Matador Resources Co (MTDR) 2018 Q3 法說會逐字稿

Good morning, ladies and gentlemen. Welcome to the third-quarter 2018 Matador Resources Company earnings conference call. My name is Daniel and I will be serving as the operator for today. (Operator Instructions).

As a reminder, this conference is being recorded for replay purposes and the replay will be available on the Company's website through 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 would 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. And with that I would like to turn the call over to Mr. Joe Foran, our Chairman and CEO. Joe?

Thank you, Mac, and good morning to everyone on the line and thank you for participating in today's call. We appreciate your time and interest in Matador very much. Now I would like to introduce the executive committee who is 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. And 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 a just a great performance. Also to our normal [E&P] new zones, reduced cost on drilling, some innovations and completions that have made a difference, some great land work. The whole group I want to commend.

Also 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 an agreement in place for our midstream and they just were relentless in getting all this done. And, as we kid around the office when we shout ahooga, ahooga goes off, they just get to work.

And finally, our guys in the field, you know, who have kept after the production to help us achieve these production results. And they fought through rain, truck traffic, 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.

And so, it's been a total team effort and I wouldn't feel right without mentioning them. And I also want to thank the analysts today for their many kind words. But want to reassure all of you we are not letting up a bit on working hard to keep up this momentum. So let me turn it back to Daniel and the questions.

(Operator Instructions). Scott Hanold, RBC Capital Markets.

Joe, you were talking about the midstream asset and how that's progressing pretty nicely. And 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 look across your acreage position?

Scott, that's an ongoing question that we talk about literally every day. Where do we want to go with this? And what seems obvious to me is that we will be close to capacity, so now you look at the feasibility of where you want to extend the reach of your gathering lines for water, oil and gas.

And the first thing is locating probably some additional saltwater disposal wells in areas where you're going to have production. And 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. And we are encouraged by our continuing movement North and the kind of results we are getting there we feel are steadily improving.

And so, those areas makes sense to begin with saltwater disposal, follow-up with potentially pipelines to gather the gas and bring it into a central processing statement -- station. And the third area is in the oil and further developing our strategic agreement with Plains so that in the future you will have more options on what markets you want to take to your oil. So, kind of layering that in in kind of that fashion, Matt or Gregg, would you add anything to that?

Yes, Joe, I think you said it well. To me, Scott, what I think is really important is the success that the midstream team has had thus far. With the plant being at 80% that you mentioned, we have got six saltwater disposal wells that will be drilled at Rustler Breaks. We've got three down at Wolf.

And just what that does for us I think it gets 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 are usually adding that when you've got committed volumes going forward. So the team has done a great job and I think the opportunity base 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.

Thanks. And as my follow-up, you also talked about production in 4Q being a little bit more flat. And it looked like that maybe 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? And is this something that -- 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 looked like it might be a little bit more?

Yes, 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 this quarter was just -- looked like it was going to be just a little bit higher. If were 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.

But I just felt like looking -- we felt like looking at the forecast that it was just worth mentioning this time. And sometimes it's not only our wells that we are completing; it may be offsetting wells from other operators that are getting completed that cause us to need to shut in some of our recent completions too. So, it was just one of those things that kind of stuck out a little bit this quarter and that's why we mentioned it, but it always happens.

Before we go to the next question I would like just to note the leaders of our marketing and midstream group, Gregg and Matt, they've formed a great team together and where Gregg primarily does the planning and Matt does the execution. And you can see the results and want to thank them for the planning and their work with us on the executive committee on making sure it all rolls out smoothly.

And the operational effect that they've had and that we are 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 are waiting with a pipeline when production is ready to hand over. So I don't want to admit -- they're not just smart guys; they are hard-working guys.

Tim Rezvan, Oppenheimer.

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 are now at about 2 times, which is kind of the highest level since 2016. And organic deleveraging is -- I think most people see it as 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 bat clean up. But first, we are going at this deleveraging that balance sheet kind of like we do land, just 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 some of (technical difficulty) 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. And we are 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 tract or countywide or for the whole thing, the same way we are nibbling around the acreage and doing trades out in the Delaware, we are collecting -- being careful about collecting our accounts receivable -- all those little things and it's added up.

So in the -- say over the last month picked up $15 million here a brick at a time and we'll continue to do that. We also see -- you saw a big jump in our EBITDA this year from last year and we are pretty pleased with that trend. The E&P is working out pretty well for us, so we are 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?

Yes, 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. But we've always tried to keep things around that level. And as we look into next year, we don't -- it may not go down that much, but don't expect it to go up very much either.

So I think it will stay fairly constant, we believe, as we go through the next year, absent any kind of significant downturn in commodity price. And 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 and I think we never entirely take the need for -- to -- if we need to issue equity down 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 will continue to try to do that to protect the cash flows as well. So, I hope that helps.

Yes, that does, it does. I appreciate the context there. And if I could have a follow-up and change topics back to San Mateo. On your Analyst Day earlier this year you gave some kind of EBITDA parameters for the segment, $65 million to $75 million, and I know there's a big ramp quarter to quarter.

Can you talk about where you stand year to date on sort of the high case of $75 million versus your base case? And specifically, you had talked about maybe a 4Q high case segment EBITDA of about $25 million setting the stage for 2019. So just any color on how that EBITDA ramp is going at San Mateo. Thanks.

Yes, sure. Well, 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. And so, we are 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 we'll quite get there, but I think we will be in spitting distance of it. And if we don't get there in Q4 we will get there in Q1. So, I think that, if anything, it might just be a matter of a little timing. I think that -- I feel quite confident that we will be in that range; we will hit that and probably exceed it by Q1.

Some of the old gathering revenues that we were counting on towards the end of the year didn't come on quite as quickly as we had anticipated. And that probably will end up being the biggest reason if we don't get to $25 million in the fourth quarter. But we are still going to get awful close to it, Tim. And I would say for the year as a whole we will probably come out to somewhere probably in the middle of the $65 million to $75 million that we had anticipated for the year.

The other thing I'd say, Tim, is when you look long-term out into 2019 and 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 third -- long-term third-party contracts that bode well and give stability to the cash flow.

And so, everything has gone -- everything is working and everything has gone pretty much as they planned. And the delays were not by us so much as some of the right of way issues that were belonging to -- provided that other people was in their area and really beyond their control. But they've worked hard to get them done so you are days behind, but you're not months behind.

(Multiple speakers), Matt, Sorry.

Sorry, David. I'll just underscore what David and Joe said, in regards to how we are handling the assets, we have the infrastructure in place for the oil gathering when we finally get the crude line up to it, so we are 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 more 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.

So 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. So that will be done for the entire volumes for the plant. And we have the NGL contract to back that up. So all those NGLs that are produced are guaranteed to be fractionated and transported. So feel really good about where that asset is right now.

And 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, capacity was about 30 million. Now we are up to 200 million up at Rustler Breaks, so that is 6 to 7 times the capacity we had down there at Wolf.

And things are looking promising and we are 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 that is something that is possible and -- those are nice projects to consider is what I'm saying. We've 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. So I will leave it there. Thanks for your time.

Gordon Douthat, Wells Fargo.

Just wanted to ask about Antelope Ridge actually. The well results you have there look pretty strong. Obviously a good area. But 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.

Gordon, this is Matt. We are continuing to tweak our completion design. We've kind of settled in on profit volumes and fluid volumes. We have been tinkering a bit with more slick water designs. We've also been looking and pumping more and more regional sand. As we've 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 just overall just optimizing the completion design. The other thing that we've been doing that's not related to completions is targeting. We've got seismic in the area so we are able to utilize our max time operations to steer the wells better and find better zones to drill them in. And plus it's just a good area with some great rock.

Okay. And 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?

Hi, Gordon, this is Ned 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.

So, moving forward into 2019 we will have the bulk of our acreage under 3-D in the Delaware basin. And really we've seen a lot of value out of that data so far and I want to reiterate what Matt said. We are seeing the targeting of 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. So increasingly we are going to be folding that into our workflow.

Neal Dingmann, SunTrust.

A question just for you and all the guys. You had such an obviously tremendous well there setting a new record on that strong 1424S. My question is, is that just continued improvement with your D&C or was there anything 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. But I'd also like to complement our geoscience team. I think that, again, to what Matt said about the importance of targeting and to follow up on what Ned said about the use of the 3-D, 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 kind of, as Joe likes to say, turning double backflips on that.

But 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. And I think that's attributable a lot to the Maxcom team and the fact that we had group downstairs working 24x7 to be sure that these wells are steered right where they need to be. And I can't help but think that that also made an impact on the quality of this well.

I would like to give a shout out to our Maxcoms. They go 24x7, seven days on, seven days off. And they are staying in zone better. So, if you stay in the zone an extra 100 feet or 10% that adds to your reserves. And it's a mix of geologists and engineers and they work together, interdisciplinary, and they've got televisions that go out in real time to the well with the directional drilling.

And this was Billy Goodwin's idea, our Head of Operations, that we think is really making a lot of contributions. They are -- and I have to admit, I had reservations at first because they wanted to use the room I was going to have as a Board room. And so we didn't get the Board room; we got the Maxcom room. But they're saving money on every single well and they are adding net fee to pay because they are staying in zone. And so --.

I think it's a perfect example of working together. We've got engineers sitting next to geologists shoulder to shoulder down there. And they are not only working on geo-steering but they're working on drilling performance. So you've got the advantage of having geologists sitting next to drilling engineers when they start talking about why it's drilling faster, why it's drilling slow. There may be a very good geological reason why things are happening. So they are saving money and drilling better wells. So that's not us.

And Neal, I'd just quickly say also that no matter where you put these wells, they've still all got to get fracked. And I think that the completion guys also just do a terrific job of getting all these stages pumped away, pumped away successfully and it makes a big difference.

They are constantly trying to innovate and improve on what we are doing out there. And I think this was just a case where it all comes together. And one thing I've always known is that fracking makes -- fracking sometimes makes bad wells good, but it always makes good wells great. And so, this is one of those cases where I think it took a good well and made it great.

Great color, guys, and then just one follow-up. I think, Matt, some of you guys were hitting on this earlier. Can you just talk about over in Antelope and then Stateline just maybe in broad terms how you see the infrastructure buildout progressing? Not necessarily the remainder of this year but more for 2019 if you could.

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. So the team is -- as we speak they are actively putting all that together, finding out where they are going to put drilling pads, where they are going to have production pads and how the infrastructure, the internal infrastructure is going to look.

And 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 one of -- another midstream company or whether we want to do it ourselves.

So, it's a big enough thing that we are working on it right now and not just gas, oil and water but also electricity. We've been talking about the substation and getting electrical in on these blocks is going to be important too. So, that's ongoing, Neal, and it will be a big part of our development plan.

Noel Parks, Coker & Palmer.

Good morning. 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 pulled you over the line in making that decision finally? The LLS premium staying in place, service costs, day rates, other peer's returns? And also curious what well cost and you were thinking -- and also working interest we might see from the 10 wells?

Okay, I'll start off and you all pitch in. And I'm not sure that we are all of exactly the same mind, but when we weighted those various considerations you mentioned, some of us gave them different weight. But in the end we were all of the consensus that this was the right thing to do. You had a differential so you took advantage of a little better oil price that you got.

You are also validating -- we didn't have a lot. Most of our acreage was HBP already, but with these wells you will get to, I think, approximately 95% and nothing else would have any exploration until 2020. So we thought that was a positive thing. And we also thought it was good to look at the economics. And I'm pleased to say that the first well out-of-the-box established a new record in time it took to drill. And I'll turn that over to Matt for further details.

Yes, 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 Patterson rig, 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 Riggs, their high-tech rigs that we like and all seven of the Riggs we have are these XK rigs.

So it has been really nice working with Patterson. And 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. So the two fastest wells we drilled in the Eagle Ford were right out-of-the-box with this new rig. So very happy about all that.

The other thing I think we are anxious to do is just to complete these wells. One of the things that happened last year when we drilled these wells, we bought the completion technology that we advanced in the Delaware and put them on these new Eagle Ford wells and did really, really well with those completions. So we will be completing the first ones here towards the end of the year and we look forward to how those are going to turn out.

You asked a question about working interest and I can tell you that almost all of these wells will be essentially 100% working interest for Matador. Probably on the cost, I imagine we are probably plus or minus $5 million if we have a 1-mile well and probably in the order of maybe $7 million, $8 million if we have a 1.5-, 2-mile well. And some of these wells will be longer -- will be longer laterals. So I think about six of the 10 will be longer laterals.

Okay, great. And 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, and so 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 and so we are probably going to give that a shot here in this program.

Irene Haas, Imperial Capital.

So my question for you is really getting the oil and gas out of Delaware basin can be pretty daunting and challenging, understanding you have a plant at Wolf and Rustler Breaks, which is going great. Elsewhere I am kind of 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 have been? And then the second question is really Mid-Cush differential. It looks like October is the worst. Any color?

In regards to what we've got there at Rustler Breaks and at Wolf, you are right. We've got very good coverage on getting oil out, getting gas out, getting the gas processed, getting the NGLs out. We are rock solid there. And what Gregg Krug and his marketing team have been able to do at Antelope Ridge and Ranger, Arrowhead and up into Twin Lakes, they've been able to go out and secure firm capacity for our products.

And the discussion kind of goes, Gregg will call and say, hey, can we get this on firm? And they will say, yes, and then it becomes a negotiation about price and term. So, knocking on wood here, Irene, but so far we have not had much of an issue getting that done. And that's how we are severely limiting the number of MCF that we are flaring.

As Joe said earlier, the stuff at San Mateo, up at Rustler Breaks and Wolf is less than 1% and we are in single-digit percent 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.

Yes, this is Gregg and, yes, I'd like to add a little bit. 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. It had nothing to do with being curtailed on downstream markets. We've never been cut back from our markets. So, we feel really good about that.

Richard Tullis, Capital One Securities.

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 are mostly all stock deals. Joe and the rest of the team, how do you view of the larger M&A landscape as we sit now?

And should we look at it as a tougher environment to potentially monetize the Eagle Ford and Haynesville? But at the same time maybe it makes it a little easier for Matador if it chooses to do a bigger acquisition? How do you view the landscape right now, Joe?

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 are a public company with a public trust and we're going to play a straight game. Matador has shown that it sold itself way back there in 2003. We sold a good part of our position to Chesapeake in the Haynesville in 2008/2009. We sold our first processing plant to EnLink and we sold part of our Rustler Breaks to Five Point.

So, when a really serious offer comes in we're going to give it serious consideration. And we have said for some time we're not a company that says we are a single basin company and we are going to reduce ourselves down to whatever basin is most important. Clearly the most important right now is the Delaware. But as you can see, being in several basins has shown to be good strategy in that that diversification leads to more options.

There are several companies that are talking about themselves now the wisdom of being a multi-basin. So I don't -- to me it doesn't matter so much whether you are a single basin or multi-basin; the point of it is to get into the best rock you can with the best economics and 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 is midstream or oil or gas, is more important to them, to us, and they want to -- they will -- we're always ready to talk or trade, JV, whatever they think makes sense and would make sense to us.

Usually the people that come in to try to buy say we are so sorry you are burdened with Haynesville, we will buy at PDP. Or here we don't want you to have to go down to South Texas, so we will buy your Eagle Ford and they're trying to buy it on the cheap. That won't work, typically with a company that has a strong balance sheet. And 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 are very open to that, but it's got to be full value or to offer something better in trade. But we're very open to that and want everybody to know that, look, we play a straight game here. And when something makes sense we will pull the trigger on it. Now I hope that answered the first part of your question, how do we feel about the M&A transactions in 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 and you know as long as they can keep generating that I see us continuing to move forward.

And 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, and 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. And the consistency that this group has delivered -- I think this is now the 17th straight quarter where we've met or beat industry consensus.

So, I think -- and we've grown primarily organically, almost all organically, virtually all organically. And then when you can do that you should make a higher rate of return when you roll the acquisition, naturally that's generally a lower rate of return, closer to 10%. So I think it's made sense what we've done. I think our guys have been very careful about spending the money.

Matt, as kind of a guiding principle, he articulated the guiding principle that we want to grow -- we want profitable growth at a measured pace. And the outspend, we've had some outspend. But 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 5.625% and get a 40% to 50% rate of return, I think that's good business.

But yet everybody here really looks at the financial discipline, so we don't get over our skis. And we don't double our rig count, it goes up one rig when we know we've got it covered with good prospects. So that's kind of that tension we want to grow, but we want it at that measured pace and we want it to be profitable.

And we want to watch the balance sheet, but 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 then you'll never have another chance to do it and the same thing on midstream.

These midstream opportunities, when we first did it people questioned why are you doing that. And you can now see the help that it's been operationally, financially, creating a presence and it's worked out every bit as I said it would -- improved takeaways, improved our hedging. And so, I think your point is very, very well taken and that 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 and today we have still got a lot of room for improvement, but we are steadily making progress on that consistency in delivering now over 40 years of consistent returns that are -- and I'm touching wood, don't know how long it will 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. It's -- I don't know where the end of that is, but each of the groups keep finding ways to improve. So I'll rest my case on that and, as long as they keep telling me they can make further improvements, we will -- the executive group plans to be supportive of that. David?

Yes, I think you summarized it well, Joe. I do 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 is just right. We know we are officers in a public company and if we should get an offer we will consider it. And we look for opportunities to improve our Company all the time. But I think those transactions are difficult to do, but obviously, as you said, we've seen several of them get done this week.

Thank you for that, David and Joe. Appreciate your response and that's all from me. I will leave it there. Thank you.

Well, thank you and thanks for giving me the time to say all that.

(Operator Instructions). Dan McSpirit, BMO Capital Markets.

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 was 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, 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? Or should an outspend still be expected given where the Company sits in its lifecycle?

Dan, I'm going to say something real short and then I'm going to turn it over to David for further detail. But I'd 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 are two variables involved: how much do you outspend in relation to your balance sheet; and second is what are you getting for it?

And if we weren't getting some really good results we wouldn't be out spending or didn't have exceptional opportunities. So, whatever we outspend is on a very select basis and really has to really fit in, that's the first thing. And second is I'm very pleased we've got the kind of opportunities that you would want to do so. And 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 are doing the right thing. At some point our opportunities won't be as robust as they are now perhaps, and then you would see that slow down. And we are closing it in, it is narrowing on that -- on the free cash flow. We are aiming for that to get things in better balance.

But I started with $270,000, so I've had to outspend to grow to get to this point. And -- to grow to this point. So, it's something with practiced for a long time on a very select basis. But if you just spend the same money, that would be like two football teams who have got to come in and they have all got to -- you can't run around in; 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.

No, you know that's what this capital market is and different people with different styles. But you've 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. So, it's a very select basis and it is two variables. So with that, let me turn it over to David and let him say how he thinks.

Sure. 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 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 regard to your comments about lifecycle, I think -- of the Company or where we are in our lifecycle, I think we feel like we are still at a scale that doesn't quite lend itself yet to the best of the free cash flow model. But the fact of the matter is we could do it next year.

I think it will 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 is something we are going to want to get going on. And we are optimistic will be able to get going on that certainly by the fourth quarter of next year, maybe even a little earlier. And if we can we are going to get after that. And I think that will also make a big difference in what we are able to do in the out years.

But I certainly would imagine that we will see an outspend again next year and it will still be, I think, a couple years before we'd be able to achieve that. I might point out that, as Joe said, I do think we've continued to narrowing 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. But 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. So I hope that helps.

It does. I appreciate the well-rounded answers. I do; it helps in framing 2019 and periods beyond. And 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 is cost inflation or plateauing productivity gains or other such variables?

Ask that again, Dan. I didn't quite get what you were asking me there.

What are the challenges that you see next year to putting up a more capital efficient year, whether it is cost inflation or on the production side, just plateauing of productivity gains in the field?

I think you probably hit on a couple of them. Certainly although I am a pretty optimistic that we can continue to improve upon the profitability or the productivity mix in some ways just perhaps by the mix of wells that we drill.

And 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.

So you certainly have -- you always fatten the declines and that's just a part of this business. But 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 years getting our footprint held by production. And the best way to do that in a lot of these areas was to focus on 1-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. But now that we have a lot of that behind us, I think we have now the luxury of being able to go back and drill the next round of wells on those properties at a little bit longer laterals than we have when we started doing that at Rustler Breaks. We are doing it at Wolf and we put the rig up in Stebbins.

We're already making plans to have longer laterals up in Stebbins. When we get to the BLM acreage a year from now we will be consistently drilling 2- and 2.5-mile laterals on that acreage. And so, I think 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.

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 bought last year 25,000 -- we acquired 25,000 acres, a little more than that. And our whole weighted average base of our 130,000 acres is $11,000.

So yes, we bid strongly for the BLM because we consider that the best rock in the country. But the brick-by-brick strategy gave that weighted average where we are well below the weighted average costs that other producers have out there. The same thing, this little brick by brick, it will make a deal little or small acreage trade also favors those are highly efficient capital transactions, while not big any one instance they add up.

If you acquired 1,000-1,500 acres a month end of the year you've acquired 15,000 to 20,000 acres that can be quite expensive, but our guys have done that on that brick-by-brick approach. And the $11,000 an acre includes our mineral position.

So I think that's kind of a highly efficient but not necessarily fully appreciated effort and the same thing on our midstream. That's kind of been -- working with that has gotten us either cash or carries or -- and further efficiencies, operating efficiencies by having that. So that's an indirect efficiency but it adds up to the bottom line of improving your overall.

So we kind of call that our guerrilla campaign, so to speak, of getting out there and getting it one way or another. And so, when you start with $270,000, which in perspective is one frac stage, you learn all these ways to try and create additional capital because you just don't have very much of it. And 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.

And our vendors have really stepped up and, whether it is Halliburton or Schlumberger or Patterson or Forrester, they've helped us. And I want to express my appreciation to Champion's pipe is well that they've -- instead of coming in and saying you've got to lower your prices, they have helped us show us ways to use their services in a more capital efficient way. And I just had to say that; I couldn't restrain myself.

I appreciate the additional thoughts, Joe. Thanks again and have a great day, gentlemen.

Mike Scialla, Stifel.

Hi, good morning, everybody. I just want to ask a few questions on the Eagle Ford. Can you say where production is now? And if you do all 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 on various parts of the acreage that we think can still be drilled. And then of course, as we mentioned, we have always in the past said we've only tested and only drilled into the lower part of the Eagle Ford.

And 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. So that inventory could be higher.

As far as the production goes, I think that we were -- I think it was about 8% of our production this past quarter. So 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. So I would expect that -- 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 will probably early on get up in the 6,000 to 8,000 Boe a day, I would imagine, from this program, maybe even a little better. But on average I would expect that for 2019 our production might be 50% better out of the Eagle Ford as a result of this project.

That's helpful. Thanks, David. And Joe, I wanted to ask on -- you mentioned your 11,000 per acre average to date in the Delaware for acreage acquisition. Do you have a number for -- I know you've got the BLM number out there which is a big part of this year's, but 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. But most of that other acreage for the BLN was done at lower levels, including some mineral -- a fair amount of mineral acreage that we acquired. So, 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.

Sameer Panjwani, Tudor Pickering Holt.

So, one of the wells that we have been watching for is the Wolfcamp XY test at Arrowhead. It 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?

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 and we have some land work that we're doing up in that area right now. And I think until that's done we would prefer just to remain silent on the results from that well.

So, I think we are satisfied with how it's gone. But just because of -- we've got a couple of deals we are finishing work on, it would probably be better to -- we just get that done before we report on the results.

We would also like a little more data history before we come out.

That's right.

One thing you probably noticed that we've moved to doing 90-day IPs to try 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. And there can be great change in these wells, as you know. So we are encouraged, I will say that, that results today have been positive, but we just want to be more confirming before we make an announcement and before we commit more capital to that area.

Okay, that is fair enough. Maybe on the Twin Lake flow then, 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? And then, are there any intervals being tested by operators in the region outside of the Wolfcamp D or the B?

With regards 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 [Yaso] and 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 Culbertson. That was the Olivine well.

But I think in the Wolfcamp proper, the answer -- to the best of our knowledge anyway -- is that it has either been the D or the B. And I think that Continental is the first one that has tried the B out there.

With regards 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 hole core on this well also and we did some additional mechanical testing and -- not only for targeting but also for helping us to select a zone that we thought might frac better than what we'd experienced in the previous well.

I think that absolutely happened. So the well treated much better. And it's just started flowing back and we just don't have a whole lot of results to talk about on it as yet, but I think we should fairly soon.

Was there anything different on the completion front on that well?

Nothing real significant in terms of outside of what we are doing in other areas. I think 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 hole 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've drilled and better than some of the others drilled in the area. We did actually pump some resin coated sand on the tail end, so we haven't -- in the early stages of production here we haven't flowed the sand back. So like David said, it's just still a little early to tell.

Okay, that's helpful. Thank you.

Jeff Grampp, Northland Capital Markets.

I will just 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? Or are there any midstream facility-related buildouts you guys maybe need to get ahead of before accelerating there? And then I guess just building off that, are there any stack pad type tests or anything you guys might be planning at Antelope Ridge as well?

To that question, I say yes to all of them, is that the Antelope Ridge is certainly emerging as you get more data in. That's one of the things that's changed is we are 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. But 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. And 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. So we first have to get them before we can drill them. And so, the exact order -- and that rig may drill some Antelope Ridge, go drill a saltwater disposal well or two, then come back to Antelope Ridge or vice versa.

So, that's all part of the planning process and, 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. But that's all up in the air as we talked. Does that answer your question? David has something.

I'm just going to say, Jeff, the only thing I would add is that while we are (inaudible) 100% we're very excited by the way the Antelope Ridge area is testing out. And certainly it will -- it's going to compete well for next rig or rigs before very long, especially with the additional BLM acreage that we acquired.

But I do want to also say that we've been pretty happy with the results we've seen recently up at Arrowhead. I will point you back to the recent Stebbins wells in the second and third Bone Spring, the SST wells that we reported on last quarter. So I will say that team is making a pretty strong statement for having another rig in that area as well.

And 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 the rig parked right there in the same vicinity for a good period of time. So, that is something we are seriously considering in making the rig allocation decision as well.

All right, understood. It's a high-class problem, but I will leave it there. Nice quarter, guys.

Tim Rezvan, Oppenheimer.

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 and come by and see us. That's something we'd like to invite all the listeners to is come by and see us in person. And I think we always gain from meeting you all in person and taking all your questions.

And the same thing, meet with us and meeting some of these young staffers that we've been touting, those 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 to get to know you better, too. So with that, I'm off and thank you again for the kind words many of you had. We are continuing work just as hard as ever and look forward to reporting you next quarter.

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