Matador Resources Co (MTDR) 2012 Q4 法說會逐字稿

Good morning, ladies and gentlemen. Welcome to the fourth-quarter and full-year 2012 Matador Resources Company earnings conference call. My name is Lisa and I will be your operator for today.

At this time, all participants are in listen-only mode. We will facilitate a question-and-answer session at the end of the conference. As a reminder, this conference is being recorded for replay purposes, and the replay will be available through Thursday, March 28, 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 your host, Mr. Joe Foran, Chairman, President, and CEO. Please proceed. Thank you.

Thank you, Lisa, and good morning to everyone. First, thanks to all of you for participating in our fourth-quarter and full-year 2012 earnings conference call.

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

Today is about a year and a month since we went public, and we are very pleased, obviously, with our 2012 operating and financial results, our fourth-quarter 2012 performance, and how we've continued this progress through the first 60 days of 2013. Our staff and Board have done an excellent job finding ways to drill better wells for less money.

In 2012, we grew our production eightfold to just over 1.2 million barrels from just 154,000 barrels in 2011 and 33,000 barrels in 2010. Sequentially, we increased oil production over 40% from approximately 303,000 barrels in the third quarter of 2012 to approximately 426,000 barrels in the fourth quarter of 2012. This growth is continuing in the first quarter of 2013, despite having approximately 10% of our wells shut in and at given time.

Matador had record adjusted EBITDA of $115.9 million for the year ended December 31, 2012, a year-over-year increase of 132% from $49.9 million reported for the year ended December 31, 2011, and slightly above the top end of our 2012 guidance range.

Sequentially, we had adjusted EBITDA of $38 million for the fourth quarter of 2012, a sequential quarterly increase of 33% from $28.6 million reported in the third quarter of 2012 and a threefold year-over-year increase from $12.4 million reported for the fourth quarter of 2011.

I'm also pleased to announce this stronger year-end well performance has continued into the first 60 days of 2013. Since the first of the year, we have averaged approximately 5,000 barrels of oil per day and 34 million cubic feet of natural gas per day, compared to production guidance of approximately 4,000 barrels per day and 31 million of natural gas per day as announced at analyst day on December 6, 2012.

With that, we'd go to questions and turn the call back over to Lisa and take some of your questions.

(Operator Instructions). [Corey Markling], RBC Capital Markets.

Hey, good morning. I'll start with the Eagle Ford. It sounds like both rigs are drilling on multi-well pads. How much of the 2013 Eagle Ford drilling program will be on multi-well pads this year?

The 2013 program, we're starting off, we've got two pad drilling operations going right now, one on the Martin Ranch, one on Cowey. There are three wells on each of those pads. As we go through the year, depending on how the schedule unfolds, we'll use pad drilling whenever and wherever we can.

And then, in the Permian, can you guys provide a little bit of an update on that and maybe what formations you're going to be targeting going forward?

Yes, David Nicklin.

We are on track to drill three wells this year. We will be focusing primarily on the Wolfcamp, but also on the Bone Spring. They will be our main formations, and we're focusing there because we're encouraged by a number of well results from around our lease areas.

I don't know, Brad, if you want to add anything about some of the surrounding wells?

Sure, David. There has been some recent activity around our Wolf acreage. Oxy has just drilled their Regan McElvain well, which had an initial potential of almost 600 barrels per day with over 2 million cubic feet of gas, and it made 18,000 barrels in the first month. So that's an average of about 600 barrels a day.

And then, Energen has drilled a well also offsetting our Wolf acreage with an initial potential of about 800 barrels a day with over 7 million cubic feet of gas. So we're very encouraged by those nearby wells.

And of course, the big well everybody talks about up in our Ranger acreage is the Concho [Strateget] well, which is about two miles from some of our acreage. That well has made 300,000 barrels of oil in the first year. So, again, we're very encouraged by some of those results, and the Strateget is in the Second Bone Springs, which will be our target.

Thank you, Brad.

Brian Corales, Howard Weil.

Yes, hey, guys. Can you maybe talk about -- so far this year, production has been pretty strong. Can you talk about what the cause is? Did you add more wells that you planned, not have to take many off, or has the well performance been better than originally estimated?

Brian, I'm going to ask David to take the call, but it's primarily well performance. David?

Yes, hi, Brian. This is David Lancaster. Yes, I would say that it's primarily well performance, Brian.

In the last three months, December, January, February, we've drilled a number of wells that have just come in and been better than our expectations. I think that a lot of that is the result of improvements we've made in our fracture treatment designs, and really it has nothing to do with additional wells being put on or wells coming on any sooner. I think that's all pretty well on track for the quarter, but the production of the wells has not only come on a little stronger, but we've been encouraged and incented to hang in there a little better, relative to some wells that we drilled previously.

Brian, I would add -- this is Joe. I would add to it. It's been a team performance because I would also says that it's been helped by this restricted choke that we've done, artificial lift on those wells that have gone to artificial lift.

And Ryan is in what he calls his fourth-generation frac design with closer perf clusters and more fluid, and it seems to break up the rock better and lead to more stimulated rock volume. Ryan, would you add to that?

That pretty much characterizes the design changes, and just in a side-by-side comparison, when we've gone into areas where we drilled wells with what we called our generation two design and compared those with the most recent wells to the generation four design, we've had improvements in every case and in some cases as high as 100% improvement.

On that same note, is it too early to -- I mean, are you all considering even increasing the EUR?

I guess the way I would describe it, Brian, there's been improvement on productivity, that's what we can clearly see, of 50% or more. But I wouldn't go out there and say EURs until we have more data to confirm that. But clearly --

Understood.

-- we have enough data to see a 50% more increase in productivity.

And Joe, if I can just ask one more. A lot of your neighbors in both the east and the west have been testing down-spacing or drilling on tighter spacing. Can you maybe comment on where you stand from that standpoint, if you're testing it or if you plan to in 2013?

Yes, David Lancaster?

Yes, Brian, thank you. We do, in fact, see what you see, which is that a number of the other operators are testing it, you know, with inter-spacings. And we also are planning to do that.

In fact, we have a couple of 40-acre down-spacing tests planned here in the very near term. And so, we're looking forward to doing those and we're excited to see what the results from them may be.

I think we feel like that, particularly on the western side of our acreage, but also in the eastern side, particularly in the more northern part in the Karnes and very southern Wilson County, that we will have the ability to go to 40-acre spacing, and we're excited about the opportunity to test that out and see how it works.

And Brian, I would just add that would -- if successful, that would increase the number of locations that we presently have that we rated Tier 1. Presently, we have 275 locations. 155 are rated Tier 1 and 119, Tier 2.

And these are all engineered locations with specific proration units. The 155 Tier 1 are expected to have EURs at 225,000 barrels of oil or better and the Tier 2, 119 -- the 119 Tier 2 would be expected to have 150,000 barrels of oil. And again, these are barrels of oil, not BOE.

The Tier 1 would have a better than 20% or 25% rate of return and the Tier 2 would have better than 10% to 15% rate of return.

All right, guys. Thank you.

Stephen Shepherd, Simmons & Company.

I noticed that the NGL hedge volumes increased quarter over quarter. Is that a readthrough for NGLs as a percentage of the total stream increasing into the future? And during the fourth quarter, how much, if any, of your liquids production was NGLs?

Hi, Stephen, this is David. I think what you can sort of read through from the hedging is that we've seen sort of a softening in the NGL pricing, and so we've entered into the hedges in order to help us with just our realizations with the price declining.

So I think that's really where we are on the hedges, just as a way of protection, particularly on the lighter ends of the spectrum and particularly, of course, where ethane is concerned.

With regard to the amount of production or what percentage that it is, Matt, do you want to take that question? You probably have a little better handle on that.

Sure. You know, for the year-end months, November and December, we had running about 12,000 or 15,000 barrels per month NGLs in November. In December, it was up closer to 22,000, 25,000 barrels per month. It carries on into the first of the year.

The one thing that may be of interest is that we are, per our contract, in the conditioning mode for ethane. So we're rejecting as much ethane as we can at this point. It's more profitable for us to be paid on an MMBTU basis on the ethane production.

That's great. Thanks very much. And one more, if I can, with regard to the increased well performance. Has that been focused in the Tier 1 or is it Tier 2 acreage, and maybe asking it a different way, what specific counties are you seeing the better performance in?

Steve, the improved performance is across the board and, as we mentioned earlier, largely related to the improved frac design and the operating practices that we have, the simultaneous fracs, the restricted choke, this frac design that -- as Ryan calls it, the generation four with the closer perf clusters. So that's across the board.

I think there was a second part to your question. Ryan, would you add to that?

Well, just addressing the first part of the question, I think a lot of our characterization of the improvement comes from the side-by-side comparisons, and that's, like Joe said, that is across the board, but that's specific instances where we can point to to really quantify our improvement. In some of our newer acreage, of course, we don't have older wells to compare it with, but we feel like we're getting substantially better wells with the new frac design.

Okay, and is there any change to well costs in any of your areas? At the analyst day, you had given a $7 million figure for the western Eagle Ford, and then $8 million to $9 million for kind of the western part of east, and then $9 million to $10 million for the rest. Any change to any of those ranges?

I think those ranges are probably still about right. We're seeing some softening in some of the pricing. You know, the rig rates are coming down a little bit, some of the competition, you know, for saltwater disposal rates and for different vendors, even steel prices have softened a little bit.

So we're making improvements on those costs and also the drilling efficiencies. That may be partially offset by -- as Ryan continues to evolve his frac design. We're right now currently pricing out frac -- products -- frac jobs with these guys right now, and it looks favorable. But we may increase fluid volumes. We may do some things to -- it will be a constant cost-benefit analysis we'll be doing on these frac jobs.

Okay, thank you for your comments. I appreciate it.

Gabe Daoud, Sidoti & Company.

Most of my questions have been answered already, but I guess just in terms of acquisitions this year, if there's anything specific that you guys could be looking at? Maybe some bolt-on acreage in the Eagle Ford or maybe even something additionally in the Permian that you guys are seeing?

Gabe, you're right. We're working on both of those ideas as we speak. We see deals in the pipeline, and we're encouraged and optimistic that we will have both some bolt-on acreage in the Eagle Ford and that we will continue to add to our position in the Permian.

Okay, great. And then, Joe, just one follow-up question, I guess in terms of the Haynesville, what prices do you need to see for the economics to make sense to get back out there? And if they do get -- if prices do get to a point where you would get back out there, would you add another rig to the program or maybe just take a rig from the Eagle Ford and move it to the Haynesville?

Gabe, those are good questions. As to when we would jump back in, that's a combination of where prices are and where they're headed and where costs are over there.

And it looks -- and you'd probably want to have a situation where you could hedge your gas to be assured to protect yourself against volatility, but it doesn't take much. EnCana announced they were going over there at $3.50. All of our acreage is HBP, so we don't have to do anything and we would probably wait to a better price -- that is, it starts to get over $4.00 is where I think our interest level would be.

And then, as far as taking a rig, we would probably do it with a rig that's over there. That's probably where you can make your best deal was hiring a rig over there. But we'd like to see a little better price, start to go over $4.00, and with the trend being more likely to go up than down.

Any of you guys to add to that?

All right. Thank you, Gabe.

All right, great. Thank you, guys. I appreciate it.

(Operator Instructions). Bo Howard, HMJ Trust.

Just a quick pricing question. Are you guys getting priced on TI plus or Brent or LLS minus?

Matt, go ahead.

Yes, Bo, what we're getting is the LLS differential. So it's basically we're the LLS differential, less trucking.

Okay, that's (multiple speakers). What is the LLS differential today? Or not today, but what is --

It nets us about $10 to $12 more per barrel, after trucking. That's after all costs. We get about an uplift at $10 to $12 above WTI.

Excellent. We want you on our trading team.

(Laughter). Thank you, Bo.

Thank you for your questions. I'll just advise you there no further questions, so ladies and gentlemen, this ends the Q&A portion of this morning's conference call. I'd now like to turn the conference over to management for any closing remarks. Thank you.

Thank you, Lisa. I think the biggest contrast with Lisa and me is the elegance of her accent versus mine. But I appreciate all of you putting up with that contrast. And we appreciate your participation.

We're continuing to work and build Matador and grow its worth and value, and we appreciate visiting with you and look forward to seeing all of you again soon, we hope. Thanks.

Thank you very much, ladies and gentlemen. That concludes today's presentation. You may now disconnect your lines. Have a good day. Thank you.