Matador Resources Co (MTDR) 2014 Q3 法說會逐字稿

Good morning, ladies and gentlemen. Welcome to the third-quarter 2014 Matador Resources Company earnings conference call. My name is Ben and I will be your operator for today.

(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, 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 comparable financial measures calculated in accordance with GAAP are contained at the end of the Company's earnings release.

As a reminder, certain statements included in this morning's presentation may be forward looking and reflect the Company's current expectations or forecasts of future events based on the information that is now available. Actual results and future events 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. 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, steady progress in all areas. Our total oil equivalent production of approximately 16,100 BOEs per day and 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 shut in 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 respective totals from all of 2013 despite experiencing an 8% -- an 11% decline -- quarter over quarter in oil production.

Oil price.

I mean in oil price, excuse me, thank you David. In early October our average daily oil equivalent production increased to over 20,000 BOEs per day for the first time in Company history and for the month averaged 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 are now pointing investors to the high end of our upwardly revised oil production guidance range of 3.2 million to 3.3 million barrels of oil.

Additionally, we are reaffirming our 2014 guidance metrics as revised upwards 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 may be 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 could 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 would like to introduce the members of the senior staff joining me on this call who have 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 & 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) Irene Haas, Wunderlich Securities.

Good morning, everybody. So very strong quarter for margins in production. My question is, can give us a little color on your cost structure?

It seems like things really kind of jump up quite a bit likely a lot due to start up in Permian. So could we have some guidance perhaps for fourth quarter and onward to 2015? How this all to shape up with a bigger drilling program in Delaware Basin?

Irene, I really appreciate your question. I'm going to say a couple of things and then I'm going to ask David to jump in here too.

First, we are concerned about the cost just like you. We don't want to see them 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 the production are 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 have set an aim for reducing cost this year 10% or 15% and we feel like we are making progress in good areas. Some of the unit production costs were a little higher due to various reasons but we will work on those. And I am just going to ask David to summarize and work Irene through those on a detailed basis.

Okay. Hi, Irene it, is David. Just to follow up on what Joe was saying there, I think that we can maybe to 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 have added some additional staff. Some of the water disposal costs have been a little higher, but we are taking steps to work on all those things.

We currently have a saltwater disposal well that we are getting ready to put in. And we think that that could lower our costs on disposal by as much as $1.25 a barrel, which will be a significant improvement going forward. I would also probably just point out to you the fact that even though we had a little bump in LOE in this quarter that year over year we are actually down 6% on LOE.

So we are actually very pleased with the overall trend in our lease operating expenses and the way that is 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 are at about 878 and we think we will do better than that in the fourth quarter, not only because we feel like our costs will improve but also because on a BOE basis we are going to have 35%/40% growth on a BOE basis in production. And that is 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 have made a big difference in terms of a lot of the progress that we've made this year. 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 $5 per BOE range for the quarter, maybe even a little less than that.

Is that helpful? Did I touch all the points you needed there?

Yes, that's super helpful. So it's really sort of timing issue the way the costs enter your pool and really having production ramping up just really synchronizing the two pieces. So --

Yes, I was just going to say I think that is right. Some of it is just an early costs in the Permian that showed up this quarter.

We had that when we kind of got going in Eagle Ford. But over time, as you recall, we've made a lot of progress in improving those costs and we will see that in the Permian as well as we have more scale and have more activity out there and just get some saltwater disposal wells in and do some things like that, we expect that costs will come down. So I really expect them to be down in his quarter as well.

I am just going to reiterate what David has said there. I think Bill McMann and his group have done a really nice job in getting started out in the Permian.

We have 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 fixed costs will remain the same. So I think relative to where we were in the Eagle Ford at this same time frame two or three years ago we are in really good position.

Okay, great. Thank you.

Scott Hanold, RBC.

Thanks, good morning. So, obviously you guys are taking a pretty diligent approach at looking at 2015 in a potentially 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 accomplish this?

Sure, Scott. One of the things that you would do on this probably cash given the fact that almost all of our Eagle Ford is HBP that 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 still have everything either HBP or capable of being held by a production with just one rig down there right now.

But it may be an overlap. You may have half a year in the Eagle Ford and then move out. We will just have to consider the timing.

But then that would put us -- and with the rig that we are 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 are having in the Permian, you could add a fifth rig in the summer or midyear sometime.

Now, it is important to remember that when you are drilling in the Eagle Ford you are drilling them faster. So you are reaching more wells but you are also completing them needing to pay for the fracs, which cost as much or more than the drilling.

For example, some parts of La Salle County you are 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 are drilling them faster and you're completing them at that deal, is we are running one rig in the Eagle Ford is a lot more expensive than more CapEx is involved in running that same rig in the Permian where the wells take a little longer. And in more often than in the Eagle Ford you have other working interest parties because of forced 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 obviously the emphasis appears to continue to be on the 60,000 that you all have in the Permian and --

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

Yes, David makes a good point. And we haven't finalized numbers but if we used the same number for land in planning next year as we did this year, it is about $50 million, which is very flexible. We intend in land to be more selective on land, so 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 ideas, or things like that.

And the other point to keep in mind about this spending is our guys are working hard on these costs particularly service costs, rental costs, all of those. And they are optimistic that they can achieve a 10% to 15% reduction in service costs out there because we are not going to stop drilling. We're not trying to rubber hose the vendors into it, just relationships.

They 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 that everybody's got to work together and make some adjustments. Matt, did I describe that right?

I think you got it right there, Joe. What we are 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 little tighter but most recently we've had some vendors that have come to us and reduced their pricing.

In addition we've got some of our vendors, some of the bigger ticket items and entered into discussions with them about how we are going to progress through the $80 oil price and how we are going to work together. And we are getting a lot of favorable response there, as well.

And you mentioned the improvements in costs, Joe. The drilling guys are doing a fantastic job in the Eagle Ford driving these days on wells down from 18 to 19 in the early days to 7.5 most recently on some of these wells. And they are doing the same thing in the Permian.

For example, they have taken in one particular whole section in an 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's a five-day reduction right there, which is if you are figuring a $70,000 a day, that is $350,000 right there.

So the costs are moving in the right direction and we don't have any -- on our fracture stimulation -- we don't have any obligations in the Permian yet. We have a pricing agreement in South Texas we are still negotiating in the Permian. So in a good position there as well.

Yes Scott, you can see we are really trying to gang 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 in the service cost, the economies of scale, the addition of saltwater 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. Appreciate that. If I may have a follow-up question here, a 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 that as more of 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 of you all within your hands. Which one of you all go first?

I'll go first, Joe, thank you. This is Brad.

Scott, Second Bone Springs has always been one of our primary targets out there. We have several wells that we have drilled up in our Ranger area that have targeted the Second Bone Springs. We are 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 like the show that we see when we drill through it.

That is we are planning a 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 are very anxious to get some wells drilled and tested in that area too.

Scott, it is 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 are 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 at the kind of resolution we are talking about here. We are 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 have said because the Second Bone Springs has always been one of our prime targets, if not the prime target in the Northern Delaware Basin.

Scott, this is Matt. I just want to, you mentioned the completion, and I just wanted to touch on that a little bit too.

We, as you know, we went out there early on with our Second Bone Springs wells and we pumped the bigger completion jobs, we pumped much larger jobs than most of the -- if not all the offset operators -- and we are seeing really nice results from that. Additionally, we have 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 is all working for us.

Yes, Scott. We've talked about this before on gas lift and how we handle it and what we did in the Eagle Ford when we took that right out to West Texas, to the Delaware Basin and didn't miss a beat. And the guys handled it great and it's not rocket science, gas lift, but we manage it a little bit differently.

And how we manage it we are able to have quite a bit of success and the Second and Third Bone Springs are prime targets for that. So when we run our tubulars after completion after flow back when we run tubing, we run gas lift valves right away and as the well is flowing we start hitting it with some gas, lightening the gradient.

We manage the chokes and we manage our production from the well and it has 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 a lot about of companies coming up to our guys in the field asking how are you guys making this work? We can't make this work. And we have been able to do it and then repeat it out to the Eagle Ford, or out to the Permian from the Eagle Ford.

Okay, really appreciate that. And David, maybe this is a question for David Nicklin for you as well, up in the Twin Lakes area, just to be clear, in the Twin Lakes area specifically, what is the prospectivity for the second -- the Bone Springs package in general in the Twin Lakes area? Could you remind me?

Yes, we are 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 up there.

You are looking at Yeso, Abo, those formations. It changes considerably. The only part of the Twin Lakes area where that is 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 southernmost parts of the Twin Lakes area actually sits right in that fairway.

So we are looking at it there. But Scott I would underscore that as we go further north into Twin Lakes, what we really exploring for there is the Pennsylvanian and Lower Wolfcamp, and that is our primary goal in that area at this point.

Thank you.

(Operator Instructions) Jeff Grampp, Northland Capital Markets.

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

I'll address that. It's a little of both.

In New Mexico we are drilling on a section township range, so our laterals are limited in certain sections to a shorter length. Down in Texas in the Loving County area, it is Texas obviously, so we are able to drill longer laterals.

So in those case is 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 New Mexico. Going forward as we continue developing New Mexico we will 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 bench. Are there any plans to do any other types of tests 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 a couple of the Bone Springs. David, or David, which of you want to elaborate on that?

Yes, I would just say Jeff, that in addition to that X sand that we have been what we call the X sand that we have 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 is a little bit deeper, in some places a little Z sand.

There's a more conventional looking -- I would say it looks a little more like the Haynesville model to me. It's got the bump in resistivity that you see a lot with these shales that we are going to be targeting. Plus some of our partners -- 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 toward the middle of the section in the Wolfcamp B.

So with time we will be looking at others of those intervals and have already started kind of planning out some scenarios if we get the X to work and the B to work and kind of the zone in between at the lower part of the A to work, Third Bone Spring, how we might go about doing wells and actually inspecting the wells kind of in W patterns, or both classic W and upside down W kind of thing. So we are actively looking through that.

I guess just to summarize, the answer to your question is yes. And we think that there are probably still I would say four or five other intervals right there at Wolf that will want to look at with time.

Jeff, if I could just jump in. Just to underscore what David said, the important thing to remember about our Wolf area is that it is highly overpressured.

And when you are dealing with a source rock system that has what I would call conventional sandstone reservoirs interbedded with it, that's very important. Because the overpressure is what is driving the oil out of the source rocks directly into the interbedded reservoir rocks. And that is why those wells are so prolific as they are and why we are 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 are in a Rustler Breaks, for example. We've got plans to test a multitude of zones over in Rustler Breaks that look very prospective and the same thing up there in the Ranger.

While we are 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 is you have a 600-foot zone that is interbedded with these conventional-type zones that is overpressured and is going to be, we think, an excellent target, multiple zones within the Wolfcamp. David Nicklin, do you want to add anything to that?

Yes, Joe. Just to underscore what Joe is saying, we recently drilled the Pickard 2H, which we have released the results of. And while it may not be readily apparent why we are 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, which is just what I described previously, an interbedded mix of porous sandstones, limestones and source rocks.

And because it is overpressured there, it is charging into some of those thinner interbedded sandstones. Now when we drilled the Pickard 2, that was very illustrated by the oil flows that we actually got on the shakers and in the pits while we were drilling it. So they are 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 are still in the early stages; although we have established good production in various areas, there is still a lot to learn.

We still think there's a lot of room for continuing to improve the fracs, particularly in the Second Bone Springs that people have been doing, and cutting the cost and making them even more economical. So in these conference calls to come I think you are going to be continuing to get more information about how we are testing various intervals around our whole position out there in the Delaware.

Definitely excited to see it, guys. I'll hop back in the queue and let someone else get in.

Neal Dingmann, SunTrust.

Quick question. Joe, just your thoughts about -- a good problem to have. When I look at capital allocation next year whether the budget stays the same, or falls, your thoughts -- again, I like the returns certainly we're seeing in the Eagle Ford, I like the returns you are seeing in the Permian. So how do you think about capital allocation between the two plays next year?

Well Neal as you know how we work around here it's a reiterative process where it starts out with our team leaders trying to put together somewhat of a schedule with input from all of us and the idea evolves over time. And so we are still evolving and we still are trying to build in some of the flexibility into these rigs that the new ones who are coming are newbuild rigs designed to our specifications so that you can be drilling one zone and completing in another from the same pad.

So those are little things like that that we are trying to build in and develop this program and allocating the capital between rate of return. And the rate of return is dynamic because we are achieving some of these cost savings and our drill times are going down, which means you adjust how many wells you may get. So at this point that exactly what wells we are doing, or evolving -- but Ryan, do you want to add to that explanation?

Sure. 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 you look at our Eagle Ford program and it is basically cash flow funded and it is a well-oiled machine right now.

We know what the outcomes of the wells are. We have the cost down. But everything is HBP out there.

And you look in our Permian area and you look in our Wolf area and the Wolf is an area we are trying to move into development mode. So we are 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 looking at trying to identify the specific zones and areas that we are going to focus on in the future. And so when we look at wells we are going to be drilling next year, it is kind of a balance between all of those three things. And so as we really focus at the end of the year on what we are going to be doing, that's when we will have a little bit better answer for you.

Neal, did that get your answer?

That was great. And then just one follow-up if I could, just a little separate.

And this seems to continue to be a non-issue very nicely for you all. Just wondered on the Permian differentials you certainly continue to have more than ample takeaway in every regard. Joe, for you or David or the guys when you are forecasting on a go-forward, how are you thinking the difference just sort of maintaining here in line with what we have seen?

Yes, I am asking Gregg Krug who is head of our marketing to give you the detail of the current situation.

Yes, we are looking at a couple of different things. We are looking at as far as the differentials are concerned, if you notice the differentials are definitely narrowing. A few months ago you were looking at $12 differential out of Midland push dif.

Yesterday it was $3.39 and I think the biggest reason for that is because of the available capacity out there as far as takeaway on the different pipelines. And then one thing we're looking at is also we are talking about -- we are actually in the process of connecting our production to these pipelines in order to get it out of the area. So we are not subject to that big differential if it ever does appear again.

All right. Thank you very much.

(Operator Instructions) Brian Corales, Howard Weil.

Good morning, guys. 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 in 2015? Is it kind of getting another area into development?

Yes. Brian, it looks like you have read the playbook. Yes, we think for example, either Ranger or Rustler Breaks or both areas getting much closer to a full development mode like the Wolf and that is one reason why we designed the rigs as we have.

And a do think you want to hear these are designed because Matt and Billy I think did some real good work with Patterson. And Patterson really cooperated to come up with something that would really fit development programs in the Permian. Matt?

We have talked about SIMOPS rigs and I will just take a couple of minutes and maybe describe what that actually does for us. And so SIMOPS, we have nicknamed 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 style rigs. And so you are drilling an Eagle Ford well right next to an Eagle Ford, next to an Eagle Ford well.

So in the Permian we have the opportunity to drill a Second Bone Spring well and a Wolfcamp well off the same pad, so they are stacked laterals, so they will be different wellbores. So these SIMOPS rigs we have worked with Patterson to develop allow us to come in and say we drill the Wolfcamp well first.

We drill it, we skid the rig over, start drilling Bone Spring wells. Since it's in a different interval that is thousands of feet apart, we don't have any concern about the frac interfering with the drilling operation.

So we are able to move the frac fleet and complete the first well while we are drilling the second well. So that's going to work for us in what we've got planned for 2015 and beyond in that we can actually be in a development program in one horizon and exploring in another one, or developing two different horizons at the same time.

That's helpful. And one more question, if I can.

I think in the past you all 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 have seen 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 of the encouragement we have had with the Pickard 2. And so we expect that sometime early in 2015.

In Zavala I think you are referring to the Glasscock rig. 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 that, which has been processed and we are studying and so that ranch, 9,000 acres all rights, all depths is held HBP. So there isn't compulsion, a time compulsion to hurry up and while you are still evaluating the Buda, we just haven't been in a rush to get into it.

But we do feel we fracked the one well that was drilled on that originally with one of a first- or second-generation frac. And we think one of these modern fracs we would have the same kind of success that we are having there just a few miles away in Northwest La Salle County by putting a walking rig, putting it in full development mode now that we've got our drill cost down to $6 million or below, put them in a full development mode.

And I would say just the thing that is holding that back is just there's a lot of good opportunities so there just isn't a rush until we are ready to really have decided between the Buda, the Eagle Ford and to put it into the full development mode. But that is kind of an oil 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 oil bank and the Cotton Valley is a gas bank.

And by the way, Brian, just a 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.

Jeff Grampp, Northland Capital Markets.

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 is kind of the timing that you guys see it?

The timing is, we are 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 the end of the first quarter.

Okay, great. And then last one for me, we have seen a lot of folks recently talking about Upper Eagle Ford results in the Eagle Ford. Just kind of curious what you guys view 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 operators are completing their wells and 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 a nice areas are actually HBP 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 are focusing our efforts on our Lower Eagle Ford and really the Permian play.

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

Yes, it's mostly Eastern acreage in our Hennig lease specifically up in the Eastern Eagle Ford. We have some -- a thicker zone also in our Northwest La Salle area, that really the Upper Eagle Ford, the success of it is really in our opinion driven by the width or the thickness of the Eagle Ford.

Where you have 200- to 300-feet thickness, that's where you're really going to have an opportunity. And so those areas in kind of the northern end of the play, more 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 would just like to thank everybody for their questions and interest. Those were great questions and we appreciate the chance to answer them.

There are just two remaining ports 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've done a very good job. And they brought in these wells in here basically between $7 million and $8 million and they have come online and they are in the $10 million to $12 million, which as a result of that our net production from that has pretty much doubled our daily gas production from the first quarter of this year.

Prices seem to be strengthening a little bit. And we are receiving a better price due to the fact that we are marketing our gas separately. But these wells appear to be in the 10 Bcf or better range and we are -- that has worked out and we will have four net wells on by the end of the year, which will carry over into 2015.

And we will have 2 or 3 net wells out of the 15 or so wells that Chesapeake is going to drill in 2015. And it still only comprises about 10% of our budget.

The second thing I do want just to complement our staff, not just the ones in the room but others that may be listening in, that what a good job they have done in raising our production, getting it online fast so that in October just the timing differences that our production has increased up to 20,000 barrels. And usually I'm going to kid you all out there listening that usually you ask a whole bunch about what is going to happen in this next quarter, so I was waiting for you all to ask me that so I could say we're going to get it up here 30%, 40% in this fourth quarter and end the year real strong and you will see strong year-over-year comparisons.

So I want to put that plug in for us that amidst the decline in oil prices we are still going to increase our revenues, our production, our assets, our PV-10 and our EBITDA. So we are excited by that and we are excited by the continuing technology advances and the drilling efficiencies that are getting our costs down. So with that I just want to give a real tip of the hat to the staff because I think they have done some real exceptional work in the face of some difficult pricing environment.

So thank you, staff, and thank you executive group. And with that I will sign off and we would welcome feedback from all of you.

We know that the press release had a lot of information in it. We approached it with the view that it was a recap of all that we did this past quarter.

But if you all have thoughts on it or want a condensed version, we would sure try to accommodate you on that going forward. So any feedback you all have or questions we are always happy to follow up with you and appreciate your interest and participation.

Thank you very much for joining today's conference. This concludes the presentation.

You may now disconnect. Good day.