Matador Resources Co (MTDR) 2013 Q1 法說會逐字稿

Good morning, ladies and gentlemen. Welcome to the first-quarter 2013 Matador Resources Company earnings conference call. My name is Kathy and I'll be your operator for today. At this time all participants are in a listen-only mode. We will facilitate a question-and-answer session at the end of the conference. (Operator Instructions)

As a reminder, this conference is being recorded for replay purposes and the replay will be available through Friday, May 31, 2013, as discussed and described 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 forecasts of future events based on the information that is now available. Please refer to the forward-looking statement in the Company's earnings release for more information.

I'd now like to turn the call over to Joe Foran, Chairman, President, and CEO. You may proceed.

Thank you, Kathy, and good morning to everyone. First, thanks to all of you for participating in our first-quarter 2013 earnings conference call.

I would like to introduce everyone from Matador joining me this morning on the call. We have David Lancaster, Executive Vice President and Chief Operating Officer; Matt Hairford, Executive Vice President of Operations; David Nicklin, Executive Director of Exploration; Ryan London, Vice President and General Manager; and Brad Robinson, Vice President and Chief Technology Officer.

We are very pleased, obviously, with our first-quarter 2013 operating and financial results and feel we are off to a strong start in 2013, and have increased our guidance accordingly. Much credit is due to our staff and our Board, who have done an excellent job finding ways to drill better wells for less money and to make use of technology. Like many others in the industry, we are seeing the very positive effects of improvements in frac design and operating practices.

In the first quarter of 2013, our oil production was 460,000 barrels, which was a year-over-year increase of 130% from 200,000 barrels in the first quarter of 2012 and a sequential increase of 8% from 426,000 barrels in the fourth quarter of 2012. It is important to remember that this increase was not generated by adding a bunch of new wells, because the last well we've added was on at the very first of February of this year. It's just simply that the wells have sustained themselves longer and show increased productivity as a result of these fracs and operating practices, and the reduced chokes.

More particularly, our average daily production for the quarter increased from a guidance rate of 4,000 barrels to over 5,100 barrels of oil per day and 34.7 million cubic feet of natural gas per day, which exceeded our expectations for the quarter and the previous guidance that we had noted of 4,000 barrels of oil per day and 31 million cubic feet of natural gas per day provided during our Analyst Day meeting in December.

We had Adjusted EBITDA of $40.7 million for the quarter, which was a year-over-year increase of over 91% from $21.3 million reported for the first quarter of last year, and a sequential increase of 7% from $38 million in the fourth quarter of 2012. Notably, the increased production that we experienced from guidance generated approximately a 30% additional return on our Adjusted EBITDA.

It's also exciting to announce we have continued adding to our position in Southeast New Mexico, acquiring an additional 14,700 gross and 12,500 net acres in Lea and Eddy Counties, New Mexico, during March and April of this year, bringing our total prospective acreage position in Southeast New Mexico and West Texas to approximately 22,900 gross and 18,100 net acres.

As a result of very encouraging results in the last two quarters we are increasing, formally, our 2013 annual oil production guidance from a range of 1.6 to 1.8 million barrels, to a range of 1.8 to 2.0 million barrels. We are also increasing our 2013 annual Adjusted EBITDA guidance from a range of $140 to $160 million, to a range of $155 to $175 million.

Finally, it's important to mention our oil production of 5,100 barrels per day, oil equivalent production of 10,900 BOE per day, oil and natural gas revenues of $59.3 million, and Adjusted EBITDA of $40.7 million for the first quarter of 2013 were all the best quarterly numbers in the Company's history and all exceed the expectations we had for Matador when we went public a little over a year ago.

With that, we would like to be sure that we have time for all your questions. I would now like to turn the call back to the operator to take your questions and invite, after the first round, to ask as many as you wish.

(Operator Instructions) Ben Wyatt, Stephens.

Good morning, guys. Hey, Joe, I know you guys have been changing completion techniques; on your fourth revision, so to speak. Just curious if there is going to be any changes on the next round of Eagle Ford wells. Maybe just give us a little color on that, from that perspective.

All right. I am going to turn the question to Ryan London, who is the head of our completions program. Ryan?

Yes, Ben. We made mention I think last quarter that we have honed in on two things that seem to make the most difference, and that is fluid volume and proppant. We have continued to do that. We have emphasized that since the last quarter, increasing our fluid volumes by about 20% on a stage-by-stage basis and likewise with the proppant.

Got you. I guess just moving over to the Permian, you guys are going to go drill a few test wells here. Do you guys just envision maybe when you will let us know about those results, a time frame there?

And then will we get that on all three at the same time? Or what are you guys thinking on that front?

Ben, that is a good question. It is hard to say, but most likely the way we have done in the past is just save those results until we can turn out all three results. But we may even drill a fourth well, just depending how the program unfolds.

But my expectancy at this point would be just to announce them all together rather than try to do it one at a time.

Very good. Good quarter, Joe. That's it for me. Thanks a lot.

Well, thanks, Ben. We really appreciate you.

Neal Dingmann, SunTrust.

Morning, guys. Good quarter. Joe, just a question on this Lea and Eddy County acreage that you added. What is the size? How quick could you start to drill something over there?

Well, we are drilling it right now. We are drilling some of the acreage that we have acquired right now. And then the additional acreage we acquired in March and April are right in those same areas, so it just -- it would be very easily -- it just depends on the best order to do so.

I'd turn to David Nicklin to give an assessment of our exploration idea out there.

Yes, Neal, we are focusing on both the Bone Spring. That has got, as you are probably aware, there are several zones within the Bone Spring. There is the Avalon at the top; there is first Bone Spring, second Bone Spring, third Bone spring. And in addition to that we have Wolfcamp as well as underneath, and there are several zones in the Wolfcamp, as several other operators have published previously.

We feel that our acreage is very well positioned, very closely spaced and close to some very significant results that other operators have already published. So we are excited about evaluating all of those zones.

Did that answer your question, Neal?

That was perfect, Joe. Then just one other moving over back to the Eagle Ford. What's your thought, Joe, on going out for -- I know some guys talk about an upper Eagle Ford as well as drilling some Pearsall. Just wanted to see what your new guidance thoughts are of different formations that you might have in the Eagle Ford.

Neal, that is something we are looking at very closely, these other formations. We were also doing a seismic program over in the area of our Glasscock/ZLS out there on the West side.

But let me turn this to Nicklin to give you more detail. David.

Yes, Neal, we are continuing to evaluate a lot of the results of some of the wells that are being drilled around and close to our Western side of our Eagle Ford play. There are some excellent results in the Buda Southwest of the Glasscock Ranch by a couple of different operators. There is also some very interesting Pearsall production just North of our Martin Ranch acreage.

And Joe has alluded to, the 3-D seismic is being shot over Glasscock as we speak, and we should have results of that later this year. I am reluctant to drill until I have got that data; but I am very optimistic about the potential for 2014.

Well, Joe, it sounds like a lot of upcoming activity. Look forward to seeing the results.

Thank you, Neal. Appreciate it.

Scott Hanold, RBC Capital Markets.

Hey, good morning. Looking at the Eagle Ford activity in the second quarter, it looks like you have got seven wells you plan on putting online. Can you talk a little bit about the timing of when those will be brought into production and how, I guess, volumes will ebb and flow a little bit with that?

I am going to let David Lancaster speak on the timing of that and bringing these wells on. We expect to bring them on in the second quarter.

But you are going to get some unevenness simply by the timing. Whether you're on for 30 days is going to look different than if you are on for 15 days. But, David, would you add to that?

I think what I would say, Scott, is as you know we did four wells in the first quarter, and we put the last one on in early February. And then we had these two three-well pads ongoing.

The one on our Cowey lease, the wells have now been fractured, so the completion operations are completed. We are in the process of drilling out the plugs, so I don't think it will be more than a few more days until we have those wells beginning to flow back.

Then we have frac-ed one of the wells on the Martin Ranch lease of the four that are coming on in the quarter. The next three are scheduled to be frac-ed here very quickly. So I would think that around the first of June or so that it is reasonable to think that we will have those four wells beginning to come back.

The other thing that will be helpful is that we have had some of the neighboring wells shut in, in both places, while we have gotten these pads -- these wells drilled and frac-ed. So it will be good to get that production turned back on as well.

So as far as timing, through the first half of the quarter we haven't had a lot of new production come on. And that will tend to come on more and now in the last five or so weeks of the quarter.

Okay, okay, so we've got a lot of flush stuff coming around midyear. Okay. Fair enough.

Then moving over to the Permian a little bit, can you give us a little bit of color on that acquisition and your view on your ability to pick up more acreage? It seems you have been fairly successful in getting a few nice packages put together.

Are you dealing with private land owners? And what price are you paying there?

Scott, one thing -- while we are talking about New Mexico I want to be sure, when we talk about drilling three wells or four wells over there, they are first wells on each of these leases. So it is not pad drilling. Those are going to be separate parts of our acreage.

Our acreage is really centered around, right now, what we call the Ranger area up there, where we are drilling the first Ranger well; and then down there in Texas, in Loving County on the Wolf acreage; and then the third main area has been the Indian Draw area. We may add a well in Indian Draw, just depending on timing and a whole bunch of factors.

So those are our three main areas. We have been able to add in each of those areas, and we are doing all the above. Some are -- we are working -- we have bought some acreage at state leases and federal leases. We have made leases with fee owners. We have purchased some leases from others on fee acreage and state acreage.

The Wolf deal was a deal between an operator and us, and we expect to make other deals with other operators. So that is really kind of all the above, and we are trying to be careful about the cost.

We like these areas very much, but we are also trying to be sure that we are buying them as competitively as we can. And so far our costs have been down there in the low thousands.

Okay. Okay, very good. So then I would assume that the CapEx increase that you all had was relative to these recent purchases?

Yes, that's right, Scott, is that we put in a little capital increase really to take care of the fact that we are having to assess buying some leases, and we see more potential for that this year. And want to again reiterate that we are still very actively looking and buying leases in the Eagle Ford or the Haynesville. So when the opportunity arises in any of those areas, we see this as a good time to add to those positions.

Okay. That's great. Thanks, guys.

Thank you, Scott.

Ipsit Mohanty, Canaccord.

Morning, Joe and team. Kind of -follow-on from Scott's question about Delaware. Let me take a step back and bunch a couple into one.

What was the rationale behind going into Delaware in the first place? I mean, as we know, this is not the most mature of plays yet. It is a complex, complicated play with multiple stacks. And at the same time this didn't come with existing production or proved reserves or anything like that. As I understand, this was pure acreage that you have gone into. So if you could talk a little bit about why Delaware.

And then the second part to that is, as you go on to acreage could you just briefly, quickly talk about what is your process going to be from here to September?

Then finally, why the delay till September? Is there anything beyond some extensive testing that you will be doing? Thanks.

When we sold old Matador we were the 15th largest producer, approximately, out there in Southeastern New Mexico. So it is an area that we know well from previous vertical drilling in the old days.

And we just see a lot of promise of taking a lot of this technology that has been developed in the industry to drill horizontals. Those improved fracing operational techniques can have application out there, because when you look at it, it has not been as extensively drilled with horizontals that other areas of the country have been.

The economics on that that we have looked at extensively feel that can be very comparable to the Eagle Ford. And when we have looked at it, it has had a range per zone, I want to emphasize that, between 300,000 BOE to 600,000 BOE. Now that is a big range, but the fact is you have got three and four zones to look at over there.

So it is a very, very active petroleum system that has a lot to yield without a lot of this current technology that is showing itself very effectively in a number of good plays. And we have a lot of previous knowledge. When you look around our staff, the amount of experience that they have in the Permian, it is a natural place to grow.

We are certainly not saying we are not going to be active in the Eagle Ford. We plan to be there for many years. But we think this is a good area to expand. It gives us a second oil leg to our portfolio.

But let me turn it back -- I am looking around the room to see if David or Brad or David Nicklin, any of y'all would like to -- did I overlook? David Nicklin is nodding his head.

Yes, I would just like to say Joe is absolutely right about the historical perspective here. Matador has a wonderful database in the Delaware Basin, and we have been able to use that. We have done a lot of work extensively over the years.

We have looked at the Delaware Basin for quite some time, and what has been the turning point is really the realization that we can apply a lot of the technologies and things that we have learned in South Texas in the Eagle Ford play and in the Haynesville play. We can apply those very effectively, we believe, in the Delaware Basin. So it makes a lot of sense for us to not only leverage our expertise but also leverage this great database we have.

By the way, this is Matt Hairford. I might just add, looking back to South Texas on the Eagle Ford, we've got the vast majority that acreage will be held by production. And as we have seen -- as we develop this acreage the frac evolution is significantly valuable. So while we certainly are not leaving South Texas, we do feel as though, as we learn to frac these wells better and better, it's going to improve the EUR. So therefore we are not in a great rush to go drill it up real fast.

Wonderful. Anything else to read into the delay till September? Just more of testing?

No, I don't think -- this is David Lancaster -- I was going to say with regard to your question on process, I think actually the scheduling is running right at what our expectations were. The first well that we are drilling is a vertical well, and we are going to take extensive log data, probably cut a hole core in that well in a certain part of the Wolfcamp interval. And we are going to spend our time studying that and looking at where we want to complete that well and how we want to.

We're going to move down to a second well in Lea County and then a third well on our Wolf prospect in Loving County. And in all those cases we are looking to drill pilot holes and get a good set of base logs. And those things just take a little longer than they will, of course, once we get into development mode.

So there is really nothing to be read into that other than we just want to take our time on these first wells. They are important to us out there.

Great. Given your division of midyear proved reserves, they have stayed the same in a while. But you have also talked about borrowing base redetermination sometime in the end of the second quarter. Is there a timeline for that? Is there a particular month that you are going to?

Well, I hope that the banks will be able to complete their process this month, and that that is something that we will be able to announced by the end of the month. I am optimistic that will happen; can't promise, but having spoken to the banks I think there is every reason to think that they will get through the process this month for us.

Wonderful. I will leave it at that. Thank you, guys.

Stephen Shepherd, Simmons.

Good morning, guys. Can you remind me what the specific terms of your crude oil sales agreements are in the Eagle Ford? And what I mean by that is, do you have a specific percentage of the oil that is sold on fixed-price contracts? Where is it sold at? Just trying to get some detail behind the agreements that you may have worked out there.

This is Gregg Krug. No, we have got -- most of our gas is sold -- or most of our crude, I'm sorry, is sold at NYMEX plus or minus the roll, less trucking, plus -- but we get the LLS/WTI differential. So that's -- and those are usually on a month-to-month basis.

What is that trucking differential?

There is a range there. It is anywhere from $7.25 five to -- I think our highest is like $8.50. So I think a good average would be around $8.00.

So I guess following on to that, of your reported liquids volume, how much of that would you call condensate, if any? And what I mean by that would be just be 45 degree API or higher as the divider line. And how much of that would be NGLs, if applicable?

I think we can certainly answer that none of it is NGLs, because our NGLs are captured as natural gas. The gas transfers before the liquids are extracted. So none of it is NGLs.

Then with regard to how much of it is condensate versus crude, do you have a good number on that, Gregg?

Well, not really, as far as the NGLs that we are showing.

Let me take a stab at it then. I think that in the first quarter, Stephen, the stuff that was higher-gravity condensate was probably coming from -- not probably, was coming from one of the wells on our Cowey lease, one of the wells or a couple of the wells on our Lewton lease. So I would estimate that that would have been on the order of 600 or 700 maybe barrels per day of the 5,000.

So that is probably on the order of, let's say 15%. I don't think I would miss it much with that number.

Everything we have to the West really doesn't fall into that category, and even some of our stuff to the East when you're on like our Sickenius or Danysh, Pawalek tracks and all, that is all not in that light API kind of category. So I think that is a pretty good number.

Right, David. I think that is the last time we -- it is a little obscure question; but the last time we looked at it is over 85% of our oil was black oil. And then you had that there in the Eastern about that 15% level from those wells.

But we are a two-stream reporter, so the NGLs serve as an uplift to our gas price. Did that answer your question, Steve?

It did. And there's one more if I can. Can I get an update on well costs by area? Is there any change to your thinking that the Tier 1 stuff is kind of the $8 million in development mode, and the Tier 2s may be at $6 million? Any update there?

Steve, this is Matt again. I think as we've characterize this, the wells to the West we think are still in the $6 million to $7 million range. We have seen about a 10% decrease or reduction on the drilling side.

We have got some of the major service providers are cutting their costs, cutting their pricing by 10%, 15%, sometimes 20%. So we are seeing that in both the drilling and the completion side.

And as Ryan mentioned on the completion side, we are putting some of that back into adding value to the wells by increasing the size of the frac job. So as we walk from West to East we will go $6 million to $7 million on the West; and we get into the -- onto the East side, the deeper, higher-pressure wells, they will be $8 million to $9 million. And in what we consider the wells where we have to run the higher string proppants, they are still running probably $9 million to $10 million.

And the other thing, Steve, I'd like to emphasize on the wells in the Far East, they need -- the increased cost is the proppant and the extra string of casing.

But I think you are confused by calling the ones in the West Tier 2 and the ones in the East Tier 1. We don't rank them like that. Tier 1s can be in other areas.

The ones in the West have very comparable rates of return to what is in the East because the costs are less, even though recoveries are a little higher in the East. So those are very, very comparable and I wouldn't characterize them Tier 2, Tier 1 in that fashion.

I think there is a little confusion. When we rate Tier 1, Tier 2 that involves rate of return.

Okay. Thanks for your answers. I appreciate it.

All right. Thank you, Steve.

Mike Scialla, Stifel.

Morning, Joe. Last quarter you had mentioned you were planning to do some 40-acre tests in the Eagle Ford. Just wanted to see if your thoughts have changed at all, based on what you are seeing in the play and maybe what you are seeing from other industry players in the Eagle Ford.

That is a good question, Mike, and it is timely because we are currently testing that. For details, let me call upon Ryan.

Yes, we have seen a lot of operators testing 40-acre spacing and even tighter. I think we mentioned last time we are going to test that ourselves.

We have already drilled one of our 40-acre wells and we are in the process of drilling another one. And one of those 40-acre wells we're actually in the process of fracing right now.

So regardless of the apparent success other operators have had, we are going to prove to ourselves it is the right move. And we are excited and encouraged by what we have seen so far, but we are eagerly awaiting the results from our current tests.

That's great. Then I was going to ask on the -- you said you were contemplating a three-rig program beginning in September. I assume that is contingent upon success in the Permian. Just trying to get a sense for what that could mean.

If you do keep a rig running over there, would that maybe add $25 million to $30 million to the budget? Am I thinking about that correctly?

Yes, Mike, that's right. David Lancaster has the specifics on that. I can see him nodding his head here.

But it is assuming success in the Permian, and the pricing outlook is still favorable, and that everything is coming together, and we can secure a rig, and the cost outlook is right. So you have those kind of macro factors.

But on the specific if we did it, David, would you comment on that?

Yes, sir. Hi, Mike. It's David. I think that $20 million, $30 million is about the right number for the additional CapEx. A lot would depend, Mike, on the specific locations that we drilled.

Obviously in some of the sections out there in New Mexico we have all or almost all of the entire section. In others we would have less of the section, and so we might have a 40% or 50% or working interest in some of those wells. So that would have some impact on the amount of CapEx that we expended.

But you would probably be looking at two or three additional wells. So I'd think $20 million, $30 million is probably in the ballpark. Might be even lower if we were kind of half interest on some of those wells.

That helps. Thanks.

All right. Does that answer it, Mike?

It does, thanks.

Okay, good.

Sir, you have no questions at this time. (Operator Instructions)

Are there any other questions?

Mike Scialla, Stifel.

Yes, just I guess a couple more. In the Permian, just trying to understand, you mentioned you added that acreage. From the last update it looks like the gross acreage number actually went down while the net went up. Are you changing your (multiple speakers)? Go ahead.

Let us explain that, Mike. The gross amount of acreage that we have in West Texas and New Mexico is about 30,000 gross and a little over 20,000 net. All right?

We have one lease that is kind of up on the Central platform that we don't particularly think is prospective for the plays that we're talking about here. And it is probably something that we're not going to drill.

So to try to give you a little more specifics on what we feel about our acreage, the actual perspective then is on the order of about 20,000 gross -- and I think it is about 23,000 gross and about 18,000 net. So that is the only distinction there.

So we have actually added essentially 5,000 gross and 5,000 net since the time of our last release in April, about a month ago, when we talked about buying that acreage.

Yes, Mike, we are underscoring, that is on the Central Basin Platform, so it isn't in the Delaware. So we didn't include it.

Got it. Thanks. Then it does look like, and, David, you talked about it a little bit in terms of the timing of the wells, but it looks like you were planning on having three of those online in late April; and now it sounded more like you're going to have all six or seven come on toward late May or early June. Did you change anything in the way you are developing those wells? Or has something else caused that delay?

Go ahead.

No, really what it was, was one of our frac dates got pushed about a couple weeks. So just due to the timing of the frac dates is really the only thing that impacted the dates that those come online.

Okay, great. Nice quarter, guys. Thanks.

Thanks, Mike. Are there any other questions?

No further questions. Thank you, ladies and gentlemen.

Wait, wait, wait. Wait, wait. Wait, Kathy, before you sign them off. I have a couple of closing remarks, all right?

Is that I wanted to leave you all with that I want to thank you all for your questions today and to tell you that we appreciate it and also just to say that the way we evaluate Matador, there is I think three or four important catalysts or factors to consider on increasing value.

First is it was noted that we are doing the 40-acre testing; and if that goes through most or all of our Eagle Ford acreage we think that'd make a big difference.

Second, we are pleased to continue to see gas prices strengthen and rise; and as they do so that makes a big difference in our gas position in Northwest Louisiana, particularly in the Haynesville. And just to give you a feel for that is that, as you move from the values we are carrying on our gas, from just $3.00 to $4.00 it basically triples that in rough terms. And similarly, as it moves from $4.00 to $5.00 it triples the value.

So we are carrying in our last investor presentation, if you look at those pie charts, a little under $25 million. And in rough terms as you hit $4.00 and if you start to include the PUDs with that and the like it starts moving it towards the -- tripling that to the $75 million level. And similarly, if you move the price from $4.00 to $5.00, you will triple it to the over $200 million, which of course would have a substantial impact.

We have just got to wait to see prices. And I tried not to predict them because if I do I am always wrong. But it is encouraging to see them headed in the right way.

The third factor is the acreage value that we have been assembling in New Mexico and West Texas. Is that we think we have been buying it right. We think they are in good areas, and that that has some ongoing value.

And, finally, something that we didn't again emphasize is our economics in drilling in New Mexico is really based on one zone; but we know there are multiple zones to look at that. And that you are getting the future potential of stacked pays or way to complete them in a dual manner.

So when we look at Matador today versus a year ago when we first went public, last year we essentially had one choice. With gas prices being low we had the Eagle Ford to drill, and we really didn't have a whole lot else.

Today, we think we have got three real good choices, Eagle Ford, Delaware, or the Haynesville, all of which would work at today's prices. So that choice has really increased, and we have developed these other catalysts.

So being public we feel we have made a lot of progress. It has helped us hire, I think, a lot of really good people. Helped us improve our planning.

And the extra locations that we show are all engineered locations where we have a location, a name, and have done an EUR, ultimate recovery, on that location, depending on its location in the Eagle Ford. And we expect to start doing the same in New Mexico.

So we feel we are excited about the going forward, but we are also pleased with the progress and the achievements of this staff. And appreciate you-all's many questions because it has helped us sharpen our business plan, and look forward to a continuing dialog with all of you.

If there is no further questions, we will sign off but give you this last chance. Hearing none, thank you all very much. Talk to you all later. Bye.

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