Good morning, ladies and gentlemen. Welcome to the Third Quarter 2014 Matador Resources Company Earnings Conference Call. My name is Ben, and I’ll 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 the company’s remarks. As a reminder, this conference is being recorded for replay purposes and the replay will be available on the company’s website through Friday, November 28, 2014 as discussed 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’d now like to turn the call over to Mr. Joe Foran, Chairman and CEO. You may proceed.

Thank you, operator and good morning to everyone on the line. And thank you for participating in our third quarter 2014 earnings conference call. We appreciate your time and interest in Matador very much. The third quarter was another solid quarter for the company’s steady progress in all areas. Our total oil equivalent production of approximately 16,100 BOEs per day in total oil production of approximately 839,000 barrels of oil were both record quarterly production numbers and in line with our expectations. All achieved despite having 15% to 20% of our total production capacity, temporarily shoddy at various times during the quarter. For the nine months ended September 30, 2014, our total equivalent production of 4.0 million BOEs, total oil production of 2.3 million barrels, oil and natural gas revenues of $275 million and adjusted EBITDA of $193 million were all record results for any nine month period in the company’s history. Oil production notably, oil production, oil and natural gas revenues and adjusted EBITDA for the first nine months of 2014 have already exceeded their respected totals from all of 2013 despite experiencing an 8% of -- an 11% decline quarter-over-quarter in oil production.

Oil price.

I mean in oil prices, excuse me, thank you David. In early October, our average daily oil equivalent production increased over 20,000 BOEs per day for the first time in company history and for the month average 21,800 BOEs per day. The fourth quarter is on pace to be our best quarter ever and because of the strong production start we’re now pointing investors to the high-end of our appropriately revised oil production guidance range of 3.2 million to 3.3 million barrels of oil. Additionally we’re reaffirming our 2014 guidance metrics as revised efforts on October 14, 2014. Finally, we want to reassure our investors that we are mindful of the recent decline in oil prices and are considering appropriate changes that maybe needed to our operating plans and capital expenditures for 2015. There are two key points we want you all to remember. Should oil prices remain in the mid to low $80 per barrel range, we remain cautious with our spending and anticipate that our capital expenditures to remain flat or even reduced as compared to this year. But we anticipate that by keeping the CapEx flat if we should elect to do that, that the increase in our total oil equivalent production should still approach 50% while continuing to rely on only a modest amount of debt to fund any outspend of our capital. Second, given our strong balance sheet and financial position and operating flexibility, declining oil prices may provide opportunities to continue to grow our assets in our core operating areas, particularly in the Permian Basin at attractive prices. With that, I’d like to introduce the members of the senior staff joining me on this call who has all greatly contributed to these good results and who are standing by for any questions you may have. They are Matt Hairford, President; David Lancaster, Executive Vice President, and Chief Operating Officer and Chief Financial Officer; David Nicklin, Executive Director of Exploration; Craig Adams, Executive Vice President of Land & Legal; Ryan London, Vice President and General Manager; Brad Robinson, Vice President of 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; Mark Golborne Vice President of Exploration; Sandra Fendley, Vice President and Chief Accounting Officer as well as key members of the senior staff who are standing by for your questions. I would now like to turn the call over to the operator for your questions.

Thank you very much. (Operator Instructions). The first question comes from the line of Irene Haas from Wunderlich Securities. Please proceed.

Hey, good morning everybody. So very strong quarter for margins and production. My question is, can you give us a little color on your cost structure? It seems like things really kind of jumped up quite a bit late, a lot due to start up in Permian. So could we have some guidance perhaps for fourth quarter and onward to 2015, how this ought to shape up with a bigger drilling program in Delaware Basin?

Irene, I really appreciate your question. I am going to say a couple of things and then I’m going to ask David to jump in here too. But we are -- first, we’re concerned about the cost just like you. We don’t want to seem go up any. But again, we try to look at these on half year or full year basis on these costs. So some of them again just like a production or related to timing and accruals and things like that. But there is a concentrated effort here all around this table and all the departments to work on cost, because we’ve set an aim for reducing cost this year 10% or 15%. And we feel like we’re making progress in good areas. Some of the unit production costs were a little half due to various reasons, but we’ll work on those. And I’m just going to ask David just kind of summarize and work Irene through those on a detail basis.

Okay. Hi Irene, it’s David. Just to follow-up on what Joe was saying there. I think that we can maybe just start with LOE. I think LOE was a bit higher in the quarter for the reasons that we enumerated in the earnings release, a lot having to do with just early operations out in the Permian. We’ve added some additional staff; some of the water disposal costs, have been a little higher, but we’re taking steps to work on all those things. And we currently have a salt water disposal well that we’re getting ready to put in. And we think that that could lower our cost on disposal by as much as [buck] in the quarter a barrel, which will be a significant improvement going forward. I’d also probably just point out to you the fact that even though we have a little bump in LOE in this quarter, but year-over-year we’re actually down 6% on LOE. So, we’re actually very pleased with the overall trend in our lease operating expenses and the way that’s going. I would probably guide you to actually model something a little bit less than the average for the year, so far I think we’re at about 878 and we think we can -- that we will do better than that in the fourth quarter not only because we feel like our cost will improve, but also because on the BOE basis we’re going to have 35%, 40% growth on a BOE basis in production and that’s going to make a lot of difference. Our Eagle Ford LOE has continued to come down. On the production taxes side, again, I would probably guide you to something that is lower in the fourth quarter likewise on the G&A. As we pointed out, we have added a number of additional staff, which made a big difference in terms of a lot of the progress that we’ve made this year. But, and as we have this growth in the fourth quarter, I think our G&A on a per unit basis will come back again in the fourth quarter to probably something more in the kind of $5 per BOE range for the quarter maybe even little less than that. Is that helpful? Did I touch all the points you needed there?

Yes. No actually that’s super helpful. So, it’s really sort of timing issue, the way the cost enter your pool and really having production ramping up just really synchronizing the two pieces.

Yes, I think… no go ahead I’m sorry. Yes. I was just going to say, I think that’s right. I think some of it is some just some early cost in the Permian that showed up this quarter, we had that when we kind of got going in the Eagle Ford. But overtime, as you recall, we’ve made a lot of progress in improving those costs and we’ll see that in the Permian as well as we had more scale and had more activity out there and just get some salt water disposal wells and do some things like that, we expect the cost will come down. So, I really expect them to be down in this quarter as well.

Irene, this is Matt, I’d just kind of reiterate what David has said there. I think the Bill McMann and his group had done a really nice job in getting started out in the Permian. We drilled a few wells out there and it takes a certain amount of staff and operations to operate those wells. And as we drill and produce subsequent wells, those costs, those fixed costs will remain the same. So, I think relative to where we were in the Eagle Ford at the same timeframe two or three years ago we’re in really good position.

Okay great. Thank you.

Thanks Irene.

Thanks Irene.

Thank you very much for your question. The next question comes from the line of Scott Hanold from RBC. Please proceed.

Thanks. Good morning.

Good morning Scott, how are you?

I’m fine, thanks. So, obviously you guys are taking a pretty diligent approach at looking at 2015 in potentially a lower oil price environment, but it seems like there is still an appetite to want to attack the big position you all have in the Permian. Can you discuss if you were to keep the budget flat to maybe slightly down, how you’ll accomplish this?

Sure Scott. One of things that you would do on this is probably cash given. The fact that almost all of our Eagle Ford is HBP then we would probably move one of the two rigs in the Eagle Ford out to the Permian at some point in 2015. And you would see I’ll have everything either HBP or capable to be inhaled by production with just one rig down there right now. But it may be an overlap; it may have half a year in the Eagle Ford and then move out. We’ll just have to consider the timing. But then that would put us and with the rig that we’re picking up in December four rigs in the Permian and one in the Eagle Ford. And if we continue to have the success that we’re having in the Permian, you could add a fifth rig in the summer or midyear sometime. Now, it’s important to remember that when you’re drilling the Eagle Ford you’re drilling them faster. So, you’re reaching more wells, but you’re also completing them needing to pay for the fracs which cost as much or more than the drilling. For example, some parts of Nassau County, you’re drilling the wells for approximately $2 million and then the fracs are costing upwards of $4 million. And so, you can see that ratio, if you’re drilling them faster and you’re completing them at that deal is when running one rig in the Eagle Ford is lot more expensive than more CapEx is involved in running that same rig in the Permian where the wells take a little longer; and more often than in the Eagle Ford, you have other working interest parties because of forest pooling and the divided nature of the working interest out there. So you need more rigs in the Permian but the CapEx per rig, per year is less than the Eagle Ford. Did I make that as clear as mud or is that?

No. I think you answered my question. And certainly obviously the emphasis appears continue to be on the 60,000 that you all have in the Permian and…

Scott, this is David. Just one -- add one other comment to what Joe was saying too, which is that we also have -- a fair amount of our budget was devoted to land expenditures too in this year. And we have some of that scheduled for next year, if we needed to draw back on that a little bit if we could and that would also help in terms of keeping the CapEx flat or to down.

Yes. David makes a good point. We have -- and we haven’t finalized numbers. But if we use the same number for land and planning next year as we did this year, it’s about $50 million, which is very flexible. We intend in land to be more selective of land side; there is no compulsion to spend all of that money. And you have more chances when prices are down here to be more creative on some drill to earn deals or things like that. And the other point to keep in mind about the spending is our guys are working hard on these costs, particularly service costs, rental costs, all of those. And they’re optimistic that they can achieve 10% to 15% reduction in service cost out there, because we’re not going to stop drilling, we’re not trying to rubber-hose the vendors into it, just relationships. They’d know if oil prices go down, they need to make adjustments. And these things are starting to happen on a voluntary basis because they know if they want to keep the relationship, everybody’s got to work together and make some adjustments. Matt, did I describe that right?

I think you got it right, Joe. What we’re starting to see relative to service company pricing is in the Eagle Ford prior to the drop in oil price, we were seeing some softening out there but in the Permian, it tended to be a bit tighter. But most recently, we’ve had some vendors that have come to us and reduced their pricing; in addition, we’ve gone out to some of our vendors, some of the bigger ticket items and entered into discussions with them about we’re going to progress through the $80 oil price and how we’re going to work together; and we’re getting a lot of favorable response there as well. And you mentioned the improvements in cost, Joe. The drilling guys are doing a fantastic job in the Eagle Ford driving these days on wells down from 18 to 19 in early days to 7.5 most recently on some of these wells. And they’re doing the same thing in the Permian. For example, they’ve taken in one particular hole section on offset well took seven days to drill, the subsequent well with an increased use of better bit technology, better bottom hole assemblies, they were able to reduce that to two days. So there is a five day reduction right there which is if you’re saving $70,000 a day that’s $350,000 right there. The costs are moving in the right direction and we don’t have any -- on our frac stimulation, we don’t have any obligations in the Permian yet. We have a pricing agreement in South Texas; we’re still negotiating in the Permian, so, in a good position there as well.

Okay.

Yes, Scott, you can see we’re really trying to gain tackle this. And in six to nine months, we may see that we can make an adjustment on our CapEx from these significant cost savings from the faster drilling adjustments and the service cost, the economies of scale, the addition of salt water disposal and other type of activities. So, we take it as times like this is a good challenge to try to make ourselves more efficient producers.

Okay. I appreciate that. And if I may have a follow-up question here, couple of larger operators in the Northern Delaware Basin have put out some pretty impressive data on some recent drilling in the Second Bone Springs with some enhanced completion designs. Can you just discuss on your acreage how much prospectivity you all see in the Second Bone Springs and do you plan on looking at it as more of I guess a formation that you could target more near-term given that type of productivity?

Scott absolutely, that’s one of the motivations for moving, increasing the rig count in the Permian and we see the same thing. Brad, or Matt, I see both you all waving your hand, which one of you all go first?

I’ll go first, Joe. Thank you. This is Brad. Scott, Second Bone Springs has been, has always been one of our primary targets out there. We have several wells that we’ve drilled up in a Ranger area there, had targeted a Second Bone Springs. We’re actively evaluating it down in Rustler Breaks and all the way down into Loving County. We see some wells down there that have produced some Second Bone Springs over to the East. We’d like to show that we see when we drill through it that we’re planning formation evaluation program from some of these upper zones. And that is one of our definite targets even down in the Southern part of the Delaware Basin. So, we’re very anxious to get some wells drilled and tested in that area too.

Scott, it’s David Nicklin here. I would just like to add as well that Matador shot 130 square miles of 3D seismic in Northern Delaware Basin this year. We’re just getting the final process data back in about a week’s time. And we shot that specifically with the Second Bone Spring and Third Bone Spring sands in mind. We think that we can resolve channel geometries within those, the kind of resolution we’re talking about here. We’re very pleased with the quality of the 3D data. We have high frequency, good resolution. And I believe that that will be very helpful. And I’d just underscore what Joe and Brad has said, because the Second Bone Springs has always been one of our prime targets, if not the prime target in the Northern Delaware Basin.

Okay.

Scott, this is Matt. I just want to -- you mentioned the completion. And I just wanted to touch on that a little bit too. As you know, we went out there earlier with our Second Bone Spring wells that we pumped the bigger completion jobs, we pumped much larger jobs in most of the office, not all the offset operators and seeing really nice results that. Additionally, we’ve installed our artificial lift systems sooner than later and I’m going to ask Bill McMann if he would to maybe talk just a little bit about how that’s all are working for us.

Yes, Scott. We’ve talked about this before on gas lift and how we handle it, what we did in the Eagle Ford and we took that right over -- right out to the West Texas Delaware Basin and didn’t missed and the guys handled it great. And it’s not rocket science [effort], but we manage it a little bit differently. And how we manage it, we’re able to have quite a bit of success in the Second and Third Bone Springs are prime targets for that. So, when we run our tubular after completion, after flow back, we run tubing, we run gas lifts right away. And as the wells flowing, we start to hit with some gas, lighting in the [gradient], we manage the chokes and we manage our production from the well. And it’s been great. Every well in the Second and Third Bone Springs have responded tremendously to it just like our Eagle Ford wells do. And so, I think that’s how we differentiate ourselves sometimes to other companies, because we have a lot of other companies coming to our guys in the field asking, how you guys are making this work? We can’t make this work? And we’ve been able to do it and then we repeat it out to the Eagle Ford or out to the Permian from the Eagle Ford.

Okay. I really appreciate that. And David, maybe this is a question David Nicklin for you as well. Up in the Twin Lakes there, just to be clear, in the Twin Lakes area specifically, what is the prospect you need for the Bone Springs package in general to spend like there, could you remind me?

Yes. We’re not -- the Twin Lakes area, the Bone Springs sand interval really changes its lithology as you go into the Twin Lakes area. And it is no longer called the Second Bone Spring or the Bone Spring formation out there. You’re looking at the (inaudible) those formations. It changes considerably. The only part of the Twin Lakes area where that’s not exactly correct is at the very southern part where Devon is exploring in the San Simon channel for Second Bone Spring sands. And we do have two of our southern most parts of the Twin Lakes area actually sits right in that fairway. So, we’re looking at there, but Scott I would underscore that as we go further north into Twin Lakes, what we’re really exploring for there is the Pennsylvanian low Wolfcamp. And that’s our primary goal in that area at this point.

Thank you.

Thank you for your question, Scott. (Operator Instructions). The next question comes from the line of Jeff Grampp from Northland Capital Markets. Please proceed.

Good morning, guys. I want to touch on the Permian and I guess kind of specifically I have seen a lot of folks out there drilling some longer laterals and getting some really good results and I know you guys have stayed a little bit relatively shorter. Is that more lease geometry driven or you guys just kind of staying short given you’re relatively early in the play or how should we think about you guys potentially stretching out laterals longer term?

Jeff, this is Matt. I’ll address it. It’s a little of both. In New Mexico we’re drilling on section township range and also our laterals are limited in third section to shorter length. Down in Texas and in the Loving County area we have Texas obviously, so we’re able to drill longer laterals. So, in those cases, we’re drilling more to the geometry of the lease. And so, we may have longer laterals down in Loving County and the Wolf area than we will in Mexico. Going forward, as we continue to develop in New Mexico, we’ll make arrangements where we can, get permits to drill longer laterals.

Okay. And then Matt, you kind of touched on the Wolf area and you guys have had a tremendous amount of success targeting the upper Wolfcamp or the A banks. Are there any plans to do any other types of test in the Wolfcamp or any other prospective zones or how should we think about development playing out in Wolf?

Yes. Jeff, we are planning this year to test the Wolfcamp B as well as the couple of the Bone Springs; David or David which one of you wants to elaborate on that?

Yes, I would just say Jeff that in addition to that [XN] that we’ve been -- what we call the [XN] that we’ve been targeting right at the top of the Wolfcamp. We have several other intervals below that. We’ve got a little [y sand] that we like that’s a little bit deeper in some places, a little bit [v sand], there is more kind of conventional looking, I would say it looks little more like the kind of the Haynesville model to me. It’s got the kind of bump and resistivity that you see a lot with these shales that we’re going to be targeting, plus some of our partners are -- I mean peers out in the area have been testing the Third Bone Spring in that area too, plus as Joe mentioned, there is also we feel like prospectivity down towards the middle of the of the section in the Wolfcamp B. So, with time, we will be looking at others of those intervals and already started kind of planning out some scenarios if we get the extra work and beta work and kind of the zoning between at the lower part of the eta work. Third Bone Spring, how we might go about doing wells and actually spacing the wells kind of in w patterns or both classic w and upside down w kind of thing. So, we’re actively looking through that. I guess just to summarize, the answer to question is yes. And we think that there are probably still, I would say four or five other intervals throughout there at Wolf that we’ll want to look at with time.

Jeff, if I could just jump in, this is David Nicklin here; just want to underscore what David said. The important thing to remember about our Wolf area is that it’s highly overpressured. And when you’re dealing with a source rock system that hasn’t what I would call conventional sandstone reservoirs inter-bedded with it that’s very important, because the overpressure is what is driving the oil out of the source rocks directly into the inter-bedded reservoir rocks. And that’s why those wells are so prolific as they are and why we’re so enthusiastic about other zones, additional zones as David just described.

Jeff, this is going to be a theme throughout this next year to 18 months is we’re in Rustler Breaks for example. We’ve got plans to test the multitude of zones over in Rustler Breaks that look very prospective and the same thing up there in the Ranger. While we’re going to be focused primarily on the Second Bone Springs in that area, we are alert to some of these other zones; and moving back to Twin Lakes that’s one of the things that excites us about Twin Lakes as you have 600 foot zone that’s inter-bedded with these conventional top zones that is overpressured and is going to be we think an excellent target multiple zones within the Wolfcamp. Dave Nicklin, do you want to add anything to that?

Yes, Joe. Just to underscore what Joe is saying, we recently drilled out the Pickard 2H which we’ve released the results of. And while it may not be readily apparent, why we’re so excited about that well, one of the reasons is that the Wolfcamp in that well has turned out to be overpressured and sitting right in the upper part of that is what we call a hybrid reservoir of all, which is just what I described previously, an interbedded mix of porous sandstones, limestones and source rocks. And because it’s overpressured there, it’s charging into some of those thinner interbedded sandstones. Now, when we drilled Pickard H, that was very illustrated by the oil flows that we actually got on the shakers and in the pit, while were drilling it. So they’re very good targets and offer us a lot of future potential I think.

All right. But throughout, I think all the different areas have multitude of zones and we’re still in the early stages. Although we’ve established good production in various areas, there is still a lot to learn; we still think there is a lot room for continuing to improve the fracs, particularly in the second Bone Springs that people been doing and cutting the cost and making them even more economical. So in these conference calls to come, I think you’re going to be continuing to get more information about how we’re testing various intervals around our whole position out there in the Delaware.

Yes. So Joe, that’s what I said to you guys. I’ll hop back in the queue and let someone else get in.

Okay. [Technical Difficulty] Hello?

I’m sorry, I didn’t hear you. This is Neal, SunTrust.

Okay.

A quick question Joe. Just your thoughts about, it’s a good problem to have. And when I look at capital allocation next year whether the budget stays the same or falls, your thoughts? And then again, I’d like the return; certainly we’re seeing in the Eagle Ford, I’d like the return as you’re seeing in the Permian. So, how you think about capital allocation between the two plays next year?

Neal, as you know how we work around here it’s a reiterative process where it starts out our team leaders trying to put together somewhat of a schedule with input from all of us and the idea evolves overtime. And so, we’re still evolving and we still are trying to build in some of the flexibility into these rates that the new ones are coming or move the old rigs designed to our specification so that you can be drilling one zone and completing another from the same pad. So, those are little things like that that we’re trying to build in and develop this program and allocating the capital between rate of return and the rate of return is dynamic, because they were achieving some of these costs savings and our drill times are going down, which means you had jack hammy wells you may get. So, at this point that exactly what wells we’re drilling or evolving, but Ryan, do you want to add to that explanation?

Sure. Can you guys here me okay?

Yes.

Yes. So, I think what Joe is trying to say is exactly right. When the team leads get together, we look at all of our different areas. And if you look at our Eagle Ford program and it’s basically cash flow funded and a well hold machine right now. We know where the outcomes of the wells are, we have the cost down. But everything is HPP out there and you look in our Permian area and you look in our Wolf area and the Wolf is an area we’re trying to move into development modes and we’re trying to get cost down and optimize the fracs out there. So, it’s a little bit in between our Eagle Ford and what we consider our exploration area up in our Ranger area in the Permian. In that area we’re really looking at trying to identify the specific zones in the areas that we’re going to focus on in the future. And so, when we look at what wells we’re going to be drilling next year, it’s kind of a balance between all those three things. And so, as we focus at the end of the year on what we’re going to be drilling that’s when we’ll have a little bit better answer for you.

Neal, does that gives your answer?

That was great. And then one just follow-up if I could and just a little separate, it seems to continue to be non-issue very nicely for you all. Just wondering on the Permian differentials, you certainly continue to have more than ample takeaway in every regard. Joe, for you or David or you guys when you sort of forecast on a go forward, how are you thinking that difference just sort of maintaining it in line with what we’ve seen?

Yes. I’m asking Gregg Krug, who is Head of our Marketing to give you the detail of the current situation.

Yes. We’re looking at a couple of different things. We’re looking at -- as far as the differentials are concerned, if you notice the differentials are definitely narrowing. A few months ago you’re looking at $12 differential at Midland [depth]. Yesterday it was $3.39. So, and I think the biggest reason for that is because of the delay and the capacity out there as far as takeaway on different pipelines. So, and then one thing we’re looking at is also we’re talking about we’re actually in a process of connecting our production to these pipelines in order to get out of the area. So, we’re not subject to that big differential as it never does appear again.

All right, thank you very much.

Thanks Neal.

Thanks for your question Neal. (Operator Instructions). The next question comes from the line of Brian Corales from Howard Weil. Please proceed.

Good morning guys.

Hi Brian.

We’ve had a lot of detail thus far. And it sounds like the Wolf area is getting into development mode. Can you maybe talk about the two other Permian rigs and kind of what you plan to accomplish maybe in 2015; is it kind of getting another area into development?

Yes. Brian, it looks like you’ve read the playbook. Yes. We think the for example either Ranger or Rustler Breaks or both areas are getting to much closer to a full development mode like the Wolf. And that’s one reason why we designed the rigs as we have. And I do think you want to hear how these are designed because Matt and Billy, I think did some real good work with Patterson and Patterson really cooperate to become something that would really fit development programs in the Permian. Matt?

Yes. Brian, we’ve talked about SIMOPS rigs and I’ll just take a couple of minutes to make me describe what that actually does for us. And so, SIMOPS, we nick named it SIMOPS; it stands for simultaneous operations. So, if we think about the Eagle Ford, the big thing we’re doing out there that we talk about is batch drilling with these walking star rigs. And so you’re drilling an Eagle Ford well right next to an Eagle Ford well, next to an Eagle Ford well. So, in the Permian we have the opportunity to say drill a Second Bone Spring well and a Wolfcamp well off the same pad. So, there is stack laterals; there will be different wellbores. So, the SIMOPS rigs, we’ve worked with Patterson to develop, allow us to come in and say we drill the Wolfcamp well first. We drill it, we skipped the rig over, started drilling Bone Spring well. Since it’s in a different interval that’s thousands of feet apart, we don’t have any concern about the frac interfering with the drilling operations. So we’re able to move the frac fleet in and complete the first well, while we’re drilling the second well. And so that’s going to work for us. And while we’ve got plan for 2015 and beyond, I mean we can actually be in a development program and one horizon and exploring in another one or developing two different horizons at the same time.

That’s helpful. And then one more question if I can. I think in the past, you have talked about testing Twin Lakes and potentially even drilling a well back in Zavala in the Eagle Ford just with some encouraging results we’re seeing by other operators. Is that still in the cards for next year?

Yes. In Twin Lakes for example, we are actually moving it up on the schedule some because the encouragement we’ve had with the Pickard 2 and so we expect that sometime early in 2015. In Zavala, I think you are referring to the Glasscock Ranch. We have been also looking in that, if you remember Brian for Buda. There has been some very prolific Buda wells drilled in that area. And we shot 3D seismic over there, which has been processed and we’re studying. And so that ranch, 9,000 acres all, rights, all depths has held HBP. So there isn’t compulsion, the time compulsion to hurry up and why you’re still evaluating the Buda, we just haven’t been investigating into it. But we do feel, we frac the one well that was drilled on that originally with one of first or second generation frac and we think one of these modern fracs, we would have the same kind of to say as that we’re having there just a few miles away in Northwest La Salle County by putting walking rig, put it in full development mode, now that we’ve got our drill cost down to 6 million or below, put them in a development mode. And I’d say just the thing that holds them that back is just there is lot of good opportunities. So, they’re just in the rush until we’re ready to really have decided between the Buda, the Eagle Ford and to put it into the full development mode. But that’s kind of an old bank that we feel we have much like what we have in the Cotton Valley as a gas bank in Northwest Louisiana that’s an old bank and the Cotton Valley is a gas bank.

By the way Brian, this is David here. Just as progress update, we have completed the 3D attribute study; we are running through the results right now. And that will be adding to this.

Thanks guys.

Thank you very much for your question, Brian. The next question comes from the line of Jeff Grampp from Northland Capital Markets. Please proceed sir.

Hey guys. I wanted to circle back on David’s comment about the 3D that you guys shot in the Delaware. Do you guys have kind of a timing or a sense for when you can get that analyzed and then potentially, spud or drill a well based off of that 3D; what’s kind of the timing that you guys see it?

The timing is we’ve actually -- we’re very close to completing the processing. We will be getting the data volumes later this month and we will do the mapping of that and working that through the early part of 2015. It should be impacting our drilling selection by I would say probably into the first quarter.

Okay, great. And then last one for me, seeing a lot of folks recently talking about Upper Eagle Ford results in the Eagle Ford. Just kind of curious what you guys kind of view it as being any prospectivity across your acreage block for Upper Eagle Ford?

Ryan, would you like to take this?

Sure. We’ve been looking at the Upper Eagle Ford for quite some time now and we look at how the other operators are completing their wells specifically Pioneer and Penn Virginia has spent a lot of time in their areas and we have acreage near those areas. So, we have a lot of interest in the Upper Eagle Ford. Most of the land that we have or the leases we have in those areas are actually HPP right now. We already have Lower Eagle Ford wells producing. So, we have no real rush to get out there and drill any Upper Eagle Ford wells. So, we have the luxury of watching how other operators, how successful they are and then at some later time we can come back in. Right now we’re focusing our efforts on our Lower Eagle Ford and really the Permian play.

Okay. And Ryan, can you kind of quantify maybe what you guys view as the acreage that you guys have in around Pioneer and where you’re seeing some successful results?

Yes. It’s mostly our Eastern acreage and our (inaudible) specifically up in Eastern Eagle Ford. We have some thicker zone also in our Northwest area that it really the Upper Eagle Ford the success of it is in our opinion driven by the width of or the thickness of the Eagle Ford. We have 200 to 300 feet thickness that’s where you really can have an opportunity. And so, those areas in kind of the Northern end of the play more of the oil window of the play is where we think it’s going to be successful.

Okay, great. Thanks guys.

Thank you for your questions. This ends the question-and-answer session of this call. I would now like to turn the call back over to management for closing remarks.

Thank you very much. I’d just like to thank everybody for their questions and interest, those are great questions and we appreciate the chance to answer them. There are just two remaining points that we really didn’t get to that I want to touch upon. First is the drilling in the Haynesville in Northwest Louisiana with Chesapeake. I want to give a compliment to Chesapeake. We think they have done a very good job. And they brought in these wells in here basically between 7 million and 8 million and they’ve come online and they’re in the 10 million to 12 million, which as a result of that our net production from that pretty much doubled our daily gas production from the first quarter of this year, processing, the strengthening a little bit. And we are receiving a better price due to that fact that we’re marketing our gas separately, but these wells are appear to be in the 10 Bcf or better range and we’re -- that’s worked out. And we will have four net wells on by the end of the year which we’ll carry over into 2015 and will have two or three net wells out of the 15 or so wells at Chesapeake, going to drill in 2015. And it still only comprises about 10% of our budget. The second thing, I do want to just a compliment our staff, not just ones in the room, but others that maybe listening in, what a good job that they’ve done in raising our production, getting it on line fast, so that in October just the timing difference is that our production has increased up to 20,000 barrels and usually (inaudible) you all after your listening that usually you ask a whole bunch about what’s going to happen…

Thank you very much for joining today’s conference. This concludes the presentation. You may now disconnect. Good day.