Good morning, ladies and gentlemen. Welcome to the second quarter 2019 Matador Resources Company earnings conference call. My name is Cherie, and I'll be serving as your operator for today. At this time, all participants are in a listen-only mode. We will facilitate a question and answer session at the end of the company's remarks. As a reminder, this conference is being recorded for replay purposes, and the replay will be available on the company's website through August 31, 2019, as discussed in the company's earnings press release issued yesterday. I would now like to turn the call over to Mr. Mac Schmitz, Capital Markets Coordinator for Matador. Mr. Schmitz, you may proceed.
Thank you, Cherie. Good morning, everyone, and thank you for joining us for Matador's second quarter 2019 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 quarterly report on Form 10-Q.
Finally, in addition to our earnings press release, I would like to remind everyone on the call that you can find a short slide presentation summarizing the highlights of our second quarter 2019 earnings release on our website on the Events and Presentations page under the Investor Relations tab. I would now like to turn the call over to Mr. Joe Foran, our Chairman and CEO. Joe?
Thank you, Mac, 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 feel this has been a very strong quarter for us, so we appreciate your attention. I'd also like to introduce the executive committee, who are the ones with the staff who are really responsible for these exceptional results. They are Matt Hairford, President; David Lancaster, Executive Vice President and Chief Financial Officer; Craig Adams, EVP and Chief Operating Officer, Land, Legal, and Administration; Billy Goodwin, EVP and Chief Operating Officer, Drilling, Completions, and Production; Van Singleton, EVP of Land; Brad Robinson, EVP of Reservoir Engineering and Chief Technology Officer; Gregg Krug, EVP of Marketing and Midstream Strategy.
As outlined in our earnings release issued yesterday, we are very pleased with the execution and operating performance during the first half of 2019. We had many financial and operational challenges, the staff really rose to the occasion, I wish to personally acknowledge the entire Matador staff for all their hard work and dedication. It sounds corny, it was truly a team effort the way everybody put in a little extra effort and applied their skills to achieving these results. Really, I wish I had all the words to express my appreciation the way everybody pitched in and worked together. I know that's corny, it is really fun to see the teams really working with each other to achieve these ends. Second, also would like to recognize Midstream.
They're certainly coming of age with our most recent project in San Mateo II, as well as continuing to achieve stellar results in San Mateo I. In particular, we've done now, San Mateo II represents our fourth midstream project. All have come in on time, on budget. I'm pleased to say this most recent one is working right now on track to be on time, on budget too. We have a great partner there with Five Point and appreciate their help and cooperation in getting us to this point and look forward to reporting more on midstream in the next quarter.
Finally, at the beginning of the year, it was clear the market was interested in what kind of efficiencies were each company going to have because that was, I would say, the number 1 theme when we were on the road is what kind of efficiency are you achieving? I think these results reflect the increasing capital efficiency that we're joining as reflected that we were able to drill more wells but actually bring in CapEx that was less than projected or in the budget. There was, again, a lot of cooperation. One good example is working with Halliburton on the sand, using local sand helped bring down cost without apparent degradation to our production or reserves.
At the same time, part of the team effort was Patterson working with us on rig efficiency and upgrading some of our rigs to the three pumps and the top drive. Really appreciate the way they worked with us. The same thing on operational, the cooperation between our midstream and production groups, so that when those wells are ready to come online, midstream was waiting there with the pipe, and we're pleased with the services we've been able to render to other third parties and give them the same type of efficiency. Finally, just within the organization, I thought there was really a special effort by all the groups to work within our discipline, the geologists and the engineers, and the various teams that we have, the operational, and just everything clicked.
It happened this time, doesn't mean it happens next time unless we get busy and get to work. Really appreciate also all the kind words that we received from you for the efforts this quarter, and please know we're going to continue to try to get better this next quarter, the next half of the year, and into 2020. We like our chances. With that, like to open the call to questions.
Thank you. Ladies and gentlemen, if you have a question at this time, please press the star, then one key on your touch tone telephone. Due to time constraints, we ask that you please limit yourself to one question and one follow-up. Again, we ask that you please limit yourself to one question and one follow-up until all have had a chance to ask a question. After which, we would welcome any additional questions from you. Our first question comes from Scott Hanold with RBC Capital Markets.
Guys.
Hi, Scott.
Hey, Scott.
Hey, Scott.
Hey. Seeing CapEx where it was this quarter was very good. Well below expectations. Can you give us some quantifications on some of the savings you're seeing and where we could ultimately, maybe a look through of where you were at the end of 2019, where we are today, but where could we be as we enter 2020? I don't know if there's a relative figure like dollar per foot completed or an average well cost of a typical lateral length, or if you can give us some context of how that's progressed to today and where we expect it to go in 2020.
Hey, Scott, it's David. I think that we had put out in the investor deck last quarter or so, a slide that had talked to how we thought that 2019 could go in terms of our ability to improve our capital efficiency. I think that we had said that on a dollar per foot basis, as I recall, that we thought that would be down 13% or 14% over the course of this year. So far, I think we're probably a little bit ahead of that this year. I think that that had projected we'd be down another 10%-12% again next year. Of course, that assumed that there wasn't any inflation in service costs, that those would remain flat because we were trying to give an idea of what our own capital efficiencies could be.
I think that we're probably running a little ahead of our expectations, and I give a lot of credit, of course, to the operations group for their abilities to do that. I think that's been accomplished both on the drilling side and probably in particular on the stimulation side as well. It's been a really good effort to this point in the year. I do think it's important to note that a lot of what we've done in the first half of the year hasn't been as much associated with the longer laterals, although it probably was in the Eagle Ford. In the Delaware, while we do some longer laterals at Wolf, we're just, I think, still in the beginning stages of that.
As we go through the second half of the year, we'll see that a little more, and then, of course, as we go into 2020, think that will even kick up more. I think we're pretty optimistic that as that transition happens, we'll continue to make progress in terms of dollars per foot.
Okay. No, that's good to hear. Appreciate that. Shifting to the midstream for my follow-up question, on San Mateo, it looks like you all elected to spend a little bit more to accommodate growing third-party potential there. Could you give us a sense as you look into 2020 and maybe even 2021, where do you think that based on your own expectations of growth for Matador and what you're seeing in third-party volumes, how much spend is needed to continue to enhance that investment?
Scott, this is Matt. It's a good question. I think the way I'll answer that, it just depends on the opportunities. We have a really good handle on what Matador is going to do. We know what expansion we need to do on the current assets. The third parties, it's been a good thing. As we're talking about increasing the CapEx for the back half of the year, that's been demand related. The thing that we take a lot of comfort in is that we have the base asset, we've got the gas processing there in Eddy County. We've got the s altwater disposal facilities. We're looking at completing our 10th saltwater disposal well, so we got a really nice footprint to expand on.
That's the way I think about that. Just getting back to capital efficiency, this deal we've got with Five Point for San Mateo II, we do have the carry that we'll continue to get on the first $250 million of build out of San Mateo II.
Okay. Thanks for that.
Thank you. Our next question comes from John Freeman with Raymond James.
Good morning, guys.
Hey, John.
Hey, John.
Just following up on Scott's questions on San Mateo. I'm just trying to see if we could get maybe a little bit more detail on the breakout of the additional expenditures, because you mentioned in addition to sort of these additional projects that y'all are going to be working on, you also entered into an agreement to make a few sort of commercial SWD well permits, some acres that was sort of more acquisition oriented, just sort of maybe the composition of that?
Hi, John, it's David. I think I would be correct in saying it was probably about half and half, I think, in terms of probably the additional CapEx. We thought a special opportunity come up to be able to acquire an existing commercial well and facility up in what we call the Greater Stebbins area. That was something that we were probably going to drill anyway. There was also some surface acreage associated with that, and we're working to get that finished up. That was a particularly, I think, good opportunity for us and I think for the seller as well. That worked out well.
Of course, because the fact that the midstream business development team, I think, is just doing such a good job in terms of securing additional commitments and finding other third-party customers that we just made the decision that we wanted to pick up that business. It requires sometimes building out a little extra pipe to get to them or putting on a little extra compression on our system to do it. I think that's what we were trying to convey.
That's very helpful. In addition to the completed well cost improvements y'all have seen, you had a pretty nice decrease in LOE that y'all mentioned was a good bit driven by the lower saltwater disposal cost as you had more of those volumes that got moved from truck to pipe. As I just sort of try to think about maybe the additional sort of running room you have on improving the costs on that front, could you give me kind of rough numbers what percentage of your saltwater is now on pipe versus truck?
John, the answer to that on the Rustler Breaks side, we've got San Mateo over there, so we've got almost all our water is on pipe there with the goal to get to close to 100% or get to 100%. Over in Lea County, where we've just recently began adding these volumes on pipe, we're probably at about 80% or so, maybe a little better of the volumes. Towards the end of the year, we're projecting that we're going to get again closer to the 90% or 95% on that. The team's done a really nice job. As we talk about LOE, there's just a couple of things I want to point out, John. Number one, you want these cost savings to be sustainable, and we feel like absolutely on the saltwater disposal side, that is.
I mean, when you get those volumes off trucks and on the pipe, that's for the duration of the contract. We're very happy about that. The other component of this that we mentioned is workover costs. The team has done a really nice job in reducing workover cost. In addition to that, we've got a task force that's actually looking at ways to mitigate even having to do workovers. A lot of it ties back to artificial lift and how you install the artificial lift and how you make longer run times on ESP, better gas lift operations. The team's really focused on not only doing better execution on these workovers, but also eliminating a lot of them.
That's great. Congratulations on a really nice quarter, guys.
Thanks, John.
Thanks, John.
Thank you. Our next question comes from Neal Dingmann with SunTrust.
Morning, guys. It's nice to be able to tell somebody nice quarter these days. Congrats, guys.
Hey, Neal.
Hi, Neal.
Hi. My question is on your slide. There seems to be a lot of talk these days, even more so than ever about on slide nine. You guys always do a great job breaking that out into different plays. Just maybe if you could talk spacing a little bit. Matt, Joe, or David, any of the guys. You haven't changed this now in a while. Where I'm getting at is there's some investors now seem to question parts of that in the Permian, I'm just wondering if you could maybe talk about your spacing assumptions and going forward, how you still have belief in that.
Yeah. Hi, Neal. It's David. I think that our spacing assumptions remain pretty well unchanged. We, I think, have been pretty consistent in saying that our inventory, for the most part, was based on 160-acre spacing and that the wells that we drill are fairly consistently at that kind of spacing. We do have some locations in zones that are particularly thick, like maybe the Wolfcamp B, where we've identified two or three different landing targets, where we've kind of spaced things on a kind of a wine rack 80. Again, at any one plane or in any one sort of stratigraphic location, we're still at 160 acres apart. I think we feel like that serves us well to this point.
Clearly, in our non-op program, we've had the opportunities, at times, to participate at a fairly small working interest in some of the closer spacing tests that some of the other operators have done. Certainly, we are very interested in doing so. I think one thing that we've always said here at Matador is that we reserve the right to get smarter. So we're always trying to figure out what the optimal way is to do things. At this point, I think we'll probably continue. You probably remember there were several years ago when we drilled a few wells a little closer to that and weren't particularly satisfied with the results. Some of our Eagle Ford experience, I think, had made us a little more cautious coming into the Delaware.
For all those reasons, I think that we've pretty well continued, regardless of the stratigraphic interval, to keep ourselves spaced at least 160 acres.
This is Matt. Just to add on to what David's saying there. We do reserve the right to get smarter, and one of the things that we have the pleasure of doing is participating into non-op wells that have closer spacing than what we would be comfortable drilling. It's nice to be able to participate in those wells for a single-digit percentage and be able to get the data and see how those react, whether it's a wine rack spacing or maybe even something closer than that.
No, that's great to hear. Maybe if I hit the other hot topic just on GOR, it seems you've held in better than some others. Again, David, for you or Matt or the guys, just how you see that as far as when I'm looking sort of, I don't know, west to east from your Rustler Breaks and maybe all the way down to some of the newer BLM. Maybe if you could just comment if you have any thoughts of change in the GOR or what you're thinking about it these days.
I think generally speaking, Neal, it's been pretty clear that different areas of the basin just have different gas cuts associated with them. We've talked about that a lot and been pretty transparent about it all along. Even sometimes different stratigraphic intervals within a particular asset area have different gas cuts. You look at Antelope Ridge, it seems like most of our wells tend to come in the low 80s over there in terms of oil cut. You look down at Wolf, things are more like 60%-65%. You go up to Rustler Breaks, from the Wolfcamp B, those may be 30%-40%, you get up into the Wolfcamp XY, it's 75% or more. You go up into the Antelope Ridge area, some of those wells are 90%+ . It's never been just one thing.
I think it seems to be fairly consistent when I think we have a pretty good idea of when we drill some of these wells, what to expect in terms of the oil and gas cuts from the particular wells. One thing I always remember when we talk about this is several years ago when Ned and the geologic team did one of the coolest things I thought that I'd ever seen at that time was they went out and got a bunch of cuttings, and did some geochemical analysis, and brought a chart in, and basically spread it on the table and said, "Now, when we drill these wells at Antelope Ridge, these ones at the bottom are going to be gassier. As we go up, it's going to get progressively oilier." That's exactly what happened.
That's exactly what it was, and I just always had to give them a ton of credit for the really good science that went in long before we actually stuck the first drill bit in the ground. I hope that's helpful, but again, it's just an area where things just change across the basin, and I think we've adapted to all of them.
Yeah, Neal.
No, that's helpful. Go ahead .
This is Brad. To add t o what David said, and because you mentioned the BLM specifically, and that acreage is in more or less the deepest part of the basin. As you get deeper, the pressure gets higher, which is a good thing because it adds more energy to drive the oil out, and with that comes more gas in the oil. We do expect to see different GORs around the basin, as David mentioned. That can be a real good thing in terms of driving the oil out of the rock.
Very good. Thanks so much, guys.
Thank you. Our next question comes from Sameer Panjwani with Tudor, Pickering, Holt.
Hey, guys. Good morning.
Hi, Sameer.
I know it's still a bit early to talk about 2020, but just given the continued capital efficiency improvements you've seen both on the well cost side and cycle times, along with the potentially negative oil macro backdrop going into next year, could you just share your updated thoughts on activity levels heading into next year, and also how you think about the strategic goals for capital allocation?
Well, Sameer, let me take the first shot at it, and Matt, David, and others can chime in and give their perspective too. The very f irst part is we're just getting started on these various efficiencies that I mentioned earlier, particularly the capital efficiency. We're very early on coming to realize, they're on the plans, and we are taking more and more advantage of them, but we're just really getting started on the rig efficiency of drilling the 2 mi, the longer laterals. Otherwise, I mentioned several other ways we're increasing the effectiveness of here, the working together of the various groups, the rigs.
We're going to continue that. We see that as a big part of the future of Matador and the industry is continuing to improve on efficiencies, drilling the wells faster, trying to frack them faster, the pad drilling, all those sort of things are becoming more and more commonplace, and we're trying to stay with that trend and make it happen. The next thing I was to point out on 2020 is we're making do with 6 rigs and not 7 rigs. The market for a long time seemed to be very worried about us adding a seventh rig.
We try to do what we say we were going to do, and so we didn't want to say we were definitely taking a rig, or we definitely weren't taking a rig until we could see more clearly what the lay of the land was. It's now clear that we don't need it to reach our targets. We drilled some wells faster. We've been reaching our targets with less. They give credit to the operation group and Billy's people. We're not going there, and hopefully you and others are now more comfortable with the 2020 outlook, that that isn't going to be necessary. We won't say we won't add at some point in the future, a seventh rig, but just don't see any need for it in the foreseeable future or on the horizon. Have I left something out, Sameer? Matt?
Yeah, Joe, just to build on what you're saying there, I think, Sameer, one of the real nice things that's happened this year and going on into 2020 are these efficiencies. We feel like we were talking about adding a seventh rig. Billy and his team have done so good with six rigs. We're getting more and more things done with that. As you talk about Matador and how we think about things, we put a lot of value on optionality, and we talk about it just about every quarter. We're going to maintain that optionality with our rigs. We've got three rigs on longer term contracts. We've got three rigs that are shorter term contracts with our agreement with Halliburton on the frack pricing. We've got a lot of optionality in that.
Just as we talk about going into 2020, where we're indicating 85% and 90% of these laterals that are going to be a 1.5 mi or 2 mi, the operations team has done a really nice job in preparing for that. We've got Patterson rigs. We're very happy with our Patterson rigs. We're very happy with the upgrades that we've made to these same rigs. In anticipation of drilling 2-mi laterals, more and more 2-mi laterals, and even at the state line, 2.5 mi laterals, Billy and his team have gone and had some modifications done to the high-tech rigs we already have and adding a third mud pump.
I'll ask him to speak about this here in just a second. Higher torque top drives and our guys, our drilling engineers on these bits, they just continue to push the envelope, and we just go faster and faster and faster. Billy, you might want to talk about the add-ons to the rigs.
Okay. Hey, Sameer. This is Billy Goodwin. Like everyone's been saying, we stepped into the 1.5 mi then 2-mi laterals, and that's given us time on the drilling and completion side to look at different techniques and different equipment and get ready for going to 80% 2-mi laterals next year. In doing so, we found things that really worked for us and helped us get more efficient. Some of the things we've seen that really look good and helpful for us is having the three pumps and high torque top drive, and we think we can get things done a lot better there, shave more days off, and get a lot quicker on that end.
The guys, the engineers working in the MAXCOM room with the geologists, while we're doing it, we're staying in target on a lot of these wells 100% of the time and in the preferred target 90% of the time. We keep getting better there too as well. We're getting better, faster, saving on the CapEx and drilling better wells at the same time. We look forward to continuing with that. Also, since we started up the MAXCOM room, we've set approximately 50 records since we started that last year. It's been a great deal for us.
Yeah, I'd just like to add a little bit to what Billy said, is 50 records. It's not just in one category, but it's across the whole drilling spectrum and all around our properties around the basin. It isn't just in one area with one set of engineers, but it's across all areas, all across activity. Also, this MAXCOM room, would invite everybody to come see it because I think you have to see it to appreciate it, to fully appreciate it. It runs 24/7. One of the things that we have in there, one of the attributes of it, is that you have both engineers and geologists in there working together 24/7. They have a rotation where they're not always working nights or always days, that's at cooperation, they're learning from each other.
You take young engineers, young geologists, and there's a great exchange, and you're not waking people up at night, and taking those delays, because as fast as you're drilling, you could be several hundred feet. They're making decisions. They're learning how to work together to make decisions and to, what Billy says, stay in zone, not just in zone, but in preferred part, usually within a horizon. Some parts of that horizon are better than others, and being able to stay in zone and track it in real time has really delivered an advantage to us. It takes a lot of extra work on Billy's part and Ned's part to organize and schedule those people. Austin Wright and Steve Rogers have all contributed, Clark Collier, and that's been a big boost.
It's taken a little bit of that extra work that I mentioned earlier, and Matt and David and I are real proud of it.
Yeah, we really are, Sameer. Just to continue on that line of discussion, to get to the point where you've got the 1.5 mi- 2.5 mi laterals, there's a lot of work that has to happen on the land and legal side. And those guys have done a really nice job in making trades and putting joint operating agreements together and working with other operators and putting it together. That's why you see the hockey stick for us on the number of longer laterals to go from 9% last year to 90% next year. It's because of a lot of very hard and effective land and legal work, too.
That's really great color. I really appreciate the comprehensive answer there. I guess, onto my second question. On the minerals side of things, looks like you remain active in continuing to acquire interest in building the portfolio. I'm just wondering if you've started to look at the ideal structure for that business towards making a determination of whether you'd like to keep it internally to further enhance your economics and capital efficiency, or if it could be a source of proceeds at some point down the road.
Sameer, I would say your thinking is a lot like ours. We talk about it nearly every day. We just don't know yet which is the best route to go, it depends on a number of variables. It's actively studied, and almost on a regular basis, we're invoking a right to get smarter and move this direction or that direction to try to get to what we think is the optimal situation. We think we have some valuable assets there that can enhance the company's value. We're just not sure which one will deliver the most value over the long term. We don't want to do something short term. We want it to be long term, sustainable, and something that enhances what we're already doing. We're making progress, just still early in the process.
Okay, fair enough. Thank you.
Thank you.
Thank you. Our next question comes from Irene Haas with Imperial Capital.
Hello. I just want to congratulate you guys on hitting and exceeding your goals quarter after quarter, 24/7, especially against a really challenging macro. It is really quite an achievement.
Thank you, Irene.
Thanks, Irene.
My question, actually, if David can give me a little update on the performance incentive that you have for San Mateo I and II for 2019 and 2020. Do you have a schedule for that?
I think, as you know, Irene, we earned the performance incentive in 2018, in 2017 and 2018 from Five Point. Those were both paid in the first quarter of 2018 and then the first quarter of 2019. The $14.7 million in San Mateo I incentives were paid. The company anticipates that it's on track to earn the 2019 incentives, which would be paid in the first quarter of 2020 with regard to San Mateo I. That would be another $14.7 if we're successful, and as we expect to be. If you look at the San Mateo II incentives, they're a little bit different. They're drilling based. They require us to drill certain wells. I believe there's a threshold of about 20 wells that we drill before those incentives begin to kick in.
It may be toward the end of 2020 or early in 2021 before we begin to realize those incentives. Those will actually be paid on a quarterly basis. I would think that we'd probably estimate by the first quarter of 2021 for sure that we would be in a period of time in which we would be earning some of those incentives each quarter going forward until they were exhausted.
Great. If you don't mind, one quick question is that you did some divestiture during this quarter, and I think earlier you said you expect to sell about $50 million roughly. Should we expect some more divestiture in the second half? Also, your 2019 guidance, is that net of divestiture? That's all I have.
Well, with regard to what we'll be able to get done in the second half of the year, certainly, we're optimistic that we'll be able to do some additional deals. I think the land guys have been very proactive in the first half of the year in terms of making some of these deals happen. We're certainly optimistic that we'll be able to do some more in the second half of the year. Usually, Irene, in terms of our forecast, we typically assume that it belongs to us until we know different. At this point, our guidance would include any of those volumes that potentially could be divested over the second half of the year. I don't know exactly what those are. Until we do, until that's more definite, they would be included.
Thank you so much.
Thank you. Our next question comes from Jeff Grampp with Northland Capital.
Morning, guys.
Hey, Jeff.
Hey, Jeff.
Was curious, first off on the operational side, these Rodney Robinson wells that you guys referred to in the release on the Western Antelope Ridge, can you guys just give us a sense, strategically, how you're approaching those six wells in terms of the zones that you plan to do? You mentioned two, three well pads. Is the plan to complete all six before flowing any back, or would you do three and three, just hoping to get a little bit more color on your approach there?
Yeah. I believe that, Jeff, I'm correct, that first of all, we do plan to, assuming the approval and the receipt of the permits from the BLM, we will plan to move a couple of rigs onto the Rodney Robinson tracts. We plan to drill three wells with each rig initially. It'll be a six-well package. I believe I'm correct that there'll be some completions in the Bone Spring and some completions in the Wolfcamp. We'll drill three separate stratigraphic intervals with each rig. Yes, all six wells will get drilled before we begin completion operations. They'll all be then completed before we turn any of them to sales.
Right now, if we're able to stay on track and get started on them early in the fall, then we would anticipate that probably first production would come from them, I would say, probably late in the first quarter of 2020.
All right. Great. Appreciate those details. Quick follow-up just on the land side, you guys mentioned doing some acreage trades around the Stebbins area. Obviously had that nice Wolfcamp well that you guys updated us on. Can you guys give us a sense with the recent trades, how sizable of a block is that for you all, and can you remind us the average NRI? If I recall, it was a little bit above the standard 75%.
Yeah, I think I'm correct that it's in the 2,500, 3,000 acre sort of range currently. We have, I think, hopefully the potential to continue to improve that, but I think that's where we are right now. There will be multiple drilling targets that we'll have there. There's at least immediately a couple of second and third, the Second Bone Spring, the Third Bone Spring, and the Wolfcamp AXY. I would imagine the team will have other targets that they want to complete there as time goes on.
The other thing, too, is that because of the good land work that's gone on, it's really sort of taken a nice block for us that maybe a year ago or 18 months ago at this time, we were thinking was gonna be mostly 1-mi laterals, and it's turned it into a project that is going to be pretty much 1.5 mi and 2-mi laterals going forward. We've just begun drilling our first 2-mi laterals in the Bone Spring, second Bone Spring there. We have our first Wolfcamp AXY longer laterals scheduled there, getting going before the end of the year. A lot to look forward to, I think, in that particular block, and it's one where I think we feel like that we can keep a rig going for quite some time as we develop it out.
Jeff, if I can jump in here just a little bit, is that on the land work, is again, it's our practice, we want to do deals, but we want to do deals that build relationships so that these are win-win deals. To get some of this acreage, we had to give up some of our favorite tracts. As you know from the wells that have been released here in Eufaula, I've been naming, since these are state and local tracts, after a number of our early shareholders. As satisfied or pleased you may be by a trade that allows you to do longer lateral, when you call up the person whose tract was traded and tell them that we're not gonna be drilling his well anytime soon, that he's been traded to XYZ company in order to block something up, I've gotten a little pushback.
If you see some names moved around the basin like that. I know how major league players feel when they get called in and told they're traded, and these guys have kidded me about that. It's really an encouraging sign in the industry to have increased cooperation on sharing retention ponds or cooperate with information or on these trades. The real aim of it is to help make a win-win deal and build the relationship. We hope to keep that up, and sure, we think those are all healthy trends and will help us all do better to get to 2 mi, that when that happens, both sides win.
Yeah, I think too, Joe. By the way, Jeff, this is Matt. One of the other things that we've been talking about is just related to efficiency. It's putting this block together where we've got a rig we can just park there. It's drilling 1.5 mi and 2-mi laterals. The other thing that a block this size allows you to do in regards to parent-child relationships is you can just march your way down through the asset. Instead of having years where you come back and drill a subsequent well, you're looking at weeks or months. It's a very efficient way to develop a large block like that.
Yeah, very good point, Matt. Joe, to your point, nothing wrong with a nice sacrifice bunt once in a while.
Well, yeah, I'm going to use that because one friend, Kevin Grevey, was a professional basketball player from and I called him up. His designated well got traded two or three times. He says, "It's okay. You understand it." The Warriors traded him to the Milwaukee Bucks. I mean, the Bullets traded him to the Bucks. He said he's used to it. Not all have been. There's a good atmosphere out there. When at times like this happen, the service providers and everybody else are looking for some strategic relationships and efforts. They're open to ideas that help everyone. As tough as it is sometimes on prices or pipelines, it's good that everybody seems to be of a greater degree of cooperation.
Every cloud has a silver lining, and we appreciate the way that's happening and appreciate the way our staff is meeting some of these challenges. I don't want to go on, but overall, the trends are a net positive.
Yep. No. 100% agree and appreciate all the thoughts and the time, guys.
Thanks, Joe.
Thank you.
Thank you. Our next question comes from Tim Rezvan with Oppenheimer.
Hi. Good morning, folks. Thanks for taking my question. I wanted to circle back to San Mateo quickly. I noticed the strong 2Q results. You had 9% sequential EBITDA growth. The guide for 2019 of $90 million looks increasingly attainable, then you have additional projects in the works. How should we think about, from a modeling point of view, earnings growth for that segment? Is that 9% ramp an attainable level, or has growth been more lumpy as projects get tied in? How do we think about longer-term growth there?
Tim, I'm going to say something, but I think Matt and Dave will have some thoughts. I just don't think we have enough data points to draw a real firm bold line on how much growth is going to occur. I think there are scenarios where it could be less or it could be more. I just think we need a few more data points before staking our reputation. We want to do what we say we're gonna do, and I just don't think we know yet. Matt?
Yeah, no, I completely agree with that. Tim, it's been a great quarter. First quarter was good, second quarter is even better. As we move forward, at San Mateo, you want a balance of your anchor tenant, which is Matador. You've got great visibility into what they're going to do, and particularly for us, I'm proud to say we do what we say we're gonna do. You really have your finger on that pulse. The third-party stuff is a little more difficult. People can start and stop, and there can be commitments that you think are coming on Monday and they don't show up till Wednesday or maybe months down the line. There's a lot more, I hesitate to use the word ambiguity, but there is more of a.
Degrees of freedom, per se.
There you go. Degrees of freedom. Thank you, David. That's exactly right. It's good news. I think the quarter we've had is great, and it's indicative of a lot of hard work for the San Mateo guys, and they're continuing to, as we say, push on that rock.
Dave?
Yeah, I don't really have a lot to add, Tim. I think that we continue to feel good about the guidance that we've given to the year. I think things are progressing as we would have thought. I'd be reluctant to say it's going to be up 9% every quarter per se. Nevertheless, I think it was a very strong quarter for San Mateo, highlighted not only by some nice increases in third-party revenues. A shout-out to that team too. They did some nice work on their op costs too during the quarter, and they definitely made some improvements there, and it showed up in the bottom line this quarter. We're hopeful that we can see that continue. I think they just had a particularly nice quarter.
Matt, and I'm not trying to put words in your mouth, but I think we all see, based on what you've been talking about, that the $90 million is we're increasingly confident will be attainable.
Thanks, Joe. This is Matt Spicer. Matt Hairford hit the nail on the head. I think we've got a really nice mix of blue-chip quality customers out there, and we have a really nice mix of contracts. Some of them are firm, some of them have interruptible agreements. When some of that interruptible stuff shows up, it looks real nice, and sometimes it doesn't. We have to be careful on what we're going to estimate, but I think we had a great quarter.
Okay. Thanks for the details. Just as a follow-up, you provided longer-term performance on the Stebbins well up in Arrowhead. We've seen strong well results from that area and Ranger, but in a tough market to really add capital for delineation. How do you think over the medium term about proving up the value of that acreage? If you're running six rigs, is there the opportunity that you could possibly allocate more capital up to the north to really prove up that resource?
Yes, Tim, all that you say is true and possible, and it's just how you put the jigsaw puzzle together. One aspect I'd really like to stress is that we keep track of how much we spend on each well and how much revenue we get. There's a little bit of counterintuitiveness that you make more money about drilling wells in this low-cost environment than you do when oil sometimes is $100 a barrel. The reason for that is that 25% of the revenue generally goes to the royalty owner and another 5%-10% to the governments for severance tax and others. When you save $1 in cost, that goes all the way to the bottom line.
When prices go up to 100, costs go up, and there's a balance there that you want to keep going, keep your groups and teams together and getting better with new technology and new areas. You don't want to go too fast or too slow. We feel we're on a good pace. We're gaining efficiency on the drilling and on the whole processes. Yes, you could allocate more up there, that you'd make money if you did, but we're making money on these other areas, and there are just a lot of variables that make it more of a calculus than a single variable deal. You got to take a lot into consideration. Matt?
No, I agree, Joe. I think that you get a nice mix like what you said, Tim, on this Stebbins well, the Wolfcamp well. We've been talking for quite some time now that we're going to just keep moving Wolfcamp farther north and farther north and farther north, and we've done that, and you're able to do that while mixing in these second and third Bone Spring wells that have a great rate of return. As we learn more and more about these reservoirs, the delineation becomes a little bit easier, I guess, is what I should say.
I might just add one comment on that, Tim. I do think that, I mean, a lot of that acreage that we have up there, not all, but a lot of it came through our merger with HEYCO a number of years ago. A lot of it is HBP, which is positive. In addition, I think the teams are really doing a very nice job now up in that area of using this time also to, now that we understand it a little bit better, to really, again, reformulate units and do trades and things like we've done in Stebbins. Some of that's going on in other places too, to try to reformulate these units into longer laterals because I think we feel like that's going to be very important to the, not only development there, but all across our acreage position.
I know there's a lot of good work going on up there and taking this time to get that in place.
Well, and again, following up, among all the variables, one is just the notion that, yeah, we'd like to be hitting away for doubles, triples, and homers all the time, but occasionally, as Jeff said earlier in the conference, you got to sometimes lay down a sacrifice bunt or a bunt single to confirm the delineation process and to give geology time to process new information on wells and the 3D seismic that we have. Last year was a hard decision, with all the concern about capital spending, that we authorized paying a pretty good sum of money for a 3D seismic that would've been easy to abstain from, but it's been a good move. Ned recommended it, we honored his request, and he's made it paid off.
There's still more work to do, so there's a little timing incorporating this new information and this new data into our overall understanding of these areas. That's, again, just an example that generally it's a more complex decision than first appears as you start taking everything into account.
Sure. That all makes sense. Thanks for the details, folks.
Well, thanks, Tim.
Thank you. Our final question will come from Gabe Daoud with Cowen.
Hey, good morning, Joe, David, Matt, everyone. Thanks for squeezing me in. Just a quick one back to 2020. I guess if we're thinking about a flat rate program into next year, how should we think about the impact on capital relative to 2019?
Go ahead.
Let me be real quick and then jump in there. Gabe, just because we're keeping the rigs flat doesn't mean we're keeping the amount of footage drilled flat, is that that's just the big point that Billy and his group have achieved, is they've drilled more footage with the same number of rigs. That's partly the rigs getting better equipped, the crews understanding these areas better, and our guys finding ways to save a hour here, a hour there, new technology in the form of bits. These things all combined that we give Billy a hard time. He came in and said he was just going to get the same amount of footage with the same amount of rigs. He's built up high expectations for us, we think we can achieve that.
The other thing is that as you move in and you're able to get a higher percentage of your working interest, then you increase your recoveries even with the same number of rigs. The final note is that as you move to from 30%, I think this year, as we're expecting 2 mi, to 80% or 90% next year, you're going to have a big boost in recoveries because you're going to be able to drill a 2-mi lateral faster and have better recovery. I just wanted to try to put that in perspective and then turn it to my good friend and colleague, David, for the patient touch.
Yeah. Obviously, Joe, in this case, I don't believe I can improve upon your answer. I'll decline to. I think you said what I would have said, and probably better. There we go.
Let's get that on a recording. Document it. I think you want to document it.
Yes. I think it is recorded.
Gabe, I hope that helped.
Hey, Joe. Yeah. No, that's helpful. Okay, I guess that's it for me, guys. Well, thanks a lot.
Thanks a lot, Gabe.
Thank you, Gabe.
Thank you, ladies and gentlemen. This ends the Q&A portion of this morning's conference call. I'd like to turn the call over to management for any closing remarks.
Thank you. The biggest closing remarks that I have is to invite all of you on the call to come by and see us sometime, large or small shareholder, or even prospective, is come by. We'd like to meet you in person. We'd like to show you around to the MAXCOM room, and I think you can see what a difference that makes, and meet a few of the management and some of the staff that are really doing such a good job making things happen. Our business is complex enough that we feel it's not so much grand strategy, but execution and making the train run on time. We'd enjoy having you come by and meet everybody in person, and hope that you all will take us up on that. The light's always on, so to speak. Come see us.
Thank you for your time and attention. One last big shout-out to the staff and to the executive team. It's really been a neat time, and we appreciate all the many kind words that you all have had, and we think our best years and quarters and months are still ahead of us. Thanks, and come see us.
Ladies and gentlemen, thank you for your participation in today's call. This concludes the program. You may all disconnect, and have a wonderful day.