Matador Resources Co (MTDR) 2015 Q2 法說會逐字稿

Good morning, ladies and gentlemen. Welcome to the second-quarter 2015 Matador Resources Company earnings conference call. My name is Shinise and I will be serving as 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, Shinise. 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 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 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 are 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 and Administration; Brad Robinson -- 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 has been record production in that not only were these the highest production numbers but the 1.26 million barrels we produced for the past three months it has exceeded our entire oil production for all of 2012, three years ago, the year we went public.

As noted in the earnings release, we have increased our oil production guidance for the second time this year 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 of return for this time of low commodity prices. We are achieving even at $50, 20% to 50% rates of return and as it approaches $60, those rates of return jump up and start to look a little sexy in the 40% to 65% rates of return and these rates of return are improving because we are continuing to get our costs down both from production efficiency and working with our vendors as well as the fact that we have been able to continue to improve our frac designs and make these wells a little better.

The third point I would like to emphasize is that as these costs improve, the rates of return will get that much better. We are making great strides in both our Wolfcamp and Bone Springs horizontal wells. We are working with nine different horizons so we are confident that we will continue to achieve these cost improvements. And if you will note also our LOEs have improved so that in 2014 we had all-in cost on our financials as noted at $47 and $43 and this year we are down there at about $37.

So I want to give great appreciation and thanks to the hard work and professionalism of our staff and our Board of Directors in continuing to achieve these targets.

It goes without saying that we feel not only have we had a good year so far but we are on a solid trajectory for the second half of the year. We have much work ahead of us but we believe we are well positioned, both financially and operationally to take advantage of the opportunities that times like these present.

With that I would now like to turn the call over to the operator for your questions.

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

Operator? Operator, can you hear us?

(Operator Instructions).

Operator, we can't hear you.

Neal Dingmann, SunTrust.

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 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 that acreage a bit further north, do you consider that to be as prospective as some of the success you have already had?

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

Sure, Neal, we have 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 have had pretty good results so far especially in the second Bone Spring. As you remember, our Ranger No. 1 and our Ranger No. 2, our (inaudible) No. 1 all have turned out to be really good wells and those are kind of in that northeastern portion of Lee County. And then beyond the second Bone Spring we have drilled some third Bone Spring wells too.

Here recently we drilled our Cimarron well and it came in around 800 barrels of oil per day. So we are really excited about the results we have seen so far and certainly we are excited about what is to come considering we merged with HEYCO and they have a lot of acreage on the northern (inaudible) of our basin.

Ned, do want to add anything about the second Bone Spring potential? As you know, our EUR estimates for the Bone Spring are in the 350 to 650 MBOE territory and these are all very high oil cuts too. These are all 80%, 90% oil cuts and we are actually putting a rig to work, our rig number 809 is destined to be the 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.

I would just follow up on what Ryan said, this is Ned Frost speaking. I think we are 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 are continuing to view this as a fruitful area for us.

This is Matt. I just might add too, the Bone Spring that Ryan is talking about is normally pressured and it does respond very well to artificial lift. We have used both gas lift and ESP in this zone and it responds very favorable.

Are you still picking up just last follow-up, is there bolt on, is there more acreage in that approximate area still available?

Yes, we think that we will continue to pick up acreage in that area, they are not going to be huge chunks or large ranches that you have like in South Texas. But if you just stay after it, you will 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.

Scott Hanold, RBC Capital Markets.

Thanks. Good morning, guys. Sticking obviously to the Permian since it is a key area for you guys right now, you have 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 driver of that concept and the potential implications on your oil/gas mix when you look at your acreage position?

It is David. 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 have had at Rustler Breaks in particularly in the Wolfcamp. We continue to have very good success at Wolf drilling the Wolfcamp XY there at the top of the Wolfcamp interval. But our geoscientists have done a great job of really sort of identifying and helping us extend that play to the Northwest into Eddy County there in the Rustler Breaks area.

And so we have drilled several very attractive Wolfcamp A and Wolfcamp B wells. Clearly the Guitar well was a very good well for us, that was sort of the first one we had tried in the XY interval there at the top of the Wolfcamp and it was a very good well as you recall. The one we recently reported on of course, the Tiger 124 was the second test like that that we did and it was as I recall in the 1400 BOE per day IP range.

Of course the Wolfcamp B, we feel like that well is still tracking our 1 million BOE type curve. So we have been really, really encouraged by the recent results that we have seen in the Wolfcamp there and I think when we refer to emphasizing the Wolfcamp a little more, that is one area where we are doing so. So our mix of wells going forward this year will 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 part of your question with regard to the gas mix, I mean actually I think we have been really pleased with what we have seen in that Wolfcamp XY because our wells there tend to be about 80% oil cut which is as good as if not even a little better than up in Wolf. So I think that interval has also a very attractive oil cut.

And so that is a lot of the rationale behind our decision there, Scott. We are really extremely pleased and excited with the results that we are seeing there.

Scott, I will add, our results have been very repeatable in our Wolfcamp wells. We look at the very first well we drilled down in our Wolfberry on our Dorothy White well, it was one of the best wells we have ever drilled as a company and as we have gone in there and started to develop in the Wolfcamp X and Y, we have been able to repeat those results and drive the costs down which further boosts the rate of return.

And there is a variety of reasons why we are focusing on the Wolfcamp beyond that too. I mean the Wolfcamp units hold 320 acres, they hold from the Wolfcamp all the way to surface whereas if you drilled a Bone Spring well first, you wouldn't necessarily hold below the Bone Spring. There is some land reasons why we are doing the Wolfcamp but I think it is mostly dominated by just the wells you are just turning out just phenomenal and we are trying to move into a farming operation in our Wolf area and we are pointed in that direction in our Rustler Breaks area as well.

Scott, this is Matt. I just want to kind of underscore what Ryan said there, it is something that we have been able to repeat over and over when we move into these developments. We are able to go in and really drive well costs down and improve the completion designs on a particular interval.

So I think what you are seeing is a move in that direction as well where we are going to really capitalize on operational efficiencies and get in more into the development mode with the Wolfcamp.

That is all I've have got. I appreciate, that is some good context. I guess for my follow-up question for 2016, Joe, can you provide a general framework of what you all are thinking at this point in time. 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 a 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?

Yes, Scott, it is the same way we look at 2015. We are very right of return driven and we are not going to do something we don't have that kind of -- we don't have lease expirations that we have to go drill and we don't have to do this. We gave it a lot of thought on the CapEx whether to take this third rig and boost the CapEx. And of the CapEx I think it is, the boost in CapEx, one-third is related to this rig one-third is we are achieving great cost savings and there is profitable opportunities from our midstream so we have 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 costs, that has been a big portion of it.

In addition, the leasing opportunities that we have seen now that we have delineated a lot of these areas, we can see opportunities and so as they have come along, we've tried to take advantage there.

But the boost in CapEx was something that 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 the economics were so strong for it and would allow us to continue to build the organization and gain expertise. So one of the key points as we conferred on all of this was the fact that we had nine different horizons and each horizon will drill differently and need to be treated differently and you needed that extra rig to address that.

Things were going so well for us in Wolf you needed to leave one rig there, things in Rustler Breaks were knocking it out of the park so you sure wanted to leave a rig there. Ranger and Arrowhead looked so promising, the Cimarron well that Ryan referred to earlier is strong as the Ranger performed. It is actually looking a little stronger and is leading to other areas.

The Arrowhead, which is a lot of the HEYCO acreage is very, very promising and so we felt we needed to put a rig there to really learn and delineate the area and that the economics of the Ranger well, the Cimarron, some of the non-operated wells up there in the HEYCO acreage certainly justified a third rig. And so we are putting it there to continue to make money, grow the value of Matador and we see the rates of return going to get better, much like South Texas and the Eagle Ford. When you compare what we drilled the first well there for versus the last eight wells, those last eight wells had some of the best rates of return of any that we drilled.

So that is the confidence that the staff feels there is a lot of ways with the state-of-the-art drilling rigs we have and the tweaks we are going into the next generation of frac, everything is clicking. And you really couldn't refuse a rig in the [Glackton] area that is going make you a lot of money like Arrowhead and Ranger. So that was the thought.

There was a lot of discussion of the pros and cons and ultimately it was just too ripe an opportunity and that if we moved the second rig away from Rustler Breaks we would be hurting the company and we think it is more important to keep it growing and setting up 2016.

So as we get to 2016, we are going to have three rigs working. We are going to see how productive they are and we are going to compare a comprehensive look. But we are building for the long-term, Scott and we will look to see where we are and whether we can make a rate of return. But if we can't make a very reasonable rate of return with the prospect of improving that as we get to know it, we are going to do it.

The best guidance I can give you at this point is that is going to be one of our main priorities for the next few months, working with David and continuing to monitor how these wells turn out. We are doing a 3 zone pad down there, a valuation in the Jackson Trust on some shallower zones so that will play a key role. And David, what am I leaving out?

David Lancaster

Joe, actually I think you covered it very well, the last little comment 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 are 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 Brushy part of the Delaware.

And so we are looking at those intervals as well and again that could set us up very well for a real development opportunity there at Jackson Trust.

I think the addition of the third rig was to help us do all of those things in preparation for 2016.

And we felt we could afford it and we have always tried to be prudent on the money and disciplined. And it was a thorough and I would say lively discussion but in the end it was just the opportunities were too profitable just to turn away from arbitrarily because of price because you never know.

If you make money today at $50 as we are with our all in costs and some of our finding costs are down there in the $11 and $12 area, reducing the LOE if you make money at $50 we feel very strongly that we will do better as the year goes along because we are continuing to make adjustments and I still think prices will 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 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've targeted already so there are a lot of efficiencies that are gained by continuing the momentum we have. We have 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 learnings and expand and have two of the rigs working on development type projects and it is a small delineation component in the third rig that is pretty much in the delineation mode for the remainder of the year and into 2016.

Scott, I will be the one to finish this long (multiple speakers). There were several wells we drilled this year with the specific intention to set up 2016. Just going down the list, 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 recently brought on line and it peaked out that 400 BO per day which is right in line with where we expected and it is going to get right in the range of our EUR estimates for the Bone Spring but it came in well below our estimated costs. Again, our Tiger second Bone Spring well again came online. It has done very nicely since it came online, right in there 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 northernmost tip of our acreage block on our Scott Walker well as part of our delineation program. And so this again -- as this well we get the results back from this well has major implications for our drill schedule in 2016.

So you can see that most of the wells we have drilled this year have 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.

Appreciate all of that color, guys. Thanks.

Irene Haas, Wunderlich Securities.

So if I might ask two questions. Firstly, it is 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 an upswing during the first half of 2016? That is question number one.

Question number two has to do with the Twin Lake area I am really excited that you're going to go in and drill a 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 like the first mover in that specific area.

High, Irene. It is David. Good morning. I will 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 is probably when we are going to first see the impact of production from the third rig. Given that we 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 will drill five or six wells probably by the end of the year, they will be completed toward the end of the year, some of them just right at the end of the year or first of 2016. So I think that is when you will start to see the first production from that come in and as a result, our production should pick up.

With regards to the second half of 2015, as you said, that is understandable and I think that is right, nothing different than what we have said all year long except for the fact that I think we probably peaked out at about 1000 barrels a day higher than we thought we would see or that we reached these current levels at 13.8 or so for this quarter which was substantially better than what we thought. And I think reflects the success of the wells that we have 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 eight Bishop-Brogan wells that we drilled in the Eagle Ford.

So now we have 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. I think you have got it right in terms of how the profile is 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 would just ask Brad and Ned to make their comments. Brad is the Head of Reservoir Engineering and Ned is our Head of our Geoscience Group.

Hi, Irene. This is Ned Frost. I think we are continuing to be encouraged by Twin Lakes and as we mentioned, we do have two wells that we plan here. We have I think it is hard to know exactly what it will take to delineate that trend but we have our [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 D to collect data and get a sense of it there.

And then in the Western part of Twin Lakes, we have a [Kimness] well permitted so really what we are seeing is we think we will get to these in probably the fourth quarter of 2015 to the first quarter of 2016.

Really one of the things here thus far when we collect data, we really are seeing pretty immediate returns on those science dollars. 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.

Brad, do you have anything you want to add?

Yes, I will just add to what Ned was saying, Irene. We of course have always like this area, it has been 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 is in the shallower areas and we do think it is probably going to be two wells to answer your question.

The Western part of our acreage, the Wolfcamp D or Penn Shale interval is over 800 feet thick and it is a solid oil column. We have got multiple targets there so it could take some additional wells to identify those multiple targets within the Penn Shale interval. That is an extension of the Pickard well that we drilled and we are real pleased with the results from our Pickard well where we tested the Wolfcamp D.

The whole area that is -- there have been a lot of drill stem tests, those are open hole tests that are conducted when people are drilled and they have gotten oil from the Penn Shale for years from these drill stem tests. So we know the intervals are productive of oil, we want to test it with modern technology, horizontal wells, hydraulic multiple hydraulic fractures and we think that it can be a substantial resource. We are real excited about testing it.

Just to elaborate a little more on what Brad said, our Pickard number two well was drilled into the 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 ex sand.

And so in the Wolfcamp ex sand in our Wolf area, that is the zone that gives us a lot of deliverability that is charged by the shale and so that is what we are looking for up in the Twin Lakes area and if we can find that zone, we feel like it is the recipe for success up in the Twin Lakes area. It has been a success down in the Wolf area and so that is what we are looking for.

As far as the development of that Twin Lakes area, we think it is just going to be very reminiscent of what you have 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 and into development. 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, we really kind of need to probably look more like what you guys are doing in Wolf sort of in situ model rather than a Bone Spring type completion. So should we expect quite a bit of reliability and continuity because you are 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. We will get rock mechanic data from the core, we will get permeability data but I would expect that you are going to see kind of an in situ or microcoupled type frac design in this area. We put the in situ design on the Pickard No. 2. If we can find that Wolfcamp ex sand equivalent up in the Twin Lakes area, then it would be a little bit closer to the microcoupled.

But I can guarantee you it is going to have a lot of sand and a lot of fluid and we are going to hit it with a lot of horsepower.

That is great. Thank you so much.

Ben Wyatt, Stephens.

Good morning, guys. Just have a quick question maybe around the Bone Springs. One, wanted to see if you guys could remind us maybe on the spacing of stages in the Bone Spring? And then just curious based on kind of where the spacing is now in the permeability of that zone is there in the chance that you could actually widen the stages there and lower well costs even more?

Ben, this is Ryan. That is what we have done as we have moved from our generation one design to our generation two design. The first generation was 50 feet between clusters and we have moved to 75 feet between clusters and the purpose of that move was exactly how you described it, just to cut costs. We felt like we were over-fracking at 50 feet and we can get the same effect with 75 foot spacing.

We did keep the amount of sand the same per cluster but since you have spaced it out to 75 feet instead of 50 feet, it just makes it 1300 pounds per foot but we are still hitting each frac at the same amount.

Got it. Very good. Maybe just, Matt, on the artificial lift, you mentioned kind of ESP. Will you guys do that based on the zone with Bone Spring or will that go across the entire Delaware at all three of your different zones? How are you just kind of thinking of out testing the different artificial lift on each well?

Ben, that is a good question and we are very favorable to gas lift. We are work -- it is a very cost efficient way to lift high volumes of fluid, both water and oil so there is a component to the gas lift that we like a lot in that we can run the tubing during the initial installation in the well, run the gas lift valves and the well will flow for whatever time period that it is allowed to flow. And then the gas lift valves just sit in place and once the well starts needing a little help we just start up the gas compressor and start injecting gas down the back side so it is a 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 is I guess our first test if you will on the ESP and there were 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 rod lifts but it will be down when they get any 100, 150 barrel a day range. I would like to ask Trent Green, our VP of Production, to add his thoughts as well.

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

Ben, we have also run an ESP down in Loving County on the Wolf acreage on one of our Norton Schaub wells and it is early on but the results look good for that as well.

Got it. Care to comment maybe on just what the difference in cost would be if you go ESP versus gas lift?

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

One of the advantages on the gas lift as well is it is kind of an automated system. Once you start injecting gas, it starts lifting off the top valve and as the well dictates, it will ultimately work its way down to the bottom of the valve so there is some advantages there as well just comparing the operating expense on the gas lift is around $4000 a month.

About $4000 a month is correct, about $12,000 on the ESP due to the electricity.

Very good. I appreciate it. Keep up the good work.

Brian Corales, Howard Weil.

I just have a follow-up kind of to Scott's question on 2016 and I know you all 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?

So to first answer your question, Brian, this is David. Yes, you are right on the run rate for the rest of this year, about $80 million a quarter is right. 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 with the three rigs or if we would look to modify that in any way. And also I am not certain at this point what we might look to do in terms of additional midstream investment or land or even nonoperating opportunities. We've had a few more of those even come our way.

so I think actually that will probably be the difference but I think that if 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 would like to emphasize is that our base case is the three rigs and we are not going to four rigs unless we think we can make money or add value and achieve a desirable rate of return. What I do always try to suggest is we view this very broadly, we don't look at it from a single variable but we take a lot of different variables into account and circumstances what can we achieve with another rig and what is the rate of return and how does it affect what else we are 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 the rate of return.

The fourth rig we will look at that and if price of oil is $40 and we can't make money, we are not going there. The same thing, if we are not making money, we can give up one of these three rigs, it is not like we have to use it.

So we are trying to maintain our flexibility and change according to the times and take advantage of the times. That is 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 are driven not for growth sake but as Matt said, trying to achieve profitable growth at a measured pace. So we are headed into this.

And the other thing that has worked for us is the rigs have added productivity and the staff on the rigs, on this third rig, we staff it with the same people as one of our old rigs. So they got up and running from day one and we have already moved it twice just in these first days and everything is working and clicking on it.

So we may not need, we may be able to do with three rigs what four rigs could do a year ago with these rigs. They are just more productive and would invite any of you all out to see them because they are just remarkable with the better pump systems and Billy can tell you all the features but they have got great experienced people and great systems and that we are confident that we are going to do -- we will approach doing with three what once would have required four rigs. Matt?

I think you summed it up well, Joe. It has been really fun to watch. When you go from 43 days on a well to 23 days on the same type well, that is a big jump in productivity and the rigs are built specifically for our purpose and a lot of the features that we have 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 are moving new rigs in but we are really proud of the rigs that we put together and really proud of what they have done for us.

That answer your question? Does that help?

That was very good. That was very helpful. Just one more, with this three rig program though it sounds like -- can you at least kind of keep production flat or can you potentially see growth if this -- you are at your current productivity and obviously it is likely to get better but could you see production growth next year at this level of activity?

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

All right, guys. Thank you.

Mike Scialla, Stifel.

Good morning, everybody. Joe, I think you just answered my question. But maybe just to investigate a little more, you talked quite at length about the decision to add the third rig, the focus on the rate of return and the opportunity set in front of you. It sounds like if I heard you right, $40 is based on your current returns is kind of a spot where you would actually slow down and would you drop one rig or do you have flexibility to get rid of even more if need be?

Mike, that was an arbitrary number I put, it is not 40 or 41 or 42 because again what I've tried to stress, we are 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 is a comprehensive look and you know how we meet as a group and we sit around here and discuss and that is what happened on the third rig is everybody worked 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 operations. So there is just a lot of reasons to do that.

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 a rig or drop a rig depending on what is best for the shareholder value of Matador.

We don't have to do any drilling. On the other hand, we got the wherewithal to take advantage of special opportunities that may arise and we are 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, we are not flaring any gas at all of our wells are hooked up to pipe. There is a little bit of flaring because of pipeline issues but that is not us, that is a pipeline that is having to make some adjustments. Ours are hooked up, they have priority. We are working with people, that is emerging as a real value creator.

So the deal that we discussed after hard thought, the third rig clearly offered a lot of advantages and next year we are going to begin to look at the same thing. If Arrowhead and Ranger turn out Rustler Breaks and Wolf, we are going to look hard but we will look at whatever price it is and make sure it makes sense.

But I feel confident that if any of you were in on these meetings with us you would have reached the same conclusion that the third rig is going to help build the long-term value of Matador and there were a lot of reasons to do it and not many reasons not to do it if you were interested in building the overall value of Matador.

It is just like our decision to go into midstream, that has had the same effect of building the overall value of Matador and I think you are already starting to see the benefits of that in both saltwater disposal and by the end of the month when we have the gas processing online, that will give us further options.

Did that answer your question, Mike?

Yes, great. It does, it did. I was just -- I understand these reasons, understand and appreciate your thought process behind it. Just kind of wanted to investigate the downside and the flexibility if oil prices were to head down not to try to pin you down to a specific number but --.

And the same light on oil price, you don't want to just look at what the price is today but what is the outlook going forward and what are further productivity savings you get or the further cost savings and drilling and some delineation, what is the value of delineation?

We have got nine horizons, we need to do some testing of those. So I think we are 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 since inception and going back to first Matador, we have always tried to look at what builds the long-term value and builds up the company. We are building be kind of staff that can double the company in a short space of time and our people here are getting better as they get more experienced in the Delaware.

David, you and Matt are pretty articulate. I think it is a pretty easy reason when we finally got to it.

I think the long-term view is the most important thing here. We do have a very rich set of opportunities that we need to determine how we are going to develop. And the good news about low oil prices or low service company prices, the good news about continuing to run these rigs and getting these operational efficiencies going are those stick with you. So on the long-term approach, we are able to go in and Ryan is able to tweak his frac designs at low cost and we are able to look back and see what it is we need to change, what we want to change, how we are going to as we always say drill better wells for less money. So the long-term view I think is the most important thing here.

Just wanted to ask a specific question on Ranger, that recent second Bone Spring well you drilled that in a lower bench you said than the earlier wells. I am just wondering is that because you think there is maybe a separate reservoir there that you can develop in the stack nature or is that because you are looking at that as maybe the optimum landing zone?

Mike, this is Ryan. I think there are several people around the table who can chime in on this but I will just start it. When we drilled the first Ranger well we had a hard time deciding between those two zones and we can map those zones throughout the northern part of the basin specifically it is the B sand and the C sand and most all wells you will see are drilled into those two zones. And when we did collect sidewalk cores in our Ranger No. 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.

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, Bone Spring, any one 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.

I will just add there was actually -- the A sand look pretty good too so we may have three targets there.

And you think those could potentially be separate reservoirs?

Yes.

They are spread out over 800 to 1000 feet roughly.

Got it. Great. That is all for me. Thank you.

David Amoss, IBERIA Capital Partners.

Good morning, guys. 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 bull's-eye on your Jackson Trust acreage and said this is the core of the core of the Avalon. So just want to get your thinking about how to test that, the timing of testing it and what that threshold may be before the Avalon specifically becomes a development target that is competing with what you are doing elsewhere?

I will start and Ned I am sure will want to add to that but this is David, David. You know, one of the three zones that we are testing initially in Jackson Trust is the Avalon. So one reason again for us to add this third rig was to have an opportunity to do this three well stack test at Jackson Trust where we are at the Bone Spring, Avalon and the Brushy Canyon. So it is one of the targets, it is one that we are excited to test and see what the result will be and we should know that I think by early in the fourth quarter.

Ned, I will let you add to the geologic part of the story there.

The Avalon is one that we were always aware of as a 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 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 drilled the Jackson Trust initial well there, we took sidewalk cores and a log suite and 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 is going to be as Joe has alluded to and numerous other people have alluded to, we have tested nine horizons with an Avalon test here and a Brushy Canyon test, we will have ramped that up to 11 horizons that we have tested in the basin. And really kind of what we look to do going forward both with spending science dollars is really seeing where each of those zones works.

So they are not going to work perfectly in each one of our asset areas but we are going to continue to really begin to burrow down and hone in on those best targets for each of our asset areas. But yes, we are extremely optimistic about the Avalon test here in Loving County.

Okay, thanks. Second question, it sounds like your commentary recently is much more optimistic on the 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 what the initial cost may be?

Yes, David. This is Matt. What we have got in place right now, we've got the saltwater disposal facility put together there in Loving County on the Wolf acreage. We are currently disposing of around 16,000 barrels a day so that is up and running. We are in the mode to drill an additional saltwater disposal well, maybe two there so that is up and running.

The second and third disposal wells will be a change for us from going from disposing of mostly (inaudible) water to those will be primarily third party water disposal. So that will go from a cost savings to the revenue-generating mode.

On the gas plants, we have got 30 million, 35 million a day capacity that will be operational sometime this month, later on this month. Right now the facility is basically built. They are going through the testing phase and we hope to be operational by the end of the month.

We spent -- it was pretty much on budget for 2015, it was a $38 million, $39 million investment.

And Rustler Breaks, David, the notion at Rustler Breaks is we are looking at doing basically the same thing up there, we are contemplating probably a $60 million a day cryo facility up there as well as putting in a saltwater disposal facility.

Okay, and then when do you expect that online, Matt?

The Rustler Breaks will be sometime next year, David.

Got it. Thank you very much.

Dan McSpirit, BMO Capital Markets.

Good morning folks and thanks 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 sitting at what are still very manageable levels. Just want to confirm that you see the same on your own internal model and is there a range or comfort level that is used as a guide within the Company?

We feel the same way that we are watching the balance sheet, we don't think this in any way I guess moves us beyond anything other than one of the strongest balance sheets of any company our size and we plan to remain that way. This is a very prime opportunity to add a lot of reserves and opportunity and evaluation of horizons.

As an example, a year -- we have increased reserves from a year ago of 52% and 27% since the end of the year to get our total reserves up to 87 million barrels. So the money invested in just the two rigs or what we have done year to date is pretty remarkable and with the production coming in better than expected, horizons better than expected, it was just an opportunity that needed to be done to keep building the value.

So we keep a careful eye on that balance sheet. We don't intend to compromise it and we have said all along it is our intention to keep it below 2. I wouldn't slit my wrist if it went over a little bit for that depending on value but as any increase in leverage, it gets stickier on what kind of projects we are willing to put additional capital in.

So if the leverage grows we are going to want a higher rate of return from the projects we are involved in. And to the extent price goes up, we will 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 a 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 them.

Got it. Thank you.

Did that help, Dan?

It sure did. Thank you, Joe. As a follow-up if I may, appreciating that we are 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 it is still limited production history on the wells, is there potential today's EURs prove more conservative than not? And maybe what B factors are applied in shaping those curves and how could those change over time?

I will start and Brad or Ryan may want to also chime in. But I think that we feel good about the estimates we have for EURs. As you have noted, obviously the more information that you have the 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 well, the Dorothy White being the longest producing well that we have at Wolf. And we had kind of set up a range of [500,000] to 1 million Boe as to where we though wells in that area would come out. Really initially we had about 500,000 to 700,000 and we headed up having to ultimately take the Dorothy White out to 1 million BOE type curve because of its 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 has only continued to improve against that type curve.

Likewise at Ranger, we kind of started out in a range of 500 to 700 Mboe and really both the Ranger 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 estimates.

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 is not as good as when you have 18 months or approaching two years but I do feel like we continue to be very comfortable with our numbers.

With regard to the B factors, I will say that I think 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 think that is a very, very reasonable B factor to be using in these estimates. I think it is typically slower than what I have seen some of our peers use. And so I think that we are 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 will add to what Dave 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, Reynard Baribault; we have a former President of to Collier McNaughton, who is an advisor to our Board, both very well respected reserves companies worldwide, world renowned.

We also of course we have all of our reserves audited by Netherland Sewell so we meet and go over these curves and parameters. There is a wealth of experience amongst those individuals and those firms and we apply what we believe are to be the most accurate parameters to our type curves and to our forecasts and again all of our reserves our audited. And we are typically within 5% or less agreement with our independent auditors on our forecast and our reserves. So we feel very comfortable with the numbers right now, things change 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 once we put all of these wells in artificial lift. So that might be a pleasant surprise down the road, that might alter the B factor as David pointed out.

So at this point we are very comfortable, maybe we are a little bit conservative but we will see going forward.

In all three areas, the first well we drilled in Wolf, the first well in Rustler Breaks, the first well in Ranger, those estimates have all been revised upwards two or three times. So our starting point in each of those areas was a fairly low base and we've raised them three times. But I would much rather be doing that than having to bring them down. So the B factor of 1.1, no one seems to object to. Everybody is in agreement that is a good solid area safe harbor for our shareholders, for the commercial banks, for every other use that we have had. And I think that I really commend the staff for their restraint and the Board for the restraint they had in not trying to use a more aggressive B factor for a headline but stayed with what I call the 1.1 safe harbor that is then later revised upwards. I hope that helped.

It sure did. Thanks again and have a great day.

Jeff Grampp, Northland Capital.

Good morning, guys. A question on back to the rig count and just kind of go forward thoughts there. Obviously you guys have done a great job in derisking your various areas out of the Delaware and moving those into development mode. So just wondering if you guys look across your acreage position what areas are maybe close to being worthy of that kind of development rig whether that is a new area like Ranger or Arrowhead or could we even see you guys maybe put two rigs in somewhere like Rustler Breaks or Wolf?

Jeff, that is a great question and that is something that we ask ourselves constantly, where are we in the development and delineation of these assets? And I think that we are in clear development in Wolf and in Rustler Breaks and we have a rig there.

Now that third rig is going to be up there in Ranger and Arrowhead and we will just have to see the results before committing there and we 0are studying these multiple zones and that as I said, we are just getting our first production from some of these zones right now. So it is a hard question.

We hope that banks continue to develop as they have with better than expected results but I don't want to count the chickens yet until we have more history with these wells but everything that we see is very encouraging at this point.

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 continue to delineate your acreage position and optimize things out there?

We moved into our second-generation design for our Bone Spring and our Upper Wolfcamp here a few months back and so we are starting to get some production data from those wells. And we typically have 180 days of production or so from these test wells before we make another evolution to our frac design. So we still have a little bit of time left. As far as the results go right now, the results look very promising on the changes we have made. Some of the changes were done more for the cost reasons.

I think Ben Wyatt at Stephens asked earlier about changing the spacing on our Bone Spring design. That design change was largely driven to reduce costs and so we have a mix of cost reductions in our second generation designs for the Wolfcamp and the Bone Spring.

Here in the next 100 days or so, we are going to get plenty of data and we will be looking in the generation three design. We anticipate as we move forward through drilling in the Permian basin for the years to come, we will experience many evolutions to the current design. Does that help, Jeff?

Yes, that was great color, certainly appreciate it and great quarter, guys.

Richard Tullis, Capital One Securities.

Richard, did we lose you there?

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

Thank you very much. I would like to thank you again for the interest and the questions and the participation. And as we have tried to express ourselves, we remain focused on rate of return, achieving profitable growth at a measured pace, trying to be good stewards and look out 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 are also achieving at 30% to 50% rates of return on our recent drilling in the Eagle Ford and in the Haynesville. In the Haynesville it is actually probably greater than 50% but it is not a big part of our budget.

We would 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 have turned in what is a fantastic quarter in all respects and it looks like we are 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. With that, I am signing off. Goodbye.

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