Welcome to the Fourth Quarter and Full Year 2015 Matador Resources Company Earnings Conference Call. My name is Kayle and I will be serving as the operator for today. [Operator Instructions]. I will now turn the call over to Mr. Mac Schmitz, Capital Markets Coordinator for Matador. Mr. Schmitz, you may proceed.

Thank you, Kayle. Good morning, everyone and thank you for joining us for Matador's fourth quarter and full-year 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 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 2015 earnings release on our website on the Presentations & Webcast page under the Investors tab. 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, Executive Vice President of Land, Legal and Administration; Van Singleton, Executive Vice President of Land; Brad Robinson, our new Senior Vice President of Reservoir Engineering and Chief Technology Officer. He is not new to the Company but that is a recent promotion we wanted to note for you all. Similarly, Billy Goodwin has been promoted to our new Senior Vice President of Operations and Gregg Krug has also been promoted to Senior Vice President and Head of Marketing and Midstream. Also in the room with us are Matt Spicer, our Vice President and General Manager of Midstream; Trent Green, Vice President of Production; and Rob Macalik, Vice President and Chief Accounting Officer. Before I turn the call over to your questions I wanted to briefly highlight a few points the Board, the staff and I hope to emphasize in this call. First, we're very proud of our 2015 operating and financial accomplishments despite the challenging commodity price. We reported record oil production of 4.5 million barrels; record natural gas production of 27.7 billion cubic feet; and third, continued improvement in all phases of our operations. And fourth, improvements in our financial condition and operating options due to the fact of our merger with HEYCO which is now at one-year anniversary, the public bonds we issued this past year and the equity underwriting that we had. Second major point that I wanted to note is the continued improvement in all phases of operations as you will hear as we go through the questions today. And third, we feel and believe that we have increasing value and potential in our Delaware position. Finally, the executive committee and the staff are continuing to challenge each other and remain focused on delivering better wells for less money. And we're pleased to announce positive and encouraging results in yesterday's release. For example, in Rustler Breaks we achieved the best 24-hour IP test of any well drilled by Matador this far in the Delaware basin. We completed this well, the Janie Conner number 224H in the Wolfcamp B and it tested 1,703 BOE per day or 1005 barrels of oil and 4.2 MCF of gas. With that I would now like to turn the call over to the operator for your questions. Operator?

[Operator Instructions]. Our first question comes from the line of Neal Dingmann with SunTrust. Your line is open.

Joe, obviously with all the success you are seeing in all these plays, the Wolf Loving and Rustler Breaks in the Delaware thus far, just a general question first. What would it take to see you bring back some activity in the Eagle Ford given all the success you are seeing in the [indiscernible]?

Yes, Neal, that is a good question and we look at it. I think it is really a matter of higher prices more than anything else. The returns that we were getting on the last Eagle Ford well are very comparable to whatever formation we're drilling to in the Permian. The big difference is in the Eagle Ford you go down there and you drill to the Eagle Ford, you turn right, you make a horizontal well. And your economics on that well are very good. The big advantage you have in the Permian is when you drill to the Wolfcamp you are getting behind [indiscernible] only maybe the Wolfcamp A, the [indiscernible] you've got first Bone Springs, second Bone Springs, you have Avalon. You just have a host of formations that add millions of barrels with each well drilled. And potential value in those zones that are proved, probable possible reserves. And that is just the big added advantage; you get a whole lot of other good zones to consider going forward that presently the Eagle Ford doesn't have.

And then just last, obviously I mentioned you continue to have a lot of just operating efficiencies all throughout the Del, I guess the one maybe I will just ask is obviously on that Avalon where you added the ESP you certainly got a nice uplift and certainly since the Analyst Day it was quite a bit higher. You mentioned in the release about adding that maybe on another well or two in that area. Your thoughts about artificial lift throughout the play, Joe or for one of the guys.

Well, I think our production group has been very creative and innovative on the different things they have done to increase and sustain production. And I give them a lot of credit of working with our tackle teams to continue to improve in that area. And, but I have let David take a hand on this question, I see he is eager to dive in to discuss this because we do, later in the year as we start to bring more of this production online you will see continued improvement in our LOE as there is a number of little innovations that are coming; as they get their rates up and they are adding this new technology, I think you will see improvement in not only our production but also our LOE. David?

I would say that we were really very encouraged by the results we saw from the Avalon well after putting the ESPN. I think as we have discussed a number of times before, the second Bone Spring and some of the shallower zones out here are very much normally pressured or are close to normally pressured. And certainly the Avalon and the Brushy Canyon are, whereas the Wolfcamp zones that we complete are geo pressured. So in the Wolfcamp it is pretty typical that -- in fact, it is always the case where when we complete those wells they flow naturally for some length of time before they require any kind of artificial lift. I mean, for example our Dorothy White well, you know the first well we drilled there at Loving or in Wolf is still flowing after two years. So that is not that uncommon but in the lower pressure zones in the Bone Spring, in the Avalon we know that we have to go to some kind of artificial lift soon. Of course we started out using gas lift on a lot of these wells and many of those have responded well to gas lift. I think here in the Avalon though it is a little different beast. And I think that we tried the gas lift first and just didn't seem to be able to clean the water up quickly enough. And one thing we knew was that we were going to have to get probably a higher percentage of the water back off this particular formation and probably the Brushy Canyon before we started seeing hydrocarbon response. So, when the gas lift wasn't doing that quite as quickly as we wanted to we went to the ESP and installed that. It really improved our ability to get the fluids off the formation and as a result we saw the oil response that we were hoping to and sort of expecting to see all along. So I think now we're optimistic that when we do the same thing in the Brushy, don't know exactly where that will turn out. But I do know that getting a little more of the water off of it quicker should help improve the hydrocarbon response there too.

Just to add on to what David was saying, I think it is important that everyone understands we're optimizing artificial lift on all of these wells. So as David said, some of them we'll gas lift, some of them will use ESPs. We have also got rod pumps down in the Eagle Ford; we have got bungee lifts. And so the production team has done a really nice job of figuring out which application works best on each well and we will continue to do that going forward.

Neal, the last thing is just note that when we did run the ESP up there on the Avalon on the Jackson Trust we only had recovered about 25% of load. So it was still relatively early, but it certainly has proven a difference maker and to get that water off early.

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

I wanted to maybe dig a little bit more on this diverter result you guys got. Can you just maybe talk a little bit more about if that kind of met your expectations in terms of the uplift on performance? And just kind of how you guys look at maybe deploying that across some of your other assets or formations moving forward in the Delaware?

And maybe a little background. What we did there, Jeff, was we had an offset well, an 80 acre offset well that had been producing about six months. And we came in and drilled the new wells, again 80 acre offsets and expected to see possibly some depletion, weren't sure. And so the diverting agent, the win for us in this example would have been if the production would have been similar and as we talked about on the Analyst Day, we actually got a little better than 25% increase in production in the first 90 days. So it is still early, but the initial results are very encouraging. And I think the success there is that you are actually able to ensure that most of your perf clusters get a frac originated at that point So, the real win too is we were able to spend about $50,000 on the diverting agent and save around $75,000 on the well cost. So, we're going to continue to use this practice and keep a good look on the evaluation and continue to do the look backs.

Jeff, this is Brad Robinson. I just would add to what Matt said, in terms of increasing the overall productivity of the wells and ultimately the reserves and the value of the wells, we're really pleased with it. And as Matt said, it is very important to make sure you have a hydraulic fracture at each one of those perf clusters and these diverting agents are helping assure that we can do that. So we're increasing our stimulated rock volume and ultimately the recovery.

And then maybe on the Midstream side, you guys have talked about possible divestitures there. How you guys kind of look at conceptually and I guess parsing out some of the cash flow that it looks like you guys right now are kind of internalizing in terms of savings. So I guess when I look at, for example, the $6.5 million in savings you guys quoted from your saltwater disposal in Loving, if you guys were to theoretically potentially look to divest of that. Is the thought process kind of monetizing the entirety of that cash flow or maybe retaining some of those cost savings? I guess just trying to get a sense for how your all's cost structure changes on potential Midstream monetizations.

I think what databases David again, Jeff. I think what is important to think about there is the fact that the savings have really been realized from actually having the saltwater disposal system in place and going from trucking it to actually a system where you are actually disposing of it and piping it. All of that will stay the same and internally we're already charging ourselves a disposal rate. And I think that we're optimistic that if we were to look to monetize that the rate wouldn't change significantly. I mean there might be a little uplift in our cost, but I mean I think the real advantage and the real savings we have seen as in being able to go from trucking it to actually putting it into disposal wells. And that certainly doesn't get lost even if we monetize the asset.

Jeff, I would add to that is that if we were to do that it is the same thing on EnLink, we wouldn't do a deal where we didn't get our prices on that disposal so that we got a favorable rate much like we're charging ourselves right now for accounting purposes. So we don't feel like we will lose that. If anything we will more or less capsulate that rate going forward. The other thing I would like to mention, just to go back to your previous question, is the other reason we felt good about diverters when we put them in, there would be pressure differentials so that we knew that diverters were filling plugs and opening new areas with new stimulated rock volumes. So that I think helped account for some of the increase. So those two things that I would note that we're going into this on the saltwater disposal as we did with EnLink the same principle that we're going to get our terms. We hope to add a strategic partner who can help us grow and take their specialization to keep things going smoothly or adding on or building out the plant and allow us to focus more on our E&P business.

[Operator Instructions]. Our next question comes from the line of Scott Hanold with Royal Bank of Canada. Your line is open.

A question on the Midstream. Can you give us a sense in the Rustler Breaks, the facility you are building, just an update on where you are [indiscernible] progress? You did talk about the CapEx spend in the press release. But generally a sense of when that capital gets deployed and when this facility will be up and running?

We're right on schedule, latest right on budget for our plant to come online mid this year up there at Rustler Breaks.

As far as the deployment of the capital, I think as we outlined in our Analyst Day presentation, the majority of the $40 million in 2016 capital that we had budgeted will be deployed in the first half of the year. So the expectation is that the plant is going to come online sometime in the third quarter. So the majority of the capital will get spent in the first half of the year.

And then, Joe I know there is a lot of conversation, especially at the Analyst Day and certainly across the industry right now, on taking a look at cash inflows and outflows. And can you give your updated thoughts on how you feel Matador is positioned and the various options you have? And it would be nice to see if you could sort of give a rank of where you think the most palatable options are at this point.

Scott, we don't look at them as palatable, that wouldn't be a word that I would use. Is that it's not we're being forced to do anything. We feel that is why we took the steps that we did last year. We finished the year with money in the bank and that's been borrowed on a commercial line of credit. So any time we do that we have plenty of liquidity to borrow money and that is what you try to do in this business over 30 years. As prices go up and down what I have always tried to do is build a strong balance sheet so that when you entered a time like this that you always have that leverage available to you. So it isn't a matter of -- I don't know if this is a [indiscernible] but it is the number of options that you have. And those are complex questions. It doesn't come down to one thing. You have got to consider it. Is it like Midstream? We said at Analyst Day that we would consider serious offers that came in we would give it appropriate consideration but if they are not going to be strategic to us, if they are because we're going to be in here for a long time with them and if we don't feel the relationship we wouldn't do something if we wouldn't get our terms. So there is considerations other than money. We have been very encouraged by the strong interest we have received in a number of our assets, not just the various Midstream assets that we have had where we have had interest in all of them, individually and the like and continue to receive them. But also with Haynesville and the Eagle Ford. We have proven…

Yes, sure. I mean just there at Rustler Breaks a year ago we were completing one interval in the Wolfcamp B. It was a great interval, we were excited about it. But given a lot of additional geoscience work that was done over the course of the past year, we have identified two additional targets in the Wolfcamp B, one of which we have completed which is even better than the initial target we had. Those are the wells that are going to be 1 million BOE plus given the first couple wells that we have done there. There is also a lower zone in the Wolfcamp B below the two that we've completed that some of the folks in the area have completed that looks like it is also going to be a nice target. And then I think the real success in addition to that of 2015 and the Rustler Breaks was the fact that we added Wolfcamp A. And not only has that been a very prolific zone for us, but it has also had a little higher oil cut which I don't think most people in that area expected. So we knew it was going to be a Bone Spring area and we completed some Bone Spring wells there too. So I think just over the course of the past year there we have added four additional potential completion targets that we didn't come into the year with. And think we have some others that we just haven't had a chance to test yet. And I think that is pretty consistent with what we have done pretty much across our acreage and particularly in Loving County and there in Eddy County.

Kind of finishing up a long answer to your original question that kind of indicates the complexity of these things is that, look, the stronger the offer, the stronger the money the more palatable it is, but I don't use palatability, I would say fit is a better word to use of how we judge things. What is the pit regarding the relationship since whoever is on our Midstream, because we're going to be the anchor tenant, we have got to feel we're going to have a long and mutually beneficial relationship for them to trust us and us to trust them. The second thing is, yes, you look at the money, but you also want the fit on the type of asset that it is. And we're open on the Haynesville and the Eagle Ford, although they are both cash flowing and holding up very well. We think those are really quality assets, they give us a very valuable gas option and a very valuable oil option. And in the case of the Haynesville, remember we have the Cotton Valley above that, so we have hundreds of billions of cubic feet of gas there under option that isn't costing us anything. And it may be not this year or next year, but at some point these commodities are going to become increasing in value. And Scott, if we didn't feel so comfortable we could have gone from three to two, but we just think these things are going to work out and have been strongly encouraged. Is that helpful to you?

Yes. No and I appreciate the long answer because, frankly, in my opinion these are the questions and these are the discussions that really matter for investors right now. So I appreciate you taking that extra time to give a little bit more detail.

Well, you know, Scott, it is a great question and we look at this all the time and if we were worried about the plan we would go something different. But when you are looking at cash in the bank, nothing borrowed on your line of credit, that is a pretty good option. And the options only get better from there.

Our next question comes from the line of Gabe Daoud with JPMorgan. Your line is open.

So I guess maybe just going back to Midstream and I know there is not a formal process, but kind of piggybacking on Scott's question related to potential outstanding, just kind of addressing that. The Loving County plant was sold just a few weeks, maybe even a few days after coming online. What's maybe the likelihood that we could see a similar time frame for the Rustler Breaks facility? And I guess what I am getting at is if the year progresses and, for whatever reason a Midstream sale begins to appear less likely, are you guys comfortable I guess funding be outspend through unused revolver capacity? And maybe just a follow-up to that would be initial thoughts on what the $375 million borrowing base will look like post the redetermination season? Thanks.

Okay. Let me try to take those in parts, Gabe and if I leave something out remind me. We could have something midyear on the Rustler Breaks and we're not going to be rushed to it because we do think we have good options. We're confident that this new system is going to be improved as we have learned things from the construction of the first one. We're very pleased the Midstream and our Midstream guys and their mechanical prowess in starting off that cryo plant and having it work so well. And we have had work -- EnLink has done a good job and we have gotten along fabulously, that has worked out very, very nicely. We're open to that. The process is kind of funny, I wouldn't say we're not running a process, but we're trying to work with the logical people and considering, as we have received expressions of interest, how good the fit is. And what I am trying to emphasize, that money is one part of the occasion and the fit between the companies and their objectives is also another important consideration, as well as their experience in the area and their commitment to the area. So there is a lot of things going on. And it is hard to say in February exactly when in the year it is going to happen, but you know that we're confident that it would. And maybe by fall if it hasn't happened you might see something different, but then prices may be different in the fall. You will have to kind of see how that goes. But even if you keep the asset you may be adding a lot of value because as we bring the asset online it will be easier to bring in third-party commitments which will enhance the value and may help us to get an even better price than what we'd get as simply Matador as the anchor tenant and the plant. So I don't want to commit ourselves to selling just when the plant is ready because we may miss out on that opportunity to gather third-party through to that plant and we're first in the area. And I think we're in a good position to add a lot of capacity there that could really help the price and make that of considerable more interest. Did I say that right, David?

Yes, I think so, Joe. I might just add that, Gabe, just a couple of quick things. Number one, as you know, the prior plant at Rustler Breaks is one thing that we might look to monetize. But as we have discussed, it is only one of a number of midstream assets that we have that could potentially be monetized. I think it is important to reiterate again that when we sold the plant at Loving that that was only a small part of the Midstream infrastructure that we have there. I mean we have a very well-built out gas gathering system, an oil gathering system, a water gathering system, a water disposal facility and really very much a brand-new commercial facility there that -- all of which may be of interest to others and would be something that we could consider monetizing. In addition, I think with regard to your question on the borrowing base, it is probably a little early to know exactly where the redeterminations are going to come out. We just finished our reserves and are just kind of getting started on that process. But one thing is for certain, we already have spoken to the banks about if we didn't monetized the Midstream facilities would we be able to achieve some additional financing on that. And their response has been very favorable there. So I guess I feel like that even if there were any kind of reduction to the borrowing base and I am not really -- can see that that will even be the case at this point. But if there was I think that on the other side of that we would probably be able to replace that liquidity with some sort of a financing against the Midstream asset. So again, I think we have a lot of optionality there. I think we're very confident of our ability to navigate through this year with the plan that we have put together. And just to kind of reiterate what Joe said earlier, I mean I am really comforted by the fact that I think that we do have a lot of options. We have assets that we can look to monetize if we need to. We feel like that we will do better on our costs as the year goes forward which I think will also help to squeeze a little bit on the outspend there. And we have assets beyond the Midstream that attract interest as well. And as Joe mentioned, we can always shut down a rig if that is something that we need to do. Right now that doesn't feel like what we need to do. So I think all of us around this table are really very confident in our ability to do what we have done before which is execute on the plan that we put forward. And when we do I think things will be just fine.

You know, Gabe and I think these are good questions. And I appreciate you asking them, you and Scott both. Because I do think these are on the minds of everybody to be sure that we're thinking about them but here is an example of if we were told that, hey, costs aren't coming down, this is the best we can do on cost. You have an outspend, one of the analysts used the number $180 million and that is a ballpark number let's say. And someone said they can't do any better. That is one thing. But when you think maybe you could do 20% better, that brings that number down to $144 million. And to me when we're at our size of roughly $1.5 billion market cap and that we're going to have EBITDA moving up and prices look like they may get better, there is a big difference between having $180 million outspend and $144 million because in addition to the cost there is other ways to potentially trim that $144 million, a little better LOE, nibble on that. And other ways it becomes pretty manageable again given the fact that of our commercial availability and given the fact that we can have a facility for Midstream. And I think the likelihood of that would depend on some point in our Rustler Breaks are we adding and can we add third-party gas to add value to that system which I kind of like and our Midstream guys are asking for that opportunity. And well, as they performed and executed it is hard not to let them give them a little chance to add value in that way as well. But we're going to do what is best for Matador and the shareholders and we all have a lot of skin in this game and it is something that we talk about every day. And as you know, Gabe, we have traveled with you and others. And we get out among our shareholders and others and we try to listen. And we have a saying around here, we always reserve the right to get smarter. So as we go through the year and the circumstances become more clear, we would certainly exercise that right to get smarter and make some course adjustments. But right now it is looking pretty good.

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

David, maybe this one is for you. But just kind of thinking as we exit 2016, any chance you can give us maybe what the percentage of Delaware production, where that comes from not absolute numbers, but maybe what percentage comes from Wolf, what percentage comes from Rustler Breaks as we kind of exit 2016?

Ben, I really haven't ever sort of put those numbers out there. I think that our Delaware production I think is pretty well going to double over the course of this next year. And I would imagine that given just the number of wells we will have in service that a little bit more of that, maybe it is going to be 60/40 coming out of Wolf versus Rustler Breaks. But to the extent that that is important we can look at trying to be a little finer on that. But we're figuring that our production out of the Delaware ought to at least double this year over what it was last year.

And, Ben I would like to speak up for the Arrowhead Ranger area, that isn't that we don't think that area has as much potential or returns. Most of that is HBP, so we've just been focusing and it has been more delineated than the area of Rustler Breaks and Wolf and so we have to use those areas -- we're delineating more in that. But the Arrowhead Ranger, as you know from the quality of wells that have been drilled up in there, we have a lot of value on it and think it will contribute in its own time as we work our way around the basin.

[Operator Instructions]. Our next question comes from the line of Dan McSpirit with BMO Capital Markets. Your line is open.

Where do you put the economic limit or breakeven oil price on your Delaware basin asset today? And where could it go should the cost structure continue to shift to your benefit?

I think that is a little bit of a complicated question to answer from the standpoint that I think that, as we showed in some of the materials that we presented at Analyst Day, I think we could generate north of 10% rate of returns even at $30 or in certain of these assets. I think as long as we're drilling wells in Wolf and the Rustler -- in the Wolfcamp B that are on that plus or minus million BOE type curve or in the Wolfcamp A, if we're in that 800,000 MBO kind of range, I think that our work suggests that we can continue to have very solid returns, Dan. And I think if the cost structure continued to improve that, I think we typically estimate about 1.5% to 2% improvement in rate of return for every $100,000 that we say. So if we can get $0.5 million or $1 million that can add another 15% maybe to your rate of return. So it can only improve as you do better but what we tried to do this year is to really focus on selecting wells to drill that are going to deliver good returns. And whether that is at Wolf or that is at Rustler Breaks or even the wells at Ranger Arrowhead, we have tried to put together a program that is really emphasizing on being able to deliver results at the higher end of the productivity ranges or the production ranges that we have established for these areas.

Dan, this is Matt, I just want to build on what David is saying there. The thing that I'm most comforted with is we're working on both sides of that equation. The cost reductions, the service cost reductions, those continue to improve, the efficiencies continue to improve and we're really, really focused on the efficiencies. So driving the cost down is one thing, but we have been able to drive up the EUR, the productivity, as David has said, on the other hand and that has been done in the case of the diverting agent at a reduction in cost. We're going to try the nano surfactants, we pumped the higher volumes of proppant on some of the wells at Rustler Breaks, we had a favorable response there. So we're able to do these things at very low cost times. And so, even going forward when service costs go back up, we're still going to have the efficiencies and we're still going to have the innovation and the understanding that we were working on right now.

Yes, Dan, I am just going to build on what Matt and David have said. I look at it slightly different. They are looking at those type of returns that if you say $300,000 per well we have driven the cost down from $12 million to about $6 million. And another 10% would be $600,000. But just take half that, that is $300,000 which is about an increase in your rate of return about 6%. And then if you increase your recovery 100,000 barrels, that is about a 4% add to rate of return. All of a sudden you have doubled the rate of return with simply cutting cost 5% and improving your recoveries by a factor of somewhere between 5% and 10% with this innovation. And then the other thing that I add and I think it is an important perspective, is what does that set you up for in the long run. Well, in the long run you are getting all of these additional zones that we've talked about that have millions of barrels because Wolfcamp B location is 320 acres which means you are going to drill three other wells there, it is going to amount to millions and potentially millions of barrels in each of those zones. And that sets you up in the long term going forward. But if you are in the Eagle Ford where you only get one zone you don't have this additional [indiscernible] or a potential and that makes a different drilling choice. If we were only Eagle Ford we might do things a little different. But we're in an area that each time we drill we're picking up other opportunities that are not little opportunities, 1 million barrels still matters a lot to us. And over last year you saw just the drilling we did in the Delaware it nearly doubled our oil reserves and we have got even more zones to work with. When we went from the Eagle Ford we had 30,000 acres and one zone. And the opportunity set that we now have in the Delaware is three times that acreage amount and about 10 times the zones. So when we first went out there we were thinking Bone Spring, one Bone Spring, one Wolfcamp. We have gotten into a lot more of that and in learning that the opportunity set is just much bigger and we still haven't seen the limits of that. Our geological group keeps coming in here and saying, instead of drilling the bird in the hand, they keep saying try this in the bush and it keeps working out. And it gets us really excited. Ned, you have been coming here, what gets you excited about the opportunity set?

Yes, to follow on Joe's comment, I mean I think really at Matador we have been -- as we have said many times today, we have been challenged with delivering better wells for less money and the geoscience and engineering department are really focused on the first half of that, delivering the better wells. So with every well that we drill we learn a little bit more. And we understand to really do that we have to understand the basin and we feel that we can -- with everything that we learn we can continue to bring better wells and better prospects to the table. So there is a lot to be excited about in the space and there is a lot to be excited about in Rustler Breaks, there is lot to be excited about in Wolf, there is a lot to be excited about in Ranger Arrowhead. And also in Jackson Trust. Twin lakes we took our core up there, we're currently analyzing it, it is actually down on the third floor of the office right now the geoscience staff is looking that over and looking for the best landing zone there. So, I think going into 2016, Matador has an extremely fine opportunity set ahead of it and the geoscience and engineering staff will continue to work to bring the best prospects forward.

And one of the things that we're noting is how valuable this core data is in evaluating these zones, is that I think they have done a real good job on taking that in 3-D and the interdisciplinary team is working really well to come up with some ideas that are working out. And they are just -- there is hard work, pick and shovel work that they are doing but there is also good science here. And again, to the question about going from three to two, if the innovation and the discoveries weren't as strong maybe you would argue moving three to two. But they are establishing a lot of value and a lot of improvements in process that are going to be sustainable that will lead to cost savings and the EUR recoveries. And when you look at information we put out on Analyst Day, getting the recoveries up 100,000 barrels and moved as we have revising upwards our type curve has a bigger impact actually than the cost savings. The cost saving is more obvious, but the improvements that you can do [indiscernible] in the recoveries has an even greater impact. And so, we're eager to see as we bring these next wells online and as we continue this year that look forward to reporting you in the third and fourth quarter on the gains we have made.

And just as a follow-up here. The inventory in the Delaware basin seems to deepen and widen with every new well drilled, as you highlighted. Where do you think you are in the process of making fully transparent the resource potential on the acreage, the present acreage in West Texas. You can answer that question maybe using innings of baseball or periods of hockey, whatever is easiest and most concise. Just trying to get a sense of how far away we're from full development mode where that same cost structure can be shifted further?

Well, Dan, we're making strides, that is why we have done a three well pad and a four well pad. But I would say it is more like a poker game. There is plenty of time for counting your chips when the dealing is done, that we're right now concentrating on seeing what there is rather than trying to just make a resource potential of that because it is dynamic right now, it is changing. But we're taking those steps, three well, four well pad and keep asking this question, keep prodding us, we will get it done. But right now we're just really in the midst of things and working to make things work and make things better. And feel like there is -- like in the poker game, there is still cards -- there are still deals to -- you are going to deal the cards for a lot longer, too early to count the money right now when so much new stuff and progress is being made. And I would like to give a lot of credit to Van Singleton, our land group and our [indiscernible] group that has brought in some great acreage. And that we're looking to add more acreage this year at an appropriate time and within the budget constraints that we have set for ourselves but very excited and hopeful that we can continue to add value there too.

Joe, I just want to build on what you are saying there. Dan, in regards to the pad drilling, we're drilling four well pads, three well pads, we have gotten very good at that in the Eagle Ford. We have learned a lot in the Eagle Ford, we brought that to the Delaware basin. We actually upgraded the rigs from what we were using in the Eagle Ford that we're using now in the Delaware basin. The big difference is and we said earlier, in the Eagle Ford we had one zone. So, if we're drilling a four well pad in the Eagle Ford, that is four Eagle Ford wells. What we're able to do here and what we have done down in Loving County is drill four different intervals off the same pad on one location. So it's a big difference there, but it does go a long way to your question about proving up these reserves.

This is Brad. I was just going to add, we have been focusing mainly on the deeper zones because that is going to help hold the acreage for us. But as an example, up in the twin Lakes area, there has been 1.3 billion barrels of oil produced mainly from shallow zones. And just like at Jackson Trust, we're always finding more oil zones up the hole that we haven't even begun to scratch the surface on. I think we're going to be in this area for a long, long time. I think we were in a meeting the other day and he said -- he looked at the young guys and he said we're building on something that is going to last through you all's kids and your grandkids and we're going to be out there discovering new intervals a long time out here I think.

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

I have two questions if I might. Firstly, I know there's an Arrowhead area, if you guys decide to drill later this year you have got two second Bone Spring and three third Bone. So I would like some more color on the third Bone as a horizontal play as compared to the second, what the difference in cost, EUR and such. And what kind of targets you are trying to land in as a micro coupled reservoir. The second question really has to do with your whole land base, you've got six buckets and they are all doing well. So you have started development on Wolf and Rustler Breaks, just wondering who is third in the pecking order for development?

Irene, I will take that this is Brad. The difference between the second and the third Bone Springs, they are really fairly comparable in thickness and oil saturation and so forth in these areas. The second Bone Springs is a little better permeability. So we're able to complete those wells at probably a little lower cost, especially on the completion end, they don't require bigger fracs. The third Bone Spring is a little lower permeability, so they require a little bit bigger fracs. But it is sitting right on top of the Wolfcamp so you are getting some pressure support, some additional gas that helps produce those wells. We're real excited about drilling. We have drilled one third Bone Springs well up there, that was our Cimmaron well, it is -- if you look on some of the type curves and so forth it is doing very, very well. The three walls we have got planned for the third Bone Springs are the [indiscernible] laterals this year, the 7500 puts laterals just to the south and so, we're moving some of the long lateral technology that we have been applying in some of our Texas wells up there, we're really excited about those, those ought to be some of the best wells we drill in that area.

Thank you. Ladies and gentlemen, this ends the Q&A portion of the morning's call. I would like to turn the call over to management for any closing remarks.

Yes, I do, we really appreciate your questions and we really appreciate these discussions and invite all of you to come by and see us and talk about these things in person, because it is a volatile environment, it is dynamic and there are more -- we feel there are more opportunities today as people are making trades that -- and deals that they wouldn't have done in more robust times as people have to rationalize their assets and their opportunities. So we welcome these discussions, we reserve the right to get smarter and we welcome discussions with our peers in the Delaware and other areas that -- where things make sense we want to talk about them. I would also like to really recognize for all the technology and all the capital that goes into this, it comes down to judgment and really appreciate our team leads, Tom Elesner and Drew Wellsfry and Brad and Chris Carlton [ph] and for the great work that they have done in their areas and Glenn Stetson and also recognize our Vice President and Chief Accounting Officer, Rob Macalik, who has done a real good job. A statistic that gets overlooked is your accounts receivable and Rob has done a good job attending to that and our accounts -- he has reduced our accounts receivable to about 25% of where it was when he arrived. And it is less than $0.5 million. So I think that is a little thing, but it just shows what we have tried to challenge the staff [indiscernible]. Every little bit makes a difference. And people are coming up, bubbling up with some really good ideas and we appreciate the work of the teams in doing this. And the last thing I would like to leave everybody with…

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