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Good morning, ladies and gentlemen, and welcome to the First Quarter 2018 Matador Resources Company Earnings Conference Call. My name is Ayala, and I will be serving as the operator for today. At this time, all participants are in a listen-only mode. We will facilitate a question-and-answer session at the end of the company's remarks.
As a reminder, this conference is being recorded for replay purposes, and the replay will be available on the company's website through May 31, 2018, as discussed in the company's earnings press release issued yesterday.
I will now turn the call over to Mr. Mac Schmitz, Capital Markets Coordinator for Matador. Mr. Schmitz, you may proceed.
Thank you, Ayala. Good morning, everyone, and thank you for joining us for Matador's first quarter 2018 earnings conference call. Some of the presenters today will reference certain non-GAAP financial measures regularly used by Matador Resources in measuring the company's financial performance. Reconciliations of such non-GAAP financial measures with the comparable financial measures calculated in accordance with GAAP are contained at the end of the company's earnings press release.
As a reminder, certain statements included in this morning's presentation may be forward-looking and reflect the company's current expectations or forecasts of future events based on the information that is now available. Actual results and future events could differ materially from those anticipated in such statements. Additional information concerning factors that could cause actual results to differ materially is contained in the company's earnings release and its most recent annual report on Form 10-K.
Finally, in addition to our earnings press release issued yesterday, I would like to remind everyone that you can find a short slide presentation summarizing the highlights of our first quarter 2018 press release on our website on the Presentation & 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; Billy Goodwin, Executive Vice President and Head of Operations; Van Singleton, Executive Vice President of Land; 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 & Asset Manager; Jim Basich, Vice President and Managing Director. So with that group, I hope we can answer at any questions that you may have.
We believe we're off to a great start in 2018 and I'm proud to announce the first quarter was another strong current quarter marked by both excellent financial and operational execution. I want to take a moment and personally acknowledge Matador staff for all their achievements this past year and quarter. It was truly a team effort with each department and each group contributing to this success.
In terms of awarding the game ball, it's a hard choice because everybody did so well. But I'd like to particularly callout the guys in the fields, who work through the weather problems and delivered better than expected production and have really been committed to that work and it's not as noted sometime because they're in the field, but they’ve done great into our Midstream Group, who brought on their new plan on time, on budget and also came up with some important deals that have start to build the momentum and the value in our Midstream Group.
Now having said all those sayings, we also are very interested in your feedback. We heard from you that while we were trying to be fairer and transparent and comprehensive that perhaps our earnings releases were tending to get longer and longer and maybe not quite as easy to find the information. So we've tried to come up with a new condensed version and welcome your feedback with the like this best, the one we have that's half the size of the other one or the full comprehensive set that it does such a good job pulling together.
The second point, I want to be – to make is that this is the 15th straight quarter that we met or exceeded guidance. Again, our total team effort as each group is contributed to that. Second is we believe and feel that we have a new key operating area in Antelope Ridge and the third point that I would like to make is just in all of our operating areas around the basin from Wolf to Rustler Breaks to Ranger to Arrowhead to Antelope Ridge and to Twin Lakes, we had some great encouragement on our operations in all that area. And Van has delivered – in his Land group have delivered the brick-by-brick adds to our acreage and within the basin, where about 60% HBP.
And with that, I'd like to ask Matt Hairford, our President to address the most often asked question we've received this quarter at various conferences and non-deal road shows which is that takeaway in the differentials. Matt will you give some note on that.
Sure, Joe. Thank you. Joe's right. It's been a topic of discussion at most of the meetings, that takeaway capacity and when we hear Matador are focused on takeaway capacity for gas or oil and our NGL’s as well as making sure that we have an ability to cost effectively dispose of our salt water. So on the gas front, we got to firm transport FT for all the gas that we produced at Wolf, all the gas we produce at Rustler Breaks and all the – well not all the majority of the gas for the designed play capacity at Rustler Breaks there. So the FT we have is from the field to Waha/Mendoza Trail.
So let get it’s to Waha. That being said to get from Waha to say the Texas Gulf Coast, we're currently evaluating and conversing with lot of midstream companies about that next step. How we do that? And one of things, we're going to be very methodical as we do this and make sure that whatever deal we do today, we're going to be happy with it today. We're also going to be happy with that tomorrow. So that kind of takes care, I guess, for us on role.
Our takeaway capacity has been greatly improved with this transaction we did with clients. So right now, the oil that we produce at Wolf is going to play into the vast majority of it on the pipeline systems and accrued systems that they have in Loving County. They are going to extend that system up into rest of rigs areas, so all that we gather and produce at Rustler Breaks will be going into that system, probably sometime in this summer. So we feel pretty good about that.
The deal we have with client is not our traditional FT but what happens is as Plains are actually buy those barrels at the wellhead or with the CDP, charge us transportation fee to get it to Midland. When it gets to Midland, we have had our discretion. The option to buy those barrels back. So if we can access other markets – say, St. James, Cushing, Texas Gulf Coast. We can buy those barrels back in and deliver into those markets, if not Plains, we keep those barrels and deliver them on their system. So that takes care of the workforce.
The NGL is an interesting thing for us. We just recently finished an interconnect at the tailgate of the Black River plant there Rustler Breaks for NGLs. So it's a Y-grade NGL line. BP is actually buying the NGLs for the total plant volumes, Matador and other producers in the area. They're buying the gallons or barrels putting them on this Y-grade line and then taking into market bid or so. Feel pretty good about that.
We’re also real advantages with this NGL interconnect. One of them being the elimination of the need for trucks, so even when we're running the $60 million a day plant, we had 20 to 25 trucks per day going into that plant hauling out for NGL. So we get rid of those trucks and then as we continue to increase the volume, if you go from 60 million to all the way up to the plant capacity 200 million, 260 million cubic feet per day. You can see – then the logistics around having all those trucks on the plants is just not very good. So quite to have all those NGLs on pipe – the transportation cost is obviously a lot of cheaper on pipe than it would be for trucks too, so that's a big advantage. And then the third thing really is the ability to go into full ethane recovery mode in this plan, so big advantages there. At some point in time, ethane will likely become – in the money as a liquid as opposed to selling at back end of the gas chain on a Btu basis. So we have the ability to do that. The other advantage that gives us, it does reduce the residue gas volumes at the tail gate of the plant by 5% or 10%, so that frees up some additional capacity there.
And then the fourth thing, it's not really a take away issue, but it's more the ability to be able to cost effectively dispose of our water. So these wells in the basin they make a lot of oil, they make a lot of gas, they also make a lot of water. So if you've got a well it's making 2 maybe 3 or 4 times the amount of water than oil you certainly need to have an outlet for disposal of that water. So we've got things covered, we got 160,000 barrels a day capacity now at Wolf and Rustler Breaks. We owned 220,000 by the end of the year. So I think all in all we feel pretty good about the proactive steps that we’ve taken to make sure we can cost effectively flow our wells.
Thank you, Matt and thank you for your hard work in those various projects – those multi-location projects. So now we’ll open the line for questions.
Thank you. [Operator Instructions] Our first question is from Ben Wyatt with Stephens. Your line is now open.
Hey, good morning guys.
Hi, Ben.
If I can maybe start on the midstream side just because I know you just finished up with that. Obviously it sounds like you guys are in really good shape there. But where do you believe third-party volumes need to go for Matador to maximize value for its midstream assets? Or should we kind of view this as an asset that is dispersed a safety net for Matador and its volumes. And then really kind of any third-party volumes that move through the system or just grabby. Just curious your thoughts there.
Ben, thanks for the question. What we would like to really insert, we're playing the strike game with this midstream that we have a partner in here Five Point who owns 49%, while we’re at 51%. It's very important that people know that we're going to give them – we're going to play a strike game, there's dependence between the two companies where we collaborate. But the midstream has been charged with delivering the same services – just as good as services to third-party as they deliver to us.
So that the third-party decided to go with us is going to get that same high end and be just as service oriented. That's our task and that's their challenge. That's what Five Point, the deal was based on, that this wasn't going to be a brother-in-law kind of deal. That this was going to be good service for everybody in all ways. And we think that we can tailor it to make it better because we're in the business. And that we think we can – because of our size that we can tailor the agreement to fit the particular needs of the people and provide the three part services that are becoming, I think the high end of the business in terms of service to the independence of providing gas take away all gathering on part and then salt water disposal.
So it is not a – we're not going into it, it is a – so that other parties are going to be stepchild or any kind of guess, they’ll give us a chance, I think they'll say it's going to be the same high quality services, we're expecting our mid group – midstream group to render to us. Did that answer your question?
Yes. That's helpful, Joe. I appreciate the explanation there. And I guess my second one here. Just around the potential that the seventh rig, you guys kind of alluded to that maybe by year-end. Does the current environment around takeaway concerns in the Delaware delay that seventh rig potentially until late 2018 or is this just – so I just think this is just Matador kind of staying consistent with its approach to kind of to move it that measure pace that you guys have always talked about.
Ben, that's another good question. And it is not a single factor we’re way in both of those concerns that you’ve said. That's going to be the final decision is going to be based on the number of circumstances. One is commodity prices; two, just as you said what's happening on the gas take away from the basin; third one is, yes we have a biased towards doing things in methodical manner, profitable growth at a major pace as we say. But another factor that we would weigh is that, that we weigh so heavily as opportunities and when you speak of opportunities not only in our new development NL bridge and the march northward up into the northern part of the basin where we’re being really encouraged and have plans.
If this price different – we don't think it's going to stay at this all differential but you have about $13 advantage in the Eagle Ford on your oil price. If that should remain we might get down there and put a seventh rig to work go in four or five more wells in the Eagle Ford to take advantage of $13 advantage, I’m not saying that’s our first choice today by any mean. But $13 is a significant difference and it does make you consider where is the best place to put it right in all the different circumstances.
So again I want to – I don't want to mean it by that we're going to dump money in there but we're churns would be a couple and you can take if you're going to have a problem of differential turn some of it into an opportunity. So no one should re-debt that we have plans to do there other than that we take the full range of circumstances and try to be opportunistic in what we do.
The last thing that I'd like to underscore and this is some that both Matt and David talk a lot about is that we have the option – we have three of the rigs on very short-term contracts. So we could drop one of those rigs and pick up one of these newer rigs that have most technologically advanced state of the art equipment. The pumps and the top drive and we have one of those now that’s working very well for us and give a lot of credit to Patterson.
And we’ll keep picking up another such a rig in case add six but that’s another circumstance – how much help could that be – still saying six rigs, so we’ll look at price, obviously price drops and is less likely but it's just too early in the year to know exactly what is the best line up of rigs and drilling opportunities because we want to be nimble and may prepared to make some changes in various rig lines dependent on the circumstances. I know that’s a long winded answer but it's complex and we give it a lot of thought.
No, I think Joe very, very helpful and appreciate the answers here and for what it's worth. The team here at Stephens, appreciates you guys saving us a little paper.
So I just might add. Ben, this Matt. I might just add to what Joe said. He’s exactly right on maintaining the optionality we have with the rigs – we can’t, if we go to seven we can quickly go back to six or five or even four. I think on the other side, it’s a continued methodical approach, unlike the – use those words because actually that’s the way we think about things. But we do have our factories where we could, if we had seven to eight we have a second crew that would be available for us to – on a dedicated basis. And also with the factories if we wanted to go back to one we can do that too. So that’s an optionality in the program.
Very good. Thanks again guys and keep up the good work.
Our next question is from Neal Dingmann with SunTrust. Your line is now open.
Good morning guys. Joe, this question for Mac Schmitz and his team. That Leo Thorsness well certainly very notable, I think as you mentioned maybe even a record IP for you all, which was something different or specialty all did on the completion side or is it more just sort of advancement as you continue have more knowledge on the play.
You’re right. There a very nice well. We're very happy with the results there and I think it's just a continuation of folks were just there as well as drilling very well for less money – The notion that it was any one thing that made that well particularly better than a lot of other wells is, I think is probably it's more of picking the right target us continuing the state in that target and be effective completion that's going to continue to evolve. So I think it's just a member of the things I put together and the good right part of it is it's a big portion of it too.
I agree with everything, what Matt said. One thing to add is one innovation that we have we put into effect this quarter, it's a very last year was what we call Maxcom program where it's a 24 room where we have some of our young engineers and geologists working together 24/7 and it's working out to stay in zone better to drill faster wells and it's really didn't wonderful job and so on some of these wells if you just stay in zone. So you get more exposure to the right rock you need to be really helped, and they're growing faster which means less money and this is very good aid for a number of people what head places as we've drill three wells in this area three different zones and very pleasing results in each zone. So you you've got a lot to work with going forward.
One digression is what – my thing is we've been fortunate to have been number of Medal of Honor recipients of share holders and one of them was this [indiscernible] and interestingly and coincidently – service recently and in his service was service was an Arlington Cemetery on February 14 about the day we brought in this well. So [indiscernible] for six years in North Vietnam and it's really not said we could honor him and his family and tell them here's your son for your well and it's the best well we've drilled from that zone and have that kind of positive message for them and positive message for our shareholders and you.
So that it is nice to hear Joe. And then just one maybe follow-up just on M&A, you guys continue just to do a fantastic job on leasing not only now having more leases but now even had some minerals this last go around. Just any comment is that how do you all feel the market still is it still pretty opened and continue on the pace you all been mean from either you or anybody from the land team would love to hear your thoughts there.
Neal, that’s a hard question, we can clearly see the market has not yet gone. There are still plenty of opportunities out there, but you never know when that door is going to shut down or just burst open. We're nibbling away, that brick-by-brick concept, and we don't see the market closing. The Land group – Land and his Land group are still encouraged by what they see, it's just really hard to predict a challenge to me – trying to get a date to prom. You don't know whether there's a lot available or none available. But you're just going to be out there pitching until – as best. So I don't think we've got enough data points for this year. I'd say let's look for this summer, mid the late summer and we should have a better idea how we're going. But we're encouraged by what's in that plan, but you're not ready to say victory yet.
Great. Thanks so much guys.
Thanks Neal.
Our next question is from Gordon Douthat with Wells Fargo. Your line is now open.
Hey good morning guys. Just had a question on Garrett pad and just wanted to get kind of some more details on your observations on that stacked development and if that looks like it’s how that's producing relative to one after one or two well pad and if that’s kind of been – it more those types of stacked pad development or in the future as you.
Hi, Gorden its David. Well, so first of all I think we were very pleased with the results from those you know those three wells and – had a high degree of confidence I think going in to the drilling of that three-well pad that we had three intervals there in both the WolfcampA-XY a lower and then the big bowers that we are all going to be very successful intervals for us based on our other drilling at Rustler Breaks and it just made sense to not come out at the same time. So just helps you on the rig move and so it's cost when you're able to back drill and so cost when you're able to come back in fact sort of at the same time and, so you know it's not only did we feel like we really get good results on the production side, but we knew that doing that was going to also contribute to us to that same some money on those wells and so I think that as we said this year that most of our drilling is going to be done in twos and threes and I think that you know as we go forward you'll see us begin to drill wells in more going to get this back mode but I think we'll continue to move toward more of these three and three plus kind of pads. We certainly had varies is Rustler Breaks already where we've drilled up to five different zones. I believe of the same essentially of the same pad sometimes five in one direction and five in the other direction, we just haven't done them all up the same time, but I think this was – we're not state of point and we were pleased with the outcome.
Okay. Thank you for that. And have you noticed any – from a productivity side of it maybe any doing it all now.
I would say that the well productivity has certainly been very good from all the zone, so that's been positive. I would say just on overall maybe capital efficiency I think that’s also been positive as is I mentioned I think in the operations got always liked it when we're let's drill multiple well after same pad or are scheduling them that way because he's frequently in my office, telling me the more we do that the more money can save. So I'm always we're always paying attention and then in addition you know I believe we're also receiving a discount from our service provider on the fracturing side. When we're doing – we're doing these wells on a kind of what we call a simultaneous operations type basis where we have both the tracking and the red line go on for some time and as a result we can get more stages down in the day and so. So all in all think that it definitely helps from a capital efficiency standpoint
Okay. Thanks a lot guys.
Our next question is from Scott Hanold with RBC Capital Markets. Your line is now open.
Thanks, good morning. So Joe you had a pretty good discussion about were at seventh rig you know on that seventh rig and I have a question in the bridge area obviously you got a rig that dedicated to that area continue generally give us a sense of now that you can be more into development mode or start to move into that at this point. Is there capacity added second rig there or how do you contemplate the midstream need there and how you approach that?
Scott, our plan on that is just what we try to do everything is be very methodical we're going to start at one rig we're not going to just because we have a very good well suddenly double to two or three rigs there. We have so many good opportunities around the basin and we're going to continue to go in methodical fashion and develop this with one rig and at some point we hope it just fast a second rig. But we've got a number of good areas that are very promising and that we're going to test more those as we move north in the basin to other good rock, I think Ned, Head of Geoscience, sees connections from the Antelope Ridge area and going north that he's advocating. And I'm going to let him speak in a moment on that, on what the encouragement that he sees moving north. But also wanted to say, if we go to seventh rig and amidst all the volatility, it may not happen, we're looking at it towards the end of the year, which will have little impact on our overall CapEx spending, because if it's put in service. It'll be towards the end of the year and it's really a 2019 event.
And we are hedged, so that we are protected through 2018 for many drastic downside moves in price. And the reason we are trying to emphasize maybe options more this year, optionality on where to put the rig. What kind of rig, always questions is because the volatility and price, but we keep in our message that I think it's notable, Scott that Matador had $0.36 of earnings per share and compare that to other companies that I think that's one of the better ones and that effort to try to put everybody on a level playing field is going to the earnings per share.
And I'm of proud that, I'm proud of better EBITDA was at record level. This is the best quarter we ever had in terms of the EBITDA, not just production, but EBITDA and reserves. Our reserves are growing the way we want. So it's a good plan we want to tinker with it, find ways to improve it, but also the pace that – as I said Matt and David like to shares with me is working is that we don't get in a hurry, we're in a third deal. We’re validating the acreage and there are opportunities moving north and you never know, if we committed the second rig here with the exploration work we're doing in Northern Delaware. We may have to come back and say, we spoke to soon, we really need to appear this is an even better area.
So everything is on the table, we're trying to remain nimble, we're trying to keep up the optionality, and how we make the joke around here, we reserve the right to get smarter. That if things need adjustment, we’re going to be quick to make them, that's got to be one of our advantages. Matt?
Yes. I think that's absolutely, right, Joe about Antelope Ridge and the Northern part of Lea County. As you remember, we really drilled some of our first wells up in the range area, which is Northern Lea County. And it feels very familiar to step into Antelope Ridge, because a lot of the high quality upper Wolfcamp and Bone Spring, that people are drilling in Antelope Ridge. It’s really expense up into Ranger.
So I think we're excited to push the boundary for that play and the first three wells we drilled here, I think we're all very high quality results. And they showed the potential of that area, but as the exploration is that I think, you begin to see what works in Antelope Ridge really extends quite a bit further north. So we're excited to continue to keep pushing that boundary further and further north that are done.
Scott, this is Matt. In regards to your midstream portion of the question, it's going to continue to be what it's always been for us. It's going to be opportunity based. So if we get – getting to an area, say, Antelope Ridge and it looks like we need to drill a commercial salt water disposal, well that matter to what will be the anchor tenant on and then we can serve as other producers in the area that will be something we would look at. It’s probably the most likely, I guess, processing or oil gathering things like that will come too, but it’s all going to – always going to be opportunity based.
Okay. On the midstream, when do you need to make those decisions, I mean, when do you think, we have enough deal and then operated volumes you have to make the decision both salt water disposal and processing and all the other things.
Yes, thank you. It kind of falls into what we've done in the past, where we get to where Matador can be an anchor tenant, it's a 50% capacity or something like that, Scott. So it's – these areas are through the salt water disposal, if you drill several wells that kind of justifies drilling. One of those – we actually have with salt water disposal well in the area that we're utilizing it's not a commercial, it’s just from Matador’s use, but as we continue to increase activity, both at Antelope Ridge and in other areas, we will just look at that on a case-by-case basis.
Okay. That makes sense and as my follow-up question, working interest was a little higher this quarter. It looks like you guys have done a pretty good job of blocking and tackling, and adding on wells you all are drilling. Similarly that gives some of your best rate of returns on acquisition or a swap investment. What should we expect throughout the rest that I guess you’re running a little bit high to the budget on the working interest how does this bias the production and CapEx expectation through rest of the year?
Thanks, Scott. It’s David. I think that it’s quite a little early to know that so we are taking a look at that, but I think that it’s a little early to know when – as far as the ability of the group to make the trades, I mean I really want to compliment the land group for all their great efforts this all of the time, but in particular, this past quarter and making some very high value trades and doing some good things and sometimes I think as everyone knows. We’ve talked about it a lot. there are areas where we don’t always have 100% in the wells that we’re drilling and maybe we’ll have 50 or 60, our objective is always to try to maximize our working interest in those wells. And so we did the best that we can to sort of forecast that in advance, but sometimes the gas come through with just an offer you can’t refuse. and I think there were several of those in this past quarter and really delighted that we had the opportunity to take advantage of that, I don’t know of any specific other ones that are out there pending, but I’m confident of is that some of that will happen and what as I say, we’ve tried to anticipate that to the best of our ability. but if we have undershot a little bit and are picking up some extra interest in some wells that really had value. that won’t bother me.
Understood. thanks
Our next question is from Gab Daoud with JPMorgan. Your line is now open.
Hey, good morning everyone. Could we maybe just talk a little bit about just the CapEx overage on the Antelope Ridge wells? I think there was maybe $10 million average, we mentioned something along the lines of a little bit of a slow start? And maybe just a little bit more color, and then just overall what you’re seeing on the ground form a logistical standpoint in the basin? Thank you.
A part of that costs that you’re referring to as the Antelope Ridge, just about every area what we’ve gone into we’ve improved. Once that gets started, so a little bit of it is going to the new area and learning a new area, and the drillings guys are going to drill these wells faster and faster and faster and in the completion, guys going to improve that too. So, a lot of that’s distorted across there. There is a fair amount of that in there, that’s related to extended flow back. And so we make conscious decision from time-to-time to flow these wells a little longer into flow back and in fact, it indicates the legal source since we actually had additional flow back equipment out there due to how good that well really was. So, there’s a number of different buckets that those all fall into, but the costs there at Antelope Ridge I think are something that we certainly will improve as we go through time.
Got it. Thanks, Matt. And then just a logistical, any issues at all from a logistical and services standpoint in the quarter and then any update on basin trends I think, that will be off from me. Thanks guys.
Yeah, Gab. We’ve been out talking on the big ticket items for not only availability, but also for price. We really haven’t seen anything moved in an upward direction. that being said, some of the smaller services, we are finally starting to see some upward movement in those costs, but – and I think it’s really related to the – we talk a lot about pressure pumping services. so when we think about that there has been additional capacity come in to the area.
So there’s a good amount of variability of that equipment and it’s still at a very competitive price. so I’ve not seen a whole lot of movement there.
but on the demand side, you’re ratcheted about your wells…
Yeah.
Your smaller, there is a shortage of them, they haven't come into the basin proportionately like the pumping services of the sand. And on the sand side, there we're slow to move too fast on the brown sand, because there are some problems with that. One is the size and the second is the brown is from some of the iron content that it has. And there have been problems in the past and we're going to first test the size with northern white sand to make sure that the smaller size that have an effect with white sand and again, a methodical approach to seeing if you can use the regional sand.
Yes. This is David. I think you summarize that well, Joe. So I mean, it's certainly something we're looking at as we said and the guys are got plans to test things as we’ve said, but we'll probably go to fairly methodical pace in terms of moving to the in-basin sand.
And Gab, you bring up a good question on the cost, because we look at that too. I mean we're always looking for ways to improve the cost without compromising the quality of the well, and I'm going to give Billy a chance to define his drilling and completion gas that they were getting their money's worth throughout the quarter even though as we do exploration work, there are going to be a little bit higher and as we get to do the repair, it will come down and as we adjust for the equipment as well and get that first infrastructure here.
As David mentioned earlier, as we move into development mode, we’ll be able to batch drill and zip refract the wells. We're already looking at the Wolfcamp wells and some of the areas there, and I think we can eliminate a string of casing that's going to help us out. We're going to get facilities into place there. And everywhere we've been going, developing wells, the MAXCOM room that Joe mentioned earlier is really helping us out. We've got like just a whole page of new records we've drilled just faster and each whole section we've got occurs now, we're drilling them seven to 10 hours. So it's over 100 foot an hour all the way through. So I think you hadn't a lot quicker there and we're going to see these things happen in Antelope Ridge as well. So it's a good quarter and good things ahead.
Great. Well, thanks a lot, everyone.
Thanks, Gab.
Our next question is from Dan McSpirit with BMO Capital Markets. Your line is now open.
Thank you, folks. Good morning.
Hey, Dan.
Hey because of my short attentions Dan, I also welcome a short earnings release, so you can make it shorter if you'd like.
Great. We'll keep trying to ahead in that direction Dan, we do welcome all of those comments. We will make your time as useful as we can and productive. So keeping comment.
Well, appreciate it. First question, if the basis differential issue in the Permian, proves to be more trend toward the Northern, would it make sense to put a route to work in the Eagle Ford rather than maybe monetizing what looks to be a priced asset. And maybe where those proceeds could finance or running the seventh rig in the Delaware, where the inventories much deeper?
Dan, that’s a great question. That’s something we evaluate all the time. We've take pros and con on those issues all the time. And I think you make a good point and you identify a couple of issues. Is this basis differential? Is it transitory? Or is it going to be intact for a while what are the opportunities. We've got almost all the Eagle Ford HBP. So we don’t have to do something. But holding on, we're not say holding on to it. Anybody brings us an offer that hits the magic number, we're going to make a deal. We run a straight game. It just that, but it would sold it two years ago, we wouldn’t hear nearly what we get for today. And we would have missed out on some valuable production.
So it gives us an option and just think about these companies, it sell like reach for one number and they come back two years later and pay five times it number for the same acreage. You need to think about this and there have been other companies, major companies, it sold out of the basin and now they've reentered the basin and they are paying much more for their acreage today demand. So it needs to be a deliberate long-term look, but Matador has sold itself to Tom Brown. We sold part of our Haynesville to Chesapeake. We did a deal with EnLink. We’ve done a deal with Five Point. So when the numbers arrived, we will pull the trigger and make no mistake about that, but it is nice to have some options on where to go for example in the Haynesville we not only have Haynesville, but we have 200 or 300 bcf of Cotton Valley, that’s HBP, that’s sitting there as a gas bank and is not accounted in the acreage.
So you make a very good point and we have people that as I said we invite them to come in and very interested in the Eagle Ford. We will make a deal there. We have reserved the right if it were more lasting differential to go there, but that’s not our first choice. It’s to continue – the first plan of action absent more complicating factors is to continue methodically, moving north to take advantage of our experience in our acreage position in the Northern Delaware, which is proving to be one issue that came out of Analyst Day where some people said, hey wait, we’re not and give a lot of value yet to the Northern Delaware, because you’re not spending money, you’re taking activity, well, look we had growing all along, the Antelope Ridge wells were on in process at the time or thinking about it.
We had good success with Cimarex, another improvement to the Twin Lakes. We’re excited about the well we’re going to drill. It is working, but each data point helps to make our evaluation of what to do or where to put the rigs, we can be that much more confident. And we have plans over in Arrowhead and Ranger, our rig is over there in Arrowhead right now. And we think that – got some really good ideas. And so, we’re fully engaged and work in the day that as it comes in and the more and more data I think makes our plans clear.
And I think it’s just not to have a plateful of opportunities, and being able to high grade them and that’s a kind of a high class problem. And if you remember in Matador when we first came public, there was a lot of push back. We didn’t have enough acreage locations. And now as you looking at something that is in the order of about 2000 net locations and that number will grow. So it's exciting there and in the Eagle Ford to Haynesville all that is quality rock. So kind of gives us a handful of cards to play.
Yeah, understood, Joe. And that’s a good segue into my second question, my follow up question. Moving further north into Delaware, what did you conclude from Cimarex’s Wolfcamp B well that supports putting more capital work in the Twin Lakes area and what is the timing of results from your own Wolfcamp B test?
Yeah, hi, Dan. It’s David. Look I think we were encouraged by the results of the latest Cimarex well, which we were a minority partner in. They did test at slightly different interval of the Wolfcamp B then what either we or they had tested previously. So – and in doing so, have a little bit – have a bit better results. Then what you – the first time, I think that’s positive. So I think we have learned some things about targeting. I believe that the stimulation of that well went – went a littler, smoother than what either was experienced on our first wells in the Twin Lakes area. And so, there were some tweaks made to the design and I believe also to the – kind of the strength of the pipe that was used into the completions. And so as a result, I think that was a good learning and something that will – that we’ll be able to piggyback on going forward.
We're probably actually test it slightly different target even to they sell. We're going to be a little bit to the east of where they were even though we're on the western portion of our acreage what we call the Kemnitz area. But we’ve just actually begun drilling that Twin Lakes wells. And so I would imagine that it will be at least the next call before we would have anything that we would be able to talk about on the well. It will take us a while to get it drilled and tracked.
But we're still very encouraged by this area. And I know that Continental too has come into the area and is looking to drill a couple wells. And so it's nice to have some acreage that they are kind of working together. And I think we’re understanding that on the Midland side that pioneer and maybe among others have begun to maybe collectables can't be met also.
So all in all, I think that we've known this was going to be an exploratory area for us and one that was going to take a little while to get right. But I don't really see it as being all about much different than some of the other areas that we worked in. Our initial wells in some of the other areas weren’t best, but as we got up the learning curve, we continued to improve and now are very happy with the results we’re able to deliver in those areas.
So I hope that answers your question. Those are some of the learnings that I think we were able to take away from our participation in that latest well.
Well, I appreciate the answers folks. Have a great day.
Thank you.
Our next question is from Irene Haas with Imperial Capital. Your line is now open.
Yes I have two questions. Firstly, Matador certainly is opportunity rich. So in light of that and stronger prices wondering when Matador might be able to kind of update full year guidance as of now as 2018 guidance still intact as specifically on the CapEx. And secondarily is the Wolfcamp B well at Twin Lake? What is the AFE and how much drilling time and completion time you have allotted for that particular project?
Al right, I’ll take the first of that Irene. And just say look it’s early in the year but we feel it's very early in the year. We just don't have enough data, don't know enough about the direction of processes to make those calls. And as we're still wigwagging every day the sixth and seventh rate exactly where, what direction we're going. So it’s just early and it will kind of give us some time into the summer. And we can probably help you there.
As today you see on this next well in Twin Lakes, let me get that over to either Matt or David.
Yes Irene this is Matt. And the next well we’re going to drill is Twin Lakes, it's going to be a lot like the first one we did. We're going to spend a fair amount of time and money on gathering some very important data for us. We do truly value to whole core and sidewalls and things like that that we can get from these wells. So I would think about it more in terms of on a development basis these wells are going to be comparable to what we're doing just to the south of Ranger/Arrowhead. So if you're looking for a development type cost that's kind of what I look to.
And how much time have you set aside to drill and complete company there very interesting exploration project?
About 40 days I think Irene.
Great, thank you.
Our next question is from Jeff Grampp with Northland Capital. Your line is now open.
Good morning guys.
Good morning Jeff.
I have a broader question on your Delaware asset base. When you guys kind of take a step back and kind of think about profitable growth at a measured pace in the long-term, what kind of an efficient max rig kind of case for you guys that efficiently develops your assets? And if we just kind of think about Twin Lakes in a different bucket and just kind of thinking about more of your in more proven areas, where you guys think is a good max rig number for you guys to build towards?
I’ll try then you revise. We’re not of one mind on that frankly. And so much of it it's just hard to pin that on a single variable, is because so much of your decision is based on products and you don't know for sure. You can look at the features, market and that gives you an objective gauge. But you just don't know the pace, that's like coming up with a game plan in football and say this is the order of the place we're going to run. Well it turns out the weather is rainy that would change your game plan, or it's windy it changes your game plan. What the other team is, why they are running that would change your game plan.
And what you are having to say as you might have a running back or quarterback having a good day and you're going to call more of his place. So there are just too many factors, you don't have a plan and we make plans, but they are meant to be changed to go along as circumstances change. And you can have new technology. One example of that is the bid designs, is when we first got to the Permian it was difficult getting to chert and you would spend four or five days and the bid companies have come up with significant improvements there, they should get them drilled in a matter of hours. So that made a significant change in the way we did think how many rigs, because you shortened and compressed those drilling times.
And I'm not trying to disrespect your question at all, is it's a very good one that we talk about all the time. But we're not even yet committed where – that we can't make a change for six or nine months. We think it's important to maintain as much flexibility as we can. And that's what we look at all the time and evaluate. We make plans, but we also try to drill them in ways of option A, option B, option C, depending on well results, gas prices, oil prices. Now that makes a big difference, and service cost and personnel.
It’s is a great question and we did a good job internally. But when you're a public company, you got to be careful if we were different we could probably we could try a lot plans to our shareholders and see what they think. But as a public company once we say this is what we're going to do, you're expected to pretty much stay with that. So we have a lot of plans going on but we'll kind of stick with what we said at the Analyst Day for now. And watch the temperature and circumstances and go from there.
Yes I think you said well Joe. I think the one thing that we won’t do Jeff and you know it's a long time we're not going to have a knee jerk reaction, we're not going to move from zero 90. We’re pretty methodical in the way we approach things. And Joe is right there, there are a lot of different variables and we just – we take this stuff very seriously and as t he acreage grows, the efficiency of the rig grows. So there’s a lot of different things that are happening all at the same time.
Jeff I’d like to think that we’re building some sort of record for consistency. This is the 15th quarter where we've met or exceeded guidance. So when we issue guidance there's a lot of thought, and effort and discussion behind that. And we feel like that's what we will achieve and deliver to the shareholders and they can count on it and we're not going to react to the fashion of the day, but stay with what as I said Matt says that that proper growth at a measured pace and we're growing organically.
I think it’s important to note too we're not after bond companies that may have a transformative effect. We're going along, buying the acreage, drilling the wells, building the midstream. And making it work and you look at where we were when we went public 400 barrels oil a day. And today we're over 30,000.
So the plan is working acreage if you remember when we went public, we got a lot of pushback for not buying more acreage in the Eagle Ford. And that's where we should be spending money. And we got this pushback, why are you going to the Delaware to an acreage. Well, if we'd just stayed in the Eagle Ford, and I don’t think we would be around today, but I think it was the right decision to go up there and start buying in the Permian and people said, you'll never get past 30,000 and then we have – and look where we are today.
Yes. I would like – we try to be as transparent as we can and put it out there, but public – once we say it, then we've got to stand behind it and do what we say. So we're working on those questions now, and I think as you will see in this, hopefully you will relay up on what we say we will do, and take some comfort that we'll get that done and anything else will come along and take care of itself in its own time.
All right. I have understand and then I appreciate it’s not a straightforward answer, but appreciate the time and thoughts guys.
Jeff, I tried to make it straight-forward, lessen I’d say. Maybe the listener didn’t get to hear what he wanted to hear because we couldn't tell you that, but we are working on it, trust me.
Our next question is from Philip Stuart with Howard Weil. Your line is now open.
Good morning, guys. Congrats on a good quarter.
Thanks.
Circling back to Garrett pad and Rustler Breaks, David, I know talked about improved capital efficiency by completing those wells on a multi-well pads, but I'm just curious if you could actually quantify the savings per well that were achieved on those wells versus what the AFEs would have been for those wells on single-well pads.
You want to take the other.
Yes. Phil, this is Matt. I think there are multiple efficiencies that we achieve and we're drilling these wells on a singular pad, you saved on drill pad cost, you saved moving the rig cost, there's lots of different cost savings, but I might just ask Billy to quantify this. But I think we're thinking in the $400,000 per well range on average when we're drilling these multiple well pads.
I think when we put three of them together like that, we can see even more than that. We can get some more of a wider range inwards $400,000 to $600,000 or $800,000 of oil that we will see. So it's just big number and we can go in and drill them all together and get to do the zipper fracs and all the flow back and all the services together. So it really helps out, a lot more efficient.
One think that is easy to point to Philip is on the pressure pumping, we pump our fracs. The agreement we have with Halliburton is that they will actually give us a specified discount of $150,000 per well if we are fracking multiple wells at the same time, so that's a hard and fast number there.
Right, I appreciate that, that makes sense. And then one more stick in Rustler Breaks. Any update on the Breaks sand? And I know you all participated in a couple of wells and I think you are planning to participate in another one this year. Any update as to when that test would be or any other data points you can get around on that formation?
Yes, I don't think we have a lot really to update you on there, Philip. And what we talked about on the Analyst Day, I think the wells that we participated in are doing okay, and we're still looking at the possibility of doing our own test, but probably nothing much to add to that discussion from Analyst Day at this point.
All right, guys, I appreciate the time.
Well, thank you.
Our next question is from Sameer Panjwani with Tudor, Pickering, Holt. Your line is now open.
Good morning, guys.
Hi, Sameer.
Good morning.
So, thinking about Waha in the worst case scenario if gas flows do get backed up, how do you think about flaring versus shut-ins from at operational and regulatory standpoint, and you know from Matador specifically how quickly are you able to shift capital all the way from gas seasons to the earlier results.
Sameer, this is Matt, on the take away we feel pretty confident that we can continue to sell the gas, you know in the worst case scenario I think it gets down to what you're actually realizing progress on that gas, so you know we don't think we're going to have to flair gas to start with if we need to we can get fare permits and do some different things but as I mentioned early, one of the advantages we have been in this play, we have Rustler Breaks is ability go into refrain our coverage, so we can add value to the gas stream by doing that and reducing the amount of gas it does go to Waha.
And I guess how would you guess frame that answer in the context of the broader industry rather than Matador specifically?
You know it's really we can't – really speak for everybody but I think it's one thing I do know is that this industry tends to respond to things like this very well, so you know it's going to be a shorter-term problem I think whether it's something that gets over corrected or not I guess this maybe just a question to ask but I think for it's going to be a very short-term thing, there are projects coming in our line, and that’s going to add additional capacity which will also improve the price, so I think it's a relatively short-term problem.
Sameer, this is Dave, my just follow up on maybe add one comment to what Matt said, certainly I agree with all the things that he just said, but you asked about kind of the shifting of CapEx or not drilling as you know some of the gas user.
First of all, you know we've probably have fewer, I believe both completions actually clean you know this year, and may be last year or so. So I think that you know not that we were anticipating this particularly that's the reason we did, it just I just don't have our drilling schedule this year, but this is just sort of how it works out, but certainly I think you know it's I think through your question we have – we have been working recently on a number of different opportunities up on our air head and ranger area, which tend to be all here produce less gas, and I think it would be pretty easy for us at that this point, if that become a significant problem to maybe move one of the rigs up to that area. And just focus on an area like, again, maybe like, Stebbins or some of the stuff in Ranger that Ned was talking about earlier that might tend to have less gas production because we tend to have 80% to 90% kind of oil wells sort of are better up in that area. And so that might also be something that we could do temporarily if it becomes a more serious problem.
Okay, that's helpful. And then on the midstream JV, I know there are still a lot of opportunities to create additional value. But as you think about the longer-term plan, I think you guys have talked about not wanting to be a midstream company. So just trying to think through when do you think if that business only matures enough to actually start pulling forward additional value to get more cash in it or ?
Sameer, this is David again. I think what we've said pretty consistently, this year is that or here recently is that what we're really focused on right now is finishing or continuing to build out the projects that we have scheduled. Getting the plant finished was a big goal of ours. And hats off to the midstream team and to San Mateo for bringing that in again on time and on budget and plants up and working. We're pushing over $100 million a day through the plant now and beginning to sign up third-party producers or other producers for that plant as well. So I think we're moving in the right direction there.
On the water disposal side, as Matt mentioned earlier, we have six water disposal wells in the Wolf and Rustler Breaks asset area. We’ve got two more to drill this year, so we'll be adding additional capacity. And the guys are doing a good job of getting that filled up as well. And then, of course, you know about the Plains project.
So I think we have a pretty full plate of things that we're trying to get done and accomplished on the midstream side this year in addition to adding new customers to the three top solution that San Mateo can offer. And I think we're just – we're very focused on that for this year before we begin any thoughts about kind of what's the – if there’s a monetization strategy or do we want to do anything, any kind of a dropdown or anything else. Not telling we’re not thinking ahead on that, but I think that kind of one step at a time. And I think for us the most important thing is to continue to get these midstream assets built out and in service, and the rest of it probably takes care of itself if we just make that happen.
Okay. Thanks, guys.
Thanks, Sameer.
Thank you, ladies and gentlemen, this ends the Q&A portion of this morning’s conference call. I’d like to turn the call back over to management for any closing remarks.
Thank you. I’d just like to close this, again, with a notion that this has been a great quarter and the outlook we really lock our chances. Here, this first quarter, we’re off to the start with record production, record reserves, record EBITDA, very strong earnings per share, and a lot of our chance is going forward on that pace. And it should be obvious that where we have spent our money has been good towards us that with good well results, good land results, good midstream results.
So I really compliment the staff for being good – not only good stewards, but executing well; would like to give them, again, the hats off, and tell them how much we appreciate their effort. And the plans going forward get better and better. We think we've come a long way since going public and we are proud of this consistent return, and the technical innovation that we've done with drilling rigs, with completions, with production, the use of the facilities, and really think their staff is – and Matador is coming of age and the platform for growth has never been better.
I think a number of good questions have been raised today and we’ve tried to answer them, but it's hard to go out there and committee without the review of all of the circumstances. And we think that's one reason we’re enabled to do what we can because we have pivoted in the middle of the year or as we've had well results to achieve better results. So we look forward to coming back to the year at the annual meeting and give you an update, and we look forward to report in July. And I think that you'll see this pace of record results continue in the right direction. This is probably the best set of opportunities we've ever had. Appreciate your questions.
And, well, again, emphasize what we've left for you all we comment into this in person and for you to meet their staff that’s delivering the results, it's not just Matt, David and me, and some of the old guys, but there's a young group of – have really come into the forefront and everybody is pitching in, and making things happen. And like for you to kind of meet them and say that this is a very strong group in all the different areas and getting better. Still planning room for improvement, but I think we're on our way.
So with that, I’ll turn off and hope that Joe will take us up on our invitation to come, have lunch or breakfast with us.
Ladies and gentlemen, thank you for your participation today. Conclude the program.