Mac Schmitz - Capital Markets Coordinator Joseph Foran - Chairman, Chief Executive Officer and Secretary Matthew Hairford - President Trent Green - Vice President Production David Lancaster - Executive Vice President and Chief Financial Officer Bradley Robinson - Senior Vice President of Reservoir Engineering and Chief Technology Officer Van Singleton - Executive Vice President Land Billy Goodwin - Senior Vice President of Operations Ned Frost - Chief Geologist Gregg Krug - Senior Vice President and Head of Marketing & Midstream

Gabriel Daoud - J.P. Morgan Securities LLC Scott Hanold - RBC Capital Markets Michael Scialla - Stifel, Nicolaus & Co Ben Wyatt - Stephens, Inc. Jason Smith - Bank of America Merrill Lynch Irene Haas - Wunderlich Securities Neal Dingmann - SunTrust Robinson Humphrey Jeffrey Robertson - Barclays Capital Inc. Gordon Douthat - Wells Fargo Securities, LLC Jeff Grampp - Northland Capital Markets Michael Breard - Hodges Capital Dan McSpirit - BMO Capital Markets

Good morning, ladies and gentlemen, welcome to the Second Quarter 2016 Matador Resources Company Earnings Conference Call. My name is Gabriel and I will 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 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 August 31, 2016 as discussed in the Company’s earnings press release issued yesterday. I will now turn the call over to Mr. Mac Schmitz, Capital Markets Coordinator for Matador. Mr. Schmitz, you may proceed.

Thank you, Gabriel. Good morning, everyone, and thank you for joining us for Matador’s second quarter 2016 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 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 and its most recent and report on Form 10-K. Finally, in addition to our earnings press release issued yesterday, I would like to remind everyone you can find a short presentation summarizing the highlights of our second quarter 2016 earnings release on our website on the presentation and webcast page under the Investors tab. I would now like to turn the call over to Mr. Joe Foran, our Chairman and CEO. Joe.

Thank you, Mac, and good morning to everyone on the line and thank you for participating in today’s call. As always we appreciate your time and interest in Matador very much. Now I would like to introduce the senior members of our operating staff joining me this morning 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; Van Singleton, Executive Vice President of Land; Brad Robinson, Senior Vice President of Reservoir Engineering and Chief Technology Officer; Billy Goodwin, Senior Vice President of Operations; Gregg Krug, Senior Vice President and Head of Marketing & Midstream; Matt Spicer, Vice President and General Manager of Midstream; Trent Green, Vice President of Production; and Rob Macalik, Vice President and Chief Accounting Officer. The second quarter was full of milestones and achievements for Matador and I’d just like to make a couple of simple points before taking your questions. The oil, natural gas and total production grew significantly, those numbers and our cost numbers speak for themselves. Secondly, the new cryo plant that we have at Rustler Breaks is nearing completion and will be operable in the next few weeks. Most importantly, we were on time and on budget. The trunk line is already working and I want to complement our Midstream Group for the first time they built a cryo plant, this team, together, they did it in other areas, they brought the Wolf plant on, on time, on budget. This plant now in Rustler Breaks is twice the size and it also has been done on time, on budget and we look forward to having it operational in the very near future. So, with that, let me turn back to the operator to introduce the questions.

Yes, sir. Thank you. [Operator Instructions] And our first question is coming from Gabe Daoud.

Hey, good morning, Joe, good morning, everyone.

Hi, Gabe.

Gabe.

Nice quarter, guys. Just I guess a couple of things from me maybe first, LOE down sequentially quite a bit. Just wondering – and obviously getting below your guidance for fourth quarter, any reason why I guess moving forward that would revert – I guess trying to think if there was any one time items in 2Q that would increase that moving forward?

Gabe, this is Matt. And you know we have had a great quarter, $5.17 is a great LOE number and the team has done a great job in reducing those costs. And we talk about them on a unit basis, but on an absolute basis we were 2 million or so of – 15% to 20% less on the quarter on an absolute basis. So going forward that may creep up a bit, but we are really excited about the changes we made and looking forward to the third quarter.

Yes, this is Trent Green. I just want to echo what Matt says and give a shout out to our field crews who were instrumental in making these happen as well. But, yes, we continue to optimize and we expect these numbers to be in the range as we go forward.

Yes, Gabe, we were helped some by the record gas production, always has a little less list cost, so it may edge up a bit in this next quarter, but we think it will stay down in this area. And then for the year our LOE cost will be down as well as cost in our other categories, G&A, all the different unit costs will also improve over the next six months. So, what we say in guidance is probably pretty accurate. It will be in this range, it may creep up a little bit in the next quarter, but then it is likely to come down the next.

Great, thanks, guys. That is helpful. And then, Joe, I guess in the release you had mentioned ways to fund I guess the outspend for 2016. Would you mind maybe just sharing some more color on the options available to Matador? Obviously I guess one being the cryo plant at Rustler Breaks. Could you just maybe give us a little bit more color on that and specifically the potential for a JV as well?

Sure, Gabe. Let me just begin by saying we have nothing borrowed, we still have cash in the bank, we have nothing borrowed on our line of credit. So there is $300 million there. The indication from the banks is they would be happy to lend on the cryo plant particularly once it is operational. So, there is no – we can access that if we wish. We do think a couple of things, and first let me go through our Midstream assets what our range of – up at Wolf we still have the three pipe system which is gas gathering, water gathering and oil gathering. So that is something that we could make a deal on that we still own and we think it has substantial value. And then over in Rustler Breaks we already have operational the 12-mile trunk line coming into the plant, it goes North and South across our acreage. So that is operational and working and we’ll have the three pipe system behind that, gas gathering, oil gathering and saltwater disposal gathering. So you have got quite a few assets there to pick and choose if you want to sell one or all or whatever you want to do. We felt on this as we were staying on budget, on time that we would increase the value that the value of the plant would increase by going operational so somebody wouldn’t have to take a chance. Will it work, will it not work? We think we can demonstrate in a few weeks that it is going and that it is efficient and one other important point is that with the outperformance of our wells we are able to fill up the plant for it to go efficient from day one. We will have –…

I just want to – I think you said it very well. I just want to underscore a couple things that you said and circle back to Wolf and the midstream assets we have down there. As we have mentioned to people what we sold to EnLink was simply part of the trunk line and the actual processing facility. We retained the Joe caused it the three pipe system. So, we are gathering in disposing of water. In the saltwater disposal facility we have there is commercial, we are taking on third-party water. We are disposing of north of 40,000 barrels a day. So, we do have all the gathering and disposal there at Wolf. And then what you said earlier, Joe, about building these plants to fit our needs, I think that is very important. We did it at Wolf; we are doing it at Rustler Breaks. So we will have 60 million and we are bringing on the plant efficiently at a little over half, but we have the optionality to expand there as well. The midstream guys have built the gathering system there to accommodate 150, 200, 250 million a day depending on pressure. So, as we expand that thing it will be again need based on our behalf.

With potential for an increase in its value to someone else if we should go that route. The third menu option of course is some of the assets that we have in the Haynesville and in the Eagle Ford and the Delaware has now overtaken earlier than we had previously expected, the Eagle Ford in the amount of value and production that we are getting from it. And while we liked our returns from the Eagle Ford and very grateful because it helped us get to where we are today, we also realize that it is not as strategic to us as it once was. And that just as we have tried to prove and sell in first Matador and selling part of our Haynesville to Chesapeake is we want to be value conscious and do what is best for our shareholders. And so, we are open to any of those alternatives - the plant and then finally I think you acquired about the idea of a JV. It is not that we are seeking a JV necessarily, but we want to be clear that we are open to the best whatever it is – the best deal for our shareholders. Gabe?

Yes, no, that is great color, everyone. Thanks, thanks a bunch. If I could just squeeze in one more. Joe, you mentioned Chesapeake and Haynesville and this morning I think they announced a desire to sell potentially 130,000 net acres or so. How if at all would this impact I guess Elm Grove and the property that they operate for you guys? Just trying to think about that. Thank you.

Well, I may ask David to share this with you; I don’t know what 130,000 acres they are selling. I would be surprised if it was Elm Grove because that has been their best area.

Gabe, it is David, hey. We just saw the announcement too this morning and really we haven’t really had anytime to dig into it. And as Joe said, don’t really know what it is that they are selling. So, but certainly Elm Grove has been one of the best spots for – I think for Chesapeake. So if they are keeping any of it I would expect they are keeping that.

Sure, makes sense. Thanks, David. Thanks, everyone. I will hop back in.

Thanks, Gabe.

Thanks.

Our next question comes from Irene Haas from Wunderlich. Ma’am your line is now open.

I have a question on the Rustler Breaks area. I mean obviously your plant is coming online, it’s already been super sized. I was wondering how would this impact your gas price realization for the second half of the year in 2017? And secondarily, in light of the stronger deep bench Wolfcamp B well, although you have super sized the plant for future expansion, would this cause you to actually have to expand quicker than you would have planned otherwise? And those are my two questions.

Hi, Irene, this is David. Maybe I will take the second part of it, then ask Gregg to help me out with the first part on the price realizations. I think that the completion in the deeper bench of the Wolfcamp B, what we call the Blair Shale, was very exciting for us in this quarter. It was an excellent zone, one of the more productive that we have had in the Delaware basin. We were excited by the fact that it produced a significant amount of liquids similar to what the other Wolfcamp B wells were producing, but it just also had a lot more gas associated with it. So we considered it a real highlight of the quarter. And I tip my hat to the asset teams and particularly the geoscientists that have helped us find yet another highly productive target in the Wolfcamp. They’ve got several more ideas in the Wolfcamp B and I hope we get to test those before long. I think that is all still pretty new. The nice thing is that we know that that is an option. As I have told people who have asked me about those wells, when you are just about to turn on a brand-new gas processing plant, having 8 million and 10 million a day gas wells to send that direction is a good thing. And so that was good. We certainly are going to have ample gas to get that plant commissioned and working very efficiently. And I think, Irene, we will, as we look ahead to the remainder of this year and 2017, we will factor that in of course in terms of how we want to develop out the Rustler Breaks asset going forward. The nice thing is the midstream team has given us plenty of optionality. We have got enough capacity to handle what we need in the near-term and the ability to rapidly expand if that is what we choose to do. So I think that the team has really delivered not only in finding the resource but also in having the capability of handling it whatever we may choose to do.

Yes, David, Irene, this is Matt, just to build on what David is saying there about the expansion. The real beauty of this is we can continue to do it to fit our needs. And when I say our needs that is what Matador, the equity gas we would provide and also whatever third-party. So, we don’t have to go from 60 million to 200 million, we can increase it in 60 million increments or 30 million, whatever we want to do so we can maintain the efficiency of the plant and not have to go out and overextend ourselves.

Great, thanks. And pricing?

This is Gregg. As far as pricing is concerned it is going to be – we are going to charge market rates to ourselves out there. And so I would see that our realized price will be better than what it is today. But it will be within market and that is – the good thing about this is that we will also be charging ourselves. So eventually that will turnaround and go back into the coffer.

Well, I think the other thing too is although it may not impact actual differ – I mean our price realizations. We will – as we add third parties to the plant that will be an additional source of income that will just further enhance our overall net revenues and profitability.

The last thing, Irene, is ethane prices are on the rise and should help the margins out there. It is too early to determine, but they are trending in the right direction.

Great, thank you very much.

Thanks, Irene.

Our next question comes from Gordon Douthat from Wells Fargo. Sir, your line is now open.

Good morning, everybody. Another question on the Haynesville regarding kind of the Chesapeake announcement this morning. They had a couple pretty big long lateral wells out there and I am just wondering if you have – some of those I guess were – or at least one of them was in Cado; I am not sure if it was in Elm Grove or not. But I’m just wondering if you have seen those wells, if you have been in the wells. And given that result of those new completions might that change the strategic importance of that asset for you?

Gordon, this is Brad Robinson. We haven’t participated in any of the 2-mile long laterals but they have proposed one on our property and that will be coming up. So we are anxious to see the results of that. We have been watching – we have been involved in a lot of work that Encana did out there years ago when they were drilling 7,500 foot laterals. And so, those wells were very successful. So we are real anxious to see what the 2 mile lateral is going to do.

And I guess just to add to what Brad said, Gordon. The proposal is on our desk and we intend to participate in that well. So, we will have a small interest in that well.

Okay, and will that be coming this year?

Yes, I am sure it will be – I think so; I think they are planning to drill it here sometime in the third quarter. So I don’t know what their completion cadence will be or whether they will have it completed by the end of the year, after the first of the year. But I would see it would be toward the end of the year at the earliest.

Okay. And then just one last one kind of general over in the Delaware. You have been kind of leaders testing the increased proppant concentration in your wells there and I am just wondering if you have thoughts on have you reached an upper limit there or do you still see room for tweaks, improvements, et cetera, as you look at these completion designs. Just kind of wanted to get your general thoughts there?

Yes, Gordon, this is Matt and we have had a lot of success on our completion design, and we’ve pumped well over a dozen wells with 3,000 pounds per foot of proppant. And as we discussed before, it takes time to evaluate these things. The early results look good, but we will continue to watch in the coming months and see how the EURs actually respond. The really good thing about all this is we are able to do this at a very low price. So, when you increase the proppant volume by 50% it is not a huge cost that you are incurring. So we are able to do that. Some of the other things we have been working on that also are early on – the results are good but the early results are using diverting agents. We have talked a bit about that and that seems to be helping a bit, some additional technologies. There is these dissolvable frac balls and plugs that are out there that we are continuing to look at using some of those technologies. So everything is kind of moving in the right direction, but it does take some time before you can actually see the real results.

All right, thank you very much.

Thank you, Gordon.

Thank you, Gordon.

And our next question comes from Jeff Grampp from Northland Capital. Sir, your line is now open.

Good morning, guys.

Hi, Jeff.

Good morning, Jeff.

Wanted to go back to Rustler Breaks and talk about a little bit more of the Wolfcamp B results that you guys have been getting? Can you just remind us kind of what is – back at Analyst Day when you guys updated your inventory across the basin? Can you remind us kind of what is baked into Rustler Breaks Wolfcamp B? And then talk about potential upside as it relates to the middle and the Blair Shale that you guys have been seeing some nice results on.

Yes, hey, Jeff, it is David. As far as what is baked in, we essentially have one horizon of the Wolfcamp B baked into our forecast as I recall – our location counts. And I think the reason for that is it was then and still may be a little early for us to know exactly how those different horizons may communicate with each other if they do and so whether we will have all three of them in any one area or if there will be some two in one, three in one, that kind of thing. And how we are going to space the wells, whether we will stagger them, whether they can handle - each area can handle its own lateral. So I think there is a lot for us still to figure out there. But I can tell you there is only one of those horizons that is baked in at the current time as I recall. And so we are very excited about that. I am also excited about the fact that there is another horizon above anything we have completed so far that I think sometime next year will probably propose a test and actually look at that too. So, the Wolfcamp B is 1,000 foot and we are sort of in the - I think these zones start 300 foot or so down into it and they are about 500 foot from top to bottom. So, there is - I think we have still got some additional intervals to go hunting in there too.

Perfect, that is great color, David. And then thinking about maybe a bigger picture type of question. As we look out into 2017 you guys kind of talked about maybe a three rig case, and I understand obviously a lot can change between now and putting together a firm 2017 plan. But if that indeed was the case for three rig cadence, is there kind of any kind of big picture comments you can make in terms of production growth you guys think you could achieve or anything on that front to just kind of help maybe set some book ends going forward?

Well, Jeff, that is one of the most skillful ways I have heard anybody say what are you thinking about of a fourth rig. And the answer to that is Matt has been - Hairford and Billy have been tasked with being ready to either go to the fourth rig or go back to a two rig. With the price moving around as it has you have to have - be prepared for either way. And we will let circumstances - look at the circumstances to determine which way we go. Three rigs has served us very well this year and there are no plans and there is no discussions presently with any - with the outside vendors to say what about a fourth rig. We said we were staying at three, we are honoring that word. We are open, we would like to have circumstances change where oil gets $50 or $60 and you may look at it. But we are living in the here and now that three rigs is the appropriate number. And I sure hope it doesn’t go to two. We challenged our guys, one anecdote is it the first of the year, first day of business, I had a firm wide meeting and said that in 32 years I have never had a layoff of coming and calling people in and saying we are going to lay off 10% to 20% of the force. But there was a challenge out there that we all had to get to work and do a bunch of little things, get the cost down, get a little more for our gas and oil and everybody has really responded. And I couldn’t be more proud of our staff, the way they got the efficiencies going, hustled around for better prices,…

Jeff, I’d just kind of build on what Joe is saying. And I think one thing it is incredibly important is this business is to maintain a lot of optionality. So Joe said if we decide we want to go to four rigs, and I think Billy is probably the best I have ever seen at doing this and getting prepared without a whole lot of fanfare. So, if we were to go to tell Billy we wanted to go to four rigs he will be ready. And if we tell him we want to go to two rigs he will be ready for that too. So the guys do an excellent job preparing for going in either direction.

And, Jeff, one last point I want to make is that one circumstance that would be considered if we made a deal on our Midstream or on Eagle Ford or one of those, that would factor in to the viability of a fourth rig. And we don’t intend to increase our outspend at this point. We certainly with our borrowings we can go into next year. But - even to the end of next year. But I think if you made a deal and you had more cash in the bank it would be more attractive. So I wouldn’t expect it unless you really had a catalyst to commodity prices or a catalyst and deal of some sort. David, would you add to that?

The only other thing I would add, Jeff, just to the first part of your question, I think that we feel like we can continue to grow our oil production with a three rig program. And certainly with a similar level of capital spend than what we have had this year I am quite confident we can do that. So, I think that that is very positive. And again, we will - we are looking pretty hard at the mix of wells and sort of the environment going forward that we will want to put out there in 2017. But I think that - I think we will still be able to grow our production, our oil production particularly.

All right, great. Thanks for the color and solid quarter, guys.

Thanks, Jeff.

Our next question comes from Mike Scialla from Stifel. Sir your line is now open.

Good morning, everybody.

Good morning, Mike.

Joe, I wanted to ask you about the Longwood plant. You stressed the importance of getting the right partner there. And you said in the past there has been some interest that even though you have not been running at a data room there. Just wanted to kind of investigate that to see if any of the parties that have expressed interest there are the kind of potential partners you are looking for. Or has more of the interest come from kind of purely financial entities?

Mike, you mentioned Longwood, did you mean Rustler Breaks?

I meant Rustler Breaks, I am sorry.

I would just say, Mike, the interested - the parties who have expressed interest cover the full range. And we are not - they cover the full range of partners. And each one has their positive attributes and we are looking at all of them. We do - the longer we are involved we tend to like the ones who have been in the business and have a track record to consider. Since we have the money, the financial partners, we don’t need a bank. They have got to really come in extra strong if they are going to say because we just don’t need a bank. We have already got it and our banks have indicated that they would lend whatever we needed to build or expand the plant. So, that is why you look for somebody that is more strategic that would be a fit. But we have had the full range. And each time you meet with somebody you learn something and you see the relative advantages of different kinds of suitors. Dave is it - Gregg is that the way you would describe it?

That was exactly how I would describe it. Yes, we are looking for a strategic partner in this case as far as if we elected to do something there. So we have had a wide range of folks coming in kind of all over the place as far as for one side of this to the very skilled – a lot of experienced operators.

David, anything?

No, I think Gregg probably added to what I wanted to say. I do think - just to reiterate what Joe mentioned, I think financing, there is not an issue. We know that - we know our bank group would be very supportive and we have already had discussions with them. So, should we decide to either - to even retain the plant 100% ourselves and go forward from here, that is certainly something that we can do. So, I think what is important for us is to find someone who is not only going to be a good strategic partner going forward, but I think also someone who is going to realize the value that we have already - that we have already created and wants to work with us to help to continue to enhance the value of that asset for both parties.

That is great, appreciate that. Wanted to ask about at Wolf, if you have done enough testing there yet to know if the XY and the deeper A bench are separate reservoirs there. Or if not when you might - is that a 2017 kind of test that might give you some sense of what the inventory there could be?

Mike, this is Brad Robinson. We just finished completing a Wolfcamp lower A well, you probably read about it in the operational summary. We are very excited about that well. So, we are going to watch that well a little while and look at the communication level, if any, between that and the A XY right now, it looks really good. So we’ll probably have more results on that later in the year, first part of next year. Those things take a little while. You have got to look at months of history before you can make any calls on that. But so far we think it is very positive that that could be a separate reservoir. But we will know again probably by year end.

That is great. Thank you.

Thanks, Mike.

And our next question come from Jason Smith of BofA. Sir your line is now open.

Hey, good morning, everyone. Congrats on the results.

Hi, Jason.

On the A and D front, you highlighted in the release the acreage you have been able to tack on this year. I’m just curious, just the interest - interest in the basin has also moved significantly higher in recent months. So are you still seeing opportunities to tack on additional acreage? And also what have you seen just in terms of acreage prices in the market?

Yes, we have continued to see opportunities and - in the basin and we continue to chip away. We of course have been impressed with some of the prices that have been paid for that, but they have generally been larger transactions to facilitate a new entrant in the basin. We are working our areas and continuing to make deals. But it is a competitive area and has always been a competitive area, which reflects the quality of the basin. We on our total acreage count, I am going to let Van speak on it because we have some acreage has expired that we had outside the basin, principally in the Midland Basin for which we think we have upgraded that acreage and replaced it with acreage in the Delaware that is within our areas. And we are continuing to increase our working interest in these areas. But for the exact numbers, would you give an idea on the adds?

This is Van. What we have done this year, as Joe said, we have had some acreage, not a whole lot, 700 or 800 acres that was outside kind of our core area in the basin that has either been traded, sold or has a little bit - has expired, but we have been trading up into our core areas. And the prices as far as activity, as Joe said, it has always been very competitive. It was competitive before we got there and it has maintained that level. We have been pretty selective throughout our acquisitions in the basin. We continue to do that and our prices have remained fairly steady. So we are still seeing a good deal flow, we are still being selective and just trying to buy the best of the best.

Does that answer your question?

Yes. No, that is helpful. And then just one other follow-up. You guys have been big proponents of higher proppant concentrations. So I was just curious in terms of how much more aggressive you think you can get on that front, and kind of what you think becomes the de facto, if anything, for kind of what you guys are doing across your acreage?

Hey, Jason, this is Matt again. On the proppant volumes, one thing we found with these reservoirs is they will take a lot of proppant. Some reservoirs in the country, you can only get so much proppant in the reservoir. These reservoirs are very kind in taking proppant. So I think where it will go is still yet to be determined. There is typically not, in my opinion, really not a downside to more proppant other than cost. It becomes a point of diminishing returns. So you need to find that sweet spot or that Goldilocks place in there, and we jump from 2,000 to 3,000 pounds per foot. So maybe it is somewhere in between, still not sure. And as we’ve said before, if we are having the same discussion two or three years from now, we will still be talking about how to optimize these completions.

Thanks, Matt, I appreciate it.

And our next question comes from Neal Dingmann of SunTrust. Sir, your line is now open.

Good morning. Joe, just a question on the plays. I mean at this point, you guys have obviously made tremendous progress. I guess my question would be, do you feel like at this point you all have mostly delineated each of these five? And if so, will we continue to see these costs go down largely through efficiencies in the development mode?

I don’t think we are there yet in fully delineating that in development mode, because I think part of full delineation is what is your spacing and how do you - what is your spacing and, again, your proppant, and that is still in the learning mode. And the new technology is really very neat. Our head of operations, Billy, was talking about some of the new technology, and it is exciting. So I think you have a lot of room for efficiency - a lot of room for further delineation, and new reserves. And I think the Blair Shale is a good example of that, that it has got enormous gas potential. And I think end of the year and shortly in the New Year that you are going to have a much better idea of how enormous it really is. But let me turn to Billy just to mention some of the efficiencies that they are working on just in the last year. Billy.

Hey, Neil, this is Billy Goodwin. And like Matt was talking about earlier, all of the different things we are doing there on the completion side. We have seen our costs come down over 10% this year so far, and we see that continuing as we get better on that side. On the drilling side, just consistency is the word for what we are doing there. Not just consistently staying right there close to record wells, I mean each well we drill, we’ll drill like - at least one whole section of the well will be faster than the other wells. We just finished Wolfcamp A well in our Rustler Breaks area. It’s a four-string casing well. We just finished that up in less than 12.5 days. That is pretty amazing when you have to stop, pull out of the hole, run casing and cement. So you think about that that is amazing. And then on top of that, we are fixing to introduce some new bit technology out there called the axe cutter technology. That would be the first time it has run in the Permian Basin. We are going to follow up with the well we just set the record on in the same Rustler Breaks area. We are expecting that to cut that another half-day off. So now we are getting down into the 11-day range. And it is amazing, we just keep getting better and better, improving efficiency and cutting costs on both sides, drilling and completion. So there is still a lot out there for us and we are going to keep taking those gains. The asset teams are doing well, working with the drilling group and geologists, and it is just amazing what they are doing.

Joe, it sounds like they need to keep cutting my cost assumptions for you all.

No, I don’t want you to get too aggressive at this time. I am going to have to tell them to caution what they say. But we are pleased. I mean that technology in these - it is old hat now, but these new rig designs that we had, the oldest one is like 18 months old, and the bigger pumps and everything else has really made a difference. And we couldn’t be happier with the service work that we have gotten from Patterson on the new rigs or Halliburton and Schlumberger. You have got very experienced hands now out there on them, and they are really doing good work. So we went - we made the conscious choice to stay with the larger service companies who could really stand behind their work and we are breaking out with new technology, and I think it has paid off. So we are encouraging Billy to keep finding ways, but not maybe to tell you about so…

Hey, Joe, and the last one, any thoughts of just moving a rig over towards Arrowhead anytime soon?

Yes. That is actually something that’s being actively discussed, and we are going to move, we have a rig up there now drilling in Arrowhead on the Mallon leases which are longer laterals, they are a section and a half laterals. Those wells will start to be complete in September. So that is a big - there are three wells, they will be drilled back to back to back, which again may affect a little bit of production in the short run. And that is why we continue to encourage people to look at us on a six month to six month basis because that takes out a lot of the effects of timing. And we will be drilling up there in Twin Lakes. That has worked out well for us. Our geologist had a discovery up there in the Strawn. We went down there just to see what it looked like, very encouraged in drill stem tests that we completed. That well is still flowing, should make over 40,000 barrels in its first 12 months. It is a vertical well and we believe it is very repeatable. But we still want to get down. And it has done so well, we have elected to drill a new wellbore for our Wolfcamp D test in there, because that well is performing. So we are going to have to locate our Wolfcamp D in a different location. Ned, our chief geologist, would you add to that?

Yes, absolutely. I think, Joe, you said it very well. But again - I realize you are asking about Arrowhead, but we will take a moment to brag on Twin Lakes while we are at it. The core that we took in the Olivine well shows exactly what we’d always thought. It is a lot of oil in place. It looks to be a strong source rock up there, so we are very encouraged about the test up here. We are still examining whether we are going to test this as a new wellbore in the Olivine area or go west to our [Kimnets] area. They’re both great areas and we are very optimistic about this. I should also say that the Twin Lakes test is important for us because the Wolfcamp D really extends over much of our acreage area in New Mexico. So what we learned from the Wolfcamp D and Twin Lakes we hope will be portable and help really in Arrowhead as well, because there will be a large number of potential locations in the Wolfcamp D and Arrowhead as well.

Great progress, guys, and your stock is certainly showing today.

Well, thank you very much.

And our next question comes from Dan McSpirit of BMO Capital. Sir, your line is now open.

Thank you. And good morning, folks.

Hi, Dan.

A couple questions on the contemplated asset sales or monetizations. What is the EBITDA margin or contribution from your midstream assets today, or at least remind us of the margin or contribution on the assets sold to EnLink? Just asking in effort do you get a better sense of the amount of the potential sources of proceeds here?

Yes. Dan, it is David. You know, as far as of course the contributions of what we sold to EnLink when we sold it on day two of the plant, it didn’t have much time to make a lot of contribution to the EBITDA. So you may recall that we did sell it right after we turned it on, and it was a nice multiple of what we had invested. I think this year the remaining assets at Wolf between the water disposal, the oil and natural gas gathering, the water gathering, if we kind of had that as a separate business line, it would spin off something in that maybe $8 million to $10 million of EBITDA range this year. Of course, the Rustler Breaks plant itself hasn’t started yet. So a lot of that will just depend on the amount of not only Matador equity gas that we are taking, but also the amount of third-party gas that we can sign up and put through the plant. So we will probably get a little better handle on that once the plant gets up and operational.

Great, that is helpful. And then as a follow-up here, just remind us of the remaining locations in the Haynesville and in that part of the world, as well as the average working interest on those assets? And would you be more inclined to sell the Haynesville over the Eagle Ford, for example?

No, I don’t think we have preference one way or the other. And we are not running any process on either one of them. We just - look, there is a lot of M&A transactions going on. People are thinking about it and we are just trying to be good stewards that if people get serious, we will give appropriate consideration to someone making the appropriate price. So we are more price oriented than area oriented. And on locations, Brad can fill you in on how many expected locations in the Haynesville. But Dan, it is also important when we made the deal with Chesapeake, we reserved all of our Cotton Valley rights. So we have not only locations in the Haynesville, we have 100% of our Cotton Valley rights which are extensive. It is another 200 [billion] or so potential in there. And finally in our deal with Chesapeake, we kept our overrides, so we have 85% and 90% net revenue interest, and we have the right to market our own gas which is giving us a positive price differential. So, Brad, how many locations do you estimate in the Haynesville and Cotton Valley?

Joe, I think it is going to be – Chesapeake had gone up there and planned on drilling around 50 wells. I think they roughly drilled three-fourths of those wells. So there is probably still another dozen or so locations still to be drilled there in the core area of Elm Grove. And I can get those numbers exact, but that is where I am remembering. But I was going to make the point that you made about the Cotton Valley. I mean we are sitting on many hundreds of Bcf of gas in the Cotton Valley that we operate, and that is really sort of your gas bank right there that we’ve got; it is all held by production and that is really a large upside for us.

I think the other thing, Dan – this is David, I would add to what Brad just said was that the program he is talking about was where Chesapeake went in and sort of downspaced everything to four wells a section. So we don’t know if at some point in the future they may come in and add additional locations there in the Elm Grove area itself. But outside of Elm Grove, we have acreage that we operate 100% ourself that still has locations to be drilled, plus we have significant additional acreage holding that are operated as well by Chesapeake or what was JW, I guess, Vine now that Encana took them over – or the other way around. So other non-op wells that we from time to time be HBP participate in. So there are quite a few additional Haynesville locations still throughout the basin, as well as all of the Cotton Valley upside that we would have as well.

Thank you. Have a great day.

Thank you.

And our next question comes from Richard Tullis of Capital One. Sir, you line is now open.

Hey, thanks. Good morning, everyone. I think most of my questions have been addressed.

Richard, we can’t hear you.

Can you speak up?

Sorry about that, Joe. I think most of my questions have been addressed already, but just one left, I think. Could you just update us on the inventory of drilled uncompleted wells? I know you used the second completion crew to knock out most of that, but where does it stand right now, Joe?

Hi, Richard, it is David. Good morning. It really stands that what we have just drilled is waiting to be completed. So we have gotten ourselves and when I say we, my hats are off to the operations group and the completions guys. They did a great job in the second quarter of getting – running two and sometimes three crews. And so they’ve got us caught up, Richard. So we are sort of back up. We’ve always been pretty much in the mode of drill the wells, move the rigs off, get the frac crews in, get them completed, and that is back to what we are doing here. So we are essentially caught up.

Okay.

Richard, for us the wells that are waiting completion are typically on the same pad where we have got the drilling rigs. So if we are going to drill three or four wells off the same pad, most of the time we will wait and bring the completion crews in behind that as fast as we can. And then when we do get additional well locations on different pads put together, we will go ahead and expand, like David said, to two or three crews to go ahead and get those producing.

Okay, thank you, Matt. Appreciate it. That is all for me, and congrats on a nice quarter there.

Thank you, Richard.

Our next question comes from Scott Hanold of RBC Capital. Sir, your line is now open.

Thanks. Hey, guys. Just have a couple quick ones. One…

Scott, can you speak up. If you can speak up, you are coming in at low volume. Can you speak up a little bit, please?

Sure, sure. My question is, as you look into 2017, and your operating costs have come down pretty nicely here, how much of your oil rate now is in gas or oil on pipe and will that change with all of your plants operational next year, will that be close to 100%? And if so, what implications does that have to further reduce your operating costs?

Gregg?

Yes, as far as what is on pipe right now, it is probably in the neighborhood of 7 to 10, somewhere in there. And that is Eagle Ford and also the Permian.

7 to 10 what?

I am sorry, 10,000 – 7,000 to 10,000 barrels a day.

14,000.

Yes, yes.

Over half.

Right. As we go on, and I think everybody has talked about as far as the three stream systems that we have got in the Wolf – in the Rustler Breaks, that will expand that because we are planning on putting those gathering systems, further expansion there at Wolf and also there at the Rustler Breaks. So those will increase the barrels that are on pipe. And with that being said, we should see our transport costs go down. Currently right now, it is pretty competitive right now with the trucking cost being quite a bit lower today. But historically, that is not always the case and we expect that to go up as time goes on, as far as trucking cost. And that is another reason to put those on pipe.

Okay, and do you think in the Permian you could – as you go through 2017, you can get close to most of your oil on pipes, or would you probably need your – get your partners or yourselves to put in that capital to get it there?

I can see that – I don’t know about – I’d majority of it, yes, except for of course the Arrowhead, Ranger areas, we are not going to have – we will probably not put those on pipe initially anyway until we get some critical mass there. And then we would consider doing that.

Okay, that is great.

This is Matt, and I think just to build on what Gregg is saying, at Wolf where we got started earlier down there and have more production in that spot early on, we are selling all of those products into pipe. And as we continue to drill at Rustler Breaks, that becomes a more viable option. And then and Ranger Arrowhead, it is going to be a little slower coming up, mainly just because we are just getting started up there and also that it is spread out a bit.

Okay, well that definitely makes sense. One last real quick one. You mentioned obviously being caught up on your well completions. With that three rigs, generally speaking is it one tracker you need to chase around those three rigs, or from time to time will you need a little bit more?

Yes, Scott, this is Matt. It just varies. Like I said, if we have got the rigs moving around from drilling one-well pads to one-well pads, you have got probably a need from a timing perspective for a couple of frac crews. If you have got them all on pads, then you maybe able to take one crew and move it from pad to pad, drilling multiple wells off the same pad. It comes down to timing. We typically don’t want to sit there and wait. The wells don’t get any better while you are sitting there waiting. So we just typically try to move in the crews as quickly as we can.

Okay, appreciate the color. Thanks.

Thanks, Scott.

And our next question comes from Ben Wyatt of Stephens. Sir, your line is now open.

Hi. Good morning, guys.

Hi, Ben.

Joe, if I can ask another question and if you have already answered this, just tell me to go read the transcript. But back to the potential asset sale or something like that if we are talking Eagle Ford or Haynesville, are you guys kind of thinking something along the lines of 10,000 acres and some production or the entire block? I am just trying to get a sense of how you guys are thinking about that, especially when I kind of hear or when I hear it is not as strategic as it used to be when you are talking about the Eagle Ford.

Ben, the management team here is not necessarily of one mind of what to do. But we wanted to explore what the options might be just for we think that was good planning. We would like to have a little price discovery of what other people may be willing to pay for it. We have seen some transactions occur that had pretty strong pricing on it, and wanted to take a look at that. So it could be all or part. We are not saying – because we have the backup of an undrawn line of credit, it is not that we have to do something, but it is something that we are open to and would give appropriate consideration for a strong offer. We are not interested in tire kicking or somebody think there is a distress, because the cash flow is going well. And in the Eagle Ford there’s only about 12 to 15 wells that need to be drilled for it all to be HBP. And then you would have all of the Haynesville, all of the Cotton Valley and all of our Eagle Ford assets, all HBP serving as gas and oil banks. So they are good properties and they have served us very well. But at a time where the opportunities are strong in the Delaware, we are open to them. But it is not a fire sale; it is not – as we do with any assets, we do a methodical thing and want to be sure that we have signaled we are open. A year ago or two years ago, we weren’t as open because the Delaware was still being delineated. But our confidence has grown in the Delaware to the point, and we are gaining some economies of scale to implement more…

Got it, and that is helpful. And I appreciate that and understand that nothing definitive here. But David, if I could ask you maybe if something were to happen, again kind of speculating here, but if something were to happen, any sense of what would happen to the revolver? Or have the reserves just grown so much in the Delaware that you wouldn’t expect any type of meaningful cut, if any at all, to the revolver if you guys were to get rid of an asset?

Yes, I think I wouldn’t expect a significant cut, if there was any at all. I think that a lot would depend on the timing of it, too. But I don’t think it would be – it wouldn’t be anything that would be significant or would substantially impact our liquidity at all. And obviously, the sales proceeds from the asset of the sale would far swamp any reduction in the borrowing base that we might see.

Yes, you bet. Very good. And sorry, can you guys just remind me when we could potentially get the next Twin Lakes result?

Yes, we are probably going to spud the well toward the end of the year. So I think it will be into the first part of next year before we will have a chance to get it drilled and completed. So it will be probably late first quarter or maybe early second quarter before we would have that.

Very good. Guys, I appreciate it. Good quarter, and thanks for letting me ask some questions at the end of a long call.

Great to hear from you, Ben.

Our next question comes from Jeff Robertson of Barclays. Sir, your line is now open.

Thanks, just a follow-up question on operating costs. Are you all doing anything different with how you lift these wells, or do these wells allow you to do anything differently with the artificial lift that is also contributing to lower LOEs?

Jeff, this is Matt, and that is a good question and it is a little bit different in the Delaware Basin than it is in the Eagle Ford. The Eagle Ford, we had significant success with gas lift. It became our artificial lift of choice early on, and has served us well throughout the years. And as you move those wells in the Eagle Ford from gas lift in the Eagle Ford from gas lift in the rod pump as they mature, that is a natural progression. If you go to the Delaware Basin, we started with gas lift out there and we are still using it in places. But with the difference in the fluid volumes that the wells produce and different depths, we have got some wells that we are lifting with gas lift effectively, some that we are using ESPs on. We have actually got a well or two out there that we are plunger lifting, and then we have got rod pumps. So we have got all four different methods in the Delaware, and really it is just a case-by-case basis. If we have a well that is making a large amount of fluid from deeper depths, the ESP makes sense. If we are somewhere less than 1,000 barrels or so on total fluid, the gas lift is the way to go. Then obviously when you get down in the 100s, 150 barrel range, rod pump works very well.

Just a follow-up; will the plant at Rustler Breaks contribute to downward pressure on Eloise by putting more water on pipe?

Jeff, this is David. We certainly will look at, as we continue to develop out the Rustler Breaks asset, it will I think make sense for us to consider putting our own disposal well up in that area or wells. And at that point, we would I’m sure look to put the actual water transportation on pipe to that facility. So that is certainly something that we will be considering going forward.

Thanks. My last question, did you all – were you able to include anything in the Blair in the June 30 reserve numbers you put up?

I think that the first two wells that we completed that we mentioned in the operations update, the Jimmy Kone 228 and the Tiger 227, I believe were both booked, obviously is proved developed producing reserves. Brad can probably comment on whether we added any pus as a result of the drilling of those two wells, or deferred that until later.

David is exactly right, Jeff. We did add those reserves in and we were able to book some proved undeveloped reserves associated with that. And as we continue to delineate that reservoir, we will continue to add more reserves.

Okay, thank you very much.

Thank you.

And our next question comes from Mike Breard from Hodges Capital. Sir, your line is now open.

Okay. Concho was very positive about some Avalon wells, been talk about the Brushy Canyon wells. You have got the Blair formation. You’ve obviously hit a jackpot in the Delaware Basin, but would you still say it is as much an exploratory province as anything else? I mean are you just maybe in the first inning of working there?

Hey, Mike, this is David. It is good to hear from you. I think I would characterize it this way. I don’t know if it is the first inning, but I still think that it is – I still think that it is a very early still in understanding all of the opportunities that we may have. We have been focused a lot on the Wolfcamp X and Y down at Wolf. This year we have drilled another fat well that we are lower, we call it fat around here, but the lower portion of the Wolfcamp that we are very pleased with. I think you see from our recent releases that we have drilled a couple of new second Bone Spring wells there at Wolf this year and they are much better than what we thought. We have bumped up our type curves for the second Bone Spring there as a result of that. Every meeting I sit in just about, I have a geologist telling me of a new zone he wants to test. So there is definitely Avalon potential in the Wolf area. I think there is Wolfcamp B potential. We haven’t even tried the third Bone Spring or the first Bone Spring in that area. And then you go up to Rustler Breaks, obviously this new bench of the Wolfcamp B has been exciting, but I think we feel like we have additional intervals to test. As I mentioned, there is some Upper Wolfcamp B that I know the guys would like to test. And really when you go up then into the northern part of our acreage, we know that is going to be very solid for the Bone Spring because it is the historical Bone Spring area. So second Bone Spring, third Bone Spring, there is going to be areas where those are all very good. But I think we even, kind of from the exploration side of things, have some thoughts about the fact that it may have great Wolfcamp potential too. You heard Ned mention that earlier. And we don’t know yet; we haven’t tested it, but we have some ideas for some places that we would like to do that. So it is a real nice thing to have acreage that sits on 4,000 to 6,000 foot of hydrocarbon saturated rock and have the ability to try to figure out what intervals are going to work and when they are going to work and how they are going to work and how you can extract more hydrocarbons out of it. I think it is the thing that makes the business so much fun. And it is a pleasure to work with our technical team here and see them continue to bring those ideas to fruition. And we are going to keep pounding on the rock, literally.

One of the things some people don’t understand, when you hit a new formation say in the Rustler Breaks, you’ve added 15,000 acres of leases essentially. I know you don’t like to break it out.

Yes, sure.

But if you went formation to formation, you might have – who knows, a billion acres.

Yes, certainly. Yes.

Okay, thank you.

Thanks, Mike.

And our next question comes from Gabe Daoud of JPMorgan. Sir, your line is now open.

Hey, guys. Just wanted to squeeze in one last one if I could. It was asked previously, but just on Rustler Breaks and the cryo plant. I guess if you just assume full utilization on the plant, is there a cash flow number that you could kind of estimate on what the plant could do at semi-full utilization?

Hey, Gabe, it is David. I think that again we would prefer just to kind of not – to get it going before we disclose any of that information. So obviously, we have our internal estimates. But again, we would just like to get it up and going and as we do, we will be happy to share more of that information.

Okay, got you. Figured I would try one last time. Thanks, David.

Thanks, Gabe. End of Q&A

Ladies and gentlemen, this ended the Q&A portion of this morning’s conference call. I would like to turn the call over to management for any closing remarks.

Well, thanks. Obviously, some earnings calls are easier than others. This has been one of those, and we appreciate your questions and your interest very much. A couple of points that I’m not sure we completely touched on, but two of our wells in Loving County for this have been the best wells in Loving County. And the operations report that we did prior to this earnings release has got a lot of valuable data in it on actually what we drilled and how we drilled it and IPs on it, and we would refer you to that. But we do see this combination of drilling in concentrated areas and adding the Midstream in there as a unique opportunity that really works both ways. And we will have more information coming into it because we think that is an important element to our growth and our operational success, and getting better prices and lower operating costs. And we are not in a hurry because good deals are hard to do. They take time and if you are patient, better things seem to happen. The quality of the suitors are better and the quality of the fit and the prices are better. Naturally as we get operational and show it works, add some third-party. So as we are waiting, we think we are adding value. But we appreciate the interest and support of all you analysts, and it keeps us sharper for your questions, and sure have obviously all done your homework. And we really appreciate it and hope you will come to see us. We look forward to the next time we see you in person. So from all of us to you, thanks very much and we really appreciate your interest and your questions, and we will get back to work. The last thing I want to end on is at the suggestion of a number of you, I hope you noticed that we cut down the size of our deal. We have been advised that less is more on the earnings release, and we’ve cut out about two-thirds of the wordage or the verbiage from the last report. And we appreciate your compliments on it, but we also appreciate knowing from time to time what is most important to you and your feedback on our communications that help you do your job. So thanks again, and come see us. Bye.

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