Matador Resources Company
Q1 2014 Earnings Call Transcript

Published: 7 May 2014

[Operator:]

Good morning, ladies and gentlemen, and welcome to the first quarter 2014 Matador Resources Company earnings conference call. My name is Kathy, and I'll be your operator for today. (Operator Instructions) As a reminder, this conference is being recorded for replay purposes and the replay will be available through Tuesday, May 27, 2014, as discussed in the company's earnings release issued yesterday. 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 release. As a reminder, certain statements included in this morning's presentation maybe forward-looking and reflect the company's current expectations or forecast of future events based on the information that is now available. Actual results and future events could differ materially from those anticipated in such statements. Additional information concerning factors that could cause actual results to differ materially is contained in the company's earnings release, its most recent annual report on Form 10-K and any subsequent quarterly reports on Form 10-Q. I'd now like to turn the call over to Joe Foran, Chairman and CEO. You may proceed, sir.

[Joseph Foran:]

Thank you, Kathy, and good morning to everyone on the line, and thank you for participating in our first quarter 2014 earnings conference call. We appreciate your time and interest very much. There are three key points, we would like to emphasize on this call. First, we achieved record oil production in the first quarter of 661,000 barrels of oil, which is a year-over-year increase of 44% from the first quarter of 2013 and an increase of 9% sequentially from the fourth quarter of 2013. All this, despite having 15% to 20% of our production capacity shut-in or restricted at various times during the quarter. These first quarter operating results reflect our continued success in both the Eagle Ford and the beginning of a successful drilling program in the Permian. Second, we continue to pick up high quality acreage across all of our operating areas and to build our presence in the Delaware portion of the Permian Basin. Our first three horizontal exploration wells in the first three areas have tested three different zones and continued to exceed our expectations. And the Ranger 33 and the Dorothy White wells have shown shallower than expected declines. The Wolf area in Loving County, Texas, in particular is maturing to the point, where it may soon be ready for development program. We also expect to be able to at least replace the acreage we grilled in the Eagle Ford in 2014, with opportunistic acreage acquisitions. Third, Chesapeake is significantly increasing its Haynesville drilling activity in the core of the play, on our acreage, on our Elm Grove acreage in southern Caddo Parish, Louisiana. We believe these wells may have ultimate recoveries of 8 Bcf to 12 Bcf per well and should generate favorable returns for Matador. Matador in its transaction with Chesapeake retained certain override, so we are advantaged by having 85% to 90% NRIs, net revenue interest. As a result of this increased activity by Chesapeake, we are now increasing our 2014 natural gas production guidance by approximately 18% from 13.5 Bcf to 15 Bcf and the top end of the range from 16 Bcf to 17.5 Bcf. We expect to achieve these totals for the year and we are reporting natural gas production for the quarter of approximately 2.5 Bcf of natural gas or about 27.4 million a day, which was below our expectations. The issues we experienced were temporary due to shut-ins, production connections and other timing issues. And the most important point is the fact that our natural gas production is already back above expected levels at about 42 million cubic feet of gas per day. And these rates are obviously expected to increase throughout the year, although we will see most of the impact of this additional Haynesville production in the third and fourth quarters of this year. Next, we would like to know the fact that we are continuing to build a significant presence in the Permian Basin in southeastern New Mexico and West Texas. First, we have added to our leasehold position, acquiring 16,100 gross acres, 11,400 net, since the first of the year to bring our total acreage position to approximately 87,000 gross, 56,200 net acres at May 6, 2014. Of particular note, we are excited about our presence in Loving County area or Wolf area, where we have added 5,700 gross, 3,700 net acres, since January 1, 2014, to bring our total acreage position in the Wolf area to 10,900 gross, 7,000 net acres at May 6, 2014. Due to an anticipated temporary drilling contact overlap, when we picked up a second walking rig in the Eagle Ford last month, we took advantage of this and moved the rig that was being replaced in the Eagle Ford to Loving County, to drill the next two wells on our Wolf prospect in Loving County, Texas. The Norton Schaub number 1H and the Arno number 1H, and we are considering keeping this rig to accelerate development of our Delaware properties in this area. Finally, we are updating our previously announced full year guidance metrics, which we provided at our Analyst Day on December 12, 2013, to reflect the increased activity in the Haynesville, the additional land and seismic acquisitions we anticipate for the balance of 2014 in the following manner. Number one, we are increasing our capital expenditure budget from $440 million to $540 million. Number two, we are increasing natural gas production guidance for the year by approximately 18% from 13.5 Bcf to 15 Bcf and on the top end from to 16 Bcf to 17.5 Bcf, as previously noted. We are increasing all the natural gas revenues guidance from $325 million to $355 million and on the top end from $380 million to $400 million. We are increasing adjusted EBITDA guidance from $235 million to $265 million and on the top end from $270 million to $290 million. We are affirming our oil production guidance of 2.8 million to 3.1 million barrels, but are guiding you to the high end of this range for 2014. With that, I'd like to introduce the members of our senior staff joining me on this call, who have all contributed greatly to these results and who are standing by for any questions you may have. They are

[Operator:]

(Operator Instructions) First question is from Scott Hanold of RBC.

[Scott Hanold:]

A question on the CapEx increase that you all had, and just to clarify that doesn't assume, obviously, any incremental activity or your guidance on production does it include any kind of incremental activities, if you decide to keep that Permian rig and if you can extend your answer queue, what would cause you to make a decision to make that rig permanent?

[Joseph Foran:]

David?

[David Lancaster:]

To answer your question, specifically the raise in the CapEx guidance did not include any incremental activity. As Joe mentioned, the rig that we're running, drilling the Schaub and the Arno wells was already included in our 2014 capital expenditure budget, originally that we laid out for you guys at Analyst Day, so that was anticipated and is proceeding according to plan. And so as we try to lay out in the release, the increase in the CapEx is due to the fact that we've had big opportunity to acquire some very attractive additional leaseholds thus far in the year, particularly in the Permian; and in addition, that we're going to be participating with Chesapeake in some additional drilling on our Elm Grove properties in the Haynesville.

[Joseph Foran:]

Scott, I would underscore that, on the additional activity in the Haynesville, Chesapeake is an asset. They'll be better than 50% rate of returns. But ours are going to be even more advanced than that, because when we made the deal we kept the override, so we have about 85% to 90% net revenue interest. So we should be 15% or more above their rate of return. Additionally, we upgraded our gas contracts, so our net realization should be approximately $0.70 per Mcf more, which also added to our economics. And finally, I'd just like to make a point on the Haynesville, because it's drawing some attention that it represents about 10% of our budget. So it's not a huge amount that we think for those kind of rates of returns, and the balance that it gives us that it's an overall a very positive effect.

[Scott Hanold:]

And specifically with that, you had said there's a chance you might add in additional rig to the Permian, as a permanent rig. When you step back and look at it, what are the key factors? Obviously, well performance appears to be more than adequate, if you want to do that? And can you just talk about like financial flexibility, how you'd fund that and what the go-forward plans with that would be?

[Joseph Foran:]

Well, that's a very fair question. Let me try to get all those parts is that, obviously we're going to look at well performance, but if it sustains itself, that certainly makes it more attractive. And of course, being the conservative company that we are, we're going to make sure that we have sufficient cash flow or borrowing capacity, and to fund that rig without stretching ourselves too far. It's an opportunity and this rig gives us a little flexibility, we'll see how it works and we'll see if these results match to the Dorothy White, we understand as one of the better wells in the area.

[Scott Hanold:]

So what I'm hearing from you Joe, and correct me if I'm wrong, is sort of your next couple of wells going out of the Permian Basin look just as good at least as the wells you've recently drilled, there is a good chance that could bring you to want to keep that rig.

[Joseph Foran:]

Well, yes, assuming that it didn't compromise our conservative balance sheet or our financing flexibility. But it's my understanding, we're in a good position now with all avenues open, but we're just not going to take an unnecessary chance there.

[Operator:]

The next question comes from Neal Dingmann of SunTrust.

[Neal Dingmann:]

Joe, just one for you or the guys, obviously now that you got these walking rigs in, your thoughts on the spud-to-spud time over an Eagle Ford or just you're continuing to get more efficient there, I am just wondering how much more can you get?

[Joseph Foran:]

Matt?

[Matthew Hairford:]

In response to that question Neal, I would tell you that the drilling guys are never going to say they can't go faster. The implementation of the walking rigs has really been good for us and the cycle times have come down. We've talked in the past about drilling times from spud to TD, eight to nine days. So we're going to continue to improve on that. This most recent walking rig that we've added is a build for purpose walking rigs, so the efficiencies we're going to see there are going to continue to improve and it's got a great start. So those cycle times will continue to come down, Neal. You know, what we're going to do it, five days less, probably not, but we'll continue to work on that and we will see improvements.

[Neal Dingmann:]

And then lastly, Joe, just you guys continue to have just great takeaway. There is some people that continue to have some issues in the Eagle Ford, not as much maybe in the Perm, but just wondering on a takeaway situation you all continue to build that out or just your thoughts Joe for you and the team on that?

[Joseph Foran:]

Neal, really, the credits really due to Gregg Krug, our Vice President of Marketing, and he's done I think just a fantastic job getting us ready for as we drill the wells, making sure before we drill the wells that we have adequate markets and takeaway capacity. And he's been very clever in arranging not only takeaway from our wells, but also from the processing. And he is not only in the Eagle Ford, but out there in the Permian, and just we really can't give him enough credit that he's just done a superb, superb job.

[Operator:]

The next question comes from Irene Haas of Wunderlich Securities.

[Irene Haas:]

Just kind of wanted to get a little more color on your CapEx increase, maybe a little more granularity as to I think half of this is going to go towards seismic and acquisition as such. Can we have a little better picture of where the money is going to end up getting deployed? Then secondarily, maybe just a little more color on the New Mexico projects. You guys are drilling some Wolfcamp D wells and maybe just a little timeline, and should we kind of expect sort of similar performance versus the other Wolfcamp D wells being drilled on the Midland side since they probably were somewhat connected in the geologic path?

[Joseph Foran:]

Irene, I'm going to ask David Lancaster, Our Chief Operating Officer to address both.

[David Lancaster:]

Well, I'd see the first question you asked had to do with just a little more color on the CapEx and you specifically were I believe addressing the land part of the budget. We're really quite excited by the opportunities that have continued to present themselves to us to acquire acreage. Van Singleton in our land group has done an excellent job in providing us with opportunities to add to our position in the Permian and particularly in the Delaware side, in just since the first of the year. And just recently we're particularly pleased with the fact that we've been able to add a significant amount of additional acreage to our Wolf area and our Loving County area. And obviously, that area has been working out well for us, so far. And frankly Irene, we would anticipate that the majority of the increase in our land CapEx will continue to go into the Permian to continue to identify really strategically I think from this point forward, not that we haven't been strategic in terms of where we wanted to be, but we're really look to now more carefully sort of fill-in in the areas where we've acquired acreage and where we're particularly excited. And most of our recent acquisitions have been just that. Certainly, we are always looking for additional opportunities in the Eagle Ford as well, and if you noted in our release that we have actually added another 1,300 acres in the Eagle Ford. We always go into the year with a goal of 2,000, 3,000 acres at least as a minimum, because we believe that that will enable us to continue to replace our inventory. And if we find the opportunity to add more, we will do that opportunistically. So I hope that addresses your question on the land side of things. And then, with regard to the other intervals that we're testing, the zone that we're drilling in, currently up in the Pickard well, is the Wolfcamp D. And we actually have TD that well, we finished that well and we are going to now be drilling a second well from the same surface pad into the Second Bone Spring sand. So it still will be a little bit, before we come back and complete both of those wells, and can give you a little more color on the performance of the Wolfcamp D up in that area. We think that the Wolfcamp D is likely to be a little bit higher pressure up there than on the Midland side. I can't tell you that in that Pickard 2 well that we drilled a vertical pilot hole all the way through the Wolfcamp. And we used that to as we often do, in first wells that we do in an area, to gather additional well log data that's been very helpful to us in then planning the horizontal in the Wolfcamp D. And also it's going to be very helpful to us in drilling the Second Bone Spring sand well. In addition, we've had some [indiscernible] in that well, as we drilled through it vertically, and as we have drilled the horizontal leg in the Wolfcamp D. So we are continuing to be encouraged and look forward to being able to complete both of those wells and report the results to you just as soon as we can.

[Joseph Foran:]

One thing, I'd like to add to just David's remark is, when we talk about opportunistic land, it's not only that it is in the right areas, but we've been able to get them at the right price. Van's done a great job for us there. And we have averaged about $3,300 an acre this year in the Rustler Breaks, Ranger, Wolf area, on our acreage. That's not Twin Lakes, that's in the Rustler Breaks, Wolf and Ranger areas. And in the Eagle Ford, we've acquired acreage in the range of just a little over $3,100 in the Eagle Ford. So we think good process in good areas that bolt on to what we already have.

[Operator:]

The next question comes from Jeff Grampp from Northland Capital Markets.

[Jeff Grampp:]

I was hoping to maybe you guys take on strategically, what you think kind of the idle leasehold might be in the Permian, and when you guys think you maybe finished up with the big land grab? And do you think you're kind of already at that point, where the acquisitions are maybe a little bit smaller and more strategic bolt-ons going forward?

[Joseph Foran:]

Can you say that question again, Jeff?

[Jeff Grampp:]

Sure, Joe. Just wondering, when you guys -- if you have kind of targeted an ideal leasehold in the Permian in terms of a net acreage target that you guys have or when you maybe finished with kind of more aggressively seeing and doing kind of more smaller bolt-on stuff like you're doing in the Eagle Ford?

[Joseph Foran:]

Well, Jeff, that's a good question. And I guess I would address it in this way is that, as we have established what we feel is a fairly significant position out there, we tend to get more and more selective on our acreage. And try to look carefully what really enhances, what we already have. So most likely is it will slowdown some, and be more selective and will be sensitive to price and make sure, we don't think we're over paying for anything, at the same time, we tend to be opportunistic if acquisition opportunities arise. But the expectancy at present is that we'll tend to be more and more selective. Van, would you add to that?

[Van Singleton:]

The only thing I would add, Joe, is that we have been very fortunate this year in our targeted efforts to add acreage around our existing, let's say, core areas, but it's kind of four buckets. We have been seeing a lot of good opportunities coming up right near our acreage and whenever those opportunities come up, if we can make the right deal, I think we want to really try to do that.

[Joseph Foran:]

And I would say also, Jeff, that it will be determined. We pay a close attention to recoveries in the area. Brad Robinson, our Vice President, Reservoir Engineering has placed our type curves that have held up very well in the 400,000 to 500,000 range. Our first three wells are obviously doing much better than that type curve, but we're paying attention to the recoveries throughout that area.

[Jeff Grampp:]

And then just kind of hoping, to maybe talk about kind of the completion plans in terms of in the Permian, maybe Bone Spring versus Wolfcamp. And maybe how you guys specifically look at the differences in completion between those two formations and kind maybe today's best practices between the two and how those vary?

[Joseph Foran:]

Ryan London, our Vice President, we call him our frac master. Ryan, will you address that please.

[Ryan London:]

Jeff, what we've tried to do from a very early start in the Permian is to apply what we learned in the Eagle Ford. And what we learned over time in the Eagle Ford is that the frac size has a big impact on the wells. As we've gotten bigger and bigger fracs out there we've gotten better and better wells, we're going to take that same technology, same concept and apply to the Permian Basin. So you can see on our first three wells, we pumped too much bigger fracs than I think most of the wells in our neighborhood. And I think we're showing that it's had a big impact as well. I mean the production in those wells, like Joe just mentioned is outperforming the type curves. And it's not just the fracs, it's the overall completion. It's the restricted chokes. It's the way we shut-in our wells for us at fracs, all of those things I think are going to have a big impact in the Permian Basin.

[Operator:]

The question comes from Gab Daoud of Jefferies.

[Gab Daoud:]

A couple of questions on the Permian, I guess, for your full year oil guidance of 2.8 million to 3.1 million barrels, are you able to break that out between, I guess what's coming from the Permian versus the Eagle Ford? What are your expectations around that?

[David Lancaster:]

So Gab I think that we laid that out. This is David. We laid that out in our original forecast at Analyst Day. And said we thought that roughly 15% would come from the Permian this year. Obviously, as Joe just mentioned, our initial wells on Ranger and Dorothy White have exceeded our expectations and continue to do a little better than what we had originally forecasted. So that might bump up a little bit. But I would still think that's probably a reasonable expectation.

[Gab Daoud:]

And I know Joe mentioned 400 to 500 in BOE type curve for the Permian wells so far, I guess. Now that you have six months worth of production on the Ranger well and are approaching six months on the Dorothy White, I guess I was just wondering when you guys would be more comfortable with to bring out some more detailed type curves and economics I guess and just liquids mix on each area.

[David Lancaster:]

Just to take the second part of that, first. I mean, as far as liquids mix, the Ranger well is essentially 90% oil well. And the Dorothy White has been roughly two-thirds. I think its 66% oil. So that kind of gives you an idea of the mix on those. And I think with regard to changing the type curve, we are changing estimates. We will continue to look at that and we'll do that at the appropriate time. Just would like to have a little more data on some of these wells before we maybe ready to do that internally.

[Joseph Foran:]

Brad, would you add to that.

[Bradley Robinson:]

No, I think that was a good summation David had. Well, we'd like to see a few more wells too. I mean getting some additional history is a good thing, but we'd also just like to see a few more wells in each of these areas to sort of fill out our distribution for the EURs and that's what we used to build our type curves with.

[Joseph Foran:]

So by end of the year, Gab, we should have more for you on this.

[Operator:]

The next question comes from Brian Corales of Howard Weil.

[Brian Corales:]

Couple of questions. The Eagle Ford, it sounded you had maybe a little bit more downtime with the shutting in wells to normal. Can you maybe kind of quantify that, or at least talk about maybe, is there could be less of an affect for the rest of the year or is this kind of a similar pace of shut-ins?

[Joseph Foran:]

I'm going to have Ryan address that, but Brian a lot of that was the fact that we were drilling a walking rig and drilling three or four wells off the pad at the same time, but for this specifics of that, Ryan, why don't you go ahead and talk his call.

[Ryan London:]

The issue I think in the last quarter and here just in the past few months was when we started on our 40-acre downspacing program, we started right in the middle of the southern fairway of our Martin Ranch. So we were right in between a lot of our existing producing wells. As we move west on the Ranch and into that southern fairway, we're going to get out of the area where we've drilled a lot of a 80-acre wells. So the existing producers -- we're not going to have as many existing producers to shut-in. And if you look into the remainder of 2014 and 2015, we'll be moving up into the north-end of our Martin Ranch, where we only have a couple of producing wells. So in that area in particular, we'll have substantially less shut-in volumes. Throughout all of our acreage, it's kind of the same story. We're getting into a lot of areas where we haven't drilled a lot of wells. Lot of the new acreage we're getting, that's Van has gotten here recently, no existing producing wells, so we're looking to have a little bit less shut-in volumes on a go-forward basis.

[Brian Corales:]

And then one, I guess more for just modeling purposes, Haynesville. Can you just talk about what the cost are there today? I haven't dealt with this in a while.

[David Lancaster:]

Brian, one of those we've gotten recently in the Haynesville from Chesapeake, they're anywhere from $8 million to $9 million. Those wells are also 5,100 foot completed with lateral lengths with the cross-unit laterals, and so we did a little bit more than I think they were a few years back, but we're getting about 10% higher production out of those wells, just by virtue of the extended lateral length. And I think it might be also important to point out to you Brian, as you know that Chesapeake is also to our knowledge using the walking rigs and they're planning to drill multiple wells off the same pad. And so we expect that they will and hope that they will achieve a lot of the same cost kind of efficiencies that others have seen and certainly that we've seen with using those same kinds of process as down in the Eagle Ford.

[Operator:]

Next question comes from Ben Wyatt of Stephens.

[Matt Beeby:]

This is Matt Beeby for Ben Wyatt. Just a follow-up to the Haynesville. Can you give any update on the timing, if that program has actually started or what the expectation is? Should we see that as a steady ramp through the end of the year?

[David Lancaster:]

The program has started. Chesapeake has just begun actively drilling on the property. And as far timing, they're going to be drilling multiple wells off the pad before they come back and complete them. And as a result we really expect to see most of this impact in the third quarter and then more so in the fourth quarter from a production standpoint.

[Joseph Foran:]

And in that we are already back on track at 42 million. It will increase substantially through the year by a third or more. So we're very excited by this, because the rights of return are right. It helps to balance our oil production. We are hedged this year on our gas. So we're delighted, they are out there, drilling some of these wells. And this program again is about 10% of the budget, so if we were to design it ourselves, we think this were to be just about perfect.

[Matt Beeby:]

And then just another question, if you don't mind. Are you guys seeing any inflation on the service pricing or ability to get equipment, I guess more specifically in the Permian or are you seeing the drilling contractors pushing for longer term on the rigs?

[Joseph Foran:]

Matt, our President is waving his hand. So he would like to answer.

[Matthew Hairford:]

That's a good question and I'll kind of answer it in two parts. We'll go to the Eagle Ford first. I think what we're finding in the Eagle Ford is [indiscernible] settled out down there. The prices from 2011, 2012 obviously have come down, but it seems to have leveled out a bit in the Eagle Ford. Moving over to the Permian, I think that's it's a little tighter in the Permian. We with our current arrangements we have with [indiscernible] receiving the same pricing in the Permian as we are in the Eagle Ford. As far as the drilling contractors, there is a lot of pressure on new builds. So we're seeing them asking for a little longer-term. We do really have a really good relationship with [indiscernible] that we'll continue to work with them, but as far as back on the Permian and just general services companies out there, I think it's a little tighter. We sometimes have to make two or three calls to get the same service and same price that we would to make a single call in the Eagle Ford.

[Operator:]

The next question comes from Michael Scialla of Stifel.

[Michael Scialla:]

I wanted to ask if you do decide to maintain that second rig in the Permian, I'm trying to estimate, is that about another $50 million or so to the budget? And Joe, you had said to finance that all avenues are open, but you don't want to stretch your balance sheet too far. Would bank debt stretching the balance sheet too far or what kind of avenues are you looking at there?

[Joseph Foran:]

Mike, that's again a very fair question. And I can't answer it except, what I can tell you is that the cost of the rig is probably $50 million is in the ballpark for that rig net to us, because in the Permian you've don't always have a 100% interest. The interests are sometimes divided, small tracks, and you have of course pooling. As far as stretch in the balance sheet, that's a I'd call it a reiterative process working with our banks and making sure our bank group is comfortable, looking into the other times a longer term debt, seeing what they might do. So we are looking at everything, we're wanting to get also as well as to feel confident what are the type curves. We'd look to have a comfort of another well or two to prove up the type curve or the area. So I can't give you that precise answer today, those are the part of the calculus that we're looking. And I think is it feels like all those different avenues are open. So we're running those kind of models or sales.

[Michael Scialla:]

I want to ask you too on the Eagle Ford. Just looking at your improved reserves that you've reported in the 10-K. I see numbers there that are lower than the ranges that you used in your presentations for your three areas. But when I look at the state data, the data you've reported to the state, it looks like that supports those ranges that you've guided to us. So I wanted to see, one, if you see that same discrepancy from off basin? And two, if there is a discrepancy there, could discuss that at all? I guess I'll just leave it there.

[Joseph Foran:]

No, that is somebody's computer that fell off the table.

[Michael Scialla:]

A bit more on that question, I'm glad.

[Joseph Foran:]

Mike, it wasn't an engineer, it's our landsman down there that let his computer slip down there, and so he banged it, but let David Lancaster address your question.

[David Lancaster:]

Well, I feel confident that the ranges that we've provided and have indicated are certainly reasonable for particularly the recent wells that we've drilled that where we've used our Gen 5 and Gen 6 types of frac design. So I think that the additions that we've made would support that. If in the aggregate, it appears that the numbers seem less to you in what you're looking at and maybe that's something we can look at offline. I would think that it might reflect the fact that some of the early wells that we drilled with some of the earlier generations of fracs may not have held up quite as well as what we had originally thought. And from a blended standpoint that may have something to do with it. Of course, we also don't always have 100% working interest in these wells, although many that we do. But I think that the recent wells that we've certainly added in the Eagle Ford certainly support the ranges of numbers that we've been discussing.

[Joseph Foran:]

Ryan, Brad, would you add anything to that.

[Ryan London:]

No, I think that's a fair assessment. And I think the wells are performing pretty much as expected.

[Joseph Foran:]

Mike, I would just say, the production reports what's actually being produced is always the best evidence what our well will do. And there maybe an element of conservativeness on the reserve evaluations for the report as well as what the very first wells have gotten much better as the fracs had gotten along. But it's very perceptive question we'll check it out.

[David Lancaster:]

The other thing too, I think Mike that we might point out is that sometimes on the initial 40-acres spacing wells, that Netherlands has asked us to book those, maybe the 20% haircut cut or so 15% to 20% haircut from what other wells may have been and with time we may see that those are actually going to be better than that. But that may also reflect some of what you're talking about there.

[Joseph Foran:]

But we're going to check it out for sure.

[John Nelson:]

I think that the state data does support the ranges you guys have put out there, I was just curious as to how conservative maybe your reserve auditor is, but that seems to be the case to me anyway. So I appreciate the answers.

[Operator:]

The next question comes from John Nelson of Citigroup.

[John Nelson:]

I'm just curious with the acreage that's been added in the Permian year-to-date, if you guys have any updated thoughts on the location inventory? Or again kind of to the callers earlier question on EUR updates, is that something we should think about more towards the Analyst Day later in the year?

[David Lancaster:]

As far as the locations go, and Ryan may have something to add to that as well. Obviously, with the additional acreage that we've added and the drilling that we are doing, we are in the process of looking at all of that and looking to and updating our location count and probably aren't ready to come out with anything new on that right now. But I think that as the year moves on, we probably will. Certainly, we think that as we mentioned at Analyst Day that we've been quite conservative in our estimate as to the locations. Again, they are pretty well based on 160-acre spacing, what we've laid out so far. And in a lot of cases, they've been just one horizon per surface location, that's not always true, but for the most part. So I think we feel like that our locations are quite conservative, particularly as we continue to add to the acreage position. And at some point this year, I feel surely we'll come out with some updates as to what we think we have at this point. Again, we would like to have a few more well reserves before we put some of those numbers out. Ryan, anything you want to add to that.

[Ryan London:]

I think you described that perfectly. We are trying to be conservative. And all along, we've said that this year was going to be about delineating our acreage and testing the different geologic horizons. And I think we want to stay consistent with that. Certainly, we didn't expect the Dorothy White and Ranger and the rest of rigs to turn out quite as good as they did. They've turned out fantastic. And so we may move to a bigger number earlier than the end of 2014, but I think for the time that's what we are trying to do is stay conservative and just look at one horizon per location. And as we add more acreage and drill more wells, I think that we will learn quite a bit and we'd be able to expand on the inventory.

[John Nelson:]

And then I am just curious on the acreage that's been picked up year-to-date, are there any HBP requirements that might cause you to keep this second rig active or is that decision purely a function of just the encouraging wells you've seen and maybe staying ahead of tightening rig market?

[Joseph Foran:]

John, that's one of our major land projects for this year is to go through our, as we always do, is go through our acreage, look at the times and see what is our plan to be sure to validate all of this acreage. A good part of the acreage has been HBP already, shallow production. All the sate and federal leases that we purchased, the state leases are all five years long. The federals are 10 years long. Most of the fee acreage that we've leased has a kicker on it, three years with the three year kicker -- two year kicker, three years primary term with the two year kicker, which makes them five. So we've tried to be up on the front end, trying to be sure to allow us some time. Van, would you comment on whether anything has -- am I right in understanding that there is very little that is due to expire before 2016.

[Van Singleton:]

Joe, that's exactly correct. In fact, we have looked at all of our leases and have begun to map out HBP requirements out through 2020, but there is not really any significant drivers before 2016, and then not again until 2018.

[David Lancaster:]

Joe, I'll add a little bit to some of that too. I mean what we have done is a very comprehensive program of looking at all of the different continuous development of clauses, all the billing provisions, the expirations of the primary term and on the extension, and there is a lobby goes into planning out this schedule to HBP on this acreage. And I can tell you that all the work is being done and is largely been done and we certainly have a program to HBP of acreage and then satisfy all the influences of production and reserves. And so I think that you rest assure that we've got a plan and we'll execute on that plan to take care of business.

[John Nelson:]

And I guess just one last one for me. I think we kind of hit on it earlier, sounds like as far as timing assumptions that are baked into your guidance, you really expect the non-Haynesville activity to kind of come on very late 3Q and have a big jump then in 4Q. Just curious kind of similar to this quarter, should we expect then any maybe a sequential decline in that gas production in 3Q as completion operations go ahead or any thoughts or color you want to baked into guidance there?

[Joseph Foran:]

John, did you say 3Q or 2Q?

[John Nelson:]

I mean, your thoughts are probably better than my assumptions, but I think earlier there was a comment on construction from the Haynesville, starting to come on in late 3Q and then really benefiting in 4Q. And so I'm just curious if the completion of those wells could have a negative sequential impact in 3Q or any thoughts on sort of the timing assumptions you guys are using for guidance?

[David Lancaster:]

This is David. At this point, I don't expect that there would be a sequential decline in 3Q. I think that we may see some of these wells beginning to come on in a bigger way, sort of around the middle of 3Q, and then, kind of ramping from there throughout the fourth quarter. Now, the only thing, of course that we can't control in the process is exactly when things will be completed and so that could come forward or go backwards a little bit. But right now, I would not anticipate that 3Q would be a decline at all, I would expect it to go up. And then I will expect fourth quarter to go up, even more from there.

[Matthew Hairford:]

This is Matt. And I think David has mentioned it earlier, but Chesapeake is using best drilling techniques on these wells. So they don't drill as fast as the Eagle Ford wells, it does take quite a bit longer to drill three or four wells on the pad. So that just pushes the completion further end of year. But as David said, I wouldn't expect to see a decline in Q3 at all.

[Joseph Foran:]

I think Chesapeake has as much incentive as anyone to bring these on as orderly and prudently as one can, but as fast as one can, because they have certain volume considerations to meet too. We have been meeting with them and we've been in touch with them, we can call them. They've really been good partners at this point on this project. So we've been impressed with their professionalism and the way they're bringing this about. And really if we were the operator, I'm not sure we'd be doing much different.

[David Lancaster:]

John, just one more thing that I might add, if it's useful and that is that as with the many of these wells in the Haynesville, these wells were right in the very core of the play. These wells are certainly capable of 20 million a day plus when they come on. But we expect that Chesapeake will bring them on, only in plus or minus 10 million a day and we'll produce them flat at those rates for some period of time, and so the pressure declines to the point that the wells begin going below that on their own. And so just from, as you think about it in terms of modeling or how the production may come on that that's certainly the way that we are thinking about it and how we've modeled it.

[Joseph Foran:]

One other last thing Kathy before you go to next question. One last thing on your modeling, John, is that remember these well have a two year tax holiday on the severance, so you have a further advantage on that that helps your rate of return too.

[Operator:]

Next question comes from Dan McSpirit of BMO Capital Markets.

[Dan McSpirit:]

Sticking with the Haynesville. How do you feel about level returns in the Haynesville compared to what you're drilling in South Texas and even the Permian Basin today, that is do you see them as competitive or even superior at current gas prices?

[Joseph Foran:]

We see them as comparable. Not as very comparable to the other returns. And as we try to outline the regions is that you can't call them superior at this time, until you start to see what the gas process will be going into 2015. But they're certainly going to be compared to even comparable. And we like the mix because we think that the mix is helpful to our plans and it's not a big portion of our budget, but it can contribute and it doesn't take up a lot of man power. So we're still able to keep our best and broadest on the Eagle Ford and the Permian, that's delivering most of the value, but yet I think it improves and diversifies our mix of production. David or Matt, Ryan?

[David Lancaster:]

I would just add maybe slightly, little bit to what Joe said, again we may sound like a broken record on this, but again, just want to be sure that everybody realizes the fact that, couple of important points. Number one, we do have very advantage in our eyes on these properties as a result of our previous transaction with Chesapeake where we're able to retain some overrides on some of these leases. That's certainly something that enhances our returns. And then, in addition, I think we've been proactive in terms of anticipating that some of this might come at some point in 2014. And our marketing group, Gregg, has done a very nice job of redoing our gas contract there. We're taking our gas in time. We've renegotiated our deal with Axis. And the all of that we believe will improve our realizations by about $0.70 per MMBtu over what we were seeing. And so if we take all that into account, it really makes the returns here at these current price levels look very nice for us.

[Matthew Hairford:]

I think the other thing I would add is one thing that I think advantage us to play is that it has a little maturity to it. The wells that we drilled in 2008, they've been producing for six years. Chesapeake drilled a bunch of those wells. They tried a bunch of different completion techniques on those wells. So they've had the advantage to look back, as we have to look back over time how these wells have performed. And as we found in the Eagle Ford and our Haynesville and Permian coming up to completions are so very important, so it's really nice for us to have that history to look back on.

[Ryan London:]

And I'll add to that, this is Ryan, once again. I think that we consider the Haynesville to be a very low risk area. It's very much of gas thing for us. And like David mentioned this is some of the best Haynesville there is. We know that this is very high EUR territory. They have the drilling and the completion is down to its time. They've been doing this well over five years. They've gotten better just in recent years from a regulatory perspective and drilling across unit-laterals. So they're getting a bump on the EURs that they've already experienced in the past. So I think we're all very excited about the opportunity in Haynesville, that we have very good investments taking place here.

[Dan McSpirit:]

If you could just quickly turn to the Delaware Basin, can you walk us through the timing of next well results in the Delaware Basin? Is it the Pickard well and its offset that we should be looking for here on the horizon? And if so what is the timing?

[Joseph Foran:]

Well, there is two, that Pickard well is not an offset. It's testing a different horizon, the Second Bone Spring. So this would be the first multi wells, the two wells drilled from the same pad on 160 acres from two different horizons. So that will tell us a lot about each of these two respecting horizons drilled from the same pad. Those results, because you got to drill one than the other before you complete them are probably 45 days to 60 days away. Now down there on the Norton Schaub, on those wells we'll know those results quicker. So that's 30 days to 45 days, to give you some aspect of that.

[Operator:]

We have another question it comes from Scott Hanold from RBC.

[Scott Hanold:]

Just a quick follow-up, I know we're reaching the top of the hour here, but a couple of larger offsetting operators that have had some good success in the shallower Delaware Sand. And I assume this is on your guy's radar, but any thoughts on testing that as well?

[Joseph Foran:]

Yes, Scott, that is on our radar. We are looking at that carefully. Some of those results, as you've noted are very interesting. David Nicklin is here, our Head of our Exploration. David would you give a word?

[David Nicklin:]

It's a great point. And we've longed since looked at the Delaware and seen the Delaware potential. And we are very excited about where we're actively looking for horizontal drilling targets in and around our acreage. And we see a lot of potential. So you're hitting on something that we are certainly excited about.

[Scott Hanold:]

Could this be a 2014 objective by chance or is this something maybe a little bit further out?

[David Nicklin:]

No, I think it's going to be a little bit further out.

[Scott Hanold:]

And then one last one, Howard County, I know in the past you've talked about having maybe 2,000 acres there. And obviously we've seen some good well performance in Howard County on the Midland side of the basin. Could you be more specific if you all think that the 2,000 you have out there is on strike to potentially that as well?

[Joseph Foran:]

Well, Scott, we like that toehold that we have there. We think it's in good country. We'll just have to wait, say, if we put more acreage there or what we do with it, but we certainly like it at this point and think its additive. This is part of what we're trying to stress is that, again we're trying to focus on quality, not quantity, but we'd like to add acreage. We think that's one of the quality pieces that we have in a quality area.

[Operator:]

The next question comes from Jeff of Northland Capital Markets.

[Jeff Grampp:]

Just kind of curious, if maybe we could get an update on your 40 acre spaced wells in the Eagle Ford, if there is anything incremental you could provide us in terms of performance for those?

[Joseph Foran:]

Ryan?

[Ryan London:]

Jeff, we started our 40 acre program back in September of 2013, and since then we've drilled and equated about 22 wells that we have, greater than 30 days of production line. So we're starting to amass and update now to really give us some clarity on outcomes of these. And I got to say, it's turned out very well. Throughout our acreage we've drilled these wells, and if compared very favorably with the 80 acre order generation fracs. And we have several instances where we have a 40 acre generation-5 next to a generation-6 well. And I got to say our new frac design, our generation-6 design, has compared favorably against the generation-5 design. So moving forward, our goal is to marry the concept of a frac design, tailored specifically for down spacing with our 40 acre program going forward. And we think that it's going to turn out very well. Our generation-7 design is going to be more about fracture geometry than it is going to be about fluid and proppant, and we think that that's going to have a very favorable outcome.

[Jeff Grampp:]

And then, last for me. Just curious, if you guys have any plans maybe in '14 or maybe in '15, and potentially putting Eagle Ford well back in Glasscock Ranch, given all the achievements that you guys have made on the completion front?

[David Lancaster:]

We've looked at that extensively. We do feel like that a more modern frac generation would have a favorable outcome, specifically on the Glasscock Ranch, where we're really looking at the Buda for later this year. We have done an extensive 3D seismic program out there, we've studied that, we're going to have a well on the ground and we're really excited about the Buda potential out there in the near term.

[Matthew Hairford:]

I think the other forward part about that block is, is there are particular blocks that are almost 9,000 acres is held by production. So we the advantage there to really refine and let Ryan and his team come up with the best 40 acre design and the best design for the area. So we have the advantage of being able to wait.

[Operator:]

And the next question comes from Irene Haas of Wunderlich Securities.

[Irene Haas:]

Hey, thank you.

[Operator:]

I am afraid, Irene has left the call.

[Joseph Foran:]

All right. Well, maybe we'll get her back. While we're waiting for Irene, I do want, before we leave, some has been overlooked is the progress. We've talked a lot about the fracs, the drilling progress, we made in drilling, but I'd also like to mention to saying aloud, Bill McMann, our Vice President of Production, for his work on the artificial lift, that using gas lift in the Eagle Ford, we have felt has made a big difference. He has refined that and brought that out to the Permian, and we attribute some of the good results that we have in the shallower declines, that his work on the gas lift which is seeming to have the same good effect out in the Permian as it does in the Eagle Ford. And while we are talking about all the technical we've brought ourselves some brilliant oil guys and I didn't want to leave Bill out, because his work has been impressive. Matt?

[Matthew Hairford:]

I agree, and I think that one of the most significant things is the policies that we've taken on these two completions, is just to install those gas lift right upfront. So that's all we did on the Rangers 33, and so the transition from well flowing to any gas lift assist was very seamless, and it just continued right on and subsequent to that the wells continue to perform very well.

[David Lancaster:]

I'll say our last two wells unfortunately haven't had have gas lifts installed necessarily in order to flow, they're still flowing naturally at a very high pressure. So I think eventually those will benefit from that, but the Dorothy White and the Rustler Breaks still flowing strong.

[Operator:]

Irene is now on the line.

[Irene Haas:]

My question is, are you guys going to do a midyear reserves update this year? Then secondarily, I remember you kind of kept some of your Cotton Valley acreage in Louisiana what not. And can you remind me how much you have in terms of sort of gas and oil mix and would there be any thoughts of going back there, not this year, but in the next few years?

[Joseph Foran:]

David?

[David Lancaster:]

So let me take the second part of that first, Irene. We have 20,000, 25,000 acres in East Texas and Northwest Louisiana that's essentially HBP for Cotton Valley and above. I think what you've referring to, when you say, you remember we kept some of it, that refers specifically I think, maybe your recollections is going to the block that we did do the transaction, with Chesapeake, our Elm Grove block, where we sold down with them and retained the 25% working interest in Haynesville. But we kept all of our Cotton Valley in above rights there, and so we still have 100% of that in some legacy Cotton Valley production there. You might remember that several years ago we actually drilled a horizontal well in the Cotton Valley there, a well we called the Tigner Walker, and it's probably going to be on the order plus or minus 5 Bcf kind of well. And we also think that with some improvements to our fracture treatment design and things that we may have 6-plus Bcf wells there. So we have a lot of acreage there that we certainly could go back to and actually certainly have some potential locations for that, that are already defined and I think have been disclosed. But that's an area with a little bit better gas prices from what we're seeing here that could hold the potential for a lot of gas. If I recall, that gas has a little bit of liquids content to it, not certainly as high as what we see in our Eagle Ford or Permian gas, but it is advantaged a little bit that way also. And so it's certainly something that we always have in our back pocket and continue to look at and evaluate. And I think you had, there was a first part to your question, I am afraid I didn't --

[Joseph Foran:]

That was the reserve update.

[David Lancaster:]

The answer to that is likely, yes. So we probably will put out a midyear update.

[Operator:]

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

[Joseph Foran:]

Well, thank you all. We appreciate you all listening in. We appreciate all your questions. We want to make sure we've taken them. And we appreciate the interest in gas, but also don't want to leave any doubt in people's minds that for this next year and into 2015, we see ourselves continuing to focus 80% to 90% of our effort on the oil-rich areas in the Eagle Ford and the Permian, and that's the focus of our drilling and completion and other technical work and nothing has really changed. We appreciate this opportunity, since questions have come up so much about the Chesapeake and the Haynesville, to answer them for you, and we'll continue to do so. But still the value of Matador is going to continue to be driven by the Eagle Ford and the Permian, and this is just a nice gas option to have this in the Haynesville and the Cotton Valley, is the way we see it. So I appreciate you all calling in. We are always available to you, if you need us.

[Operator:]

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