Matador Resources' CEO Discusses Q3 2013 Results - Earnings Call Transcript

Nov. 7.13 | About: Matador Resources (MTDR)

Matador Resources Co (NYSE:MTDR)

Q3 2013 Earnings Conference Call

November 7, 2013 10:00 AM ET

Executives

Joseph Wm. Foran – Founder, Chairman, Chief Executive Officer, President and Secretary

David E. Lancaster – Executive Vice President, Chief Operating Officer and Chief Financial Officer

Matthew V. Hairford – Executive Vice President-Operations

Ryan London – Head-Eagle Ford Effort

Bradley M. Robinson – Vice President-Reservoir Engineering and Chief Technology Officer

Analysts

Cory Markling – RBC Capital Markets LLC

Irene O. Haas – Wunderlich Securities, Inc.

Ben Wyatt – Stephens, Inc.

Neal Dingmann – SunTrust Robinson Humphrey

Michael S. Scialla – Stifel, Nicolaus & Co., Inc.

Bryan M. Baritot – Citigroup Global Markets Inc.

Operator

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 the 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 maybe forward-looking and reflect the company’s current expectations or forecast of future events based on the information that is now available.

Actual results and future events 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 will now like to turn the call over to Joe Foran, Chairman, President and CEO. You may proceed.

Joseph Wm. Foran

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 the interest very much. All in all, this year is coming together very nicely for us in many ways, which is reflecting the fact that the third quarter 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 the 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 this 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 results of our drilling activities.

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 and cost savings there, with our frac designs, drilling times and production techniques, but also by our progress with down spacing 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 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 Lea and Eddy Counties, including additional 7,524 net acres acquired in the last 60 days. Not only do we consider this one the best resource place in the country along with the Eagle Ford, but we consider the large majority of our acreage to be prospecting for multiple oil and liquids rich targets, including the 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 reminder 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 base ever achieved in their respective period in Matador’s history. For the third quarter of 2013, our oil and natural gas revenues were $81.9 million, which is a year-over-year increase of more than 100% from the 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 1x this year’s adjusted EBITDA.

In addition, for the third quarter of 2013, we are 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 common 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 million to 2 million barrels to a range of 2.0 million to 2.1 million barrels. Second, a natural gas production guidance increase from a range of 11 billion to 12 billion cubic feet to a range of 12 billion to 13 billion cubic feet for the year. Third, annual oil and gas revenues guidance increased 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 condition and operating practice we follow, such as the use of batch drilling for one of our drilling rigs in the Eagle Ford, and the use the restricted chokes on our new wells.

As a result of these practices and the fact we estimate up to 20% of our production might be shut-in at 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 7, 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 to 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, 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.

Question-and-Answer Session

Operator

Thank you.

Joseph Wm. Foran

Jasmine?

Operator

Yes, thank you. Ladies and gentlemen, due to the time constraint, we ask that you please limit yourself to one question and one follow-up. Again, we ask that you please limit yourself to one question and one follow-up and so all have had a chance to ask a question, after which we would be welcome to additional questions from you. Your first question comes from the line of Cory Markling from RBC Capital Markets. Please go ahead.

Cory Markling – RBC Capital Markets LLC

Hey. Good morning, guys. Congratulations on another good quarter. Starting with the Permian, you expanded your footprint by another 75,000 acres, how much exposure do you envision building here going forward?

Joseph Wm. Foran

Cory, it’s hard to say exactly. We don’t have any target number at this point. It will 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 are doing in the Eagle Ford and the Haynesville.

Cory Markling – RBC Capital Markets LLC

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

Joseph Wm. Foran

We would – Cory, we’re looking for results that will be comparable to the Eagle Ford.

Cory Markling – RBC Capital Markets LLC

All right. Thanks, guys.

Joseph Wm. Foran

Thank you.

Operator

And your next question comes from the line of Irene Haas from Wunderlich. Please proceed.

Irene O. Haas – Wunderlich Securities, Inc.

Yes. Hey, good morning. Really great quarter. My question is really [indiscernible] Delaware Basin for multitude of reasons and you guys being an Eagle Ford operator, can you enlighten us on sort of what kind of technologic – technology transfer we can expect to gain from your experience in Eagle Ford into Delaware Basin. Yesterday, we saw Cimarex drilling a long lateral [indiscernible]. Just to give us a little color as to how good things would be and who much the industry can leapfrog from experiences from other basins?

Joseph Wm. Foran

Irene, thanks and I’m going to – Irene, I’m going to turn the question. For some reason, I’m getting an echo, are you all hearing an echo?

Irene O. Haas – Wunderlich Securities, Inc.

No.

Joseph Wm. Foran

Okay. We’re getting it on this end.

Irene O. Haas – Wunderlich Securities, Inc.

Okay. I’ll mute myself.

Joseph Wm. Foran

Maybe that’s it. Now it’s – now, I’m not hearing it. Thanks for muting. Let me turn the question to David Lancaster, he has been – we’ve been talking about that around here, and I think David is best qualified to answer that.

David E. Lancaster

Yes. Well, hi, Irene. How are you this morning? I’ll start and then may defer to Matt and Ryan as well to add any comments they would have. 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 long laterals and in doing the multistage fracs and our experience with numbers of stages to add and how to better frac these wells is all going to translate. Even just in terms of the operations, the things that we’ve learnt from the Eagle Ford in terms of how to flow the wells back and how to produce them, the use of artificial lift, I think we feel like all those things will translate for us going forward.

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

Ryan London

Yes, Irene, this is Ryan. I’d like to just echo what David said about what we’ve learned in the Eagle Ford and the Haynesville. I think what we’ll probably do from the frac design standpoint, will probably air on the high side beginning there, we’ll probably start off with bigger fracs than I think a lot of the other operators in the Permian Basin on what we’ve learned in the Eagle Ford, just sticking with the fundamentals of simulated rock volume and more profit, tighter spacing trying to take advantage of near wellbore, and then which creates a wellbore pattern that’s more conducive for tighter spacing. So we don’t run it upon later on. Matt?

Matthew V. Hairford

Well, yes, I think those are really good points and as we’ve discussed before, these first wells, we’re going to do like what 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 relating to how we’ve developed the Eagle Ford process and we hope to get up the learning curve pretty quick.

Irene O. Haas – Wunderlich Securities, Inc.

Great. Thank you.

Joseph Wm. Foran

Hold it, Irene. Hope you’ve asked a real good question, Brad, wants to add something here too.

Bradley M. Robinson

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

Irene O. Haas – Wunderlich Securities, Inc.

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

Joseph Wm. Foran

All right. Thanks, Irene.

Operator

And your next question comes from the line of Ben Wyatt from Stephens. Your line is open.

Ben Wyatt – Stephens, Inc.

Hi. Good morning, guys.

Joseph Wm. Foran

Hi, Ben.

Ben Wyatt – Stephens, Inc.

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 see – 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 can just give us a little color on that front?

Joseph Wm. Foran

Ben, it’s a little early, we’ll have more detail at the Analyst Day. We’re just drilling these first three appraisal wells, we’re going to drill our fourth appraisal well in the Indian Draw, Rustler Breaks area, and with those four appraisal well, we’ll add results, our results and the way those areas you’re developing drive us to more in 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 the Analyst Day.

Ben Wyatt – Stephens, Inc.

Very good, and then I just guess on more, pick that more acreage out in the Permian, do you guys still grabbing that kind of in the $1,500 to $2,000 per acre range, and is that sustainable kind of going forward you think?

Joseph Wm. Foran

Ben, this last block that we – I mean, this last group that we bought in the last 60 days of average in that range, I don’t know as the areas get more delineated or clear, the process may go up some, but right now, that’s where they are. The opportunity is in that range and maybe a little bit higher, but it’s still we think at a pretty intriguing price really.

Ben Wyatt – Stephens, Inc.

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

Joseph Wm. Foran

Thanks, Ben.

Operator

And your next question comes from the line of Mike Scialla from Stifel. Your line is open.

Michael S. Scialla – Stifel, Nicolaus & Co., Inc.

Good morning, guys.

Joseph Wm. Foran

Hey, Mike.

David E. Lancaster

Hey, Mike.

Matthew V. Hairford

Good morning.

Michael S. Scialla – Stifel, Nicolaus & Co., Inc.

I wanted to ask you about the pilot test in the Eagle Ford, I wasn’t sure from your release when you said there’s – you are 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 this higher, you are 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?

Joseph Wm. Foran

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.

Ryan London

Hi, Mike. We have seen production interference on both of these pilot 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, it’s a period where all the 80 acre wells in that particular lease. The two pilots that we were mentioning specifically in the release, we did see a little bit of production inference, they’re quite as good as the other 80 acre wells that we frac with generation 5 design early on, but they look like they’re going to 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’re encouraged enough to continue drilling on 40 acres for the rest of 2013 and 2014.

Michael S. Scialla – Stifel, Nicolaus & Co., Inc.

Okay. As a follow-up, Ryan, the ones you mentioned in the release, I think you’d said the two pilots in Karnes were, they had recovered about 35,000 barrels each in three months and the 140-acre pilot in Martin Ranch had done, I believe 36,000 in four months. Just wondering how that compares to the type curves that you are looking out for each of those areas?

Ryan London

Those are right in line with most of the type curves in that 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. Our generation 5 fracs have actually outperformed that baseline curve. but Mike, I said earlier, they’re hanging in there with all the wells that we’ve fraced in the respective leases. You really start to see a departure from that in month four or five and six. but right now, there are acting as expected and we don’t expect to have any – we expect the wells to perform very well.

Matthew V. Hairford

Mike, this is Matt. I’d just like to add to – it is early on in the process for the part of wells, you’re talking about and we’re adding to that dataset. So we’re drilling more of these wells and as they progress and produce, then we’ll have a much better dataset to make that evaluation on.

Michael S. Scialla – Stifel, Nicolaus & Co., Inc.

Very good. Thank you, guys.

Matthew V. Hairford

Thanks, Mike.

Operator

Ladies and gentlemen, we welcome additional questions from you. We ask that you please limit yourself to one question and a follow-up. Again, additional questions are welcome at this time. Your next question comes from Neal Dingmann from SunTrust. Your line is open.

Neal Dingmann – SunTrust Robinson Humphrey

Good morning, gentlemen. Say, Joe, for you or Ryan, one of the guys just wondering back to the Permian side, you obviously have a lot different formation, 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 cost, I mean is that something that you’d be looking at down the line once you start identifying some of these formations?

Ryan London

Neal, that’s certainly possible. We focus on first getting one horizon that is really going to return, rather than trying to say, well, this would be good if we could make two or three work. We wanted to be good on – to be able to stand alone on one horizon. So – but we’re certainly not opposed to – 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, our Head of Operations, to give comment. There is anything you want to comment on that?

Joseph Wm. Foran

Neal, there is no doubt that there is prospectivity, multiple horizons in most of the – well, in all of the areas that we’ve chosen that was 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 calls 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.

Matthew V. Hairford

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

Joseph Wm. Foran

Yeah.

David E. Lancaster

This is David, Neal. I don’t – I wasn’t quite sure if your question was going to stack collaterals at the same wellbore or just more different horizons of the same pad and if it was more of the latter, then I think that certainly, we think that, if our acreage could lend itself to the – possibly to the drilling of different horizons of the same pad, I mean different targets.

Neal Dingmann – SunTrust Robinson Humphrey

That’s exactly what I was going to. Maybe, just a follow-on to that guys a little more info there. As far as on that one, I mean I noticed, I think you drilled one of these on the 43,000 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?

Joseph Wm. Foran

Neal, we’ll drill the laterals as long as we need to, in the Eagle Ford, we drilled them all differently, because that’s the geometry of the leases there, 7,500 feet or more. So – and we have the same thing in the Mexico, we’ll drill them as way, the geometry of the leases since most of those are square sections, I think the – 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’re prepared to drill all differently, so…

Ryan London

Yeah, Neal, we can drill as long as we want – most of the – our desire, maximum desire at the lateral length is probably in the 7,000 to 8,000 foot territory, but the well you are talking about the 4,300 foot lateral, it was constrained by the – just the section township-range-format in New Mexico and there’s local regulations are required them to stay 660 feet from each lease line. so right off with that, we are kind of in that 4,300, 4,500 foot lateral range right now. As time goes on and we can get better fuel rules and possibly drill cross unit laterals. I mean we can expect that to increase. but right now, we’re at the 4,300 foot in New Mexico.

Joseph Wm. Foran

And of course, that is in the Mexico, I mean, on our lease in Texas, it’s differently configured geometrically. and so we would be able to drill longer laterals and 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 see from us in the Eagle Ford is that I think we proud 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 bout.

Neal Dingmann – SunTrust Robinson Humphrey

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

Ryan London

Thanks, Neal.

Operator

Ladies and gentlemen, we welcome additional questions from you. We ask that you please limit yourself to one question and a follow-up. Additional questions are welcome at this time. Your next question comes from Mike Scialla from Stifel. Your line is open.

Michael S. Scialla – Stifel, Nicolaus & Co., Inc.

Yes. Just to add a couple more. On the Permian 40,000 net acres, can you break that down by the areas how much then Wolf and Ranger in particular?

Joseph Wm. Foran

Now I guess you want to give, Mike, we’ll break that down to Wolf and Ranger, we’re not trying to say we’re every saying, yes, because we’re trying to add to 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.

Michael S. Scialla – Stifel, Nicolaus & Co., Inc.

Yes I do. Yes I don’t mean 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 had always given us two sets of acreage numbers for the Permian one, kind of a total number and then another one where subset of that or you felt like the horizons you’re chasing now are really perspective. 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 perspective for these horizons is – has something changed there or I might read too much into that?

David E. Lancaster

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

Michael S. Scialla – Stifel, Nicolaus & Co., Inc.

Yes, yes, that makes sense.

Joseph Wm. Foran

First, the pace that expired was really a gas prone area and everything else now is all and liquids-rich.

Michael S. Scialla – Stifel, Nicolaus & Co., Inc.

Great, okay. And again, I don’t know if you can answer this one, don’t want to compromise any competitive situation here, but the 1,250 net acres that you picked up in the Eagle Ford, can you say where those were located?

David E. Lancaster

Yes, it’s in the eastern part of our acreage position, Mike mere where our – leases if you look at our maps, it’s near where that lease was.

Michael S. Scialla – Stifel, Nicolaus & Co., Inc.

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 just wanted to have that is drilling in drill times, compared to your previous wells?

Matthew V. Hairford

Yes, Mike this is Matt and I’d be glad to answer that question. We did contract a rig for the walking package on and just go to the chase; it’s been very successful in this first package that we drilled. We drilled four wells in 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 credit to the drilling guys, the initial rollout of this thing has gone really, really well. So we drilled four in the Martin and then 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?

Ryan London

Yes, Mike. I’ll add something to that. This is Ryan. We were expecting the $300,000 savings 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 we’re – I don’t we’ve actually seen all it can do for us. we hope it does more as the year goes on.

Michael S. Scialla – Stifel, Nicolaus & Co., Inc.

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

Ryan London

Thank you, Mike.

Joseph Wm. Foran

Thank you, Mike.

Operator

Ladies and gentlemen, we welcome additional questions from you. We ask that you please limit yourself to one question and a follow-up. (Operator Instructions)

Joseph Wm. Foran

All right. The only thing, we want to thank everybody for listening, for your time and your interest. I do want to make one correction, I did made 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 there will be broadcast and you can listen that. We have one more question on the line and I’ll take it and then – in the conference call, I appreciate everybody’s participation. Go ahead.

Operator

Your last question comes from the line of Bryan Baritot from Citigroup. Your line is open.

Bryan M. Baritot – Citigroup Global Markets Inc.

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

Matthew V. Hairford

Bryan, this is Matt, and we’re very pleased with the LOE numbers for the quarter. We do expect that Eagle Ford, we’ve got most of our facilities build and we 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 SWD cost or salt water disposal cost. So those would come down. As we’ve discussed before we’re big proponents of artificial lift, particularly gas lift.

and so our workover cost has come down as we move from our uplift to gas lift, and additionally, there’s lot of things in that bucket and we’re working on each and everyone of those items, chemicals from 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 an Eagle – we’re trying to get in front of all those to mitigate that, but an 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.

Joseph Wm. Foran

And I’d make a final comment to that question. I think this goes to the larger question of our overall performance is that the good numbers that 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 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 fracs in the Eagle Ford, that’s down space and there’s working.

So it’s just an abundant 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 in the year, 2014 looks broad and that we’ll have similar type growth. So we appreciate your interest and hope we having a chance to talk with you all again soon. And with that, I’m going to end unless there is a one more? All right, thanks.

Go ahead operator, Jasmine.

Operator

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.

Joseph Wm. Foran

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

Operator

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

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