Concho Resources Management Discusses Q1 2013 Results - Earnings Call Transcript

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 |  About: Concho Resources Inc. (CXO)
by: SA Transcripts

Concho Resources (NYSE:CXO)

Q1 2013 Earnings Call

May 02, 2013 10:00 am ET

Executives

L. Price Moncrief - Vice President of Capital Markets & Strategy and Director of Corporate Development

Timothy A. Leach - Chairman, Chief Executive Officer, President, Chairman of Concho Equity Holdings Corp and Chief Executive Officer of Concho Equity Holdings Corp

E. Joseph Wright - Chief Operating Officer and Senior Vice President

Analysts

Scott Hanold - RBC Capital Markets, LLC, Research Division

David Yedid - Crédit Suisse AG, Research Division

John Freeman - Raymond James & Associates, Inc., Research Division

Pearce W. Hammond - Simmons & Company International, Research Division

Ryan Todd - Deutsche Bank AG, Research Division

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Brian Singer - Goldman Sachs Group Inc., Research Division

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Ann L. Kohler - Imperial Capital, LLC, Research Division

Irene O. Haas - Wunderlich Securities Inc., Research Division

Operator

Good day, ladies and gentlemen, and welcome to the First Quarter 2013 Concho Resources Inc. Earnings Conference Call. My name is Gwen, and I'll be your operator for today. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes.

I would now like turn the conference over to your host today, Mr. Price Moncrief, Vice President of Capital Markets and Strategy. Please proceed, sir.

L. Price Moncrief

Good morning. Thank you for joining us today for Concho's First Quarter Conference Call. Before we get started, I'd like to direct your attention to the forward-looking statement disclaimer contained in the press release. In summary, it says that statements in last night’s press release and on this conference call that state the company’s or management’s expectations or predictions of the future, are forward-looking statements intended to be covered by the Safe Harbor provisions under the federal securities laws. There are many factors that could cause actual results to differ materially from our expectations, including those we've described in the press release, our 10-K and our other filings with the SEC. In addition, we will reference certain non-GAAP measures, so be sure to see the reconciliations in our earnings release or our most recent investor presentation. Both the earnings release and the investor presentation can be found on our website.

On today's call, I'm joined by Tim Leach, our Chairman and CEO; as well as other members of our management team, who will be available to answer questions. With that, I'd like to turn the call over to Tim.

Timothy A. Leach

Thanks. Good morning. As I hope you saw in our press release last night, we reported our first quarter results. We're pleased with the operational performance of our business, despite the unprecedented widening of the Permian oil basis differential during the quarter. As we discussed on our last call, the Midland-to-Cushing basis differential had a $7.80 per barrel impact on our first quarter realizations. Much of this was related to the impact of Hurricane Sandy and the extended border refinery outage. These challenges seem to be behind us, and new pipeline capacity has already started to move Permian crude to the Gulf Coast. The average Midland-to-Cushing differential for April and May was $0.38 and $0.17 per barrel, respectively. More importantly, our oil realization guidance for the full year remains unchanged at 93% and 95% of NYMEX oil.

Through the first 3 months of the year, we're right on track to deliver on our annual production guidance and our $1.6 billion capital budget. Production for the quarter averaged 86,000 Boes per day, and our growth was driven entirely by our increased crude oil volumes, which were up over 3%. That oil growth was enough to push our overall crude oil mix up to 62%, which goes to show that our drilling efforts in the Delaware Basin are moving the needle. And I'm excited that we have an abundance of drilling opportunities in this world-class asset.

The Delaware Basin is clearly the focus of our operations today, where we've allocated over 50% of our '13 capital budget. Over the last 2 years, both the industry and Concho have made tremendous progress toward understanding the multi-zone potential of this play, and today over 2/3 of all Permian horizontal rigs are in the Delaware, targeting 7 unique play zones. This industry is a high-risk business, and we've always directed our capital and activity to areas with the highest risk-adjusted rate of return.

In 2013, we will drill more than twice as many wells in the Delaware than we did just 2 years ago. Our rig count in the Delaware currently stands at 12 and will likely continue to increase as we move forward through the year. The result of all this activity is that we have clearly established a core asset that now produces over 23,000 Boes a day and has a compounded quarterly growth rate of 25% since the beginning of '11.

It was just last year that we started to fund the acceleration of our horizontal Delaware program with cash flow from our Yeso and Wolfberry assets. Both the Yeso and Wolfberry have plenty of high-quality drilling opportunities remaining, but these assets are largely held by production. While our capital allocation strategy is evident by our rapid growth in the Delaware Basin, our legacy core areas are growing at a much slower rate. So when we talk about reinvesting our cash flow and growing organically in 2013, that company-wide growth will come almost exclusively from the Delaware Basin. This growth from the Delaware is sustainable and can be accelerated. We have over 4,200 drilling opportunities currently identified, all of which are in the Northern Delaware. Those locations are primarily in the Bone Spring sands and Avalon shale, where we have an established record of proven well results. And there is an opportunity to expand our inventory in the Delaware through additional Bone Spring and Avalon, and adding new zones like the Brushy Canyon, the Wolfcamp and the Penn Shale. A few months ago, we provided type curves and drilling economics for our Bone Spring and Avalon drilling inventory, which at current commodity prices provide for a 60% and a 40% rate of return, respectively.

Our oldest wells are 2 years old, so we still have a lot to learn about the ultimate shape of the curves and EURs of our wells. However, we continue to add new wells that are consistently outperforming our models. During the first quarter, we added 18 new horizontal wells in the Delaware Basin with at least 30 days of production data. Those wells averaged over 760 Boes per day, making over 70% oil. 13 of those wells were Bone Spring wells that came in above our Bone Spring-type curve and averaged 80% crude oil. More importantly, the wells we have previously reported are holding up above our type curve, reaffirming our confidence that our wells are capable of delivering on our modeled rates of return.

As we move closer to development mode in areas across the Northern Delaware Basin, the next challenge will likely center around how we process all of this opportunity. Our first stack lateral, the Reposado #2, was completed in the Avalon and the second Bone Spring in Eddy County. It is currently producing from both these zones and performing in line with our expectations. We will continue to test this concept with additional dual laterals later this year. In addition, we're experimenting with longer laterals, and that program is going very well. Our typical lateral length is approximately 1 mile, but we have been testing laterals as long as 2 miles. And we just spudded our first ultra-long lateral in the state line area, which is expected to extend 2.5 miles, representing one of the longest laterals in the Permian Basin.

Let me shift gears and talk about some of the progress in the Southern Delaware Basin and Reeves and Pecos Counties. Before I do that, I'd like to reiterate that our current view of the Southern Delaware Basin is that it's still an early play. We still have not included any potential drilling locations in our inventory account. We have had some early success, which gives us confidence to continue to test the productive extent of the play to the South, as well as additional zones. For strategic reasons, I expect over the near term we'll continue to be tight-lipped on our results in the Southern Delaware. But a measure of our success will be reflected in our rig count progression and drilling activity. We recently moved a third rig into the region and are on track to deploy roughly 20% of our Delaware Basin capital to this play in '13. The team is drilling its 13th horizontal well and currently has 10 horizontals that are either producing or completing. Nine of those wells are in Reeves County, one is in Pecos.

Our current presentation contains a cross-section of 4 wells, that include our Rawhide State in our North Harpoon prospect and moves all the way down to our Boldest Hider [ph] in the South Harpoon prospect in Pecos County. Other than the fact that the Rawhide well made over 100,000 barrels of crude oil in just 12 months, the key observation from that slide is that the Upper Wolfcamp interval is productive across our acreage from North to South. And it looks like additional zones like the Bone Spring are also present across the area. One of the more recent developments in our Southern Delaware position is that our first horizontal Bone Spring and Southern Reeves just completed and is making oil. I've said before that in this business, you really need to have access to more than 1 zone to compensate for the risk. While I don't think that industry is quite there yet in the Southern Delaware, I do believe that we're making good progress.

Over in the Midland Basin, we recently initiated a horizontal program in our Wolfberry play. The Wolfberry has been a key source of growth for Concho since we acquired those assets from Henry Petroleum in 2008. We have a deep inventory of vertical Wolfberry locations. However, the horizontal Wolfberry is interesting because it could potentially enhance rates of return and allow us to accelerate the development of infill wells. We drilled 3 horizontal wells to the Upper Wolfcamp in Upton County and plan to drill 10 by the end of the year, but could adjust that number depending on our results. So far, we're encouraged with the early results and expect steady progress in this play.

As I've said in the past, I expect 2013 to be an execution year. Strategically, I want to build one of the Permian's largest drilling machines, primarily for 2 reasons. First, we're more opportunity-rich today than at any point in our company's history. Our substantial inventory of high rate of return drilling opportunities will require tens of billions of dollars to develop over many years. So it's critical that we expand our execution capability, which industry-wide is in short supply.

Secondly, whether you're a Delaware Basin or in the Midland Basin, industry has only begun to understand the vastness of the resource opportunity, and I expect in the next few years, this will drive consolidation across the Permian. This presents a huge opportunity for those capable of executing large capital and drilling programs. And I want to make sure that we're one of the leaders with operational scale to leverage our best-in-class technical expertise and create value in the Permian for years to come.

So now let me turn the call back over to the moderator. I look forward to taking your questions.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from the line of Scott Hanold with RBC Capital Markets.

Scott Hanold - RBC Capital Markets, LLC, Research Division

This is Scott Hanold. So looking at the Northern Delaware Basin, your rig count is at 12. It sounds like you have an appetite to potentially increase that through the year. I think, if I'm not mistaken, the budget was based on like an 11- to 12-rig program. Are you contemplating -- if you contemplate more activity there would you scale back somewhere else or would that be an increase to your budget for the year?

Timothy A. Leach

Well, we're still working on that $1.6 billion budget. We're working to stay within it plus or minus kind of 10%. But to the extent that we get additional dollars, can generate additional dollars, it will all go to the Northern Delaware Basin and that's where I'd like to increase my rig count.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay. So based on the current budget right now, are you expecting to sort of maybe steady state activity elsewhere and increment [indiscernible] in the Northern Delaware or could you shift some activity there and away from other places that are more of a test at this point?

Timothy A. Leach

Well, we've been in a process of moving capital out of the Wolfberry and out of the Yeso and moving it into the Northern Delaware. I think that process will continue.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay. Now I understand. And then on the Southern Delaware Basin, you want to stay tight-lipped, yet it sounds like results are progressing nicely. Can you just kind of speak in general to your view down there? Are you being tight-lipped right now because you think there's some more acreage acquisition opportunity or there's some other competitive reason at this point?

Timothy A. Leach

Yes. You're exactly right. I mean, it's an area that is new. We continue to build and refine our acreage position. I think we have an advantage, we drill more wells down there than anybody else. We ought to understand it better than anyone else, and I want to make sure that we can utilize that advantage.

Operator

Our next question comes from the line of Arun Jayaram with Credit Suisse.

David Yedid - Crédit Suisse AG, Research Division

It's actually Dave Yedid. Quick question, so you completed 39 wells during the quarter in the Northern Delaware, but we only got 30-day rates for 18 of them. Can I make the assumption that the majority of those were completed near the end of the quarter?

Timothy A. Leach

Yes. I'll turn that one to Joe.

E. Joseph Wright

Yes. This is Joe. That's correct. I mean, when we pick up that 30-day rate, it's when they produce that 30 days. So if they started later in the quarter, they wouldn't have been picked up.

When you look at our completion count, I know it's kind of over the last several quarters, it looks like it's falling. But keep in mind, we shifted from drilling a lot more vertical wells than we do today to horizontal. So our total drilling count has fallen -- wells have fallen since we're putting more money into the horizontal. So our total number of completions will look like it's falling. We're not in -- we don't have a backlog building on our completion side at all.

Operator

Our next question comes from the line of John Freeman from Raymond James.

John Freeman - Raymond James & Associates, Inc., Research Division

Just a follow-up on that last question. So if I -- to understand that right, Joe, we shouldn't expect then in the second quarter to have kind of what you have had historically where you have a big uptick in the wells completed where you work off the backlog from the first quarter? Because the last few years, that's been the case.

E. Joseph Wright

Yes. And certainly, that's always choppy between quarters for various reasons. How many wells you get completed, sometimes you run into some problems or that sort of thing or sometimes you have a little more maintenance days in the quarter than you did the quarter before. So I can tell you that when we look at wells waiting on completion and the number of frac crews we're running, we're not building a backlog. For the second quarter, I noticed in the first month that our completions per week were up. So we could, for the quarter, have more completions than we did in the first quarter. But think about it over a long term, we stay up. We have a very few backlogs of completing wells.

John Freeman - Raymond James & Associates, Inc., Research Division

Are you able to give me what the waiting on completion number was at the end of the first quarter?

E. Joseph Wright

No. But I will get it and get it to Price.

John Freeman - Raymond James & Associates, Inc., Research Division

Okay. And then just last question for me. On Brushy Canyon, I know you've drilled at least a couple of wells there, you've had some encouraging results. There's been a private operators that's had some success. Just could you -- did you have any more of those during the quarter? Any plans to just -- maybe when we might get more color on that play?

E. Joseph Wright

Well, we did not drill anymore in the first quarter from Delaware sands horizontal. I would anticipate us drilling a couple this year. And what's really nice there is that every well we're drilling in that Delaware Basin, we're penetrating that interval, so we're getting to evaluate. And we're really working hard this year from a geological standpoint, as well as engineering to kind of understand what our potential could be there.

Operator

Our next question comes from the line of Pearce Hammond with Simmons & Company International.

Pearce W. Hammond - Simmons & Company International, Research Division

Tim, can you provide an update on Delaware Basin infrastructure oil gathering, gas processing plants, et cetera? And how do you see this as a bottleneck to be overcome in order to meet your production guidance for this year?

Timothy A. Leach

I'm going to turn it to Joe, but let me first say that the whole progression of development in the Delaware Basin started in the North and moved South. It started in the North a couple of years ago. The infrastructure in the Northern part of the Delaware Basin is much more advanced than it is in the Southern part of Delaware Basin. And industry is racing to keep up with the development -- the midstream industry is racing to keep up with the development and the productive capacity over in the Delaware. You want to talk about specifically what's going on?

E. Joseph Wright

Yes. I mean, when you think about take aways, let's start there first. We've got 4 new plant capacities -- 2 new plants and 2 new plant capacities coming on this year from a gas processing side. Pipeline-wise, the lines are getting laid that will give us a lot of flexibility, both East and West and North and South. So we can get into a lot of the lines all the way to the Gulf Coast or up through Cushing as well. So that's going really pretty well. In some areas, when I think about disposal of produced water, electricity, those kind of things, some areas are better, like Tim said. When you think about the Northern part, that's kind of where it's growing from, so we have better infrastructure for those. But there are still areas in Eddy and Lea County that do not have electricity or the capacity yet for us that we need from a disposal standpoint. So you do see higher lifting cost in those areas then you would if you had all the infrastructure in place. And then as you move down into Texas, it becomes even less. So some areas, I think we're ahead. And some areas, I think we're a bit behind. But we're spending a good bit of money this year to build out our infrastructure.

Pearce W. Hammond - Simmons & Company International, Research Division

Great. And then on your horizontal drilling in the Delaware Basin. What type of [indiscernible] do you use for your completions and how does this differ from offset operators?

E. Joseph Wright

The type of [indiscernible] is dependent a lot about depth between a sand or a man-made type of ceramic. But in terms of what we use exactly, I really don't like to comment on that. I think we do, do some things differently than our offset operators. So I'm just kind of going to leave it at that.

Operator

Our next question comes from the line of Ryan Todd with Deutsche Bank.

Ryan Todd - Deutsche Bank AG, Research Division

Question for you on volumes. Your oil volumes that you referenced, they were in line, generally, with our expectations. And gas was probably a bit weaker than we expected. Was there anything going on with gas volumes, infrastructure, bottleneck-wise in the quarter that would have explained the weakness there or is that just a mix shift?

E. Joseph Wright

Well, I think -- this is Joe. And I think always, again, quarter-to-quarter you get choppiness in terms of production. I wish it was always as smooth so everybody could -- as the model said it should be. One of the big things to keep in mind though, our shift to Bone Spring's drilling and away from that Avalon gas is a significant change that we started last year. And you can see it with those oil -- our percent oil volumes picking up. Those are very oily and less gassy wells as we bring those -- that new volume on. There's always things within the quarter that kind of mess with you in terms of wells going down or areas going down. I think everybody was probably familiar in the quarter that the Sweeney plant down in Houston, there was an outage down there from an NGL standpoint. It may have made a small amount of difference but not much.

Ryan Todd - Deutsche Bank AG, Research Division

Okay. So it's mostly just a mix shift issue. And then on the horizontal Wolfberry program that you highlighted. Should we think about that the way that you've seen the New Mexico Shelf, where you had envisioned that eventually replacing a portion of the vertical program there? And do you have any early comments on what like well cost in EURs would look like in the horizontals there?

Timothy A. Leach

No. Your first question, I think, is correct. I think that horizontal in the Wolfberry could be or will be a more efficient way to process the oil. So I think it will replace vertical wellbores. I mean the early cost look like it's in line with what the rest of the industry is reporting and the rates of return look, hopefully, like there'll be better than what the vertical has produced.

Ryan Todd - Deutsche Bank AG, Research Division

And then would this be an addition to [indiscernible] or would this be one or the other?

Timothy A. Leach

I'm sorry, you cut out during the middle of the question. Can you repeat the question please?

Ryan Todd - Deutsche Bank AG, Research Division

Would this be in place of the Wolfcamp-specific wells potentially there in the area or would you be able to do horizontal Wolfberrys and Wolfcamps?

Timothy A. Leach

Well, I mean, right now what we're doing is we're drilling in the upper bench of the Wolfcamp and that is a zone that we complete vertically when we drill a vertical well. So right now in those areas where we're going horizontal in the Wolfcamp, you would leave that part of the vertical behind.

Operator

Our next question comes from the line of David Tameron with Wells Fargo.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Can you guys, and a little bit was alluded to the last question. But if I think about your crude differentials and your natural gas price realizations going forward, crude as everybody knows, right, Midland is now at a premium to Cushing. And then for net backs, it would seem like NGL prices from here would get better rather than worse with the start up of some of the pipes out there? Can you guys just talk about pricing assumptions and how you're thinking about that?

Timothy A. Leach

Yes. Let me kind of answer from a very high level. The crude oil differentials have swung back to better than they have been historically. We've hedged those in for the remainder of this year in a way that we can land the differential within our guidance. On the natural gas realizations and the differential there, we changed our guidance this quarter for the remainder of the year. And that's basically a reflection of, if you look at a rising gas price -- if you look at the strip on gas and you look at the strip on NGL values, that kind of drives you there. And for us, it's not that much cash flow, but it is different than where we guided previously. And it's just a reflection of what it looks like -- the future markets look like for those 2 components.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Okay. And so just to clarify, the crude side it sounds like you've hedged that in so there's -- I was thinking there was upside to that differential number within your numbers, but you're saying you've kind of hedged that.

Timothy A. Leach

Well, we've hedged it only for the remainder of '13. So I do believe in the near term, Permian crude is going to be well positioned and the pricing on Permian crude probably will improve over what it has been historically, and we'll benefit from that.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Okay. Away from that to the op side. In Irion County, could you talk about the Three Rivers acquisition? Can you just talk a little more about your activity there? If you covered that, I apologize, I missed it. Or what other people are doing around you as far as horizontal drilling?

Timothy A. Leach

That is not an area of focus of ours for horizontal drilling. We do have a rig down there that's drilling vertically and it's successful in producing results that we're pleased with. We have drilled 1 horizontal well down there to test the idea, and there probably will be more. But it's not an area that we're intensely focused on.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Okay. Northern Midland. So Northern Midland, is that a tight-lipped region or is there anything up there that you care to discuss?

Timothy A. Leach

No. I mean, it's truly an exploration region and we've spudded our second exploratory well up there. And that's about all we can report on it today.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Okay. Last question, I'll get back to your core assets. If I go to Northern Delaware. I know last year you had previously talked about you're still going vertical, trying to find where to land the horizontal. Are you guys still doing that? And the bigger question I'm asking, I guess, is how much more potential do you have as far as driving down well costs?

E. Joseph Wright

When you talk about drilling the vertical, we call those pilot holes. We drill vertically and take a look at what we're doing and then come back up the hole. We're doing a lot less today. We probably cut that in half in Northern Delaware Basin. And a lot of that is because we're getting a good understanding in a broader area and we don't need to drill the pilot holes. We still do some of it. Costs kind of vary, it kind of depends on depth and drilling times and so forth. So some areas, I think, it can save as much as $500,000 to $700,000 a well, to be honest with you. And then other areas, I think it's going to be about $200,000.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Okay. And so just snapshot in general a year from now -- if I look at costs at the end of last year and look at costs 12 months down the road, what kind of difference do you anticipate?

E. Joseph Wright

I think the area -- let me answer your question this way. When I look at areas like the State line, where we've really drilled a lot more, what I would say closer to a manufacturing kind of process or a development process anyway. We've gotten our costs down there probably about as low as they're going to go for now. And that's probably -- we've probably dropped those almost 10% in that area.

Operator

Our next question comes from the line of Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc., Research Division

On the dual-lateral well, it sounds like, as you mentioned, the first is performing in line with expectations. Did the dual-lateral wells see the type of cost savings that you expected as well? And how widely are you considering employing dual laterals in Delaware?

Timothy A. Leach

Yes. As we talked to you earlier about this, this was the first one, so we wanted to make sure that it was mechanically successful. And we did see cost savings on this well compared to drilling 2 stand-alone wells. There was a fairly significant cost savings, but I think it can get better. This is the first -- this is just 1 well. So I think this program, along with other programs whose purpose is to improve the efficiency, will continue to go forward. And I think that this, along with the extended length laterals are going to be the 2 things we really focus on. Right now, we're drilling a whole lot more extended length laterals than we are doing duals.

Brian Singer - Goldman Sachs Group Inc., Research Division

Got it. And when you think about the efficacy of a dual lateral, did the Avalon and Bone Spring 2 zones, does that make uniquely the most sense to test or would this and could this apply to different combinations of zones across the Delaware?

Timothy A. Leach

Yes. It could certainly apply to more zones. We're focused on those 2 zones because that's where we have the most developed inventory.

Brian Singer - Goldman Sachs Group Inc., Research Division

Great. And lastly, on the Wolfcamp and the Delaware Basin, I think you mentioned 10 wells have been drilled so far. Can you just kind of talk to what you see there? And when you think about the Delaware, you've talked to 2 zones working on average throughout, is that still what you're thinking or do you see upside to that?

E. Joseph Wright

You're talking about the Delaware Basin?

Brian Singer - Goldman Sachs Group Inc., Research Division

The Delaware Basin, that's right.

E. Joseph Wright

And you're talking about the South Delaware Basin?

Brian Singer - Goldman Sachs Group Inc., Research Division

Yes, yes. Actually, no, I'm sorry, the Northern Delaware Basin you've talked to about 2 zones working on average. Do you see the Wolfcamp as being additive to that or should 2 still be the base case?

E. Joseph Wright

I think 2 is the base case. But we've said is that we think there's upside to the base case through these additional Brushy Canyon, Wolfcamp and Penn Shale, in addition to the expansion of the Bone Spring and the Avalon.

Timothy A. Leach

Brian, just to be clear, those Wolfcamp wells that he talked about were down in the Southern Delaware.

E. Joseph Wright

All the wells except our first Bone Spring sand well -- all the wells down south have been Wolfcamp. We've just drilled our first Bone Spring down there.

Brian Singer - Goldman Sachs Group Inc., Research Division

Yes. I think, I was just looking at the slide in the presentation where you had 10 wells in the Wolfcamp in the Northern Delaware Basin. I think I hear where you're coming from.

Timothy A. Leach

Right. Okay. Good.

Operator

Our next question comes from the line of Brian Lively with Tudor, Pickering Holt.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

I know you guys have been fielding a lot of questions about differentials over the last 3 months. Seems like, to a large extent, those issues are in the past. I'd like to focus just a little bit more on costs, the things that you can control. It seems like some of the Delaware plays you're drilling out in front of, where you have good infrastructure developed. And I'm just wondering, we're seeing an LOE rise in the short term, but as you build out that infrastructure, could you give maybe some color on where you think LOE will trend over the next 12 months?

E. Joseph Wright

This is Joe. Let me answer that one. I think our guidance at 7.50 to 8, I think it's going to be pretty flat in there over the next 12 months. Keep in mind, too, you've got a big base at the Yeso and a big base at the Wolfberry, that it still costs us to keep those wells on. We have to do well servicing type of work. So we've made those projections, we look at that. So just the normal repair work of changing out the pump or tubing in those jobs, or those type of fields, they increase over time.

There's no doubt about that. I think you're exactly right though, as you think about the Delaware Basin. As we get ahead of that infrastructure, that cost per barrel will drop very nicely.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

So Joe, if I understand what you're saying. Are you saying that, yes, the Delaware will improve on the horizontal wells, but the trade-off is the vertical programs and the higher cost over time with those?

E. Joseph Wright

I think so. I think -- right now, I would say, I would plan that to be flat cost over the next 12 months. And so I think that's exactly the way you rephrase that.

Operator

Our next question comes from the line of Mike Scialla with Stifel.

Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division

You've given us a tight curve for the Bone Spring, 360,000 Boe. Joe, you had said your oldest wells there now are 2 years old and they're consistently beating that curve. I want to see if you could quantify that at all? And then it sounds like some of the newer wells are doing better than that. I wanted to see if you could give us an indication on how much better?

E. Joseph Wright

I think, as I think about those models that we have, that's a composite of all the opportunities that we have in the Bone Springs in that Delaware Basin. I think that model can move up over time as we get more information. Yes, we do have a some wells that are 2 years old. But as you can tell by our quarter-to-quarter 30-day IP, they've improved over time. So the things we're doing today from a drilling and stimulation standpoint are different than they were 2 years ago. So I think, let me have a little more time to get some more data and work with the third-party guys and I think that model can continue to move up some.

Michael S. Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Okay. And in terms of the newer things that you're doing. Is that $6.6 million well cost still applicable to the newer wells?

E. Joseph Wright

Yes. That's a good average to use.

Operator

Our next question comes from the line of Ann Kohler with Imperial Capital.

Ann L. Kohler - Imperial Capital, LLC, Research Division

Just kind of a 30,000-foot question here or a 30,000-foot level. To me, you started your closing remarks, I guess, talking about the opportunities that you have and that it's never been greater. And discussing execution and also the opportunities given that you think that there'll be consolidation within the Permian. What is it that you need to do, if you need to do anything, from an execution standpoint of view or from the corporation standpoint of view to take advantage of all of those opportunities?

Timothy A. Leach

Well, I mean, the 2 things I think about are adding scale to our drilling program. I mean, we're running 33 rigs today. We probably have the capacity to run 50% more than that. And I think as we build into that, that adds a lot of capability for execution that's going to be needed here in the Permian. And I think the other thing is a lot of these questions and a lot of our conversation have been about infrastructure. And I think the build out of infrastructure in the areas where we're active also gives us an advantage for consolidation.

Ann L. Kohler - Imperial Capital, LLC, Research Division

And is there anything you need to do in terms of -- within the organization itself adding people or do feel that you're adequately staffed to be able to execute on your opportunities?

Timothy A. Leach

I think we're ahead of the curve. But we've, I mean, we've got -- our staff has grown dramatically every year. We will continue to be on that growth curve. We're always looking for talent. And so is everybody else, it's a very competitive business. So we want to be the kind of company that somebody that's young and talented -- or even old and talented -- would like to come to work for.

Operator

Our next question comes from the line of Irene Haas with Wunderlich Securities.

Irene O. Haas - Wunderlich Securities Inc., Research Division

Question on the Wolfcamp and Southern Delaware Basin. You show that cross section and as you kind of enter Pecos County, does the target get deeper? That's my number one question. The number two, would the well cost be more than the $6.5 million that people have been quoting?

Timothy A. Leach

As you go South, the wells get shallower, not deeper. The deeper part of the basin is to the North. And yes, the well costs down there are substantially higher than the average we talked about in the North. I think that those wells down south are running around $10 million or something like that, $9 million or $10 million. And I mean, there's a lot of science that's being applied to those down there too. So we're not anywhere close to being in a manufacturing state down there.

Irene O. Haas - Wunderlich Securities Inc., Research Division

You mean the wells, in general, in both Reeves County and Pecos County are running $10 million?

Timothy A. Leach

Yes.

Operator

At this time, we have no more questions.

Timothy A. Leach

Okay. Well, thank you once again for -- I know it's a busy day for you. Thanks for listening in on the call. I look forward to talking to you in the future. Thank you.

Operator

Ladies and gentlemen, thank you for your participation in today's conference. This concludes the presentation. You may now disconnect. Have a wonderful day.

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