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Good morning, ladies and gentlemen, and welcome to the Second Quarter 2018 Matador Resources Company Earnings Conference Call. My name is Sonia, and I'll be serving as 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 August 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, Sonia. Good morning, everyone, and thank you for joining us for Matador's Second 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 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, and its most recent quarterly report on Form 10-Q. Finally, in addition to our earnings press release issued yesterday, I would like to remind everybody on the call that you can find a short slide presentation summarizing the highlights of our second quarter 2018 earnings release on our website under the Presentation & Webcasts page on the Investors tab. I would now like to turn the call over to Mr. Joe Foran, our Chairman and CEO. Joe?
Thank you, Mac, and good morning to everyone on the line, and thank you for participating in today's call. We appreciate your time and interest in Matador very much, and we welcome your questions and comments.
Now I'd like to introduce the executive committee of Matador who is joining me in this call this morning, along with other members of our management team and senior staff who are all standing by for your questions. 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 Head of Operations; Van Singleton, Executive Vice President of Land; and a new Executive Vice President, Brad Robinson, of Reservoir Engineering and Chief Technology Officer. Congratulations, Brad.
Thank you, Joe.
Now you're in -- part of the sharp questioning and comments staff that we are about to receive.
As outlined in our earnings release, yesterday, the second quarter of 2018 was the very best overall quarter in Matador's history, both operationally and financially. I want to take a moment and personally acknowledge the Matador staff for all their achievements and to recognize them, I think, for their extraordinary teamwork this past year, where the teamwork among the different departments and within the departments have continued to improve. And this quarter was a real example of how everybody pushed on the rock. Land and legal combined to make an $80 million acquisition yesterday. Production and the midstream have combined and worked together as a team so we're not flaring any gas. And just over and over, the teamwork with our MAXCOM program with our drilling program has been extraordinary. And so from the executive staff is that I'd like to shout out to the guys in the field who have really been connecting wells, working in tough weather conditions and making it all happen. So very pleasing to us is just the way everybody has worked together. And I didn't want this conference to go by without recognizing them.
We're now going to move into questions in just a moment, but I do want to address just quickly a couple of items and then take your questions, your comments on. One is the outspend that is of concern, and I think you all know our views on that, that we are very selective about any outspend that we have. And when we do, we weigh the choices of, is this going to have better than average returns? Is this an opportunity that has to be done now and won't be around in a year from now? An example of that is some of these leases and minerals that we've taken. And third is there -- in the midstream, that if we don't do it, someone else will. The same way is that we've discussed in previous conversations we take away in flow assurance. And we issued a press release, June 4, that summarized and updated our views then. Since then, we've made additional deals that we can discuss here and address it in different ways. And we're not done yet. We're going to continue to improve and feel like not only we'd made great progress, but we're working towards the long-term. And with that, I'd be happy to turn it back to you all for questions.
[Operator Instructions] Our first question comes from Scott Hanold of RBC Capital Markets.
I was wondering if you could talk about the OBO activity that is incremental. It seems like, especially on a gross basis, there's a lot more happening in the areas where you guys are at. And I'm assuming that it's pretty strong economic returns. Could give us a little bit of color on where some of that activity is concentrated on? And you did mention longer lateral. So is this like some of the -- is there -- can you give us some color also on like the operators that are doing this? Are these some of these larger scale kind of big development pad that we've been hearing about from others?
Scott, thank you. I'll take it first. And then if David and Matt will follow up. But first, I want to thank you, because in our outspend, this is -- the wells operated by others is one of the major motivators for the outspend because when these wells are proposed, and there are more wells being proposed than we had projected -- you don't want to go nonconsent, because many of these wells have this higher rate of returns and big reserves from, as you said, from the 2-mile laterals. So I think the overall CapEx associated this year with OBO is going to be somewhere in the neighborhood of $70 million. And that -- and the amount of additional wells, we have 2.5 net OBO wells to drill in addition to the 5 net that we had projected. And as you said, these are some high-return, large recovery wells, big pad drilling, and we want to be a part of that, and I think the economics are clearly there to do it rather than to go nonconsent. So OBO is going to be a factor. And when you're in the better areas of the basin, you have more OBO proposals. That just goes with that territory. And we've always like them and what we felt was the core of the core or the best of the best and accepted that competition. David, do you want to comment further?
Yes, sure. I'd be happy to, Joe. Scott, I think just to add a little to what Joe said, probably the 2 areas where we've seen the most nonoperated proposals have been in Rustler Breaks and Antelope Ridge. But we do have, from time to time, wells that we're asked to participate in on a nonoperated basis up in the Arrowhead and Ranger as well. And I think in previous releases, we've talked about some of the results of all of those wells. We -- I think you know the folks that are kind of in the areas that we are, I mean, we've talked in the past about wells we've been in with Cimarex or Concho or [indiscernible] or WPX, Marathon. So the folks that are in the areas that we're in, we do have some smaller pieces, some smaller tracks outside the course of our positions at times, and this has been a great way for us to get those tracks held. So I think that we've been real pleased with the results. It gives us a chance also to learn some things. I think in the last quarter, we were talking about -- in our Analyst Day anyway, we were talking about, for example, Concho doing some break sand wells down in the Rustler Breaks area. And so that only gives us a chance to learn a little bit about participating in these wells, too. So we're happy to continue to participate in these wells. They've -- our fellow peers are doing a good job with them. And as long as we feel like they're going to make us good returns, we're always interested to participate.
And Scott, this is Matt. And just to jump on with David and Joe here, I think very good wells that we're participating in. I think what David mentioned there, the ability for us to learn, is very important, and we always reserve the right to get some order. I think it also gives us an opportunity to collaborate with our offset partners. So we are pretty active in a non-op role, in calling their technical folks and discussing which targets are picking and how they're going to drill the wells and complete them. And then another thing is it just sets us up to -- these relationships set us up for potential trades. When we get offered a non-op position, we may want to trade all that into something that we're operating in. And it works both ways. It's a good deal, a win-win situation for both of us in the non-op.
The last thing, we also feel it enhances our midstream because every well drilled out here in Rustler Breaks is right in our gathering systems for oil, gas and water out there for San Mateo. So it represents and also an opportunity for San Mateo to gain from participation. If we're not in the well, there's less chance that they'll do it. But if we're in it, then we can [indiscernible] much more fluids and gas that we can send through our system there. So again, it's just very selective bid on outspend, and the OBO is an important factor. We've never taken the view that we had all the answers on every drilling, completion or production system. There's always a chance to learn from others to develop some relationships that will pay off going forward.
Great. Great. And you're kind of leading down my second question. On San Mateo, can you give us a little bit of color on the progress on signing up third-party operators? I think claims should be complete, but they're part of the system in the not-too-distant future. And you did sign a deal with Marathon on the water. Can you just give us some general sense of how that's going? And is there more interest in one piece than the others? Say, there -- does it seem like there's more interest in the saltwater disposal versus the oil or gas lines? Or do you see pretty good progress on sort of all the streams of pipes you have?
Scott, we feel we're making progress on all 3. And I can't say that one stands out to the other necessarily. That we believe that there are probably more options sometimes on the gas than having oil on pipe. And then of all of those that with gas you can flair, oil you can truck, but water has to be disposed of, or they'll shut your well in out there. So we've built up a lot of capacity in our saltwater disposal well, and that's another area where our teams have worked very well together, is we have a capacity to drill deep, and the knowledge that most midstreams don't have because we're doing it in our everyday. So we moved a couple of our rigs from drilling oil and gas wells to drill 2 saltwater disposal wells to 14,000 feet or so and get them completed on time. And that enhances both our own need for saltwater disposal, but it helps attract further business. And I want to make clear, we, as a practice, don't reveal who our third-party contracts are with. So I can just say thanks for working. And we're pleased with the third-party contracts that we've entered into, the ones that are working, and we feel the ones that are yet to come. And we did announce that we have done an exchange offer with -- on an interruptible basis, some gas coming through. So we feel we're ahead of the curve on what we've set as our goals. And we can't guarantee we've said as a target that in the fourth quarter of this year, that we'll have $25 million in EBITDA. And while we are not yet ready to guarantee it, we do believe that it's achievable, more likely to be achieved now than was 3 months ago or 6 months ago, and the guys are working right along. And the plants running on time efficiently. And they've done a number of improvements. For example, they have an interconnect line with BHP -- I mean BP. And so we're selling our natural gas liquids to them on pipe, which has given an uplift to our gas prices and have put us in a position to do the ethane recovery, either the full recovery or quasi recovery. Again, that would be helpful to our commodity pricing. Matt, did I forget something there?
No, I think you summed it up pretty well, Joe. But Scott, just to kind of talk about where we're at in relation to San Mateo. We've got the saltwater disposal system put in place. Joe mentioned we're drilling an additional 2 wells, so that's going to ultimately get us well north of 200,000 barrels-a-day capacity. So that's a good thing for the San Mateo team to go out and sell to people. Additionally, we've got our inlet design capacity, 260 million cubic feet, which will be at full capacity where we can bring on 260 million by the end of the year. Like Joe said, with the ethane recovery option available, the oil system, the oil gathering system is complete for us at Wolf. We are selling into the Plains Pipeline there. We've got our infrastructure in place at Rustler Breaks. So when Plains gets test, we'll be ready to go there. So it's really in a nice position that the guys can go out and say the water is important to one of the third-party operators. But as we start talking about having the ability to process gas, to go in ethane recovery, to make sure that they got flow assurance and a pricing agreement for the NGLs at the tailgate of the plant, as well as being able to bring oil onto the system, I think that's a pretty powerful thing for them to sell.
Last thing, Scott, is in our oil ferry, that pipeline, oil pipeline gathering system, is complete and operational. So that as we gather that up on our gathering line, we can turn it over to Plains at Wolf, and they'll go away on their pipeline. And we like to note on this flow assurance and take away that we're selling our barrels at the wellhead. So we don't have the concern about piping it to Midland and we have the option to buy it back there, but we don't have the obligation to get it to Midland or other markets. It's sold at the wellhead to Plains. And we've enjoyed working with Plains. They've really been very professional. And we're -- that's going very smoothly, and I'd like to give them a shout out. Their work with us is -- hard to think of any improvements.
Our next question comes from Gabe Daoud of JPMorgan.
Could you maybe, Joe or David or Matt, just talk a little bit about how you're thinking about the seventh rig at this point? You did mention in the release your expectations about the oil differentials for the third quarter. And I guess at one point do you think it absolutely makes sense to put the seventh rig on the Eagle Ford?
David, why don't you take this?
Sure, I'd be happy to. So I think what we put in the release sort of reflects where we are, which is that we are continuing to evaluate it, but we haven't actually made a decision on what to do yet. I think that we're still looking at the possibility of maybe putting the rig down in the Eagle Ford for a short period of time. But we're also weighing that against the potential for putting that seventh rig when we're ready to go with it into the Permian. Clearly, we're real pleased with the early results we're seeing in Antelope Ridge, and I think it could -- it could certainly be a candidate for the rig. I'll also tell you, we're pretty excited by the -- some of the things we've been seeing and reporting on from the Arrowhead area, the Stebbins area, the SST. I mean, the -- and so we're giving considerable consideration to that being the candidate for the next rig. So I think that it's a little bit of a high-class problem. We probably have 2 or 3 different options where we could put the rig, and our teams are working to be ready no matter what we might decide together is the right thing to do. But at this moment, we're still kind of debating that internally, Gabe.
Thanks, David. That's helpful. Definitely a high-class problem like you said. And then I guess, maybe just a similar question, but do you think there could be a point where it makes sense to -- if differentials continue to get worse, it makes sense to not only not add the seventh rig, but -- in the Permian, but also slow down the current pace of activity. Just any thoughts around that?
Well I suppose that it's always a consideration. I mean, obviously, commodity price and differentials clearly have an impact on our thinking. And as to what they will be, what the duration of that will be. I mean, certainly 2 years ago when commodity prices declined the way they did, we looked at things and felt like it made sense to slow down at that point, and so we did. But we didn't stop. We continued with a 3-rig pace. I don't think today that we're entertaining a slowdown at the moment, because I think we feel like that this issue will resolve itself sooner rather than later. But certainly, we remain vigilant in terms of watching it and seeing how it goes. One thing I'll say is that I'm always very comforted by the fact that I think we've done a good job in terms of the optionality that we've given ourselves. And as we've added rigs back, I think as you know, we have done them on a short-term basis. Even the long-term rigs that we have now are under contract for less than a year. And so we really have a lot of optionality in terms of the ability to go faster or go slower if that's what we should decide to do. So I think that it's not necessarily something we're entertaining at the moment, Gabe. But one thing I do know is if the environment indicated it was the right decision, we could get there pretty quick.
Gabe, I'd like to just chime in here a little bit, and mention again that we're focused also not just on commodity price, but returns. One thing is that if price goes down, generally, your cost go down, and that you can still achieve 40% to 50% rate of return. And I think we demonstrated that, when oil was $50 or even less, we were still making money. And we were beating consensus now for 16 straight quarters as that -- we make adjustments and focus on returns and how to get to the desired returns and not just be driven by price. And as Matt says, we aim at profitable growth at a measured pace, and measured means taking into account the environment, but maintain a strong balance sheet, as you've seen over time. So over 5 years, we've kept that debt-to-EBITDA ratio as being one of the best in the industry. And that's still a core belief of ours that if you're going to be in this business -- I've been in it 34 years -- you've got to maintain a strong balance sheet. So as David says, you maintain your flexibility and ability to carry through, because some of those times where it's tougher, you actually make more progress. So I would like for everybody to feel comfortable that we're not out there growing for just the sake of growing, but it's select -- it's a definite plan that's based on returns and profitability and the value-added, and we're all committed to that. And we do think that if you're selective enough, you can still have -- and you're fortunate to have the acreage, the right kind of rock, you can still have growth with profitability in almost any circumstance. You've just got to be a little creative and a little bit -- put in a little extra effort. Matt?
Yes. I just want to add one thing, Gabe. Just the way we think about things is pretty consistent across all the different activities we do. And David mentioned the optionality we have with the drilling rigs. We've been talking with Patterson for just really continuous discussion with them about if we decide to add a seventh rig, what kind of rig are we going to get. And we're assured that we're going get a high-tech rig. It's going to be just exactly like what we want. On the other hand, we're in discussions with them if we need to go down a rig or 2, we can absolutely do that. Same with the frackers. We don't have any obligation to frac a number of wells or a number stages or anything like that. We have a pricing agreement that allows us to go up or down. The Eagle Ford versus Delaware option is there. We still -- nobody's said anything about it for a long time, but we still have our [ angel ] option. So keeping all our options open, even in the midstream business. We've got -- one of the things that Gregg Krug, our Head of Marketing, still lists since day 1, is options are good. So when we built our plant, we built a number of outlets that we could offload gas into it. And one of those outlets now has turned into the one that's bringing gas into us. So just maintaining optionality in all our business lines is very important to us.
Gabe, it's a great question that you asked. I hope that answer was sufficient. And I would advise you to come see us, and we, again, continue to discuss at length. But we really -- it's really important for us to have that flexibility. And we do have that deal if it does provide a return. We don't do it unless it makes economic sense. You know how much stock that these executives in our board own, we make more from our stock than we do our salary. So we're not out here to invest in things that don't add value. That sounds corny, but we really believe that, and a lot of other shareholders, our friends and family. And so everybody's pretty value-conscious.
And our next question comes from Dan McSpirit of BMO Capital.
Speaking of driving shareholder value. Joe, if we could just turn at Twin Lakes, no ignoring what Twin Lakes could mean to the inventory and how it could help write the next growth chapter for the company. How do you frame the asset's importance in driving shareholder value? And how do you assess the risk of it not working and not competing for capital?
Well, Dan, let me try to take your question in this basis. A question like that has to be taken in relation to your other assets. And very fortunately, we have -- we'll probably finish the year with over 90,000 acres in the Delaware portion of the company. So we've got great assets, we've got 2,000 engineered locations down there, no shortage, lots of options. So what you have up in Twin Lakes is very additive to what we already; it's exploration acreage that we acquired for the most part on a weighted average basis of probably $200 to $300. So in terms of investment up there, they're in that much. And on the other hand, we've been encouraged by what we've seen. We've approached it like we've done everything. If you think about our progress in the Delaware, we went public in 2012 with a small Delaware position. We announced that it wouldn't be until 2015 that we thought it would really gear up or -- and that's exactly what we did. We drilled a well in 2013 or 2014. Drilled a few more following that as we began to delineate our position and then gear it up. So I think most good exploration is done deliberately over a period of time. And that's what we've approached. Others have gotten interested in that area up there; Continental, Cimarex, GreyWolf.
DGP.
DGP. And so we're not the only ones that appear to be encouraged by the data. The 3 wells that we've drilled up there ourselves have all done better-than-expected, the Olivine, the Culbertson, and the one that we're in now in the process of completing, we're very encouraged by. But it's a deliberate game. If you go too fast, you waste some money. But we've cored 2 wells. We're able to compare, they look promising. And they're behaving better-than-expected, but much like we had projected that it would have not headline-grabbing initial rates; but over time, they're a little better permeability, and for us, they would have a more general decline. And we've raised our reserve estimates on those wells. And so we think it's going to be additive. If the whole thing should not happen, we didn't pay much in acreage. I mean it was a couple of hundred dollars, and it's to me, good exploration to go into an area where you know there's oil. That area out there has produced billions of barrels, is still very promising, and I think it will come to contribute. And things are moving faster up there now that other companies have seen kind of what we've done and the results. And so that's building some momentum. Brad, what would you add to that? Brad's our Head of Reservoir Engineering.
Joe, I think you hit all the key points there. I do think the point you made on just the Wolfcamp especially is a little different up there. And what we're finding is that targeting can make a big difference. And we're producing in our Culbertson well. We're really pleased that it's done probably better than I expected at this point. And we're learning that it could be better with some slightly different targeting. And that's things we're learning from the data that we're collecting, and we're applying that now over in candidates, and we're really excited to be completing that well, which should be towards the end of this month and we'll know something probably by our third quarter. So it's a little different up there than down in the heart of the basin. But we've got a great science team with Ned, and his geoscience team analyzing all the data. And we're real excited that it is going to be a major asset for us in the future.
Well, it certainly could be. But we're going at it in a way we're not dependent upon it anyway to achieve our 20% growth that we aim for or the profitability. But we think it'll be additive. You have the opportunity because that area is blockier for the longer laterals. Also, it has opportunities for midstream possibilities. And we're going to continue this methodical approach to exploration just like what we did down there in Wolf, and then again in Rustler Breaks; and we've gone in our other areas. So I hope that answers your question. We see a lot of upside, not much downside. And so, anyway, again, we feel there's 2 areas, the Kemnitz area over on the other side of Lovington, both showing a lot of possibilities, not just in the Wolfcamp, which is thick and there's a number of target zones, but also in the Strawn, the Olivine well that we drilled has held up very well, too, and exceeded expectations. And that was just a vertical well. So looking good. I don't want to tell you it's going to be better than Rustler Breaks or any of that. It's hard to meet that kind of success, superstar. But I think it's going to be pretty productive area, and it could get really good.
Our next question comes from Philip Stuart of Scotia Howard Weil.
You guys have, obviously, done a very good job of adding acreage to kind of your existing operating areas. I'm just curious, if you see a larger opportunity set in any one particular operating area to add acreage going forward, maybe Rustler Breaks just given kind of the San Mateo partnership there and kind of that's kind of your area where you're running the most rigs. Is that maybe the most likely spot where you continue to look to add? And kind of what kind of prospects are out there?
Phil, a very good question. And we ask us that same question of ourselves all the time. We included a map on our website, which shows on this $80 million deal that we did yesterday, where we added acreage. And I would refer people to that. And that showed that we acquired acreage in Wolf, a good amount in Antelope Ridge and, of course, a good amount in Rustler Breaks that has really add on to our existing acreage or in the adjacent tracks. But I think there's still just as much opportunity up in Arrowhead and Ranger to add acreage. And the pleasant thing for us is that each of our operating area across all of our acreage, we're having good drilling success, and even up there in Twin Lakes. It's a high-class problem, as David said. But each of the asset teams are asking for more drill time and more CapEx being expended. And they're proposing some pretty good wells. And we're trying to, again, keep to that measured pace. So I would just tell you that in Wolf, Jackson Trust, all that down south, our guys did a good job, but they're going to be -- but I think up there in Arrowhead and Ranger, you're going to see opportunities, and in our core areas of Twin Lakes. So over the next 12 months, expect additions in all of those areas. And I did want to, again, thank you, and the other analysts who last time really wanted to see a map, so we wanted to be responsive to that and included a map to give people an idea and tie it back to our -- when we did the equity raise in our operating document there that we did exactly what we said we'd do, that this was -- a good part of this money was going to go to buy acreage, lease acreage and mineral interest in and around our acreage. And I think people can see that we've done that and that we're -- we haven't stopped yet. My experience over 34 years and out here in this area, being a landman, is there's always acreage to be had, deals to be had, trades to be had with other companies, which I think are picking up steam because that's such a win-win proposition, that you fill in your sections, they fill in theirs, you do the trades. So I see that opportunities continue. And we kid with Van, he still has his RV, and that -- and you never know when he's going to pull down the knife and just set up shop at all the courthouses...
Oh, I'm sorry. Joe, I'm just going to add to that. It's not entirely coincidental that a lot of these opportunities present themselves in areas where you're very active. Down in Wolf with Rustler Breaks, Antelope Ridge, as our activity levels increase in those areas over time, we had more and more opportunities come to us. And I think there's a number of reasons for that, and maybe one of the most important one is when you get in an area and you start to show efficiencies and you're drilling good wells and you're a good operator, those opportunities will come to you. So I think as we increase our activity level in the coming years, so up in Antelope Ridge or in Arrowhead and Ranger, I think we're going to see additional opportunities up there as well.
And Phil, this is David. I just wanted to make one quick comment while we're talking about acreage in the maps. In the slide deck that we sent out last night as part of our earnings release, I noted this morning as we were getting -- actually, last night, as I was kind of doing one last review of all the materials in preparation for the call today. On Slides 8 and 9, where we showed the update in the map, and particularly Slide 9. The callout box that we had for Antelope Ridge actually happened to cover up a chunk of the acreage that we bought in Antelope Ridge. So that was probably not the best place for that callout box. But we have corrected that on the website. And so if you just go back, if you're interested, anyone who may be listening, and kind of reprint Slides 8 and 9, you'll see the acreage in its fullness as opposed to the little peek-a-boo that we had last night there.
Our next question comes from Neal Dingmann of SunTrust.
David or Joe, my question is really just on the opportunities you continue to see. You guys did a great San Mateo long-term agreement deal. You've talked a lot about, that's been really beneficial, as well as this Kinder firm sales agreement. And Joe, my question is really are there -- as you guys continue to see out there, are there more opportunities, or you call it needs, for more of these things going forward?
Neal, yes. We're not done yet. We do see further agreements or arrangements that can be made to improve our lives, so to speak. Improve where we have set things up that will give us more options, volumes, prices, terms. When I say terms, I'm talking about duration that we're looking at some very tempting deals, but they're, say, a little longer term than we'd like to have and we're looking at some shorter-term deals that we think can be favorable. So we're never going to stop trying to provide better takeaway and flow assurance and processing options and market options. We're working towards just like we did with Plains where we buy the barrels back in Midland. But those days, when we might want to send it to Cushing or down to the Gulf Coast, we're working out deals to get our gas down the Gulf Coast, which we think is a good market. Or even to Henry Hub. So I give a lot of credit, Greg Krug and his marketing group have really done a good job of creating those options and those opportunities. And we think there'll be more to come. I mean this business is -- there's going to be more pipes, which mean you have more opportunities. The marketing is getting more sophisticated. And they've been good about building relationships and I've really learned a lot from all of them on what can be. So I think in October and in the end of the year, your going have more comment from us at how they continue to further our position. Matt?
Neal, this is Matt. I think the way you phrase the question in regards to San Mateo, I think is important. So that takeaway capacity we're talking about, as Joe's talking about to do with Plains, any third-party volumes that San Mateo brings on board for the gathering system will be in that same agreement so they'll have the same flow assurance that Matador has, getting the barrels bought at the wellhead and the opportunity to buy back at the Plains. But one thing that doesn't get near as much discussion is the NGL takeaway and the fractionation. I think people are starting to talk about it a little more, but that's for Matt Spicer, who heads up the San Mateo group. That's one of the things he can now go to third-party operators with and say, look we've got -- not only do we have firm takeaway capacity for your residue gas, but we have a couple of things in regards to NGL. We're going to have the full ethane recovery option, which ethane now is in the money and certainly as gas prices would continue to deteriorate, that would be even more valuable for them to be able to offer that. But also disagreement that we have with the pipeline that then comes to the tailgate at Plains for NGLs. That's a firm takeaway issue there, too. I mean, BP, is actually buying the NGLs at the tailgate of the plant, so they own them, they're putting them on their system, taking them away to where they got fractionation capacity and so that's a pretty good deal for both Matador and San Mateo.
Very good. And just one quick follow-up, Joe. And talk to why your well cost continue to be about among the lowest up in the basin there in the Delaware. Was just wondering about when you talk to about local sand, are you looking at things like local sand or more vertical integration to bring cost down further? Or are there -- are opportunities like that getting a little bit more difficult to come by?
Neal, again, an excellent question. And the answer is, yes to all of those. Every phase of cost that we are really looking at and we've begun some experimentation with local sand, we're doing almost all of those things. And then Billy, I want Billy to pitch in here and Matt, because they're due a lot of credit for working out some pretty good arrangements. We have a maxed comp program, which goes 24/7 in our offices, where the geologists and engineers are doing the directional drilling and that working out amazingly well the teamwork between them, the engineers learn geology, the geologists learn engineering, and we're saving a lot of money, because you don't have drilling engineers that got to wake up in the middle of the night and make a decision and takes 2 or 3 hours. Our guys are making them instantly. That's already saved us a ton of money. Our young guys that are running the rigs have -- they just get better and better than ever. Let me just let Billy speak for his group, because I know he's beaming with pride at your question.
That's right, Joe. The max comp room, 24/7. It's tied together the drillers and geology department and asset teams. They all spend a lot of time in there working together, having meetings, watching what each other is doing. And we found that we're staying in zone a lot more, and not just zone, in the target zone, but in the preferred part of the target zone. And thinking that we're going to be doing that, we were thinking we might be slowing down, but we didn't. We've actually started staying in there and drilling faster at the same time. So making better wells, drilling faster, saving money. And hats off to all those guys, like we say, 24/7. So that's a great thing for us, and we've set records in each hole section. And we've become not just like a one-off record, but they become consistent. They'll mark down curve in an area from 12 hours to 10 hours to 7 hours to 6.5 hours, and then they'll just keep matching it. So we're consistently performing at a high level, and expect that to continue. So we're all doing a great job there. And then also, like you mention, the completion side, we've been testing and evaluating new techniques, the slick water fracs and spacing and the local sand. And I'll let Matt chime in here.
Neal, I like the fact that you said we run a low cost. What we're really looking at is trying to maximize value. And so the completion team, Neal, we talked in quarters past about moving towards regional sand, and we're going to do our testing, we're going to do our research, we're going to make sure that we're comfortable. I think we're pretty comfortable at this point. So we've actually pumped some jobs with regional sand. And as we've talked about before, we're not going to know from an IP or even 30 or 60 or 90 days. But so far, the things look good, the cost savings that we had anticipated are there. So there's a reason for us to do that. But Billy mentioned some slick water job. That's an area where we may actually spend a little more money. But if we can increase the production in the reserves, we're very willing to do that. So again, we just try to maintain a lot of optionality with this. And we're also, as we put the drill schedule together for this year and for next year, we've got a large number of the wells that we're going to drill will have some component of pad drilling. So we talked at Analyst Day about 2/3 will have some multiwell component to it, so we're going to continue to focus on, not only the cost structures, but also efficiencies.
And then I want to thank Patterson for working with us as they have on the rigs, because these are really state of the art rigs, as Billy will describe. I mean, they can do a lot more. They are more powerful and better pump systems. And again, they have helped set those records in each section of the hole has made a difference, Billy?
Right. That's right, Joe. We've got out front with Patterson putting together the rigs for us with the high-pressure, 7,500-psi piping, the 1,600-horsepower pumps. Redundancies in the midst -- in the mud system, the higher pressure, the higher capacity, gas separators and we've added our managed pressure drilling packages to those, and it's up to us as we face challenges in the different hole sections when they appear, and we just blow right through them. That's helped us be really efficient. And then also the walking packages like Joe mentioned there with the BOP [ handlers ] and all so we can get the rigs moved around and batch drill the wells and working with the asset team there saved a lot of money.
And our next question comes from Gordon Douthat from Wells Fargo.
So just had a question. As you put on these wells across various benches, multiple benches in the Bone Spring, multiple benches in the Wolfcamp. Pretty strong results across various areas. Are there any projects that are rising to the top from an economic standpoint kind of as you look to playing out your development what are you seeing kind of rise to the top?
Gordon, it's David. That's an interesting question. I think that in some ways, it's a little bit dependent on the area that we're in. I think that we've been very pleased with the returns from both the X-Y and the B in Rustler Breaks. You get up to Ranger and Arrowhead. I think the second and third Bone Spring had probably been what we're focused on the most, and we're pleased with what we're seeing there, though we're, even as we speak, we're doing another test at Stebbins on the upper Wolfcamp. They're in that area as we continue to try to test the Wolfcamp a little farther to the north. I think you get over to Antelope Ridge there's a number of targets that we're excited about, but I would say this First Bone Spring target is one that I think it's really begun to catch our attention and catch our fancy. Of course, the lower part of the Wolfcamp, where we drilled that Thorsness well in the last quarter, has certainly been a standout and continued to do well. And been down in the Wolf area, while we like what we see in the B, in the pad in the lower part of the Wolfcamp and the Bone Spring, I think the X-Y has probably been the strongest. But then you go over to Jackson Trust, and it's probably the lower part of the Wolfcamp there. So it's hard to just say; it kind of becomes more asset specific, I think.
Okay. That's all I have.
Gordon, before you go, I don't want to leave out because we have some deeper targets that we hadn't got into that have showed promise. In one of our wells, we decided just to deepen a well to the Morrow just to get "a easy test," just to get some gauge of it. But here's a vertical well we took to the Morrow and it's made $3 million a day, very steadily for a long time. It's really held in. That's the [ Nora Staunton ] well, named after 2 of our shareholders, who were recipients to the medal of honor. And so I told them that we really appreciate their efforts to make sure we have really good well coming out of their nomenclature, I guess, so to speak. But that test alone shows some of the options you have by going deeper to these other zones that we hadn't gotten to. So we're in that -- we haven't yet reach full development mode, because we're having so many different zones. And just to give you a story, when this -- when we were doing the IPO, our reasons for going out there to the Delaware was that we had done the oil in the Eagle Ford, that was the hot area of the country, and we felt there was more application for these oil techniques, these oil shales out there than anywhere else. And as we went out there, it was on the strength of 2 or 3 formations, and now we've got production coming from about 16, and it hadn't stopped yet. And so it's been a very favorable area. The Eagle Ford has had comparable returns on the well you drill. It just has 1 or 2 zones: the Austin Chalk is coming back down there, and the Buda. But out there in the Delaware, as I say, you got 16, and we may end up with 20 before -- different zones. And if that column is so thick, 5,000, what Brad was talking about targeting, we found that even moving as little as 30 feet can sometimes make twice the well. So we've been proponents that, over time, targeting will be as important as any of the other steps of looking at some formations and figuring out which ones offer the most potential. So we're -- the thing that pleases most that across all of our acreage, we are earning the targeted returns that we try to get to, 40% to 50%. And we're still assessing and watching the new innovation and new frac techniques, all that, that can have a big effect on, which zone has got the most to offer and where should we go economically. Thanks, Gordon, and it's a great question. As I said, it's hard to say. They've all been so good that you can't say we're going to go over here and put this other area on hold. All the asset teams make very compelling cases to keep up investment in each area and see what happens.
Our next question comes from Jeff Grampp of Northland Capital Markets.
I was curious, you guys referenced in the release a couple of times the trucking of your oil in the Delaware. I'm just kind of curious if you guys can give us a sense what's truck versus what's on pipe on your Delaware oil? How it could potentially change over the next few months? And then just in general, your conversations with the trucking companies, what's your sense of how availability might be trending on that side of things?
Jeff, this is Matt. As we talk about the Wolf acreage, everything at Wolf is currently on pipe. And so we get Plains into Rustler Breaks up there, all of that will be on pipe. So I think in the basin you're probably looking at certainly north of 70% of all the oil will be on pipe. The remainder of it, we've been successful thus far, and we'll knock on wood, but we've been successful thus far in securing firm capacity on the stuff at Antelope Ridge and the stuff at the Ranger and Arrowhead that's not on pipe. We're -- typically, the negotiation is about term. And how long we're willing to sign up for that. But even the stuff that we've got on trucks there, we've got firm capacity there.
Okay. Great. And then for my follow-up. I'll hop in the weeds here, you guys may not have this off hand. But on the minerals acquisition side of things, can you give us a number of where that's kind of mineral acreage stands today? And maybe what kind of production is coming from those minerals?
Yes, this is David, Jeff. If you will just sort of forgive us, I think, we are not quite ready to disclose. I think we said in here that we had 3,400 acres of minerals that closed in this deal. I think you can go back to previous releases and kind of see what we had. But we're not just quite ready to disclose what all we've done there. We still have a little bit of work to do there and want to maintain as much of our competitive advantage as we can. So if you will indulge us a little bit there, I think we will -- we'll certainly we'll talk more about that as time goes on. I do think that as we said at the time of the offering, that the minerals that we had acquired over in the Rustler Breaks area, for example, we're probably going to add plus or minus 500 BOE a day, as I recall, once they had closed. So we'll begin to see that. I think what's exciting to us is that so many of those minerals are under tracks that we actually already have on production or will have on production, and it's certainly in an area where there's a lot of activity. So we expect those minerals to get drilled. Likewise, the things that we acquired in the other areas should have the same kind of activity on them. So I hope that's adequate, but that's probably about as far as we're ready to go today.
Our next question comes from Noel Parks of Coker & Palmer Institutional.
I wanted to go back to Twin Lakes for a minute again. And I was wondering there, I know one of the features of the petition out there is the water content. It is expected to be lower than elsewhere in the basin. And I was just wondering from the wells that have been drilled so far, I know it's early still, but has the cleanup and then sort of the oil cut relative to the water, has that come about like you expected predrill?
This is Brad. It is. We expected it to be a little lower up there. And it right now, the water cut averages maybe 40% or 50%. So that's substantially less than what we found down in the main part of the basin. So I'm not too surprised, but I am pleasantly surprised that it is actually a little bit lower than we expected.
Yes, in the lower part of the Delaware Basin, you may have 4x the water for each barrel of oil. And up here, you're having half a barrel for each barrel of water. So certainly makes your lift cost better, that's one of the economic advantages. And as I said, we like both areas, they are different kinds of production and wells, but we believe both will add value.
Great. And just for follow-up, as you plan the next well you're going to do out there between you and your partners that's going to happen, are you more drilling at this point sort of along a trend? Or are you going to be heading more towards, if you will, the 4 corners of your acreage just to get a sense of how the formations might develop across it?
I'll speak and then anybody else can say what they want, but we don't tend to go the 4 corners, we tend to go the very core and then expand out, is the way I would describe it on a kind of step out controlled basis. Brad?
I agree, Joe. I think we go right to what we believe to be the core of the acreage and we collect data in that area, and we use that data to help extrapolate in all directions and try to help us predict based on our geologic models and our reservoir models where we think the acreage can be developed. And over in Twin Lakes, we had identified 2 different specific areas where the Wolfcamp looks very good to us, and you can tell from our acreage position, where the areas we're interested in and we went right in the middle and drilled some test wells there. So we're really excited to complete and test this new well that we've drilled. As Joe mentioned earlier, there's quite a bit of activity going on up there. If you would have looked at that area 2 years ago, it wouldn't have been very active. But -- so we're really excited about it, and that's what we're planning on.
Our next question comes from Mike Scialla of Stifel.
Just trying to do some math here, which is always a challenge for me. But I wanted to see if it sounded right to you. I'm looking at your first half D&C capital of about $336.5 million to complete the 35.7 wells, works out about $9.5 million per well. Is that in the ballpark? Or is there something faulty with my math there?
Yes. I would tell you what probably is faulty with the math, Mike, is that there's always cost of wells in progress that from an accounting standpoint, have to be accrued. So -- and I don't have that number exactly on the top of my head. But I can guarantee you that there will be a significant chunk of capital that's been accrued in that $335 million for wells that have not been turned to sales yet, because they were either drilling or completed or in the process of drilling and completion. And so I think you just always have to take that with a grain of salt. For example, we had 2 wells on our [ Coleman ] lease up there in Rustler Breaks. They were absolutely drilled, completed, finished and that didn't come online until the first or second day of July. So when we report numbers turn in the line, well they didn't make the cut, so they weren't shown on the list, but all their cost, I guarantee you, are in that number already. So I think that's -- I think until you kind of get through a year and have a chance to kind of look at all that, in hindsight, it's a little hard to make that kind of math work.
Got you. Okay. I wanted to follow up on Joe's commentary on the 16 zones that you've tested, that you guys have been really a pioneer in the basin on testing, both the number of zones and the acres that you've delineated. Do you foresee at some point next year or I guess my question is when you foresee -- there's a lot of issues with full development. People have talked about parent/child issues and how to set up the infrastructure. When would you or do you have any plans for 2019 or beyond to maybe look at a full development scenario?
Mike, it's Matt. I think the way we're approaching this is kind of, as Joe said, a measured pace. We do our -- we are currently drilling wells on what we think here is likely the proper spacing, both vertically and horizontally. And as we learn more about that, we'll adjust that as we go. But I think it's going to take a while before we are able to determine exactly what we want to do in a full development on the section. And others, some others that are out testing that, that are actually doing multiple wells. But our approach is going to be a little more methodical, I think we're going to do it in a section here and a section there, where we're looking at the right type of spacing before we jump off in the full development [ cube ] type drilling.
Mike, the big risk about rushing into full development is you are going to -- there's a likelihood of over drilling the sections. That this is something that we discovered in the Eagle Ford that when you thought that you could drill, say, these on 40s or 80s, you didn't notice on the [ high P ], the first month, that there was any interference. And it wasn't until after a year, you began to see the interference. And so as a result, you just can't rush in and drill 4 off the pad, and I wouldn't do that, I think there's too much risk, that you take some time and some data points to know whether it should be 4 wells to the section or 6 wells to the section. And you need to go add it in a pretty methodical fashion. And the same thing, it's a tension between delineation and full pad, and you can't say there's always a bright line and you have a push-pull there that depends on a lot of different circumstances. It's not a single factor. And you can do a pad, and in the first months of production you'll think, hey, no interference, but at the end of the year, it will begin to be seen.
This is Brad. I agree, Joe. That's exactly -- and we treat each area a little differently because the reservoir properties do change. And so what might we may develop on 160-acre spacing in one area might be 80-acre spacing in a different area for essentially the same reservoir. So as we drill these parent wells and we analyze the production and the data that we collect, we are constantly looking at optimizing the well spacing. And just to expand a little bit, in Wolf right now, we are more in the development mode for the X-Y. It's been our bread and butter down there, but we're still doing some exploration. And so there are some areas where we are, I would say, full development mode, while in other areas, we're still delineating new reservoirs.
Did that answer your question, Mike?
Yes, it did. It sounds like you're still primarily delineation probably through next year I would guess, but then isolated areas like Wolf sounds like you're there, but I wouldn't expect a big [ cube ] type development for 6 or 7 zones in a section next year, that'd probably be too early to anticipate, it sounds like.
Yes, I think that's fair. Matt?
Yes, I think it's accurate. Like you said, I don't think we're quite ready to start doing that. Just we're kind of, like Brad said, peace mealing together, what's going to work in the X and Y and what's going to work in the Second and Third Bone Spring and First Bone Spring in areas where we're drilling just we'll take it piece by piece.
And, Mike, we're trying to gather data from some that are operated by others that are in a bigger development mode like that and see how those results compare. So kind of letting somebody else go first and through our OBO would give us a chance to get smarter.
Our next question comes from Sameer Panjwani of Tudor, Pickering, Holt & Co.
Is the increased non-op activity in the Permian is that pushing more aggressive stand basin-wide. I'm trying to get trade that are done to have better control over company-specific spending and development?
Well, this is David, Sameer. I think that I would characterize it as it just provides for more opportunities to do that. I mean, there are times that we issue proposals to partners, or they issue proposals to us. And as part of that activity, you may discover, hey, we could swap out our interest in this section for your interest in that section, and it would -- it might result in a situation that both of us prefer from an operating standpoint. And when that's a mutual win-win for both of us, we're certainly be very willing to do that. And have done it many times and I compliment our land staff on the ability to recognize those situations and seek them out. So I think that we've done several trades, and we've done a lot of trades. But we've done a number that we've talked about that I think we felt like really added value for us, and I'm confident they did for the partners that we traded with. So I think we are pleased with the cooperation that we see and get, and are appreciative of the other companies that we work with and the relationships that we have, I think we're all trying to just improve our lives the best we can, and this is proven to be a good way. And I'm glad that the industry is very open to doing that sort of thing.
Okay. That make sense. I guess, it would be fair to say that the pace at which those opportunities are presenting themselves has accelerated?
I think that's probably fair because of the fact that activity has picked up. And as activity has picked up for everyone, then there's just more of these kind of proposals that are being issued. And when they are, that just opens up the opportunities.
Okay. Okay, great. And then on the midstream side, you guys are quickly approaching that $100 million EBITDA mark. It kind of feels like that's the point where, generally, it might be able to stand on its own 2 feet. Are there any incremental third-party opportunities available today? And how far away do you guys think you are from achieving the scale required to make a decision on the future of that business?
Well, I think that -- this is David again. I think that, first of all, sometimes the midstream guys think they already are standing on their own 2 feet. So they might push back with you a little bit there. But I know what you mean. But I think, look, we feel like that there continue to be a lot of midstream opportunities available to Matador and to San Mateo. San Mateo has done a great job of getting the infrastructure in place, both at Wolf and in the Rustler Breaks area and for all 3 streams, for natural gas, for oil, for water, drilling out 2 more saltwater disposal wells up there now as we speak. The oil infrastructure, gathering infrastructure is all in place. The trucking facility is all just about finished up. So that we're all ready when the Plains line arrives. And there's areas of our acreage: Antelope Ridge, Arrowhead, Ranger, where we're starting to talk about what might we want to do from a midstream basis in those areas as well. And then the areas where we are, there's always additional third-party opportunities. I mean, clearly, the significant agreement signed with another producer on the water side this year, I mean, this past quarter, was great. It's just terrific. But we have other agreements that are already in place. As Joe mentioned earlier, there's another, and we put in the release, there's another midstream company where we're going to be having the ability to purchase some of their gas and process that there at San Mateo. So that will add to the volumes there. And the guys are working on other deals all the time. So I think we're very optimistic. I'm pleased where we are, but very optimistic that we will continue to add to these third-party opportunities.
David, I think you made a very good point. And one of the things that I think is very advantageous is the footprint we now have in the basin with oil gathering, water gathering and disposal, gas gathering, processing, all these things are at a point now where, as the third-party opportunities present themselves, and those continue to grow and grow, it's pretty easy for us to add to these assets, for instance on the saltwater disposal system. We've got to the point where we've got a number of saltwater disposal wells, and there's more opportunities, more volumes come online. It's pretty easy to drill another well and add to that. Even on the gas plant, the gas processing plant we have at Rustler Breaks, if we get that thing full 260 million a day, we can easily add another train and just continue to build the business. So it's in a very nice place for growth.
Okay. That's really helpful. Last one for me, I'm just trying to understand with the second quarter production outperformance and the increase to the full year guidance, how much of that is coming from operations and how much of that is coming from the acquisitions?
It's coming almost entirely from operations. So the acquisitions are going to add round off area to what those numbers are.
Sameer, that's one of the things that we think distinguish Matador from many other companies out there. We haven't been acquiring really producing properties, all of our growth has almost all come organically from drilling of wells. And when you grow organically, you should have higher rates of return. When you have to grow by buying production and things like that, that may work out for you over time. But generally, you're likely to get a 10% rate of return, because there are a lot of competition. It turns in one way or another into a bidding auction. And the seller is going to do his best to get that rate of return as low as he can and be much less than what your drilling opportunities are. Now it's trickier to grow organically and with the drill bit, but our teams have met the challenge. You know that Matador started off with $6 million, and we're at the $4 billion level. And when we went public, we are making 400 barrels of oil a day, and now, it's 30,000 barrels of oil. So you got to give credit to our various teams, and that production we have comes out of 3 basins. We made good decisions in the Haynesville, in the Eagle Ford and now the Delaware. So I think that's one thing we'd like to be noted, that over the 15 years that we've had a very steady rate of return, we've done it organically, and that we put the money back in good decisions. And the outlook for us going forward, we think has never looked better. All areas of the company are doing very well, exceeding the expectations. The wells are exceeding expectations and the teams are really working well together. And a couple of things I don't think are fully recognized in the market, one is the growing value of the midstream. As you noted, they're really doing a good job in their areas. I don't know when it reaches critical mass. We're studying it, and we have a great partner there that has worked with us. And we're very pleased with the way that joint venture is going. Our minerals are growing in value, and that gives us further options there. And then the ongoing development plan that we have. We're not finished targeting our various zones or other zones, and our teams are building scale. So we like our chances going forward, and are very pleased with the opportunities we have above. We just enjoyed the 2 best quarters in company history. We like to think that momentum will continue and we invite all of you to come see us and see that the depth of Matador isn't just with the executive committee, but goes throughout the company, and we've got rising contributions from our young leaders here in each of the departments. So the outlook, I'd just like to say, looks very promising here. We've got a lot of hard work in front of us. We got to keep finding ways to improve. But I like our chances.
Ladies and gentlemen, this ends the Q&A portion of this morning's conference call. I would now like to turn the call over to management for any closing remarks.
Compliments of Sameer, I think I just did it. And if you want more, hit your rewind and do that again. But thank you all. We do appreciate your questions and comments. We do think it helps make us better, and we hope to see all of you soon and more to report in the near future.
Ladies and gentlemen, thank you for your participation today. This concludes the program. You may now disconnect.