2015 with $38 million, $39 million investment. In Rustler Breaks, David, the notion of Rustler Breaks is we're looking at doing basically the same thing up there, we're contemplating probably a 60 million a day credit facility up there as well as putting in a salt-water disposal facility.

Okay. And then when do you expect it online, Matt?

The Rustler Breaks will be some time next year, David.

Got it. Thank you very much.

Our next question comes from the line of Dan McSpirit with BMO Capital Markets. Your line is now open.

Good morning folks, and thank you for taking my questions. If we could just turn to the balance sheet, on our model we see leverage moving higher in the out periods although we're sitting at, but are still very manageable levels. Just wanted to confirm that you see the same on your own internal model, and is there a range or comfort level that's used as a guide within the company?

Dan we feel the same way that we're watching the balance sheet. We don't think this in any way, I guess moves us beyond, you can gather one of the strongest balance sheets of any company or size and we plan to remain that way. This was a very prime opportunity to add a lot of reserves and opportunity and evaluation of horizons. As an example, we've increased reserves from a year ago of 52% and 27% since the end of the year to get our total reserves at $87 million barrels. So the money invested in just the two rigs are what we've done year-to-date is pretty remarkable, and with the production coming better than expected, horizon as better than expected. It was just an opportunity to have to needed to be done keep yielding the value. So we keep a careful eye on that balance sheet, we don't intend to compromise it, and we sail along, it's our intention to keep it below two. I wouldn't slit my wrist if it went over a little bit for that depending on value that has any increase in leverage, it gets sticker on what kind of projects we're willing to put additional capital in. So, if the leverage grows, we're going to want a higher rate of return from the projects we're involved in. And to the extent price goes up. We'll be a little bit open, but we are really watching that very closely and both the Board and the staff want to remain financially strong with those options that make sense during the time like this so that if opportunities come up, we can take advantage of them, but if and only if we think we are going to make money from it.

Got it. Thank you.

Does that help, Dan?

It sure did. Thank you, Joe. And as a follow-up if I may, appreciating that we've past the hour mark on this call. The company is now including EURs around certain wells, as identified in the various operations updates. How accurate are these recovery estimates appreciating the still limited production history on the wells. That is, is there potential today's EURs prove more conservative than not, and maybe what these factors are applied in shaping those curves, and how could those change over time?

Yeah, hey Dan it's David, I'll start and Rad or Ryan may want to also chime in. But, I think, that - I think, we feel - we feel good about the estimates that we have for EURs and as you note - as you've noted, the obviously the more information that you have better. But, as an example, I would maybe go back to some of our longest producing wells now, which were the Dorothy White and the Ranger 33 wells, the Dorothy White being the longest producing well that we have at Wolf. And, we had kind of still at the range of sort of 500 BOE to 1 million BOE as that where we thought wells in that area would come out. Really, initially we had about 500 BOE and 700 BOE, and we ended having to ultimately take the Dorothy White up to 1 million BOE type curve. Because of its - it's exceptionally strong performance early on. The nice thing about that is we probably did that within about three months of the time that that well started coming on. And, now 18 months down the road, we haven't had to really make any adjustment if anything it's only continuing to improve, against that type curve. Likewise at Ranger, we kind of started out in the range of 500 MBOE to 700 MBOE, and really both the range of 33 and the Pickard wells, the Second Bone Spring wells have actually also improved against our original type curve estimates and against our original EUR estimate. So I hope that that will continue to be the case. Obviously, when you have two months of data or three months of data, it's not as good as when you have 18 months or approaching two years, but I do feel like that we've - that we continue to be very comfortable with our numbers. With regard to the B factors, I will say that I think that, we probably tend to be a little on the conservative side when it comes to the B factors. Our B factors are typically about 1.1. And I don't - I think that's a very, very reasonable B factor to be using in these estimates. I think it's typically lower than what I've seen some of our peers use. And so I think that we're again comfortable with our estimates there, and should these wells flatten a little more as time goes on and justify a little higher B factor, that will only be good for those estimates, because they would tend to go up from here.

I'll add to what David said, this is Brad Robinson, Dan. We do a lot of work ahead of time looking at the history of wells in the area. We have on our board, as you probably know, a former Vice President of Netherland, Sewell, Rey Baribault, we have a former President DeGolyer and MacNaughton who is an advisor to our board, both very well respected of reserves companies worldwide, world renowned. We also, of course, we have all our reserves audited by Netherland, Sewell. So we may and go over these curves in the parameters, there is a wealth of experience amongst those individuals and those firms and we apply what we believe to be the most accurate parameters to our type curves into our forecast and again all our reserves are audited and we're typically within 5% or less agreement with our independent auditors on our forecasts and our reserves. So we feel very comfortable with the numbers right now, things changed obviously. Most of our wells are still flowing. So what we don't know going forward is how much artificial lift is going to increase those EURs and once we put all these wells in artificial lift, so that might be a pleasant surprise down the road, that might all through the B factor as David pointed out. So at this point, we're very comfortable, maybe we're a little bit conservative but obviously going forward.

In all three areas, the first well we drilled in Wolf, first well in Rustler Breaks, first well in Ranger, those estimates have all been revised efforts two or three times.

That's correct.

So our starting point in each of those areas was fairly low base, and we've raised them three times, but Matador had to be doing that than having to bring them down, so the B factor, 1.1, no one seems to jack to our [indiscernible] agreement, that's a good solid area, safe harbor for our shareholders, for the commercial banks, for every other use that we've had and I think that I really commend the staff for their restraint and the board for they're trying to head and not trying to use more addressing B factor for a headline, but stayed with the what I call, the 1.1 Safe Harbor that is in light or robust output, hope that helped.

It sure did. Thanks, again. And have a great day.

All right.

Our next question comes from the line of Jeff Grampp, with Northland Capital. Your line is now open.

Good morning, guys.

Hi, Jeff.

Hello, Jeff.

Question on back to the rig count, and just kind of go forward thoughts there. Obviously, you guys have done a great job in de-risking your various areas on the Delaware and moving those into development nodes. So, just kind of wondering, if you guys look across your acreage position, what areas are maybe getting close to being worthy of that kind of development rig whether that's a new area like Ranger or Arrowhead or could we even see you guys maybe put two rigs in summer like Rustler Brakes or Wolf?

Well, Jeff that's a great question and that's some that we ask ourselves constantly. Where are we in the development, the delineation of these assets. And, I think, that we're in clear development in Wolf and in Rustler Breaks, and we have a rig there. Now, we've got third rig it's going to be up there in Ranger and Arrowhead, and we'll just have to see the results before committing there, and we're steady in these multiple zones, and as I said, we're just getting our first production from some of these zones right now. So, it's a hard question. We hope that things continue to develop as they have with better than expected results, but I don't want to count the chickens yet. So, we have more history with these wells. But, everything that we see is very encouraging at this point.

Okay. Great. And then, maybe a question for Ryan on completion designs and maybe tweaks or anything you guys have been seeing on recent wells or any plans for kind of upcoming tweaks that you guys may have as you guys kind of continued to delineate your acreage position and optimize things out there?

Yeah. Jeff, we've moved into our second generation design for our Bone Spring and our Upper Wolfcamp a few months back. And so we're starting to get some production data from those well and we typically rate - or we typically have 180 days of production or so from our - from these test wells before we make another evolution to our frac design. So we still have a little bit time left. As far as the results go right now, the results are very promising and the changes we've made. Some of the changes we've done more for the cost reasons, I think Ben Wyatt and Steven asked earlier about change in the spacing in our Bone Spring design. That design change was largely driven to reduce cost. And so we have a mix of cost reductions in our Second Bone Spring - or our second generation designs for the Wolfcamp and the Bone Spring. Here in the next 100 days or so, we're going to - you get a plenty of data and we'll be looking into generation redesign. We anticipate as we move forward through drilling in the Permian Basin for the next - for the years to come, we'll experience many evolutions. Does that help, Jeff?

Yeah. That was great color. Certainly appreciate it and great quarter, guys.

Thanks, Jeff.

Our last question comes from the line of Richard Tullis with Capital One Securities. Your line is now open.

Richard, did we lose you there?

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

All right. Thank you very much. I'd like to thank again for the interest and the questions and the participation. As we've tried to express ourselves, we remain focused on great return, achieving profitable growth at a measured pace, trying to be good stewards and look at long-term, maintaining our flexibility to adjust our drilling plans with the economies of the moment and the outlook, and adjusting our other facets of our operation to the opportunities that may present themselves. Just a quick note that we're also achieving a 30% to 50% rates of return on our recent drilling in the Eagle Ford and in the Haynesville. The Haynesville is actually probably greater than 50%, but it is not a big part of our budget. We'd also like to welcome Rob Macalik to Matador, who is our new VP, Vice President of Accounting and Chief Accounting Officer. He is off to a good start, and thanks to the whole staff and the Board, I think they've turned in what is a fantastic quarter in all respect. And it looks like we're on a good trajectory. So, I really appreciate the extra work and effort that they put into and thank all the shareholders for their support too. We had a great annual meeting. We had over 200 people there, and 99% were in favor. So want to express our appreciation to the investment community too. Please, remember our door is open, we welcome your visits, and hope to see all of you soon. And with that, I'm signing off. Bye.

Ladies and gentlemen, thank you for your participation today. This concludes the program. Have a great day.