Matador Resources Co (MTDR) 2014 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the second-quarter 2014 Matador Resources Company earnings conference call. (Operator Instructions)

As a reminder, this conference is being recorded for replay purposes and the replay will be available on the Company's website through Friday, August 29, 2014, as disclosed 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 compatible 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 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 Mr. Joe Foran, Chairman and CEO. Please proceed.

Thank you, Jackie. Good morning to everyone on the line and thank you for participating in our second-quarter 2014 earnings conference call. We appreciate your time and interest very much.

The highlights are longer than usual because we are reporting both for the quarter and the first six months of the year, both of which returned record results. No one at Matador takes these results for granted. As we all know, all this does not happen without great work by our Board and staff, and I wish to take a moment to thank and congratulate all the various teams within Matador that have contributed to these record results and to our people in the field.

Financially we achieved record results in a number of areas including quarterly oil and gas revenues of $99.1 million, a year-over-year increase of 70% from $58.2 million reported in the second quarter of last year, and a sequential increase of 25% from $78.9 million reported in the first quarter of 2014. Quarterly adjusted EBITDA of $69.5 million, a year-over-year increase of 70% from $40.8 million reported for the second quarter of 2013 and a sequential increase of 23% from $56.3 million reported in the first quarter of 2014.

For the six months ended June 30, 2014, we had oil and gas natural gas revenues of $178 million, oil revenues of $142 million, natural gas revenues of $36 million, and adjusted EBITDA of $125.8 million. In addition, we have provided charts in the news release highlighting various aspects of our growth on a sequential six-month basis with our earnings press release issued yesterday after the market closed. And we hope you will take a look at that graph because it shows you how steady our graph has been over these last three or four years.

To put this quarter in perspective, each of these -- our quarterly metrics is greater than their respective full-year 2011 total.

Operationally, the staff is focused on blocking and tackling and doing the small things in the short term to help build long-term value. The emphasis has been used on using state-of-the-art drilling rigs and techniques to improve drilling times, finding ways to improve the next generation of our hydraulic fracture treatments, and to improve the economics of our properties in the Eagle Ford and South Texas while we expand our exploration and delineation efforts in the Permian Basin in southeastern New Mexico.

These efforts have led to a number of operational records including quarterly average daily oil equivalent production of 15,424 boe per day, consisting of 8,809 barrels of oil per day and 39.7 million cubic feet of gas per day, a year-over-year boe increase of 46%. And a sequential increase of 30% from the first quarter of 2014.

Quarterly oil production of 802,000 barrels, a year-over-year increase of 79% from 447,000 barrels during the second quarter of last year and a sequential increase of 21% as compared to 661,000 barrels of oil during the first quarter of this year. For the six months ended June 30, 2014, adjusted EBITDA of $126 million, a year-over-year increase of 54% from $81.4 million reported for the first six months of last year and a sequential increase of 14% from $110 million reported for the first six months of -- -- ending December 31, 2013.

To put this number in perspective, the adjusted EBITDA results for the first six months of this year is greater than the adjusted EBITDA number for all of 2012, just 18 months ago. These records were achieved despite having as much as 10% to 15% of our total production capacity shut in or restricted at various times during the second quarter, while offsetting wells were drilled and completed and pipeline connections were being made.

Our Permian Basin exploration and delineation efforts continued to be successful as we reported in our update last week, with production coming from five different zones out of our first six wells. In particular, we have had strong initial potential test results from the Norton Schaub 1 well recently. It is a Wolfcamp A test in the Wolf prospect area in Loving County and the Pickard 20-18-34 1H well, a Second Bone Spring test in the northern part of the Ranger prospect area in Lea County, New Mexico, both of which are discussed in greater detail in this earnings release.

Given the strong performance from these three original wells and then the two recent wells we just put online and the early performance of the Pickard State 20-18-34 2H, a horizontal Wolfcamp D test, we have decided to further accelerate our Permian drilling program by adding at least one additional rig in the beginning of 2015. I would also like to highlight the work the land department has done so far this year, increasing the overall position in the Permian Basin by more than a third.

We have added approximately 23,200 gross, 17,200 net acres, primarily in Loving County, Texas, and Lea and Eddy counties, New Mexico, since the first of the year, bringing our total acreage position in the Permian Basin to approximately 94,000 gross, 62,000 net acres. Details on these acreage acquisitions are also included in the earnings release.

Finally, we are pleased to be reaffirming our 2014 guidance metrics as revised upwards on May 6 and May 22, 2014, including estimated capital expenditures of $570 million, estimated natural gas production of 16 billion to 17.5 billion, estimated oil and gas net revenues of $380 million to $400 million, estimated adjusted EBITDA of $270 million to $290 million, and we reaffirmed our guidance to the high end of our oil production range of 2.8 million to 3.1 million (technical difficulty).

With that, I would like to introduce the members of the senior staff joining me on this call who are available for questions, all of whom have contributed greatly to these results and are standing by. They include Matt Hairford, President; David Lancaster, Executive Vice President, Chief Operating Officer, and Chief Financial Officer; David Nicklin, Executive Director of Exploration; Craig Adams, Executive Vice President of Land and Legal; Ryan London, Vice President and General Manager; Brad Robinson, Vice President, Reservoir Engineering and Chief Technology Officer; Billy Goodwin, Vice President of Drilling; Bill McMann, Vice President of Production and Facilities; Van Singleton, Vice President of Land; Gregg Krug, Vice President of Marketing; and Sandra Fendley, Vice President and Chief Accounting Officer, as well as other key numbers of the senior staff who are standing by for your questions.

I would now like to turn the call over to your operator for your questions.

(Operator Instructions) Neal Dingmann, SunTrust.

Morning, gentlemen. Nice quarter. Joe, for you or the team, just wondering with the change now in rigs that you have in the Eagle Ford --? You mentioned I know and you highlighted in your press release some of the early cost savings. Will you continue to see more of those, I guess, with these walking rigs in different completion drilling savings?

I guess my question really is is there additional savings we should forecast in there and are there more rigs that you need to swap out?

On every rig we drill, every well we drill, the rigs are trying to find all the different ways to save money. A lot of this is just a little bit here and a little bit there.

But as that -- there's more room in the Permian than in the Eagle Ford, but we are still not giving up saving money in both places. The Eagle Ford has been around longer, so you've gotten some of the low hanging fruit but there's still ways to do better. I would like to turn it over to Billy Goodwin, our Head of Drilling, for a little further explanation. Billy?

All right, Joe. Yes, we are continuing to see improvements. You know some of the wells in the different areas in the Eagle Ford we are moving the walking rigs into. The previous wells, offset wells were drilled with the conventional-type rigs where we were skidding from well to well.

And, of course, our batch drilling has helped us improve our costs and drilling time and we are still seeing those types of improvements. We also have mechanical engineers and chemical engineers on staff that are working to look at the different tools and all. Coupled with the new technology of the rigs, we are still seeing improvements out there, like I say, improving on times and cost.

Neal, something else that has been impressive to me is that our group with this mechanical engineers, several of them are bit specialists and they have really improved our bit technology and how much time we have saved that we attribute to the bits, for example. In addition, Billy has done a fantastic job continuing to upgrade our rigs.

The oldest rig we have right now is a 2009 rig, and even from there, from 2009 forward, the rig technology has really advanced. Billy has really stayed up there with it and made sure. And today the next rig we receive will be specially built for us so that we can have both a drilling operation and a completion operation going on at the same time on the same location.

Okay. I wanted to just follow up, Joe, if I could just on the Permian; you are certainly making big progress there. I know it seemed like I think you've got at least a couple of the A wells and I think your most recent well talking about going after the Wolfcamp B. So with the two rigs running, will you do some multi-stack laterals or --?

Just wondering how you are going to --? Because you have so much potential with all obviously the different formations, if you could give me an idea of -- I know the last one I mentioned is going to be at Wolfcamp D I think that you have talked about the Pickard State 18 2H. I'm just wondering as you go forward how you will tackle the various formations.

Well, there's a lot of work being put into that right now among our staff teams and are Permian teams, but this year we said at the very beginning we were going to be dedicated to the delineation and the exploration of our acreage in the Permian basin. And we've been doing just that.

We have drilled six wells out there. They are producing from five different formations and they are on all parts of our acreage from Wolf to Rustler Breaks to Ranger and the northern part of that almost touching in our Twin Lakes area. So we've been doing that.

On the Pickard, that was another one of the importance of the Pickard is that is the same location and you've drilled a Second Bone Springs sand and we also drilled down to the Wolfcamp D. The Wolfcamp D is important to remember that it is the organically rich part of the Wolfcamp that is the source rock for much of the Wolfcamp production in the Permian basin and in the Twin Lakes area. So we are just really pleased to have that flowing and showing that that is producible, too.

There's still a lot of work to be done throughout our acreage on determining which formation is good/better/best, and even within a formation like the Wolfcamp D there's a number of stringers. It's reminiscent of the Bakken in that you may have several zones to work with there. So there's a lot of work ahead in determining that.

But let me turn it around to Ryan or Matt or David to add anything. Ryan?

Yes, I will add one thing. There's an important station between how we optimize or move towards efficiency in the Eagle Ford and the Permian. Joe mentioned earlier that the rigs -- and Billy mentioned too that these rigs were purpose built for simultaneous operations.

What we will be able to do in the Permian Basin is from a single location drill multiple different horizons, which means because of how we are attacking this by formation, we can actually frac a well while we are drilling on the same location. Whereas in the Eagle Ford you can't do that simply because of the interference between the drilling and the fracking. So a different kind of efficiency optimization here, but something we are really looking forward to and will be implementing in the coming years.

Okay, great. Thanks, guys.

One last thing, Neal. Dave Nicklin wanted to say something.

Neal, it's David here. I just wanted to mention we have a pretty deliberate process by which we evaluate and rank the different drilling opportunities that present themselves to us. Part of that is also we do a pretty careful evaluation of a lot of what our peer companies are doing as well in and around our acreage.

And of course, a lot of these zones have been penetrated in the past by wells that were drilling to significantly deeper horizons. So the well logs from those wells are very helpful to us in our ranking and evaluation of these zones. So we will be conducting this and continuing with this as the year goes by and as we continue to gather around data.

That was Ryan London, our team leader for the Permian, and David Nicklin, our Head of Exploration.

All right. Thanks, Joe.

Ipsit Mohanty, GMP Securities.

Good morning, everyone. This is Chris filling in for Ipsit today.

Just wanted to ask a little bit about the Martin Ranch 40-acre tests. You mentioned in the release that you might see less interference as you go towards areas where there is untouched reservoir. Just curious when we might see some results for those areas.

All right. Chris, it's probably easier to just turn it directly to Ryan London.

Chris, that's actually starting now. When we started our 40-acre campaign in the Eagle Ford, we wanted to start immediately drilling near the older (technical difficulty) wells, because it's better to drill sooner rather than later near the offsets. And so what we have experienced over the last year or so is exactly that, drilling next to these old wells.

During that time we drilled right offset to our oldest well on the ranch and that one turned out to be a good well. It experienced more interference than the other wells and so we have a good handle on how much interference we are going to experience based on the vintage of the wells.

As we move forward to the Martin Ranch, we will be drilling in virgin rock, so everything there will be 40-acre from the start. And we expect that we will have some of the best 40-acre results moving forward in the Eagle Ford starting now.

Chris, this is Matt. I'll just add to that, too, the really encouraging advantage we've got on those wells are the cost reductions that we've seen since we've been drilling out there. We've gone back into these areas and drilled these infill wells for much cheaper, and with Ryan and his team, with the evolution of the frac design, the wells are actually very economic. So it has ended up being a really good deal for us.

That was Matt Hairford, our President, and what he means it's not cheaper in quality. It's just the costs have now in some of those areas approached $6 million, which is 40% less than what the first well was drilled in that area.

Got you. Thanks, guys.

On the Pickard State well that is, of course, close to the Ranger well, which you saw it came on at a little bit lower rate but it cleaned up very nicely and picked up oil rate especially quite a bit. Is that something you think you might see in the Pickard as well?

Yes, that's a good observation. You really won't know what the Pickard 2 will do until it's put on artificial lift, just like the Ranger 33. And the Ranger 33 was just kind of so-so and that artificial lift made a difference and now you've got a great well.

Some of those wells when they are flowing that much oil, oil -- we are 80% to 90% oil that column is just much heavier than something that is 50%/50% oil and gas. So when you get up to 90%, the column is heavier and it needs artificial lift to help produce and to help tell you what it has.

I think in the case of the Ranger 33, it was like 50 days before it had begun to show what it could do. Since then I think Brad Robinson, our Head of Reservoir Engineering, has raised the EUR on that a couple of times.

But Brad, let me -- I don't want to put words in your mouth. Why don't you --?

I agree, Joe. That was an important point about the cleanup. These normally pressured reservoirs do require a little longer to clean up the frac water, and so in the case of Ranger 33 it took about 50 days, as Joe said, before it reached its peak rate of around 600 barrels a day. And so we expect the Pickard 1 to do the same thing.

The encouraging thing is it's already flowing 400 or 500 barrels a day naturally, so we are really excited to see what it will do on artificial lift.

I think though there you are referring to the number 1. I think the question -- he was also talking about the number 2, right, and I think we think we will see similar kinds of things in the 2.

Yes.

Does that answer your question?

Absolutely. That's a lot, guys.

Thanks, it was a good observation.

Good observation.

Scott Hanold, RBC Capital Markets.

Thanks. Good morning, guys. Just if I could follow-up kind of on that same line of question on that Wolfcamp D test, you all kind of mentioned you had some encouraging results. Can you give us a sense -- I know this Wolfcamp D is all deeper tests -- what you are generally seeing right now in GOR and API of the crude? Do you have an update or at least sort of an assessment of what that could be?

Scott, it's David. Yes, the well is making 85%, 90% oil. GOR is about 1,000, more or less, and it's producing about a 40 to 42 degree API oil.

Okay, okay. Good, thanks. As a follow-up question here on use of another rig in the Permian potentially, even a fourth into 2015, when you look at your acreage position it's a pretty big footprint. When you think about like the need to HBP down to kind of the lowest prospective zone, how much of that needs to go on? Or are you pretty good set from in terms of like lower existing production from lower formations?

Scott, it's a great question and that is one of the things we are working through right now is the rig schedule. It is that calculus of having some well results and knowing where is the real value out there and where your acreage is. It is a high-class problem, but we have drilled all over acreage and we have had success in all the areas.

So you haven't struck out somewhere where you can say we eliminate that acreage. It is a high-class problem.

One of the big advantages of being out here is, unlike in the Eagle Ford where you have Pugh clauses that if you didn't drill down to it and produce it you could lose it. Out here so much of the acreage is in government leases and on the state and federal leases one well holds the whole track and holds all zones throughout the track. So if you drill even a shallow well, you hold the deed on a government lease.

And so you just have much more operator-friendly leases out here than you do in the Eagle Ford or even in the Midland Basin.

Okay, that's exactly what I was getting at. So, okay, you do have a lot of government and federal leases that allow you to kind of dictate your own drilling plan.

Scott, this is David. I would just add to what you Joe said. Look, our teams -- and I certainly will compliment to Ryan London here and Josh Sudderth, who is working with him -- have done a tremendous amount of work already in terms of looking at how we are going to need to approach our acreage over the next several years in order to be sure that we effectively get everything held.

I think they have put together a very fine plan and schedule for us and we are going to begin executing on that in the beginning of 2015. It will change a little bit here and there, but I think we are very much on top of what we are going to need to be doing and how we are going to need to work in order to hold our acreage position out here.

Scott, this is Matt. In answer to your question, yes, we do have a mixed bag out there. We have got -- as Joe would say, we've got a lot of state and federal issues. We do have a lot of acreage that is held by production currently. And then what David was saying, the schedule contemplates all those things as well as continuing our delineation phase.

One other thing, Scott, is our acreage is about a third state, about a third federal, and a third fee. And on the fee leases, very few of them have any depth severance so you've got to drill it up by proration unit, but once you have drilled within that proration unit, you hold all rights above and below. So that's what I mean by being more operator friendly.

Scott, one more thing on top of that. Most every lease we have still has a fresh primary term left on them and many of them also have two-year extensions on leases that we can activate to. So like Matt said, all of that is contemplated and realized in the drill schedule. We have a variety of different ways that we can go as we evolve through the exploration phase in the delineation phase, but there's many iterations to come on the drill schedule.

Scott, internally we are working out schedules right now contemplating going out four or five years if necessary on these leases to make them work, but then you've got to figure in which area adds the most value. And we will concentrate on that too. But this year has been delineation and exploration and next year we will get into the more intense development.

Okay, thank you. Thank you very much.

Irene Haas, Wunderlich Securities.

Good morning, guys. My question has to do with -- you've got four sandboxes and thus far it's almost like every well you've drilled in each of the sandboxes looks promising. So it seems like Dorothy White or Wolf prospect is probably going to go to development, so that's going to eat up one rig.

And so is it logical to expect you to park one rig sort of in the northern part and then another one around Rustler Breaks area? I see that you have got a few more locations staked in the northern part close to Pickard like [Pentel] and Cimarron. Are those double targets, like Second Bone Springs and Wolfcamp D type targets? Can you give us a little color on that?

Thanks, Irene. It's too early to get into where we are going to park rigs other than I think you are right, the Loving area is the furthest along. It is ready for a rig to be put there and kept there.

The other areas we are still evaluating, because on virtually every -- every well we have drilled so far, there's secondary targets that look very promising. In Loving County on the Dorothy White and the Norton Schaub; there's a Bone Springs that looks -- that will probably need to be tested over in Rustler Breaks. We drilled a Wolfcamp B test there, but you also have Bone Springs in that area that is very promising.

Delaware; up there in the Ranger area on the Pickard lease alone you are going to have now a second Bone Springs and a Wolfcamp D. And just about a mile away you're going to have the Jim Rolfe, which is producing from the Third Bone Springs. You know we are -- it's probably too early just where we want to put these rigs and we have also got to work sure.

We intend not to get over our skis and get too far ahead of ourselves, because as we bring on these rigs we also want to make sure we maintain the quality of staff that we currently have and that we don't want to hire just a bunch of bodies. We want to continue to hire these people who are really interested in building the Company and trying to get a little better every day.

David, did I leave anything out there on the plans or --?

No, sir. I think that was actually a good explanation of it all. The only thing I might say is we are -- I think you said that we were producing from the Third Bone Springs. We are just actually drilling that right now. That was just (multiple speakers).

I'm sorry, I didn't mean to --. (multiple speakers)

But just wanted to clear that up, but otherwise I think that was very good.

Irene, we will get that to you when we feel comfortable with it.

And the Pentel and Cimarron permits are those a little also dual target, sort of a Second Bone Springs and Wolfcamp D type wells you're looking for?

Specifically, the Cimarron is a prime Third Bone Springs target. The Pentel it's got any variety of different Bone Springs and Wolfcamp horizons. Those -- we are permitting quite a few areas right now in anticipation of the outcomes of a lot of these wells. But more than anything else, just in preparation for having a full-scale development mode.

Irene, it's David here. We continue to be very pleased and impressed with the way that several different formations in this area. I don't think there's any one of these areas up there where we don't have multiple horizons. It's just a very interesting geological challenge to rank the order that we are going to do these in.

That's right. And going on these sort of multi-bench type ideas and multi-zones, the EOG's Avalon Leonard play kind of expand to your area or it's a little further on south?

Do you want me to take that, Joe? Irene, there is some Avalon production up in the northern part of the Delaware Basin as well. The Ranger area, there are a number of wells there that produced oil, and we have actually produced oil in our original test well from the Ranger 12 from the Avalon zone as well.

We are currently mapping that because along the eastern flank of the basin we get quite a mixed bag of lithologies and the Avalon comes and goes, so it requires careful mapping. And we are doing that right now. But we are obviously very pleased for EOG and the results that they are turning and where they are.

Irene, this is David Lancaster. I might also just mention that we do have a little bit of acreage in and around that area ourselves. We are actually going to be participating in a well with EOG coming up here pretty quickly that is a Third Bone Spring test, and I think we also anticipate that we may also be invited to participate in one or more of their Avalon wells going forward.

So that's a nice opportunity for us, too, to be able to see what's going on a little bit closer in those areas.

That's right, these are shallower wells so presumably a little cheaper. That's great, thank you.

David Daoud (sic), Jefferies.

Good morning, guys. Just wanted to go back to I guess the Eagle Ford completion design. I think in the release you guys had mentioned a generation seven design and the most recent deck just has generation six. So I just wanted to I guess get an idea of what exactly has changed from generation six and generations seven.

Is it more proppant, tighter cluster spacing, tighter stage spacing? All of the above maybe? If you could just add a little bit more color to that.

Gabe, this is Ryan. Our generations seven design we have kept our cluster spacing, our proppant per foot, and our fluid per foot the same as our generation six design. What we have changed is a little bit harder to depict graphically, but what we have done is we have tried to really focus on making it more appropriate for downspaced wells.

And so what we have done is we have changed the size of the perforation holes, the number of holes, we have changed the viscosity of the fluid and the injection rate. Like I said, it's a little harder to show graphically and it may not mean as much to everyone listening, but to a completion engineer it's a pretty dramatic change. So what we're trying to do is ensure a more uniform diversion of fluid into the perforation, so we get a more uniform fracture pattern.

And so we've only been pumping this job for about two months now, so our results -- we don't have any long-term results. Our long-term results are going to be more evident. The results will be more evident of the impact long term considering it is an issue with interference of the other wells. So far the generations sevens have actually turned out very well. We have pumped them on our Danish wells and our Northcutt wells and the IPs on those wells were very good from the get-go.

This is Matt. I will just kind of add to that, what Ryan has said about the cluster, the proppant, and the fluid volumes staying the same. We kind of determined through our testing and looking back at these wells that that's pretty close to what we think is optimal. So we are moving on down the road and we want to proceed.

There will be a generation seven, eight, nine, 10. This thing will continue to evolve, but as we continue to figure out which of these parameters we can optimize, we can start working on the next set.

Got you. Thanks, guys. That's helpful. I just wanted to move over to the Permian. I know you are still obviously in the exploration phase, but could you maybe just comment on what current well costs are and I guess how you see them moving into development mode?

Obviously, I'm sure they will decline from what they are now, but if you could just maybe speak a little bit to that. And even what the current completion design is in the Permian. I know you have been pumping larger jobs from the get-go, so do you think there is room for more improvement on Permian completion designs as well?

This is Matt. Just to start off here, we don't see things in the Permian completely dissimilar to what we see in the Eagle Ford as far as there being a range. We are talking about Second Bone Spring wells and we're talking about Wolfcamp D wells, so the depths vary.

In the Eagle Ford, where we are looking at maybe $6 million, $7 million, up to $10 million to $11 million well costs across there, the Permian is probably $8 million to $9 million to maybe $9 million to $11 million or so on those well costs. As we continue to work in the Permian, those costs will come down from what we are doing now.

We've seen such a drastic improvement in the Eagle Ford from the drilling times going from 18 or 19 days down to eight or nine days, and we're going to see those same type of improvements in the Permian. Additionally, we are pumping larger frac jobs and I will ask Ryan to address that here in just a moment, but we could reduce those well costs. But as with the Eagle Ford, we are going to figure out what is going to make us the most money there so we will be optimizing those completions and knocking days off the drilling times.

Gabe, I will just add a little bit more to what Matt said about the costs. Like you said, we can hack $1 million or $2 million off of our well costs right away if we wanted to cut our completion down in half like a lot of the other Permian operators. But we still firmly believe that the bigger frac jobs have an impact on the well and they are going to more than pay for themselves and so our designs in the Permian across the board are larger.

It's hard for us to characterize exactly what they are because we have so many formations and so many different depths, whereas the Eagle Ford is basically one formation and a variety of depths. So our -- we broke out our branding of our frac design to a generation one Wolfcamp, a generation one Wolf Bone Spring.

Those right now, as you said, they are very much larger than a lot of the other operators and what we are already seeing is that we can expand our perforation clusters a little bit farther apart. This is simply just due to some of the horizons we land in have little bit higher permeability streaks. And so we will be able to trim down on the cost of our frac jobs and we feel like get the same stimulation overall.

Gabe, it is also important while you are on the subject of cost to think about production numbers as a big part, we think, of our success in the Eagle Ford and out here is attributable to the gas lift that we are now installing most of the time as we run the pipe into the ground. And that has made a big difference, we think has really accelerated our recoveries in the Eagle Ford and even into the Permian has really improved the PV-10.

But something that we are proud of and particularly Bill McMann, the Head of our Production and Facilities, is the reduction in LOE. And I would like for Bill to be able to talk about what they've accomplished there. Bill?

You know, Gabe, a couple quarters ago we talked to you about that we would see a reduction as we went across because we had some fixed costs that were set in there and production would start coming to us. And that is exactly what we have seen across the board. All we are seeing is variable cost increases as we go down on the total, but the dollar per boe cost continues to drive down because our fixed costs are set across the board.

We are able to take those advantages that we have had there and the people that we've already trained, which we've got a tremendous staff out in the field. And we are able to take that group and move them, too, out to the Permian and expand out there. So we've already got people that are trained, that understand our gas lift and how we've done it and how we want to do it.

Like Brad mentioned a little bit ago, when he talked about a lot of these normal pressured reservoirs and, like Joe just mentioned, we run right in with tubing, with gas lift valves right after. So we are ready when those wells come on with normal -- the normal pressure. As they start to go down we start hitting them with gas lift, just like similar to what we did in the Eagle Ford.

And we are seeing tremendous results. We've done that on the Ranger 33 and we expect the same things when we do the Pickard. We haven't done those in the Dorothy White and the Norton Schaub. Obviously those are over-pressured areas. But, yes, we just had tremendous success and I think we will see the same thing as we move towards the Permian.

Bill, on that deal is -- and Gabe is that last year the lift cost about this time last year was $11, over $11, approximately $11.12, and then this past quarter it was $8.34. But that wasn't a one-time thing. For the past three quarters they have been in that $8 range.

So as your production ramps up, that becomes an important contributor because that's 100% goes to the bottom line, that's not something you have to share with the royalty owner. So we are pleased on that and hope to keep that on that track.

Thanks, Joe, and thanks, everyone. That's all I had. Nice quarter. Thanks, guys.

Brian Corales, Howard Weil.

Good morning, guys. Most of my questions have been answered, but I think on the last call, Joe, you all talked about drilling a vertical test in Twin Lakes. I was just kind of -- if you can provide a little bit more information, I don't know if you all started drilling that. Is that later in this year?

That will be later. David Lancaster?

Brian, it's David. We had planned to drill a vertical test in Twin Lakes toward the end of the year and we are still looking at that, but, frankly, given the way the schedule has kind of unfolded and some additional acreage that we have taken on this year, it might also be that we push that into the first part of next year. We are kind of working through that right now, but it may slide a few months.

Maybe a follow-on on that. Obviously you all have kind of very quietly grown your acreage position in the Permian very significantly. You don't really have any lease issues there I'm assuming, especially now at Twin Lakes. But how fast -- is adding two rigs next year is that going too fast for you all? When do you think you can really push on the accelerator?

Brian, that's just hard to say. It's a little early to be making that call. We have certainly looked at a case where we add more rigs and we have looked at cases where we have even slowed down from where we are.

A lot of it depends on the staffing, because we just don't want to grow too fast without having the people who embrace the culture, are technically qualified and fit our system. So we have been very fortunate to date. We have added 30 or 40 people this year, but want to be sure that we maintain the quality.

Another big factor is just the timing, because right now it is a high-class class problem. It's close to an abundance of riches in that we have drilled effectively six wells and they are all productive and really better than expected. So we need to sort that out and continue to watch production.

Loving County is the furthest along, so that was an easy one to say let's put a rig down there, but if we wanted to go all out and just drill you would put two down there right now. But you have the staff considerations and you have the delineation and the exploration, which we will resolve to do this year, which takes a little discipline. Because you drill a well like the Ranger or Rustler Breaks and you say let's put another one out there, or the Pickard.

So we are really trying to manage that and to get it right. Also, with these rigs we are getting these specially built rigs and you want to be sure you are getting good crews on them. That takes a little training in and of itself. The field staff -- there are just a lot of calculations and the funding.

We are in a volatile time. You are not exactly sure the direction oil prices are going to take or how much stabilization they have, and you hate to commit to a rig contract unless you are sure you've got -- we feel we have a place for it, but we want to be sure the economics remain attractive to our shareholders.

So give us a few months, Brian. By next quarter we should have a clearer idea of it and you can trust that we are thinking about this every day.

I think it's safe to say it's a fully integrated approach to putting the schedule together. It includes capital, it includes human resources, it includes how fast we're going to drill the wells and it also includes our notion of profitable growth at a measured pace.

We're not going to get out over our skis. We are going to make sure we get it done right. The hiring Joe is talking about is very critical to that and hires we have made this year have been good hires and we are going to continue to hire good people. We are not about filling boxes; we are going to find the best people to continue our success.

Good. Thanks, guys.

Brian, did that answer your question? I would just like to make -- I presume it did. But if not, get back in the queue and we will be happy to give more detail on it.

Ben Wyatt, Stephens.

Good morning, guys. Quick question and I will hop over to the Haynesville. You guys have laid out kind of a plan for 2014 on what you want to do or participate in over there.

Just thinking about how you guys are thinking about 2015, with your marketing agreement and your midstream agreement, the NRIs you have over there, I would imagine you guys would want to participate as much as possible. But just curious if you could give us any color on maybe what Haynesville looks like in 2015.

Ben, it's David Lancaster. Sure, I think we have talked about the fact that Chesapeake is talking about drilling a total of 30 wells on that property -- 30 gross wells, 6.3 net wells to Matador.

It looks like to us that they will probably get 19 or 20 of those wells drilled and on production by the end of the year. So there will still be another 10 or 11 or so that we have to go in the early part of 2015. And if in fact they elect to do all those wells, which we certainly think that they will, it's our intention to participate in those.

So I think you can see this program really kind of kicked off in the second quarter. They are drilling ahead. We are going to see the first wells start to come on now later in the third quarter, but it's going to be primarily the fourth quarter and into the first quarter of next year before we see the majority of these wells getting on and contributing to our production.

I think then you will see that make an impact, obviously, on our 2015 forecasts and numbers. But as of now, we think they will execute this program and it's our intention to participate with them in it.

Ben, I think they are serious. They've got four rigs out there, and while we have only seen the first light of day with the first two wells and don't expect a lot more to come on till the end of the quarter or into the fourth quarter, the first two have come on at 12 million a day, which is about 3.5 million net to us a day at 7,500 pounds. So those are tremendous wells and we are eager for them to get started, but realistically don't think it will happen until the end of September or sometime into October.

Got you, appreciate it. Then maybe just one more, hopping back to the Permian. I believe lateral lengths have been kind of in the 4,000, 4,500 foot lateral so far. Is that kind of the plan as you guys kind of derisk the acreage? And when do you kind of see or envision kind of laterals lengthening out out there in West Texas?

Ben, this is Ryan. Most of the lateral lengths right now have just been basically due to the geometry of the section and township range format in Mexico. In the Texas area where we don't have that restriction, those will be a variety of lengths and we will be pushing them to 6,000 and 7,000 feet regularly.

Going forward, you may see something like in Haynesville where you drill across section lines and you get extended length laterals in the New Mexico section format. But I think for the near future we will probably be kind of in that 5,000 foot territory.

Very good. Keep up the good work, guys. I appreciate it.

John Nelson, Citigroup.

Good morning and congratulations on the quarter. I apologize if any of this was covered in the prepared remarks, but getting back to -- not to beat the Permian activity acceleration with a dead horse, but can you talk -- I guess maybe to come at it another way. Can you talk about the leadtime you think you need to have in order to secure an additional rig and have any of those procurement activities started?

Then I guess just listening to the call it actually sounds like internal staff maybe in your eyes is also a pretty significant bottleneck. So maybe if you could just marry those two and if you think sort of the internal staffing is maybe the driver, more so than the ability to procure a rig?

John, I wouldn't call the staffing a bottleneck. It is a continuous process and we are -- you can always use good people. Usually an engineer, a good engineer can always pay for himself with additional planning. And a geologist the same way.

We've got work for them to do. The work is getting done, but with the kind of growth when you're growing 50% a year as we have been for the past three years and look like it's going to continue for the foreseeable future, you are always in the market needing good people and to add to them. So we've got plenty of room to add; there's not a bottleneck.

We have already added 30 people so far this year and we are delighted by them. A real good example of this is we hired a couple of mechanical engineers that normally we higher petroleum, but these mechanical engineers were bit specialists and they have really added to our knowledge there. One was a chemical engineer, and between them it has really helped vet several issues like bit design, the mud systems, and have really added to the toolbox.

So that has been great and there has been just good work all around. So I don't call it a bottleneck, but it is something that you consider.

As far as procuring the rigs go, Billy -- we have developed a great relationship with Patterson. Patterson has done us a very good job and they have been very proactive with Billy in asking us what do we think our rig needs are going to be and have worked with us. In particular, the next rig we get, and maybe the one after that if we really desire, are specialty built for our purposes so we can be both drilling and completing on the same location.

Now with that second -- those two rigs like that, we have the option either to keep it and add or drop one of our older rigs. Now when we talk about older rigs, we are only talking about going back to 2009, so it is a fairly new rig. And that is just at our option. We can either keep it or we can let it go and just stay with a more updated fleet.

The same thing, there's thought given to using some of the old mechanical rigs to drill the shallow part of the hole and then bring in the more modern rig to go horizontally. So I think there are just really good staff work among the teams vetting these issues and trying to work them through.

I think they are handling the growth really, really well and I think things look good. The procurement doesn't seem to be a difficulty and the same thing with the guys in the field. We are trying to continuously upgrade the quality there. So it is working as it is supposed to and the challenges are there, but they are very straightforward ones.

Joe, you hit on it there. We have a very good relationship with Patterson. It's a very open dialogue to the point where they call Billy and say, hey, we are building these number of rigs, these are the schedule, these are when these rigs are going to be available. If you guys are interested in one, let us know, we will put your name on it.

Further to that, once we get to the point where we know we want to build one of these simultaneous operations rigs, we go down there. We go to their yard, we help them design. We get input from them. Obviously, they are working with other operators.

It's just a very healthy open relationship with them. So as far as procuring the rigs, I think we are in a good spot there.

Matt, is that schedule about six to nine months out now or sort of --?

In that time range, John. There's a lot of demand for newbuilds, but to Joe's point about our oldest rig being six years old, it's not like we are out there with antiquated equipment doing what we are doing right now.

But there is a wait list and, like I said, they are calling us weekly and saying, hey, here's where we are at in the schedule. We may have someone dropout; are you guys interested in that? So we've got a lot of optionality there.

That's really helpful. Then I guess just maybe also coming at the other end, I imagine as the rig dedicated to the Wolf area goes to the development mode you will sort of realize synergies and sort of days to drill. Maybe just on the two rigs that you have running now, any thoughts on what the number of gross wells they could sort of put on in 2015 just from those two? Sort of big range, any thoughts?

John, I think you hit on a very important point there. In fact, in our Loving County acreage from the first well to the third well they have knocked 20 days off the drill times, and they are going to continue to get better.

We are using managed pressure drilling down in that area, which is saving time, saving money, getting those wells drilled faster. We have started using rotary steerable in the curve, which is taking it from several days to less than a day. So those improvements will continue.

Where we will ultimately get, I can't tell you. It is going to be the eight-day wells we are drilling in the Eagle Ford? No, we're not going to do that, but we are going to significantly cut those drill times down.

Fair enough. Then just my last question. I think the release talked about a Howard County well coming before year-end. Just any more color on that timing? Do you expect the completion to actually happen in 2014 or is it just the SPUD? Then also what formation do you guys expect to target?

John, this is Ryan. Our Howard County well we are going to be targeting the Wolfcamp B and we do expect to have that well on before the end of the year. Probably about a month and a half before the end of the year we will have probably the frac completed and start our flowback.

Great, perfect. Congrats on the quarter, guys.

David Amoss, IBERIA Capital.

Good morning, guys. My question -- so you guys have obviously been very leading-edge when it comes to evolving your completion, especially in the Eagle Ford. And now you are starting to hear a lot of your competitors talk about increasing their sand loading, one in particular talking about doubling it relatively overnight.

I guess the two-part question is A) are you seeing any tightness in the proppant market specifically that has you concerned, and then B) what can you do to get ahead of that as a lot of your competitors start to kind of copy your completion recipe?

I'm going to turn it over to Ryan in just a second, but basically the only tightness in service we have really encountered is the sand. It's one of the reasons why we have had a close relationship with Schlumberger and the other large frac companies to help in that regard, which has alleviated it. But our experience is the laws of supply and demand work and where there's tightness today there will be an abundance in the very near future as people work to meet that demand.

So I think that is where a little tightness is and where you have tightness it requires a little more planning. With that, let me turn it over to Ryan for more detail.

David, the sand problem -- and it's basically manifested in the Eagle Ford just due to a shortage of sand, but also a shortage of truck drivers. Sometimes it is perceived as it is sand. It's not always.

I think a lot of the bigger companies have done a good job of securing good sand supplies. They have been a little bit behind on securing enough truck drivers to haul that sand around. We probably have the same issue out in the Permian Basin, and like you said, a lot of other people are amping up on their frac designs.

So it is something that we are paying attention to and it's something that, as Joe said, our relationship with Schlumberger certainly helps us there. As we cultivate our relationship with Schlumberger in the Permian basin, we feel like that that's going to help us out. We are going to have a different challenge next month and next year that we are going to have to tackle, and so it is an ever-evolving process of trying to get better and work with Schlumberger and evolve the frac designs.

Okay, that's great color. Thank you very much.

Jeff Grampp, Northland Capital Markets.

Good morning, guys. Thanks for squeezing me in. Just a question, and I know you guys are working hard to get this out and everyone is excited to get it, but in the Permian location count, obviously nothing in the press release here. What is kind of the timing on when we could get kind of an updated location count given all the progress you guys have made out there?

Jeff, that's a difficult one because just sorting out -- if we put out a number we want to be sure we don't have to ever backtrack from that number. The date that I would point to most on your best deal is we will probably have an analyst day in the middle of January this year and certainly would have something updated by then. Earlier than that it would be hard to say.

Again, it gets back to that high-class problem is you drill a location and virtually, I think all, of the locations we have drilled have secondary zones or even a third zone that looked almost as good as the zone that we are in. So we are right now -- we are only putting one location, one well at each location even though there may be two or three zones that could go there.

We are not over that hurdle yet, because we are still in that delineation and expiration phase, but it is a bucketful. I can tell you, because you look at the different zones we have drilled across that acreage and realize in each case there's a second one. And the Pickard is the first one where we tried two horizontals from the same pad.

So it's quite exciting for us. Because the leases are so friendly that you don't have to worry about depth severance for the most part and you don't have to worry about Pugh clauses for the most part, you are able to fashion a drilling plan that gives you a lot of flexibility. So that is one of our top priorities is putting priority on our acreage and saying this is prime country. And then second concentrating our acreage, putting it together in nice blocks if we can, and then continuing to delineate and explore these various horizons.

Working on that and the earliest I would care to say that an update would be in January at our analyst day. Prior to that maybe we can get a little better handle on it, but we need a little -- still a little more time. David, what --?

No, sir, I would have answered it the exact same way. I know that we will have an update by then and if we feel confident in putting out something incremental in between, we will consider that.

But, like Joe said, I think we are excited to be continuing testing all these various horizons and benches. Even though we've gotten -- we are working on our fifth one now and I know we've got a couple more scheduled before the end of the year. So I think, Jeff, we will just be able to have a much better idea on all of that and have a much better number to share once we get through this program of exploration and delineation that we have been sort of methodically going through this year.

Okay, perfect. Yes, looking forward to it. Other thing; fit one quick one in here.

On EURs in the Permian I think you guys had mentioned that I think on the Ranger well you guys keep bumping that up. And with some longer-term performance now on some of these earlier wells, can you just give us any sort of sense for what you are thinking on some of these earlier wells in terms of EURs, either internally or what these were booked at on your midyear report?

Yes, David, that's really been nice. It's always fun to bump it a little bit. And it's not just the Ranger; it's also the Dorothy White and Rustler Breaks. The three wells that we have any history on. Of course, three different formations, three different areas, and all three have been bumped a couple of times.

But for the numbers I am turning it over to Brad so you will be sure to have it right.

That's right, Joe. We are continuing to be very pleased with the results from those first three wells and we have increased the reserves on all three since the original estimates.

As far as the numbers go, of course it varies from area to area because you have a higher oil content, say, for example, in Ranger than you do in the Dorothy White and the Rustler Breaks area. But we are looking at probably greater than 500 Mboe up in Ranger, which was the area you mentioned with oil content, and the 80%-plus down in the Dorothy White.

We are continuing to increase those reserves. We think we are going to exceed 750 Mboe easily and those wells in that area have about 65% oil. Over in the Rustler Breaks area, we are somewhere in the 500 or better Mboe range. The oil content in that area is around 45% to 50%.

For the Wolfcamp I think it was mentioned earlier today that we expect some Second Bone Springs in that area and that's a very oily zone, probably in the 80% oil concentration area. And those wells, based on some of the offset wells, are going to easily be in the 400 to 500 Mboe range.

You might mention, Brad, in the Rustler Breaks, for example, we elected go down to the Wolfcamp B because that lent itself if successful more to a play concepts. But to say in Bone Springs there's a couple of nearby wells, why don't you name those and make it easier for them to --?

Okay, yes. The Second Bone Springs wells that are near our acreage are one well that Concho drills call their -- they named it the Really Scary well. And I think it's really scary because it's probably better than what anybody expected.

And then [Meuberne] has drilled a couple of Second Bone Springs wells. The [Malaga-30] wells, which are also Second Bone Springs and we are watching those carefully.

Those are fairly new wells, but we have some insight into that because one of our partners over there also owns some interest in those wells. So we are getting some early intel and they are looking really good. Both of those have IPed at over 1,000 barrels of oil per day from the Second Bone Springs.

And you're just talking BO there, not BOE?

That's BO, that's not BOEs, that's right.

The other thing is that the B factor that we are using on this is a very conservative 1.2. Others are using a little more optimistic B factor, but that is why I think it's -- we are standing behind the numbers that Brad said, but it's more likely they will go up than down as we get a little more history.

Okay, great. Thanks for the color, guys. Great wells.

Irene Haas.

Just a follow-up question. I am a little interested in your Wolf prospect. You are surrounded by some pretty classy names. You've got Anadarko, Energen, Shell, and Apache close by.

I am just kind of curious what are they after? Are they going for the Bone Springs or Wolfcamp A or kind of alternatively? It's a lot of activity from some big boys.

That's a good observation. That's kind of the way we felt, too, Irene. Ryan has your response.

Irene, we have been watching Apache in particular. They have been drilling right near our leases and they have put wells with downspacing tests in a variety of different formations, specifically the Second Bone Spring stacked on top of an Upper Wolfcamp and a Middle Wolfcamp. So we've been watching what they are doing.

They have tapped into something that we've actually got on our targets, which is a Wolfcamp test in a different bench as well, and we are hoping to have that test done before the end of the year. But you're exactly right, that territory lends itself to much more than just the Wolfcamp A, the [ex-sandwich] we are after, a variety of different targets.

Thanks.

Thanks, Irene. We really appreciate your knowledge of that area.

Mike Breard, Hodges Capital.

Joe, I was going to ask about Howard County but instead I will ask about the transportation of your oil and gas in the Permian. Are you making progress on contracts for that?

Yes. That's also a part of our midstream effort that Bill McMann is looking into and we are -- out there in the Permian there's a lot of (technical difficulty). There needs to be new infrastructure is coming in. It looks like there's some opportunities in that. So Bill has been looking into that and we are likely to add some gathering system probably first in the Wolf area to help give us more optionality on the gas that we are producing there and perhaps even the oil.

Gregg, on the transportation do you have something to add to that for Mike?

This is Gregg Krug, our Head of Marketing. As far as the transportation -- as Joe alluded to, there's a lot of old infrastructure out there and it lends itself to opportunities for midstream activity. And that is exactly what we are doing.

We are looking at on the gas side as well as the crude side. We think there's a good opportunity for us out there to not only lower our rates, but also as well as have prime or firm service as well. So that is very attractive to us.

That answer your question, Mike?

Yes, thank you.

Appreciate your question. We are thinking about our takeaways in our transportation every day, too. And we have hired some -- a couple of people specifically to dedicate themselves to that transportation, saltwater disposal, all those related midstream type issues, and I think it's starting to come together pretty well.

With that, this ends the Q&A portion of this morning. I would now like to turn the call over to management for any closing remarks.

Well, again, I would like to thank everyone for their interest, questions, and participation. I would like to include in my final remarks, again, we enclosed a graph that shows our progress since the second half of 2011. It has been fairly steady across a six-month period and we see these trends continuing on.

The other thing I'd like to stress is what under the hood, so to speak, that's not visible but is important in adding to this is, as the good staff work, the improvements in our drilling equipment and practices, the steady improvement, little things like LOE, the marketing that Gregg has done, and everything are paying off.

A couple of things I am delighted to have a chance to do -- all of you asking questions know our Chief Operating Officer, David Lancaster. And David Lancaster learned yesterday that he was being named as a distinct graduate of the Texas A&M Petroleum Engineering School. Only 1.5% of the graduates are so honored, so we are pleased to have him receive that, just as we were last year Brad Robinson named Engineer of the Year by the local SPE and one of our geologists received best paper award.

These are great things and they are well deserved. For all the capital and technology that it takes in this business, it still comes down to people and I want to express my appreciation to the staff for all their extra work and late nights and to the Board for their support of getting these people together.

So it's really pretty exciting for us now to have the Permian start to be proved up in a way and for the Eagle Ford still to be working out. Ryan alluded to this. I don't want to lose sight of the good work in the Eagle Ford, the [Lissy] and the Northcut wells with this most recent frac have really exceeded expectations and are really delivering the rates. And that combined with lower cost has made a difference.

So for the Eagle Ford team, I didn't want them to get neglected as old shoes, so to speak, because they are really doing some good this year as we get the Permian delineated. So I just wanted to conclude with that.

Thank you again. We look forward to visiting with you all. And if you have follow-up, we will make ourselves available.

Ladies and gentlemen, that concludes today's conference. Thank you for your participation. You may now disconnect and have a great day.