Good morning, ladies and gentlemen. Welcome to the Second Quarter 2017 Matador Resources Company Earnings Conference Call. My name is Takiyia, and I'll be serving as the operator for today. At this time, all participants are in a listen-only mode. We will facilitate a question-and-answer session at the end of the company's remarks. As a reminder, this conference is being recorded for replay purposes and a replay will be available on the company's Web site through August 31, 2017, 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, Takiyia. Good morning, everyone, and thank you for joining us for Matador's Second Quarter 2017 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 to the company's current expectations or forecasts of future events based on 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 annual report on Form 10-K. Finally, in addition to our earnings press release issued yesterday, I would like to remind everyone on the line that you can find a short slide presentation summarizing the highlights of our second quarter 2017 earnings release on our Web site on Presentations & Webcasts page under the Investors tab. I would now like to 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. 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 Land, Legal and Administration; Van Singleton, Executive Vice President of Land; Billy Goodwin, Senior Vice President, Operations; Brad Robinson, Senior Vice President of Reservoir Engineering and Chief Technology Officer; Gregg Krug, Senior Vice President, Marketing and Midstream; Matt Spicer, Vice President and General Manager of Midstream; Rob Macalik, Vice President and Chief Accounting Officer; Kathy Wayne, Vice President, Controller and Treasurer; Brian Willey, Vice President and Co-General Counsel; Bryan Erman, Vice President and Co-General Counsel. Ned Frost, Vice President of Geoscience; and Tom Elsener, Vice President Engineering and Asset Manager. I'm proud to announce the second quarter of 2017 is one of the best quarters, operationally and financially ever delivered by the Matador staff. Our average daily oil, natural gas and oil equivalent production were all the best quarterly results in Matador's history. And one reason why we emphasize production at Matador is that subjective it's sometimes hard to compare our results to others at sometimes apples to oranges because of the different accounting methods and different ways things are calculated, but production is production. And we like to look at that and look at the growth and count the barrels each quarter. The same thing I'd really like to emphasize, and it's really corny I understand, but this quarter was a total team effort that I just look at every aspect at Matador and…

[Operator Instructions] First question is from the line of Scott Hanold of RBC. Your line is open.

Thanks. Good morning. A nice quarter, and it seems like some of the well results you've drilled this quarter continue to progressively get better, especially some of that -- the Wolfcamp sands and you've got the Wolfcamp B over in Rustler Breaks. Can you tell us what some of these more recent results? How that makes you think about potentially the depth of the inventory, how that's changed in the various formations that you all would really want to sort of target on more of a go-forward development basis? Just what is higher on the pecking order here?

Hi, Scott. Good morning. This is David. While I would say that as far as the inventory goes, I think we feel pretty solid with our estimates on the inventory at the current time. I mean, we're still, I think fairly conservative with regard to the spacing. We've got everything pretty much at 160 acre spacing at Rustler Breaks and we'll see how that goes over time. Clearly, I have to hand it to the teams as far as the Wolfcamp A goes, the X-Y, that's certainly been a very solid zone for us and continues to expand throughout the area. Very pleased with our results, very encouraged, too, by some of the offsetting results that we're seeing to the north and western parts of our acreage. So that's clearly a very, very strong zone for us. And the two wells we reported this quarter, the Joe and Kathy Coleman are among the best wells that we drilled at Rustler Breaks, and they've held up extremely well. So we're very, very pleased with the way that's going. I think the Wolfcamp B continues to be a star, I mean, what can you say about the Blair, it just continues to print, I think, exciting well after exciting well and certainly the results from those two behind have gotten -- combined, not behind. Those two combined have gotten us to exceeding our gas plant volumes even more quickly than I think we could have possibly imagined. So those are definitely superstar zones. But, we still have a couple of other benches in the B that continue to deliver very solid results for us as well. So, real excited about that. I was particularly pleased and I think the team and the rest of the Rustler Breaks team was too this quarter with this first result in the A lower zone there in the Guitar 205 well. I mean that delivered a very nice IP. That well has done just fine. Since we've had it on, I think it's really validated that as another good completion target. And then, there's probably not a day that doesn't go by that Ned Frost and Tom Elsener aren't in wanted to talk about testing some different zones at Rustler Breaks. So, I think that, overall, that's gone from kind of an asset that we first started on a couple of years ago. I don't think people gave it much credit to one that sort of rocketed into the superstar status in a way. And so I think we're real pleased with how that looks and I'm sure we'll be reporting on more A-XY, Wolfcamp B and probably A lower wells, in particular going forward as we look to test some of the other intervals.

Okay. So a lot of good stuff there. And fortunately, you guys did make a nice entry cost basis entry into that play too. For my follow-up, Twin Lakes obviously, you've got the Wolfcamp B well. And maybe just give us some context of how you perceive that well? It did seem like it's got a nice productive rate. What is really the goal up in Twin Lakes right now? Is it more conceptually testing with up there or is it trying to figure out what's going -- what it's going to take to make it say competitive with an area like Rustler Breaks for instance?

Well, Scott, I'll start off, and the rest of the group can follow in. But, what you said at the very beginning where you talked about on all these areas we're drilling and all these different zones, we continue to get better each time that we drill and go along. That's what you can expect up there at Twin Lakes. We thought it was a good start. We think we'll get better with the next well and the well after that. We can see room for improvement. We did not use diverters up there. That was something very simple that we think can improve and you have other factors like that. But, what we will do there as we have done in other areas, because the first well in Jackson Trust was not a headliner nor in Rustler Breaks. But, what we'll do there as we've done in these other areas in the Eagle Ford and the like is a very methodical approach to extending our plays into Mexico. In the first well, the Olivine, we did a pilot hole, and then, we came back on this well and we now have a good data point for the east side of the acreage. Now, we're going to go over on West side and we'll do that later this year and it behaved as we expected. I mean, we felt good from a geological point of view that there weren't a lot of surprises. You have movable oil. I mean that's -- if you don't have that, you don't have anything. So you have men on base now and we can move it from there. We all saw it was oilier; it came in as we thought, much heavier on the oil, no water, very little water. And another shout out to our drilling team. They really reduced the number of days that it was expected to drill the well. So they did a fantastic job lowering the wells, which increases the commerciality of it. And I thought it was a very solid first step. We're real encouraged and we're also were encouraged by the increased activity up there. So I think -- as someone some of you all describe it, a very solid start is a good way to do that. And there wasn't a lot of disappointment, there was a lot, as we did our postmortem things that we could do to make it better just like we've done in these other areas. David, Matt, what am I leaving out?

Yes. I'll just kind of underscore what you said, Joe, about we do think it's a great start there. And back to the operations guys, Billy and his team, they did drill this well, basically twice as fast as we originally thought it was going to be. When we started thinking back, we were 23 days from spud to TD and we were expecting maybe double that. But, the other thing that I think is important is we did pick a target interval. We had 2 that kind of came down to A and B and we picked the lower interval and a more organic interval and the guys were able to stay in that for the entire lateral. So a great job with the drillers and the geoscientists working together, make sure that we're in the right target zone all the way through and then the completions guys came in and put an effective frac on this thing. But as we always say, Scott, we reserve the right to get smarter and do believe that these wells will improve as we continue to drill.

Scott, I'll just add something to what Matt said, he mentioned the two zones there in the Eastern part of our acreage. And as you move to the West, Joe mentioned drilling another test there later this year in the western acreage. The thickness of the Wolfcamp D almost doubles to 800 feet over there to the West and we're looking at maybe three or four different zones over there. So we're real excited to go drill that next well.

And I'll follow on, this is Ned Frost. I think it kind of gets lost in the context here of the significance of this well. I mean, it truly is an exploration play. There's only been a handful of Wolfcamp D tests in the whole basin and this most certainly is the first test in the Twin Lakes area. So, in terms of how we feel about this well result, I think we're all very happy, it confirms a lot of the play concepts that we originally had. And I think it puts us on a good foot moving forward when we continue to delineate the play off to the western side. So, we're all very excited about the result here.

All right. I appreciate all that color. It's great. Thanks.

Thank you, Scott.

Thank you. Next question is from Gabe Daoud of JPMorgan. Your line is open.

Hey, good morning, everyone. Maybe just sticking with Twin Lakes. If you could maybe just talk a little bit about the cost for the Culberson well and what the ASV on the next test looks like at this point?

Gabe, this is Matt. And kind of in regards to cost these first wells are always more expensive than others. So I think it's a little early for us to talk about what we think the ultimate development cost on these wells might be. We've got -- I know the drilling guys are going drill these wells faster and faster and faster. It wouldn't surprise me if we got under 20 days right away, which is going to help with the cost. On the completion said, half the well costs are related to completion. So, until we get that nailed down and it's going to be hard to predict exactly what those costs would be, but I think just in terms of what you're seeing in the basin, they're going to roughly be in those type numbers.

Thanks Matt. That's helpful. I understand, it's still pretty early. And then, a quick follow-on with that one, I guess, it's just, again, it's still early, but any thoughts on potential recoveries from that well, what that could look like? And ultimately, how you think the declines shape up there given the lower overpressure nature of the reservoir?

Gabe, no. No real outlook right now, what it will recover. It's just too new and as Ned explained, it's an exploratory well. So, this first data point that we have to go off on. We do think it will behave more like the Midland Basin wells and that you will put them on gas lift, on pump sooner and we are expecting better permeability up here a little in here. You've got a good oil cut and we'll have to kind of see how that permeability works out. In some of our other Wolfcamp wells is the permeability has been better, they've been much flatter in their decline and we hope and think that, that should occur here, but we just need more time. It's still very early days.

Understood. Thanks Joe. Just one quick follow-up then for me. Just in the Eagle Ford, some nice results there, first time you put some operating results up on the board in a couple of years. This question has obviously come up before on previous calls. But as you just think about the asset moving forward given the strong results and production nearly doubling quarter-over-quarter, I know activity left for the foreseeable future, I guess, now. Is now a good time to think about a divestment at this point or how should we just think about it moving forward?

Well, Gabe, we've tried to make it clear that we play a straight game here. As we've made sales before, we sold first Matador, we sold part of our Haynesville to Chesapeake and we've done two midstream transactions. And if somebody comes in and offers a sufficient amount, we'll be happy to make a deal with them. And it's the same thing whether it's Haynesville or Eagle Ford that we'll make a deal. We're not compelled to any; we have nothing borrowed on our line of credit. So, we think we can afford to be patient. And we think we demonstrated here that there's still a lot of life in the Eagle Ford. And we didn't leave it because there wasn't opportunity, we left it because we had pretty much things held by production that didn't have to do it and we built up a gas bank there, just as we built up a gas bank in the Haynesville. And when we did the deal with Chesapeake over in the Haynesville, we reserved our Cotton Valley rights. So, there is 200 to 300 Bcf of reserves over there between our Haynesville and our Eagle Ford and it's an opportunity, but it's almost all HBP. And the same thing here at the Eagle Ford is we don't have now any rush to validate any other acreage because nothing is expiring in the near future. We're not going to sell it for PDP, but if someone sees that it's a fit, we'll sell all or a part of it, but they've got to make a strong offer. My experience is when someone doesn't owe a lot of money, you got to pay up. I mean, we've got money in the bank, nothing borrowed on the line of credit, so you might want…

Definitely Joe. That makes a lot of sense. Thanks a lot for the color guys.

Well, thanks Gabe.

Thank you. Next question is from Ben Wyatt of Stephens. Your line is open.

Good morning, guys. Congrats on the good quarter and strong outlook. Joe or whoever on the team there, you guys had some commentary on potentially moving a rig to the Antelope Ridge acreage in late 2017. Just curious maybe what could get in the way of that not happening? We know that's really good rock and you guys want to get after it. But just curious why that would not happen sometime in 2017?

Well, Ben, I think it's going to happen. And it's an excellent question. We thought the same thing. It's good rock and I've got Tom Elsener, our Vice President and Asset Manager for you to tell you what his thoughts on that. But, it's definitely scheduled for 2017. Tom?

Hey, Dan, it's Tom. We're really excited about Antelope Ridge. There are a lot of great target that we've outlined in the Upper Wolfcamp, Third Bone Spring, Avalon, First Bone Spring, Second Bone Spring, there are just a wealth of opportunities out there and we're excited to hopefully, if I can get David to approve some ASVs, maybe Q4 this year.

So you know how that may go. I think what Tom's saying, that's the reason it might not happen. But, David is going to surprise him and approve them, so [indiscernible].

I think Tom is kidding. This is his rookie earnings call. And so, yes, it's already been decided. I don't know what he's talking about, that we would like to do it in only good rock and nets are way up there. They're above [Technical Difficulty], they're 80, 87.5, they are good wells, very close to nearby, you don't have as much water. What's there not to like is that the only reason for a little bit of slowness, we've continued to add some acreage in that area and we like it. And I think you'll see something happen in the fourth quarter. And Tom and his team have been doing some good work, we think.

Yes, Ben. This is David. In all seriousness, I couldn't agree more with what's been said. It's a really good area and I'm certainly excited about some of the opportunities that the team is bringing forward. So, I suspect that here before the end of the year, by fourth quarter, for sure you will see us spud one.

Very good. Well, I appreciate that. And then maybe as a follow-up more, maybe just kind of housekeeping, but obviously, the processing plant there is kind of exceeded capacity. You guys have gone out and gotten some third-party processing. Can you guys share with us which plants those are, who those are with, just so we can keep an eye on things. And I'm assuming that will be there in 2018 that availability will be there in 2018 if they were just a hiccup in bringing this extra 200 million on?

Ben, not at this time. A lot of those deals are either right now confidential or in various states. So we haven't released that information, we will at some point in the future. But right now, as there's a scramble among midstream people out there for securing commitments, just don't think it would be wise to do so. They will come along, you can see the cash flow and the income growing, too, on the midstream sides. The plant is on time, on budget. We've had better than expected results. So, we have filled it a lot with our own gas. But, with this new capacity coming on, we will be adding and are pleased with the way all that's coming along. Matt Spicer, do you have anything to add to that?

No, Joe. I think you said it right, we're -- Q1 next year, [indiscernible] online with 200 million a day, and like we talked about a little earlier. I think marketing's done a real nice job with our production that we have. So when we come online with that, we'll have a homeport, plus the optionality of the other offer in case there is a hiccup.

And Matt mentioned a word there that, Ben is very important to us when we think about our midstream operations and that's optionality. So, we typically won't put all our eggs in one basket. We'll have multiple outlets where we can and have been going with our gas and crude and NGL products.

And the last thing on the subject, Ben, is we're not flaring any. This has been one of the operational advantages we mentioned to why we wanted to build a midstream as our guys have these wells ready to hook up. The midstream has been there waiting with a pipe, so we're not flaring. And from day 1, that's been, again, part of that team effort and the coordination between the teams to make it work out for us. So, we're not flaring, they've coordinated, we've got the gas going through and it's been a real win-win situation.

Well, very good guys. I appreciate taking my questions and keep up the good work.

Thanks Ben.

Thank you. Next question is from Neal Dingmann of SunTrust. Your line is open.

Good morning, guys. And Joe congratulations on the delineation. Joe, just one question. Could you guys talk about how you're continuing to boost your enhanced completion, specifically what you're doing in proppant and fluids as it pertains to Rustler Breaks and the areas? Thank you.

Neal, this is Matt, and thank you for the question. We're really excited about the things we've been doing and what we're going to be doing going forward. So, as you probably know, we're typically the pump more sand guys. So, we migrated to the 3,000 pounds per foot on a lot of our completions. We think the 40, 50 barrels per foot is probably right too. The thing we've been -- knobs we've been tweaking most recently are perf clusters spacing. So we've tightened up the perf clusters spacing, we call it high-density perf clusters spacing. And in addition, to that, the diverters, we've talked about in the past these high temperature diverters that we're very happy with and most recently, we've started using the lower temperature diverters. So, we'll continue to turn those knobs. And part of the exercise and one of the things that I think we do well is to look back. So, we'll continue to turn knobs here at a methodical pace, if you will and not make any fast changes, but very excited about the perf clusters spacing and diverters most recently.

Great color. Thanks guys.

Thank you. Next question is from Irene Haas of Imperial Capital. Your line is open.

Hey, good morning and congratulations on your Twin Lakes exploration. In your press release, you mentioned a little bit of a completion challenges. So, I would like to have a little color on that. In addition, on the Cimarex project, how far it is versus the Culbertson 234-H and what kind of targets are you guys looking at there with the Cimarex well?

Okay. Maybe I'll take those in reverse order, Irene. With regard to the well to the West, I suppose that that must be, what, 6, 8 miles to the west. And as Brad mentioned, just a few moments ago, the Wolfcamp over there is thicker, it's about 800-foot thick the Wolfcamp D, as opposed to at the eastern location that we just drilled. I think that the -- as Matt, I think said a minute ago there were even a couple of targets that we debated where to put the landing target in this first well. And certainly as we get over to the Western side of the acreage and the section expands, I know that there will be a number of other landing opportunities. As we mentioned in the release, we're actually going to do some tests in a vertical well that's right near this location that we proposed at the moment and try to get some additional information on running some logs, some case toll logs, running some kind of pressure, frac pressure tests on that well to kind of help us in identifying the landing target and getting some information sort of a priority drilling this well that will help us with the frac design. I would say on the frac side, I would really complement our team on their ability to get this well fractured. And I think they put away 35 stages in this particular well. They got most of them away. We did have some challenges as we referred to. I think the frac pressures were a little bit higher. But again, I think a lot of that could have to do with the landing target. And as we change our landing target, our interval, that I think that we'll find perhaps a little bit better interval to frac, in fact I'm confident we will. So it's a, I think, for the most part, as Joe mentioned, we'll have the opportunity to use diverters in the next well. I didn't want to complicate this job or with that this particular time. I think we'll always look at kind of the sand loading, I mean, we've experimented down in Jackson Trust, for example, with going with a little bit more of kind of a slick water type treatment that may be something we look at in this well in some stages. So, I think that it's just, as in all places, we start off with what we think will work best and we kind of evaluate the results that we get and then continuously improve upon the design. And in every area we've been, that's what we've done and so we kind of gravitate what seems to be working the best. So I think that's the approach that we'll take here and I expect that we'll continue to improve as we go forward.

Great. Thanks. So it sounds like to the West you possibly could have more than one target to work on. And so it would probably take you guys a few more wells to even begin to understand the full potential for this play?

I think you're right, Irene. And even on the east side, there's at least two zones to give a look at. And the same thing on the tinkering, I thought Dave you gave a good answer on the different challenges. But, anytime you frac an exploratory well with a rock, you have so little data, you got to kind of experiment as you go and we're going to have more information to design the next one, as one example is just the kind of sand that you use. We changed it up on some of the different stages and it worked better. So we learned things as we were doing it. And we're encouraged and we don't want to overstate, but also just like the way we started out in these other areas it wasn't -- you don't begin with a home run, you generally get movable oil, get your cost down, make it work, and this one appears solvable to us. So, I'm sure there will be more to come. The other thing that hadn't been mentioned is this acreage up in here lends itself to the longer laterals. And we're going to test that idea with Cimarex up coming. So I don't know quite what to say because I knew everything this has drawn a lot of attention and we were pleased to report what we did, but we're -- as someone said early in the beginning, we tend to get better on these wells and we think we'll get better here. We just don't want to get in a hurry, would want to do the methodical approach that we use wherever, but we're spending more money, we put our money where our mouth is, committing to another well and even buying acreage in here that this thing still shows a lot of promise.

Great. Congratulations. And we look forward to seeing more surprises coming from the Twin Lake area. Congrats.

Thanks Irene.

Thank you. Next question is from Richard Tullis of Capital One Securities. Your line is open.

Thanks. Good morning, everyone. Also echo congratulations on the quarter. Real nice quarter lowering cash OpEx, Joe and the team. Current thoughts on ability to retain this level of execution and maybe even drive cost down lower on a BOE basis?

Well, that's what we've told our staff to expect. We challenge them to keep finding ways to continue this execution and continue to try to lower cost and be the low-cost producer. I think that we're gaining economies of scale out here, which is helping the overall cost. And I give a lot of credit to our guys in the field. They really work hard out there and they come up with a lot of good ideas. Our production staff here has come up with a lot of good ideas. And there's things that they're doing, I think that are very imaginative. More central tank batteries, they've been doing a lot of study on various kinds of pumps and what pumps work best under this situation and there. And there's a lot of new pump technology coming on. So I like to think they will be resourceful and keep finding some ways to lower the unit production cost and we don't think that we're in the final innings there yet at all. Matt?

No, I agree with that, Joe. I mean, the scale thing is happening that's big for us. But, I think two things just we talk about them in the drilling completion and production, it's all about efficiency. And these guys are getting more and more efficient. I think the technology that's being used in the basin is evolving as well. We've been very successful down in the Eagle Ford with conventional gas lift. And we came out to the basin, the Delaware Basin and thought this is going to work for us our here, too, and it does in certain situations. We've tried another technique that you all may not be quite as familiar with is reverse gas lift, where you're actually injecting gas down the tubing and producing up the tubing casing [indiscernible]. The advantage there is you can lift north of 3,000, 3,500 barrels of fluid a day by doing that. That's a very efficient way to lift those wells. And in addition, if you've got -- if you're producing frac sand or any type of solids, that's a very efficient way to do that. But they're not just focused on conventional gas lift and this reverse gas lift. We've also got wells that benefit mostly from ESP. Ultimately, these wells will probably all go to [indiscernible] and then most recently, we've talked about and started utilizing jet pumps. So the guys are continuing to think about better ways to lift these wells. And at the end of the day, I've said this often before, Richard, but the drillers have these wells for two weeks, the completion guys have them for a week and then the production guys got them for 20 years. So, it's very important that we get those things figured out and I think we're doing that quite efficiently.

This is David, Richard. I just wanted to add one quick thing. Joe alluded to this a bit in his remarks, and it's not exactly an LOE thing, it's really not exactly LOE thing at all. But it is a CapEx thing and I would like to acknowledge the fact that I think our production teams have done a really, really nice job this year of getting the initial installation costs for facilities and tank batteries and what we need down this year. They've come up with some really innovative and clever things to reduce the cost and it's made a difference and we see that it's made a difference and I think subsequent hookups are -- we're probably $300,000 better than what we would have been a year ago. And so I really give them a lot of credit for as you see a little inflation out there in service cost, this has been an area where we've really been able to mitigate the overall cost on our well cost. And so I just want to acknowledge that. I think it's been a really, really strong effort by that group.

And I would like to follow up some that you've said, for example, on saltwater disposal. Our groups here have recycled some of that saltwater disposal. So you don't have saltwater disposal going into LOE. It saves some money on the frac side and has helped -- you've used the recycled water. And it was done very cleverly without a lot of direction from the executive committee. It's just the individual initiative of some of these guys come along and coming up one good idea after another. So, I'd like to claim credit for it, but really can't. And as I said at the beginning, it's corny but -- it's really neat to see a lot of the young professionals we have step up and make these kind of important contributions.

Thank you, Joe. That's helpful. And just lastly for me. Looking at this last acquisition, it looks like you were able to pick up that 8,000 acres at a pretty good cost there and lower than what you spent in the first quarter, Rustler Breaks, Antelope Ridge acquisition. Where exactly is this latest acquisition in any associated production with it?

Yes. Hi, Richard, this is David again. Well, first of all, just to be clear, it isn't an acquisition. It's an aggregate of a lot of pieces that were done during the course of the quarter. So as we've mentioned, the land team is very efficient and very good at being able to buy parcels of property, a lot of them sometimes much smaller than 1,000 acres. If we pick up working interest from participants in our wells, we pick up small pieces of acreage in the units that we're putting together. We trade acreage. And so the 8,300 acres really reflects over 20 different transactions that our land team control are being closed during the quarter, some of which might have been 1,500 acres and other of which might have 150 acres. But all in the aggregate and that's kind of what I think we've said a lot, we've been out on the road. We tend to build our house a brick at a time. And we've got some pretty good brick builders here. And so, I think a lot of credit is due to them for their persistence in making this happen. I would say that there was a very limited amount of production associated with what we picked up. Of course if we picked up additional working interest in a well, that would have been a small amount of production that would have come along with that. But by and large and as far as where it was, there was a little bit of it in Wolf, there was a little bit of it in Rustler Breaks, there was a little bit of it in Ranger and Arrowhead, there was some of it in Twin Lakes. So it's some more tetris pieces that are just all in and around where we are, one that we highlighted in the release that I was just thrilled about, this last quarter was the fact that we -- they picked up about 700 to 800 additional acres in our Wolf property, they made a great trade that enabled us to have a much better operated position in one portion of our Wolf property and probably added 32 operated Matador locations. So, those kind of things sort of fly under the radar, but 700 acres sometimes doesn't get a big headline, but I'm telling you, it makes a big difference not only in your ability to operate the number of locations that you have, the reserves that you can book and so a shout out to the land guys for that.

Thanks David for that clarification. That's all for me.

Ask us how we really feel?

Thank you. Next question comes from Jeff Robertson of Barclays. Your line is open.

Good morning. Joe or the team. With all of the results you all have posted in different zones across the asset base. Can you talk a little bit about how these results go into shaping your priorities of what you want to test in going out through 2018? And not so much how many wells you drilled or capital spent but just which zones you want to test to learn to push your understanding of those zones to further the development?

Jeff, that's a really hard question to answer. Our process on identifying what wells is very much a reiterative process. The teams will propose certain wells and within the team even, you may have the geologist lead on the teams, want to test a new zone, the engineers want to do something a little different or vice versa. Your land people may want because of depending on whether the lease is held by production, or whether you're validating it to drill a zone that earns the most acreage. And then come back and do the other. And the same thing, you look to basic economics of oil, the Blair shale is a little gassier. But, those are some great wells but they're a little gassier and maybe you want -- you look at your oil mix, and then they propose wells to Matt, David, Brad and Billy and they talk about where the rig is located and what sort of move makes sense and even do you want to do this from a pad? And so there's a lot of -- I would say a complex decision and everybody has a say in it. But somehow at the end, it works. And there's general consensus on what we should do and why. And then, as Matt likes to say, on the drilling side, he and Billy are very good about changing the plan as we look at competitors and what new zones they test and come up with and sometimes match. And so we alter the course of drilling during the year. And what we try to avoid, doing is drawing lines and say we're only doing this as Matt said earlier in this call, we have a saying around here where we reserve the right to get smarter and alter it if the competitor on the other side of the fence has drilled something good. We try not to just fall in love with our own stuff, but be open to new ideas there or our new opportunities that may come up. David, Matt what would you add to that?

I think used the word there, complex, Joe. I think that kind of sums it up. But it's a number of things that we look at, Jeff, and is something the teams spends a lot of time talking about and first off, the rates of return have to right. We're not going to drill uneconomic wells. And so, how the land factors into that and geology, and then you've also got this mix of delineation and development that you want to do. We also want to throw in some different spacing tests so we can get that figured out early on and make sure that we're developing these properties very efficiently and in the right way and I think one of the most important things that we said is, we do keep our head up and we look around and we pay attention to what others are doing and run our business accordingly.

I think, Jeff, you also always have the considerations of as you work to get your assets held by production, both not only aerially but vertically, you have the considerations as to want to drill the deepest zone first in some places so that you hold all those [indiscernible] above it and I think also there's always consideration in terms of the strategy of developing your acreage such that it maximizes your reserves as well. So there is a lot of things that we consider when we're putting together our programs.

Thanks. Just to follow-up on Avalon well that Barnett test. Would the second Avalon test be the other potential landing zone at this point or is it too early to tell?

It's probably a little too early to tell although I don't think that's unreasonable likelihood. So, as we mentioned, that's about a 800, 850-foot thick section and our team had entered their five to two specific or two kind of primary landing targets that they liked. We chose one. And it wouldn't surprise me to see us test the other going forward. But, I think a lot of it just depends, of course, on the results from this well in which we're excited to start seeing here pretty soon.

Okay. Thank you.

Thank you. Next question is from Jeff Grampp of Northland Capital Markets. Your line is open.

Good morning, guys. Wanted to follow-up on this prior question you guys were just talking about doing some, I guess different spacing tests, and obviously you guys have done a great job derisking a ton of different zones here across the asset base. And just wondering if you guys have any spacing tests planned in the near term or medium term here, either, I guess, within any particular landing zones or on a stacked basis, for example, doing an X-Y and lower and some kind of stagger stack configuration? Have you guys looked at doing any of those types of tests here?

Well, Jeff, it's David. I would say that as far as having a specific spacing test in the way that I think they sometimes are thought about in the industry, I would say it'd probably be sometime next year before we would probably have something like that done. That said, you can go back and look at some of the wells that we've drilled. I think, for example, the Janie Conners or the Tigers, for example, they are essentially off the same pad area and we probably have 8 or 10 different wells that are going into multiple zones of the A and the B there now. So I think we're able to observe some things from that, draw some conclusions from that. They may not have been necessarily the classic. We announced we were going to drill four wells in each direction from this particular pad and have an eight well spacing test per se. But I think that we've done some of those kinds of things and are learning from those even though the timing may have been a little staggered on it. Look, we contemplate all the time. Putting a rig on a particular pad and drilling multiple wells and it may be that as early as next year that we -- certainly we always drill -- we drill multiple wells already. We drilled 2s and 3s and 4s, but we certainly kind of have some ideas in mind for some more significant tests like that. But, I don't want it to be lost the fact that we certainly have got 8s and 10s in some places, that I think you would almost consider to be a spacing test if we had done all exactly at the same time.

Okay. Got you. That's all real helpful. And at Arrowhead, since I don't think anyone has given you kudos for the Stebbins well here yet. Can you give us a sense you guys mentioned doing some future development on that acreage block? Can you give us an idea of how big that block is? And if I recall, some of the federal land, you guys had had some higher NRIs, so can you talk about if this area has any of that or if that's kind of the standard 75% there.

As far as the NRIs go, I mean, it is a federal block and I think that there are portions of it that have some enhanced royalty interest as a result. I'm going to have to ask Trent exactly on the size of it. So it's probably 9 to 10 gross sections, I guess. And we have different working interest in each one. So it's a fairly sizable area for us and I will say shout out to our, again, land group, and particularly the team that's been working so hard, Sam Pryor and Edward [indiscernible] that have been working so hard on getting these federal permits in place. This was, of course, all acreage, it's Fed acreage. And so as we've mentioned that we've been working for a while since we made that acquisition, as we said in the release, we've got 14 or 15 permits that right now that are ready to go, that we can drill. So I appreciate you bringing this up because we were real excited by this First Bone Spring well and we've got a Third Bone Spring Well right under it that I'd hoped we would have been able to release results on at this call. We just didn't quite get it complete on production in time. I shouldn't say complete, because the frac guys will fuss at me if I do that. But in any event, it's one that's just started to flow back. So I think we'll have results from them pretty quickly. But it's an area that we're encouraged about. I think the Stebbins result was excellent. I mean, 1,000 BOE per day. And it's really just held up beautifully. I mean almost no decline -- I mean the 60-day rate from it is about 1,000 BOE per day too. So it's really done well, optimistic about the Third Bone Spring and that's an area where too we have some encouragement for drilling a Wolfcamp A-XY kind of well. And so -- and another I think target that you might see us be testing sometime next year. So I just feel like given the size of the block and the number of permits they already have in place that it's a real encouraging start. Also, I might mention that it does probably lend itself to some longer laterals, too, just given the configuration of the block. So I think we have a lot of optionality there, Jeff.

And Jeff, thank you, we were afraid we were going to have to bring that up ourselves.

I did my job, then. So, I end on a high note. Thanks guys and a great quarter.

Thank you. Next question is from Adam France of 1492 Capital. Your line is open.

Good morning, guys. Thanks for squeezing me in here. I'm guessing the answer is lease related, Joe, but why did you choose to start on the east side of Twin Lakes with 400 feet of thickness, the west side was 800? Was that a lease issue or…?

No. It was more that the pilot hole we drilled was over on the east side. And we wanted to be fairly close to it. That was the Olivine well. We ended up completing not in the Wolfcamp D, but because of the Strawn looked so good and that well, as you know has been flowing back and has made 75,000 BOEs and we were just trying to stay close to where the most data that we had on the acreage play. And now that we've tested the east side, we'll go to the west side. But, we debated whether to begin on the west and go to the east, but thought it was best to go east to west. Matt?

Yes. That's right, Joe. And kind of the thought process was initially we knew we had enough acreage out there. We got 30,000 acres that one well was going to be sufficient to test it. But, the team looked at the Strawn and said this looks like maybe something we were interested in, in looking at. And oddly enough, Adam, and you probably remember this, it was going to be one of these deals where we'll drill down through the Wolfcamp into the Strawn and hopefully we can produce the Strawn for a few months, while we're getting all the data back on the whole core and the logs and picking our landing targets and give us something to generate a little cash. Well, the Strawn well was good enough that we just elected to drill the D Culbertson as opposed to going back in and sidetracking that well. So that's been a good thing for us. And like I said, the second well was always in the works here anyway. So, we're looking forward to heading to the West.

Right. As you think about the West and forgive me I'm not a geologist by training, is that 800-foot section deeper and you might expect better pressure or is it fairly flat as far as this area goes?

This is Ned here. It's a little bit deeper over to the West and I think even locally within the eastern fairway, you might find pockets of higher pressure. I think 0.6 psi per foot pore pressure gradient is actually quite a respectable pore pressure gradient. So I think we're happy with what we encountered in the east. And if that's what we got in the west, we'd be happy with that as well. But to that end, I think I'm optimistic that we'll see a little bit higher than that in the west. Really kind of going back to the characterization on the east side, one of the reasons we also picked the east was the Strawn to help offset the cost of that well, but it's a little bit easier to characterize the whole section over on the east side. So that was part of the thought as we wanted to get a look at the whole Wolfcamp B to be able cut whole core across all of that. And I think we really learned a lot from that that helped us get to a pretty advanced point on targeting, picking the right window for drilling and I think it will help us optimize completions moving forward. So, we like both of those targets and I wouldn't say it was a coin flip, but the fact that we jumped into one side versus the other doesn't really mean that we like that one more than the other. They're both, I think, completely viable and we look forward to drilling the Western well soon.

Okay. And have you and Cimerex decided on lateral lengths yet? What are the key issues as to whether it's 6,000, 7,500, 10,000? Any thoughts there, guys?

Adam, that technical work is being done and I don't think there's a final decision. It's progressing. And in all of this, when you're in an exploratory deal, it's not like development that you got a lot of data points and you can get a scheme easily. This is one you want to propose and then get everybody to think about it and refine the idea as soon as you go through. So that's development. I mean the really encouraging thing is that you have moved the oil. And that's more important than the pressures. The pressures are certainly satisfactory or sufficient that you could do something with. You're looking for permeability, either natural or what you can create through fracking and these other innovations and the diverters and the pump and deal and that's why we're encouraged. But, it's going to be a methodical approach just the same way as we've gone through all these different formations in other areas. Each play is different. And it's off to a good start. And, I mean, you have commercial -- you have it at those rates, clear path towards commerciality. And it's just our work, and you don't want to waste money or even if you do it methodically and plan it out, you'll spend a whole lot less on your exploratory efforts than if you try to rush it. And I kind of like the way that we're using the core to help balance. I'm glad we're working with other operators. And I like our chances, I guess that's what it comes or we do. We like our chances and we like the ways it's coming about.

This is David, Adam. I might just add one quick on it, which was the, personally, the pore pressure rating was actually better than I thought it was going to be here. I thought that we might have 0.5 kind of gradient for some of the things we looked at before. So the fact that we had something that was 0.6 or so, I thought was actually quite good. And you got to remember, too, like the Bone Spring they're in the northern part of the acreage, it's pretty well a normally pressured environment and still yields some very good well result. So again, I think we see that as a positive data point not a negative data point.

Got you. Very good. Thank you guys.

Thank you. Next question is from the line of Geoff Jacques of Iberia Capital Partners. Your line is open.

Good morning and thanks for taking my questions. Just looking at the 2016 Wolfcamp B wells, those wells look pretty strong, I guess the last few months. And I was just curious how you guys think about type curve increases. And obviously, you're very deliberate in the way that you structure things. So I was just hoping you could provide some color on that?

Well, I'd say first of all, we love to have it. So, generally, that's how we feel about it, we love them. So in terms of, specifically, look, I think we're pretty much in the feeling that you need to give these wells a little while to see how they're going to perform. I think the range of type curves that we have for the Wolfcamp B, you may recall, we raised them from 2016, where they were 800,000 to 1 million BOE, to 1 million to 1.2 million, so we did give them a 20% or 25% nudge at Analyst Day. And I'm pleased that the results of the 2017 class seemed to be meeting those loftier expectations and some other of them were even running above that. So I think that as time goes, we may find the need to bump that up a little further, Geoff. And certainly, we'll do that when we think that's appropriate. But you know us, we typically kind of make those moves, maybe on a little bit more deliberate kind of basis and usually sort of around our Analyst Day is when we choose to do those things. So I would say if we make a move, it will probably be late in the year or early next year before we would move those.

The other thing is that we do the reserves typically twice a year, end of the year and then the Analyst Day. And we're very pleased to have added the reserves that we have. Brad, will you give a little detail on our reserves picture?

Yes, Joe. Thanks, Geoff. We of course have announced that we had a 27% increase in our reserves just in the first half of this year. And so a lot of these wells are actually performing better than expected. And of course, we've had roughly a 40% increase in our reserves just in the past year. But a large portion of that has just come this year due to better well performance. So we're real excited. And as David said, we are pretty methodical in how we analyze these wells and our projections and so forth. It does take about 6 months to a year to establish a fairly predictable decline on these wells. So we're always looking at our type curves and tweaking them to correspond to the actual well performance. So, we're really pleased with the way they're performing and have really enjoyed an increase in our reserves base as a result.

Great. I appreciate the details. Thanks.

Thank you. Next question comes from Gordon Douthat of Wells Fargo. Your line is open.

Hey, good morning, everybody. Just had a question on Twin Lakes area, just given the vertical well result you've already reported on. Do you see any horizontal potential in the Strawn?

Gordon, this is Matt. And we've talked about that, and the answer is yes, there is this potential there. It's a more conventional type reservoir. So we would possibly look more like an Austin Chalk type well or something like that. We have talked about it a lot, and don't have it on the schedule for right now. But it is something that we'll [indiscernible] there.

Okay. And then I know you've got that sixth rig that's out there temporarily. But previously, at your Analyst Day, you'd mentioned the potential for a sixth rig in 2018, and we've had commodity come back a little bit, but just wanted to get a sense on what commodity price levels you'd be looking at to potentially add that sixth rig back full-time in 2018?

Gordon, you've asked a very good question that we're discussing every day. And quite candidly, if you'd ask me two weeks ago or three weeks ago, it would have been unlikely that we would add that because the price of oil was down. It's come back a little bit into that area of which way is it going to go? Is it topping out to go back or is it going to keep strengthening? So we're waiting to make that decision. We've asked Billy over here and the teams to plan it both ways. And so that we can either go to a sixth rig or stay with five depending on what makes most sense for our shareholders. And so those things are being considered right now. We'll have a better answer by towards the end of the third quarter.

Gordon, this is Matt, and we've consciously built in a lot of optionality into our rig contracts. We have a great relationship with Patterson and really like using their rigs and working with their management team. So what we have of the six rigs, three of them are on longer-term contracts, and they're not really all that long, they're about 1.5 years left on those contracts. The other three we've layered in on shorter term contracts where we can go from the six rigs to five, to four if we even wanted to go to three. So we've got a lot of optionality where we can do that in the short term. And I'm also very happy that Billy has been able to put together the rigs that we have. It's not like we have anything, but A-plus rigs out there -- they're the higher tech rigs and we're happy with all that we have right now.

Billy, you want to add a word on the caliber of rigs we have and what we like about them?

Yes, Joe. The Pattersons worked with us to stay out in front and keep the rigs that we want to work with available with all the high-tech equipment. And recently they wanted to try out some new things on their rigs and they came to us and proposed we try them out because they enjoy the way we get the most out of the rigs that they [indiscernible].

Give a little specific on how they're equipped differently from what they were two or three years ago.

Right. We had the -- we started out with the 7,500-psi system, which was strong and helped us out a lot. And we've moved on now, they have a high torque top drive they've added, and we're also trying out a third pump and generator. And on that rig specifically, we see no down time due to pump. So that's helped us out a lot, helped us be more efficient and cut days off the well.

One of the things that this high torque, high horsepower top-drive allows us is going to allow us to do is have better rotating capabilities on these longer laterals that we've been talking about. We were just talking about the Stebbins block and having a longer Second and Third Bone Spring laterals. And that being sandstone, there's more torque involved in getting those drilled. So this rig will be very well suited for those type of operations.

Does that answer your questions, Gordon?

It does, yes. Thanks very much.

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

Thank you very much. Just a couple of closing remarks that I'd like to note that I give credit to David and his group, Michael for their accuracy in the guidance. I think this is the 12th, at least, the 12th straight quarter that we've had where we've met or exceeded guidance. And we've had great team performance, but it's also been good that the financial group and the planning group with Brad have been so accurate in trying to steer the guidance. One of the things we're trying to continue to always to establish is our credibility that we'll do what we say we'll do and that the information that we provide you is useful and would like to thank everybody for these, again, these great results. Appreciate the good questions. Want to, again, invite all of you to come see us. We'd like for you all as analysts and the like to come see us and meet the staff and see -- try to see the depth that we're making. We didn't get the question about staffing, but very pleased with our staffing, with the new people that come in the past year or two are really stepping up and making contributions. The management team has really executed. And we're delighted that we have been making the progress that we have. Got a lot of work ahead of us. But, as we exit this, you may remember two or three years ago, we said we were peak, we were growing in the Eagle Ford, establishing this position in the Delaware. And that would become increasingly important. The first wells being drilled in 2015, end of 2014, and that by 2016, it would be about half ours. And today, it's about 80%. So we have good wells this quarter in the Haynesville as Chesapeake completed that three [indiscernible] our gas increases weren't due to Permian, they were due to the Haynesville. So we are continuing to get oil there, maintain our proved developed reserves percentages, while adding more reserves to the base. And congratulations to the Eagle Ford team for pulling the rig out of the yard and drilling it in record time. Billy, good job. And Midstream, thank you for us not having to flare out, hope you know we appreciate that very much and also all the teams. So with that, I'll turn it back and end the call. But, thanks again for your interest and support and come see us.

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