Matador Resources Co (MTDR) 2018 Q1 法說會逐字稿

Good morning, ladies and gentlemen, and welcome to the First Quarter 2018 Matador Resources Company Earnings Conference Call. My name is Ayala, and I will be serving as the operator for today. (Operator Instructions) As a reminder, this conference is being recorded for replay purposes, and the replay will be available on the company's website through May 31, 2018, 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, Ayala. Good morning, everyone, and thank you for joining us for Matador's first quarter 2018 earnings conference call. Some of the presenters today will reference certain non-GAAP financial measures regularly used by Matador Resources in measuring the company's financial performance. Reconciliations of such non-GAAP financial measures with the comparable financial measures calculated in accordance with GAAP are contained at the end of the company's earnings press release.

As a reminder, certain statements included in this morning's presentation may be forward-looking and reflect the company's current expectations or forecasts of future events based on the information that is now available. Actual results and future events could differ materially from those anticipated in such statements. Additional information concerning factors that could cause actual results to differ materially is contained in the company's earnings release and its most recent 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 2018 press release on our website on the Presentation & Webcasts page under the Investors tab.

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

Thank you, Mac, and good morning to everyone on the line and thank you for participating in today's call. We appreciate your time and interest in Matador very much.

Now I would like to introduce the senior members of the 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; Billy Goodwin, Executive Vice President and the Head of Operations; Van Singleton, Executive Vice President of Land; Brad Robinson, Senior Vice President, Reservoir Engineering and Chief Technology Officer; Gregg Krug, Senior Vice President, Marketing and Midstream; Rob Macalik, Senior Vice President and Chief Accounting Officer; Matt Spicer, Vice President and General Manager of Midstream; 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; Tom Elsener, Vice President, Engineering and Asset Manager; Jim Basich, Vice President and Managing Director. So with that group, I hope we can answer any questions that you may have.

We believe we're off to a great start in 2018, and I'm proud to announce the first quarter was another strong quarter marked by both excellent financial and operational execution. I want to take a moment and personally acknowledge the Matador staff for all their achievements this past year and quarter. It was truly a team effort, with each department and each group contributing to this success.

In terms of awarding the game ball, it's a hard choice because everybody did so well. But I'd like to particularly call out the guys in the field who worked through the weather problems and delivered better-than-expected production and have really been committed to that work, and it's not as noted sometimes because they're in the field, but they've done great. And to our midstream group, who brought on their new plant on time, on budget and also came up with some important deals that have started to build momentum in the value in our midstream growth.

Now having said all those things, we also are very interested in your feedback. We heard from you that while we were trying to be thorough and transparent and comprehensive, that perhaps our earnings releases were tending to get longer and longer and maybe not quite as easy to find the information. So we've tried to come up with a new, condensed version and welcome your feedback, whether you like this best, the one we have that's half the size of the other one or the full, comprehensive set that David does such a good job pulling together.

The second point I wanted to make is that this is the 15th straight quarter that we've met or exceeded guidance -- again, a total team effort as each group has contributed to that.

Second is we believe and feel that we have a new key operating area in Antelope Ridge.

And the third point that I would like to make is just in all of our operating areas around the basin, from Wolf to Rustler Breaks to Ranger to Arrowhead to Antelope Ridge and to Twin Lakes, we've had some great encouragement on our operations in all that area. And Van and his land group have delivered the brick-by-brick adds to our acreage and that within the basin, we're about 60% HBP.

And with that, I'd like to ask Matt Hairford, our President, to address the most often-asked question we've received this quarter at various conferences and non-deal road shows, which is the takeaway and the differentials. Matt, will you give us a note on that?

Sure, Joe. Thank you. Joe's right. It's been a topic of discussion at most of the meetings, that takeaway capacity, and we here at Matador are focused on takeaway capacity for our gas, our oil and our NGLs as well as making sure that we have an ability to cost effectively dispose of our salt water.

So on the gas front, we've got firm transport, FT, for all the gas that we produce at Wolf, all the gas we produce at Rustler Breaks, and all the -- well, not all -- but the majority of the gas for the designed plant capacity at Rustler Breaks there. So the FT we have is from the field to Waha/Mendoza Trail, so that gets us to Waha.

That being said, to get from Waha to, say, the Texas Gulf Coast, we're currently evaluating and conversing with a lot of midstream companies about that next step, how we do that. And one of the things, we're going to be very methodical as we do this and make sure that whatever deal we do today, we're going to be happy with it today; we're also going to be happy with it tomorrow. So that kind of takes care of the gas for us.

On oil, our takeaway capacity has been greatly improved with this transaction we did with Plains. So right now the oil that we produce at Wolf is going to Plains, with the vast majority of it on the pipeline systems and the crude system that they have in Loving County. They are going to extend that system up into our Rustler Breaks area, so all the oil that we gather and produce at Rustler Breaks will be going into that system, probably sometime this summer. So we feel pretty good about that.

The deal with have with Plains is not your traditional FT, but what happens is Plains actually buys those barrels at the well head or at the CDP, charges us a transportation fee to get it to Midland. When it gets to Midland, we have at our discretion the option to buy those barrels back. So if we can access other markets -- say, St. James, Cushing, Texas Gulf Coast -- we can buy those barrels back and deliver them to those markets. If not, Plains will keep those barrels and deliver them on their system. So that takes care of the oil for us.

The NGLs is an interesting thing for us. We just recently finished an interconnect at the tailgate at the Black River Plant there at Rustler Breaks for NGLs. So it's a Y-grade NGL line. BP is actually buying the NGLs for the total plant volumes, Matador and other producers in the area. They're buying the gallons or barrels, putting them on this Y-grade line and then taking them to market there. So feel pretty good about that.

There are some real advantages with this NGL interconnect, one of them being the elimination of the need for trucks. So even when we were running the 60-million-a-day plant, we had 20 to 25 trucks per day going into that plant and hauling off the NGLs. So we get rid of those trucks, and then as we continue to increase the volume, if you go from 60 million to all the way up to the plant capacity, 200 million to 260 million cubic feet per day, you can see the logistics around having all those trucks in that plant, it's just not very good. So glad to have all those NGLs on pipe. The transportation cost is obviously a lot cheaper on pipe than it would be for trucks, too, so that's a big advantage.

And then the third thing really is the ability to go into full ethane recovery mode in this plant, so big advantages there. At some point in time ethane will likely become in the money as a liquid as opposed to selling it back into the gas stream on a BTU basis. So we have the ability to do that. The other advantage that gives us is it does reduce the residue gas volumes at the tailgate of the plant by 5% or 10%, so that frees up some additional capacity there.

And then the fourth thing -- it's not really a takeaway issue, but it's more the ability to be able to cost effectively dispose of our water. So these wells in the basin, they make a lot of oil, they make a lot of gas, they also make a lot of water. So if you've got a well that's making 2, maybe 3 or 4 times the amount of water than oil, you certainly need to have an outlet for disposal of that water. So we've got things covered. We've got 160,000-barrels-a-day capacity now at Wolf and Rustler Breaks. We're going to 220,000 barrels a day by the end of the year. So I think all in all, we feel pretty good about the proactive steps that we've taken to make sure we can cost effectively flow our wells.

All right, thank you, Matt, and thank you for your hard work in those various projects, those multi-location projects.

So now we'll open the line for questions.

If I can maybe start on the midstream side just because, Matt, you just finished up with that. It obviously sounds like you guys are in really good shape there. But where do you believe third-party volumes need to go from Matador to maximize value for its midstream assets? Or should we kind of view this as an asset that is first a safety net for Matador and its volumes, and then really, kind of any third-party volumes that move through the system are just gravy? Just curious for your thoughts there.

Ben, thanks for the question. What we'd like to really emphasize is that we're playing a straight game with this midstream, is that we have a partner in here, Five Point, who owns 49%. While we're at 51%, it's very important that people know that we're going to give them -- we're going to play a straight game. There's independence between the 2 companies where we collaborate. But the midstream's been charged with delivering the same services, just as good of services to third parties as they deliver to us so that a third party deciding to go with us is going to get that same high end and be just as service oriented. That's their task and that's their challenge. That's what Five Point, the deal was based on, that this wasn't going to be a brother-in-law type deal, that this was going to be good service for everybody in all ways. And we think that we can tailor it to make it better because we're in the business and that we think that we can, because of our size, that we can tailor the agreements to fit the particular needs of the people and provide the 3 pipe services that are becoming, I think, the high end of the business in terms of service to the independents of providing gas takeaway, oil gathering on top and then saltwater disposal. And so it is not a -- we're not going into it as a -- so that other parties are going to be a stepchild or anything. Yes, if they'll give us a chance, I think they'll see it's going to be the same high-quality services we are expecting our midstream group to render to us. Did that answer your question?

Yes, no, that's helpful, Joe. I appreciate the explanation there. And I guess as a -- just my second one here -- just around the potential that a 7th rig -- you guys kind of alluded to that maybe by year end. Does the current environment around takeaway concerns in the Delaware delay that 7th rig potentially until late '18, or is this just, should I just think of this as just Matador kind of staying consistent with its approach to kind of to move at that measured pace as you guys have always talked about?

Well, Ben, that's another good question. And it is not a single factor. We're weighing both of those concerns that you've said, and that's going to be the final decision is going to be based on a number of circumstances. One is commodity prices; two, just as you said, what's happening on the gas takeaway from the basin. A third one is yes, we have a bias towards doing things in a methodical manner, profitable growth at a measured pace, as we say. But another factor that we would weigh is that -- that we weigh so heavily -- is opportunities. And when you speak of opportunities, not only in our new development in Antelope Ridge and the march northward up into the northern part of the basin, where we're being really encouraged and have plans, if this price differential, we don't think it's going to stay at this high oil differential. But you have about a $13.00 advantage in the Eagle Ford on your oil price. If that should remain, we might dip down there and put a seventh rig to work, drilling 4 or 5 more wells in the Eagle Ford to take advantage of a $13.00 advantage. I'm not saying that's our first choice today by any means, but $13.00 is a significant difference and it does make you consider where is the best place to put it, weighing all the different circumstances. So again, I don't want to alarm anybody that we're dump money in there, but where returns would be comfortable and you can take -- if you're going to have a problem of differential, turn some of it into an opportunity. So no one should read that, that we have plans to do that other than that we take the full range of circumstances and try to be opportunistic in what we do. The last thing that I'd like to underscore, and this is something that both Matt and David talk a lot about, is that we have the option, we have 3 of the rigs on very short-term contracts. So we could drop one of those rigs and pick up one of these newer rigs that have the most technologically advanced, state-of-the-art equipment, the pumps and the top drive. And we have one of those now that's working very well for us and give a lot of credit to Patterson and would look at picking up another such rig and keeping it at 6, but that's another circumstance. How much help could that be is still stay in 6 rigs. So we'll look at price. Obviously, if price drops, then it's less likely. But it's just too early in the year to know exactly what is the best lineup of rigs and drilling opportunities, because we want to be nimble and be prepared to make some changes in the various rig lines, depending on these circumstances. I know that's a long-winded answer but it's complex, and we give it a lot of thought.

No, I think that, Joe, very helpful and appreciate the answers here. And for what it's worth, the team here at Stephens appreciates you guys saving us a little paper.

Ben, this is Matt. I might just add to what Joe said. He's exactly right on maintaining the optionality we have with the rigs we have. We can, if we go to 7, we can quickly go back to 6 or 5 or even 4. And I think on the other side, it's a continued methodical approach. I like the fact that you used those words because that's exactly the way we think about things. But we do have our frac crews set up where we could, if we add a 7th rig, we have a 2nd crew that would be available for us to -- on a dedicated basis. And also with the frac crews, if we wanted to go back to 1, we could do that, too. So lots of optionality in the program.

Our next question is from Neal Dingmann with SunTrust.

Joe, my first question is for Matt or somebody on the team: that Leo Thorsness well, certainly very notable. I think as you mentioned, maybe even a record IP for you all. Was there something different or special that you all did on the completion side, or is it more just sort of advancement as you continue to have more knowledge on the play?

Yes, Neal, you're right. That is a very nice well. We're very happy with the results there. And I think it's just a continuation of, like Joe says, us drilling better wells for less money. The notion that it was any one thing that made that well particularly better than a lot of other wells, I think, is probably it's more of us picking the right target, us continuing to stay in that target, and then the effective completion. That's going to continue to evolve, so I think it's just a number of those things all put together. And the good rock part of it is a big portion of it, too.

Neal, one thing I'd add. I agree with everything, what Matt said. One thing to add is one innovation that we have, we put into effect this quarter or at the very end of last year, was what we call a MAXCOM program, where it's a 24 room where we have some of our young engineers and geologists working together 24/7. And it's working out to stay in zone better, to drill faster wells. And it's really doing a wonderful job. And so on some of these wells, if you just stay in zone so you get more exposure to the right rock, you can be really helped. And they're drilling them faster, which means less money. And this has been a good area for a number of people. What pleases us is we drill 3 wells in this area, 3 different zones, and very pleasing results in each zone. So you've got a lot to work with going forward. One digression is we've been fortunate to have a number of Medal of Honor recipients as shareholders, and one of them was this Leo Thorsness. And interestingly and coincidentally, he died and his service recently, and his service was at Arlington Cemetery on February 14, about the day we brought in this well. So Leo was a POW for 6 years in North Vietnam, and it's really nice that we could honor him and his family and tell them, “Here's your sign for your well, and it's the best well we've drilled from that zone” and have that kind of positive message for them and positive message for our shareholders and you.

That is nice to hear, Joe, and then just one maybe follow-up, just on the M&A. You guys continue to just do a fantastic job on leasing, not only now adding more leases, but now even adding some minerals this last go-around. Just any comment of how you all feel. Is the market still, is it still pretty open to continue on the pace you all have been? From either you or anybody from the land team, we'd love to hear your thoughts there.

Neal, that's a hard question. We can clearly see the market has not shut down. There are still plenty of opportunities out there, but you never know when that door's going to shut down or just burst open. We're nibbling away, that brick-by-brick concept, and we don't see the market closing. The land group, Van and his land group, are still encouraged by what they see. It's just really hard to predict, kind of like hemi, trying to get a date to prom. You don't know whether there's a lot available or none available. But you're just going to be out there pitching until -- as best you can. So I don't think we have enough data points for this year. I'd say let's look for this summer, mid to late summer, and we should have a better idea how we're going. But we're encouraged by what's in the pipeline, but sure not ready to say victory yet.

Our next question is from Gordon Douthat with Wells Fargo.

Just had a question on the Garrett pad and just wanted to get kind of some more details on your observations on that stack development, if that looks like it's -- how that's producing relative to a one-off or 1- or 2-well pad and if that's kind of in -- if more of those types of stack pad developments are in the future as you continue on.

Yes, hi, Gordon, it's David. Well, so first of all, I think we were very pleased with the results from those 3 wells, and we had a high degree of confidence, I think, going into the drilling of that 3-well pad, that we had 3 intervals there in both the Wolfcamp XY, the A-Lower and then the B-Blair, that were all going to be very successful intervals for us based on our other drilling at Rustler Breaks. And it just made sense to knock them all out at the same time. So it just helps you on the rig move and saves costs when you're able to batch drill and save costs when you're able to come back and frac them sort of at the same time. And so not only did we feel like we were going to get good results on the production side, but we knew that doing that was going to also contribute to us saving some money on those wells. And so I think that as we've said this year, that most of our drilling is going to be done in 2s and 3s, and I think that as we go forward, you'll see us begin to drill wells in more -- we've always been doing it in this batch mode, but I think we'll continue to move toward more of these 3- and 3-plus kind of pads. We certainly have areas in Rustler Breaks already where we've drilled up to 5 different zones, I believe, essentially off the same pad, and sometimes 5 in one direction and 5 in the other direction. We just hadn't done them all at the same time. But I think this was a nice data point and we were pleased with the outcome.

Okay. And have you noticed any, from a productivity side of it, have you noticed any benefits from doing it all at once?

I would say that the well productivity has certainly been very good from all the zones, so that's been positive. I would say, just on overall, maybe, capital efficiency, I think that that's also been positive. As I mentioned, I think Billy and the operations guys always like it when we're letting them drill multiple wells off the same pad or are scheduling them that way because he's frequently in my office, telling me the more we do of that, the more money he can save. So we're always paying attention to that. And then in addition, I believe we also receive a discount from our service provider on the fracturing side when we're doing these wells on kind of what we call a simultaneous operations type basis, where we have both the fracking and the wireline going on at the same time. And as a result, we can get more stages done in a day. And so all in all, I think that it definitely helps from a capital efficiency standpoint.

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

So Joe, you were in a pretty good discussion about where that 7th rig -- on that 7th rig. And I have a question. In the Antelope Ridge area, obviously, you've got a rig that's dedicated to that area. Can you generally give us a sense of now that you're going to be more into the development mode or starting to move into that at this point, is there capacity to add a second rig there? Or how do you contemplate the midstream needs there and how you approach that?

Scott, our plan on that is just what we try to do every day, is be very methodical. We're going to start out one rig. We're not going to, just because we have 3 good wells, suddenly double to put 2 or 3 rigs there. We have so many good opportunities around the basin, we're going to continue to go in methodical fashion and develop this with 1 rig. And at some point we hope it justifies a second rig. But we've got a number of good areas that are very promising and that we're going to test more of those as we move north in the basin to other good rock.

I think Ned, Head of Geoscience, sees connections from the Antelope Ridge area going north that he's advocating. And I'm going to let him speak in a moment on that, on what the encouragement that he sees moving north. But I also wanted to say if we go to a 7th rig -- and amidst all the volatility, it may not happen -- we're looking at it towards the end of the year, which will have little impact on our overall CapEx spending because if it's put in service, it will be towards the end of the year, and it's really a 2019 event. And we are hedged so that we are protected through 2018 from any drastic downside moves in price. And the reason we are trying to emphasize maybe options more this year, optionality on where to put the rig, what kind of rig, all these questions, is because of volatility in price. But we keep an eye on this is that I think it's notable, Scott, that Matador had $0.36 of earnings per share. And compare that to other companies, that I think that's one of the better ones, and that's an effort to try to put everybody on a level playing field, is going to the earnings per share. And I'm proud of that. I'm proud that our EBITDA was at a record level. This is the best quarter we ever had in terms of EBITDA. Not just production, but EBITDA and reserves. Our reserves are growing the way we want. So it's a good plan. We want to tinker with it, find ways to improve it, but also the pace that -- as I said, Matt and David like to stress with me -- is working, is that we don't get in a hurry, we're in a fair deal, we're validating the acreage, and there are opportunities moving north. And you never know; if we committed a second rig here with the exploration work we're doing in the northern Delaware, we may have to come back and say, “Hey, we spoke too soon. We really need it up here. This is an even better area.” So everything's on the table. We're trying to remain nimble. We're trying to keep up the optionality. And as you know how we make the joke around here, we reserve the right to get smarter, that if things need adjustment, we're going to be quick to make them. That's got to be one of our advantages. Ned?

Yes, I think that's absolutely right, Joe, about Antelope Ridge and the northern part of Lea County, is you remember we really drilled some of our first wells up in the Range area, which is northern Lea County. And it feels very familiar to step into Antelope Ridge because a lot of that high-quality Upper Wolfcamp and Bone Spring that people are drilling in Antelope Ridge really extends up in the Range there. So I think we're excited to push the boundaries in that play, and the first 3 wells we drilled here, I think, were all very high-quality results. And they showed the potential of that area, but as the exploration is that I think you begin to see what works, and Antelope Ridge really extends quite a bit further north. So we're excited to continue to keep pushing that boundary further and further north than done.

Scott, this is Matt. In regards to your midstream portion of that question, it's going to continue to be what it's always been for us. It's going to be opportunity based, so if we get into an area, say, Antelope Ridge, and it looks like we need to drill a commercial saltwater disposal well, that Matador will be the anchor tenant on it and that we could service other producers in the area. That would be something we would look at. It's probably the most likely. Gas processing, oil gathering and things like that will come, too, but it's always going to be opportunity based.

On that midstream, when do you need to make those decisions? I mean when do you think you have enough scale in operator funds where you have to make the decision, both saltwater disposal and processing and all the other things?

I think it kind of falls into like what we've done in the past, where we get to where Matador can be an anchor tenant at, say, 50% capacity or something like that, Scott. So it's easier, as I said, through the saltwater disposal. If you drill several wells, it kind of justifies drilling one of those. We actually have a saltwater disposal well in the area that we're utilizing. It's not commercial; it's just for Matador's use. But as we continue to increase activity, both at Antelope Ridge and in other areas, we'll just look at that on a case-by-case basis.

Okay, that makes sense. And as my follow-up question, working interest was a little higher this quarter. It looks like you guys have done a pretty good job of blocking and tackling and adding onto wells you all are drilling. Assumedly, that gives you some of your best rate of returns on an acquisition or a swap investment. What should we expect throughout the rest of the year? You're running a little bit high; I see the budget on the working interest. How does this bias the production and CapEx expectations through the rest of the year?

Hey, Scott, it's David. I think that it's probably a little early to know that. So we are taking a look at that. But I think that it's a little early to know. And as far as the ability of the group to make the trades, I really want to compliment the land group for all their great efforts all the time, but in particular this past quarter, in making some very high-value trades and doing some good things. And sometimes, I think as everyone knows, we've talked about it a lot. There are areas where we don't always have 100% in the wells that we're drilling and maybe we'll have 50% or 60%, and our objective is always to try to maximize our working interest in those wells. And so we do the best that we can to sort of forecast that in advance. But sometimes the guys come through with just an offer you can't refuse, and I think there were several of those in this past quarter. I'm really delighted that we had the opportunity to take advantage of them. I don't know of any specific other ones that are out there pending, but what I'm confident of is that some of them will happen. And as I say, we try to anticipate that to the best of our ability, but if we have undershot a little bit and are picking up some extra interest in some wells that are really high value, that won't bother me.

Our next question is from Gabe Daoud with JPMorgan.

Could we maybe just talk a little bit about just the CapEx overage on the Antelope Ridge wells? I think it was maybe $10 million. You mentioned something along the lines of a little bit of a slow start. And maybe just a little bit more color there, and then just overall what you're seeing on the ground from a logistical standpoint in the basin?

Yes, Gabe, this is Matt, and part of the costs that you're referring to was at Antelope Ridge. And just about every area where we've gone into, we've improved once we got started. So a little bit of it is just going to a new area and learning a new area. And the drilling guys are going to drill these wells faster and faster and faster, and the completion guys are going to improve that, too. So a lot of that's just startup costs there. There is a fair amount of that in there that's related to extended flowback. And so we make a conscious decision from time to time to flow these wells a little longer into flowback. And in fact, in the case of the Leo Thorsness, we actually had additional flowback equipment out there due to how good that well really was. So there's a number of different buckets that those all fall into, but the costs there at Antelope Ridge, I think, are something that we certainly will improve on as we go through time.

Got it, Matt. And then just the logistical -- any issues at all from a logistical and services standpoint in the quarter? And then any update on in-basin sand testing? And that will be all for me.

Yes, Gabe, we've been out talking, and on the big-ticket items for not only availability but also for price, we really haven't seen anything move in an upward direction. That being said, some of the smaller services, we are finally starting to see some upward movement in those costs. And I think it's related to the -- we talk a lot about pressure pumping services, so when we think about that, there has been additional capacity come into the area, so there is a good amount of availability of that equipment, and it's still at a very competitive price. So not seeing a whole lot of movement there.

But on the demand side -- your roustabouts, your welders, your smaller -- there's a shortage of them. They haven't come into the basin proportionately like the pumping services or the sand. And on the sand side there, we're slow to move too fast on the brown sand because there are some problems with it. One is the size and the second is the brown is from some of the iron content that it has. And there have been problems in the past, and we're going to first test the size with northern white sand to make sure that the smaller size doesn't have an effect with the white sand. And again, a methodical approach to seeing if you can use the regional sand.

This is David. I think you summarized that well, Joe. So it's certainly something we're looking at, as we've said, and the guys have got plans to test things, as we've said. But we'll probably go at a fairly methodical pace in terms of moving to the in-basin sand.

And Gabe, you bring up a good question on the cost because we look at that, too. We're always looking for ways to improve the cost without compromising the quality of the well, and I'm going to give Billy a chance to defend his drilling and completion guys, that they were getting their money's worth throughout the quarter, even though as we do exploration work, they're going to be a little bit higher. And as we get to do the repetitive, they'll come down and as we adjust for the equipment as well and get the first infrastructure in.

That's right, Joe. And as David mentioned earlier, as we move into development mode, we'll be able to batch drill and zipper frac the wells. We're already looking at the Wolfcamp wells in some of the areas there where we think we can eliminate a string of casing. That's going to help us out. We're going to get facilities into place there. And everywhere we've been going developing wells, you know the MAXCOM room that Joe mentioned earlier is really helping us out. We've got like just a whole page of new records. We've drilled just faster in each whole section. We've got our curves now. We're drilling them 7 to 10 hours, so it's over 100 foot an hour all the way through. So things are happening a lot quicker there, and we're going to see these things happen at Antelope Ridge as well. So good quarter and good things ahead.

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

Because of my short attention span, I also welcome a shorter earnings release, so you can make it shorter if you'd like.

Well, great. We'll keep trying to head in that direction, Dan. And we do welcome all of you all's comments. We want to make your time as useful as we can and productive, so keep them coming.

Well, I appreciate it. First question: if the basis differential issue in the Permian proves to be more transitory than not, then would it make sense to put a rig to work in the Eagle Ford rather than maybe monetizing what looks to be a prized asset and maybe where those proceeds could finance the running of a 7th rig in the Delaware, where the inventory is much deeper?

Dan, that's a great question, and that's something that we evaluate all the time. We take pro and con on those issues all the time, and I think you make a good point and you identify a couple of issues. Is this basin's differential, is it transitory or is it going to be intact for a while? What are the opportunities?

We've got almost all the Eagle Ford HBP, so we don't have to do something. But holding on -- when I say hold onto it, anybody that brings us an offer that hits the magic number, we're going to make a deal. We run a straight game. It's just that -- but if we had sold it 2 years ago, we wouldn't get nearly what we'd get for it today, and we would have missed out on some valuable production. So it gives us an option. And just think about these companies that sell acreage for one number, and they come back 2 years later and pay 5 times that number for the same acreage. You need to think about this. And there have been other companies, major companies, that sold out of the basin, and now they've reentered the basin and they're paying much more for their acreage today than then. So it needs to be a deliberate, long-term look. But Matador has sold itself to Tom Brown. We sold part of our Haynesville to Chesapeake. We did a deal with EnLink; we've done a deal with Five Point. So when the numbers are right, we'll pull the trigger, and make no mistake about that. But it is nice to have some options on where to go. For example, in the Haynesville, we normally have Haynesville, but we have 200 BCF or 300 BCF of Cotton Valley that's HBP that's sitting there as a gas bank and is not counted in the acreage. So you make a very good point, and we have people that, as I said, we invite them to come in and if they're interested in the Eagle Ford, we'll make a deal there. We reserve the right, if it were a more lasting differential, to go there, but that's not our first choice. It's to continue -- the first plan of action, absent more complicating factors, is to continue methodically, moving north to take advantage of our experience and our acreage position in the northern Delaware, which is proving to be one issue that came out of Analyst Day was some people said, “Hey, wait. We're not going to give a lot of value yet to the northern Delaware because you're not spending money or taking activity.” Well, look, we had it going all along. The Antelope Ridge wells were in process at the time or thinking about it. We had good success with Cimarex and another improvement to the Twin Lakes. We're excited about the well we're going to drill. It's working, but each data point helps make our evaluation of what to do or where to put the rigs, we can be that much more confident. And we have plans over in Arrowhead and Ranger. A rig is over there in Arrowhead right now. And we think that team has got some really good ideas. And so we're fully engaged and working the data as it comes in. And the more and more data, I think, makes our plans clearer. And I think it's just nice to have a plate full of opportunities. And being able to high-grade them, that's kind of a high-class problem. And if you remember in Matador when we first came public, there was a lot of pushback. We didn't have enough acreage locations. And now you're looking at something that is in the order of about 2,000 net locations, and that number will grow. So it's exciting there, and in the Eagle Ford, the Haynesville, all of that is quality rock. So it kind of gives us a whole handful of cards to play.

Yes, understood, Joe, and that's a good segue into my second question, my follow-up question. Moving further north in the Delaware, what did you conclude from Cimarex's Wolfcamp D well that supports putting more capital to work in the Twin Lakes area? And what is the timing of results from your own Wolfcamp D test?

Yes, hi, Dan, it's David. Well, look, I think we were very encouraged by the results of the latest Cimarex well, which we were a minority partner in. They did test a slightly different interval of the Wolfcamp D than what either we or they had tested previously, and in doing so, had a little bit better results than what either of us did the first time. I think that's positive, so I think we learned some things about targeting. I believe that the stimulation of that well went a little smoother than what either of us experienced on our first wells in the Twin Lakes area, and so there were some tweaks made to the design and I believe also to kind of the strength of the pipe that was used in the completions. And so as a result, I think that was a good learning and something that we'll be able to piggyback on going forward. We'll probably actually test a slightly different target, even to what they chose. We're going to be a little bit to the east of where they were even though we're on the western portion of our acreage, what we call the Kemnitz area. But we have just actually begun drilling that Twin Lakes well, and so I would imagine that it will be at least the next call before we would have anything that we'd be able to talk about on the well. It will take us a while to get it drilled and fracked. But we're still very encouraged by this area. And I know that Continental, too, has come into the area and is looking to drill a couple of wells. And so it's nice to have some neighbors up there kind of working together. And it's even my understanding that on the Midland side, that Pioneer maybe, among others, have begun to maybe crack the Wolfcamp B net also. So all in all, I think that we've known this was going to be an exploratory area for us and one that was going to take a little while to get right. But I don't really see it as being all that much different than some of the other areas that we worked in. Our initial wells in some of the other areas weren't our best, but as we got up the learning curve we continued to improve and now are very happy with the results we're able to deliver in those areas. So I hope that answers your questions. Those are some of the learnings that I think we were able to take away from our participation in that latest well.

Our next question is from Irene Haas with Imperial Capital.

I have 2 questions. Firstly, Matador certainly is opportunity rich. So in light of that and stronger prices, wondering when Matador might be able to kind of update full year guidance. As of now, is the 2018 guidance still intact and specifically on the CapEx end? Secondarily, is the Wolfcamp D well at Twin Lakes, what is the AFE and how much drilling time and completion time you've allotted for that particular project? That's all.

All right, I'll take the first part of that, Irene, and just say that, look, it's early in the year. We feel it's very early in the year and we just don't have enough data, don't know enough about the direction of process to make those calls. And as we're still evaluating every day the 6th and 7th rig, exactly where -- what direction we're going. So it's just early and it will come. Give us some time into the summer and we can probably help you there. As to the AFE on this next well in Twin Lakes, let me give that over to either Matt or David.

Yes, Irene, this is Matt, and the next well we're going to drill at Twin Lakes is going to be a lot like the first one we did. We're going to spend a fair amount of time and money on gathering some very important data for us. We do truly value the whole core and sidewalls and things like that that we can get from these wells. So I would think about it more in terms of, on a development basis, these wells are going to be comparable to what we're doing just to the south there at Ranger and Arrowhead. So if you're looking for a development-type cost, that's kind of what I'd look to.

And how much time have you set aside to drill and complete this very interesting exploration project?

About 40 days, I think, Irene.

Our next question is from Jeff Grampp with Northland Capital.

I have kind of a broader question on your Delaware asset base. When you guys kind of take a step back and kind of think about profitable growth at a measured pace in the long term, what's kind of an efficient max rig kind of case for you guys that efficiently develops your assets? And if we just kind of think about Twin Lakes in a different bucket and just kind of thinking about more of your more proven areas, what do you guys think is a good max rig number for you guys to build towards?

Yes, this is…

Yes, I'll prime and you revise. We're not of one mind on that, frankly. And so much of it, it's just hard to pin that on a single variable is because so much of your decision is based on price and you don't know for sure. You can look at the futures market and that gives you an objective gauge, but you just don't know the pace. That's like coming up with a game plan in football and say, “This is the order of the plays we're going to run.” Well, it turns out the weather is rainy -- that would change your game plan; or it's windy -- it would change your game plan; what the other team is, the way they're lining up will change your game plan. And what's your having success? You may have a running back or a quarterback having a good day, and you're going to call more of his plays. So there are just too many factors. You'll have a plan, and we make plans, but they're meant to be changed to go along as circumstances change. And you can have new technology. One example of that is the bit designs, is when we first got to the Permian, it was difficult getting to chert, and you would spend 4 or 5 days. And the bit companies have come up with significant improvements there that you can get through them in a matter of hours. So that made a significant change in the way we did things or how many rigs, because you shortened and compressed those drilling times. And I'm not trying to disrespect your question at all. It's a very good one that we talk about all the time. But we're not going to get committed to where that we can't make a change for 6 or 9 months. We think it's important to maintain as much flexibility as we can, and that's what we look at all the time and evaluate. We make plans, but we also try to do them in ways that Option A, Option B, Option C, depending on well results, gas prices, oil prices -- that makes a big difference -- and service cost and personnel. So yours is a great question, and we do that job internally. But when you're a public company, you've got be careful. If we were different, we could -- private, we could throw out a lot of plans to our shareholders and see what they think. But as a public company, once we say this is what we're going to do, you're expected to pretty much stay with that. So we have a lot of plans going on, but we'll kind of stick with what we said at Analyst Day for now and watch the temperature and circumstances and go from there.

I think it's said well, Joe. I think the one thing that we won't do, Jeff, and you've known us a long time, we're not going to have a knee-jerk reaction and we're not going to move from 0 to 90. We're pretty methodical in the way we approach things. And Joe's right. There are a lot of different variables, and we take this stuff very seriously, and as the acreage grows, the efficiency of the rig grows. So there's a lot of different things that are happening all at the same time.

Jeff, I'd like to think that we're building some sort of record for consistency. This is the 15th quarter where we've met or exceeded guidance. So when we issue guidance, there's a lot of thought and effort and discussion behind that, and we feel like that's what we will achieve and deliver to the shareholders, and they can count on it. And we're not going to react to the fashion of the day, but stay with what, as I said, Matt says, that profitable growth at a measured pace. And we're growing organically. I think it's important to note, too, is we're not out there buying companies that may have a transformative effect. We're going along, buying the acreage, drilling the wells, building the midstream and making it work. And you look at where we were when we went public, 400 barrels of oil a day, and today we're over 30,000. So the plan is working. Acreage, if you remember when we went public, we got a lot of pushback for not buying more acreage in the Eagle Ford, and that's where we should be spending the money and we got this pushback, “Why are you going out to the Delaware and buying acreage?” Well, if we'd just stayed in the Eagle Ford, I don't think we'd be around today. But I think it was the right decision to go out there and start buying in the Permian. And people said, “Oh, you'll never get past 30,000.” And we have -- and look where we are today. So I would like -- we try to be as transparent as we can and put it out there. But once public, once we say it, then we've got to stand behind it and do what we say. So we're working on those questions now, and I think as you'll see it as we, hopefully, you will rely upon what we say we'll do and take some comfort that we'll get that done and everything else will come along and take care of itself in its own time.

All right. No, I understand, then, and appreciate it's not a straightforward answer, but appreciate the time and the thoughts, guys.

Jeff, I tried to make it straightforward. Let's try to stay ahead. Maybe the listener didn't get to hear what he wanted to hear because we couldn't tell you that. But we're working on it, trust me.

Our next question is from Philip Stuart with Howard Weil.

Congrats on a good quarter. Circling back to the Garrett pad at Rustler Breaks, David, I know you talked about improved capital efficiency by completing those wells on a multi-well pad. But I'm just curious if you could actually quantify the savings per well that were achieved on those wells versus what the AFEs would have been for those wells on single-well pads.

Do you want to take that?

Yes, Phil, this is Matt. I think there are multiple efficiencies that we achieved. When we're drilling these wells on a singular pad, you save on drilling pad costs, you save moving the rig costs. There's lot of different cost savings. But I might just ask Billy to quantify this. But I think we're thinking in the $400,000-per-well range on average when we're drilling these multiple well pads.

Right. And when we put 3 of them together like that, we can save even more than that. We can get -- it's more of a wider range then, where it's $400,000 to $600,000 or $800,000 a well that we'll see. So it's big numbers when we can go in and drill them all together and get to do the zipper fracs and all the flowback and all the services together. So it really helps out; it's a lot more efficient.

One thing that is easy to point to, Philip, is on the pressure pumping when we pump our fracs. The agreement we have with Halliburton is that they will actually give us a specified discount of $150,000 per well if we are fracking multiple wells at the same time. So that's a hard and fast number there.

All right, I appreciate that; that makes sense. And then one more, sticking in Rustler Breaks. Any update on the Breaks sand? I know you all participated in a couple of wells and I think you're planning to participate in another one this year. Any update as to when that test would be or any other data points you can give on that formation?

Yes, I don't think we have a lot, really, to update you on there, Philip, other than what we talked about at Analyst Day. I think the wells that we participated in are doing okay, and we're still looking at the possibility of doing our own tests. But probably nothing much to add to that discussion from Analyst Day at this point.

Our next question is from Sameer Panjwani with Tudor, Pickering, Holt.

So thinking about Waha and the worst-case scenario, if gas flows do get backed up, how do you think about flaring versus shut-ins from both an operational and regulatory standpoint? And for Matador specifically, how quickly are you able to shift capital away from the gassy zones to the oilier zones?

Sameer, this is Matt. On the takeaway, we feel pretty confident that we can continue to sell the gas. In the worst-case scenario, I think it gets down to what you're actually realizing price on that gas. So we don't think we're going to have to flare gas to start with. If we need to, we can get flare permits and do some different things. As I mentioned earlier, one of the advantages we have in this plant we have at Rustler Breaks is the ability to go into ethane recovery. So we can add value to the gas stream by doing that and reducing the amount of gas that does go to Waha.

Okay, and how would you frame that answer in the context of the broader industry rather than Matador specifically?

Sameer, we can't really speak for everybody, but I think it's a -- one thing I do know is that this industry tends to respond to things like this very well. So you know it's going to be a shorter-term problem, I think. Whether it's something that gets overcorrected or not is maybe a question to ask. But I think for -- it's going to be a very short-term thing. There are projects coming in the line that's going to add additional capacity, which will also improve the price. So I think it's a relatively short-term problem.

Sameer, this is David. I might just follow up on, maybe add one comment to what Matt said. Certainly, I agree with all the things that he just said. But you'd ask about kind of the shifting of CapEx or not drilling in some of the gassier zones. First of all, we probably have fewer of the Blair completions actually planned this year than we did last year. So I think that -- not that we were anticipating this particularly, and that's the reason we did it -- that just, on our drilling schedule this year, that's just sort of how it worked out. But secondly, I think, as I think through your question, we have been working recently on a number of different opportunities up in our Arrowhead and Ranger area, which tend to be oilier, produce less gas. And I think it would be pretty easy for us at this point, if that became a significant problem, to maybe move one of the rigs up to that area and just focus on an area, maybe like Stebbins or some of the stuff in Ranger that Ned was talking about earlier, that might tend to have less gas production. Because we tend to have 80% to 90% kind of oil wells are better up in that area, and so that might also be something that we could do temporarily if it becomes a more serious problem.

Okay, that's helpful. And then on the midstream JV,I know there are still a lot of opportunities to create additional value. But how do you think about the longer-term plan? I think you guys have talked about not wanting to be a midstream company. So just trying to think through when do you think that business will be mature enough to actually start pulling forward additional value to get more cash in the door?

Sameer, this is David again. I think what we've said pretty consistently this year is that -- or here recently -- is that what we're really focused on right now is finishing or continuing to build out the projects that we have scheduled. Getting the plant finished was a big goal of ours, and hats off to the midstream team and to San Mateo for bringing that in, again, on time and on budget, and the plant's up and working. We're pushing over 100 million a day through the plant now and beginning to sign up third-party producers or other producers for the plant as well. So I think we're moving in the right direction there. On the water disposal side, as Matt commented earlier, we have 6 water disposal wells in the Wolf and Rustler Breaks asset area. We've got 2 more to drill this year so we'll be adding additional capacity. And the guys are doing a good job of getting that filled up as well. And then, of course, you know about the Plains project. So I think we have a pretty full plate of things that we're trying to get done and accomplished on the midstream side this year, in addition to adding new customers to the 3-pipe solution that San Mateo can offer. And I think we're just -- we're very focused on that for this year before we begin any thoughts about kind of what's the -- if there's a monetization strategy or do we want to do anything, any kind of a dropdown or anything else. I'm not telling you we're not thinking ahead on that, but I think that kind of one step at a time, and I think for us, the most important thing is to continue to get these midstream assets built out and in service, and the rest of it probably takes care of itself if we could make that happen.

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. I'd just like to close this again with the notion that this has been a great quarter, and the outlook, we really like our chances. Here this first quarter, we're off to a start with record production, record reserves, record EBITDA, very strong earnings per share. And I like our chances going forward on that pace. And it should be obvious that where we have spent our money has been good choices with good well results, good land results, good midstream results.

So I really compliment the staff for being not only good stewards but executing well. I would like to give them, again, the hats off and tell them how much we appreciate that effort. And the plans going forward look better and better. We think we've come a long way since going public, and we are proud of this consistent return and the technical innovation that we've done with drilling rigs, with completions, with production, the use of the facilities, and really think the staff is, and Matador is coming of age, and the platform for growth has never been better.

I think a number of good questions have been raised today and we've tried to answer them. But it's hard to go out there and commit without the view of all of the circumstances. And we think that's one reason we've been able to do what we can because we have pivoted in the middle of a year or, as we've had well results, to achieve better results.

So we look forward to coming back to you at the annual meeting and giving you an update, and we look forward to reporting in July. And I think that you'll see this pace of record results continue in the right direction. This is probably the best set of opportunities we've ever had.

Appreciate your questions and want to again emphasize we'd love for you all to come visit us in person and for you to meet this staff that's delivering the results. It's not just Matt, David and me and some of the old guys. But this young group are really coming to the forefront, and everybody's pitching in and making things happen. And I'd like for you to kind of meet them and see that this is a very strong group in all the different areas and getting better. Still plenty of room for improvement, but I think we're on our way.

So with that, I'd sign off and hope that you all will take us up on our invitation to come have lunch or breakfast with us.

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