Good morning, ladies and gentlemen. Welcome to the Fourth Quarter and Full Year 2017 Matador Resources Company Earnings Conference Call. My name is Sandra 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 a replay will be available on the Company's Web-site through March 30, 2018, as discussed in the Company's earnings press release issued yesterday. I would now turn the call over to Mr. Mac Schmitz, Capital Markets Coordinator for Matador. Mr. Schmitz, you may proceed.

Thank you, Sandra. Good morning everyone and thank you for joining us for Matador's fourth quarter and full year 2017 earnings conference call. Some of the presenters today will reference certain non-GAAP financial measures regularly used by Matador Resources in measuring the Company's financial performance. Reconciliations of such non-GAAP financial measures with comparable financial measures calculated in accordance with GAAP are contained at the end of the Company's earnings press release. As a reminder, certain statements included in this morning's presentation may be forward-looking and reflect the Company's current expectations or forecasts of future events based on the information that is now available. Actual results and future events could differ materially from those anticipated in such statements. Additional information concerning factors that could cause actual results to differ materially is contained in the Company's earnings release and its most recent annual report on Form 10-K. Finally, this morning, 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 2017 earnings release on our Web-site on the Presentations & Webcasts page under the Investors tab. And 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. Now, I would like to introduce the senior members of our operating staff who are 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, Land, Legal and Administration; Van Singleton, Executive Vice President of Land; Billy Goodwin, Senior Vice President of Operations; Brad Robinson, Senior Vice President of Reservoir Engineering and Chief Technology Officer; Gregg Krug, Senior Vice President, Marketing and Midstream; Rob Macalik, Senior Vice President and Chief Accounting Officer; Matt Spicer, Vice president and General Manager of Midstream; Kathy Wayne, Vice President, Controller and Treasurer; Brian Willey, Vice President and Co-General Counsel; Bryan Erman, Vice President and Co-General Counsel; Ned Frost, Vice President of Geoscience; Tom Elsener, Vice President, Engineering and Asset Manager; Jim Basich, Vice President and Managing Director, IT. I'm proud to announce 2017 was the best year ever and the fourth quarter of 2017 was the best quarter that we had ever had, and that our outlook for next year, 2018, is the best outlook that we've ever had. Now, I want to take a moment first to personally acknowledge the Matador staff here in the office in Dallas and Roswell and our people in the field for their record-setting achievements during the year and setting us up for 2018. Now, I would like to take on a few key points before taking your questions. The elephant in the room that I can tell by the comments is the concern over our proposed outspend this year. I would like to address…

Joe, I think you've done a really good job of describing what we do here at Matador and we've talked to you guys all about this before, we contemplate things in a mode of profitable growth at a measured pace, and I think this fits that very well. Joe, you talked about the E&P wells, you know we are adding value drilling wells in a very good basin. So we are adding reserves, we are adding production profitably, and that's incredibly important to us. The acreage component you talked about, we're adding great acreage at less than market price. So that to me seems like a very good investment. And in the midstream, that's really growing into a profitable and value-adding business unit for us. So, I think those three buckets, if you try to simplify things, are three very good buckets to invest your money in.

All right. First question?

[Operator Instructions] Our first question comes from Gabe Daoud with JP Morgan. Your line is now open.

Good morning, Joe, and everyone. Appreciate all the prepared remarks. Maybe if we could just start with well results, if you can maybe talk a little bit about the Break Sand interval at Rustler Breaks and any other new concepts there that you could be testing this year? And then maybe just a few words on the Antelope Ridge result and any earlier read on the First Bone Spring?

Right question, Gabe. Let me try to do that in parts. First, we are very pleased again with how the money was spent on the drilling and completion side last year. We understand one of our Mallon wells was the best Bone Spring well drilled in New Mexico last year, and that out of the top 10 wells, we had three of them. When we went out there to the Delaware from the Eagle Ford, we were expecting, we did on the basis that we thought each area would have two to three zones. We are now up to producing from 15 different zones out there in the Delaware. And the Break Sand is looking very encouraging to us, and I'm going to I guess turn it over to Ned and then to David to comment. Ned?

The Break Sand is something we've had our eye on for a number of years out there. It originally produced vertically. It's a sand within the Third Bone Spring carbonate. And we got some well proposals then. We were happy to participate in that and it really kind of shows that there is a lot of potential in this basin, that if you kind of look at the various vertical producers that have the potential to be turned into horizontal, so there's a lot of those out there. So the Break is definitely a good first result. We are excited about that. I think it's also worth kind of pointing out while we are talking about well results is the Wolfcamp A-Lower in Rustler Breaks. That continues to be a good zone for us, and I would say that that one is really being proven up so that that would be a second zone in the Wolfcamp A independent of the 'Y' sand that can now be developed out there. So that's really kind of a big win for Rustler Breaks also and you will see more of those wells coming. The Florence well, we are very pleased with how that one came on. It's a great IP and it's always nice to have the first well you drill and then new asset really come on like that. So, we are pleased with that. Really too early to say anything about the other two wells in Rustler Breaks – I'm sorry, Antelope Ridge, but kind of watch that space. We'll update you guys as soon as we have numbers for you. And really Antelope Ridge is something we are excited about. I think the geoscience and engineering teams are both very excited to keep drilling wells out there and move forward with that.

David, do you want to add anything?

Yes, maybe just a little, Joe. I think Ned did a good job of summarizing it. I would just say in general I think the team was very pleased with the whole collection of well results in Q4. I think that they continue to meet and at times exceed our expectations. They have been very, very solid results, whether it's in Rustler Breaks or Ranger/Arrowhead or Wolf, and of course Antelope Ridge was the real excitement of the quarter because it was the first one and the first new well there. But I continue to be real pleased with how the wells are drilling up in the Stebbins block up there and Arrowhead can continue to perform. I'm very pleased with just the overall collection of wells at Rustler Breaks and even down in Wolf. The new longer laterals that we had a chance to complete on the Kerrs and the Larsons, I think as we mentioned in the release, I think those are looking very solid and they behave a little differently. As we mentioned, they tend not to have quite the show-stopping IPs but they tend to produce a little flatter as I think those zones start to clean up out toward the toe. And certainly we cited a couple of examples from some of our Billy Burt wells which are also some of the longer laterals we've been able to drill several years ago and which are some of our best wells out in the Wolf area. So, I think all the way around, it was a very positive quarter for well results for us, Gabe.

All right, thanks a lot, everyone. Just secondly, we can maybe discuss well costs and the cost structure overall. Where are current AFEs I guess relative to the range you guys had laid out in the investor decks, and the 10% inflation number in 2018, is that of the high end of the range or is that of the midpoint on the range? And then, I guess finally, the new natural gas and NGL takeaway agreements, how does that impact whether it's realizations or the cost structure side, how should we be thinking about that?

This is David again. I'll take the first shot here. With regard to cost per well and per area, I think if it's all right we'd prefer just to defer that for a couple of weeks and go into a little more detail on that on Analyst Day. I think that would be a better use of time and we can give you a little more detail around all that. The 10% number is something that we'll – it's just sort of an average for the year, probably a little lower in the first part of the year and a little higher towards the latter part of the year. And it's just our best estimates of kind of where costs are going. I think that when you look at our D&C spin last year, which was about for a non-D, we had to cut 10% to it. So where we come to is not that surprising, and yet it includes additional operated and definitely additional non-operated wells that we'll be drilling this year. So, I didn't really feel like that the guide was that surprising. On the midstream side, we guided to about $80 million, which again is a little bit more than what we invested last year in midstream. But again, didn't think that was going to be terribly surprising given that I think we had messaged pretty well that we had still quite a bit to do on the oil infrastructure, the water infrastructure. We had talked about at the end of the last quarter the fact that we were going to drill up to five salt water disposal wells, of which we have three working now and two planned for this year. And then of course finishing up on the plant which is going to come in right on time and probably a little under budget here at the end of the first quarter. But then with the Plains deal, I think we've also allocated a little capital there for the potential for us to gather oil from some of the third parties to get the trucking station put in. And those are some things certainly that we weren't anticipating until right at the end of the year when this opportunity with Plains came along. So, that's also something we're very excited about. So, I hope that helps to answer your questions to some degree on that and we'll be happy to spend more time on that when we come to Analyst Day.

Gabe, I just want to add a couple of closing notes. On the Plains deal, one thing that has been somewhat overlooked is that it's a 400,000 acre area, which means 625 square mile area of mutual interest. And we'll be gathering there, delivering to Plains. So it should boost their volumes plus give us an opportunity to really expand and grow our business. The other thing is to give you an idea also of the potential of the midstream for growth is, right now we've hardly got our salt water disposal wells going, we're not fully amped up on that, and already we are disposing off 170,000 barrels between the wells in Loving County and the wells up there by Rustler Breaks, and we think that will simply continue to grow, but that's a very encouraging start. And all this added up again to doubling of the EBITDA from last year from about $159 million in 2016 to $336 million, half of which probably reflected the increase in commodity price but the other half in volume. So, because of the – if you point to the 50% increase in production, that reflects the volume increase and then the other half came from commodities. So all this is what leads us to say that 2018 outlook is probably the best that we've had because of the balance in all areas that we are operating in and the continuing growth and the expertise and experience of the staff. So, I'll point that back to you, but Gabe, we appreciate your question very much and thought it was a good one.

Thanks a lot, Joe. Thanks guys. See you at Analyst Day.

Our next question comes from the line of Tim Rezvan with Mizuho. Your line is now open.

I'd like to continue on the theme of CapEx in midstream. To be honest, I thought you might see a higher capital allocation to midstream kind of given the new opportunity set with the Plains deal, and I just want to get your views if there are opportunities to accelerate midstream spending. I mean, those are probably some of the best projects in your portfolio given kind of the revenue stream. Help me, kind of how that could grow and just kind of help frame sort of what the EBITDA growth could be as you capitalize on sort of third-party gathering?

Sure. This is David again, Tim. Thanks for your question. I think you are right. I think that there is certainly the potential for that investment to grow over the year. Some of it is just there are opportunities that we think may come to pass but they are a little uncertain at this point, and so we are hesitant to connect to them yet. But I do think that in all areas, as we get the plan on the course, there is going to be opportunity for additional natural gas gathering with third parties with San Mateo. We still, with the Plains deal there is going to be a big opportunity now to expand upon the oil gathering infrastructure that we have at Rustler Breaks and to build on that. And of course that still, we are in the process of doing that. So, the first half of the year we'll be getting a lot of that infrastructure built out, and then taking advantage of the opportunities then to go to other folks. And then I think the whole water side of the business is really just, has just taken off here in the last part of 2017 in particular. And so, we plan to drill maybe two wells at Rustler Breaks, it seemed like we needed a third, and then just the opportunities for us to add third-party volumes made it quickly pretty obvious that we are probably going to need twice that maybe. So, we are pointing towards five. If we were to come back and tell you in a few months that we have the need to go to six, I wouldn't want you to be terribly surprised because I think that's certainly a possibility. But I think we're really excited about the fact that, as Joe mentioned in his opening comments, I feel like a year ago we were talking mostly about gathering gas and processing gas. That was it on the midstream side other than maybe just some [intra-neural] [ph] water disposal and oil gathering, but that certainly changed big time for us over the course of the last year and we feel like we can offer pretty much a three-stream solution to any third party customer that's operating particularly up there in the Rustler Breaks area. And as Joe may have mentioned, and if you did, I'm sorry to be redundant, but the deal with Plains is about a 400,000 acre joint development area. So that roughly is 625 square miles. So it's a large area in which we have an opportunity to be successful and I think that will only continue to improve as the year goes on.

Tim, this is Matt. Just to add to what David said, I think it's very important to contemplate our midstream business as a three-pipe system where we are able to go get salt water disposed off for people, get oil gathering system and get it out of the basin, and process the gas for those folks. And part of the processing facility there is, is we generate natural gas liquids, and currently the way we are set up, we're processing about 70 million a day and we're hauling those NGLs out via truck. So that's around 20 to 25 trucks per day. And so, what we have got in place is an agreement to get an NGL line built into that facility, which is going to do a number of things for us and for any third party folks that might want to come onboard. Number one, it's going to allow the cost to transport those NGLs to go down significantly. Number two, it's going to make sure that you can get those NGLs out. In other words, we are subject in Southeast New Mexico to some icy roads from time to time and when you got 20 to 25 trucks a day coming in and out of that facility, it's 70 million a day and you increase it to 200 million or 260 million a day, you could see how that would be a problem. So we've got this NGL line that's going in place. We'll be able to put natural gas liquids into the pipeline and get them out of the basin. The other thing that that allows us to do is, ethane continues to slightly improve. At some point in time, ethane recovery may be a way to go as opposed to ethane rejection. So, you can't put ethane in trucks, that just doesn't work, but you can put ethane in natural gas liquid pipeline. So, we'll be having the option to offer Matador and third-party, other E&P companies that option to recover ethane. And then on the deal with Plains on the crude oil line, one thing that does do for us and for third parties is give optionality for other crude markets. We get the oil to [indiscernible], we've got access to an LLS market and multiple other markets that not only Matador but others can also benefit from.

Okay, thanks for that competent answer. And if I could just switch gears a bit, you talk in your release on the Mallon wells, they continue to be among the strongest New Mexico Permian wells we have seen. Yet you are going to be running one rig across the Arrowhead/Ranger area in 2018. I thought you might see that area compete for capital a little more given the Third Bone Spring results. So, I wonder if you could just talk about kind of how that factored into capital allocation for 2018.

Tim, that's coming into being. We run a very nimble schedule where we can move the rig up there if we need to and the opportunities are there. Some of it is working on the land to acquire, to block up little more interest, acquire a little more interest, give land a chance to increase our interest. But that's just part of the capital discipline that we try to have, is that the returns that we've had on our wells are 40% to 50% and that's the standard. So it's a pretty high standard around here. And then the other determining factor is the interest. If we think we have chances to increase the interest, then we try to be patient to wait for the most opportune time. And something like this where the interests are broken up not only by various operators because this is an older area of production in New Mexico, but also by tracks where you've got to go through either the joinder process or the forced pooling, just takes a little more time. But we are very excited about moving forward with more projects in that area and we've got a number designated but we're just trying to – I'm not saying it's no wine before it's time, but it just takes a little bit of patience and I think it will pay off in bigger interest.

And one thing, this is David, Tim, one thing I'd just like to add, but agree with everything Joe just said, but in addition, you might remember that when we bought, so much of that area up there was in the transaction with [HECO] [ph] about three years ago, and of course most of that is held by production. There's lots of existing vertical production already on those leases, so pretty much all that acreage is HBP, which was a real – was attractive to us at the time we bought it and continues to be attractive to us. So, some of the allocation of rigs doesn't really always reflect relative excitement. It's just the fact that we've still got a few more things to get HBP up in the Rustler Breaks area for example than we do in Arrowhead/Ranger. I think with time, you are probably right, you will probably see us move a little more capital that way, but some of it is just where we need to deploy the rigs to make sure that we get as much of the acreage position held as we possibly can in a timely fashion.

Okay, that all makes sense. Thanks for the answers.

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

Joe, thanks for all the details and all the color this morning. Joe, my question is really, first in Rustler Breaks you've all been very successful in delineation there. Based on that and the three rigs you kind of have focused in that area this year, could you talk about well density there and size of pads given all the success you continue to have there?

Neal, it's David. I would say that what you'll probably see in Rustler Breaks this year and what we are planning is, most of the wells that will get drilled will be done in two and three well batches up there at Rustler Breaks this year as we, as I say, continue to kind of move out particularly toward the northwest of the acreage and get the rest of the position held. Not all our drilling will be up there of course. And I think on spacing you will probably see us stay still fairly conservative with about 160 acre spacing or so, maybe a little bit tighter, but I don't think we are quite ready to move to tighter spacing, but a lot of those two and three-well batches will probably tend to be two or three different vertical zones drilled off the same pad in an area, or they may be opposing laterals that are drilled in the same interval. But I think our focus will tend to be on the XY, the Wolfcamp A-XY, the Wolfcamp A-Lower, and we'll just continue to drill some of the Blair wells, and I know the guys have another First Bone Spring test or two that are playing along the way this year, and we may look at some other exploratory opportunities. But I think that's pretty much what you'll see from us in Rustler Breaks this year.

Okay. And then just one follow-up, you all have been very successful partnering with your – and I think Joe did a good job of explaining this – with your midstream and really growing with some of them, like the Plains deal that you've got. Could you talk about any thoughts about thinking about do you have some vertical integration with some of your oilfield services or partnering with them, like the success you've had on the midstream side?

We wouldn't say never to something like that, but we have no immediate plans, we're not in discussions or anything like that. We've got right now such a strong set of opportunities with just what we have in hand on the acreage and the D&C and the midstream. Our plate is pretty full. We would have liked to have kept 100% of midstream. But it seemed to make most sense to make a deal, as we did with EnLink and with Five Point and with Plains, and focused some of the capital as to our acreage and we thought those were a little more robust, although we wanted the midstream because it's complementary to our oil and gas revenues and has operational advantages. So, it's a balancing act and we would never say we wouldn't do it, but I think it's safe to say we are not planning to go in the rig business or the frac business or one of those, and really tend to think that if you do a deal like on a sand mine, you are tying yourself up and committing yourself to using the kind and quality of sand that comes from that mine and you may be better off maintaining your option so that you can use Northern White in one area and Brown Sand in another if that choose to be the ideal way. Matt?

I think it's right, Joe. Kind of the way we think about vendors and how we work with vendors is we try to maximize value, just like we do with everything else. So, I mean we feel as though the popping service companies we use, their real expertise is in providing horsepower and equipment that operates efficiently and products that we can utilize. That being said, we do have a very active interaction with those people, both on the completion side and on the drilling side, in regards to how we do things and why we do them and what products we use. And I will just give a couple of quick examples. Neal, you know, the success we talk about often on bid design, I mean we are actively involved in that process. We don't just wait for the bid companies to come to us with a new design idea, we go to them and we work with them. On the pumping services, we get asked a lot of time, who pumps your frac jobs for you, and the answer is, we use typically the most reliable vendors we can use in regards to the equipment they provide and their ability to provide products. But in reality, we design the jobs, we have engineers and consultants on-site that execute the job, and so we work very closely with those vendors. But I'm with Joe, I think we need to let the people do best what they do best and we'll do best what we do best.

Great details. Thanks guys. All the best.

Thanks Neal. We appreciate the questions and appreciate your interest.

Our next question comes from the line of Philip Stuart with Scotia Howard Weil. Your line is now open.

Good morning, Joe, and the rest of the team. Congrats on another great quarter. When we look at the 2018 capital program and the focus almost entirely on the Delaware Basin, does that make it more likely that you would look to bring forward value in the Eagle Ford and/or the Haynesville by actively marking those assets for a potential divestiture?

Phil, thanks for asking that question. We've tried to make it very clear, is that Matador tries to play a straight game, is that we have proof that we have sold, we sold old Matador some years ago, we sold part of our Haynesville interest to Chesapeake when Chesapeake and [Petro] [ph] came bidding and what we thought were good values. And we would do the same with either the Haynesville or the Eagle Ford if someone came forth with a value we thought reflected the value and the optionality to us. We've had a lot of people come kick the tires or express interest but they hadn't gone to our press, and two years ago when oil was $25, we certainly didn't think that was the right time and we felt being patient would increase the price and improve the offers. And it has. Offers have gotten better as oil prices have risen. And so, I think our patience is paying off. We'd be open to selling them if somebody came in. We're not going to sell them just for the PDP value, but it has acreage development. The return on the five wells that we drilled in the Eagle Ford last year are going to be in this, very comparable to what we've done in New Mexico in that overall in the 40% to 50% rate of return and there is still promise there in other zones, Upper Eagle Ford, Austin Chalk, Buda. And you hate to rush in and sell. There were companies who had sold out of the Delaware that now had for hundreds of dollars or a few thousand dollars are coming back in and having a buyback at 10x that price. So, we are certainly open to it and that we don't anticipate putting…

Good deal, that makes sense, and if somebody were to offer you kind of the right price, what would be the use of proceeds? Would it be to accelerate activity faster in the Delaware or would you be focusing more on trying to acquire bolt-on acreage in the Delaware, what are your thoughts there?

I think it would be allocated pretty much to whatever these three opportunity sets that we are talking about, acreage, D&C, and midstream, and I'm not sure how they would allocate. We'd have to – that would just be another discussion, but it would be a hot class problem and we would certainly welcome that study.

All right, guys, I appreciate the time.

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

Wanted to maybe get a little bit more detail, in the release from last night you guys referenced looking at maybe some longer laterals in certain areas in 2018. I know the Wolf area you guys have successfully done that in the past. Are any of your other operating areas setting up to do some longer laterals beyond those kind of 4,000 or 4,500 that have kind of been in the norms I guess?

Jeff, this is Matt. I think you hit it pretty right there, a lot of the longer laterals we are talking about are going to be down [indiscernible]. That being said, we do have some plan and are excited to drill up in New Mexico as well. We just recently have done some and I think it's a good exercise, because in calls in the past we have talked about the risk associated with getting out in the two-mile range, and I think Billy and his team have done a great job on some recent wells we drilled, and really planning, Jeff. I mean what this really comes down to I think from an operational standpoint is to make sure that you contemplate all the things as it may what could possibly happen to you, now you are going to do with those. So, the drilling guys did an outstanding job working with the geoscience team to identify the target and staying in these targets for a mile and a half for discussion purposes. And at the same time, the completion guys were watching how they're going to get out there and how they're going to get these wells completed. And so we've done 1.5 mile in the past and we do have some even longer than that planned for 2018. That being said, most of the longer laterals will still be down in the Wolf area.

Okay, great. Appreciate that detail. And then for my follow-up, on the land side you guys have obviously continued to be pretty active throughout time. Can you just qualitatively give us a sense for how the leasing activities have trended? I mean I imagine things continue to get tougher, but I guess in other words, could you guys acquire another 20,000 to 25,000 net acres like you did last year organically? I know, obviously it's hard to guide but just directionally trying to get a sense for where you see things heading.

Jeff, the old saying in the land is, you can do anything if you have enough money. And so, if we were to raise our price targets to $20,000 or $30,000 an acre, I think we would achieve that. But what we are trying to do is acquire the acreage at a more reasonable price than that, and we are achieving that but it will be harder to do it in the 25,000 range, but we are not setting limits on it so much as still aiming what I think is most reasonable to expect is 1,000 to 1,500 acres a month and a number of small transactions. And halfway through the year, if we have achieved that, it will challenge our land guys to do a year like last year. Also I'm very pleased with each well we drill. We feel like we can say with more certainty what each acre may mean to us and have a better understanding of how to evaluate. So, I think they have done a great job and this is probably a good point to look at when you look at over the years that if you look what you have each share of Matador stock represents, you can obviously look at our growth in acreage. At the time we went public I think we had 7,000 acres in the Permian, and today 125,000. So, obviously each shareholder of Matador has had a bigger and bigger piece of the acreage, the number of acres, and plus those acres have all appreciated in value, not to mention what's in the Eagle Ford or the Haynesville which are HBP. On the same thing, you look to reserve growth per share, that's also been very significant. And now you've got the midstream, which really has helped. We've also increased the amount of mineral acres that we've been buying, which is priced even higher than a working interest acre. So, all in all, the thing that I feel comfortable with is we're going to visit with shareholders to show them how much not that Matador has grown, but the value of their share has more acreage, minerals, barrels of oil, Mcf of gas, and midstream property value that they have, and that's why we think this year is really going to be good because whatever we did last year, we should be able to do again and that's our challenge to everybody. Here, guys, you all were pretty good last year but we are expecting something better today. So, what have you done for us lately is what we ask the staff, and they are responding and doing I think a really good job and we're off to a good start.

And Jeff, if I could just add one quick comment, this is David, just wanted to say too that it's also a lot about the quality of the acreage for us, and I think that we are working pretty hard, all the guys work very hard to increase our position in wells that we know we're already going to drill or units that we know we are already going to drill. Those don't always show up the value, those don't always show up, and maybe we had 20 acres on a particular well or 40 acres on a particular well, but in terms of the value that it creates, it makes a big difference. And on the acreage count, if the land guys trade 200 acres with another operator, that can have a lot of value to both parties, and from our point of view it doesn't make the acreage count tick up but it can certainly make the value tick up, it can make the number of wells that you can drill, your ability to be the operator. So, there's a lot of things I think for us going to the whole land game other than just simply how much can we make the tugboat go up.

Jeff, this is Matt. I'll just pile on what David is saying. I think we are much more focused on quality than we are on quantity. I think we would much rather add 100 acres in a block that we've actually got a well that we have proposed to drill on than we would 100 acres somewhere else where we are not going to be the operator. So, what David said and what Joe has said, if we are adding 100 or maybe 10 acres or maybe 1 acre, no acre is too small for us, but if you can just continue to put those little blocks together in very advantageous areas, that's a homerun for us.

All right, great. Best of luck on that. Appreciate the time, guys.

Jeff, just as a follow-up to what Matt said, when I started in this business in 1983, I was doing one-acre deals. But they can really add up and aggregate. And to emphasize the mineral part again, particularly where you are drilling multiple wells on the same tracks at different depths, anything you can do to help the net revenue interest by higher net revenue interest leases or by minerals, has a cumulative effect. And what David said underscores, David and Matt said on the quality, we may not equal the 25,000 acres in quantity, but the quality we had this year may be the best ever.

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

Did you all discuss following these midstream deals that you have announced what the third-party opportunity could look like over the next couple of years and how are you taking a look at that at this point in time?

This is Matt. That's a good question. And one of the things we have done strategically when we built these midstream assets, if we go all the way back to the plant we built down in Loving County, that we ultimately sold to EnLink, we typically build these facilities initially for what Matador needs with some extra. So, going all the way back to the plant down in Wolf, we built about a 35 million a day plant thinking that initially we would need capacity for 17 million or 18 million, which is kind of what happened, that got full with liquid gas. EnLink now operates that plant. So, if we go up to the Rustler Breaks area, we did the same thing there with this initial facility. We built it and we thought we'd initially have 35 million to 38 million coming into that facility, which we did. And so, we got that full and now we are going to ultimately 260 million there. So, during the time that all of this is happening, the midstream team, Matt Spicer, Gregg Krug, and their team, they've been out talking to third-party operators and we do have some third-party coming in on the salt water disposal, and as we continue to drill these wells and add capacity, that just gives us more and more room to do that. This plant expansion will be operational here into the first quarter. So that's going to give us some room. But I think one thing that ties back into this Plains deal that Matt and his team can go out and do this is sell the three-pipe system. And so, when they do that, they're going to be able to go and say, we're one-stop shopping and we can handle all these needs. So, those opportunities are there and they are out getting these things done and the deals are coming in now, and I think they are going to continue to increase.

Matt, you did a great job on that. Do you want to add to that, Matt?

Sure. This is Matt Spicer. We have added to our business development team on the San Mateo side substantially here. We think 2018 is going to be kind of the year of the third-party now that we have space. Seems like every time we build an asset, Matador fills it up. So, we got ahead of that with salt water disposal, with gas processing, and now with our oil terminal and with our oil gathering. So, we are very excited, we know the activity is very, very high up there in Rustler Breaks, and we're meeting with pretty much all the producers in the area to make sure that they have optionality, just like we have provided for Matador.

And specifically to that point, it seems like you guys have obviously outrun your expectations over the last couple of years, so certainly good for you but maybe less room for third party. Now when you are looking at this new system and your continued development, are you thinking about over-sizing it even more with the expectation that that third-party bump is going to be a much more significant opportunity here?

I think that's a great point, Scott. The deal we did with Five Point allows us to, what you say, upsize our facilities to 260 million a day and gas processing. I think that leaves substantial room for a third party. And then our oil line, we increased that size after the Plains deal and we'll have upwards of over 100,000 barrels a day that we can take through those lines. So, with the deal with Five Point, we have gone that extra step and created a significant room for third party.

Okay, that's great. Thanks. And my next question is, royalty rates on average, and David, I think you made a point that obviously you've been buying some minerals and I know you guys have some state and some federal land, when you look at 2018 activity, could you give us a sense of what you think your just high-level average royalty rate looks like in 2018 versus say what it looked like in 2017?

Scott, I wouldn't expect for it to be very much different in 2018 compared to 2017, just mainly because the mix of oil and where we are running the rigs isn't very different. I think, as you know, we tend to have advantaged royalty interest up in the Ranger/Arrowhead area because there are a lot of those wells that are drilled on federal and state acreage where we have a little bit better royalty interest. In Rustler Breaks, we probably run a little bit ahead of the 75% number, but it's probably maybe 77% or something like that. And down in the Wolf area, it's probably similar but maybe a little closer to 75% there because most of all that acreage is fee. The other thing that we've been doing is, as Joe mentioned a minute ago, is we have been buying some minerals here and there, and certainly when we've been able to do that, that's helped to improve the royalty interest or the net interest to Matador in those cases. And there's also been a case or two where we've added a federal lease within an existing unit. That's further improved our royalty interest there as well. But I don't think mix-wise it will be terribly different than what you've seen in the past.

Okay. So, right around, it sounds like an average around 20 or maybe a little bit above that is probably not the best number to use then?

Yes, I would say if you are using that revenue interest for us between 75 and 80, you are probably going to be right nine times out of 10.

All right, thank you.

Our next question comes from the line of Irene Haas with Imperial Capital. Your line is now open.

So congratulations on another record quarter, and my question has to do with the midstream. Seems like in the Delaware Basin there's really plenty more to do requiring more capital. Just kind of wondering, outside Wolf and Rustler Breaks, which of your sandboxes might need more extensive sort of midstream buildout opportunities? And if yes, when should we expect that material to come public?

I think, Irene, as we go forward here, the deal we have with Five Point is with that Rustler Breaks and down at Wolf. That being said, we have the option to bring those guys in on anything we want to do in the rest of the basin. And I think it's going to continue to be just as it has been in the past, Irene. It's going to be opportunity-based and need-based. So, as we ramp up activity in let's say Antelope Ridge, that's a new asset area for us to be operating in. We will take a very close look at all the things we've been talking about, oil transportation and delivery and gas transportation and processing, getting rid of the salt water and transporting salt water, doing all those things, and where there is an opportunity and where there is a need where Matador can fulfill a significant portion of that as an anchor tenant, that may be something we can look at and we'll look at. In some areas it may not make sense for us to be in that business. So, it's just going to continue to be, as we've talked about it over and over, value-based and opportunity-based.

Okay. May I have one follow-up question? Just a little color on the Twin Lakes Wolfcamp D well, it's taking a little while to complete. Sort of any update and color on that? That's all I have.

Right now, Irene, I'm assuming you are referring to the well we're partners with Cimarex, and they are continuing completion operations. So, they are still in the middle of completion job.

Okay, thank you.

Our next question comes from the line of Dan McSpirit with BMO Capital Markets. Your line is now open.

Can you speak to cycle times today and maybe how they can improve over the course of 2018 and what that might mean for the production growth profile?

Dan, that's a hard question because we are drilling so many different zones, some exploration, some development. But Billy Goodwin, who is the Head of our Operations group, and Matt, and their stuff have done a very, very good job of turning down the number of days on wells. Some of it is the technique and the experience of the guys on supervising the well and some of it is just the better equipment that we've been able to get from better drilling rigs at Patterson. We made deals with Patterson on that more powerful pumps and just better equipment. And the same thing on fracking, cutting down times on the well. So, give a lot of credit to them. That's one reason we drilled more wells than expected last year, which helps to mitigate the cost. They are continuing to do that with innovations, as I said, bid design, but also now we have got a 24/7 room what we call our [Maxcom] [ph] program with engineers and geologists working together interdisciplinary 24/7. So there is somebody here on the job at all times monitoring the penetration rate on the horizontal wells that are being drilled and keeping them in zone and this is already starting to cut costs and improve efficiencies greatly. Billy, do you want to add to that? I want to give you a chance. It's a great idea you've done.

This is Billy Goodwin and Joe touched on a lot of the good points there of what we are doing to cut down on days on wells and do better and we love the rigs that we have out there custom-built with a high pressure system and piping. We rig them up for MPD, managed pressure drilling, and work closely, as has already been said, with the bedside and BHAs and adding to that – and also another thing that we are doing this year, the asset teams have gone together and we are going to be doing a lot more batch drilling this year. So we will be saving over $200,000 a well on the drilling side and also on the completion side as well. So that's over $400,000 a well we're going to save. That also helps us on our efficiency, like Joe talked about, and helps us utilize all that. And then also we mentioned our new [Maxcom] [ph] program and this is something that we started up 24 hours a day. You get a call at 2 or 3 in the morning trying to decide what to do and we as a company feel like it's very important to stay in the target zone, we think we get better wells that way, and this has people looking ahead of time not being woke up when something is wrong, to keep us in zone more of the time, right where we want to be. So we are doing better there, but also we had people in there watching. It helps us on the performance. We just recently started this program and we have already seen new records in different hole sections, vertical part of the hole, lateral section and build section, all three. So it's working out for us, improving the performance, improving our costs, and also creating situation where the engineers and geologists are working together and arguing with each other who makes better team member. So, it's better for us all the way around. We are really excited to keep moving forward this and getting better.

It's Matt. And what Billy is talking about, it's a fantastic program and we've been doing all the things he's been talking about, but this kind of rolls it all together. And so, we're all about efficiencies at this Company, we have talked about that forever, and we continue to be about efficiencies. And just in regards to [indiscernible], just had a couple of additional points there, we don't typically run large duct inventory. And so we have really good relationships with our vendors. We're using [indiscernible] nano frac jobs and we're able to – with some adequate planning, I think it's a very important part of this, to be able to schedule additional frac crews when we need them to make sure that our documentary doesn't get, hardly at all. We want to be able to drill these wells. Billy is talking about batch drilling, so we may have two or three wells that we drill on a location. And then just as soon as we can get that rig off there and get a frac crew, that's what we are trying to do. So, that's one thing that helps in cycle times. And then another thing is it ties all the way back to midstream again. It's just for us to be able to walk down the hall or for Greg to walk down the hall and say, marketing [indiscernible] hooked up to midstream tomorrow. That happens for the most part. So that's a huge benefit there. And so we do focus on cycle times, but as indicated here in the first quarter, we are going to have some batch drilling that's going to provide some continued lumpiness, as it always has before.

Dan, it's regarding question, and that's why I always encourage people to look at things. It seems like on a six-month schedule instead of a quarter schedule seems to have now a lot of the timing differences on your cycle times. So, there's a number of factors that affected the batch drilling, proximity to the pipeline because we don't want to be flaring, but everybody is very aware at each stage of this to reduce time as much as possible and collectively they keep managing the time away to cut days off each well in each area. So, I think it's great question and something that I hope you've seen the improvement over the years.

I appreciate the detailed response on how to maximize throughput. As a follow-up if I could, and last one for me is, what is the PDP decline rate on oil and gas in the Delaware Basin and how might that change over time?

This is David, Dan. To tell you the truth, I don't know if my numbers would be terribly accurate if I just try to pull something off the top of my head this morning. Maybe we can address that a little more at the Analyst Day. I think I would feel a little better prepared to take on that question at that point if that's all right.

Yes, that's fine. We'll see you soon. Have a great day.

Our next question comes from the line of Sameer Panjwani with Tudor, Pickering, Holt. Your line is now open.

I was wondering if you guys could provide some color around how you think about Wolfcamp prospectivity at Ranger. I know you have tested the Lower A at Ranger last year and you are looking at an XY test at Arrowhead this year, but just thinking about it from a broader perspective, how large do you think the Wolfcamp opportunity set could be, especially when you consider the potential for stacked pay at both Ranger and Arrowhead?

This is David. I'll start, then I imagine Ned will probably want to weigh in, Sameer. I think we still continue to feel like that there is significant potential in the Wolfcamp, in the Ranger and Arrowhead area. I think we have taken a couple of stabs at it and I know the other operators have as well, and I think that it's again going to be just a matter of – it's a very thick section, there is a lot of opportunity, there is even opportunity I think for multiple targets within it. It's just a little different animal, doesn't have quite the overpressure that you see in the Wolfcamp down to the south. And so, a lot of those wells tend to perform a little bit more like the Bone Spring up in that area. So, I think that we are still on the learning curve there as far as – but there are areas that have the XY potential, there are areas that have the Wolfcamp A-Lower potential, and there are other zones deeper in the Wolfcamp as well from Rustler Breaks on north that we are excited about. So overall, I think we continue to be encouraged. I think it is something we are going to take at a slow and steady pace. I mean we have most of all that acreage in the north as I mentioned before HBP. So I think we are going to focus primarily on the Second and Third Bone Spring, but we'll continue to test and learn what we can about the interval. And I think from an exploration standpoint, we remain very encouraged about the potential. Ned, do you want to add anything to that?

Yes, I do, David. I'm very optimistic and I think the geoscience team is also very optimistic about the potential there, and I think David kind of hit the nail on the head, we're taking a pretty deliberate approach up there. And right now, we're sending some of the team out to the various core repositories in New Mexico and Midland and [pulling cuttings] [ph] and really starting to do a pretty regional study on the Northern Delaware Wolfcamp. The initial reads on that are very positive, and as David said, we have a lot of optionality, the XY are present, [indiscernible] has got the call out for a potential test this year with the XY spreads within a lot of that Northern Delaware acreage. So, we are excited about that. The Upper Wolfcamp elsewhere looks good, the Wolfcamp B is also widespread target up there. Some of our preferred targets in the Wolfcamp B that we have seen in Rustler Breaks will also extend up there. So there is a lot of potential and I would say again just sort of watch that space over the next year or two and we are really hoping to prove up that asset.

Okay, that's helpful. For my second question, I was wondering if you guys could provide some color on what the delivery point is for that gas takeaway agreement you have with El Paso?

The current deal we have with El Paso, Sameer, gets us to Waha. We are keenly aware of the issues around getting out of Waha and we tend to look at these things on a long-term basis. So, we are looking at multiple options to continue to get that gas out of there right now. Knock on wood, we don't have any issues getting that done. But I assure you that Gregg and his team are rock-solid and they are looking at what's available today as well as what's going to be available tomorrow and in the coming months.

Okay, thank you.

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

This is actually John [indiscernible] stepping in for Ben Wyatt. So, first question just goes with rigs. So, three rigs are locked in right now, three are on shorter term contracts. Do you have any concerns with service prices maybe going higher, would you consider securing any of those three additional rigs at lower rates?

This is Matt. I'll answer and I'll ask Billy to jump in here, but the brief answer to your question is, no. I think we have a very strong relationship with Patterson and the rigs we have operating on a short-term contract, we are in constant communication with them about what our plans are for the near-term future and also for the long-term future. So, the notion that those rigs would go away from us without us having an opportunity to lock them down, that's not going to happen. I don't believe that's going to happen. As far as having them set to market rates, certainly they would be. But kind of the way I think about things, and again I'm going to ask Billy to weigh in, is the cost for the rig is a significant component of what the well costs are but not what it once was. So, I think the efficiency that you're going to achieve with having these high-tech rigs, the momentum that you're going to carry by continuing to use these types of rigs would certainly not entirely offset any cost increases but it could potentially have a very impactful result in maintaining cost.

I think that's a great answer, and just like Matt spoke about the relationship we have with Patterson, they lock some longer terms, some shorter terms, that's good for both of us together, and as we move along, move into different areas, one of the rigs we've added additional pumps and a high-torque top drive and they work with us to get those things done in that play, then we can just roll that right into the next extension on the contract. So, it's a good relationship and works good for both of us.

Got it, thanks. And just one final question, just [two D well] [ph] down in that Wolf/Jackson Trust, very strong results there, good oil cut and pressures, do you guys see the Lower Wolfcamp A becoming more of a target this year versus the A-XY in that asset area?

I think that we'll continue to focus on the Lower there. So, if I recall, the XY itself is not particularly that present there. So that's really the better of the A targets. You kind of get into the XY as you come over a little bit farther to the west there, as you get into the Wolf area. So, that's another reason why we focused a lot on that interval. There's also multiple Wolfcamp targets there. So we may look at something else as we go forward. And we may even look at a B test there too down the road. But I think you will see in the near term probably more focus on that A Lowers out there.

Got it. Appreciate the color, guys. Congrats on a good quarter and I'll see you guys soon.

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

Thank you very much. I have just two last, or I guess three points, last points I want to leave you with. As you look at the share values, I think you will – this year my prediction is you will see a year much like last year, continuing work in all three of those areas. Second is I'd really like to point this out is that staff works hard on its projections and I think we enjoy the fact that for the last 14 or 15 quarters we have met or exceeded guidance. So, that's 3.5 years of meeting or exceeding guidance. So, our consistency there, again I give a lot of credit, the credit goes to the staff here, Roswell and in the field on delivering on that. And finally, when you have a strategy, we don't have a grand strategy that we will be the 3-D in this Company, but we have a strategy based on better and better performance or continuing and finding ways to reduce cycle time or to improve the drilling, improve the fracs, like land deals, when you have that it's not one factor. So there is a lot of strength in the fact that each of our groups are working well and getting better and adding to the overall, contributing to the overall effort of Matador. And so, as we saw two years ago when oil hit $25, we kept going and there were a lot of people that said, maybe you should reduce rigs. We didn't and we had a lot of innovation and improvements and we got better rigs from Patterson as a result and it had a lot of benefits. We want to be careful about the money. We are all large shareholders here. We have big stakes in…

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