Matador Resources Co (MTDR) 2013 Q2 法說會逐字稿

Good morning, ladies and gentlemen, and welcome to the second-quarter 2013 Matador Resources Company earnings conference call. My name is Clinton and I will be your operator for today. At this time all participants are in a listen-only mode. We will facilitate a question-and-answer session at the end of this conference. (Operator Instructions) As a reminder, this conference is being recorded for replay purposes, and the replay will be available through Friday, August 30, 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 the morning's presentation may be forward-looking statements 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 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 for 10-K, and any subsequent reports on Form 10-Q.

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

Thank you, operator, and good morning to everyone on the line and thank you for participating in our second-quarter 2013 earnings conference call. We appreciate your time and interest very much.

The second quarter of 2013 was a good one for us, and this year is coming together very nicely for us in many ways. First, I want to begin by emphasizing the importance of our Eagle Ford drilling program to these favorable results and to stress our encouragement not only at the continued progress we are experiencing with our frac designs, our drilling times, and our production techniques, but also to mention our encouragement at the early results from downspacing from 80 acres to 40 to 50 acres on a couple of our leases. Our staff and our Board have worked very hard together, studying the Eagle Ford and have done solid work at consistently finding ways to drill better wells in this area for less money.

As a result, the Eagle Ford continues to be the heart of our operations. 80% of our capital is being invested here and virtually all of our present oil production comes from the Eagle Ford. As such, the Eagle Ford will continue to be the primary engine for our growth going forward for the immediate term.

Second, I would like to highlight some of our financial results for the second quarter of 2013. But one thing I just want to call your attention, in our results when we talk about downspacing on those results, those are given in terms of barrels of oil and not BOE. And just so there is no confusion, I wanted to be sure to point that out.

Also, for your record, that is 90% oil or better, and these are fairly short laterals, about 4,000 feet. So I want to put that in better context.

So now turning to the financial highlights for the second quarter as well as for the first half of the year, our average daily production for the second quarter was 44,916 barrels of oil and 34 million cubic feet of gas per day, which was slightly ahead of our expectations. Our total oil production for the quarter was 447,000 barrels of oil and represented a 57% increase from 285,000 barrels of oil produced in the second quarter last year.

This increase was achieved despite the fact we only had one rig operating in the Eagle Ford and an average about 10% to 12% of our production capacity shut in during the quarter. Nevertheless, in the second quarter we experienced a positive step change in our production as it increased from an average of 4,825 barrels of oil per day and 33.8 million cubic feet of gas in the first five months of this year to an average of 6,200 barrels of oil per day and 38.4 million cubic feet of gas during the past two months of June and July 2013.

For the six months ended June 30, 2013, our oil production was 908,000 barrels of oil, a year-over-year increase of 87% from 485,000 barrels of oil produced in the first six months of last year, and a 25% sequential increase from 729,000 barrels of oil produced in the last six months of 2012.

During the quarter just ended at June 30, 2013, we had adjusted EBITDA of $40.8 million, which was a year-over-year increase of 46% from $27.9 million reported for the second quarter of last year, and a slight increase sequentially as compared to $40.7 million for the first quarter of this year. The Company's EBITDA is expected to increase in both the third and fourth quarter, which will be more than what we had in either the first or second quarter in EBITDA results, in accordance with our revised guidance provided on May 8. 2013.

Notably, for the six months ended June 30, 2013, the Company had adjusted EBITDA of $81.4 million, a year-over-year increase of 65% from $49.3 million reported for the first six months ended June 30 of last year, and a sequential increase of 22% from $66.7 million reported for the six months ended December 31, 2012.

Third, it is also a pleasure to announce that we have continued adding to our position in the Delaware Basin of Southeast New Mexico and West Texas, acquiring 30,200 gross and 20,700 net acres between January 1 of this year and today, bringing our total prospective acreage position in Southeast New Mexico and West Texas to approximately 46,000 gross and 28,300 net acres. We see a lot of potential for growth in this area and are excited about our current drilling prospects. We believe both the Wolfcamp and the Bone Spring play in the Delaware Basin will develop into a significant area of operations for us over the next year.

Finally, we feel it is important for us to mention that we have increased our borrowing base under our revolving credit facility to $350 million from $280 million, based on our lenders' review of our proved oil and natural gas reserves at June 30, 2013, which is going to provide Matador with over $100 million in additional liquidity based on our borrowings outstanding of $245 million at June 30, 2013. We very much appreciate the banks' support in this regard.

We have eight banks in our group. All eight are participating in the increase in our revolving credit facility, and this bank group oversubscribed this credit facility by over $200 million. We want to be sure that they know we appreciate it and thank them for that support and interest.

Total proved oil and natural gas reserves increased by 63% from 23.8 million barrels of oil equivalent at December 31, 2012, to 38.9 million barrels of oil equivalent at June 30, 2013, including an 80% increase in proved oil reserves year-over-year from 6.7 million barrels at June 30, 2012, to 12.1 million barrels at June 30, 2013.

With that, I would like to introduce everyone from Matador's senior staff joining me in this call. We have David Lancaster, Chief Operating Officer; Matt Hairford, the head of Operations; David Nicklin, the head of Exploration; Ryan London, the head of our Eagle Ford effort; and Brad Robinson, the head of our Reservoir Engineering and Chief Technology Officer.

Matador, for the record, celebrated its 10th anniversary this past month. The senior staff and I average close to 10 years of working together, and I appreciate very much all their extra work, professionalism, and effort to help Matador grow to this point. I would now like to turn the call over to the operator and we will be pleased to take your questions.

(Operator Instructions) Neal Dingmann, SunTrust.

Morning. Joe, nice quarter. Say, Joe, first question. Just obviously in the Eagle Ford you guys have been highly successful and then I look at -- you certainly now, with the facility, have a great liquidity position. Just wanted your thoughts about considering adding a second rig and increasing activity any time soon in the Eagle Ford, or you will maintain the pace for a while.

Thanks, Neal. Yes, we are returning to two rigs in the Eagle Ford. But I think it is important to note that we are drilling these wells considerably faster, and the rig that is coming back is an advanced rig that is going to help us, we think, drill them a little bit faster.

And I would like to for some detail and color on this turn to our head of drilling, Billy Goodwin. Billy, just give them a little feeling on -- I am impressed with the new features of this rig.

Thank you. As Joe mentioned, we're picking up a 1,500-horsepower rig to help us drill the Eagle Ford wells. This is going to be a walking rig, so we are really excited about that, because we expect that to lower our costs an additional 10% in drilling these wells.

We expect to achieve this through drilling the wells faster by moving the rigs quicker and also improve drilling efficiencies. We will be able to drill the wells without laying down drill pipe and changing out BHA components.

This will allow us to batch drill our surface holes and our production holes. This will save us time and money with equipment, service, and transportation costs, and as we move forward we expect to see continued gains.

Thank you, Billy. Neal, did that answer your question?

Yes, sir, that was great. Then just one follow-up if I could. Joe, obviously now you've got a pretty significant position in that Delaware Basin. So just wondering, given -- I don't want to say it is real spread out, but given the Southeast New Mexico and the West Texas area, wondering for you or one of the guys there on the team, the way that you will go about tackling it.

Will you try to delineate the whole thing? There are certain core areas that you have already identified? I'm just trying to get a handle, Joe, on how you will tackle this area.

Well, Neal, I think it is still a little early to predict exactly how we will develop each of these. We are drilling the first test in each of these main areas. We will evaluate that, and from there we will work out a program. That is what we tend to do.

So by the end of the year, we should have that. We plan to do an Analyst Day in the fall that will provide more detail exactly how we will go about developing our Delaware assets.

That's perfect. Thanks, Joe, for the color.

Ben Wyatt, SCD.

Good morning, guys. Thanks for taking my call or question. Joe, just real quick on the downspacing, wonder if you guys could give us a little color on where you guys will tackle downspacing next?

And really, what is driving that? Is it the rock? What kind of variables made you guys choose the area that you will go after next?

I can take that, Joe. Hi, Ben, this is David Lancaster. I think where we are going to tackle it next is after drilling the wells there in the Karnes County on the Sickenius, we have a property right close by where -- that we call the Danysh Pawelek, or that is the name of the leases; and that is the next place that we play to work on that side of the play.

Then, of course, in La Salle County we will be continuing to work at downspacing on our Martin Ranch property and also our Northcutt property, which is just West of that. We have plans to drill downspaced wells there too. So that will all be happening now over the course of the remainder of the year and into the early part of next year.

And I think the second part of your question with regard to why, I think, or where, what are the features, just really has to do with, I think, our improving understanding of the rock and of how these wells are drained. And also how we believe we are able to frac them a little more densely, and perhaps maybe not achieving quite the length away from the well bore but a lot more concentration around the well bore, which I think is really improving the drainage efficiency around each of these downspaced wells.

So far that seems to be working well for us. So I think we are going to continue to work on that going forward. Ryan, do you want to add anything to that?

No, I think that is well put. I think everything we have done on the reservoir engineering side suggests that this is an appropriate move, to go down to 40-acre spacing. But as is the case with everything, the true testament is always in the production results. And as you might have read, all of our results so far suggests that 40-acre is working.

So our approach has always been that we're going to move into this slowly, and that is what we are doing. But I think you will see more and more of this throughout the rest of this year and into 2014.

Ben, just following on what both of them said, is that we are doing this on a lease-by-lease basis. So we don't want to overpromise. But what we have seen it, on the leases we have done, we have been very encouraged by what Ryan and David reported.

It seems to be you just have to -- this is kind of busting up the rock. And as you do that, the 40- to 50-acres will be an appropriate spacing.

Got you. Thanks for that color, guys. I guess just as a follow-up as well, wonder if you guys could talk just a little bit about maybe with the June/July production being where it is, how much of that would you say is attributable to maybe the new gas lifts, if any. Or is it just strong well performance on just the older way you're doing, with the artificial lift? If you guys could maybe just talk a little bit about that.

Sure, Ben. This is Matt Hairford. We have got -- I think the actual number is 19 wells that we are gas lifting at present, and somewhere around almost 3,000 barrels gross that we are actually lifting from those 19 wells. So the gas lift has really been a great benefit to us, particularly when the wells get close to the end of their flowing period.

But also as we frac offset wells, we found that when we install gas lift in the producing wells next to a newly fracked well that we get the load back a lot faster and get those original producing wells back to the normal production rate a whole lot faster.

Very good. Will -- I'm sorry.

I'm just saying, did that answer your question?

Yes, sir. Joe, I appreciate it. Good quarter. Keep up the good work.

All right. Thank you, Ben. We appreciate you very much.

Irene Haas, Wunderlich Securities.

Hey, guys. It is really great to see some of the gas reserves moving back on the books. So I would like to have some guidance on cost structure. You clearly did have some improvement in G&A, which is related to scope.

And also, how should we look at the tax rate, DD&A? Is it proper to use what we have seen in this quarter and project forward?

My second question has to do with some color on your Ranger and Wolf prospect. When could we expect some results? Because both of those wells are located in very, very hot ZIP Codes. And that is all I have for you today.

Okay. You want me to take it?

David?

Hi, Irene. It is David. How are you? So to answer your first question, with regard to costs and DD&A, clearly as you are aware and have pointed out, the fact that we are able to put some of our Haynesville gas reserves back on the books this time did result in an improvement in our DD&A rates. And I would say, Irene, that going forward as we continue to drill more oil than gas wells in the mix, that we will probably continue to creep up a little bit on the DD&A side from here.

This is probably a good floor kind of number. And then as we add additional oil reserves, that will probably continue to creep back up again.

But so somewhere between where we are now and where we were in the first quarter is probably where we will sort of average for the rest of the year. Did that get your question answered there on that?

Yes. And how about G&A?

You know, G&A, I think we will continue to do well on a -- as our production increases, I think we will continue to have economies of scale. This was a good G&A quarter for us. It may increase a bit from what it is in the next couple of quarters, but I look forward to continue to do well on a per-BOE basis, because we just expect our BOEs to grow.

Right. And tax rate?

Tax rate? Okay. We had no effective tax rate this go around or no deferred tax because, as we mentioned in the release, we maintained a deferred -- or excuse me, a valuation allowance against the use of our net deferred tax assets.

My expectation is if in the next quarter, for example, if there is not an impairment, which I don't expect at this point that there would be, that we would have a sufficient net income to offset the majority of the remaining valuation allowance, which is about $6.7 million. In fact, we will probably use that.

So I would anticipate a small amount of tax in the third quarter. And then if everything goes as expected in the fourth quarter, we would probably return to something more in the 35% range by the fourth quarter.

Great. Thank you.

And then your other question was on the Permian?

(multiple speakers) expect some results from the wells?

Do you want to take that, Brad?

Sure, I would be happy to. We are testing -- this is Brad Robinson. We are, of course, drilling Ranger 33 right now. We hope to have it completed by the end of this month, first part of September, somewhere in there.

We are in the process of testing a zone right now on our Ranger 12 well. We hope to have some results from that, plus there's three or four other zones we're going to test by again the end of the third quarter, first part of the fourth quarter this year. And we will let you know what those results are.

Irene?

Yes; and Wolf?

All right.

Wolf is the next well we are going to drill when we get finished at Ranger 33. And again, should have some results by the end of the third quarter, first part of the fourth quarter.

Right. And Wolf is in an area where Energen and Anadarko have recently announced some success, so we have high hopes for that area, too.

Great. Good luck.

Thanks, Irene.

Scott Hanold, RBC Capital Markets.

Yes, good morning, guys. Good quarter. Thought I would just maybe have one question or two here on the Permian. You guys have done a pretty good job of adding bolt-on acreage it seems like every month here for the last several months.

Is that a trend we should expect to continue to see from you all? When I step back and look at Matador, what is a good acreage position that allows you to have enough inventory, but not too much, where you feel pushed?

Scott, that is a really good question and that is something that we discuss and consider virtually every day. What is the right size on the inventory?

We feel we have been fortunate in New Mexico because we have been able to acquire this acreage fairly steadily for the past year. And the prices we have been paying we felt have been pretty reasonable in that $1,500 to $2,000 range.

So, we haven't set a specific target. Our land group I think has done a very good job of stretching our land dollar out there and putting together some deals. And they have been in areas where, as someone said, are the right ZIP Codes. So as those opportunities present themselves we intend to consider to take advantage of them.

But we are not through trying to lease in the Eagle Ford either and we are on the outlook for deals there as well that will fit in with our present acreage position. Van, does that summarize it fairly well?

Joe, I think it does. We continue to see new opportunities every month, and the team is doing a great job at evaluating those quickly. And as you say, when we find the right opportunities we will try to make a run at them.

So, Scott, in with drilling success in one or particular of those test areas, we may accelerate our efforts there. So it depends on a lot of factors, but we are looking at it every day.

But I think that in general, people should anticipate that we are looking to build our acreage in all three of our main areas -- in the Permian, in the Eagle Ford, and in the Haynesville. All three areas.

Okay. Understood. That's great, guys. Thanks.

Ipsit Mohanty, Canaccord Genuity.

Morning, guys. This is Chris Morris filling in for Ipsit today. We were just curious. What are you guys hearing either from yourselves or from other operators in the Pearsall?

David Nicklin, would you (multiple speakers) on to that please.

Yes, sure, Joe. Yes, what we are hearing so far in general is a little bit on the disappointing side. But there was recently a well drilled by BlackBrush at the Indio Tanks field in Frio County, which is just East of our Glasscock Ranch. And that was quite an encouraging result, at least on initial first pass, with some 570 barrels a day, I believe, of 53 API crude together with 3.4 million cubic feet of gas.

And it has quite a good flowing pressure on a fairly small choke. I think a 17/64ths choke. So that is probably the best result we have seen for some time, the most encouraging result. And the other encouraging thing about that is it is somewhat on trend with our Glasscock Ranch acreage.

But apart from that, we think most people have been focusing, certainly in our area, more on the Eagle Ford and the Buda actually. So we don't have too much new news on the Pearsall at this point, other than that.

David, I would add -- is that we are currently shooting or acquiring 3D seismic over our Glasscock to really interest us on the Buda and the Eagle Ford and think that will help in both of those areas. Dan Hughes is having success in the Buda; we are on trend with that, that trend coming up from the Southwest.

And we like our Eagle Ford results in the area Southeast of the Glasscock. So it has kind of been something with three points converging on the Glasscock, and it is very much in our future plans for 2014.

Yes, if I could just add one thing to that. We tend to think that the Austin Chalk production in many areas is a proxy for the best Buda production. We certainly think that is a performance that we can observe in the areas Joe is referring to being drilled by Dan Hughes, Sage and Crimson; and that is about five miles to the Southwest. Even some of those good wells are just two or three miles from the Southwest corner of the Glasscock Ranch area.

The 3D seismic survey we think will be -- the shooting portion of the shooting phase and acquisition phase on our Glasscock Ranch should be finished this month. So we should have -- we are on track to get data to interpret later this fall.

Great. Thank you very much.

Stephen Shepherd, Simmons and Company.

Hey, good morning, guys. In the press release you had mentioned that the early wells in the Delaware are going to cost more than you had anticipated they would cost in development mode. I was just wondering if there was any early guidance you can give us on what these first couple wells might end up costing, and then by how much you all think you might be able to reduce that figure going forward as you move into development mode, presumably.

Okay, Stephen, this is Matt again. Maybe I will address that question, the second part first. Our target goals we have got in the Delaware Basin range from $7 million to $9 million, not dissimilar to what we've got in the Eagle Ford. That being said, as we did in the Eagle Ford, on these first wells we are spending some extra money, investing extra money in drilling and coring pilot holes. Gathering a lot of log data, a lot of rock data that we will use going forward.

So these initial wells will be substantially more than the rest, but we fully anticipate a curve similar to what we had in the Eagle Ford as we start drilling development wells.

Steve, that curve was basically in 2013 you lowered cost basically a third across-the-board, and we are achieving another 20% to 30% this year. So it is hard to put an exact number on it, because at first we just want to be sure we have got the right data. We found that has been useful to get across.

So I would like to emphasize where our practice is not to shortchange the data, because we our long-term players and we don't want to just save a little money in the short run and lose out on the long-term planning. So I never try to put too much into what the initial wells costs. It is really important what you -- information you get out of there that sets up your later drilling program.

No, that makes sense. Thanks for the clarification. I guess my follow-up would be switching over to the Eagle Ford, you had mentioned earlier in your prepared remarks that the addition of that walking rig could potentially lower well costs even further. I was just wanting to check in and see what your current well costs in the Eagle Ford are running at, and what your expectations are moving forward, regarding how you might be able to improve on those as well throughout the year.

Ryan, why don't you take this? Go ahead, Ryan.

Hi, Steve. It's Ryan London. Yes, just an update on our well costs in the Eagle Ford. As you probably know, we have always looked at the Eagle Ford as an Eagle Ford West and Eagle Ford East. Really our East is kind of broke up into two parts.

So if you go all the way to the West our well costs are in the $6 million to $7 million range, probably closer to the $6 million than the $7 million.

In the middle of our acreage, our Eagle Ford, the Western portion of our Eagle Ford East, we have cut costs pretty significantly over there. Earlier, in past, we were drilling those wells between $8 million and $9 million. We've got those down to between $7 million and $8 million, actually little closer to $7 million.

And on our far East side it is always the deeper, the hotter, the third string of casing, and the premium proppant. Those are still in the $9 million to $10 million range.

I think with the walker and all, you're expecting to even improve, aren't you, Ryan?

Absolutely. Billy keeps continuing to drill his wells even faster and faster, and we having a hard time keeping up. But he is going to cut those costs 10% and will probably dip below even those estimates.

But we are going to wait and see exactly how much before we throw out a number. But we think 10% is easily doable.

Okay. Thank you very much.

Mike Scialla, Stifel.

Morning, Joe. Looking at your production guidance, it looks like you are anticipating some decline in the fourth quarter. Is that right?

Is it possible for you to say how many wells you plan to bring on in the third and fourth quarter? Because it looks like you have got some flush production right now. I'm just trying to -- realize you are sticking with your guidance, but trying to adjust for the quarters, if possible.

Mike, it is a very fair question. The decline will be attributable to some timing and some pad drilling, because we are going back to our Martin Ranch and we're going to drill a number of wells in sequence there. And when we do, we have the shut-in and then we will frac them one after another, but hold off bringing them in because the simultaneous fracking to bring in once. It is hard to put a precise number on that, but we do expect some decline due to that timing and the pad drilling.

But as far as your next question that you were asking I am going to let David Lancaster take it. David?

Okay. Hi, Mike. It's David. Yes, I think that in the third quarter, that I would estimate we will put four or five Eagle Ford wells on production. Probably have one toward the end of the quarter, just depends on when we get the frac done. I think we will then probably put six or eight on production, likely in the fourth quarter.

But the fact is given what Joe just said and what you heard about us using the walking rig and all, and drilling four rigs at a chunk or at a time, those are probably going to get on right toward the end of the year. So I don't know that they are going to do a lot to enhance fourth-quarter production, which is why we were projecting it might go down a little bit relative to the third quarter.

Right now we are in a phase where we have got -- we have none of our wells currently shut in, so everything is producing. We will probably in the fourth quarter have another 10%, 15% of the production shut in at various times throughout the quarter. So when we do that, that just causes our production to go down a little bit on a quarter by quarter basis.

But I will say I think that the way we look at it here at Matador is not so much quarter to quarter, but just in bigger time chunks. If you look at things even on a six-months window, you can pretty well see us increasing 20% or 25% each six months, and we think we will be 50% to 65% better this year than we were last year.

So I think everything continues to head in the right direction. It is just that it just is a little lumpy when we have to look at it on such short time windows. And a lot of that is really just the timing of our operations and when we get things done.

But I think we just couldn't be happier with -- if you look at it a little wider time window -- just how things are progressing for us over the last couple years.

And I think operationally, that makes absolute sense to us, to do this pad type drilling, to drill four or five wells at a time, come back in, frac them. We have experience that tells us that not only does that save us money but it is better for the wells.

I appreciate that. That helps. I was just trying to get a sense of how lumpy it was going to be, I guess, over the next six months. But that is very helpful.

Then want to ask on the down-spacing, you are obviously encouraged by the early results. You have seen some results from competitors as well.

Based on all that data you have looked at, is it too early to say or can you say at this point what you think EURs might be relative to wells spaced on wider spacing? Are you looking at do you think some degradation? Or do you think there is any reason to believe that you might get similar EURs to what you are getting on the wider spacing?

This is Brad Robinson. We are real encouraged by the results, no doubt about it. In talking to our reserve auditors and drawing on a lot of their experience, they haven't seen too much degradation in some of their other clients.

They do -- they did encourage us to apply a little bit of a depletion factor to our reserves. So following their lead, we did.

However, at this point we are not sure we're going to need to do that going forward. But at least for the time being we are applying a little bit of a depletion factor; and we will just see how well they hold up. We are encouraged so far.

Yes, this is David. Mike, I would echo what Brad says. I think that is exactly what we have done.

And I have got to tell you I think they all look good. The ones that were on the Sickenius lease in particular have just kind of -- they are blowout good, I think. So I am not sure there is going to be any degradation there at all.

Not really sure there will be at Martin Ranch, but it is a little early. We are still just 30, 60 days into this, so we will probably be able to answer that question a little better the next time we talk.

And I will say one more thing. We put our Generation 5 frac on all these 40-acre and 50-acre tests. And right now with the Generation 5 frac I think the downspaced wells are outperforming even some of the 80-acre and 160-acre wells that were done with prior versions of the frac design.

So I think whatever effects you see, if any, of the downspacing have been more than overcome by just the better frac.

Good point.

Mike, does that answer your question? Then I would like to underscore what David said about the -- you have been in the business. That 90 days just comes up as timing plays a much bigger role.

We like the year-over-year, but at least on a six-months I think gives a more comparable view. But we do the quarter because of course that is expected, too. But I think if you look at it from a longer period, we like that on this downspacing, too; that is why we are reluctant to go out too much, so we have time to accumulate a little more data. But at this point it looks good.

That's very helpful. Thank you.

David Amoss, Howard Weil.

Hey, good morning, guys. In the Delaware Basin it sounds like you have got a couple of vertical pilot holes and a bunch of data out of those. Can you talk about what you have seen so far in terms of zone thickness and reservoir characteristics, and then how you are making that decision, especially on the first well, about how to place that lateral?

David Nicklin, why don't you take this one?

Okay, Joe. David, we have been very pleased with what we found in the wireline logs and both the sidewall cores and hole cores that we have collected. They have been -- the results have been extremely consistent with our regional mapping of the nearby producing wells.

It is obviously too early to say the results of our wells yet because we haven't completed the testing. But I will say that we are -- we have consistent thickness, consistent porosity, permeability. That is how it appears to us at this point.

So, so far so good. We are cautiously optimistic. Does that answer the question, David?

Yes, yes, I appreciate that. Then just as a follow-up, the second well, you are putting the lateral in the second Bone Spring. How did you decide on that target, and what does your well design look like?

I will take that first, and then if Brad wants to come in afterwards, that would be fine. David, the second Bone Spring was selected on the basis of offsetting wells drilled by Concho. The series of wells called Strato wells have penetrated mainly the second Bone Spring. One of those wells is in the third Bone Spring.

We see very comparable results on the wireline logs between our 33 well, the vertical pilot, and those Strato wells. So, we decided -- actually it was a difficult decision, because we do have multiple zones there within the second Bone Spring; but we elected to stay pretty much in the middle of the second Bone Spring, consistent with the better producing Strato wells. Brad, would you like to add to that?

That's right, David. The basis for deciding on the second Bone Springs were based on the Concho wells to the West of us. Their Stratojet well was one of the initial wells out there and continues to be probably the single-best second Bone Spring horizontal in all of Lea County.

To date, that well has accumulated 330,000 barrels of oil, and that is roughly in 21 months. Last check it was still flowing several hundred barrels a day out of the second Bone Spring. So that was and has always been our primary target for that well.

Great. Thank you, and congratulations on a good quarter.

(Operator Instructions) Irene Haas, Wunderlich Securities. (Operator Instructions)

Thank you, ladies and gentlemen. We have no further questions. This ends the Q&A portion of this morning's conference call. I would now like to hand the call over to management for any closing remarks.

No, I don't have any other remarks. I think that the questions have been good. We appreciate the questions and the interest, and I thought they were very good questions.

We appreciate everybody's time and interest, and we look forward to the next time we can report. We are very excited about what is going on, and pleased to have this time with you, and look forward to seeing you soon, we hope.

With that, we will sign off. Thanks.

Thank you, ladies and gentlemen. Thank you for your participation in today's call. This concludes the program. Good day.