Matador Resources Co (MTDR) 2017 Q1 法說會逐字稿

Good morning, ladies and gentlemen. Welcome to the First Quarter 2017 Matador Resources Company Earnings Conference Call. My name is Ayelah, and I'll be serving as the operator for today. (Operator Instructions) As a reminder, this conference is being recorded for replay purposes, and a replay will be available on the company's website through May 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, Ayelah. Good morning, everyone, and thank you for joining us for Matador's First 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 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 annual report on Form 10-K.

Finally, in addition to our earnings press release issued yesterday, I would like to remind everyone that you can find a short slide presentation summarizing the highlights of our first quarter 2017 earnings release on our website on the Presentations & Webcasts page under the Investors tab.

With that, I would now like to turn the call over to Mr. Joe Foran, our Chairman and CEO. Joe?

Thanks, Mac, and good morning to everyone on the line, and thank you again for participating in today's call. We appreciate your time and interest in Matador very much, and we especially appreciate the many kind words that a number of you had for us and let you know how much we appreciate those and how much they meant to us.

Now I would like to introduce the senior members of our operating staff who are joining me this morning and 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; 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; Trent Green, Vice President of Production; Rob Macalik, Vice President and Chief Accounting Officer; Kathy Wayne, Vice President, Controller and Treasurer; Bryan Erman, Vice President and co-General Counsel; Brian Willey, Vice President and co-General Counsel.

I am proud to announce this first quarter of 2017, which, of course, was one of the best quarters delivered by the Matador staff, and I would like to highlight to thank the staff. Everybody really pushed on the rock this quarter and made the train run on time.

Now I'd like to highlight a few key points before taking your questions. As we've been on the road the past month or so, meeting with a number of shareholders and attending a couple of conferences, a number of questions routinely came up. And we're here to answer all of those, but also, I'd like to be sure to note on the financial end of it, we're pleased with the financial status of Matador. We've got over $200 million in the bank and nothing drawn on our line of credit. And second, that this quarter obviously has record production but larger and larger contribution from the Delaware. Third is our midstream joint venture with Five Point. It's off to a strong start, and they have further plans in line that we'll be happy to discuss today. And finally, we're an oil and gas company, and I think some of the technology advances and the better operating practices that have been advanced by our staff are really extraordinary and really helping the results as we should get in, in today's conversation.

So with that, I'd like to turn the call back to the operator for your questions.

(Operator Instructions) Our first question is from Irene Haas with Wunderlich. Our next question is from Neal Dingmann with SunTrust.

Joe, a question for you or the group. You've done a great job on smaller acquisitions at great prices. Number one, just do you see the potential continuing for that at these levels? Or just if you could expand a little bit on what you see for acquisitions out there.

Yes, Neal. It's a good question. And the answer is, obviously, yes. We think that these will continue to occur. Well, I think you -- maybe think about this, is that we're acquiring acreage in several different ways, several different pipelines, so to speak. But one is just this, out there, nibbling away 500 acres here, 1,500 acres there, averaging about 1,000 acres a month. And we have over 100,000 acres now. And if you do 1,000 acres a month, that adds 10% for the year, which is pretty good. And it's a lot of hard work. It's kind of like door-to-door selling, but the staff has got a full pipeline and has done really good work just nibbling away. The second pipeline is that when we've been proposed wells, we'll almost always, by the time we drill the well, acquire some additional interest from working interest owners who want to make a deal as opposed to participate in the drilling, and we welcome that and try to be fair with them. And so they'll want to do it again down the road. And then the third area that has been working now is there's been a lot of cooperation out here in Northern Delaware between the operators of trading acreage that is a win-win deal. We trade acreage that's in somebody else's section for a similar amount of acreage in our sections. And we get something of greater value to us, and they get something of greater value to them, and both sides comes out ahead. And so there's been a lot of great cooperation on their own operations, and so we've always liked the Northern Delaware in part for this reason. And then we've also had another pipeline on working on some mineral acquisitions, which enhance the working interest position. So we feel pretty good going at it at all different ways. And that wouldn't move the needle for a Marathon or Chevron or EOG, but it's working for us at this point. And I give a lot of credit to Van Singleton, our Head of Land and his group of land team that have been -- have done a lot of solid work and are building a lot of good relationships out there.

Neal, to build on what Joe is saying there, when he's talking about adding 1,000 acres a month, we use the term around here, surgical, to make sure. And I think he's exactly right. The 1,000 acres that we're adding, we think, is really, really good acreage at a really good value. So it's -- I don't think that you have to add at 5,000 or 50,000 acres at a time. I think you can do it 5 acres or 500 acres at a time as long as you're doing it in the right areas for the right price.

No. It certainly seems to be working, guys. And then just one follow-up. Joe, that Antelope Ridge area you had, it certainly seems to be very attractive. I know it's early. When you guys do start developing that later this year in Antelope Ridge, do you have a plan as far as what you'd be targeting would be similar to what you're targeting in some of those other sort of Delawares around that? Or any color you can give around how you see sort of tackling that later this year.

Well, obviously, we're very excited and pleased to be building a position in Antelope Ridge. It offers a lot of opportunities. And I don't think we decided which zone we want to test first in there. And we want to see a little more if we're able to acquire some additional acreage. But we'd like that area for a while and are pleased to have at least a footprint in there. The other thing on this, on acquiring acreage is we -- I don't want anybody to think we don't look at some of the bigger packages, but we run -- we had quite a bit of success acquiring in smaller chunks. But we'll look at that, and we may well do a deal sometime on a bigger package. But if we do, it'll certainly have a very close mix as probably with what we have where it's a better-than-average fit, and they'll have some midstream rise to it because midstream has been really incorporated, become part of our business like land or geology or engineering. And if those 2 can enhance each other, then it certainly gives a greater rationale for doing a larger, more expensive acquisition.

Our next question is from Irene Haas with Wunderlich.

My question has to do with this quarter, you guys have shown a lot more results from the Second Bone Spring towards the Northern Delaware basin. This is probably a bit new. And can you do a little bit of compare and contrast and your feelings as to how much proppant you might need to put into these shallower horizons?

Irene, this is Matt. And it's a good question, and we typically tend to go big on these fractions. So we've pumped some with 2,000 pounds per foot and had good results. We're testing some with 3,000 pounds per foot that we're also having good results. And then as always, it's a process to evaluate the IP, the 30-day, the 3-year number. So we're encouraged by the higher proppant volumes. In addition, we're pumping diverters now on some of our Second Bone Spring. We got the low temperature diverters that are working, so it's kind of a mix of continuation of how these things evolve. But a lot of proppant volumes look good right now.

And how is the performance versus your deeper horizon and sort of the equivalent economics? Does it cost less to drill these wells?

Yes, I would -- this is David, Irene. I would say that the initial performance is pretty well as expected on these wells. They may not have initially quite as high IP rates but they often will tend to decline a little bit slower. And I think that's just a little bit of result of the fact that it's more of a tight sand than it is the shale. And we've -- we have had some really -- if you go back 2 or 3 years when we were first drilling out here and talking about the Ranger 33 and one of the first Pickard wells, those wells have continued to perform very well and are up around our of 700,000 BOE type curve. But I think as we showed in our Analyst Day presentation that the returns from these wells, if we kind of hit that, even at the lower end of the window, at 500,000 BOE with the $50 oil, and if we can get these wells down for $5 million or so, that you're talking 70%, 80% kind of returns on those wells. And I will say that a couple of the recent wells that we've done, the Elands that we talked about in the release, we got both of those drilled for around $5 million, maybe just slightly less when it's all said and done. So I think we feel pretty good about the returns. And they can be very comparable with what we see in the deeper horizons, as you point out, because they are a little bit cheaper to drill. So I'd say, so far, so good.

Our next question is from Scott Hanold with RBC Capital Markets.

Could you discuss a little bit in Antelope Ridge, from an infrastructure perspective, is that going to be pretty well integrated with San Mateo? And remind me of any like current dedications on that acreage over there.

Thanks, Scott. It's too early to predict exactly how we'll configure that. Of course, it's -- I will say, it's highly likely that San Mateo will be involved, but it's just too early until we process all of the options. The -- we're very excited by Antelope Ridge and think it's going to fit in well with what we already have. And so those plans are being tried to put together and to see which way we can go that will add the most value. We're not just trying to build up San Mateo. We're trying to build up the overall value of the company. And we think San Mateo was, again, likely to play a role, but we want to maximize the opportunity. The acreage at Antelope Ridge is not dedicated to San Mateo at this time. It's not dedicated to anybody. So we haven't -- the San Mateo, we didn't obligate ourselves to do that. We think they're a logical option, but we also want to see what other opportunities might be out there.

And Scott, this is Matt. In regards to the infrastructure, that's very much like the rest of the basin. There are existing pipes in the ground and relative power and all that stuff due to the legacy production out there. So that's something that we're able to kind of take a measured pace approach about how to do this JV thing out there. Whether we are or what it's going to be, if it's going to be processing or saltwater disposal or both or if there's enough to build capacity out there for us to utilize what's there. So it will be a process.

Okay, understood. And a follow-up question then is on the Culbertson State well. It sounds like you're encouraged with what you've seen so far. Is there any kind of color you can give us on what you have seen so far in terms of like oil saturations and in pressures during drilling?

Scott, this is David. I think we're probably -- we probably prefer not to say much more about the well than what we've disclosed on the release. Look, we were happy with the way the well drills. As we mentioned, it drilled a little faster than we thought. And we saw some good -- some nice shales on the wellbore as we went along. And so that's always -- those are always nice signs. But I think we're a long way from still knowing what we got there. So I think at this point, we'd probably prefer just to sort of leave it there.

Our next question is from Dan McSpirit with BMO Capital Markets.

How much more blocky or contiguous will the company's leasehold look at the end of the day through these acquisitions or trades? That is, does your footprint change more in complexion than in size?

Dan, that's just -- that's impossible to say what you're -- I mean, like what are your demographics be in a given area. You don't know how the population's going to grow. You just know it's going to grow. And we're not trying to dig one and say, we're only going to grow this way. We'll take the opportunities as they come. And I think the footprint will continue to grow in fits and starts, so that you'll get more blocky, you'll get more acreage, and then you'll fill in the gap, then that might help. So that's hard to say, but we're not saying working in New Mexico is you have a degree of force pooling that if somebody then want to drill, you can generally file your proceeding and get them to elect one way or another. So it's harder to block than, say, in Texas, where if you have a gap, they can just stay out if they want.

And just -- Dan, this is David. Just to kind of add to what Joe said, it's -- certainly, I think there'll be a little change in the complexion. I think there will be continued change in the size as well. So I think things will go in both directions. But as far as just change in the complexion, I -- again, sometimes, these trades don't sound like a big deal when you talk about the fact that, oh, maybe you traded 500 acres here, 400 acres there, 100 acres here. I mean, it may sound sort of small but some of those 400-, 500-acre trades can lead to -- I know we have one that we're working on right now that when it finishes up, it probably will add 15 or 20 locations that we can drill and operate that we couldn't before. So I think that's years' worth of drilling, so it can make a real big difference.

Well, I appreciate the color and appreciate certainly that it's -- it remains a work in progress and very much in active development. As a follow-up to that, the market seems to be coming your way. That is, other -- and maybe in some cases much larger operators appear to be getting more aggressive in the northern Delaware, either through acquisitions or putting capital at work. That's certainly a good thing. But do you anticipate the market for completion services getting tighter than maybe initially anticipated? Was it maybe cost inflating at a faster pace?

Well, Dan, I think it's not a single variable. I think you've got a number of variables that will influence that. One is price. I don't see, if price goes down, they will become more available, and the price goes up, you may have some increase in competition. The other thing to keep in mind is, I think that's why it's important to have long-standing relationships with these companies. We have long-standing relationships with Halliburton and Schlumberger and Baker. And we -- and they've worked with us really well. We have one dedicated crew at this point, and we've been picking up a second crew from time to time. And our staff's done a good job of fitting them in and getting them done at the same time, so the logistics have been good, and there have been price savings. But hey, I would like to have the high-class problem of increased competition with even some price escalation because that probably means oil is getting up there, approaching $60 or so. And I would call that kind of a high-class problem. I think -- I mean, it's nice to have a lower cost, but it's even nicer to have higher prices. So if that should happen, we'd gladly deal with it. And if not, I think things are working pretty well out there. Matt, what would you add to that?

I agree, Joe, and Dan, not to keep beating out of it. This relationship deal is really important. And one of the things that I think we made a lot of headway last year is continuing to operate in the basin and utilizing those services. And there's some follow-through, there's a momentum that comes along with that. And so I'd like to think, and it's worked out so far, that we're going to be giving a good audience with those service providers, and Halliburton has done a great job. And as Joe said, they actually provided a second crew to us when we need it. And it's not that we have to commit to a second crew for so many days. It's kind of like when you guys need it, let us know. Give us some time. There's a lot of planning that's involved, but we got a few wells that were queued up to be completed, and we thought we needed a second crew, so we added it. And they came in, did some work, they've gone away and they're going to come back here pretty soon to get us caught up. So I do think that Joe is absolutely right. There's going to be commodity prices. It's going to affect this. And it's going to be, to me, more of a timing issue than it is necessarily availability. I think there's lots of equipment that's on the bank, if you will, that's ready to come back to work. Finding personnel to do that is going to be an issue in getting that stuff up and running. So it may be a little bit of a lag, but I think our relationship with our service providers will help us through that.

I appreciate the answers. I could use a high-class problem myself.

(Operator Instructions) Our next question is from Geoff Jacques with Iberia Capital Partners.

On that third rig at Rustler Breaks, I know you mentioned in the release the possibility of moving that over Antelope Ridge in the second half. Could you discuss what circumstances that you guys would do that?

Geoff, it's David. Sure, I think, really, it's just probably a matter of we just finished acquiring some of that acreage, and there's one particular piece that we have our eye on to kind of put our first well on. And that it's just a matter of sort of digesting it and have the team go through their planning and get the well on the schedule and get it permitted and get it ready to go. So -- and I would imagine, of course, if we move the rig over there, we'd probably want to do maybe 2 or 3 to get started. And so it's just -- as much as anything, it's just kind of starting to get the logistics lined up around that. I can assure you, there are a number of people that are very anxious for that to happen and that are working very hard to try to facilitate that being more of a 2017 event than a 2018 event. So I wouldn't be surprised if we do it, but we do have a few things we got to do to get ready.

Our next question is from Richard Tullis with Capital One Securities.

What's -- Joe, what's the plans for the -- over the next several quarters for the acres that you have on the Jackson Trust area, given your Totum well results and some nice offset operator, Wolfcamp results?

Richard, it's David again. The -- we have another well that's in that vicinity that's scheduled to spud, I believe, in the June, July time frame. And then we'll kind of look at that well. And then currently, we have another well, but -- another couple of wells that we're planning to come back and drill right toward the end of the year. So I think we'll definitely have one more test that will get on production this year. Then we'll have a couple of wells that will be drilled, but they probably won't come on production until the first part of 2018. But we're real pleased with the Totum results and how it's continued to hold up. We're also kind of encouraged by some of the stuff that's going on at the east, as you know, there now. So there have been some nice wells reported by their operators to the east. So I think it's -- that we're, of course, always good stuff to the west there. So we're -- we continue to be very encouraged with that, and I think we'll continue to drill there pretty methodically over the next few quarters.

That's helpful, David. And what's the acreage holding today? I know you have about 8,400 acres in that, in general Loving County, but how much of that is Jackson Trust?

There's, I believe, on a net basis, Richard, it's 3,750. And I think that's a 7,500-acre track that we have a 50% interest in, and so we have a few partners there as well. The -- as far as the acreage holding, it should not be a problem there because the -- that particular lease is one lease for the entire position, and it requires us to drill a well. I think it's around 180 days. So really a couple of wells a year maintains that lease by continuous operation. So with continued success there, we certainly should have no issues with continuing to hold the acreage there.

Okay. And then just as my follow-up, Joe, it seems like I often ask you what oil price to get you to accelerate activity. And given where we are currently, what oil price to get Matador to consider slowing activity and where might that lower activity be concentrated if you did decide to go that route?

Well, Richard, as we all know, that's a $64,000 question, so to speak. And once again, I'll just say, it's not a single variable that's going to motivate us one way or the other. We keep an eye on what the oil price is, but we also keep an eye on cost. And we also keep an eye on what kind of well results that we can expect. And we keep an eye on how does it fit into the overall drilling program and delineation efforts. And so you could drill a well that maybe wouldn't be the highest return but sets up everything else in that area and defines where the Wolfcamp or the Bone Spring or some other zone is it will be the most productive. So the -- in general terms, the stronger the oil price, the more likely it would be to add something. But we also keep an eye on the balance sheet. It's simply we're not -- as Matt likes to say, profitable growth at a measured pace, just because you have a temporary surge in oil that you don't think would be sustained, you wouldn't go do it. And the same thing is, say, you want some sustainability there, and you got a personnel, do you have the right personnel? Or do you need to add a few more people to cover that well because you don't want to go down in quality or down in cost or down in efficiencies? So there's a number of variables and -- but I think it's plain. It's the stronger the price, the more likely it is. But there are some other factors that lead the way, and we just don't want to get ahead of ourselves. Matt?

Yes, Richard. I'd just add to that, we really think about these things from a long-term perspective. And it wasn't very long ago that oil was $26, $28 a barrel, and we got a lot of pushback about why we continued to operate in the basin. And we made a lot of headway during those times, and we're really glad we did that. To Joe's point, we were able to upgrade our personnel. We were able to upgrade our equipment. We were able to make a lot of progress. So we don't want to lose sight of that. We don't want to be the ones that pick up 3 rigs and then let 3 rigs go in 3 months. That's never going to be us. We're going to be a little slower to react either way.

Yes. And I think that what Matt is saying, last year works. And one other thing I'd like to add is that we have a lot of optionality on this rig count is that we've been assured we can pick up another rig if we want it later this year. At the same time, that 3 of the rigs are on more than a year of contract, but 2 of the rigs are on short term. So if things would go down precipitously, we could be back to 3 rig if that were the case or we could go up, as you've suggested, to 6. So that's been some of Matt and Billy's tasks was to be sure we had a lot of operating flexibility and options with the rigs. And we're really pleased that Patterson has done a real good job, and we got the chance to -- provide us with a really a state-of-the-art rig that we're interested in acquiring, I mean, or using or we're going to use. And then it will give us a chance to say, how much faster you can drill some of these wells, which may obviate the need for a sixth rig. I mean, you may be able to get the efficiencies down. And if you have more that you have of a Bone Spring program, you might be able to do with 5 rigs what normally required 6 rigs.

Our next question is from Mike Scialla with Stifel.

I want to see if you could talk about any trends you're seeing for price differentials and any thoughts about entering from transportation agreements for either gas or oil. And I guess, also, have you seen any issues with any of your higher gravity crude in the basin or condensate?

Well, first thing I'd like to say is that our Marketing and Midstream group has knocked it out of the park on the differentials. They've really reduced the differentials and performed much, much better than expected. So I want to give you that shout-out, Gregg, before I call out on you to answer the question.

Well, yes, this is Gregg Krug. One thing we have seen as far as the differentials have narrowed, as far as -- when I say -- I'm talking about trucking costs and so forth, those have gone down, which helps on the bottom line. As far as the dips are concerned, as far as the Midland (inaudible) dip, yes, we've seen that spread out a little bit. But then also, we really think that, that is probably more of a baked-in number, more hype than anything, because we're not really seeing any issues at all when it comes to capacity issues. And as far as on the crude side, as far as gas side is concerned, we are -- we're always looking at those opportunities for additional capacity as far as we're looking at if that make sense for us to do that. And right now, we're not seeing any of those issues. We've got plenty of capacity. We've not been curtailed at all. So that's really -- at this point in time, it's not a huge concern of ours, but there, again, we are also always looking at that, and we're going to quickly adjust our thoughts on that as far as if we need to act on acquiring capacity.

Okay, great. And Gregg, on the higher gravity crudes or condensate prices, are you seeing any weakness relative to the lower gravity crudes at this point?

No, not at all. In fact, the market has been very aggressive out there when it comes to -- they're wanting barrels to be able to fill up their pipes. And we're not seeing any deducts at all as far as for gravity deducts. We're getting the same price as our 45 gravity. So that's not -- that's been a real bonus for us.

It's Matt. I'd just kind of want to add one thing to what Gregg has said there and how we think about things. I mean, he's talking about we're always looking to make sure we've got capacity, and when we need to get firm capacity, we're going to secure firm capacity and all that. But I think it really works nice with the midstream team and the E&P team that they're actually talking to one another, working together. And so when we go out and acquire capacity on some of these pipes, what we can do in the midstream business is we can secure enough, certainly for Matador's gas and Matador's oil, and then have some third-party stuff that could be interruptible and just kind of feather that in and as we go along. So it's really a nice blend to have the E&P team and the midstream team under the same roof and talk to one another.

I appreciate that. That's great. And my other question is probably pretty difficult to answer at this point. But if the Culbertson Estate well does happen to work the way you hoped, could you say how that -- of that 31,000 acres or so that you have in the Twin Lakes area, how much of that would become -- how much could you, I guess, derisk with one well? I know you've got another well planned for later in the year that's quite a bit further to the southwest. But I guess, just trying to understand the play a little better.

Mike, I'm going to try to answer your question first, but I invite anybody else here, Ned, to comment. But it would be hard to say how much of that acreage you'd derisk. I think one of the important things is that's becoming a more active area. There are other companies that are starting to drill something there. Cimarex and, I think, Devon and several others had been looking in that area. And so part of our hope would be -- there would be that you'd really accelerate the derisking by -- as other operators get interested. The acreage in the areas is being bid up. It's costing more, so it's becoming certainly an area of greater interest to a number of companies, which will help in the derisking of that acreage. And so I hate to say that based on 2 or 3 data points, that, that's completely defines that area because we all know how much geology can change over a short range. But what we've seen so far has been very encouraging to us, and we think it'll develop kind of like Rustler Breaks did is that first nobody gave anything. We started doing a few things. Others started doing their thing, pretty quickly, everybody began to feel increasingly comfortable. Ned, what would you add to that?

Yes, I'll second what you had to say there, Joe. I think one well definitely won't derisk the acreage, but I do feel that this well should really kind of help, hopefully, confirm the play concept up there. We're going to follow that up with, as you mentioned, a well in the Kemnitz area later this year. And I think it's worth pointing out that when Matador acquired acreage up there, we did it in a very surgical fashion. So I feel like those acreage blocks are very deliberate, and we chose the best places to be up there. So we're looking forward to getting the D. Culbertson online. And then I think the Kemnitz well really should help kind of confirm that side of the play also.

And then, I guess -- sorry to violate my 2-question rule. But is that 31,000-acre position, is that -- are you pretty well set with that now? Or is there any opportunity to add to that at this point?

Yes, there's opportunity to add to that, Mike, and we may do so. We have a pretty full play. We haven't had a lot of extra to put in here or other places, and it kind of depends on the deal's terms as they come up. We like the position that we have there, but we like adding on these bolt-on. The pipeline's been working pretty good for these bolt-on acquisitions and others. And so we kind of stayed with that, but we're balancing the equation. So I don't want to rule out further acquisitions in any of our areas. David?

No, I would agree, Joe. I think there's still lots of opportunities to add to the position. And I think a lot of that is just kind of going to be a function of seeing these well results and -- but if we decide to, we certainly can, Mike.

Our next question is from Adam France with 1492 Capital.

Guys, as you go about these 1,000 acres a month and surgically add in your core areas, where are you thinking you most likely take your laterals out longer? And can the second -- I mean, do you have an opinion yet as to whether these Second Bone Spring well that, I think, were 4,600 feet and can the Bone Springs handle a 7,500-foot lateral? Any thoughts there?

Yes. This is Matt. I think the answer to that is, we do like the concept of longer laterals to a degree. As we've discussed before, I think you get out there around 10,000 feet, 11,000 feet, the world -- the mechanical world really changes. There's a lot of risk that's there. But the amount of wells we drill were 7,300-, 7,500-foot laterals, so we'll continue to do those types of things in New Mexico when and where we can. Down in Texas, in our Loving County assets, we historically have drilled those laterals to fit the geometric shape of the lease, so we've got some longer laterals down there. We've got longer laterals planned for this year. We've drilled some longer laterals in the past. So the answer to your question really is, when and where we can, we like them, Adam, up to a certain point. And I do think the Second Bone Spring will benefit from longer laterals just, I think, almost all those reservoirs would.

Yes, Adam. It's David. I might point out a couple of things. Number one, we have drilled several longer laterals down at Wolf. With -- all our Billy Burt wells were 7,500-foot laterals. And I think, as Matt mentioned, that leads -- lends itself very well to longer laterals going forward. So as we get into more of the heart of that acreage, I think you'll see more longer laterals there. And also just to remind you, the Mallon wells were 7,300-foot laterals. So the Bone Spring will accommodate them very well, so it's just a little more of working through the land issues, as Matt mentioned.

And how long was the lateral on the Twin Lakes well?

It's about 4,500 foot, I think. It's you're standard kind of 1-section lateral. But that's another -- I will say, Adam, thank you for kind of asking that, too, because that is another area which we certainly would have the ability to drill longer laterals on and have looked at that as well. And likewise, over at the -- over Jackson Trust, that's a place where it can lend itself to some longer laterals as well.

Our next question is from Ben Wyatt with Stephens.

I've got kind of a random question. A couple of questions here for you. I don't really think Matador is affected here, but would still love to kind of get your two cents on the question. And my understanding is that when you go up into New Mexico, when you get a permit, you also have to present a gas capture kind of plan with that. I know you guys are well ahead on the midstream side with the Rustler Breaks plant. But just -- and basically, you kind of have 30 days to flare gas up there, if I understand correctly. Does that differ as you move down to Texas? Has there been any rumblings or talk of that changing? Just with all the M&A activity that's happened down there, all the production that's going to come from the southern Delaware. And again, I know you guys are tied into the Loving County plant that you sold to EnLink. But just curious you guys kind of thoughts on that, if there's any kind of update on the flaring issues down in Texas.

Well, Dan, I couldn't comment what was happening on Riggs. We're not drilling in the Riggs County or those areas. That's been part of our planning was to try to put these plants in, so that when the wells are ready to produce, we were there ready with a pipe to bring through our own processing. And that's why it's worked out with most of our drilling out there. We just kind of -- that's one reason why we wanted to build up the midstream as an integral part of integral -- or an integral function of Matador. So we weren't having to deal with that flaring problem that we observed in, say, the Eagle Ford, where there's a lot of flaring. And so we've avoided that to this point. The other thing that has helped is that we've done some pre-fab facilities that had been built offsite and then brought onsite, and that's had a dual advantage. One is it's helped produce flaring and made it ready to go. And then second is there's been some big cost savings. Now we have, in New Mexico, submitted gas capture plans on many of our locations in recent wells. And there hasn't any holdup in them or caused any delays. And again, I give credit to the staff for getting out there ahead of things and getting these plans and requests in and outlaid into the last minute. So we know that, that's a particular hazard out there, but it hasn't tripped us up. And I give credit to the staff for making the run -- train run on time and that -- as to that point.

Got it, got it. Appreciate that. And then kind of my next question has to do with on the disposal side. Obviously, a lot of water coming off these wells in the Delaware. Can you just comment, do you guys dispose of that now in the Arbuckle? And as activity ramps up there, is there any risk that, that could, for lack of a better word, kind of fill up and we have to start disposing stuff in a deeper zone, say, the Ellenberger, something like that? Just, again, kind of curious on how you guys think through that over the next couple of few years.

Yes, Ben. This is Matt. And the answer on Arbuckle is no. I mean, what we have -- the advantage we have in the basin for our saltwater disposal wells is we're a long way from the basin, and Ned can probably talk to this better than I can, but the zones we're exactly into give us a lot of cushion, if you will, both above and below, where we're able to dissipate that energy. And so we're very careful. And Ned and his team, they take a very close look at every one of the saltwater disposal wells that we drill to make sure that we're in a good spot, if you will. And then when we construct the wells, I think it's not the question you ask, but I do want to point out that we drill these saltwater disposal wells there. They're drilled for a very specific purpose, to inject saltwater. So the 2-wheelers are designed for that. The cement is designed for that. And so there's very -- there's always some risk, but there's very low mechanical risk related to those wellbores.

And I might just add to that, Ben, that the -- we do where we can, and we do recycle a lot of water and use a lot of recycled water to just track our wells, both in Wolf and Rustler Breaks. And of course, that helps with the need to dispose as well.

Yes, yes. And I imagine that, that will obviously just become more of something you guys do over time as you build that out. But no, that's really helpful, guys. I appreciate it.

Our next question is from Mike Breard with Hodges Capital.

Of the 5 wells you're drilling in the Eagle Ford, could you give a little background there? Is this partly to provide more data in case a buyer should happen to come around? Or is this an area where you might consider more drilling later on?

Mike, this is Matt. And the 5 Eagle Ford wells that we've selected to drill were selected for a couple of reasons. And probably the most important is that they are very economic wells. These are some of the 5 best wells that we have in the inventory, and that we will drill. So we're really excited about just adding production and getting a very nice rate of return on those wells. The other thing that these 5 wells do is hold acreage for us. Each of these 5 wells were on blocks that we had some expirations coming up. But the main driver for building those wells were economic reasons.

Yes, so virtually, everything now in the Eagle Ford is HBP, and these wells have come out. Our drilling group, for example, took a rig out of Patterson's yard. And together with the drilling development or drilling practices in the Eagle Ford on these horizontal wells, drilled it in record time. First well out of the yard. So we're, first of all, fully intended to make money. These will be some of the better wells that we have drilled in the Eagle Ford. And it also -- HBP gives us the option. And there's starting to be more activity. The Eagle Ford is starting to be revitalized, so we're monitoring some of the rig fracs and some of the new zones down there at the Eagle Ford. And we'll kind of wait as we prepare 2018 to see if we build upon this, and see how these wells perform. But feel very confident that as we announce results, that shareholders will be pleased.

Mike, one of the other things we're excited about, when we suspended drilling operations in the Eagle Ford, we were on Gen 7 of our completion design, and so we've learned a ton in the Delaware. When we moved up to the Delaware, we had learned a ton in there, and it gave us a head start to start completing wells out there. So coming back, we're on Gen 8, I guess, if you will, and so we're basically coming back and putting the similar completions to what we did on our Totum well, which was very successful area in Jackson Trust. So we're getting higher proppant volumes. We're getting closer -- cluster spacing. So we're excited about how this new completion is going to work for us.

Our next question is from Sameer Panjwani with TPH.

I was just looking for some color on the Airstrip well. Didn't really see an update in the press release. So just wanted to see how you guys are thinking about it now that you have some longer-term data. And if possible, what the implications for the EUR could be?

Yes, Sameer, it's David. So the Airstrip well was performing very well. We're pleased that -- it absolutely had declined a little bit, but we were encouraged by its early performance. Unfortunately, we ran into some problems with the ESP on that well. And that's one reason we hadn't talked more about it in this release was that it's currently down, and we're working to actually pull and install a new ESP. And so I just didn't, as a result, have a whole lot more to add. So I'm hoping that we'll get that back up and get that well back online and be able to look at it a little more closely. And so then we can update you on that the next go round.

Yes, Sameer. This is Matt. Just to add to what David is saying there on the ESP. We have a saying around here, we always reserve the right to get smarter. So the production team is working on a new ESP design, and we think it's going to be effective. And at this point, I just wanted to say, the completion guys, they've got a pretty huge task out there to figure out how to best execute the artificial lift on these wells. In the Eagle Ford, we're very successful with gas lift, and that was our chosen method of lift for a very long time. And in the Delaware Basin, you've got a little bit different hurdles. You got the higher fluid volumes. You get over 1,000 barrels a day conventional gas that doesn't necessarily work as well as an ESP well. So the production team has done a great job, including the field guys, of identifying which artificial lift method to put in these wells and then how to optimize them on each individual well. So it does take a little bit to figure out exactly what to do, and the guys are making a lot of progress.

Sameer, I want to commend you for picking out probably the one weak spot in our earnings release here is that this shows you we're not perfect, that we have mechanical risk on our best projects, too. So know for sure that you're always reading the material and staying current.

Our next question is from Jeff Grampp with Northland Capital.

Curious, it seems like we got some kind of back and forth on the well cost side working, obviously service guys trying to claw back some margins, but you guys highlighted a lot of internal kind of efficiencies and newer technologies you guys are integrating. So I guess, just first, I want to clarify whether or not those efficiencies are kind of baked into your well cost assumptions or CapEx guidance. And net-net, how you see both of those kind of playing out and how well costs may be move going forward.

Jeff, I'll take first stab at it. Overall, it's still in that 10% to 15% range. It varies according to the function drilling, completion production, each phase of that. But we've been able to stay within the 10% to 15% overall because you're drilling some a little faster. The production guys had done better on the LOE costs and unit of production. We've had some efficiencies there. So some have gone up. Pressure pumping, of course, is the one that's been -- gone up the most. But still the group has delivered, been able to stay within that 10% to 15% band. And Billy, would you add anything to that?

No, I'd agree, Joe. We're keeping the cost down. It varies across the board there. But the efficiencies have continued to do better. The completion group is keeping the costs down. They're doing a lot of the multiple completions there. And with those things, they're getting faster. When we started out with our zipper and narrow fracs, doing 5 wells or 5 stages a day, then went to 5.5. Now we're well over 6 stages a day, so we're saving a lot of money there. On the drilling side, the guys are working with Schlumberger and the Smith bids and looking at the new AxeBlade design or Stinger design bids. And we just keep setting new records in each section of the hole. And in the last quarter, we had several new records, and we have several more to come just this week that we'll be talking about next time. So we just keep getting better and expect more of the same.

Did that answer your question, Jeff?

No, that's perfect. I appreciate it.

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.

Yes. Before I conclude, David wanted to follow-up on one of the questions.

Yes, I just wanted to make one comment before we closed out, Joe. And that was during the course of the call, the Land Department sent me a note to say that I should not quote acreage numbers because my memory may not always be as good. So the Jackson Trust numbers are more closer -- closer to 4,000 gross than 4,000 net. So I apologize for misspeaking on that. I just wanted to clear all that before the call is over.

Okay. You all have uncovered our flaws. It's mechanical flaws and now our memory flaws. At the same time, I would like to close on this by just noting that this quarter has been very gratifying. We consider it one of the best quarters we had, all things considered. But also that we've delivered some very consistent returns over the last couple of years, and that we haven't had a miss going back quite a ways. I mean, check with Bloomberg. And -- but I think it compares favorably with other companies our size or our peers to deliver what I believe are, at least, 8 straight quarters where we've either met or exceeded guidance. And I'm proud that consistency that goes with Matt's statement about aiming for profitable growth at a measured pace, and want to thank the staff a few minutes.

One story I want to tell is that a few minutes before this began, I asked the people in the room for a show of hands. We have a lot of people sit in on this. And they were here when we went public. When we went public, we had about 30 people. Now we're about 140 and realized how much more capabilities have been added these last few years by the people in this room. So -- and wanted to thank you analysts out there, especially for your many kind remarks this time and for keeping us on our toes. And we felt we had good earnings per share. SEC limits us in what we can say, so we do look at your consensus efforts and say that we beat -- I feel like we beat on both earnings per share and cash flow per share. And -- but have appreciate the efforts that you all make to get it right and to know that how much we value this part of the process. And hope all of you, all, will continue to come see us in person and meet this growing staff and some great young leaders and some great young professionals that have really been helping push on this rock and improve our consistency and improve our results.

So with that, I'd sign off. Matt, unless you have something else to say, anybody else around the table?

No. I think it's -- thank you, guys, for your support, and thank you for your comments and your questions.

Our annual meeting is June 1, the morning of June 1 at the Dallas Westin, and really encourage any of you that are interested to please attend. We have a lot of lazy shareholders that come, and we have a pretty good time. So we'll hope to see you there.

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