Matador Resources Co (MTDR) 2013 Q3 法說會逐字稿

Good morning, ladies and gentlemen, and welcome to the third-quarter 2013 Matador Resources Company earnings conference call. My name is Jasmine, 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 a replay will be available through Wednesday, November 27, 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, actual results and future events that 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, President, and CEO. You may proceed.

Thank you, Jasmine. And good morning to everyone on the line, and thank you for participating in our third-quarter 2013 earnings conference call. We appreciate your time and interest very much. All in all, this year is coming together very nicely for us in many ways, which is reflected in the fact that the third quarter of 2013 has shaped up as simply the best quarter in the Company's history. There are three key points we would like to emphasize on this call.

First, the quarter's financial results were driven primarily by our operations in the Eagle Ford, which continued to exceed expectations.

Second, we are continuing to build our presence in the Permian Basin, and we are pleased to be able to provide some preliminary results from our efforts there in our press release.

Third, for the full-year 2013, it now appears we will manage to increase 2013 production by 67% to 75% over 2012 and increase 2013 adjusted EBITDA by 55% to 64% over 2012 without increasing total debt as a result of our drilling activity.

The $40 million increase in debt over last year is directly attributable to the approximately $40 million investment we have made in building our land position in the Permian.

As I have mentioned, we are continuing to see favorable results from our Eagle Ford drilling program that continues to be the heart of our operations. More than 80% of our capital expenditures is being spent here, and we are encouraged not only by our continued progress in cost savings there with our frac designs, drilling times, and production techniques but also by our progress with downspacing across our Eagle Ford acreage position.

Our staff and our Board are working hard studying the Eagle Ford to find ways to continue to drill better wells for less money. We intend to keep two contracted drilling rigs running in the Eagle Ford throughout 2014, and we fully expect the majority of our 2014 capital expenditures will be spent in this key operating area.

Next, I want to note the growing importance of our developing position in the Permian Basin in Southeast New Mexico and West Texas. Between January 1 and November 6, 2013, we have significantly added to our leasehold position, which now amounts to 64,900 gross and 40,400 net acres in this area, primarily in Lee and Eddy Counties, including an additional 7,524 net acres acquired in the last 60 days.

Not only do we consider this one of the best resource plays in the country, along with the Eagle Ford, but we consider the large majority of our acreage to be prospective for multiple oil- and liquids-rich targets including Wolfcamp and Bone Springs plays. Given our encouraging preliminary results from our activities, we intend to operate one contracted drilling rig in the Permian for the remainder of 2013 and throughout 2014.

Now, I would like to highlight our record financial results for the third quarter of 2013 as well as the first nine months of the year. Our average daily oil production and average daily oil equivalent production for the third quarter were the best quarterly figures in the Company's history. And I'd like to take a moment to commend our high-quality technical teams for getting us to this point.

We produced 13,482 barrels of oil equivalent per day including 6,703 barrels of oil per day and 40.7 million cubic feet of natural gas per day, an increase of more than 50% compared to the third quarter of 2012. Our oil and natural gas revenues for the three- and nine-month periods ending September 30, 2013 were also the highest values ever achieved in their respective periods in Matador's history.

For the third quarter of 2013, our oil and natural gas revenues were $81.9 million, which is year-over-year increase of more than 100% from third quarter of 2012.

During the quarter ending September 30, 2013, we achieved record Adjusted EBITDA of $61.5 million, which was more than double year-over-year increase from the $28.6 million reported for the third quarter of 2012 and more than a 50% sequential increase from $40.8 million reported for the second quarter of 2013. In fact, Adjusted EBITDA for the third quarter alone was greater than the full year of 2011, just two years ago. And significantly, current debt levels are less than 1 times this year's Adjusted EBITDA.

In addition, for the third quarter of 2013, we were reporting net income of approximately $20.1 million, or earnings of $0.35 per share, as compared to a net loss of approximately $9.2 million, or a loss of $0.17 per share for the third quarter of 2012. For the nine months ending September 30, 2013, we reported net income of approximately $29.7 million, or earnings of $0.53 per common share, compared to a net loss of approximately $12.1 million and a loss of $0.23 per comment share for the nine months ending September 30, 2012 one year ago.

In light of this progress, we have increased guidance as follows. First, oil production guidance increases from a range of 1.8 to 2.0 million barrels to a range of 2.0 to 2.1 million barrels. Second, a natural gas production guidance increase from a range of 11.0 billion cubic feet to 12.0 billion cubic feet to a range of 12.0 billion cubic feet to 13.0 billion cubic feet for the year. Third, annual oil and gas revenues guidance increase from a range of $220 million to $240 million to a range of $250 million to $270 million. And fourth, an annual adjusted EBITDA guidance increase from a range of $155 million to $175 million to a range of $180 million to $190 million. This marks the second time this year we've been able to increase our guidance since announcing the initial 2013 guidance a year ago.

We are excited about Matador's fourth quarter and finishing the year very strong, as we did last year, but still reiterate the caution we described on our last earnings call on August 7, 2013. At this point in our growth, Matador's production and financial results are likely to be uneven on a quarter-to-quarter basis and subject to various operating conditions and operating practice we follow, such as the use of batch drilling for one of our drilling rigs in the Eagle Ford it and the use of restricted chokes on our new wells.

As a result of these practices and the fact that we estimate up to 20% of our production may be shut in in various times in the fourth quarter, we estimate that our production may decline as much as 10% during the fourth quarter of 2013. But we are also anticipating a surge in production as the year ends and, again, into the first quarter of 2013 to new record levels as new wells are brought online and shut-in wells are restored to production. More detailed guidance will be provided at our analyst day December 12, 2013, but Matador is expecting a sequential increase in production for the first six months of 2014 compared to the last six months of 2013, just as Matador still expects a sequential increase for the last six months of 2013 compared to the first six months of the year.

With that, I'd like to introduce everyone from Matador senior staff joining me in this call who have all contributed greatly to these results. We have David Lancaster, Executive Vice President and Chief Operating Officer and Chief Financial Officer; Matt Hairford, Executive Vice President of Operations; David Nicklin, Executive Director of Exploration; Ryan London, Vice President and General Manager; Brad Robinson, Vice President of Reservoir Engineering and Chief Technology Officer; and other members of the senior staff and operating group.

I would now like to turn the call over to the operator, and we'll be pleased to take your questions. Jasmine?

(Operator Instructions) Cory Markling, RBC Capital Markets.

Congratulations on another good quarter. Starting in the Permian, you expanded your footprint by another 7500 acres. How much exposure do you envision building here going forward?

Cory, it's hard to say exactly. We don't have any target number at this point. It'll be driven by opportunities, drilling results, and the other opportunities we might have in our other operating areas. But we will continue to work this area hard just as we're doing the Eagle Ford and the Haynesville.

And I guess a follow-up -- what kind of results do you guys need to see to accelerate activity in the Basin?

Cory, we're looking for results that will be comparable to the Eagle Ford.

All right. Thanks, guys.

Irene Haas, Wunderlich.

Really great quarter. My question is -- we really love the Delaware Basin for multitudes of reasons. And you guys, being an Eagle Ford operator, can you enlighten us on sort of what kind of technologic transfer we can expect to gain from your experience in the Eagle Ford into the Delaware Basin? Yesterday, we saw Cimarex drilling along lateral and such. So just give us a little color as to how good things would be and how much the industry can leapfrog from experiences from other basins.

Irene, thanks, (technical difficulty). Let me turn the question to David Lancaster. He's been -- we've been talking about that around here, and I think David is best qualified to answer that.

I'll start and then maybe defer to Matt and Ryan as well to add any comments they would have. You know, Irene, I think that our experience not only in the Eagle Ford but also in the Haynesville will certainly transfer well and bode well for us as we move out to the Permian. I think our experience in drilling along laterals and in doing the multi-stage frac's and our experience with numbers of stages to add and how to better frac these wells, it's all going to translate. Even just in terms of the operations, the things that we've learned from the Eagle Ford in terms of how to flow the wells back and how to produce them, the use of the artificial lift -- I think we feel like all of those things will translate for us going forward.

That said, the Permian will have its unique challenges, and the systems are a little different. I mean, the Wolfcamp may be more of the shale-type play that we are used to in the Eagle Ford or the Haynesville. The Bone Springs is going to be a little different because it's more of the sand complex, as you know. And so, I think there will be some nuances and we will learn, but I think we're all starting -- certainly those of us who have had the experience starting from a higher place than we were perhaps when we entered into the Haynesville play or the Eagle Ford play. Ryan, would you add to that?

Yes, Irene, this is Ryan. I'd like to just echo what David said about what we learned in the Eagle Ford and the Haynesville. I think what we'll probably do from the frac design standpoint, we'll probably err on the high side beginning there. We'll probably start off with bigger frac's than I think a lot of the other operators in the Permian, based on what we've learned in the Eagle Ford. Just sticking with the fundamentals of stimulated rock volume and more profit, tighter spacing, trying to take advantage of new wellbore. And then -- which creates a wellbore pattern that's more conducive for tighter spacing so we don't run into problems later on.

Matt --

Yes, I think those are really good points. And, as we discussed before, these first wells, we're going to do like we did in the Eagle Ford as we methodically marched across our acreage evaluating each one of these acreage positions. We'll do the same thing in the Permian. And to that note, these first wells are data collection wells; we're drilling pilot holes and collecting rotary sidewall cores and logs and all these things. So we'll take all that information, roll it into how we develop the Eagle Ford process, and we hope to get the -- up the learning curve pretty quick.

Great. Thank you.

Hold it, Irene. I hope -- you've asked a real good question. Brad wants to add something here, too.

I was just going to add, Irene -- this is Brad Robinson. Some of us older hands around here actually started our careers out in the Permian. I started for Marathon Oil Company there in Midland. I know Matt started with Conoco drilling wells over in New Mexico. And, if I'm not mistaken, our esteemed colleague here from England started out in the Permian Basin when he first came here to the States on a mud logging unit looking at samples and so forth. So we do have some experience, and we're hoping to mesh some of that old experience with the new technology.

Great. Thank you. Look forward to the progress to be made in 2014.

Thanks, Irene.

Ben Wyatt, Stephens.

Joe, just really quick. Maybe you can talk a little bit about as you guys -- as we look into 2014, you guys start your drilling operations out in the Permian. Do you guys envision drilling kind of across all three areas kind of evenly? Do you think you'll have a slant towards maybe the Ranger area over Indian [Draw]? Or maybe if you could just give us a little color on that front.

Ben, it's a little early. We'll have more detail at analyst day. We're just drilling these first three appraisal wells. We're going to drill a fourth appraisal well in the Indian Draw-Rustler Breaks area. And with those four appraisals, we'll add results. Our results and the way those areas are developing drive us to more than one area or another. But we need to finish those four appraisal wells and finish -- and we continue the analysis and the regional studies that we're doing. But we'll hope to have more detail on that for you or expect to have more on analyst day.

Very good. And I just -- I guess one more. Picked up more acreage out in the Permian. You guys are still grabbing that kind of in the $1500 to $2000 per acre range? And is that sustainable kind of going forward, do you think?

Ben, this last block that we -- I mean, these last group that we bought in the last 60 days have averaged in that range. You know, I don't know. As the areas get more delineated (technical difficulty) or clear, the prices may go up some. But right now, that's where the opportunity is in that range and maybe a little higher; but it's still we think at a pretty intriguing price, really.

Very good. Well, thanks and again, nice quarter.

Thanks, Ben.

Mike Scialla, Stifel.

I wanted to ask you about the pilot tests in the Eagle Ford. I wasn't sure from your release when you said there's -- you're seeing possible interference or communication. I wasn't sure if that was specific to the 40-acre space pilot in Karnes or if that was all of your down-space pilots.

But my real question is do you think at this point you are accelerating production with these pilots, maybe not getting as high an EUR as you would with the 80-acre wells? Or do you think you might be even getting higher EURs even with some communication because you're getting a better recovery factor?

Well, you asked a really good question, Mike. And I'm going to give it to our team leader for the Eagle Ford, Ryan London.

Hi, Mike. We have seen production interference on both of these pilots' tests that were mentioned in the release. Since then, we've actually drilled a couple of more 40-acre wells, and those really haven't shown any decline in production; in fact, they're superior to all the 80-acre wells in that particular lease.

The two pilots that we were mentioning specifically in the release. We did see, like I said, a little bit of production interference, but not quite as good as the other 80-acre wells that we frac'ed with the generation-five design early on. But they look like they're going to be better than some of the older frac generation wells. And so it's a little early for us to tell right now what the EUR is going to be eventually, but right now we're very encouraged and I think that we are encouraged enough to continue drilling on 40 acres for the rest of 2013 and 2014.

A follow-up, Ryan. The ones you mentioned the release, I think you had said the two pilots in Karnes were -- they recovered about 35,000 barrels each in three months; and the one 40-acre pilot in Martin Ranch had done, I believe, 36,000 in four months. I'm just wondering how that compares to the type curves that you're looking at for each of those areas.

Those are right in line with most of the type curves in those area. As you remember, about a year ago -- year and a half ago, we started producing all the wells on restricted chokes. So the early time data, the first two or three months, most of the wells kind of hang in the same area. Our generation-five frac's have actually outperformed that baseline curve. But, like I said earlier, they're hanging in there with all the wells that we have frac'ed in the respective leases. You really start to see a departure from that in month four, five, and six. But right now, they are acting as expected and we don't expect to have any -- we expect the wells to perform very well.

Mike, this is Matt. I'd just like to add, too, it is early on in the process for the pilot wells that you're talking about. And we're adding to that data set, so we're drilling more of these wells. And as they progress and produce, then we'll have a much better data set to make that evaluation on.

Very good. Thank you, guys.

(Operator Instructions) Neal Dingmann, SunTrust.

Joe, for you, Ryan, or one of the guys, just running back to the Perm side. You obviously have a lot different formations you're looking at; two questions around that. Once you have a better idea, would you go after multi-formations and likely on a single pad to help costs? Is that something you'd be looking at down the line once you start identifying some of these formations?

Neal, that's certainly possible. We focus on first getting one horizon that is really going to return revenue than trying to say, well this will be good if we could make two or three work. We want it to be good on -- to be able to stand alone on one horizon. But we're certainly not opposed to multiple well drilling from a pad because we're doing that currently. Anything that leads to drilling efficiencies.

But since you're asking somewhat of a combined question there, I'm going to give both David Nicklin, our exploration -- Head of Exploration, and Matt, head of Operations, to give a comment. Do either of you want to comment on that?

Neal, there's no doubt that there is prospectively at multiple horizons in most of the -- well, in all of the areas that we've chosen. That was the one of the reasons that we chose those areas. But Joe is absolutely correct, that we've also chosen those areas for what we believe to be a solid, financially robust single horizon target zone. But having said that, first wells are data-gathering wells. We're taking rotary sidewall cores up and down the section in two of our areas, and we'll use that data in the coming year to rank some of the other opportunities.

And then, Neal, on an operational side -- this is Matt -- I'll just add we're keeping up with the current technology to drill and fracture multilaterals from the same wellbore. The staff we have here, there are many of us that do have a lot of experience drilling multilaterals. So when the time comes, I think we'll be ready to do that. But, as Joe said, currently we're drilling off the same pad, multi-wells. We just haven't done any stacked laterals. But we're keenly aware of how that may impact us in the future.

This is David, Neal. I wasn't quite sure if your question was going to stack the laterals in the same wellbore or just more different horizons off the same pad. And if it was more the latter, then I think that certainly we think that our acreage could lend itself to possibly to the drilling of different horizons off the same pad -- I mean, different targets.

That's exactly where I was going. And maybe just a follow-on to that guidance, a little more [input]. As far as on that one -- I noticed, I think you drilled one of these on the 4300-foot lateral. Again, will you test sort of different lengths trying to see what the optimal is there? And I know it's very premature, any idea on spacing there?

Neil, we'll drill the laterals as long as we need to. In the Eagle Ford, we've drilled them all different lengths because that's the geometry of the leases there; 7500 feet or more. And then you have the same thing in New Mexico; we'll drill them as way the geometry of the leases since most of those are square sections. I think you'll have to permit two sections at once, and we'll work on those regulatory matters as they come up in the drilling. But Ryan, you are prepared to drill all different lengths.

Yes, Neal, we can drill as long as we want. Most of the -- our desire -- maximum desire in the lateral length is probably in the 7000-foot, 8000-foot territory. But the well you're talking about, the 4300-foot lateral, it was constrained by just the section township range format in New Mexico. And the local regulations required US to stay 660 feet from each lease line. So right off the bat, we're in kind of -- in that 4300 -- 4500-foot lateral range right now.

As time goes on and we can get better field rules and possibly drill across unit laterals, we can expect that to increase. But right now, we're at the 4300-foot in New Mexico.

And of course, Neal, that is in New Mexico. On our lease in Texas, it is differently configured geometrically, and so we would be able to drill longer laterals. I expect that we will on that acreage.

And I might just add that I think that -- to your comment, it is early. It is early for us, but I think that our experience and what you've seen from us in the Eagle Ford is that we -- I think we pride ourselves on our technology here at Matador, and we'll be working very hard to figure out what the optimal thing to do is with regard to drilling, completion, production. That's kind of what we're about.

Wow, a lot of exciting activity. Thanks, guys.

Thanks Neal.

(Operator Instructions) Mike Scialla, Stifel.

Just had a couple more. On the Permian, 40,000 net acres, can you break that down by the areas? How much is in the Wolf and Ranger in particular?

Mike, we'll break that down between Wolf and Ranger. We're not trying to say where everything is because we're trying to add to the lease position now and just don't want to do something that might make it difficult -- more difficult to acquire acreage in either area because we're working hard to add in both areas. I hope you understand.

Yes, I do. I don't want you to compromise any competitive advantage or anything like that. In terms of the -- maybe I'm reading too much into this, but in the past you'd always given us two sets of acreage numbers for the Permian -- one kind of a total number, and then another one where a subset of that where you felt like the horizons you're chasing now were really prospective. In this release -- and, again, today you said 40,000. I think you're saying now that you feel like all of that is really prospective for these horizons. Has something changed there, or am I reading too much into that?

I can answer that, Mike. This is David, how are you? All it really reflects, Mike, is that we had some acreage in the Permian that we, at the first part of the year, didn't consider particularly prospective. And in putting a whole Permian number in there, we didn't want to mislead you or others that we consider that to be prospective, and that's why we broke those out. The fact is that that lease, that area has essentially expired and drilled, as we said it would and our previous disclosures, in the K's, and all. So it just isn't as impactful anymore. So now we think everything we've got looks pretty good.

That piece that expired was really a gas-prone area, and everything else now is oil- and liquids-rich.

Great, okay. And, again, I don't if you can answer this one, don't want to compromise any competitive situation here. But the 1250 net acres that you picked up in the Eagle Ford, can you say where those were located?

It's in the [Henninger].

It's in the Eastern part of our acreage position, Mike, near where our [Henig] lease is. If you look at our maps, it's near where that lease was.

Got it, okay. And then just a last one. I think one of those new rigs you brought in was a new-built walking rig, correct me if I'm wrong. But I'm just wondering how that is drilling in drill times compared to your previous wells.

Mike, this is Matt, and I'd be glad to answer that question. We did contract the rig, put a walking package on it; and just to cut to the chase, it's been very successful in this first package that we've drilled. We drilled four wells on the Martin ranch, and we had estimated that we would save about $300,000 per well with this package, and that's pretty much where we landed on the thing. I will say in credit to the drilling guys the initial rollout of this thing has gone really, really well. So we drilled four on the Martin, and we've got it on another lease where we've got a three-batch well pad that we're drilling on. And the efficiencies -- we're hoping and fully expecting that those efficiencies will improve even beyond what we've seen so far.

Mike, I'll add something to that. This is Ryan. We were expecting the $300,000 savings due to the walking rig over a long term. And right out-of-the-box, we exceeded that number. So we're really impressed with the contributions that the walking rig has made, and I don't think we've actually seen all it can do for us. We hope it does more as the year goes on.

That's good to hear. Thank you, guys, appreciate it.

(Operator Instructions)

All right. The only thing, we want to thank everybody for listening in, for your time and your interest. I do want to make one correction. I did misspeak; I said our analyst day was on December 7, that's actually Pearl Harbor day. Our analyst day is going to be on December 12, and we would invite you all to attend. And they will be broadcasting; you can listen in.

We have one more question on the line, and I'll take it and then we'll end the conference call and appreciate everybody's participation. Go ahead.

Brian (inaudible), Citigroup.

Thanks for squeezing me in here. Brian here for John Nelson. Just a quick one on LOE. We were a bit surprised to see an aggregate a drop in LOE given the sequential volume ramp. Were there any one-time benefits helping the 3Q figure, or should we on a per-BOE basis think about this is the new run rate for the business?

This is Matt, and we were very pleased with LOE numbers for the quarter. We do expect that Eagle Ford -- we've got most of our facilities built, we've got them in place. Some of the higher numbers earlier in the year related to extended flow-back, so we pretty much got that taken care of. Additionally, we worked on our SWD costs, or saltwater disposal costs, so those have come down. As we've discussed before, we're big proponents of artificial lift, in particular gas lift. And so our workover costs have come down as we've moved from rod pump to gas lift. And additionally, there is lots of things in that bucket, and we're working on each and every one of those items -- and chemicals for one thing.

But so, as we move into the Permian Basin, we're going to start to have some of these additional costs also we had in the Eagle Ford, but we're trying to get in front of all those and mitigate that.

But in answer to your question, we're very happy with the number and it's in range where we think we ought to be going forward.

And I'd make a final comment to that question, but I think this goes to the larger question of our overall performance is that that the good numbers we had this time aren't as a result of a single event. It's from a whole lot of little things, and that's why we feel encouraged about the sustainability of this, is that we've had better drilling times, we've had better LOE, we've had -- we've worked hard to get a little better pricing, we've lowered cost, we've added acreage.

There's just a number -- it's a whole process that's getting better rather than being event-driven, is that guys are working together, they're getting better frac's in the Eagle Ford, there's down spacing that's working. So it's just an abundance of things that are coming together, and we're making a lot of progress, we feel, on our Permian work too.

So we think we'll continue to have good news at the next press conference or earnings release going forward. And the year for 2014 looks bright and that we'll have similar type growth. So we appreciate your interest and hopefully having a chance to talk with you all again soon. And with that, I'm going to and. Unless, is there one more?

All right. Thanks, go ahead operator. Jasmine?

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.

Jasmine, I've done that. And I appreciate it, and thanks and hope to see you all.

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