Good morning, ladies and gentlemen. Welcome to the third quarter 2018 Matador Resources Company earnings conference call. My name is Daniel, and I'll be serving as the operator for today. At this time, all participants are in a listen-only mode. We will facilitate a question and answer session at the end of the company's remarks. As a reminder, this conference is being recorded for replay purposes, and the replay will be available on the company's website through December 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, Daniel. Good morning, everyone, and thank you for joining us for Matador's third 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.
Finally, in addition to our earnings press release issued yesterday, I'd like to remind everyone that you can find a short slide presentation summarizing the highlights of our third quarter 2018 earnings press release on our website on the Events and Presentations page under the Investor Relations tab. With that, I would now like to turn the call over to Mr. Joseph Foran, our Chairman and CEO. Joe?
Thank you, Matt. Good morning to everyone on the line, and thank you for participating in today's call. We appreciate your time and interest in Matador very much. Now I'd like to introduce the Executive Committee who's joining me this morning, along with other members of our management team and senior staff who are standing by for all 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; Brad Robinson, Executive Vice President, Reservoir Engineering and Chief Technology Officer. As outlined in our earnings release issued yesterday, the third quarter of 2018 was an outstanding and record quarter for us, which exceeded our original projections.
I want to take a moment and acknowledge the entire Matador staff for all their achievements and to note some groups in particular that really went above and beyond. First is midstream and marketing. They made a number of decisions on marketing, including fractionation and hedges, which have mitigated much of the differentials and transportation problems. Really appreciate what they've accomplished and the goals that they set, some ambitious goals in securing third-party contracts for some of our midstream facilities. They brought their plant, doubled the capacity of our Rustler Breaks plant on time, on budget, got the substation going, got the amine plant, and have turned in just a great performance. Also to our normal E&P new zones, reduced cost on drilling, some innovations in completions that have made a difference, some great land work. The whole group I want to commend.
Don't want to leave out what has been a very busy quarter for our financial group. They redid the bank agreement. They refinanced the bonds. They added to the bonds. They've got the agreement in place for our midstream. They just were relentless in getting all this done. As we kid around the office when we shout, "Auge," it goes off, they just get to work. Finally, our guys in the field who have kept up after the production to help us achieve these production results. They fought through rain, truck traffics, demand for services, of getting them out there to the wells, and we wouldn't have had this kind of record quarter if those guys hadn't given 110% throughout the period. It's been a total team effort, and I wouldn't feel right without mentioning them.
Want to thank the analysts today for their many kind words. Want to reassure all of you we're not letting up a bit on working hard to keep up this momentum. Let me turn it back to Daniel and the questions.
Thank you. Ladies and gentlemen, if you have a question at this time, please press the star, then the number one key on your touchtone telephone. If your question has been answered or you wish to remove yourself from the queue, please press the pound key. Again, that's star then one to ask a question. To prevent any background noise, we ask that you please place your line on mute once your question has been stated. Ladies and gentlemen, 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 a follow-up until all have had a chance to ask a question, after which we would welcome additional questions from you. Our first question is from Scott Hanold with RBC Capital Markets. Your line is now open.
Thanks. Morning, guys.
Good morning, Scott.
Joe, you were talking about the midstream asset and how that's progressing pretty nicely. I think in your press release, you talked about the gas processing plant being over 80% full with your recent contracts. Can you talk about where you want to take that midstream asset in 2019? Where do you really see the big opportunities to further development when you're looking across your acreage position?
Well, Scott, that's an ongoing question that we talk about nearly every day. Where do we want to go with this? What seems obvious to me is that we'll be close to capacity. Now you look at the feasibility of where you want to extend the reach of your gathering lines for water, oil, and gas. The first thing is locating probably some additional saltwater disposal wells in areas where you're going to have production. The most likely candidates there are some of the BLM acreage that we acquired, as well as our work to the north, which we think is underserved up there in the Northern Delaware. We're encouraged by our continuing movement north and the kind of results that we're getting there, we feel are steadily improving.
those areas make sense to begin with saltwater disposal, follow up with potentially pipelines to gather the gas and bring it into a central processing station. The third area is in the oil and further developing our strategic agreement with Plains, that in the future, you'll have more options on what markets you want to take to your oil. Layering that in that fashion. Matt or Gregg, would you add anything to that?
Yeah, Joe, I think you said it well. To me, Scott, what I think is really important is the success that the midstream team's had thus far with the plant being at 80% that you mentioned. We've got six saltwater disposal wells that will be drilled at Rustler Breaks. We've got three down at Wolf. Just what that does for us, I think it gives the foundation, where as you continue to add things, like Joe said, you add the sixth well at Rustler Breaks here at the end of this year. You're able to add an amine treater at the plant. You're able to get additional compression where you can build on these things, and it really takes the risk out of the midstream business as you tack things on, as you get bigger and bigger.
Adding another saltwater disposal well is not that big a deal, and you're usually adding that when you've got committed volumes going forward. The team's done a great job, and I think the opportunity-based analysis is what we're going to continue to look at, and just make sure that we're doing the right thing for both San Mateo and for Matador.
Understood. Thanks. As my follow-up, you also talked about production in 4Q being a little bit more flat, and it looks like it may be as a result of some drilling by some nearby producing wells with new ones. Can you give us some sense of what that impact for the quarter could be? How do we look at this as we go through 2019? Is it going to happen most quarters, but is there a point in time when, like in 4Q, it looks like it might be a little bit more?
Yeah. Hi, Scott. It's David. I think it just happens that this quarter just seems like it's a little bit higher than most. It happens all the time. We have wells shut in from time to time, but I think that this quarter looked like it was going to be just a little bit higher. If we're able to get through some of those completions a little more quickly and get the wells back online, which is what we always strive to do, then things might be a little better. We felt like looking at the forecast that it was just worth mentioning this time. Sometimes it's not only our wells that we're completing. It may be offsetting wells from other operators that are getting completed that cause us the need to shut in some of our recent completions too.
It was just one of those things that stuck out a little bit this quarter, and that's why we mentioned it, but it always happens.
Okay. Appreciate that. Thank you.
Thank you, Scott.
Thank you.
Before we go to the next question, I would like just to note the leaders of our marketing and midstream group, Greg and Matt. They've formed a great team together, where Greg primarily does the planning and Matt does the execution, and you can see the results, and want to thank them for their planning and their work with us on the executive committee on making sure it all rolls out smoothly. The operational effect that they've had in that we're flaring less than 1% of our gas production, because when we've been ready to turn the wells on. The coordination between them and production, they're waiting with the pipeline when production's ready to hand over. I don't want to omit, they're not just smart guys, they're hardworking guys.
Thank you. Our next question comes from Tim Rezvan of Oppenheimer. Your line is now open.
Good morning, folks. Thank you for taking my question. I'd like to start first on the balance sheet. I noticed that leverage has kind of ticked up a bit. I think people expected that with the acquisitions. You're now at about 2x, which is the highest level since 2016. Organically, leveraging is, I think most people see it as sort of modest in the next year. How are you thinking about leverage and managing that given commodity price volatility?
Tim, I may start off and then ask David to clean up. First, we're going at this, de-leveraging that balance sheet, kind of like we do land, just at a brick at a time. We've made a number of transactions that have put renewed emphasis after the BLM, and we've already retired somewhere in the neighborhood of $15 million. That doesn't sound like that much, but a brick at a time, making a deal on this property or that property. We're still open for, if we receive a serious offer on our Haynesville or Eagle Ford, we will give it serious consideration. Whether it's for a track or countywide or for the whole thing, the same way we're nibbling around the acreage and doing trades out in the Delaware. We're being careful about collecting our accounts receivable, all those little things, and it's added up.
In the, say, over the last month, picking up $15 million here, a brick at a time, and we'll continue to do that. You saw a big jump in our EBITDA this year from last year. We're pretty pleased with that trend. The E&P is working out pretty well for us, so we're keeping an eye on it for sure, but we are also continuing to address the matter and hope to provide you with further improvement as the year goes along and into 2019. David?
Joe, I think you summarized it well. I think that we finished the quarter at about 2.0, which I don't think is concerning. It is a little bit higher than we might have averaged, and I think, Tim, correctly you pointed out that it's the highest since the early part of 2016. We've always tried to keep things around that level, and as we look into next year, it may not go down that much, but don't expect it to go up very much either. I think it'll stay fairly constant, we believe, as we go through the next year, absent any kind of significant downturn in commodity price. Even at that, I don't think we feel like it would be at a level where there would be any alarm.
We certainly maintain, as Joe says, the ability to monetize some of our non-core assets. I think we never entirely take the need for if we need to issue equities on the road, we can. That's just not something we chose to do this time, but it's something we certainly can consider. We've also begun to put in some nicer hedges for 2019, and we'll continue to try to do that to protect the cash flows as well. I hope that helps.
Yeah, that does. I appreciate the context there. If I could have a follow-up and change topics back to San Mateo. In your Analyst Day earlier this year, you gave some kind of EBITDA parameters for the segment, $65 million-$75 million. I know there's a big ramp quarter-to-quarter. Can you talk about where you stand year-to-date, on sort of a high case of $75 million versus your base case? Specifically, you had talked about maybe a Q4 high case segment EBITDA of about $25 million, setting the stage for 2019. Just any color on how that EBITDA ramp is going at San Mateo. Thanks.
First of all, I think we believe the EBITDA ramp is going very well. I'm pretty sure I'm correct that the EBITDA number for San Mateo was around $17 million, maybe just a little above that in the third quarter. We're certainly headed in the right direction. I think that we will be close to the $25 million in the fourth quarter. I'm not sure if we'll quite get there, but I think we'll be in spitting distance of it. If we don't get there in Q4, we'll get there in Q1. I think that if anything, it might just be a matter of a little timing, I think. I feel quite confident that we'll hit that and probably exceed it by Q1.
Some of the oil gathering revenues that we were counting on toward the end of the year didn't come on quite as quickly as we had anticipated. That probably will end up being the biggest reason if we don't get to $25 million in the fourth quarter. We're still going to get awful close to it, Tim. I would say, for the year as a whole, we'll probably come out to somewhere probably in the middle of the $65 million-$75 million that we had anticipated for the year.
The other thing that I'd say, Tim, is when you look long-term out into 2019 beyond, the group has gotten the capacity. It's 80% of capacity out there on their gas processing. The same thing, they've secured some long-term third-party contracts that bode well and give stability to the cash flow. Everything is gone, everything is working, and everything's gone pretty much as they planned. The delays were not by us so much as some of the right of way issues that were provided that other people was in their area and really beyond their control. They've worked hard to get them done. You're days behind, but you're not months behind.
Sorry, David. I'll just underscore what David and Joe said. In regards to how we're handling the assets, we have the infrastructure in place for the oil gathering when we finally get the crude line up to us. We're ready to go there. In regards to the plant, we've got an electrical substation that was done on time, on budget, that gives us better quality, more reliable power for us to run the substation and also some of our saltwater disposal facilities. The amine treater that we've been talking about is on time, too, and what that's going to allow us to do at San Mateo is to process some small amounts of CO2 and H2S out of the gas, and also run that plant on full ethane recovery. At San Mateo, that's a great thing.
At Matador, that's even a better thing that we can recover as much of the ethane as possible. That will be done for the entire volumes for the plant. We have the NGL contract to back that up, so all those NGLs that are produced are guaranteed to be fractionated and transported. Feel really good about where that asset is right now.
One other thing, Tim, is I like to put things in proportion. In the first plant that we built down there in Wolf that we sold to EnLink, its capacity was about $30 million. Now we're up to $200 million up at Rustler Breaks, so that's six to seven times the capacity we'd had down there at Wolf. Things are looking promising, and we're considering a lot of options, including ultimately building a third train up at Rustler Breaks that would double the capacity from $200 million to perhaps something approaching $400 million. That's not guaranteed, but it's nice to be able to consider that is something that is possible, and those are nice projects to consider, is what I'm saying. That we got some good choices and some good optionality.
Okay. I appreciate all that color. Just given everything happening at Antelope Ridge, it seems like there's a lot of options on the midstream. I'll leave it there. Thanks for your time.
All right.
Thank you. Our next question comes from Gordon Douthat with Wells Fargo. Your line is now open.
Hey, good morning, everybody.
Hey, Gordon.
Gordon.
Hey. Just wanted to ask about Antelope Ridge, actually. With the well results you had there look pretty strong, obviously a good area. Just wanted to inquire about your completion designs there and see if you are doing anything different on that front relative to the other parts of the basin.
Yeah, Gordon, this is Matt. We are continuing to tweak our completion design. We have kind of settled in on proppant volumes and fluid volumes. We have been tinkering a bit with more slickwater designs. We have also been looking in pumping more and more regional sand. As we have talked about before, we took a pretty methodical approach to getting into that part of the business, but we are getting more and more comfortable with it. We are continuing to test different cluster spacing, and overall, just optimizing the completion design. The other thing that we have been doing, and it is not related to completions, is targeting. We have got seismic in the area, so we are able to utilize our MAXCOM operations to steer the wells better and find better zones to drill them in. Plus, it is just a good area with some great rock.
Okay. Then specific to that, your comment, Matt, on the seismic. Do you have that across your various areas, or is that something that could apply to other areas should you get that?
Yeah. Hi, Gordon, this is Matt Frost. We do have the seismic over Rustler Breaks and Antelope Ridge. We have some data in-house right now up in the Ranger area, and we are participating in a group shoot with Fairfield across pretty much the whole northern half of the Delaware Basin. Moving forward into 2019, we will have the bulk of our acreage under 3D in the Delaware Basin. Really, we have seen a lot of value out of that data so far, and I want to reiterate what Matt said, is we are seeing that the targeting with seismic and the identification of targets is really helping well results. I also left out that we do have coverage over our Jackson Trust asset and our Wolf asset, too. Increasingly, we are going to be folding that into our workflow.
Thank you, guys.
Thanks, Gordon.
Thank you. Our next question comes from Neal Dingmann with SunTrust. Your line is now open.
Do you hear me, guys?
Yeah. Now we do, Neal.
Hey, Joe, a question just for you and all the guys. You had such a, obviously, tremendous well there at that, setting the new record on that strong 1424 S. My question is that just continued improvement with your D&C, or was there anything sort of special to note on that one from a D&C side, or that caused that one to be so exceptionally good?
Hi, Neal, it's David. I think as Matt mentioned there, it's clearly a good area. It's good rock. I'd also like to compliment our geoscience team. I think that, again, to sort of what Matt said about the importance of targeting and to follow up on what Ned said about the use of the 3D. We thought we had chosen a good target in the Thorsness well, and clearly we had, because it was about a 3,000 BOE a day well, and we were kinda, as Joe likes to say, turning double back flips on that. The geoscience team I think really sort of adjusted the target just even a little bit on this well, and I think the other nice thing was we were able to really do a great job of staying precisely in that target for the entire length of the lateral.
We did a good job in the Thorsness, but this particular well was exceptionally good, I think. I think that's attributable a lot to the MAXCOM team, and the fact that we have that group downstairs working 24/7 to be sure that these wells are steered right where they need to be. I can't help but think that also made an impact on the quality of this well.
Yeah. I'd like to give a shout-out to our MAXCOMs. They go 24/7, seven days on, seven days off, they are staying in zone better. If you stay in zone an extra 100 feet or 10%, that adds to your reserves. It's a mix of geologists and engineers, they work together, the interdisciplinary, they've got televisions that go out in real time to the well with the directional drilling, this was Billy Goodwin's idea. Our head of operations that we think is really making a lot of contributions. They are. I have to admit, I had reservations at first because they wanted to use the room I was going to have as a boardroom. We didn't get the boardroom.
We got the MAXCOM room, they're saving money on every single well, they're adding net feet of pay because they're staying in zone.
Well, I think it's a perfect example of working together. We've got engineers sitting next to geologists shoulder to shoulder down there, they're not only working on the geosteering, they're working on drilling performance. You've got the advantage of having a geologist sitting next to a drilling engineer when they start talking about why it's drilling fast or why it's drilling slow. There may be a very good geological reason why things are happening. They're saving money and drilling a better well. That's about us.
Yeah. Neal, I'd just quickly say also that no matter where you put these wells, they still all got to get fracked, I think that the completions guys also just do a terrific job of getting all these stages pumped away successfully, that makes a big difference. They're constantly trying to innovate and improve on what we're doing out there. I think this was just a case where it all comes together, one thing I've always known is that fracking sometimes makes bad wells good, it always makes good wells great. This is one of those cases where I think it took a good well and made it great.
Great. A call out, guys. Just one follow-up. I think, Matt, and some of you guys were hitting on this earlier. Could you just talk about over in Antelope and then Stateline, just maybe in broad terms, how you see the infrastructure build-out sort of progressing, either not necessarily just the remainder of this year, but more for 2019, if you could?
Yeah, Neal, I think the advantage we have there is obviously the blockiness of that acreage and the number of wells we're going to be able to drill from a minimal number of surface locations. The team is, as we speak, they're actively putting all that together, finding out where they're going to put drilling pads, where they're going to have production pads, and how the internal infrastructure's going to look. At that point, we can decide what we want to do with those volumes, whether we want to tie into somebody locally or whether we want to do it with another midstream company, or whether we want to do it ourselves. It's a big enough thing that we're working on it right now, and not just gas, oil, and water, but also electricity.
I mean, we've been talking about the substation and getting electrical in on these blocks is going to be important too. That's ongoing, Neal, and it'll be a big part of our development plan.
Great. Thanks so much, guys.
Thanks, Neal.
Thank you. Our next question comes from Noel Parks with Coker & Palmer. Your line is now open.
Good morning.
Good morning, Noel.
I wanted to turn to the Eagle Ford, and I was interested in hearing as far as making a decision to put a rig back out there. What was it that sort of pulled you over the line in making that decision finally? The LLS premium staying in place, the service cost, day rates, other peers returning? I was also curious what well cost you were thinking, and also the working interest we might see from the 10 wells.
Okay. I'll start off and y'all pitch in. I'm not sure that we're all of exactly the same mind, but when we weighed those various considerations that you've mentioned, some of us gave them different weight. In the end, we were all of the consensus that this was the right thing to do. You had a differential, you took advantage of the little better oil price that you got. You were also validating, we didn't have a lot. Most of our acreage was HBP already, but with these wells, you'll get, I think, approximately 95%, and nothing else would have any expiration until 2020. We thought that was a positive thing, we also thought it was good to look at the economics, I'm pleased to say that the first well out of the box established a new record in time it took to drill.
I'll turn that over to Matt for further details.
Yeah, I think, Noel, it's a great story. When we came back and started drilling last year on our Eagle Ford acreage, we hit the ground running. We picked up a new Patterson rig and brought it down there and started drilling and drilled the fastest well we'd ever drilled on Martin Ranch. We picked up this Patterson rig. Again, it's one of their XK rigs, they're high-tech rigs that we like, and all seven of the rigs we have are these XK rigs, it's been really nice working with Patterson. Like Joe said, not only was the first well the fastest well we had drilled, the second well was just a few hours slower than that. The two fastest wells we've drilled in Eagle Ford were right out of the box with this new rig, very happy about all that.
The other thing I think we're anxious to do is just to complete these wells. One of the things that happened last year, we drilled these wells, we brought the completion technology that we advanced into Delaware and put them on these new Eagle Ford wells and did really well with those completions. We'll be completing the first ones here towards the end of the year and look forward to how those are going to turn out.
Neal, this is David. You asked the question about working interest. Actually, I can tell you that most all of these wells will be essentially 100% working interest for Matador. Probably on the cost, I imagine we're probably ±$5 million if we have a one-mile well, and probably in the order of maybe seven, eight, if we have a one-and-a-half, two-mile well. Some of these wells will be longer laterals. I think about six of the 10 will be longer laterals.
Okay, great. I also noticed in the press release you mentioned that the wells would primarily be targeting the Eagle Ford. Does that mean you'll be doing other targets as well, Austin Chalk or something else?
Yes, that is what that means. I think as we noted earlier when we announced the rig, we'll probably do one or two Austin Chalk tests. We've not actually done any tests of the Austin Chalk on our acreage, that's something that we do plan to do with a well or two. We think that certain of the areas are prospective for the Chalk, we're probably going to give that a shot here in this program.
Great. Thanks a lot.
Thank you. Our next question comes from Irene Haas with Imperial Capital. Your line is now open.
Yeah, hey. My question for you is really getting the oil and gas out of Delaware Basin can be pretty daunting and challenging. Understanding that you have a plant at Wolf and Rustler Breaks, which is going great. Elsewhere, I'm curious, when you try to secure a third-party gas processing, how difficult was it, and what did you do precisely to end up with just 1% gas flare, considering how tough things has been? Second question is really Mid-Cush differential. Looks like October is the worst. Any color?
Yeah, Irene, this is Matt. In regards to what we've got there at Rustler Breaks and at Wolf, you're right. We've got very good coverage on getting oil out, getting gas out, getting the gas processed, getting the NGLs out. We're rock solid there. What Gregg Krug and his marketing team have been able to do at Antelope Ridge and Ranger/Arrowhead and up in the Twin Lakes, they've been able to go out and secure firm capacity for our products. The discussion goes, Greg will call and say, "Hey, can we get this on firm?" They'll say, "Yes." It becomes a negotiation about price and term. Knocking on wood here, Irene, but so far we have not had much of an issue getting that done. That's how we severely limiting the number of MCF that we're flaring.
As Joe said earlier, the stuff at San Mateo, the stuff at Rustler Breaks and Wolf, we're at less than 1%, and we're in single digit percents on the other, and that's just time waiting to get interconnects, which is one of the beautiful things about being in the midstream business, that the E&P company walks down the hall and says to the midstream company, "We need to get hooked up," and they get us hooked up.
Yeah, this is Greg. Yeah, I'd like to add a little bit. Yeah, as far as any production that we've had curtailed, it may have only been just because of timing when it comes to hooking up the well. Had nothing to do with being curtailed on downstream markets. We've never been cut back from our markets, we feel really good about that.
Thank you. Our next question comes from Richard Tullis with Capital One Securities. Your line is now open.
Hey.
Hey, Richard.
Good morning, Joe. Congrats on a very nice quarter there. Two, I guess, bigger picture questions. We've seen at least three E&P industry transactions already this week, and those were all or mostly all stock deals. Joe and the rest of the team, how do you view the larger M&A landscape as we sit now? Should we look at it as a tougher environment to potentially monetize the Eagle Ford and Haynesville, but at the same time, maybe makes it a little easier for Matador if it chooses to do a bigger acquisition? How do you view the landscape right now, Joe?
Well, Richard, that's a great question, and it's another question we talk about almost every day in one way or the other. The guiding principle for us is that we realize we're a public company with a public trust, and we're going to play a straight game. Matador has shown that it's sold itself way back there in 2003. We sold a good part of our position to Chesapeake and the Haynesville in 2008, 2009. We sold our first processing plant to EnLink, and we sold part of our Rustler Breaks to Five Point. When a really serious offer comes in, we're going to give it serious consideration. We've said for some time, we're not a company that says we're a single-basin company, and we're going to reduce ourselves down to whatever basin is most important. Clearly, most important right now is the Delaware.
As you can see, being in several basins is shown to be good strategy in that diversification leads to more options. There are several companies that are talking about themselves now, the wisdom of being a multi-basin. To me, it doesn't matter so much whether you're a single basin or multi-basin. The point of it is to get into the best rock that you can with the best economics. That's what our primary focus is. At the same time, as I said, we play a straight game. If a company feels that something, that an asset that we have, whether it's midstream or oil or gas, is more important to them than to us, and they want to build, we're always ready to talk or trade or JV, whatever they think makes sense and would make sense to us.
Usually, the people that come in to try to buy say, "We're so sorry you're burdened with Haynesville. We'll buy it at PDP." Or, "Here, we don't want you to have to go down to South Texas, so we'll buy your Eagle Ford." They're trying to buy it on the cheap. That won't work, particularly with a company that has a strong balance sheet. That's one of the things that you have, is when you have that stronger balance sheet, you don't have to do things. We're very open to that, but it's got to be full value or to offer something better in trade. We're very open to that and want everybody to know that, look, we play a straight game here. When something makes sense, we'll pull the trigger on it.
I hope that answered your first part of your question, how do we feel about the M&A transactions and that. The second thing I would say is this is a group here that is the golden goose. For 35 years, Matador, either in its first iteration or the second one, has delivered about a 20% rate of return. These guys know how to work together. They've developed a methodology. As long as they can keep generating that, I see us continuing to move forward, because it's hard to earn that rate of return consistently and don't want to kill the golden goose, because I think these guys are getting better and better. Hope that you've continued to see since the day we went public how the improvement has been.
We've gone from 400 barrels a day to over 30,000 barrels a day. The consistency that this group has delivered. I think this is now the 17th straight quarter where we've met or beat industry consensus. We've grown primarily organically, almost all organically, virtually all organically. When you can do that, you should make a higher rate of return. When you grow by acquisition, naturally, that's generally a lower rate of return closer to 10%. I think it's made sense what we've done. I think our guys have been very careful about spending the money. Matt's is kind of a guiding principle. He articulated the guiding principle that we want to grow. We want profitable growth at a measured pace. The outspend, we've had some outspend, look at what we spent it for.
I think our shareholders have gotten full value and have greatly benefited from the outspend, because if you borrow it at 5% or five and five-eighths and get a 40% or 50% rate of return, I think that's good business. Everybody here really looks at the financial discipline, we don't get over our skis, we don't double our rig count. It goes up one rig when we know we've got it covered with good prospects. That's kind of that tension. We want to grow, we want it at that measured pace, we want it to be profitable. We want to watch the balance sheet, there are opportunities that come along, that if you don't take them, like bolt-on acreage in your tracks or to increase working interest, if you don't take them, you'll never have another chance to do it.
The same thing on midstream. These midstream opportunities, when we first did it, people questioned, "Why are you doing that?" You can now see the help that it's been operationally, financially, creating a presence. It's worked out every bit as they said it would. Improved takeaways, improved our hedging. I think your point is very well taken, when we view it all-in concept, I think the guys here have done a good job in growing Matador from the size when we went public, you remember how humble our beginnings were.
Today, we're still got a lot of room for improvement, but we're steadily making progress on that consistency and delivering now over 4 years of consistent returns that are. I'm touching wood, don't know how long it'll last, but it looks like it's very encouraging with these better than expected results. Our guys are just finding better ways to target, better ways to complete, and reducing the cost, as Matt explained, like with his MAXCOM program. I don't know where the end of that is, but each of the groups keep finding ways to improve. I'll rest my case on that, and as long as they keep telling me they can make further improvements, the executive group plans to be supportive of that. David?
Yeah, I think you summarized it well, Joe. I don't know that I would have anything to add to that. I think, as far as the M&A landscape goes and all, Richard, I think Joe's just right. We know we're officers in a public company, and if we should get an offer, we'll consider it, and we look for opportunities to improve our company all the time. But I think those transactions are difficult to do. Obviously, as you said, we've seen several of them get done this week.
Thank you for that, David and Joe. Appreciate your response. That's all from me. I'll leave it there. Thank you.
Well, thank you, and thanks for giving me the time to say all that.
Thank you. As a reminder, ladies and gentlemen, that's star then one to ask a question. Our next question comes from Daniel McSpirit with BMO Capital Markets. Your line is now open.
Thank you, folks. Good morning, thanks for fitting me in.
Hi, Dan.
I was hoping we could just hit on the company's reinvestment rate just a little more directly, a little harder here if we could. I think there's an expectation on free cash flow generation that's growing in the capital markets today. Those producers that can achieve this state may be able to separate themselves in what remains, as you know, is still a very crowded field of independents. Will the company be more explicit with respect to achieving a free cash flow neutral state when laying out its 2019 guide? Should an outspend still be expected given where the company sits in its life cycle?
Dan, I'm going to say something real short. Then I'm going to turn it over to David for further details. I'll tell you this, is that whenever outspend is discussed, I think it's vitally important to understand it isn't the outspend, just the outspend. There's two variables involved. How much you outspend in relation to your balance sheet, and second is what are you getting for it? If we weren't getting some really good results, we wouldn't be outspending or didn't have exceptional opportunities. Whatever we outspend is on a very select basis and really has to really fit in. That's the first thing. Second is, I'm very pleased we've got the kind of opportunities that you would want to do so.
Clearly, you've seen how we've grown in value, and I think we've made the right decision to go ahead. Having said that, this is a question we talk about, our board talks about, and we think we're doing the right thing. At some point, our opportunities won't be as robust as they are now, perhaps, and then you'd see that slow down. We are closing it in. It's narrowing on that, on the free cash flow. We're aiming for that to get things in better balance. I started with $270,000, so I've had to outspend the growth to get to this point and to grow to this point. It's something that we've practiced for a long time on a very select basis.
If you just spend the same money, that'd be like the two football teams that got to come in, and they've all got to. You can't run around the end. Everybody has to go up the middle, and you can't have anybody fast on your team, and you can't throw the ball but once. You know that's what this capital market is different people with different styles. You still got to be conservative, and we practice financial discipline. We've never had a layoff in 35 years, and I think we do that. It's a very select basis, and it's too variable. With that, let me turn it over to David and let him say how he thinks.
Sure. Yeah. Hi, Dan. It's David. Again, I think Joe did a nice job of summarizing it. I might just add with regard to your question about 2019. Certainly when we put out our guidance for 2019, which I would expect would be likely after the first of the year, we will discuss our plans and what we may have in the way of outspend. I think we would expect that there will be an outspend in 2019 with regarding your comments about life cycle, I think, or of the company or where we are in our life cycle. I think we feel like we're still at a scale that doesn't flatland itself yet to the best to the free cash flow model. The fact of the matter is, we could do it next year.
I think it'll be more a matter of choice because of some of the things that we've done recently, particularly in terms of adding the new acreage from the BLM acquisition into the portfolio. That's something we're going to want to get going on, and we're optimistic we'll be able to get going on that certainly by the fourth quarter of next year, maybe even a little earlier. If we can, we're going to get after that. I think that that'll also make a big difference in what we're able to do in the out years. I certainly would imagine that we'll see an outspend again next year, and it'll still be, I think, a couple of years before we'd be able to achieve that.
I might point out that as Joe said, I do think we've continued to narrow in on it every year on the E&P side. On the midstream side, depending on what we decided to do next year, again, we could also be spending within cash flow on the midstream side. We may decide to outspend that a little bit as well in order to expand our operations from the footprint that we currently have. Again, I think that we've demonstrated that those have been good investments and good uses of money that have created additional value for our shareholders. I hope that helps.
It does. I appreciate the well-rounded answers. I do. It helps in framing 2019 and periods beyond. Then just as a follow-up, just on 2019, David, what are the big challenges to putting up a more capital-efficient year, whether it's cost inflation or plateauing of productivity gains or other such variables?
Will you ask that again, Dan? I didn't quite get what you were asking me there.
Yeah. Just what are the challenges do you see next year to putting up a more capital efficient year, whether it's cost inflation or on the production side, just plateauing of productivity gains in the field?
Well, I think you probably hit on a couple of them. Certainly, although I'm pretty optimistic that we can continue to improve upon the profitability mix or the productivity mix in some ways just perhaps by the mix of wells that we drill. I certainly think as we go into the latter part of next year and into 2020, as we begin to fold some of this BLM acreage into the mix and work with some longer laterals, not only in our existing footprint but in that acreage, that actually our capital efficiency can improve. You always fighting the declines, and that's just a part of this business. As I look into next year and 2020, I really feel like we've spent a fair amount of time, Dan, in the last couple of years getting our footprint held by production.
The best way to do that in a lot of these areas was to focus on one-mile laterals because it allowed us to capture more of the acreage and get it held in a more efficient manner. Even doing that, I still think we've done pretty well with our well results and our productivity per lateral foot. Now that we have a lot of that behind us, I think we have now the luxury of being able to go back and kind of drill the next round of wells on those properties. Add a little bit longer laterals than we have, and we started doing that at Rustler Breaks. We're doing it at Wolf, and we put the rig up in Seven. We already are making plans to have longer laterals up in Seven.
When we get to the BLM acreage a year from now, we will be consistently drilling two and two and a half mile laterals on that acreage. I think that we actually have some pretty positive things to look forward to in terms of improving our capital efficiency over the next several years.
Superb. Appreciate it. Thank you, gentlemen. Have a great day.
Thank you.
Dan, before you sign off, I'd just like to add a little bit to what David was saying, is one of these capital efficiencies that I don't think is always recognized or appreciated is this brick-by-brick strategy that we have for adding acreage, as well as the brick-by-brick strategy that I mentioned on realizing more cash from our asset base, is that we acquired 25,000 acres, a little more than that. Our whole weighted average base of our 130,000 acres is $11,000. Yes, we bid strongly for the BLM because we considered that the best rock in the country. The brick-by-brick strategy gave that weighted average, where we're well below the weighted average cost that other producers have out there. The same thing, this little brick-by-brick, that we'll make a deal, little or small acreage trade, also favors.
Those are highly efficient capital transactions. While not big in any one instance, they add up. If you acquire 1,000, 1,500 acres a month, end of the year, you've acquired 15,000-20,000 acres. That can be quite expensive, our guys have done that on that brick-by-brick approach. The 11,000 an acre includes our mineral position. I think that's a highly efficient, but not necessarily fully appreciated effort. The same thing on our midstream, that's kind of been working with that has gotten us either cash or carries or further efficiencies, operating efficiencies by having that. That's an indirect efficiency, but it adds up to the bottom line of improving your overall. We call that our guerrilla campaign, so to speak, of getting out there and getting it one way or another.
When you start with $270,000, which in perspective is 1 frac stage, you learn all these ways to try to create additional capital, because you just don't have very much of it. That culture, I think, remains in Matador today. Billy and the drilling guys look for ways to work with the vendors to challenge them. We don't want to cut prices on you guys. We want you to show us how we can do things more efficiently. Our vendors have really stepped up and, whether it's Halliburton or Schlumberger or Patterson or Forrester, they've helped us, and I want to express my appreciation to Champions as well, that they, instead of coming in saying, "You got to lower your prices," they've helped us show us ways to use their services in a more capital efficient way. I just had to say that.
I couldn't restrain myself.
I appreciate the additional thoughts, Joe. Thanks again.
Oh.
Have a great day, gentlemen.
All right. Thanks, Dan.
Thank you. Our next question comes from Michael Scialla with Stifel. Your line is now open.
Yeah. Hi, good morning, everybody. Just want to ask a few questions on the Eagle Ford. Can you say where production is now? If you do all the 10 wells there, where you might expect that to go in the first half of 2019, and what the drilling inventory looks like there?
Well, as far as the latter part goes, we still, I think, have on our acreage position a couple hundred locations in the lower Eagle Ford that on various parts of the acreage that we think can still be drilled. Then, of course, as we've mentioned, we've always in the past, we've only tested the and only drilled into the lower part of the Eagle Ford. So we haven't tested the upper Eagle Ford or the Austin Chalk, some of the other areas down in South Texas that other operators have worked with, and which we think are also prospective on our acreage. That inventory could be higher. As far as the production goes, I think it was about 8% of our production this past quarter.
I think it was pretty close to 4,000 BOE a day, and it's about 2,400, I think, barrels of oil a day. I don't think we'd quite double from that, certainly not on the average. We'd probably get our rates up. With this 10-well program, they'll probably early on get up in the 6,000-8,000 BOE a day, I would imagine, from this program. Maybe even a little better. On average, I would expect it to, for 2019, our production might be 50% better out of the Eagle Ford as a result of this project.
Well, that's helpful. Thanks, David. Joe, wanted to ask on, you mentioned your 11,000 per acre average to date in the Delaware for acreage acquisitions. Do you have a number for. I know you got the BLM number out there, which is a big part of this year's, just wondered if you had a number handy for the, I believe it's 27,000 net acres you've added this year in the Delaware.
No, I don't, Mike. You just have to factor that into that overall number. Most of that other acreage from the BLM was done at lower levels, including a fair amount of mineral acreage that we acquired. I think our guys have done a real good job, and that has been a real capital efficient way for us to grow.
Agreed. Thank you.
Thank you. Our next question comes from Sameer Panjwani with Tudor, Pickering, Holt. Your line is now open.
Hey, guys. Good morning.
Hi, Sameer.
Hi.
One of the wells that we've been watching for is the Wolfcamp XY test at Arrowhead. Looks like it was completed this quarter, but not much detail in the press release. Is there any color you can provide on how things are looking there so far?
Yeah. Hi, Sameer. It's David. I would say that we would prefer not to provide any additional information on that well at this time. We have drilled and completed the well. We have some land work that we're doing up in that area right now. I think, until that's done, we'd prefer just to kind of remain silent on the results from that well. I think we're satisfied with how it's gone. Just because of we've got a couple of deals we're finishing work on, it'd probably be better that we just get that done before we report on the results.
We'd also like a little more data history.
That's right
before we come out. One thing you've probably noticed that we've moved to doing 90-day IPs to try to give you all. People didn't seem to like our instant IP, so we've tried to make it a practice of getting a little more data history before saying something. There can be great change in these wells, as you know. We are encouraged, I will say that, the results right today have been positive. We just want to be more confirming before we make an announcement and before we commit more capital to that area.
Okay. That's fair enough. Maybe on the Twin Lakes well. Did you guys do anything different here versus the initial wells that you've operated or in which you've had a non-op interest? Are there any intervals being tested by operators in the region outside of the Wolfcamp D and/or the B?
Yeah. This is David again, Sameer. With regard to the last question, I'm not aware that there's anything being tested. I mean, not in the Wolfcamp proper. In that area to the west, you've had people that have worked in the Abo and the Yeso, historically, there have been any number of different targets. We even tested the Strawn several years ago in the run-up to our first well over by the Culberson. That was the Olivine well. I think in the Wolfcamp proper, the answer, to the best of our knowledge anyway, is that it's either been the D or the B. I think that Continental is the first one that's tried the B out there. With regard to did we do anything different? I would say that we did target a little bit different interval than we had before.
We took a whole core on this well also, we did some additional geomechanical testing and not only for targeting, but also for helping us to select a zone that we thought might frack better than what we'd experienced in the previous well. I think that absolutely happened. The well treated much better, it's just started flowing back, and we just don't have a whole lot of results to talk about on it as yet. I think we should fairly soon.
Was there anything different on the completion front on that well?
Matt, you want to handle that?
This is Matt. Nothing real significant in terms of outside of what we're doing in other areas. I think one of the most important things that David said was we did find a target. We stayed in that target all along the way, and the completion guys spent a good deal of time looking at data, looking at the whole core, making sure that we had the right design, and it went off pretty well. I think it probably fracked actually better than the other well that we had drilled and better than some of the others drilled in the area. We did actually pump some resin-coated sand on the tail end.
We haven't, in the early stages of production here, we haven't flowed back sand . Like David said, it's just still a little early to tell.
Okay. That's helpful. Thank you.
Thank you. Our next question comes from Jeff Grant with Northland Capital Markets. Your line is now open.
Morning, guys. Thanks for fitting me in here.
You bet.
I'll leave it at one quick one here, hopefully. Just curious, given the results at Antelope, which continue to be really positive, is it fair to think that that's the likely bias for where that Eagle Ford rig goes when it wraps up over there? Are there any midstream facility related build-outs you guys maybe need to get ahead of before accelerating there? I guess, just building off that, are there any stack pad type tests or anything that you guys might be planning at Antelope Ridge as well?
Well, to that question, I say yes to all of them. The Antelope Ridge is certainly emerging as you get more data in. I mean, that's one of the things that's changed is, we're beginning to like having a little more data before we have to make a decision and, coming out too early can get you in trouble. The way it looks right now, as we get more and more data, it looks very encouraging. It's a little early to declare victory, but it looks good. The same point about the saltwater disposal. There's a process in getting permits out there that's not entirely your control. The state, the regulatory people have a say in how quickly you can get them. We first have to get them before we can drill them.
The exact order, that rig may drill some Antelope Ridge, go drill a saltwater disposal well or two, then come back to Antelope Ridge or vice versa. That's all part of the planning process. All things being equal, you drill your oil and gas wells at the first of the year and tend to drill your saltwater disposal at the end of the year because they won't have an effect on production. That's all up in the air, as we talk. Did that answer your question? David has something.
Yeah. I was just gonna say, Jeff, the only thing I would add is that, while we're-- I agree with Joe 100%, we're very excited by the way the Antelope Ridge area is testing out, and certainly, it's gonna compete well for that next rig or rigs before very long, especially with the additional BLM acreage that we acquired. I do want to also say that we've been pretty happy with the results we've seen recently up in Arrowhead. I'll point you back to the recent Stebbins wells and the second and third Bone Spring and the SST wells that we reported on last quarter. I will say that team is making a pretty strong statement for having another rig in that area as well.
Given the fact that we have a nice several-thousand-acre block right up there in that area, it is an area where we can go in and, I think, do some capital efficient drilling in terms of longer laterals and just leaving a rig parked right there in the same vicinity for a good period of time. That is something that we're seriously considering in making the rig allocation decision as well.
All right. Understood. It's a high-class problem, but I'll leave it there. Nice quarter, guys.
Thanks, Jeff.
Thank you. Our next question is from Tim Rezvan with Oppenheimer. Your line is now open.
I'm sorry, guys. I was hoping for color on Twin Lakes, and you gave some, so I'm all good here. Thanks.
Well, Tim, thank you. Come by and see us. That's something we'd like to invite all the listeners to, is come by to see us in person. I think we always gain from meeting you all in person and taking all your questions. The same thing, meeting with us and meeting some of these young staffers that we've been touting as guys who are really helping make a difference and adding value in a lot of different ways. That's an open invitation, and we'd really like to have you here, and we'll buy you lunch or breakfast or dinner or whatever suits you as a further incentive.
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.
As I said, please come see us. We'd like that. We'd like to get to know you better, too. With that, I'm off, and thank you again for the kind words many of you had. We're continuing to work just as hard as ever and look forward to reporting to you next quarter.
Ladies and gentlemen, thank you for your participation today. This concludes the program.