Matador Resources Co (MTDR) 2015 Q3 法說會逐字稿

Good morning, ladies and gentlemen, and welcome to the third-quarter 2015 Matador Resources Company earnings conference call. My name is Shanice and I will be serving as the operator for today. At this time, all participants are in a listen-only mode. We will facilitate a question-and-answer session at the end of the Company's remarks.

As a reminder, this conference is being recorded for replay purposes. And the replay will be available on the Company's website through Monday, November 30, 2015, as discussed in the Company's earnings press release issued yesterday.

I will now turn the call over to Mr. Mac Schmitz, Senior Financial Analyst for Matador, who also manages the Company's Investor Relations.

Mr. Schmitz, you may proceed.

Thank you, Shanice. Good morning, everyone, and thank you for joining us for Matador's third-quarter 2015 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, its most recent annual report on Form 10-K, and any subsequent quarterly reports on Form 10-Q.

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. In addition to our earnings release issued yesterday, I'd like to remind everyone that you can find a short presentation summarizing the highlights of our third-quarter 2015 earnings release on our website, at www.matadorresources.com, on the presentations and webcast page under the Investors tab. This eight-page summary is intended to supplement and try to improve or make more meaningful the information contained in this news release, and I hope that you like it. And if so, please let Mac know.

Now I would like to introduce the senior members of our operating staff joining me on this call this morning, 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, Executive Vice President of Land, Legal and Administration; Brad Robinson, Vice President of Reservoir Engineering and Chief Technology Officer; Van Singleton, Executive Vice President of Land; Billy Goodwin, Vice President of Drilling; Gregg Krug, Vice President and Head of Marketing and Midstream; Matt Spicer, our new Vice President and General Manager of Midstream. So this is a promotion, and this is his first duty as a VP answering questions. So feel free to test them out in this session. (laughter) Trent Green, Vice President of Production; Rob Macalik, Vice President and Chief Accounting Officer.

The third quarter of 2015 was full of milestones and achievements for Matador, and I would like to emphasize three key points to note on this call before taking your questions.

First, this year, 2015, will be one of the best two or three years in Matador's history, despite the lower commodity price environment we have faced. The Board and the staff are doing very well on the factors they can control. For example, this quarter was the best quarter we have ever had in terms of total natural gas production, and our second-best quarter ever in terms of total oil production. And our total BOE production year-to-date has already surpassed our record BOE production for all of 2014.

Second, the Delaware Basin opportunity set continues to impress us. We have now tested at least 11 production horizons in the Delaware, where we are seeing improved oil and natural gas recoveries. Drilling times and overall well costs continue to improve significantly, and help mitigate the lower commodity price environment.

Finally, three, third, our successful midstream business -- consisting of natural gas processing, saltwater disposal wells, oil, natural gas and water gathering systems -- are continuing to add value to each Matador share of stock, both as an asset of the Company and as a way to cut costs and make our oil, natural gas, and NGLs more available to the market.

With that, I would now like to turn the call over to the operator for your questions.

Shanice?

(Operator Instructions). Neal Dingmann, SunTrust.

Joe, for you or the team, maybe start with just a first midstream question. You mentioned in the press release about doing something and building something out now at Rustler Breaks, the processing cryo now, which should obviously have some size to that. Can you talk about timing and potential size or, again, how quickly that could come on?

All those questions are being decided now. We expect the plant to be bigger and better than the plant that we had in Wolf. There's things you learn on any construction project. You want to take those lessons learned up there. It will be bigger. We want to give a lot of credit to EPC for the way they've worked with us in both places. And so that design phase and that construction phase is happening right now. We're locating the property, doing all those steps.

So it's still in the formative stage, Neal. All that I would say is that we think that -- we believe, or know -- we are going to build something bigger and we believe that we can make it even more efficient than the other plant, which is doing very well on its recovery. So, very pleased with the way that started right out of the box. And really, it operated from day one with -- outside of a valve that maybe needed to be replaced, it has been on. The design has worked. But we still think we can make it a little better than that.

You mentioned about timing. And I think as we put in the release, our goal is for that to be on by midyear next year. So sometime in the third quarter, we think that that plant will come online at Rustler Breaks.

And, David, the thought would be to fund that with a separate credit facility, at least partially?

Well, I think that actually we have a lot of optionality there, Neal. We are certainly, as we mentioned, going to visit with our lenders about putting a separate credit facility in place. And I expect that we will do that. They are interested in working with us on that. But as we have spoken about, even with the first plants, there were a lot of options for us in terms of other third parties that were interested in financing or JVing with us on the plant. And I think it's still early. We are still looking at various opportunities. But certainly, we are going to work with our banks to put a facility in place.

Understood. And -- go ahead.

This is Matt. I'll just jump in here with Joe and David and then just mention the strategy around this plant is very similar to what we had at Wolf, where it's servicing Matador's needs first. The plant is going to be a little bigger because we're going to have a little more gas volumes. But the strategy is the same. We are building it for our own use, first and foremost, and to make sure that we are able to efficiently process our gas.

It's a great question, and I do want to underscore what Matt is saying there. As you know, the gas out there in the Delaware is 1,200 BTU or so, so it's too rich for pipeline quality. You've got to process it to get it into the pipeline. So it's necessary. And as Matt said, operating it ourselves and having that capacity, we can lower costs and obtain priority on takeaway of the gas.

And Dave is right, too, that there's just a lot of options there. So it's a complex decision. But we like our position, and we like the options. It's some really good choices that we have ahead of us.

Now, good, great. And one last one if I could, Joe -- I know you've had some fantastic -- continue to have some fantastic results at Rustler Breaks and Ranger. Just your thoughts on drilling plans regionally and the excitement level of other areas, maybe like Twin Lakes and some of these other areas that you haven't drilled as much yet?

Is that we are -- we have spudded the Twin Lakes well, so that's going to be tested, as we said we were going to do. We are drilling a pilot hole there and obtaining the data; and, as we always do, we're going to work through it very methodically. But we are excited to have that drilling now.

Rustler Breaks and Arrowhead are continuing to be focal points. We tried to provide information in there of a number of non-operating wells that we are participating in, in the Arrowhead and Ranger area. And the advantage of participating in these -- these are de-risking a lot of that acreage for us, where we have not had to do so. We like that area very much. It does require more work because the interests are more fractionated. But we are proceeding steadily along.

David, anything to add?

No, I think you covered it very well, Joe. I would just say that I think the technical teams here continue to be very excited by the opportunities that we see across our acreage position. And I think you can see by the map that Joe was referencing that we put in a little presentation that really, from the south to the north of our acreage, we are drilling exciting wells, whether they be Wolfcamp wells or second Bone Spring or third Bone Spring or As or Bs, there's opportunities all across the position. So I think we still have a very high level of enthusiasm, Neal.

I'm sure, as I've said to you and others, I think that the Company is in a great position right now, and has really got one of the finest opportunity sets out in front of it that we've ever had, probably that we have ever had. So we continue to be very excited about what we've got.

And Neil, just so you know, the non-ops are on that presentation that is on website under the presentations tab. So tried to make that easier for you, looking at what non-op activities we have going on.

That's helpful. Thanks, Joe. A great quarter, guys.

Irene Haas, Wunderlich.

My question is focused on Arrowhead. It looks like you've hit a really nice second Bone Spring sweet spot. Just wondering whether there are other horizons that you are interested in. And then, when you guys get ready to drill next year, do you have ideas other than what your competitors are doing right now? Because usually Matador adds its own little twist in there. And also, lastly, how is the infrastructure situation at Arrowhead?

Well, let me begin by letting Ned Frost, our head of our geoscience group, just address the multiple horizons.

The Arrowhead acreage is -- you hit the nail on the head; looks quite good for the second Bone Spring. And I think that's probably what we will start out with up there is looking at that. But we think there are certainly other horizons to look at, essentially first Bone Springs and third Bone Spring up there as well.

We are exploring the Wolfcamp also. I think that would be a little bit further down the road for us. Potentially, Avalon -- and Keith Svatek, our Ranger/Arrowhead team lead, is weighing in on that as well. So there's Avalon potential up in that part of the basin also.

Would the Bone Spring get a little gassier?

It doesn't appear that way.

(technical difficulty) Wolfcamp? (multiple speakers)

It doesn't appear that way. Yes, I think, actually, the -- sorry, Irene. Go ahead.

I'm sorry. If you were to pursue the Wolfcamp, would they be gassier [in May]? Just curious.

I think that we feel like, Irene, from what we've seen, the Bone Spring wells up in that area -- and you can again see it reflected on what we've shown -- our experience has been they are 80%-plus oil. A lot of the wells tend to be 90% or better. Our Ranger well, our Pickard well, and even some of the CTA State wells that we reference are 90%.

I also that we feel like that the camp will be oilier as we go north up that way. So I think our expectation is that we will see more oil as we go to the north.

And I'll weigh in. Irene, this is Brad Robinson. We've mapped gas/oil ratios for all the different zones across that area. I'll just agree with David that particularly the Wolfcamp, that part of the basin, is very oily, much different than the southern part of the basin. And so we do expect the Wolfcamp and Bone Springs sands to all be mainly oil productive up there.

And what's your AFE?

I'm sorry? Cost estimate?

Cost, yes.

Yes. So I think, Irene, that up in that area we are probably looking at Bone Spring wells in the $5 million to $6 million, $5.5 million to $6 million. And it gets a little bit more expensive as you go toward the east because it gets a little deeper. And then the Wolfcamp would probably be incrementally about $1 million higher than that.

Great, thank you.

You are asking a question about infrastructure. And as we've talked about before, most of that is acreage in Arrowhead is held by production. So there is a significant amount of shallow production in the area. Therefore, the infrastructure is in place. That being said, we will do the same type of evaluation that we did at Wolf and have done at Rustler Breaks in regards to what infrastructure we need to put in place, whether we need processing, disposal. Whatever we need there, we will evaluate that as we get further down the road.

Great, thanks.

Gabe Daoud, JPMorgan.

Just wondering if we could start maybe on the Scott Walker well, and how results compared to your expectations.

Well, I'm going to start out, and then we will pass it around the horn, Gabe. But we were pleased. The Scott Walker started out as, really, a data point well that we were just going to drill a pilot hole. And then, as we drilled into that, we saw a number of zones that we liked and elected to test the Wolfcamp for strategic reasons because as far north as it was, if it was successful in the Wolfcamp, then you proved up the oil layer from north to south. So we were very excited when we completed it. We made an oil well out of it. The IP is not spectacular, but that wasn't the point of drilling to the Wolfcamp; it was to confirm the oil presence. And we have been pleased. We would describe it as a real solid well. It's held up very well in that 300-barrel-of-oil-a-day range.

And in addition, it validated -- we have a 640 there from the State, so that one well will hold that whole 640. The other zones that we will drill will be optional. And we think in the Bone Springs, it had a couple of really -- if you were just drilling that well alone, you would have probably completed it in the Bone Spring because there's a couple of very good-looking zones. But we wanted to try the Wolfcamp, and we feel like it really answered the question that opens up that whole area, not only for drilling but also for infrastructure.

I'll jump in here, Joe. I think what you said is exactly right. What it does with the wells we have in the south, and this well in the north end, it pretty much proves up all that acreage from north to south. And additionally, in regards to the infrastructure, it gives us some indications on what we need to build, and where we need to build it. And we can get started on that sooner than later, and have the entire acreage position ready for drilling.

I would just toss in that, because -- it was an important well from a data standpoint for us, too, in that we were able to drill a pilot all the way through the Wolfcamp B in that well, and had some nice shows in the B, some things that were interesting. And in addition, as Joe mentioned, some really good-looking zones in the second Bone Spring and even the first Bone Spring.

So overall, I think we were pleased. We did elect to complete the Wolfcamp A in order to see if we could ensure that that play was going to work all across the acreage, as Matt said. And I think we have. So I think we thought it was a good well.

Ned, do you want to add anything?

Yes. I'll just reiterate what everybody has said. I think, taken in isolation, that result -- we are happy with how that well is performing. It's certainly not the exact same as Tiger and Guitar. But that's part of understanding the acreage up there. And really, that was quite a large step out for us and, I think, very important test for us, as everybody has alluded to thus far. And really, it's the furthest north that anybody has tested the X-Y sands in Eddy County, and essentially in Lee County as well. So for us, again, to hammer this point home, is it really is giving us a better understanding of what the landscape looks like in Rustler Breaks.

And to hit it again, the first Bone Spring looks prospective; second Bone Spring looks prospective; potentially, Wolfcamp B, as well. So I think it's quite an encouraging result for us.

Appreciate the color, guys. Just one follow-up if I could, maybe just switching over to Loving County, specifically Jackson Trust. Any initial thoughts there on that three-well batch? I know it's in completion phase now, but any thoughts on those shallower targets?

Well, I think that we were very encouraged as we drilled through the wells, Gabe. So we did the wells in a batch mode, so they are all three off the same pad. So they are all right there together: one Brushy, one Avalon, one second Bone Spring. It is, of course, our first test of the Brushy and the Avalon in this area. But we are encouraged by the results of some of our peer companies around that area.

We have just finished fracking the wells and getting the plugs drilled out. So I don't think it will be too much longer until we begin to be able to flow back to wells and see what we have there. But we are encouraged and excited to see the results.

When we were drilling those, we ran a mass spec log, so it's giving us an indication of hydrocarbon (technical difficulty) as well as presence in the mud stream there. And we are really getting quite good shows in the Brushy Canyon, the Avalon, and in the second Bone Spring. So we are quite [impressed] by what we saw, even while drilling. Also the data we selected from the pilot holes to come up with these three wells still look quite good. So we're looking forward to getting these online.

Great. Thanks, everyone. I'll hop back in.

Scott Hanold, RBC Capital Markets.

In looking on your map on page 6, certainly you've got a pretty good delineation in terms of some of the extent of your acreage. Obviously, the Scott Walker well, down to Loving, and some of the stuff in northern Ranger. When you look at your budget for 2016, and this case you laid out at the prevailing oil prices, that you are running three rigs. What should we expect for 2016? Is it going to be more -- a lot of delineation yet going on? Or is it going to be more of really trying to focus on what your best rate of return opportunities are?

Scott, it's going to be a mix. And your three existing rigs are state of the art. They are set up for simultaneous operations of walking packages. We are going to endeavor to put them in situations more and more for its development on the same pad, somewhat like the Jackson Trust, where you have three wells drilled from the same pad; or in a development drilling where it walks over, for the most part.

And I would say ideally, if we could, we would have one in Wolf, one in Rustler Breaks, and one working the Arrowhead/Ranger area. But they will move in between those areas, as needed, and looking for efficiencies there. But ideally, one would go in the other. On the delineation phase is -- we've done a lot of that work. There's a lot more has to do because there are a lot more zones that are involved today than what we originally thought. But that's the advantage of having those rigs with simultaneous operations. We can do more of that.

So I would say that -- think of it in terms that we are going to be moving increasingly to development, and delineation will come down as far as these three rigs. Now, if oil prices should surge, and start to move up to the $60 level, as that occurs, then the likelihood of the fourth rig will increase, too, as we approach -- go over $50 a barrel and approach $60, if that scenario happened.

But that probably won't be a state-of-an-art rig like this. It will be more of a rig that's easy to move; won't be as expensive to drill the delineation wells.

So Matt, did I say that right? Or is (multiple speakers)?

Yes. No, I think you said it just right, Joe. In regards to this other rig that you are talking about, what we would do is to put together a rig that would have a lot of the operational efficiencies. The higher pressure, 7,500-horsepower pumps would be critical. The time ops capabilities would not be so critical on that rig. But we will have lots of things to do in 2016, Scott.

And even in regards to [vertical and horizontal spaces] we've got -- that's part of the delineation and development process, is for us to figure out vertically how to space these wells as well as horizontally. And we are headed down that road, as we speak. And we've got some tests going in the various areas on spacing. So that will be an important part, as well.

Yes. And I appreciate all that color. More specific to the point I was trying to get at is, do you think at some point in mid- or late 2016, where you guys can step back after all the work that you've done and your partner has done, can say, okay, in the Wolf area we are doing pad development; our primary target is going to be the Wolfcamp, this Wolfcamp formation in Rustler Breaks; this is what we're doing, this is our primary target -- do you sense in the next, call it, 12 months, we will be to that point? Or is there just so much to do here that it could take a little more time?

It's an interesting question. But I think it could be a little bit different than what you've proposed. I'm not sure that we would necessarily look at it in terms of just drilling multiple wells to the same formation all the time. But we might be looking more at moving from pad to pad, and drilling multiple stacks of wells. So I think that will be part of the discussion that we will have going forward. We've done that in two- or three-well batches. We are about to embark upon a program in Wolf, where we are actually going to drill four from the same pad stack.

So I think, as we move forward, there may be more of the potential for us having a large pad from which we drill multiples of wells as opposed to drilling all of one formation and all of another. But again, that's just going to be a function, I think, of us beginning to understand what's right, in terms of the spacing, both horizontally and vertically on this stuff.

One of the things, Scott -- a little footnote on that is when you are drilling on the stack, you may be able to -- we're trying to see exactly how much savings you have. Because you don't -- if you are drilling from the same pad, you are not having to move the rigs, you are not having -- you can save money on logging. There's a lot of little ways to save money that don't cut back your recoveries any; just makes it less expensive to drill and faster to drill. Because you remember, a lot of the savings that we are achieving on drilling is coming from cutting down the number of days on well, and not just coming from service cost reductions but the true efficiencies of reducing drilling times and being able to do things that don't require expenditures. You get your logging down, program, where you don't have to do that the same way every time.

I think also when we get into this development phase, like David and Joe are talking about, then we can utilize the simultaneous operations capabilities of these rigs. So we will be -- while we will be drilling four stacked laterals, we can also be completing as we are drilling, which will reduce the spud-to-sales times, versus having to go in and drill all four of them and then complete them after the drilling has been done.

Okay, I appreciate all that color. And by my math, I asked 1.5 questions because I extended that first one. So I'm going to try to sneak another one in here, and maybe test Matt on the conference call here.

But the infrastructure is obviously, in the Delaware Basin, going to be important. And you guys obviously have been trying to get in front of that. Can you discuss, bigger-picture, long-term, what do you think your greater infrastructure needs are? Obviously, Rustler Breaks is the current focus. But where do we move from there, and how much more is needed? And if you could, as part of that, talk about how much capital -- and without respect, necessarily, of to how you are going to fund it yet -- but how much capital is it going to require to do this build-out over the next few years?

Scott, we have not taken it that far. The first is trying to determine needs. As Matt tried to make the point, we are not doing this to go in, quote, the midstream business. We are trying to do it as a necessary adjunct to our own exploration and production activities. Because, as I mentioned, the gas is not pipeline-quality until you've taken out some of the fluids. But the other parts of our midstream are saltwater disposal. There are not a lot of saltwater disposal wells out there that can handle this. So you need to do it yourself.

Now, our staff -- kudos to our staff. They figured out this water is potentially compatible with our frac operations. And they are recycling the water in such a way that we are saving a lot of money on our fracs from having this water, recycling it; and then we are taking on some third-party water and making a little money from it that helps underwrite and further reduces costs.

So there's a number of these factors here. And it's really hard to determine, because we can't predict who else is necessarily building cryo plants or gathering systems or saltwater disposal. That has to be taken up as you go through. The cost of planning is not very much. And so it's easier to plan for all of this. And if someone doesn't step up, we are going to be ready to move ahead. But it's going to, again, be on a selective basis that is additive and enhances our base and core exploration and production.

As an example, we want priority on our gas going away so it doesn't get flared. Well, you have a better chance of that when you operate your own plant. So you have heard me make the analysis: this is like being a cotton farmer. If you are a cotton farmer and you also own part of the cotton gin, you have a better enterprise than if you limited your ownership to one or the other.

So the deal, the way it works -- it isn't that the midstream guys come in and say, hey, I've got this project. The midstream is done in conjunction with what Matt and Billy and the team leaders are doing, and trying to coordinate that way. So I know it's going to be an active part. We are committed to building a plant, haven't fully decided how large. But that was one point in drilling the Scott Walker, to see if we wanted to extend it up north, which appears to be something that we want to do.

So that's underway right now; hard to say. But I think, Scott, we will have a lot better number at Analyst Day that we expect to be late January, first of February. And I think we have indicated that.

David?

No, sir, I think you answered that question very well and thoroughly. I don't know that I could improve on that.

He doesn't always say that, Scott, as you know.

(laughter) It's getting to be bonus time, Scott.

I'm glad this call is being recorded (laughter).

There you go. You've got proof now. All right, fair enough, guys. Thanks.

(Operator Instructions). Mike Scialla, Stifel.

You mentioned in your release -- I guess I'll call it a base plan of maintaining the three rigs next year, if oil prices stay about where they are now. What does your modeling say production does under that scenario?

I think that we expect to have probably on the order of plus or minus 10% oil growth under that scenario. And on the natural gas side, we may be fairly flat from the standpoint that -- Chesapeake has actually drilled a few more wells this year than what we had originally anticipated. So I think, as can be evidenced by the fact that we've raised our natural gas guidance a couple of times, that number is going to be a little higher this year than we originally anticipated. And next year, they are finishing up the program there. So our natural gas production may be flat to even a little bit down.

So I think we still think we will have -- on a total production basis, we will still have single-digit production growth, probably a little higher on the oil side, and a little flattish on the gas side is what we're looking at. But again, some of that always depends, Mike, on just the mix of wells that you ultimately choose to drill.

So I think that, as we firm up our plans toward the end of the year, we could decide on a little different mix or a little different program than what I'm currently modeling. So I will be able to be a lot more clear and specific on that when we get to Analyst Day. So don't shoot me if that number is a little bit different when we get there. But, again, I think that's the direction that we see.

I'm just going to jump in here and add to what David is saying. If we are looking at these type of numbers, that's clearly a reflection on what we focus on and talk about, in here, about operational efficiencies, what we are able to do with three rigs. We are drilling the wells in half the time we were last year. So we are able to drill and complete a lot more wells in the course of the year.

Got it. Okay, that helps frame it up. Realize it's still early there, appreciate that. The third-quarter production mix, a little gassier. Was that you to some Haynesville wells coming online, or something else going on there?

No; I think it was primarily due to some Haynesville wells. But like I said, we had a couple more wells that came on early in the third quarter that we had actually anticipated were not going to come on until later in the year. And that just gave us a little bit more gas production than what we were forecasting for the quarter. But nothing more to read into it than that.

Mike, one other mention on the Haynesville -- if you will remember, we have an 85% to 90% net revenue, and we market our own gas. Those wells, when first drilled, they don't have severance taxes for the first couple of years. So those are actually -- we are earning a very good rate of return on those wells. And again, they have held up very well. And Chesapeake's costs on those wells have continued to come down. But the wells seem to -- are doing just as well. So I think they've done a good job. We are pleased they have the higher net revenues, so that we are enjoying that extra 15% or so.

So everything that we are drilling, we believe we are making money on. And the more we drill a lot of these wells, the better we are doing on our rate of returns. We estimate, for everyone $100,000 savings, you are increasing your rate of return somewhere between 1% and 2%, depending on type of -- what formation you are drilling to, and just exactly where you are and a little bit on the recoveries, all of which is a dynamic process. But that starts to make a lot of difference, particularly given the number of wells in our inventory that we still have to drill for years to come.

So I think the staff is just making a lot of progress. The land people are doing a good job clearing some of these locations. So that gives us more choice in deciding where to put these rigs. We are not just doing it for the here and now; we are trying to mix in some longer-term -- like the Scott Walker and the Twin Lakes well -- as well as what Matt says is confirming the advantages of drilling batch wells from the same location to different [horizons] as well as delineating the spacing pad pattern.

So it's a great job. As you know, our people like to get around a table and discuss things. And the teamwork is -- I would like to commend the whole staff for what I consider excellent teamwork that just gets better. And that all those guys, the team leaders, are really making an effort to learn all parts of the business, from the infrastructure to land to geology to engineering. And I just really appreciate all their extra -- I would say, for the whole executive committee, we appreciate all their extra efforts.

Great. If I could squeak one more in, I just want to get an idea on how you would characterize the acquisition market in the Permian now, both from an organic leasing standpoint, and just E&D in general there versus maybe a year ago, given that oil price has been low here for a while now.

I really haven't seen much change. I think it's a statement about the quality of the assets out here, and the opportunity is the fact that undeveloped leases have continued to hold their value so well. You hear instances of sales, but they are still hard to make. We have enough on our plate that we are not really very active in going after producing properties because of the large amount of undeveloped acreage that we have that earns a better rate of return than what you can generally achieve from an acquisition of producing properties.

But I would like to have Van comment, because Van is actively out there nearly every day, trying to find things and test the market.

Van, will you respond?

Sure, Joe. We are seeing, still, a good active deal flow, and have through the year. Prices have remained steady. Deals have always been difficult to come by. We have been very fortunate, in the Delaware, to get what we have, and we are still seeing new opportunities.

So we continue to evaluate new opportunities. The team is doing a great job in their evaluations. There's a lot of folks in the market right now that are just waiting to see what oil prices are going to do. It has been pretty steady.

This is David, Mike. I'll just add one last little comment. And that is, I think I will commend our land group and say I think we have been excited, too, about the opportunities that we have had to be able to pick up acreage within the core areas that we already have. So as we have proposed and drilled wells, there have been opportunities for us to pick up additional interest in some of those wells. There's often some unleased interest in the units, and our guys have been very diligent in terms of picking that up. And we are seeing opportunities to add nice pieces of acreage, in and around our core areas, too. So very pleased about that, and still actively looking to do that.

And I think, just overall, we've grown our net acreage in the Permian by 40% this year. So we started the year at about 66,000 acres and we are up to about 91,000 acres now. And of course, that's more than tenfold where we were when we went public. So again, this was always going to be a third leg of the stool for us. And I think that our land group and our teams have just done a tremendous job of establishing this position for us in the basin. I think we had about 7,500 acres out there when we became a public company.

So I think it has been a great achievement. And we tried to highlight that a little bit in the presentation that we sent around. There's one of the slides -- I think it's on page 5 -- that in the lower right-hand corner, we had put our growth in the acreage in the Permian over the past several years. So overall, I think we are still seeing a lot of opportunity out there.

David, that's a great point. And I just wanted to add one thing is that if you look at the growth of our acreage over the past few years in the Delaware Basin, it has been a very steady growth. It has not been just buying blanket acreage across the basin; it has been very selective. And so we continue to be selective, and just try to buy the best properties that we can. So I just wanted to add that piece, that it does show that over the last few years.

Yes. Mike, we would welcome, as always, more deal flow. But I think people are -- these assets are good. And it's always hard to get good assets away from people. So I'm glad we've got the position we did. I'm glad we started as early as we did. And I'm very excited that our technical staff keeps coming up with more zones to test, and keeps finding better ways to do it.

So really have -- this has been a challenging year. But it has been gratifying in that it's going to turn out to be one of our best, too. We've done the HEYCO transaction. We've done the EnLink. We've issued our first bonds. We had an equity offering. We've resolved a number of things nagging. We've added capability in the midstream. So I think our staff is really due a lot of credit. And I appreciate you asking that question so I could brag on them a little bit.

That's great. Thanks, Joe. Thanks, guys.

Jeff Grampp, Northland.

I wanted to talk a little bit more about the Wolfcamp and Rustler Breaks. With the -- you guys are drilling this test more in the central part of the project. Just wondering, maybe geologically, how you guys have seen -- you've got a couple data points to the south, and now this data point to the north -- just geologically, how you see this formation changing across your project. And, I guess, just setting expectations -- should we think of this upcoming well more as a science project, similar to this most recent well? Or do you guys think it's a little bit more de-risked, more of a development well, given it's a little bit further south?

Jeff, we try not to drill any wells as science projects. We want every well we drill to make money, and that's what we go in to do. And I think we will make money from the Scott Walker. And I believe we will make -- I think you're referring to the Dr. K well. Is that right?

Yes. I don't think we identified the name of the well in the release, but that is the well he's referring to; yes, sir.

Right. And we expect this to be a good well, and just be a further delineation of the Wolfcamp in there.

Ned, do you want to add anything to that?

Yes. I think, as we've alluded to earlier in the call, the Scott Walker was an important test to understand how the Wolfcamp changes across our acreage. And it is -- the Wolfcamp B source rock is potentially a little bit thinner up there to the north. And the X and Y sands are a little bit thinner in Scott Walker. But once you come down to Dr. K, you are starting to see a lot more of the properties that we saw in both the Tiger and Guitar, in terms of source rock that's reservoir quality.

So we are quite optimistic about the center part of the acreage. And we feel that, again, the test in Scott Walker was important for understanding that, and beginning to delineate and really rank the acreage. But Scott Walker really doesn't change our view of being very optimistic about the Wolfcamp and Rustler Breaks. If commodity prices cooperated a little bit more, Scott Walker -- we would probably be looking at it in a slightly different light. But right now, where we are at, we would probably want to add more results like Tiger and Guitar, obviously. But --.

For the Wolfcamp.

Yes.

But the Scott Walker's first and second Bone Springs is so strong you could easily have a development program there. And that's probably what you are weighing is good, better, best, between the Wolfcamp and the Bone Springs at the Scott Walker. And then, as you get down to the Dr. K, is it going to be Wolfcamp more like the Tiger and the Guitar, which have performed so well? Or is it going to be Bone Spring has performed so well elsewhere in the area?

So it's a nice setting to drill that. And we think, either way, we are going to have a good result and be able to set up some further development drilling in the Rustler Breaks area, Jeff.

Okay. Appreciate the color on that; that's real helpful. And then just wondering, on newer frac design generations -- obviously, you guys have a great track record in the Eagle Ford, and starting to get your legs under you with different fracs here in the Delaware. Just wondering what you guys are seeing on some of these recent tests. And maybe a little sneak peek at Analyst Day, if we should be expecting some further design changes, or just what you guys are thinking on that front, moving forward in the Delaware?

Well, Jeff, you know probably how we work. We do a postmortem on every well that we drill to see what maybe we could have done better. The frac designs are being examined. They are evolving some. But you have a more complex frac questions to address because you have basically three different types of rocks. You've got the shales; you've got the micro-coupled; and then you have the more conventional sands, or, in the Bone Springs, maybe tight gas sands.

So you got -- you can't frac them all the same way. But the basic concept is still valid that generally more profit, more fluid is better. Now, exactly how you do that, and how many stages is one that that will continue to evolve. But the technology is working. You don't know what Schlumberger and Halliburton have up their sleeve that will further enhance it, and what advances some of the other operators are doing. And that's one reason why we like to participate in a certain number of non-operating wells because no one company has all the answers. So we like seeing what the others are doing and what's learning, as well as advancing our own themes would seem to have worked pretty well out there.

We came they're transferring our frac technology and results from the Eagle Ford, out there to the Permian. And we were among the first to do the really big fracs out there. And others have followed. But everybody is getting better, which makes you want to get better too.

Matt?

Joe has really hit on all the important points there. But I do want to underscore a couple things. Number one is where we started out here in the Permian Basin. We've had great learnings in the Haynesville and great learnings in the Eagle Ford. And we came to the Permian and to the Delaware specifically and started looking at every one of the rock types that Joe is talking about in the source rocks, the Wolfcamp specifically. We jumped out and pumped jobs that were twice as big as most of our competitors were pumping in the area. And I think, since then, some of them have followed suit.

But the other two rock types -- we've got different ideas about those, different ways to complete them. And as you saw in the release most recently, we've pumped a job where we put 3,000 pounds per foot of proppant in the ground. And typically, bigger is better. But as always, we are going to continue to evolve these frac designs. And what we are really looking to do is just make the most money. At some point in time, you could pump diminishing returns on the proppant volumes, and the fluid volumes as well. So we are going to try to find that sweet spot in there where we make a bunch of money.

And additionally, now is a good time for us to do that because service company pricing is down. So we are able to pump these bigger jobs and still for less money than we were pumping just a few months ago.

Really appreciate the color. Thanks, guys.

Thanks. And just last thing -- I'd like to thank our vendors, who have worked with us, not just to help us reduce costs or make these wells more economical, but have helped find better ways to drill these wells. Patterson has been good. Schlumberger has been good. And on Schlumberger, we have looked at re-fracking some of the wells to open up some areas that maybe weren't fully opened. And that's showing some promise in some of these in increasing recoveries. So we appreciate all those opportunities, too; and really feel good that as much is going on out here, a year from now we will be back to talk about some new innovations in 2016 that have really elevated recoveries and saved money.

So I think it's a great question, and can assure you that we are looking in our postmortems, after every frac, how to do it better and faster.

Thank you. Ladies and gentlemen, this ends the Q&A portion of this morning's conference call.

I'd like to turn the call over to management for any closing remarks.

Thank you, Shanice. I'd like to thank you all again for your interest, these very thoughtful questions, and your active participation on today's call. This quarter and upcoming year will continue to have its fair share of challenges. But it will also present opportunities. And Matador will endeavor to try to uncover and convert these opportunities into long-term value for our shareholders and bondholders.

We look forward to visiting with you all again soon. And with that, we will sign off, but want you to know that we are available to you if you wish to call in and visit. And we invite you to come by and see us, too. But thanks again to all of you. And we hope to see you soon.

Ladies and gentlemen, thank you for your participation today. This concludes the program. Everyone have a great day.