Matador Resources Company (MTDR) Q2 2012 Earnings Report, Transcript and Summary

Good morning, ladies and gentlemen. Welcome to the Second Quarter 2012 Matador Resources Company Earnings Conference Call. My name is Pam, 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 August 22 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, and good morning to everyone. First, I'd like to introduce everyone from Matador joining me on this morning on the call. We have here with me, David Lancaster, Executive Vice President, Chief Operating Officer and Chief Financial Officer; Matt Hairford, Executive Vice President of Operations; David Nicklin, Executive Director of Exploration; Brad Robinson, Vice President of Reservoir Engineering; Scott King, Vice President of Geophysics and New Ventures; and several other members of the senior staff who have helped us in our progress this year. I want to thank all of you for participating in joining this conference call for our second quarter earnings conference call, and we hope all of you were able to review our earnings release and operational update released last night. As a way of summary, I believe we've continued to achieve solid growth throughout the second quarter of 2012. Our oil production saw sequential quarterly increase of 43% from first quarter to a record 285,000 barrels. Year-over-year, this is almost a six-fold increase from second quarter of 2011, when we produced 51,000 barrels. Our average daily total production and average daily oil production for the quarter were, again, the best in our company's history. We produced 8,740 BOE per day, including 3,130 barrels of oil per day and 33.6 million cubic feet of natural gas per day. We also reported record revenues for the quarter. Total realized revenues of $40.8 million, including $4.7 million in realized gain on derivatives is an 87% year-over-year gain from $21.8 million, including $1.0 million in realized gain on derivatives reported in the second quarter of 2011. Oil and gas revenues were at $36.1 million for the quarter, which is a 73% increase year-over-year from $20.9 million reported for the second quarter of 2011. We also have record EBITDA reported for the quarter. We are reporting $27.9 million, which is a year-over-year increase of 82% from $15.3 million reported in the second quarter of 2011. For the 6 months ended June 30, 2012, our oil and natural gas revenues of $65.2 million and adjusted EBITDA of $49.3 million are a 97% and 99%, respectively, of the amounts reported for all of 2011. We're also excited to announce during the second quarter, we acquired 2,800 net acres prospective for the Eagle Ford shale and other targets in South Texas near our existing leasehold acreage, and we just closed the acquisition of almost 2,900 net acres in the heart of the Wolfbone play in the Delaware Basin in West Texas. The second quarter also -- I want you all to know it was not a perfect quarter. We also had our share of usual challenges, including a noncash net impairment charge of $21.3 million, resulting from the low natural gas prices. As a result, we've reported a net loss of approximately $6.7 million and a loss of $0.12 per common share, compared to net income of approximately $7.2 million and earnings of $0.17 per Class A common share and $0.23 per Class B common share for the quarter ended June 30, 2011. We are also revising our expected 2012 annual oil production downward to 1.2 million to 1.4 million barrels from our previous guidance of 1.4 million to 1.5 million barrels. It is important to note that we believe our previous oil production guidance is still achievable at the lower end of the range or 1.4 million barrels, but achieving this production target may not be the right thing for Matador to do for the long road. Rather than focusing primarily on the 1.4 million to 1.5 million barrel oil production target for the remainder of 2012, we can -- we intend to emphasize the opportunities to reduce costs and implement certain production practices and techniques that may help maximize long-term well performance and shareholder value for Matador. As the largest individual shareholder in Matador, my interests are aligned with you, and I think it's important to emphasize -- put the operational aspects first. We are making steady progress with our Eagle Ford shale drilling program. Oil production is increasing. Drilling and completion costs have decreased, and our gains from technology and production efficiencies are clearly on the rise. Finally, we are negotiating an amended and restated credit facility that may increase our borrowing capacity to up to $200 million, primarily as a result of increased oil reserves at June 30, 2012. These oil reserves have nearly doubled in the past 6 months from 3.7 million barrels at first of the year to 7 million barrels at the end of June. With that, I will turn the call over to the operator and we will now take your questions.

[Operator Instructions] And your first question comes from the line of JB Jouve with RBC Capital Markets.

My first question is around your CapEx plans. It sounds like you're in line with your budget for 2012. And I was curious about the zipper-frac operations in DeWitt, and it sounds like that's delivering very good results. Is that a technique that you would consider expanding to more of your acreage on a going forward basis? And also, I was wondering if it was too early to provide some estimate on the cost savings of the design over maybe the one-by-one kind of completion design.

That's -- I'm going to speak just a little bit, and then I'm going to give you to Matt Hairford, our head of operations. But yes, we have become believers in the zipper-frac. We think it not only saves money but appears to give a more efficient frac. And we plan to expand that wherever feasible and prudent. As far as the savings go, it's significant enough, and Matt, why don't you give some color to that?

Okay. In regards to the zipper-fracs, drilling the wells on the same pads saves some money, obviously. One of the things that we've looked at is the number of stages we can get pumped in a day and one of the -- the efficiencies we've achieved in just a conventional frac, we were able to get up to 7 or 8 stages per day. We're hoping to get almost double that with a zipper-frac. And we've done the first one, and we weren't able to achieve the double, but it's the first one. So we're certain that we will improve as we go along. We do have additional zipper-fracs planned. In fact, we've got another one planned during this month. As far as the results, we just started producing these 2 wells, so it's a little early to tell. But we're initially pleased with the results.

Okay, okay. And then maybe let me ask you another one around completion designs, again. So I think you mentioned that you are testing different treatments and flowbacks on those 3 wells in Karnes. Could you may be shed a little more light about the variations you've been working on and in particular, the recent successful modifications you were able to come up with?

Yes, I certainly can. The 3 wells we did, we did -- there's many different knobs you can turn on these things to make different parameters, different components. What we did on these 3 wells, we pumped -- changed 3 different parameters. One of them, we added some resin-coated sand to the proppant. At the end, we tailed in resin coated; second well, we increased the clean volume of fluid we pumped; and the third well, we tightened up the spacing, brought the frac clusters closer together. So we did all 3 of those wells in the same area, basically, on the same type of well. And in addition to that, we put radioactive tracers in one of the well proppant packs, and we put chemical tracers in the fluids on the other 2. So we were able to go in and determine that we were indeed getting fluid into each and every one of our frac clusters, and that we were producing fluid out of each of the stages.

And your next question comes from the line of Stephen Shepherd with Simmons & Company.

So you had mentioned in the text, the press release, that the first Zavala County test well, which is, I believe, the Glasscock Ranch, the results were disappointing. Can you elaborate a little bit on disappointing?

Well, above that is we would hope to have it flowing back at high rates, and it didn't flow back at high rates. We -- it has remained pretty steady on what it was flowing. But we have since put it on pump and it's done better. So in time, we don't get a flowback at high rates for an extended time, we're going to be a little disappointed. This one has performed better on artificial lift, but it's too early to say that it's never going to work out or that we can't figure out ways to improve the frac to get more fluid entry into that. And I think the last part of it is that looking at some of the other wells that have been drilled in the area, that we think we could do better. So I would call this one more of work-to-do as opposed to one that just struck out.

So it sounds like it was more of an issue with the frac or the completion as opposed to any sort of geological issue that you encountered in that particular area?

Yes. I think I would describe it in that terms. We don't -- it's not that we can't make a geological mistake, but I think it has probably more to do with how you complete them. We didn't expect as much pressure because it's a shallower zone, but it didn't come on as we had hoped. But artificial lift has made a difference. So maybe it's a different type of Eagle Ford reservoir than, say, what you have in Karnes County.

Okay, that's helpful. And just generally speaking, are you all willing to give any kind of rate information on any of the wells that you have going right now in terms of where those wells IP, how they declined, anything that we can have there?

No, I mean, I know we're not -- the IPs, of course, are filed with the state if you want to look them up. But my reasoning for not offering the IPs is because they're a matter of public information is I don't want to give sponsorship that ours are completely comparable with somebody else's. I think our IPs have been pretty good. And of course, some people report IPs on artificial lift and some people don't and some people give different size choke. So we wouldn't drill a well based on an IP. So I'm reluctant to put that out as something that is really meaningful. What we are trying to do to be helpful, we provided more operational guidance in this release, and we've released more about some of the operational techniques and the reservoir management techniques we are embracing to try to give you some guidance on that. And we're trying to be helpful in giving you some sort of guidance for the remainder of the year. And in the case of to save money or to start a well early, we're trying to emphasize saving money.

[Operator Instructions] And your next question comes from the line of Mike Scialla with Stifel, Nicolaus.

The decision to flow these unrestricted chokes now, was that based on something you saw in any of your wells specifically or in something that you saw in others' wells? And do you have any evidence that you're going to get a flatter decline there and a higher EUR using that approach?

The answer to those are, yes. It's -- as in the Haynesville, I think it became pretty clear after a little bit, and we were one of the early ones, that the producing long [ph] or restricted choke in a constrained rate led to better performance. And that's essentially what we're trying to do here, too, is we're -- it isn't the restriction, Mike, so much as we're trying to achieve as we're trying to manage the bottom hole pressure to try to stay between the -- to try to stay below the closure stress of 5,000 pounds psi, which is the crush resistance for white sand. And so you talk in terms of restricted flow, that's a little easier to understand, but the real effect of it is to try to manage a bottom hole pressure. And when we don't have a huge amount of experience on this, but where we have implemented, it seems to have helped the wells continue to flow longer and I think will lead to higher EURs as they did in the Haynesville. Should I add anything to that, Matt or...

No, Joe, very well said. The other thing is with the higher strength proppants, it's not as big a concern, but when we're pumping white sand, we've -- like Joe said, we're really trying to manage the reservoir pressure, bottom hole pressure as opposed to any sort of restricted flow. I mean, it's more of a pressure management technique.

Understood. You also mentioned, you're going to be testing 80-acre spacing. Can you say where on your acreage you're going to do that? And is there any acreage in the Eagle Ford that you think is more -- of your acreage that's more amenable to tighter spacing than in the other parts? And are you seeing competitors do tighter spacing than 80 acres or tighter near -- by your acreage?

Mike, we really can't comment too much on what the other competitors are doing. The lease that we're testing it is the Love lease, which is, we think is going to be one of the better leases that we've had, and we're going to test the 80-acre time set there first.

Also in Northcut.

And also on Northcut. So you have the Love on the East side, and you have the Northcut over on the West side. So one in each area that we plan to do that. And the other thing is what I mentioned about managing bottom hole pressure, it may cut your early rates, but I think you'll have your -- you'll have more EURs over time. And so we will -- we will like to have had in our plan to reach the 1.4 million. We produced 500,000 barrels in the first half of the year. We expect to produce roughly 800,000 in these next 2 quarters. And you can see just a little restriction or a little bit of drilling back-to-back wells and having those production days, you save a 0.5 million, makes a huge difference because of the size company we are. Each well is still very important to us. Does that answer your question, Mike?

And your next question comes from the line of Shirley Ogden with Lee Financial.

I was just wondering a little bit more about the new acquisition in the Wolfbone, Delaware, West Texas area, if you could add a little color to that.

Yes, Shirley. We’re very, very excited. That's something we've worked on for a long time. We think that's been some of the best part of the Delaware. It's in an area where Anadarko [ph] is to the east of us -- Chesapeake is to the east of us. You've got Energen to the south. And if you -- so it's a -- who else is in there, David?

Yes, you've covered it, Anadarko, Chesapeake and...

Anybody else? David, do you want to comment? You're -- why don't you come over here by the speaker and comment.

Yes. Shirley, one of the things that we've been very interested in is looking for places where there are older vertical wells that have produced significantly from the Wolfcamp. And in the area that we're operating -- that we've taken, there is a very interesting -- well, there are 2 wells, actually, produced from vertical wells from the Wolfcamp section, one of which have a cume of over 50,000 barrels. That's a very encouraging sign. And just to the northeast of us where Chesapeake are, there is a number of horizontal wells. These are just 3 miles away, and their IPs have been very encouraging to this point, and their cumes to this point have been very encouraging. So we feel that we're right in the heart of the Wolfcamp fairway there.

What counties are these wells -- is your acreage in?

This is in Loving County.

And, Shirley, we have some other acreage in Southeastern New Mexico across the line that fits with this. So we're in the process of determining how much of a program we wish to have in 2013 in the Delaware at present, but we can't offer anything. We'll do that when we're still working on 2013 budget and strategy, but this will be a part of it in some way.

And your next question comes from the line of Don Crist with Johnson Rice.

In the Zavala County, I know it's still early days, but can you talk about the differences between the Austin Chalk well and the Eagle Ford well and the one that mixed both zones together? And what do you think that will be ultimate development plans? Will it be 2 laterals, 1 in the Austin Chalk and 1 in the Eagle Ford?

It's just way too early to project that. We're really effectively still just cleaning up the wells and trying to get them on some sort of -- on pump and some sort of stabilized rate to where we can draw some inferences from that and to understand how they frac so that you might be able to stack them or do something. So should have more on that later this year, but right now, we're really just still in the testing phase. David, do you have anything to that?

Yes. This is David Lancaster. I think all I'll add up to it. As you know, we -- from the time that we took this block, we had always intended to go out and test 3 different targets, 1 being the lower part of the Eagle Ford, which was the more classic Eagle Ford that's being completed, and 1 was just interface between the upper Eagle Ford and the lower Austin Chalk that we have kind of denoted the Chalkleford and the other was just the Austin Chalk itself. Our block is smack dab in the middle of the historical Pearsall field. So it made a lot of oil out of the upper Austin Chalk, the B [ph] zone, and we never really expected that we had a whole bunch of opportunities there. There were -- but we thought we might have a few infill wells to drill here and there. I think that we were interested to test and see if we could make a development out of the Eagle Ford. We never expected that it was going to be quite as good as some of the acreage we had in LaSalle County and over to the East. But we were hoping it would kind of become an area of sort of singles and doubles for us. And then in the Chalkleford, this is our first attempt there, and we just barely got that well back on now. But we've got other operators, particularly some private companies in the same area that are -- they're doing pretty good with that little zone. So we're learning about that, contemplating how we might be able to use seismic to make more sense out of -- or to better direct where we drill those kind of wells. So that's sort of where we are. I think we're kind of in the early days of having done what we've set out to do, which was to test these zones, and now we're evaluating the wells and seeing what we can do. As we said, the one we have a little more information on, that being the Glasscock 1 in the lower part of the Eagle Ford, as Joe mentioned, didn't flow back quite as -- didn't come on quite as well as we had anticipated. And really, we're trying to figure that out. I think we're evaluating the frac we did. We're just also looking at the reservoir. So it may be a little tighter there. We're just -- it's still early days for us to understand that, but we've got time. That acreage is all held by production, and so we've got time to figure that out, and we're going to set about doing that.

And, David, I think, just to add to what you're saying, I just think it's important to note that the well, the Glasscock 1 did improve significantly when we put it on pump.

It did.

So we were disappointed, but we were less disappointed as the pump came on, and it seemed to respond to artificial lift, and we took some encouragement from that. But we'd also didn't want to overstate the work that we had or understate the work we had in front of us to find different ways to improve that performance and to get the cost down. So it can be the singles and doubles that we first planned for it.

Okay. And just to follow-on on that, another operator, Sanchez, to the South of you all a little bit, has done some pretty good vertical wells, commingling both the Eagle Ford and the Austin Chalk. Do you think that's a possibility in the future, moving from horizontals if they're not as productive going to verticals and commingling these zones?

Yes, I think that's got some promise. In other areas, people are doing that same thing. They find it better to drill the vertical and commingle because of cost. And so several -- that's what I've said, there's a lot of work being done on that as well as on the seismic to help improve production. And I think you'll continue to see that kind of experimentation. Matt, did you have something you wanted to say?

Well, just on that block of acreage, in regards to different types of things we might do out there. We do have all rights, all depths on that block and, as David said, it is about production. So that's a significant advantage to us.

Yes. And actually where we may try some of that is on our Margolis [ph] acreage that we recently acquired may lend itself to that kind of vertical testing that more so than this, because, as Matt pointed out, we've already got all rights, all depths.

And your next question is a follow-up question from the line of Stephen Shepherd with Simmons & Company.

I just got 2 income statement-related questions pertaining to LOE and also oil differentials. It looks like on a unit-rate basis, LOE ticked up a bit quarter-over-quarter. I'm just wondering if you could kind of frame that increase up. Is that something we should expect to persist into the future? And then on oil differentials, a real nice bump up on your oil differentials for the quarter, up to kind of a $9.50 range or somewhere in that area. Now I remember you had previously stated that you thought that you could get those up to about $9 over WTI eventually. I'm just wondering what -- how we should be thinking about that as well.

Dave, we'd want you -- Lancaster -- take the LOE question, and then I'll come back and speak a little bit what we're doing on marketing [ph].

Okay. Stephen, I think on the LOE that we're probably expecting in the near term that our LOE costs are going to run a little higher than -- and maybe more in line with what we've had in this quarter. As we've disclosed the last couple of quarters, we're drilling in a lot of new areas. And as we drill our first wells out there, we're not -- we don't necessarily have our pipeline hooked up or permanent facilities ready to go. So we have brought in some temporary testing crews and put 24-hour personnel with those and -- in order that we could go ahead and start producing and evaluating these wells. And so that's increased our costs a bit. Now that we've got a lot of that done, we're in pretty good shape now at Martin Ranch, at the Northcut, at Sickenius. We're about to get our Danysh/Pawelek, those -- the pipeline, the permanent facilities in place. The Love is pretty close. So as we do that and then return to some of these leases, we won't encounter that going forward. So I think we think some of those temporary charges will begin to subside. I will say that may be offset a bit by the fact that as the year goes on and we put a few more of these wells on pump, that has a tendency to cause the LOE to come up a little bit, too. So I wish I could be a little more definitive with you, but that's probably about the best information I know to give you. I don't know that -- I would probably tend to expect the number to be about where it is for the near term.

Then on your -- talking about the market team, we've brought on a colleague of ours full time to help us in that area, and I feel he's done an excellent job as the oil price that you've seen. We've also worked out a new natural gas agreement in general terms and are looking to execute on that. That will also help on our gas marketing. On our oil, a lot of what happens depends upon options that we create or where you've got your oil and what you can do with it and how close you are to the pipelines. And so we're working on all of that, and we think he's done a real good job and everybody else has helped contribute to it. And the gas, as we get in these pipelines, Matt has done a good job on -- in these pipelines in place, so that we're sending more down for processing. And it's interesting to note that, roughly, we have tripled the amount of NGLs that we're producing today from first of the year. Is that the first quarter, I think, averaged in there about roughly 12,000 barrels per month. And today, we're probably 36,000 barrels per month that -- to the company. Is that...

[indiscernible] I think those are quarter numbers.

Quarterly numbers. That's right, those are quarterly -- 36,000 for the quarter versus 12,000 for the first quarter of this year. So those are -- which adds about $2.50 bump to the gas uplift -- $2 to $2.50 per uplift to the gas on an Mcf basis. Did I say that right?

Yes. That's correct, Joe.

Okay, good. Did that answer your question?

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

All right. Well, thank you very much for your attention. A couple of things that weren't mentioned in there that I just thought I'd mention again to you that on this -- while we are reducing our oil guidance, I think it's important that we're reaffirming our other guidance on what we are going to spend this year, the gas rate, most likely gas rate, and third is our oil production exit rate is, again, we believe will be in the 5,000 to 6,500. So while it may have taken us a little time and we needed to do these operational concerns, we're still planning to exit where we said we were. And that's one of the things we're trying to build with you, our credibility. Spent the money where we said we would. We spent the amount of money we said we would, and the results are largely what we said they were. Our exit rates are going to be what we think it was. But during the course of the year, we were -- we've tried to emphasize that we're going to put operations first and reservoir management first that it isn't a rock problem so much as looking at the fracs and managing the ingredients of the fracs and how you do them and the per stage nature that has had more of effect on these rates and the timing of when we did them, slowing down things so you do a zipper frac or work from the same pad, all of which I think we've tried to give some examples so that you know that this makes sense. We've replaced our acreage. We've made a lot of progress on our natural gas and oil marketing contracts. We've put in place or are putting in place a new credit facility to answer any of the liquidity concerns. We've doubled oil production in 6 months. We made a lot of organizational progress not -- having moved from being private to public and just getting all the forms filled out and filed without being late. I really want to give -- commend David and his group -- Lancaster -- on that. We've developed the new focus areas. We said to many of you as we've been around the city that don't be surprised that we expected to announce something in the Delaware Basin, and we have. So we have this new focus area to work on next year. The Gracie has made progress, and we expect to have an announcement on that soon. Our exit rate is what we had said as a -- which is a bigger target for us than the actual production rate and that the year-over-year progress, we are right now at 6 months in essentially the same position we were in all of 2011. And 2011 was twice what it had been the year before. So it's a 6-month level. It's hard to be -- we feel pretty good about that. We're getting our sea legs and as we continue to work with the analysts that I think will become -- we'll get better at all of that. But we're pretty excited by where we are and how we're coming out. And we really appreciate the interest that you all have taken and look forward to getting with you, and third quarter is going to be better than the second quarter. So sequentially, we began the year with second is going to be better than first and third is going to be better than second and fourth is going to be better than third, and all that's going to happen, and you'll see that take place. David Lancaster, would you, as Chief Operating Officer, have I left out anything? Would you add to it?

No, sir Joe. I don't think so. I think that you've covered everything and just, I'd like to say, we appreciate also the folks that have been on and look forward to talking to everybody again soon.

Matt, operationally?

Nothing real to add, Joe. Real excited about the completions we're doing and the path forward, so.

David Nicklin, on -- won't you lend something -- we really haven't discussed the new focus area completely. You want to add to that, how that adds to a potential third leg?

Yes, we're very excited about breaking into a new area within -- it's not an entirely new area to the company or its staff. We've worked in the Delaware Basin before. We have some prior positions to the north in New Mexico. And we're leveraging what we've learned from the Haynesville and the Eagle Ford and applying that to this new area. Very excited.

Well, great. Well, thanks. Look forward to visiting with you all again in -- on the next earnings release. Signing off.

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