Matador Resources Co (MTDR) 2014 Q1 法說會逐字稿

Good morning, ladies and gentlemen, and welcome to the first quarter 2014 Matador Resources Company earnings conference call. (Operator Instructions). As a reminder, the 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 the 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 may be 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 would now like to turn the call over to Joe Foran, Chairman and CEO. You may proceed, sir.

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 continue to exceed our expectations. 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 a development program. We also expect to be able to at least replace the acreage we drilled 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 overrides, so we are advantaged by having 85% to 90% NRIs, net revenue interest.

As 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 even though 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 note 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, our 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 contract 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 #1H and the Arno #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 16 Bcf to 17.5 Bcf as previously noted. We are increasing oil and natural gas revenue 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 to 3.1 million barrels but are guiding you to the high end of this range for 2014.

With that, I would 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 Matt Hairford, President ; David Lancaster, Executive Vice President, Chief Operating Officer and Chief Financial Officer; David Nicklin, Executive Director of Exploration; Ryan London, Vice President and General Manager; Brad Robinson, Vice President of Reservoir Engineering and Chief Technology Officer; Van Singleton, Vice President of Land; Gregg Krug, Vice President of Marketing; and Billy Goodwin, Vice President of Drilling as well as other members of the management group who are standing by for your questions.

I would now like to turn the call back to the operator, Kathy, for your questions.

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

Scott?

The question on the CapEx increase that you had, and just to clarify that doesn't assume obviously any incremental activity or your guidance on production. Does it include any incremental activities if you decided to keep that Permian rig and if you can extend your answer to what would cause you to make a decision to make that rig permanent?

David?

Hi, Scott, this is David Lancaster. No, to answer your question specifically, the raise in the CapEx guidance did not include any incremental activity. As Joe mentioned, the rig we are running drilling Schaub and the Arno wells was already included in your 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. As we tried to lay out in the release, the increase in the CapEx is due to the fact that we have had the opportunity to acquire some very attractive additional leaseholds thus far in the year particularly in the Permian and in addition that we are going to be participating with Chesapeake in some additional drilling on our Elm Grove properties in the Haynesville.

Scott, I would underscore that on the additional activity in the Haynesville, Chesapeake has announced that they will be better than 50% rate of returns, but ours are going to be even more advantaged 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 realizations should be approximately $0.70 per Mcf more, which also added to our economics. Finally, I would just like to make a point on the Haynesville because it is drawing some attention, that it represents about 10% of our budget, so it is not a huge amount but we think with those rates and returns and the balance that it give us that it is overall a very positive effect.

Okay, that is great. And specifically with that, you said there was a chance you might add an 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 to want to do that, and could you talk about financial flexibility, how you would fund that and what the go forward plans with that would be?

That is a very fair question. Let me try to get all of those parts. Obviously we are 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 are going to make sure that we have sufficient cash flow or borrowing capacity to fund that rig without stretching ourselves too far. It is an opportunity, and this rig gives us a little flexibility. We will see how it works, and we will see if these results match the Dorothy White, who we understand is one of the better wells in the area.

Okay. So what I am hearing from you, Joe, and correct me if I am wrong, is during your next couple wells coming out of the Permian Basin look just as good at least as the wells you recently drilled, there is a good chance that could spur you to want to keep that rig?

Yes, assuming it doesn't compromise our conservative balance sheet or our financing flexibility. But it is my understanding we are in a good position now with all avenues open, but we are not going to take an unnecessary chance there.

Okay. That is some good color. I appreciate it. Thanks.

Thank you. The next question comes from Neal Dingmann of SunTrust.

Good morning, guys. Nice quarter. Joe, just one for you or the guys, obviously now that you have these walking rigs in, your thoughts on the spud-to-spud time over in the Eagle Ford? You continue to get more efficient there. I am just wondering how much more can you get?

Matt?

Hi, Neal. How are you doing?

Good.

In response to that question, Neal, I would tell you 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 have talked in the past about drilling times from spud to TD of eight to nine days, so we are going to continue to improve on that. This most recent walking rig that we have added is a built for purpose walking rig, so the efficiencies we are going to see there are going to continue to improve, and it has a great start. So those cycle times will continue to come down, Neal. Are we going to do it in five days less? Probably not, but we will continue to work on that and we will see improvements.

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

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

Thanks, Joe. Good to hear.

Thanks.

The next question comes from Irene Haas of Wunderlich Securities.

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

Irene, I am going to ask David Lancaster, our Chief Operating Officer to address those.

Hi, Irene. It is David. Let's see, the first question you asked had to do with a little more color on the CapEx, and you specifically were I believe addressing the land part of the budget. We are really quite excited by the opportunities that have continued to present themselves to us to acquire acreage. Van Singleton and our land group has done an excellent job in providing us with opportunities to add to our position in the Permian particularly in the Delaware side. Just since the first of the year, and just recently, we are particularly pleased with the fact that we have 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 are really looking to now more carefully sort of fill in the areas where we have acquired acreage and where we are particularly excited. And most of our recent acquisition have been just that.

Certainly we are always looking for additional opportunities in the Eagle Ford as well. And 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 acres-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. I hope that addresses your question on the land side of things.

And then with regard to the other intervals that we are testing, the zone that we are drilling in currently up in the Pickard well is the Wolfcamp D, and we actually have TD'd that well. We have 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 tell you that in that Pickard 2 well that we drilled a vertical pilot hole all the way through the Wolfcamp. We used that, as we often do in first wells that we do in an area, to gather additional well log data. That has been very helpful to us in then planning the horizontal in the Wolfcamp D, and also is going to be very helpful to us in drilling the second Bone Spring sand well. In addition, we have had some nice shows 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.

Thanks, David. One thing I would like to add to David's remark is that when we talk about opportunistic land, it is not only that they are in the right areas, but we have able to get them at the right price. Van has 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 is not Twin Lakes. That is in the Rustler Breaks, Wolf and Ranger areas. And in the Eagle Ford, we have acquired acreage in the range of just a little over $3,100 in the Eagle Ford. So we think good prices in good areas that bolt on to what we already have.

Okay, great. Thank you.

Thank you. The next question comes from Jeff Grampp of Northland Capital Markets.

Good morning, everyone. I was hoping to maybe get your guys take on strategically what you think the ideal lease hold might be in the Permian, and when you guys think you may be finished up with the big land grab or do you think you are already at that point where the acquisitions are maybe a little bit smaller and more strategic bolt-ons going forward?

Can you say that question again Jeff?

Sure, Joe. Just wondering when you guys -- if you have targeted an ideal lease hold in the Permian in terms of a net acreage target that you have, or when you maybe finished with more aggressive leasing and doing more smaller bolt-on stuff like you are doing in the Eagle Ford.

Jeff, that is 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 we most likely will slow down some and be more selective and we will be sensitive to price and make sure we don't think we are overpaying for anything. Yet, at the same time, we tend to be opportunistic if acquisitions opportunities arise. But the expectancy at present is that we will tend to be more and more selective. Van, would you add to that?

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, I wouldn't say core areas but kind of our 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.

And I would say also, Jeff, that it will be determined we pay close attention to recoveries in the area. Brad Robinson, our Vice President of Reservoir Engineering is pleased our type curves 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 are paying attention to the recoveries throughout that area.

Okay. That is helpful color. And then hoping to talk about the completion plans in terms of the Permian - maybe Bone Springs versus Wolfcamp - and maybe how you guys specifically look at the differences in complexion between those two formations and maybe today's best practices between the two and how those vary?

All right. Ryan London our Vice President -- we call him our fracMeister -- Ryan,will you address that please?

Sure. Jeff, what we have 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 the frac size has a big impact on the wells. As we have gotten bigger and bigger fracs out there, we have gotten better and better wells. We are going to take that same technology, same concept and apply to it Permian Basin. So you can see on our first three wells we pumped much bigger fracs than I think most of the wells in our neighborhood, and I think we are showing it has had a big impact as well. The production in those wells, like Joe just mentioned, is outperforming the type curves. And it is not just the fracs. It is the overall completion. It is the restricted chokes. It is the way we shut-in our wells for offset fracs. All of those things I think are going to have a big impact in the Permian Basin.

Okay. Thanks guys. I will hop back in the queue.

All right. Thanks, Jeff.

Thank you for your question. (Operator Instructions). The next question comes from Gabe Daoud of Jefferies.

Good morning, guys.

Good morning, Gabe.

A couple of question on the Permian. I guess for your full year - your oil guidance of 2.8 million barrels to 3.1 million barrels - are you able to break that out that between what is coming from the Permian versus the Eagle Ford? What your expectations are on that?

Gabe, I think we laid that out -- this is David -- we laid that out in our original forecast at Analyst Day, and said we thought 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 is probably a reasonable expectation.

Okay, great. 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 approaching six months on the Dorothy White, I guess I was just wondering when you guys would be more comfortable with putting out some more detailed type curves in economics, I guess, and liquid mix on each area?

As far as to take the second part of that first. As far as liquid mix, the Ranger well is essentially a 90% oil well, and the Dorothy White has been roughly two-thirds, I think it is 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 or changing estimates, we will continue to look at that and we will do that at the appropriate time. Just would like to have a little more data on some of these wells before we may be ready to do that internally.

Brad, would you add to that?

No, I think that is a good summation David. We would like to see a few more wells too. Getting some additional history is a good thing, but we would also like to see a few more wells in each of these areas to fill out our distribution for the EURs and that is what we use to build our type curves with.

So by end of the year, Gabe, we should have more for you on this. But it has been good to this point.

Sure. Sounds good. Thanks, guys. That is all I had.

Thank you. The next question comes from Brian Corales of Howard Weil.

Good morning, guys.

Good morning, Brian.

A couple of questions. The Eagle Ford -- it sounded like you all had maybe a little more downtime with shutting in wells than normal. Can you maybe quantify that or at least talk about maybe is that going to be a less of an effect for the rest of the year or is this a similar pace of shut-ins?

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

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

Okay, that is helpful. And one I guess more for just modeling purposes, Haynesville can you just talk about what the costs are there today? I haven't dealt with this in a while.

Brian, one of the APs we have gotten recently in the Haynesville from Chesapeake -- they are anywhere from $8 million to $9 million. A lot of that is those wells are also 5,100 foot completed lateral lengths with the cross unit laterals, so they are a little bit more than I think they were a few years back, but we are getting about 10% higher production out of those wells just by virtue of the extended lateral length.

I think it might be also important to point out to you, Brian, that Chesapeake is also, to our knowledge, using the walking rigs and they are planing to drill multiple wells off the same pad. We expect and hope that they will achieve a lot of the same cost efficiencies that others of us have seen and certainly that we have seen with using those same kinds of processes down in the Eagle Ford.

Okay, guys, helpful. Thank you.

Next question comes from Ben Wyatt of Stephens.

Good morning. 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 expectations is? Should we see that as a steady ramp through the end of the year?

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

And in that regard, you are already back on track at 42 million. It will increase substantially through the year by a third or more. So we are very excited by this because, again, the rates of the return are right, it helps to balance our oil production, and we are hedged this year on our gas. So we are 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 would be just about perfect.

Okay, great. 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?

Matt, our President is waiving his hands saying he would like to answer.

Good morning, Matt. That is a good question. And I will kind of answer it in two parts. We will go to the Eagle Ford first. I think what we are finding in the Eagle Ford is things have kind of 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 it is a little tighter in the Permian. With our current arrangement we have with Schlumberger, we are 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 are seeing them ask for a little bit longer term. We do have a really good relationship with Patterson and we will continue to work with them. But as far as back on the Permian just general service companies out there, I think it is a little tighter. We sometimes have to make two or three calls to get the same service and same price that we would make a single call in the Eagle Ford.

All right. Thanks.

Thank you. The next question comes from Michael Scialla of Stifel.

Good morning, Joe. Good morning, everybody.

Hi, Mike. How are you today?

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

Mike, that is, again, a very fair question. I can't answer it, except what I can tell you is this -- that the cost of rig, on your cost of rig is probably $50 million, is in the ball park for that rig net to us because in the Permian you don't always have 100% interest. The interests are sometimes divided, small tracks and you have forced pooling. As far as stretching the balance sheet, that is I would call it a reiterative processes working with our banks and making sure our bank group is comfortable looking into the other kinds of longer-term debt seeing what they might do. So we are looking at everything. We are wanting to get also as well to feel confident what are the type curves. We would like to have the comfort of another well or two on the type to prove up the type curve or the area. So I can't give you the precise answer today. Those are part of the calculus that we are looking at. The nice thing is that it feels like all those different avenues are open, so we are running those kind of models ourselves.

That is fair. I appreciate that. I wanted to ask you too on the Eagle Ford -- just looking at your proved reserves that you have reported in the 10-K. I see numbers there that are lower than the ranges that you use in your presentations for your three areas, but when I look at the state data, the data you have reported to the state, it looks like that supports those ranges that you have guided to. So I wanted to see, one, if you see that same discrepancy or if I am off base. And two, if there is a discrepancy there, could you discuss that at all? I guess I will just leave it there.

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

Nobody hit the floor on the question -- I am glad.

Mike, it wasn't an engineer. It was our landman down there that let his computer slip down there. So he banged it, but let David Lancaster address your question.

Mike, I feel confident that the ranges that we have provided and have indicated are certainly reasonable for particularly the recent wells that we have drilled where we have used our Gen 5 and Gen 6 types of frac designs. I think that the additions we have made would support that. If in the aggregate it appears that the numbers seem less to you than what you are looking at, and maybe that is something we can look at offline, I would think 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 don't always have 100% working interest in these wells although many we do. But I think that the recent wells that we have certainly added in the Eagle Ford certainly support the ranges of numbers that we have been discussing.

Ryan, Brad, would you add anything to that?

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

Right. And, Mike, I would just say this, is the production reports, what is actually being produced, is always the best evidence of what a well will do, and there may be an element of conservatism on the reserve evaluations for the report as well as what the very first wells have gotten much better as the fracs have gone along. But it is a very perceptive question, and we will check it out.

The other thing too I think, Mike, that we might point out is that sometimes on the initial 40-acres spacing wells that Netherland has asked us to book those at 20% haircut 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 are talking about there.

But we are going to check it out for sure.

That is helpful. I think that the state data did 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. Thank you.

All right. Thank you, Mike.

Thank you. The next question comes from John Nelson of Citigroup.

Good morning and congratulations on the quarter.

Thanks, John.

I am just curious with the acreage that has 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 caller's earlier question on EUR updates is that something we should think about more towards the Analyst Day later on -- late in the year?

As far -- this is David -- Hi, John. As far as the locations go, and Ryan may have something to add to that as well, obviously with the additional acreage that we have added we are in the process -- and the drilling that we are doing -- we are in the process of looking at all of that and updating our location count. Probably are not ready to come out with anything new on that right now. But I think as the year moves on, we probably will. Certainly we think that, as we mentioned at Analyst Day, we have been quite conservative in our estimate as to the locations. Again, they are pretty well based on 160-acre spacing what we have laid out so far, and, in a lot of cases, they have been just one horizon per surface location. That is 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. At some point this year, I feel sure we will 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 results before we put some of those numbers out. Ryan, anything you want to add to that?

I think you described that perfectly. We are trying to be conservative, and all along we have 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 did not expect the Dorothy White and Ranger and the Rustler Breaks to turn out quite as good as they did. They have 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 is 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 will be able to expand on the inventory.

Fair enough. I am just curious on the acreage that has 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 have seen and maybe staying ahead of a tightening rig market?

John, that is one of our major land projects for this year -- is to go through our, as we always do, is to go through our acreage and see, look at the times and see what is our plan to be sure to validate all this acreage. A good part of the acreage has been HBP already by shallow production. All the state and federal leases that we have purchased, the state leases are all five years long, the federals are ten year long. Most of the fee acreage that we have leased has a kicker on it, three years with a two year kicker. Three years primary term with a two year kicker, which makes them five. So we 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?

Joe, that is 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.

Joe, I'll add to some of that too. What we have done is a very comprehensive program of looking at all the different continuous development clauses, all the billing provisions, the explorations of the primary term and on the extension. There is a lot that goes into planning out this schedule to HBP on this acreage. And I can tell you all the work is being done and has largely been done and we certainly have a program to HBP the acreage and then satisfy all the of influences of production and reserves. And so I think that you can rest assured that we have a plan, and we will execute on that plan to take care of business.

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

John, did you say 3Q or 2Q?

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

John, hi, again this is David. At this point, I don't expect that there would be a sequential decline in 3Q. I mean, 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 we can't control in the process is exactly when things will be completed, 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 would expect fourth quarter to go up even more from there.

John, this is Matt. And I think David had mentioned it earlier, but Chesapeake is using batch drilling techniques on these wells. 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 a pad, so that just pushes the completion further into the year. But as David said, I wouldn't expect to see a decline in Q3 at all.

I think Chesapeake has as much incentive as anyone to bring these on in 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 have been in touch with them. We have been calling them. They really have been good partners to this point on this project. We have been impressed with their professionalism and the way they are bringing this about. And really, if we were the operator, I'm not sure we would be doing much different.

John, just one more thing that I might add if it is useful, and that is that as with many of these wells in Haynesville these wells we are 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 will produce them flat at those rights rates for some period of time until the pressure declines to the point that the wells beginning going below that on their own. And so just as you think about it in terms of modelling or how the production may come on, that is certainly the way that we are thinking about it and how we have modeled it.

That is all really, really helpful color. Thanks, guys. Congrats.

(Inaudible).

Thanks. And one other last thing -- Kathy, before you go to the next question, one last thing on your modelling John, is that remember these will have a two year tax holiday on the severance, so you have a further advantage on that that helps your rate of return too.

Next question comes from Dan McSpirit of BMO Capital Markets.

Thank you, folks. Good morning.

Good morning.

Sticking with the Haynesville, how do field level returns in the Haynesville compare to what you are 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?

We see them as comparable. It is very comparable to the other returns, and as we have tried to outline the reasons is that you can't call them superior at this time until you start to see what the gas prices will be going into 2015, but they are certainly going to be competitive and comparable. And we like the mix because we think that the mix is helpful to our plans and it is not a big portion of our budget, but it can contribute and it doesn't take up a lot of man power so we are still able to keep our best and brightest on the Eagle Ford and the Permian delivering most of the value. But yet, I think it improves and diversifies our mix of production. David, or Matt, Ryan, do you all --

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

I think the other thing I would add is one thing I think advantages the play is that it has a little maturity to it. You know the wells were drilled in 2008; they have 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 have 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 the Permian coming up, the completions are so very important, so it is really nice for us to have that history to look back on.

I will echo that. This is Ryan once again. I think that we consider the Haynesville to be a very low risk area. It is very much a gas bank for us. And like David mentioned, this is some of the best Haynesville there is. We know this is very high EUR territory. They have the drilling and the completions down to a science. They have been doing this for well over five years. They have gotten better just in recent years from a regulatory perspective in drilling the crossing at laterals, so they are getting a bump on the EURs that they have already experienced in the past. So I think we are all very excited about the opportunity in Haynesville. We have very good investments taking place here.

I appreciate the color there. If we 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?

Well there are two. The Pickard well is not an offset. It is testing a different horizon -- the second Bone Springs. So this will be the first multi well -- two wells drilled from the same pad on 160 acres from two different horizons -- so that will tell us a lot about each of those two respective horizons drilled from the same pad. Those results, because you have to drill one and then the other before you complete them, are probably 45 days to 60 days away. Now down there on the northern Schaub and those wells we will know those results quicker, but --

Probably late June, Joe.

Late June. So that is 30 days to 45 days to give you some aspect of that. Does that answer your question?

It does indeed. I appreciate it. Thanks again.

Anything else?

We have another question. It comes from Scott Hanold of RBC Company.

Hi, guys. Thanks again. Just a quick follow up. I know we are reaching the top of the hour here. But a couple of larger offsetting operators have had some good success in the shallower Delaware sand, and I assume this is on your guys radar, but any thoughts on testing that as well?

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

Yes. Hi, Scott. It is a great point, and we have long since looked at that Delaware and seen the Delaware potential, and we are very excited about -- we are actively looking for horizontal drilling targets in and around our acreage. And we see a lot of potential. So you are hitting on something that we are certainly excited about.

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

No, I think is going to be a little bit further out.

Okay, fair enough. And one last one. Howard County I know in the past you talked about having maybe a couple thousand acres there, and obviously we have 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 couple thousand you have out there is on strike to potentially you know that as well?

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

All right. I appreciate it again guys. Thanks.

Thank you. The next question comes from Jeff of Northland Capital Markets.

Hi, guys. Thanks for squeezing me in again. 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?

Ryan.

Yes, Jeff. We started our 40-acre program back in September of 2013 and since then, we have drilled and included about 22 wells that we have greater than 30 days of production on. So we are starting to a mass enough data now to really give us some clarity on the outcomes of these, and I have to say it has turned out very well. Throughout all of our acreage we have drilled these wells and they have compared very favorably with the 80-acre older generation fracs, and we have several instances where we have a 40-acre Generation 5 next to a Generation 6 well. And I have 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 is going to turn out really 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 is going to have a favorable outcome.

Perfect, that is helpful color. And then last one for me, just curious if you guys have any plans maybe in 2014 or maybe even in 2015 in potentially putting an Eagle Ford well back in Glasscock Ranch given all the achievements you guys have made on the completion front?

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

Sorry, Jeff, this is Matt. I think the other forward part about that block is, that particular block is almost 9,000 acres is held by production. So we have 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.

All right. Thanks guys. Congrats on the quarter.

Thanks, Jeff.

Thank you. The next question comes from Irene Haas of Wunderlich Securities.

Thank you.

Hi, Irene.

I'm afraid Irene has left the call.

All right. Well, maybe we will get her back. While we are waiting for Irene, I do want, before we leave, something that has been overlooked is the progress --we have talked a lot about the fracs the drilling progress we made drilling -- but I would also like to mention to single out Bill McMann, our Vice President of Production, for his work on the artificial lift. 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, to his work on the gas lift, which is seeming to have had 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 pride ourselves on being oil guys and I didn't want to leave Bill out because his work has been impressive. Matt?

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

I will say our last two wells fortunately haven't had to have gas lifts installed necessarily yet in order to flow. They are 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.

Irene is now on the line.

All right.

(Inaudible) question, Irene.

Can you hear me?

Sure, Irene.

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

David?

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 is essentially HBP for Cotton Valley and above. I think what you are 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 a 25% working interest in the Haynesville, we kept all of our Cotton Valley and above rights there. And so we still have 100% of that and 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 is an area with a little bit better gas prices from what we are 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 is 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 --

That was the reserve update.

Yes. The answer to that is likely, yes. So we probably will put out a mid-year update.

Great. Thank you.

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

Well, thank you all. We appreciate you all listening in. We appreciate all your questions. We want to be sure we've taken them. And we appreciate the interest in the gas, but also don't want to leave any doubt in people's mind 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. That is 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 will 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 that 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.

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