Matador Resources Company (MTDR) Q4 2016 Earnings Report, Transcript and Summary

Welcome to the Fourth Quarter and Full-Year 2016 Matador Resources Company Earnings Conference Call. My name is Nicole and I will be serving as your 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 March 31, 2017, as discussed in the Company's earnings press release issued yesterday. I would now like to turn the call over to Mr. Mac Schmitz, Capital Markets Coordinator for Matador. Mr. Schmitz, you may proceed.

Thank you, Nicole. Good morning, everybody and thank you for joining us for Matador's fourth quarter and full-year 2016 earnings conference call. Some of the presenters today will reference certain non-GAAP financial measures regularly used by Matador Resources in measuring the Company's financial performance. Reconciliations of such non-GAAP financial measures with the comparable financial measures calculated in accordance with GAAP are contained at the end of the Company's earnings press release. As a reminder, certain statements included in this morning's presentation may be forward-looking and reflect the Company's current expectations or forecasts of future events based on the information that is now available. Actual results and future events could differ materially from those anticipated in such statements. Additional information concerning factors that could cause actual results to differ materially is contained in the Company's earnings release and its most recent annual report on Form 10-K. Finally, in addition to our earnings press release issued yesterday, I would like to remind everyone that you can find a short slide presentation summarizing the highlights of our fourth quarter and full-year 2016 earnings release on our website on the presentation and webcast page under the investors tab. With that, I would now like to turn the call over to Mr. Joe Foran, our Chairman and CEO. Joe?

Thank you, Mac and good morning to everyone on the line and thank you for participating in today's call. We appreciate your time and interest in Matador very much. We have a lot of news to share with you today and I apologize for its length, but we have tried to divide the news into two parts to make it easier to digest. The first part is the highlight summary and the second part is the detail behind our financial and operational results. Now I would like to introduce the senior members of our operating staff joining me this morning and who are standing by for any questions you may have. They are Matt Hairford, President; David Lancaster, Executive Vice President and Chief Financial Officer; Craig Adams, the Executive Vice President of Land, Legal and Administration; Van Singleton, Executive Vice President of Land; Brad Robinson, Senior Vice President of Reservoir Engineering and Chief Technology Officer; Billy Goodwin, Senior Vice President of Operations; Gregg Krug, Senior Vice President and Head of Marketing and Midstream; Matt Spicer, Vice President and General Manager of Midstream; Trent Green, Vice President of Production; Rob Macalik, Vice President and Chief Accounting Officer; Brian Willey, Vice President and Co-General Counsel; Bryan Erman, Vice President and Co-General Counsel; Kathy Wayne, our new Vice President and Controller. Before we get into the numbers, I would like to express my heartfelt appreciation both personally and professionally to the entire staff and Board for overcoming the very challenging business environment we faced in 2016 and for delivering one of the strongest years in Matador's history, both operationally and financially. And also, about Kathy, our new Vice President and Controller, Kathy and I have worked together for 28 years. And we're just delighted everybody on this side of the phone call to see her promoted and recognized in this way. A round of applause, please. I think we have thoroughly embarrassed her. Now, for the staff's achievements since last time we talked. They have achieved record average daily production of over 30,000 BOE per day in the fourth quarter of 2016, a 24% year-over-year increase in proved reserves to a new record of almost 106 million BOEs; an increase in Delaware acreage position to over 100,000 net acres today; and perhaps the most significant, last year Matador devoted most of its capital to the Delaware and it appears to have really paid off. Our Delaware Basin production alone -- I get kind of excited when I read this. The Delaware basin production alone increased to 20,700 BOEs per day in the first quarter, an increase of 12% sequentially and a 138% year-over-year increase. As of the beginning of 2017, the Delaware Basin now makes up 70% of Matador's total BOE production and 75% of its proved reserves. These results occurred from a total team effort from the staff and our vendors and our contractors and our field personnel, with some very significant results occurring from each of these teams. And I want to commend them and let them know how much we appreciate that strong work. With that, I would now like to turn the call back to Nicole for all of your questions. Nicole?

[Operator Instructions]. Our first question comes from the line of Gabe Daoud of JPMorgan. Your line is now open.

Maybe just starting on the midstream side, obviously getting the JV done, pretty helpful and beneficial. Just trying to think about maybe first of all, one, how the incentives work and when you expect to earn the remaining $73 million that's on the table. And second part that would just be the fees moving forward. I appreciate the comments in the prepared remarks. You've been setting market rates. But just kind of thinking -- just wondering how that changed, relative to where fees were just before the transaction happened.

First, Gabe, is that the additional $73 million will be achieved over five years. And basically, it's as we set our internal projections, if we meet those internal projections that we have which will be reflected in guidance that will be made year to year to year and we achieve that, then we achieve the $73 million. So the easiest way to do it is just look at it from a point, are we achieving guidance? And if we're, then you can ratably include that $73 million over the next five years, a little less than $15 million a year. So then on your second question, on the effect of LOE, I'm going to ask David Lancaster, our CFO, to step in and he has worked more closely with those numbers.

Gabe, it's David. I think that you know you -- the way it's going to look to you going forward, I don't really think that the fees that have been negotiated -- as we've said, they are market rates. They are very comparable with what we had been paying and/or charging ourselves. So, that's not really going to change things very much. As you saw in our third quarter financial statements and as you'll see when we issue -- well, you've seen it in the press release, the financial statements -- you'll see that we've broken out a line for both midstream revenue for plant and other operating midstream expenses. And those will continue to be on the financial statements going forward. I think what you'll see is that our LOE costs will come down a little bit in this coming year as a result of some costs that were previously up in that category being reclassified down to the plant and other midstream services operating. You're probably going to see that number go up a little bit over the course of the year because of the fact that we've added more facilities. We've got some new facilities that are just coming on and some new ones that we're going to be building. So, that's part of the operations cost will go up and certainly we'll see the midstream revenues portion go up. I think it's important to remember that the midstream revenues that we report up there, as we note, are third-party midstream revenues, so that's only things that are not Matador. So things that -- parts of the revenue that we receive from working interest owners in our properties or any third-party volumes that we're either processing or water disposal, that sort of thing. And I think what you'll see for the most part is that the midstream services revenue and costs will tend to almost offset. The costs may be slightly higher than what's up there in the revenues. But you've got to remember, that's only a small portion of the revenues that the midstream venture is actually generating. There will be, then, a separate footnote that breaks all of that out. I think where you'll see the biggest difference on the financial statements is just that the non-controlling interest -- that the income attributable to the non-controlling interest will certainly get bigger. And that's where you will sort of see the impact. And as we put in the earnings release, we estimate that it will be somewhere between $15 million and $20 million in sort of an EBITDA impact to the consolidated; or in particularly to Matador, as a result of that this year. But that's where you're going to see most of it, Gabe, is that you'll see that non-controlling interest line just be much bigger than it has been in the past.

Let me just add in here, slip in here that one of the big areas for improvement will come from as we drill out the saltwater disposal wells and get them working just as over in Wolf where they substantially cut our LOE in the Wolf area, they will cut the -- they will save a lot of money over here in Rustler Breaks. So we think the process in all very market rates, but there's going to be substantial savings from the saltwater disposal too.

Thanks Joe, that's helpful. Then, my second question, just the nice step out well there at Ranger, the Airstrip. If you could maybe just give a little bit more color on that. And obviously given less overpressure up there and just the nature of the rock generally, how you guys think about results moving forward and just whether or not you think the Wolfcamp A program up there could be repeatable and successful.

This is Dave again, Gabe. So first of all, I think we're really excited about the result at Airstrip, being that I think that's anywhere from 11 to 30 miles north of where the nearest Wolfcamp A wells have been tested horizontally in the past. We chose to give a test up there because there had been some vertical Wolfcamp A up there in that area and so we felt optimistic that we could drill a successful horizontal well. Certainly we never had any concern, I don't think, about the oil saturation of that interval. We knew that it was going to have hydrocarbons in place. We also knew that it was going to be quite oily too. I think we know from our work up in that area, whether it's Bone Spring or whether it's Wolfcamp, it's just going to tend to be a much higher oil cut which we think is positive. One trade-off of that is that it's not quite as overpressured as it is down south. And so it does require you to think about artificial lift a little bit sooner. But that's pretty typical of wells up in that area and not a problem. And so anticipating that need, we actually designed the well so that it had a little bigger casing so that we could run ESP, if that's what we chose to do and we did. And so I think we're real pleased. As far as repeatability, other opportunities, sure; lots, I think. The zone that we picked here, it's just an interval in the kind of the Wolfcamp A; the lower, not necessarily the upper kind of XY part. But it's a little bit lower than that and get a nice -- got a nice Wolfcamp section up here. So I think with time, we'll continue to learn more about it and continue to refine our landing targets and look for the best intervals to work in. But there is a considerable portion of that acreage to the north that should work for the Wolfcamp and we're going to continue to work there. I think we've been optimistic that we could achieve some good results there. And at 97% oil cut, that's pretty awesome. And so we're pleased with our initial results there.

Yes, Gabe, I'd like to underscore what David said and also note that it's making very little water which we're very encouraged about. But I want to give a shout out to our geological group, because I think they really worked as a team with the engineers and on the flexibility that we got to run the ESP. They've been up at the forefront, outlining in this area and outlining the potential to the north. Ned, would you like to say something?

Well I think, as always, David summed it up very nicely there. But Gabe, Ned here. We're very optimistic about the Wolfcamp up north. When we made the HEYCO merger, we knew the Bone Spring would work up there and we hoped that the Wolfcamp would. And I think this Airstrip test really confirms that because as we move further south into the basin and further to the southwest, we start to pick up a more organic section. I think we will see the pressure come back. And the XY Sands also begin to appear down there. So we're really excited about this. And I think you'll see that excitement translated into wells being drilled up here over the next few years.

Our next question comes from the line of Mike Scialla of Stifel. Your line is now open.

I guess on that same theme, I wanted to ask you to discuss your other step out, the Tom Walters well. And then do either of these wells, the Tom Walters or the Airstrip, impact your drilling inventory in Ranger and Rustler?

As far as the Tom Walters well went, that was also an exciting well for us and a very nice result. That was up really in kind of the far northwestern part of Rustler Breaks. We drilled the one well up there last year, the Scott Walker which was okay but not certainly what we had hoped to achieve. And so, we had drilled some wells as far north as the Dr. K which had also been good wells. And so we've decided to jump on to the north with this test and put that well at the Tom Walters; and really happy with this outcome. I think it reflects the targeting of the well. I think it reflects a little bit more robust stimulation treatment that we put on this well. And as a result, we're pretty optimistic about the entire acreage position, not that we weren't; but I think this just really just confirms the prospectivity all across the Rustler Breaks asset position. And that result was certainly one of the best IPs that we've had a well at Rustler Breaks altogether, not just in that part of the acreage. And I would say that it certainly will have some incremental improvement in our location count as a result of that. We're kind of finishing all that up in order to be able to report kind of a new set of numbers in our 10-K. But then we've also added some acreage here recently that we'll probably be able to fully update everybody on our location count, once we get to Analyst Day. But I think we're all real excited and we're very pleased with that result.

Mike, this is Matt. And I just would kind of add to what David is saying there. We're excited about the well. And David talked a little bit about the different completion we put on it. But that's something that's continuing to evolve and the completions just get better and better. But the other thing I wanted to add to that was with this Tom Walters and us validating this northern acreage even further is how it contributes to the midstream efforts there. So it gives us a lot of confidence, to your point, to add to the schedule to go in and drill more and more of these wells. So it's going to add on the E&P side; it's also going to add on the midstream side.

That's great. And I just wanted to ask sort of a conceptual question. It looks like you guys are gaining a lot more confidence in looking at 24-hour rates and having a pretty good handle on what the wells are going to do. I know when you first started in this program, I think you guys used to just give us longer dated, like 30-day rates or even longer. Am I mischaracterizing that? Or has your confidence level grown to where you feel like you've got a good read on a well pretty quickly with the initial rates?

Mike, you may have three or four of us answer on this one because that -- there are pros and cons of each of those methods. We're trying to be as standard as we can, consistent with the market. And the -- we're not sold on the IPO as being the only -- the initial potential test as being the only thing. And the 30-day has problems if you are shut-in, awaiting pipeline. Both of those -- the confidence that we really feel is that that's just one data point. And, we look more at it's one data point. You don't know; different wells behave different ways. And we like to really look more back at six months, except we found that the analysts want earlier data. And they feel, most of the analysts, they know how to weigh the difference between an initial potential and 30 days and 60 days. And I think that the growth in production and growth in reserves confirm these are good wells, more so than what is -- amounts to a single data point early in the history. I don't know if I said that right.

This is Matt. I just was going to add to what Joe was saying there. One thing that we do think about when we flow these wells back and continue to think about is reservoir pressure maintenance. So, the IP is what it is. But David mentioned earlier, the Airstrip well, it went on ESP pretty much right out of the gate. Some of these other wells are going to continue to flow for years, if you will. So one of the things that we do factor in on the [Technical Difficulty] is choke size which relates as a proxy to reservoir pressure management. So that remains to be incredibly important to us. And like Joe said, it is one data point. We look at them at 30 days and we look at them at 180 days. And when we're evaluating different things we do with these wells, not only how we flow them back or up on one pump but how we complete them. All that rolls into the 30, 60, 90, 180 day and all the way -- years into these wells. So we continue to watch them, over and over and over.

Yes; the only other couple of other things I'd like to add Mike and David is that I think, as I think back, I don't recall that we've -- that we ever had particularly a practice of releasing 30-day success rates. I think even in the Eagle Ford and other places, we've been more consistent with releasing 24-hour IPs. I will say that you need to think about them in terms of the fact that as we bring these wells on and flow them back, the 24-hour IP test that we report may come two or three weeks into when the well has actually started to flow back. Because we wait until we feel like we have a nice, sustained 24-hour period that we can report the results on. The state in Mexico does require us to report 24-hour IP rates. And so a lot of times it just is convenience and they require those pretty quickly. So, it's just convenient for us to report the same things to you as we do to the state and find that to be a consistent way of doing it. I will say that I think that we do have a pretty good idea during the course of these tests how the wells are going to -- how the wells are ultimately going to perform. And I would say, I think we've been pretty good then at updating the Street and the analysts on how wells have performed, going forward. I mean there are wells in our investor deck, I know, where we show a year or two of performance from. And it's not uncommon for us to go back and talk about recent wells and how they've performed and what sort of EUR we think they are tracking toward. So it's just -- I guess it's just what we've sort of evolved to. But I do think we have a pretty good handle on the way the wells are going to perform as a result of these tests that we do.

Yes that's helpful. I appreciate that. I just want to get a sense of your confidence based on what, from our standpoint looks, like a pretty limited 24-hour IP. But I realize you've got a lot more data there that you are looking at and that's helpful. I appreciate it. Thank you.

Yes, Mike, I think again when I think that one of the good points that David was making was after you've done a number of these, you can kind of compare how one is cleaning up or performs relative to an earlier well. And that kind of gives you a track record, too. It's just kind of like if you have an 11-pound baby, you can generally suspect that's going to grow up to be a tall person.

Our next question comes from the line of Scott Hanold of RBC Capital Markets. Your line is now open.

So, you all have 88 wells on the plan for 2017 in the Permian. And could you give us a little color on how you look to deploy those five rigs, with respect to various target formations and pad drilling activity?

Sure. So as we laid out there in the release, Scott, of the -- four of the rigs are running today, of course. Two of them are running in Rustler Breaks and one is running down in -- on the Wolf asset and one is running up in the Ranger/Arrowhead area. Starting from the north, it's our intention to run the Wolf -- or the rig up in the Arrowhead and Ranger; primarily there for the entire year. We will take it and drill the first Twin Lakes well starting right near the end of the first quarter. So early second quarter, we'll be drilling up there on that well. And that of course is the Wolfcamp B test. The majority of the wells that we're going to be drilling or that are currently on the schedule for 2017 in the Ranger and Arrowhead area, are going to be second and third Bone Spring wells. Probably a little bit higher concentration of the second Bone Spring than third Bone Spring. Though as you get a little later in the year, especially given the success of the Mallons and the Airstrip, we might look to add another Wolfcamp A test or even a couple more third Bone Springs. But that's the way it currently lays out. If you go to the south in Loving County, we'll have one rig running sort of between Wolf and Jackson Trust down there. We'll be drilling in Wolf about the same number of, I think, XY wells; and second Bone Spring wells. I think we've got four or five of each of those planned. And then we also will drill a couple more fat targets. I think it's interesting too that we're looking to test a Wolfcamp B and an Avalon in Wolf. So those are kind of our step outs, if you will, in Wolf this year. And we're excited about the chance to do that. And that will get started sometime in the second quarter. And then, of course, given the nice result we had over at Jackson Trust, we'll have another couple wells at least that we'll drill there in the Wolfcamp lower. I think I may have called it the fat. That's what we affectionately call it around here; but I usually call it the lower when we're writing it through public consumption. Then up in Rustler Breaks, of course, two rigs running there now. And then we'll have the third rig coming up there in April. And those will primarily be -- we'll primarily be drilling Wolfcamp A-XY and Wolfcamp B wells at Rustler Breaks this year. I think there's a couple of second Bone Spring tests that are on the schedule. But it's predominantly Wolfcamp A-XY and Wolfcamp B and a little bit of -- I think it's probably 60/40 Wolfcamp A versus Wolfcamp B.

Okay, yes; that's exactly what I was looking for. Great context. And a little bit more on that lower Wolfcamp A test you all had done at Jackson Trust. Is the -- can you talk about the thickness of the Wolfcamp there? Is there the potential to drop one in the lower and still manage another one a little up higher in the Wolfcamp A? Or is it primarily just better reservoir targeting when you look at that lower number?

Scott, I think the Wolfcamp A is big enough, you could put two wells in there. I think the Totum definitely shows that the target that the team got to on this round is -- would be the preferred target. The rates and the pressure there show that you contacted a much higher-quality reservoir and that you have stimulated that effectively. And I really want to point out on that improvement from the initial Jackson Trust well -- that really was a team effort with the geoscientists and the completion engineers. They leveraged the 3D seismic data that we had there. We were able to identify a different zone. And then we pretty radically modified the completion design there to make sure that we effectively stimulated that reservoir, as well. So really hats off to the team there for working as a team and delivering a much improved result. In terms of targeting there, I think there are some other Wolfcamp ventures that are worth testing. I think the gross Wolfcamp there is probably 2,000 feet thick in that area. But I think for right now, we'll continue to probably focus on that Totum bench. And really it goes to show that even subtle targeting, as much as 70 feet difference, make a very big difference in this game. And when we talk about why we take such great effort to steer wells, it's really that's why -- is that we do feel that that targeting is very important. So we'll continue to work on that and see what else we can identify in that area.

And what we're really excited about -- at least what I am really excited about -- in regards to what Ned is saying here is having yet another tool from the toolbox to use with this seismic and looking at attributes and identifying these zones and to be able to go in and actually find additional targets within the same reservoir, like you are talking about in the Wolfcamp there. So it's exciting to have yet another tool that we've been successful using. And Ned's kind of said it there; it was a complete team effort on this deal between the geoscience team and the engineers on how to complete this well. And the results are really, really good.

And just to clarify a point there, you mostly use the 3D seismic you all had to do that enhanced targeting? And do you have that data in other areas to utilize as well?

Yes, we do. We -- that was a vintage survey that was -- I'm not sure when it was shot; but several years old in Jackson Trust. And then we've acquired a new proprietary 3D in Rustler Breaks. And that data is being processed and analyzed right now. We have agreed to a shoot in Wolf and we also have a 3D on our Ranger area as well. So, we hope to continue to leverage this, moving forward. So we have good coverage of that to answer that.

Appreciate that. More good things to come, it sounds like.

We think so, Scott. We're really delighted -- this might be appropriate to note that we have three teams out there, one in Wolf, one in Rustler Breaks and one up there in Arrowhead/Ranger. And if you look at the three big announcement of the wells that you are talking about, the Mallon Wells came from the Arrowhead/Ranger team. This Totum well came from our Wolf team and the Tom Walters came with our Rustler Breaks, among their other good achievements. So we're delighted to see the balance on our three teams all around the basin and that they are delivering and the cooperation that the teams are executing. They are doing with the geology and engineering for planning. And we're just really pleased that we've got a lot of directions and we feel like a lot of good choices.

Our next question comes from the line of Irene Haas of Wunderlich. Your line is now open.

Hey, congratulations on a very successful drilling campaign during 2016. And my question really has to do with Wolfcamp A. Towards the northern part of the basin, is the Wolfcamp A founded -- is it pretty regionally extensive? And then really similarly, what are the aerial extends for the Bone Spring, second sand and third sand? What I'm really kind of after is how stackable are these multiple targets?

It's David and I'll let Ned chime in on this, too. So I think that with regard to the Bone Spring, the Bone Spring is just a very thick alternating sand and carbonate package, up in the northern Delaware Basin. And so you sort of have a first Bone Spring sand and carbonate, first Bone Spring carbonate and sands -- third Bone Spring carbonate and sand. So the sands are amalgamations of different periods of deposition. But they all tend to be fairly thick, such that I think there's the opportunity to, at times, even consider putting multiple laterals in a particular bench of the second or the third Bone Spring and maybe even the first. I just think we've kind of scratched the surface on what's possible up there. We're going to have -- you are going to have kind of sweet spots, if you will, of third Bone Spring in some areas and second Bone Spring in some areas. And sometimes you are going to have both in the same area. But all across that acreage position, I think there is potential for at least one, if not two or three of the Bone Spring targets. And even the right place to stick your lateral within a certain bench of the Bone Spring is probably going to change with where we happen to be. So that's why our geoscientists -- Ned and his guys -- spend as much time as they do trying to really tear that apart and understand it. And Ned, you are probably better to answer Irene's first question with regard to the faults [Technical Difficulty].

David, you are getting some positive nods from the geoscientists in the room, I can tell you, with that. So in regards to the Wolfcamp A, Irene, really the limits on that play are going to be the shelf edge. So to the north, as you move away from Airstrip, you will go into the Wolfcamp platform succession and that tends to produce more conventionally. As you go to the south and to the west, I think the Wolfcamp section, the Wolfcamp A in particular, kind of opens up and becomes more organic rich. You start to pick up the XY Sands. And I think it's worth pointing out that really one of the things that is very well distributed in the Wolfcamp succession here is the Wolfcamp D. I think that is a target that is about as widespread across our acreage footprint as possible. So you'll see us continuing to try and exploit that target. And regional mapping shows that a few of our targets that we really like in the Wolfcamp B extend pretty far beyond the boundaries of Rustler Breaks. So I think you can watch us trying to delineate that as well. With regards to the Bone Spring, in reality, the Wolfcamp A probably shares a very similar distribution to the Bone Spring succession. And as David said, it's going to be a different -- I guess a different set of Bone Spring targets that work in different areas; but we're confident we're going to have multiple. And really one thing I want to say is, again, the HEYCO acreage, when we merged with them we were very excited about the Bone Spring. We knew that would work up there. We're really starting to see the potential and the quality of that rock with the Mallons. We're convinced we'll see more and more good quality Bone Spring wells across that HEYCO acreage. And we're really looking forward to continuing to delineate the Wolfcamp A. I think it's going to be an exciting campaign, over the next year or two, to do that.

And if I might have a follow-up question, it's really talking about how tall your babies are. When are you going to update your type curves? You've been pretty quiet for the whole year now. So, we're kind of curious as to resource upsides in addition to location counts.

Irene, it's David again. We'll certainly update all the type curve information, well location, resource updates, all that, when we do our Analyst Day in about a month now. I think you probably saw the announcement that we plan to have Analyst Day on March 23 here in Dallas. So I guess that's four weeks from today and we'll do it then. Normally we would have done our Analyst Day by now, but we've been a little busy with our midstream deal and thought that we could be much better as far as providing initial guidance and then some additional detail on our business going forward if we delayed that until after the announcement of the midstream deal and after earnings. But we'll have all that ready to go for you on Analyst Day.

Our next question comes from the line of Jeff Grampp of Northland Capital. Your line is now open.

Question on I guess just kind of a bigger-picture question. It seems like every year, you guys seem to delineate one or two zones that the industry was kind of leaving by the wayside. So just kind of looking forward into 2017, what do you guys kind of envision as being those potential zones that we could look at in 12 months and kind of look at as an integral part of Matador's growth plans going forward?

Jeff, I'd just say this -- it isn't that we're trying to call a lot of attention to ourselves or what we're doing. It's just that we try to take a very methodical fashion in going through here. And as the opportunities come along on the delineations, to test a few of the zones because we've got a lot of acreage in these areas and we think that's the right thing to do, rather than just drill all the proven zones in an area. We're really trying to continue to assess what we have. As you've heard me say, when we came out here from the Eagle Ford, we came out to the Delaware on the strength of possibly a couple of zones in the Bone Springs and something in the Wolfcamp. And instead of moving them from 2 to 3, we're now producing from 12 or more different zones. So it's been a delight. It's a very thick section. And there's a lot to test and we will test several of these. We're much more about, let's give it an actual test than just trying to speculate on the basis of a log; and say oh, yeah, this is going to be proved or probable reserves. We'd like to actually test them from time to time, when time circumstances and the like give us that opportunity. David, you might add to that.

Sure, I'd be happy to, Joe. With regard to new things that we're looking to do in this year, I mentioned a moment ago that -- but to give you a little background, you may recall that when we were drilling on one of our wells, the Barnett well here in the third quarter, that we actually took about 600 foot of whole core in there in Wolf, in an area that we've been working on for the last two or three years. And in doing so, our geoscience team has been really excited by some of what they've seen there. And it's encouraged us to actually schedule a test of the Wolfcamp B which is going to be below anything that we've tested in the Wolfcamp so far. And then we're also pretty sure that we're going to go up and test the Avalon. The Avalon is also a pretty thick section. I think it's around 800 feet thick here. And there may be the potential for a couple of benches in the Avalon. But we're going to give at least one of those a shot, so that's a couple of zones. And then certainly when we go to -- go up to Twin Lakes here in a month or so and start drilling that horizontal well, that will be our first test of the Wolfcamp D anywhere, but particularly up there. And that's been something we've been looking forward to having a chance to test for a while. And I'm hoping that a year from now that we'll all be talking about additional wells we're going to be putting into Wolfcamp B and Avalon and up at twin Lakes. I don't know if we'll to a perfect inside straight on all those. But I think we feel like they are all very valid targets to test and we're optimistic about the results. And I have to give a shout-out to our geoscience team. I mean this time a year ago, the Wolfcamp B was -- or year and a half, for sure -- was kind the twinkle in our eye at Rustler Breaks. And to get to carry on the baby theme, it's now a full-grown kid. So we're pretty happy with that. And so, I'm just real proud of the work that they've done to be able to unlock these other targets for us; and then of our drilling completions team to be able to get these wells drilled and completed. And so we're going to continue to see what else we can find. I think there is still a lot of treasure out there to find, Jeff.

Jeff, this is Matt. And I think we get a lot of confidence as we go through this program, like Joe and David were talking about, taking little steps, not huge steps. But we're always looking at all these different zones. And once we make one work -- and I think Rustler Breaks is the perfect example of that where a couple of years ago there wasn't -- there weren't many people that gave much value to that acreage. And the team has been able to identify several targets out there and they just kind of build on themselves. The seismic attribute that we've been talking about, that's something we can take forward. Making the completion designs better is something we can take forward. There's a lot of things we learn as we go through this process that just give us more and more confidence so we don't have to take a big shot; or to Dave's point, to pull to an inside straight. We can go ahead and make calculated, measured progress.

All right. Great detail, guys. For my follow-up, more relates to the pad drilling. You guys kind of noted in the release about doing some larger pads going forward. Can you just give us maybe a little bit more context there, as far as maybe where average pad sizes were recently or back in 2016? And kind of where you guys see that headed in 2017 and how that translates into efficiencies, well costs and that sort of thing?

2017 is going to be similar to 2016, in that there's going to be a number of different projects going on. Some are single well pads, actually. Some are going to be multiple well pads. It's just going to be kind of a mixture. But I would say somewhere north of half of the drilling we're going to be doing will have some sort of pad component to it. We see a lot of efficiencies, of course which we're going to continue to focus on. No matter what we're doing, we will see some -- we've called it in the past lumpiness, if you will. We're going to see some of these pad wells will take a little while before they come on production. But one thing we do take a lot of comfort in is the team's absolutely thinking about this and how it not only relates to efficiencies on the drilling side but efficiencies on completing these wells, where we're able to go in and -- we've called it in the past mirror fracs, where we'll have two different wellbores that we're fracking and doing waterline working at the same time. So that saves cost. It also gets those wells online sooner. And the production team, they've been very effective at getting facilities built prior to the completion. And in some cases where we have a smaller footprint, say on a BLM location where they've actually got -- where they are constructing these production facilities off-site and then bringing them in a modular fashion, we're getting them done while we're flowing the well back. So a lot of progress being made in those efficiencies too.

Our next question comes from the line of Ben Wyatt of Stephens. Your line is now open.

Congratulations on the growth in the Delaware; good to see that highlighted. I know we spent the last handful of questions on delineations and really kind of up and down the column. This is I guess a high-class problem. But can you guys give us an update maybe on where you are on spacing? Is that -- that's obviously still something you guys need to figure out, as you work your way across the Permian asset.

It's David. I think we've -- we're beginning to figure that out. I think that maybe we've concentrated a little more vertically than horizontally. But I think that certainly as we begin to infill various sections where we may only have a well or two, that we'll begin to get to have more clarity around the spacing and what we think that that's going to be. I think it's going to -- honestly, I think it's going to vary, Ben. I think they're going to be certain areas where we may feel like we can space a little closer; and others that we may feel like we need to widen it out a little bit to optimize recovery. And certainly I think we'll have kind of what people call the wine racking where we're sort of staggering. I think a zone like the Wolfcamp B -- we've got three targets there in Wolfcamp B at Rustler Breaks. But I would imagine that, going forward, we'll be looking to kind of wine rack or stack those in. I don't think that it's likely that we would stack three right on top of each other. But we probably need a few more data points to be able to be a little more definitive. And that's certainly by being able to drill quite a number of additional wells this year; that will help us to begin to answer those questions.

Very good. And then maybe just to follow up, popping over to the midstream. And I don't know if it's best for Matt Hairford or Matt Spicer. But what's kind of the lag time on getting a processing plant kind of operational, if you guys start to spend money here in 2017?

Then, this is Matt Spicer talking. Our goal is Q1 of 2018. All of the permits are running, have been submitted. And we fully expect that to be operational no later than Q1 2018.

Ben, this is the other Matt. And I'd just kind of want to add to what Matt has said. And one of the things that the midstream team is very good at doing is creating a lot of optionality. And so, in the interim, when we start building this expansion on this plant, we'll have gas coming in; and we do go out and secure third-party gas. We have another outlet or two that we can take that gas in the interim. So we don't have to wait until the plant is built before we start bringing on gas. So we'll be working on that in the coming months.

Our next question comes from the line of Neal Dingmann of SunTrust. Your line is now open.

Thanks, Joe, for all the details today. Joe, just looking at that slide 5 that you outlined in all of your -- just the huge Delaware play you have now. Can you talk about on the -- when you go to that fifth rig, just for the rest of the year, is the plan to run these rigs -- you talked about bringing one up to twin Lakes. I'm just trying to get an idea of where we should -- how active, how much are you going to be sort of moving those around? Or should we think about at least four of those kind of in a similar area where they are showing on slide 5?

Let me phrase it this way, it will start out in Rustler Breaks and it will flow to little bit as we need to. We'll drill the well up in Twin Lakes that we mentioned and maybe some others. But we'll just have to kind of see where the opportunities are, where we're having success. But initially, it will go to Rustler Breaks. And let me turn -- that's been my point of view and that's been -- but the way we work down here we'll take -- we always reserve the right to get smarter. If you are having some exceptional results, we want to be nimble enough to move it somewhere else. David? Matt?

You said it well there, Joe. We've got a lot of opportunities here. We could put that rig in any one of the three areas that we talked about and drill successful wells. So I think floater is a great term to use for this rig. We can take it and move it to one of the other areas relatively quickly and relatively easily.

This is David. Just to be clear, the rig that's currently up in the Ranger/Arrowhead area is going to spend the year up there. We will move it temporarily for the one well that we're drilling at Twin Lakes. But other than that, unless we decide to go back later in the year, that rig will run in Ranger and Arrowhead all year long. Likewise, the one down in Loving County, our expectation is that it will run in between Wolf with a couple more wells up in Jackson Trust during the course of the year. We think we'll have two rigs at Rustler Breaks. And right now, the third year, the third rig is planned to be at Rustler Breaks. We did acquire some new acreage in the quarter, as we've noted, some of which is bolt-on to what we've recovered or what we already had in Rustler Breaks. Some of which we acquired a nice new chunk of acreage down at what you might consider the Red Hills area, sort of in southern Lee County and that's a very nice track. It's five or six really nice sections, a couple of which are stacked, might lend themselves to longer laterals. And I would expect some time in the next several months, we'll probably sneak that Rustler Breaks rig down there and drill a test there. We don't currently have it scheduled. But we're really excited about that acreage that we just acquired and so I think it's likely that we might do something like that.

One other thing that hasn't been said, we've talked about drilling the well at Twin Lakes. And just for the record, the well that we drilled there about a little over a year ago, in the past year has made 52,000 barrels of oil with 66,000 BOEs with the gas. It's making no water. And those -- if you were to put them in a program and get confirmation that there -- these second or third sites were, you would put them in a program where you could probably drill them for less than $2 million. So those are pretty good economics. They don't move the needle like these big horizontal or gravity attention. But 52,000 barrels in the first year of production for a vertical well is pretty good.

That's great, Joe. Joe, could I ask one last one, just to you or David, a very broad question. With all this activity, how do you all look at it if you would just classify it simply as developmental activity?

Neal, did we lose you? We lost you, oh shoot.

Can you hear me all right? Can you hear me, guys?

For those others on the line we did not delete him. I want you to know when he comes back, we will readmit him to this line.

Can you still hear me, guys?

If you don't get him real quick, why don't we go to the next question and then put him next in line?

Can you hear me, guys?

Did we lose everybody?

[Operator Instructions]. Our next question comes from the line of John Freeman of Raymond James. Your line is now open.

Can you all hear me? Hello?

Ladies and gentlemen, please stand by. Your conference call will resume momentarily. Again, ladies and gentlemen, please stand by. All right, we're now live. [Operator Instructions].

Neal, you were saying?

Neal, your line is now open.

Neal, hello? We still can't hear anything.

It looks like he has disconnected. Would you like to move to the next question?

Yes, move to the next question. But let him back in, if he gets back in.

Yes, move to the next question. But let him back in, if he gets back in.

Our next question comes from the line of John Freeman of Raymond James. Your line is now open.

You all have done a great job here, balancing kind of the development activity with the delineation efforts. And if I sort of think, hypothetically, if you end up with a much higher oil price than you all are budgeting, where should I anticipate the incremental activity would be focused?

Well I think that it somewhat depends on what our decisions would be. I would think that if we were to kind of go down your hypothetical there and that oil prices were quite a bit higher in six months and we were looking to add a sixth rig, I think that it would likely probably go into a combination of the Loving County area as well as probably some of the stuff that we have over in analog bridge that I was just mentioning. I think that if we -- yes, the Red Hills area. So I think if we were to be able to add an incremental rig, I think it's probably more likely that that's where the next one would spend some time. But certainly with -- if we had some early success at Twin Lakes, that could also be a candidate.

That's very helpful. And then just I wanted to follow up on these sort of more modern completion jobs, with the 3,000 pounds, plus. What have you seen for the incremental cost uplift?

John, this is Matt and we've renegotiated our frac pricing just recently. We had a great price in 2016. So the incremental cost for the upside, it depends on what we're talking about. When we go from 2,000 pounds of proppant to 3,000 pounds of proppant, you're looking basically at an increase in sand costs. So once upon a time, we were paying $0.45 a pound for sand. We went to $0.045 a pound. Now we're back around $0.06. So it's not a huge cost. when you think about how many barrels it takes to pay for those. So some of the other things we've done, the diverters we talk about, that's a minimal cost. We're probably looking at certainly less than $50,000 per well. So that pays out very quickly. The latest thing we've been doing which we're really excited about, is reducing the distance between perf clusters. We went started at 50. We went to 35. We've done some at 25 and the total well we did was 20 foot perf clusters. And so there is an increase in horsepower there. The amount of proppant per foot is the same on that Totum job; it was around a little less than 2,000 pounds per foot. So that doesn't change. The amount of fluid doesn't change. The horsepower charges do. So we're adding a few hundred thousand dollars, if you will, by making that change which again pays off in just within a few months with the better well results.

Our next question comes from the line of Richard Tullis of Capital One. Your line is now open.

Joe, keeping with the well cost theme, what are you seeing overall on well cost and maybe even OpEx cost inflation pressures currently in AFEs or captured in the 2017 budget, if any pressures at all?

Interestingly, as we said in the news release, we're anticipating overall some increase in vendor cost, we estimate right now maybe 10% to 15%. Our operations staff has done a good job. In some areas, the costs have actually come down. The frac costs have come up. They bottomed out last year. They've come up a little bit. So it's difficult to say. But let me give you -- Billy Goodwin's head of our operations. Billy, how would you respond to that?

Thanks, Joe. I think you are right on. We've got the 10% to 15% budgeted in. We're hoping to keep that at single-digit into next year. We're getting pricing agreements in place with our different vendors for services. And we've actually seen some of the costs come down, like you mentioned there. So I think all in all, we're hoping to get it into single-digit. We're staying out front with technology. And we're always talking about the new things we're doing on the completion side. And we've gotten into the diverter technology, new plugs. There's new ideas, new things we're trying, dissolvable technology, recycling our water, retreating it. We're saving a lot of money there. So we're offsetting the cost increases with getting better and getting more efficient. And also on the drilling side, we'll just throw out to the guys there who are looking at new bids, new bid technology, trying new things out there. We just pulled a bit out of the hole that looks great, had a great run on it in a well, just last night. And going a step further than what we've done in the past, we're actually going -- and we meet with the account managers and the people that are local and the guys in the field. But the guys are even setting up trips to go meet the scientists and engineers that design the new bids and BHAs at the plants and get on good terms with them and really look at exactly how they are being built right there at that point and getting even better, that deep into things. So anyway, I think we're going to be offsetting these cost increases and optimizing all the way across and even in the facility, like we talked about earlier. So we're going to keep doing that.

Richard, this is Matt. We think about cost a lot. But when we talk about vendors we really think about three things. We think about price is one thing. We think about value or quality, if you will, as another; and then availability. So you know the rig count is almost double since it bottomed here a couple of years ago. So we get a lot of questions about availability. And so through the course of 2016, when availability wasn't an issue, we selected vendors that we knew coming out of this thing would be there. We think and hope and expect that the pricing is going to be sticky, as we call it. We were with those guys when things were tough. And we've had discussions with them about how quickly they will raise our prices and specifically how much availability we will have. So we're very comfortable going into the year with this 10% to 15% increase that we're talking about.

Thank you, Matt. That's helpful.

This is Brad Robinson. I just wanted to elaborate a little bit on what Billy was talking about. I'm really proud of our guys, as far as the applications and the new technologies and so forth that they are using. Billy mentioned like the dissolvable frac plugs that we're evaluating. They -- if we can get those to work out there in the Permian Basin that's going to eliminate probably $50,000 or $60,000 in coil tubing clean out cost. So a lot of the new technologies are adding to our cost savings. And so we're really excited about trying some of those new things.

Thank you, Brad. So Matador has done a real good job monetizing the midstream assets over the past year and a half or so. How do you view say potential E&P asset sales, Eagle Ford and/or Haynesville, at this point? How does that fit in plans and how are you viewing that?

Richard, thanks for the question. Matador has had a long history of making deals on assets of various kinds, whether midstream or E&P. If you remember, we sold old Matador to do more in the shales and the unconventionals. And then once we were into that we sold part of our interest in the Haynesville to Chesapeake which set us up to go down into the Eagle Ford and put together an oil leg. So we had a gas leg and then oil leg from some of Chesapeake. And then from there, we started building a position in the Delaware. And the EnLink deal enabled us, gave us further capital without having to return and just sell more stock; and has helped propel our further growth in the Delaware. So we've always tried to show that whenever we're serious about making money and value for the shareholders. And so whenever someone comes in and makes a serious offer to us, we will give it serious consideration. And we've tried to make that clear for over a year that we were going to put, in the foreseeable future, most of our capital in the Delaware. We were going to -- you know that we thought we had good assets in both the Haynesville and the Eagle Ford. But if someone came in and made an appropriate offer, we would give it the appropriate consideration. One thing we've tried to do is we don't necessarily need the money. We just did the midstream deal. So we're -- you know, we like the asset. There's a lot of potential still left in the Eagle Ford. We've only completed in the lower Eagle Ford. It's becoming apparent that there are further opportunities in the upper Eagle Ford or in the Austin Chalk, upper and lower Austin Chalk. There's even workover possibilities. We have felt the opportunity set in the Delaware was better. Although the economic returns of just drilling are about similar, you just have so many other zones and that's where the acreage was not yet HBP. Virtually everything in the Eagle Ford is HBP and everything in the Haynesville is HBP. So that gives us an oil bank and a gas bank that we don't have to get to. But we will monetize. And we had made it pretty clear we were going to monetize either part of the midstream or one of the E&P assets. It just turned out midstream happened first and we're still open to that. We're certainly aware and appreciate the opportunities there. It's great cash flow. But if we got a serious enough offer, we would act upon it. If not, we will continue to maintain those leases and keep them as an oil bank and a gas bank and use the cash flow to enhance our position either there or in the Delaware whichever has the best economics. And they are still very good. You could do very well with some of the opportunity set in the Eagle Ford and the Haynesville have been coming back. So it's some high-class choices that we think we have. David? Matt?

I think you make of a very valid point, Joe. Everything we did in the Eagle Ford -- it was really great. And we were drilling there and it still is great. But everything we did is in the lower Eagle Ford. So in the upper Eagle Ford opportunities, in the Austin chalk opportunities, we haven't exploited. And even the Buda potential on our acreage block we think is very high. So there is a ton of value still out there. And we've got a lot to do in the Delaware and we've got a lot we could do in the Eagle Ford and the Haynesville too.

Thank you. And just one last quick one, what's your total net investment in the midstream assets that were contributed to the JV?

Matt Spicer?

Sure. When we look to monetize an asset, we kind of look at the return on capital and that's one of the metrics we look at. And like our similar deals that we've done in the past, we're right in that 4, 4- to 5-to-1 multiple on invested capital. And that should give you a pretty good idea of what we have invested.

That's helpful, thank you. Appreciate all the answers.

Well, thank you, Richard. And we appreciate all of you listening in. Nicole, I think that was the end of the questions.

Yes.

All right. Well, guys, if you see Neal, tell him we did not cut him off. Tell him to call us back. But I would like to thank all of you for your interest, questions and participation. Your questions today were very, very good, on point. We appreciate them. And if you have follow-ups, please let us know. As we hope you could tell from the call, we believe our opportunity set in 2017 is very strong in each of our areas. We're in an enviable financial and operational position to address any challenges we have, as well as to take advantage of the opportunities in each of these areas. But, you know, we're about making money. And whatever uncovers that value is what we want to do. And we're going to continue -- Matador is going to continue to try to uncover and convert its opportunities into long term value; that our Board and staff are big shareholders. And we make more from our shares than we do from our salaries and we want to keep that culture and tradition up. We look forward to visiting with all of you again soon. And we invite you all to come into Dallas and see us and meet with our young staffers and us and get to know us better, because we think that's a key in going forward. And with that, I'm going to sign off and thank everybody again, both here and on the line. And we hope to see you all soon. Thanks. Bye.

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