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Concho Resources (NYSE:CXO)

Q3 2012 Earnings Call

November 08, 2012 10:00 am ET

Executives

L. Price Moncrief - Vice President of Capital Markets and Strategy

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

Matthew G. Hyde - Senior Vice President of Exploration and Land

Darin G. Holderness - Chief Financial Officer, Principal Accounting Officer and Senior Vice President

Jack F. Harper - Chief of Staff and Senior Vice President

Analysts

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

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

William B. D. Butler - Stephens Inc., Research Division

Brian Singer - Goldman Sachs Group Inc., Research Division

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

Mario Barraza - Tuohy Brothers Investment Research, Inc.

Joseph Bachmann - Howard Weil Incorporated, Research Division

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

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

Joseph Patrick Magner - Macquarie Research

Sven Del Pozzo - IHS Herold, Inc.

Scott Hanold - RBC Capital Markets, LLC, Research Division

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

Operator

Good day, ladies and gentlemen, and welcome to the Third Quarter 2012 Concho Resources Earnings Conference Call. My name is Lisa, 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 to turn the conference over to your host for today, Mr. Price Moncrief, Vice President of Capital Markets and Strategies. Please proceed.

L. Price Moncrief

Good morning, everyone. We're glad you could join us today for Concho's Third Quarter 2012 Conference Call. Before we get started, I would like 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, which includes details on our 2013 capital budget and guidance. Both the earnings release and the investor presentation can be found on our website.

On today's call, I am joined by Tim Leach, our Chairman and CEO; and Joe Wright, our Chief Operating Officer, who will discuss, among other things, our third quarter results and 2013 budget and annual guidance. We're also joined by other members of our management team who will be available to answer questions later in the call.

With that, I'd like to turn the call over to Tim.

Timothy A. Leach

Good morning. I'm pleased that you could join us this morning as we review our third quarter results, provide an update on our recent drilling activity and detail our capital budget and production outlook for 2013.

As I'm sure you saw on last night's press release, the third quarter was a good quarter for Concho. We produced nearly 85,000 barrels per day and generated $387 million in EBITDAX, both all-time records for the company.

I'm especially pleased with the progress of our development strategy in the Delaware Basin, which now represents over 25% of our net production and continues to deliver sequential double-digit growth rates. It's a real driver of our growth and noteworthy considering this horizontal effort in the Delaware is barely 2 years old.

There's lots of exciting things happening in the Permian, and the Delaware is just an excellent example. I spoke to you last quarter about the advantages of being positioned in the Permian. I continue to believe that this is the place to be in terms of profitability and growth. At the same time, the Permian is going through a transformation and the playing field is rapidly evolving.

Against this backdrop of rapid changes, it's important to step back and reflect on our strategy, our results and then consider how we're positioned for the future.

Since inception, Concho has always focused on a rate of return growth. Our belief has been simple. We invest in high rate return projects that really work. The results should be strong profitable growth. This approach enables us to preserve our balance sheet, while remaining flexible enough to capture Permian opportunities when they develop. Historically, the strategy has delivered annual production growth in excess of 40%, about half of which has been organic and the other half from acquisitions.

Looking forward, I see no reason why that strategy in resulting organic production growth should change, given the increase in opportunities in the Permian. The efficiencies realized through horizontal development are real, and in the not-too-distant future, horizontal rig count will exceed vertical rig count in the Permian. That's truly a revolutionary change.

Today, half our operated rigs are drilling horizontal wells, thanks in large part, to many of the strategic moves we made over the last 12 months. Most notably, we have nearly doubled our footprint in the Delaware Basin through the acquisition of OGX, Three Rivers and other lease hold.

We've entered areas like the Southern Delaware Basin, the Southern Midland Basin and the Northern Midland Basin. We are a better company today because we've expanded the opportunities to reinvest capital across the Permian, without having to sacrifice returns. As a company that remains committed to returns, I cannot be more optimistic about Concho's ability to deliver consistently strong organic growth, while creating value for the shareholders.

As you probably read in the press release, we announced a 2013 capital budget of $1.6 billion. We expect to fund this budget largely within cash flow and deliver about 20% organic production growth.

It shouldn't surprise you that over 60% of next year's capital is dedicated to horizontal drilling, and that 1/2 of the 30 rigs we expect operate next year are drilling horizontal wells.

Just a year ago, we outlined a smaller budget for 2012, which called for an average of 35 rigs and 20% growth.

The ability to invest more capital per rig and still deliver the same type of organic growth is a reflection of the operational and capital efficiencies achieved through horizontal drilling. It also means that we have the operational scale in place to deploy more rigs to accommodate their well performance, lower cost or reduced take away constraints.

Over the last few quarters, I've updated you on our progress in the Northern Delaware and I'm pleased to say that our results are continuing to improve.

Since our last earnings call, we've added 15 Northern Delaware Basin horizontal wells that have 30 days of production data, bringing our total horizontal wells in this area completed by Concho to 106, targeting 7 unique zones. The average 30-day IP rate of those 15 new wells was in excess of 750 Boes per day from single zone completions. 10 of those 15 wells were Bone Spring completions, with an average 30-day IP above 800 barrels a day and over 60% of that, crude oil. On the basis of EUR and rate of return, we think this area competes with anything going on in the Permian and most likely across the entire U.S. As a result, we will spend nearly half of our 2013 drilling budget in the Northern Delaware Basin.

Moving on to the Southern Delaware, our team now has 4 horizontal Wolfcamp wells with at least 30 days of production data. The average 30-day IP rate of those wells were 675 Boes per day, 84% of that being crude oil.

As a reminder, we have not included any drilling locations from the Southern Delaware in our most recent inventory count, but except -- but expect that we will add substantial locations as we continue to de-risk our 140,000-acre position. This will be in addition to the locations that we will add in the Northern Delaware Basin at the end of the year. So drilling inventory is not going to be a problem for Concho.

Before I hand things over to Joe for a more detailed review of our 2013 capital budget and operations, I'd like to highlight that we have recently signed a PSA to sell noncore assets for $520 million. Proceeds from this divestiture will be used to reduce borrowings under our credit facility and bring our pro forma leverage back within 2x EBITDA. But the biggest take away here is that the combination of acquiring assets from Three Rivers and subsequently selling noncore properties is consistent with our strategy of increasing our exposure to high rate of return drilling opportunities, while maintaining a conservative capital structure.

Going into '13, there are a lot of exciting things that are taking shape for Concho. I'm confident that we have a great strategy to consistently deliver profitable growth in the Permian. And I look forward to taking your questions at the end of the call.

I'll, now, turn things over to Joe.

E. Joseph Wright

Thanks, Tim. On the last quarter conference call, I outlined a plan for the balance of 2012 that called for a shift to horizontal drilling across our portfolio. Today, I'm pleased with that progress as over half our rigs are drilling horizontally. In the Delaware Basin, we currently have 11 rigs, 9 in the North and 2 in the South, all of which are horizontal.

The Yeso, which has, traditionally, been in a vertical play is currently running 3 horizontal rigs out of a total of 5. And over in Midland Basin, we'll continue to run 1 horizontal through the remainder of the year. The good news is that we've advanced this shift on a compressed timeline without having to adjust our 2012 capital budget or production guidance, and we expect to carry this momentum into 2013.

As Tim discussed earlier, our 2013 capital budget is $1.6 billion, of which $1.4 billion will go towards drilling in our 3 core areas, which I'll discuss in more detail.

We plan to operate on the average 30 rigs and we'll drill or participate in approximately 630 wells. We expect 50% of our operated rigs will drill horizontally, and the rig distribution among our core areas will be very similar to where we are today.

We're planning to allocate 54% of our drilling capital to the Delaware Basin. By comparison, we allocated 35% in 2012 to the Delaware. So clearly, this core area has emerged as our most significant source of capital investment in a very short amount of time.

Between the Northern and Southern Delaware Basin, we plan to operate 11 rigs, all horizontal, and we'll drill or participate in approximately 175 horizontal wells. Those wells will target zones as shallow as the Delaware Sand and as deep as the Penn Shale.

The New Mexico Shelf calls for 21% of our drilling capital, where we expect to drill or participate in approximately 190 Yeso wells, 60 of which are horizontal. We expect to average 5 rigs in the Shelf, comprised of 3 horizontal and 2 vertical.

Lastly, we plan to allocate 25% of our capital to the Texas Permian core area, where we expect to drill or participate in approximately 240 wells. We plan to average between 1 and 2 horizontal rigs out of the total of 14.

For the balance of 2012 and into 2013, we plan to continue to test a number of new concepts in all 3 of our core areas. During the third quarter, we spudded our first dual lateral in the Northern Delaware Basin, and expect to test a few more during 2013. We also continued to experiment with extended link laterals with encouraging results.

In the Southern Delaware, we continued to drill horizontal Wolfcamp wells across our acreage in Reeves and Pecos County, and expect to have drilled 10 horizontal wells -- Wolfcamp wells by the end of 2012, including the 4 producers Tim discussed in his opening comments. And within this area, we'll also test additional zones horizontally above the Wolfcamp.

Moving north to the New Mexico Shelf, our horizontal Yeso program continues to perform in line with our expectations. We're currently modeling these wells at an ER range of 300 to 350 MBoes with a 30-day IP rate of about 200 Boes per day. AFVs are between $3 million and $4 million for a rate of return in excess of 40% at $85 oil and $4 per Mcf.

We currently have 370 horizontal Yeso locations identified and we're working to expand our inventory of horizontal locations as we test the productive boundaries to the north of the shelf and in the shelf's extension to the Southwest.

Shifting gears now to the Midland Basin. We've drilled 2 horizontal Wolfcamp wells on our Upton County acreage. Those wells are in the areas with limited 40-acre Wolfberry drilling. Part of our efforts in 2013, we'll test the areas that are currently slated for vertical 20-acre Wolfberry development. The results of those horizontal tests will be measured against the results of our ongoing 20-acre pilot program to determine the most efficient way to capture those reserves.

In an ideal case, we would find the horizontal returns compelling enough to convert the vertical locations to horizontal locations, and accelerate the development of resources that would otherwise wait to be drilled through 20-acre vertical program.

Over in Irion County in the Southern Midland Basin, where we acquired acreage from Three Rivers, we're currently drilling the first horizontal well in that acreage and it will target the upper Wolfcamp.

Over the course of 2013, we'll average 1 horizontal rig to drill additional Wolfcamp horizontals in Irion, as well as horizontal plant wells in Glasscock and Terry County.

Our 2013 capital budget is predicated on current third quarter service cost. From a year ago, we've seen a softening in pricing, particularly in large ticket items like high pressure pumping in rigs. However, the real cost savings continues to come from improved logistics and scheduling, thanks to the drilling efficiencies, getting wells online faster and an increasing supply of services.

Concho has always reinvested its cash flows, so if we do see lower costs and greater efficiencies in 2013, we would stand up additional rigs where the returns are justified.

One current situation we're watching is the recent widening of the Midland to Cushing differential. I believe much of the current spread is a combination of scheduled refinery maintenance at the Phillips 66 Borger refinery and outages along the Northeast caused by Hurricane Sandy.

Current shipments to the Northeast from regions like the Bakken are now heading to Cushing. So we'll keep an eye on the situation and expect that there might be some impact to the fourth quarter realizations, but probably not enough to alter our 2012 annual guidance.

Takeaway capacity in the Permian will continue to be a key theme in 2013. However, we do see some meaningful release in the very near future. In fact, we've added some slides to our latest investor presentation that provides some good detail on planned capacity additions for both oil and NGLs.

On the oil side, Phase 1 of the Longhorn reversal will commence in the first quarter of next year, with Phase 2 coming in online in the second quarter.

Combined with the Permian Express expansion in the first quarter, we should see over 300,000 barrels per day of capacity addition, all of which is going to Gulf coast.

On the NGL side, the Lone Star expansion will be completed by the first quarter and will be followed by the Sandhills and the Texas Express in the second and third quarters, respectively. In total, we see 740,000 barrels per day of incremental takeaways capacity in 2013, all of which is going to Mont Belvieu.

These projects will add much-needed relief to crude and NGL displacement in the Permian, resulting in fewer volume mix and potentially enhanced economics.

Lastly, I would like to address one housekeeping item. As reported, our LOE in the third quarter was $7.15 per Boe, which is well below our annual guidance. The sharp decline was primarily due to lower work over costs and reductions in the cost of well service rigs, contract labor and chemical costs. However, I anticipate an increase in well servicing activity in the fourth quarter, causing LOE to range between $7.75 and $8 per Boe. We still expect full year 2012 LOE to sell around $7.15 -- $7.50 per Boe, as previously guided.

With that, I look forward to your questions and would like to turn it over to Price.

L. Price Moncrief

Thanks, Joe. I'm going to touch on a few third quarter highlights, as well as our 2013 guidance before moving to Q&A.

The third quarter was another strong quarter in terms of production growth and cash flow. We produced 7.8 million Boes, representing a 24% increase over the third quarter of 2011 and 14% sequentially. Driven in part by the contribution of assets from Three Rivers. However, a significant driver of our organic production growth is coming from our horizontal program in the Delaware Basin, where we produced approximately 16,000 Boes per day, an increase of 80% over the third quarter of 2011 and 15% sequentially.

Our production mix for the quarter was 59% crude oil, but excluding the impact of the Three Rivers properties, crude represented over 60% of our volumes. Looking at revenues, oil accounted for 82% of our total sales during the quarter, while dry gas accounted for only 5%.

Unhedged realized oil price for the third quarter improved to 96% of NYMEX relative to the previous quarter of 92%, as the average Midland to Cushing spread narrowed to $1.75 per barrel.

On the natural gas side, our unhedged realization declined to 164% of NYMEX relative to the previous quarter of 196%, reflecting a slight decline in NGL pricing and an increase in the average price of natural gas.

Despite the decline in natural gas realization, our unhedged realized price per Boe increased over the second quarter to $63.74 and our cash margin improved to 75%, still among the best in the industry and indicative of our strong oil-driven cash flows.

Moving on to 2013 guidance, you've probably read the detail in our press release, but I'd like to specifically address a few of the components.

We have outlined a 2013 capital budget of $1.6 billion, which we can fund largely through cash flow from operations, assuming NYMEX crude and natural gas prices of $85 per barrel and $4 per Mcf, current service cost environment in the midpoint of our production guidance.

We expect to produce 32.9 million to 34.3 million Boes, which implies 15% to 20% growth over our 2012 organic production estimate. Please refer to Slide 13 of our most recent investor presentation for a detailed reconciliation for the year-end guidance to this organic production estimate.

At a high level, our 2012 organic production estimate is adjusted to take into account a partial-year production contributed by Three Rivers assets, which produced 6,700 Boes per day in the third quarter, and a full-year production contributed by our divestiture properties, which produced 5,800 Boes per day during the third quarter.

As customary with our annual production guidance, we plan internally around the midpoint of our range. The ability to outperform the midpoint of our guidance will likely come through improved capital efficiencies, better productivity or reduced takeaway constraints. Our LOE expectations for 2013 is $7.50 to $8 per Boe, which is above our 2012 guidance.

This is largely due to the fact that we are allocating a greater proportion of our capital budget to areas like the Delaware Basin, where there is limited infrastructure in place. Over time, we would expect per unit LOE to improve as key infrastructure items like gathering systems, electricity sources and disposal systems are put in place.

We expect to see a slight increase in per unit DD&A next year, reflecting the effects of recent acquisitions, as well as increased drilling in emerging areas.

With respect to 2013 interest expense, the press release detailed the interest rates on our existing notes. But I'd like to remind everyone that we did issue $700 million of new 5 1/2% senior notes during the third quarter, which will add to our fixed interest expense.

Additionally, we are rolling out guidance for our noncash interest expense of approximately $14 million to $16 million for 2013, reflecting the amortization of debt issuances costs.

Concho continues to maintain an active oil hedging program. Over 60% of our expected oil production for 2013 is hedged at $96 per barrel, which provides a greater degree of certainty around our cash flows and our ability to fund our capital budget.

In closing, this was an excellent quarter for Concho and as you can tell, we will enter 2013 with tremendous momentum behind us. Our horizontal transition is in full swing and we look forward to executing the same return focus strategy that has delivered consistently strong organic growth.

Thanks for joining us. Now let's move to Q&A.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from the line of John Freeman with Raymond James.

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

First question I had -- the drilling budget for next year is basically flat. I mean, the increase is due to the infrastructures spending and then some bit of lease hold. And I guess specifically on the infrastructure, price sort of alluded to the fact that you're having to spend a good bit in the Delaware Basin when the infrastructure is more limited. And I guess I'm just trying to get a sense of sort of longer term, maybe like 2014 beyond, like how much of the spending you're doing next year on infrastructure was just sort of view as one-time? And sort of what would be a more normalized sort of infrastructure spend?

E. Joseph Wright

John, this is Joe. Let me answer that one real quick. Right now, when you look at the infrastructure cost, that's about 8% of our capital budget. Normally, I think after '14, we'll probably be in that 4% range, when you kind of think about it, just on going top of the cost.

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

Okay. So back to sort of more normalized like it was this year and the prior year?

E. Joseph Wright

I think so. John, remember the infrastructure capital cost, primarily a salt water disposal, and so it has a rate of return on that capital expenditure as well, and probably the payout versus trucking all that salt water is very short. So from a capital standpoint, that's not sunk capital with no return, it probably has a faster payout than the entire capital budget.

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

That's a good point. On the dual lateral well that you all did in the Northern Delaware, I mean, I'm not looking for like a rate or anything. But just in general, can you talk about -- did you -- what you learned from it? Did you happen the change, maybe the well design or anything that you could elaborate?

E. Joseph Wright

John, so far everything is going well on that one. We're actually still drilling it. We've started our second lateral in that. Everything's going real well. So I think we feel very good -- we drilled the lower lateral first and we're drilling the second, the top lateral now.

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

Okay. And then just last question for me. You mentioned Joe, you all are pretty encouraged by some of the work you all have done on the longer extended laterals. Could you just sort of elaborate on how much longer those laterals were? Anything else should you want to add to it?

E. Joseph Wright

Yes. I mean, we've had them out as far as 1.5 mile to 2 miles and it's working out very well right now so.

Operator

Your next question comes from the line of Brian Lively with Tudor, Pucking -- Pickering and Holt.

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

Looking at the guidance for next year from the production side, and just thinking about how you guys have started making the transition -- bigger transition towards more horizontal drilling. Could you guys just provide some context around how much conservatism you build in to those production numbers based on, I guess, timing of wells? And also just some uncertainty how with the wells will look like?

Timothy A. Leach

Yes, let me take a stab at that and I'm going to kind of jump around a little bit. But the way we think about guiding and the risk we've applied in the past has a lot of components in it. And as you know, the timing of bringing those wells on, takeaway constraints out of the basin, the risk embedded in the type of drilling that you're doing, and we try to stew all that into our guidance and come up with a range that we feel comfortable that reflects all the uncertainty that's out there in the industry right now. So I think, if you summarize all of those factors in our guidance, the range from risk to unrisk is about 3 million barrels and about 2 million of those barrels are associated with the PDP properties and about 1 million with the drilling. And the horizontal component of our drilling is going up. We have less -- we drilled thousands of vertical wells, so our confidence in those wells is higher, the risk is lower. But I would tell you that we now are getting more and more confident in the horizontal drilling and the results continue to improve, and continue to either hit or exceed the way we think about it and the way we model it.

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

That's helpful. Then maybe just more -- taking a step back, you guys are talking about, I guess, doing a little bit more activity on the Midland side as it relates to the horizontal program. Just wondering if your confidence in that the Midland horizontal potential has increased over the last quarter or so, based on your own results and industry results? Are you thinking kind of the same as you were 6 months ago?

Timothy A. Leach

Well, I don't think I'm thinking the same as 6 months ago, but I think the Delaware Basin is further along in development. I think there's twice as many rigs running in the Delaware horizontally as there are in the Midland right now. So there's just -- there's more information and it's further along in being de-risked. In the Midland Basin, the activity is more spread out. It's in different benches of the Wolfcamp or it's in the Cline shales, and there's just fewer wells that have been drilled. And we've had success over there, but I just think it's earlier stages and not in full development.

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

And last question for me, Tim, if maybe you could compare some of your earlier Delaware results with, which what you've seen on the Midland Wolfcamp in Cline side. How did those in kind of early apples to apples return stack up to one another?

Timothy A. Leach

I don't have anything in front of me to talk about actual numbers. But it seems like that the highest rate of return thing we have going right now is horizontal Bone Spring sand, and that's as high as the Yeso rates of return, they were among the highest things that we've ever done as a company. And it looks like, probably on a risk basis, the Midland Basin stuff is maybe, I don't know, 20 points below that in terms of the rate of return. So it's substantially a lower rate of -- a substantial lower rate of return. But that reflects a lot of the risk in that it's newer and we don't have as much data.

Operator

Your next question comes from the line of William Butler with Stephens.

William B. D. Butler - Stephens Inc., Research Division

Can you all talk a bit more about -- you all mentioned you're going to [indiscernible] the upper Wolfcamp and even the Glasscock and Terry decline, sort of what's driving those decisions one zone versus the other initially?

Timothy A. Leach

Let me call on Matt Hyde to address that one.

Matthew G. Hyde

Sure, this is Matt. There are number of designation of zones within the Wolfcamp. Our designation is up for our Wolfcamp is fairly generic. I think alternatively, industry uses A, B, C and D benches. So when we talk about Upper Wolfcamp, we're generally referring to the A and B benches, generally.

William B. D. Butler - Stephens Inc., Research Division

Okay. And as it pertains to the Cline in the Glasscock and Terry County areas, there any Wolfcamp potential there initially, at least looking geologically at it?

Matthew G. Hyde

At this point in time, in the Glasscock County area, our focus is, in fact, the Cline, as you know, we've been producing from the Wolfcamp there, historically, in the vertical sense, and continue to do that. But at this point in time, our horizontal activity in that Glasscock County area is focused on the Cline.

William B. D. Butler - Stephens Inc., Research Division

Okay, and then in Dawson County, is there any activity going on there and is there any Mississippian potential on that acreage?

Matthew G. Hyde

Some of that acreage actually will be or was part of the divestment that we just announced. We do not have a substantial acreage position up there in the Dawson area beyond that.

William B. D. Butler - Stephens Inc., Research Division

Okay. And is there any update on, maybe this is for Tim, more on acquisition activity in the play in general?

Timothy A. Leach

Well, I mean, in the Permian, in general, there's as many deals out there as I've ever seen, I think, and part of it is driven by year-end stuff and part of it is driven by the new technology, and just how much opportunity we're finding but it's harder to be a small company because these wells are more expensive and more complicated. So there's a lot of deal flow but, I would say, I mean, from a very big picture for Concho, our inventory that we have on our existing acreage is so compelling and has such a high rate of return that, that's probably the highest and best use of all the capital that we have. And so it's really tough for acquisitions to compete with accelerating our existing inventory.

Operator

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

Brian Singer - Goldman Sachs Group Inc., Research Division

You talked about 4 Southern Delaware Basin wells, can you say how close together or far apart those wells were on your 140,000-acre position? What percent of your acreage do you think is prospective at this point? And then make a comment on the well cost that you're seeing there?

Timothy A. Leach

Well, we think all our acreage is prospective and I'm looking at Matt Hyde, but it seems like there's a couple or 3 of those wells that are in the North and then one in the South, and they may be 30 miles apart.

Matthew G. Hyde

Or about 20 miles.

Timothy A. Leach

20 miles apart.

Brian Singer - Goldman Sachs Group Inc., Research Division

Got you. And well costs?

Timothy A. Leach

They're kind of in that -- they're in the science stage so Matt's spending money aggressively on gathering data, but it's $8 million to $9 million.

Brian Singer - Goldman Sachs Group Inc., Research Division

I assumed you would expect that, that would fall just overtime as the science phase ends or?

Darin G. Holderness

Yes, yes.

Brian Singer - Goldman Sachs Group Inc., Research Division

Okay. And in the Delaware, are you seeing or do you expect any differences in performance from the Bone Spring wells that are being drilled on the Three Rivers acquired properties versus those on your legacy properties?

Timothy A. Leach

Well, in the northern Delaware Basin, there's basically 3 or 4 different areas where you have a different set of primary targets, and Three Rivers had acreage in all of those and we have acreage in all those plays. So when you move from play to play, your primary target changes, whether it's the second Bone Spring sand or it's the third Bone Spring sand or the Avalon, and we're getting good rates of return out of all of those.

Brian Singer - Goldman Sachs Group Inc., Research Division

Got you. And then finally, in the Midland Basin, just wanted to follow up on your comments. Are there any specifics can provide on Terry or Howard County wells?

Timothy A. Leach

Terry or Howard, no. I would you say that Northern Midland Basin activity that we have, we drilled our first well and it was inconclusive and what we saw -- we're preparing to drill our second well and I still think of that whole thing is an exploration play up there.

Operator

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

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

Yes, I have a question on Southern Delaware Basin. You have about 10 wells drilled in the area. Just wondering if you have done anything in Pecos County yet and whether do you do plan to keep your 2 rigs in that area next year? And then in the [indiscernible] case, when would with this part of the Delaware Basin impact your top line? Is it going to be like a '13 event or '14 and how's infrastructure there? I suspect you probably have to do quite a bit of work?

Timothy A. Leach

That's a whole lot of questions. Let's see. We plan to have 10 wells drilled in that southern Delaware Basin position by the end of the year. We're moving toward Pecos County. We haven't drilled one in Pecos County, both those -- we have vertical monitoring wells. So the activity is going that way. A lot of the infrastructure that is planned will be infrastructure down in that area because, as you've seen, when you come out here and tour that area, there's not much infrastructure in the Southern Delaware. And that's an area that, as we ramp up on it, and I think we have the ability, as we mentioned in the call that we can add a lot of rigs as a company, so that will be an area I think that you'll see us with continued success to ramp rapidly.

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

And would it impact you in 2013? Or '14? I mean when would we start seeing sort of incremental production from this part of the Basin?

Timothy A. Leach

I think you'll see in '13.

Operator

Your next question comes from the line of Mario Barraza from Tuohy Brothers.

Mario Barraza - Tuohy Brothers Investment Research, Inc.

Can you talk a bit more about the horizontal Yeso delineation? You talked about there's upside to your horizontal count there. What percentage of your acreage position there is delineated horizontally? And what do you think you could potentially add there?

E. Joseph Wright

Yes, this is Joe. If you remember our extension to the Southwest, that acreage is really going to be developed fully with horizontal drilling. So if you think about that, that area, and potentially, we'd like to add additional acreage in that area. And when you look at the fairway of what we call the traditional shelf, traditional Yeso, that was developed pretty tightly. But out on to the North and into the edges of that fairway and in the acreage that we picked up from Marbob, we're developing areas in there horizontally. So potentially, by maybe sometime by mid-next year, I'll have a really good number for you in terms of total locations. But we've moved to where the majority of our development now is horizontal in that play.

Mario Barraza - Tuohy Brothers Investment Research, Inc.

Okay. And then just on the completion front, did the delta amongst your quarters this year, is that more just because you're tilling -- you have more horizontal activity? Or is that also tied to midstream constraints?

E. Joseph Wright

You're talking about the number of wells?

Mario Barraza - Tuohy Brothers Investment Research, Inc.

Yes. You completed -- was it 66 in the first quarter, 84 in the second and then it was down to 55 this quarter?

E. Joseph Wright

Yes, it's just a little bit of a function of timing, but as we did bring our well count down as we shifted over to horizontal, our vertical count dropped so as you think about that, now, the Delaware Basin has always been horizontal. There's not a slowdown in terms of completion timing. There's actually -- things are really pretty -- happening pretty quickly now. So...

Mario Barraza - Tuohy Brothers Investment Research, Inc.

So is it more than it's all horizontal, it doesn't have to do with midstreams at all?

E. Joseph Wright

No, no, it doesn't.

Mario Barraza - Tuohy Brothers Investment Research, Inc.

Okay. And then lastly, at the end of your prepared comments, you talked about basis differentials widening. Where are those tracking today? And you said it could potentially impact or it could -- it likely won't, but it could potentially impact fourth quarter price realizations?

E. Joseph Wright

Yes, you have October, November, that differential is already set, so we're really just look at December. And so the effect of December on the fourth quarter is going to be in that range that I gave you. So it's probably not going to hit the fourth quarter that bad. And right now -- what's the price -- did you get a current -- about $5 today is the differential.

Operator

Your next question comes from the line of Jeb Bachmann with Howard Weil.

Joseph Bachmann - Howard Weil Incorporated, Research Division

Just a couple quick questions. First, Tim, I think you talked about one of -- or an inconclusive well up in Terry County. But I saw there was another well in the release that was P&A-ed, and just wondering where that other well is located?

Timothy A. Leach

I believe that one was over in Irion County, over in the stuff we got from Three Rivers, yes?

E. Joseph Wright

One was vertical shallow Wolfcamp wells.

Timothy A. Leach

I'm not sure which well he's talking about.

E. Joseph Wright

I think it's the same well.

Timothy A. Leach

It's probably the same well.

E. Joseph Wright

I think you're talking about the same well, that we drilled up in Terry County and we have TA-ed that well.

Timothy A. Leach

But he said there was 2.

Joseph Bachmann - Howard Weil Incorporated, Research Division

Yes, I think there were 2 in the release.

Timothy A. Leach

The other one's an Abo well. We're not helping you out very much here.

Joseph Bachmann - Howard Weil Incorporated, Research Division

That's okay. And then second question, more of a wish, have you guys talked about having an analyst or investor day anytime in the near future?

Timothy A. Leach

Yes. We talk about that a lot. We want to make sure that when we have one, we can completely enlighten you and so I think the best timing on that would be when we get our year-end reserves done, have our third-party work done and all of these new curves and things like that. So probably sometime after the first quarter, or not after the first quarter, but in the first quarter.

Operator

Your next question comes from the line of Mike Scialla with Stifel, Nicolaus.

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

I apologize if any of these have already been asked, but it looked like your divestiture package was a little higher than the $200 million to $400 million you've originally guided too. I'm just wondering, did you add anything to that package? Or is that a fair apples-to-apples comparison?

Timothy A. Leach

Yes. That's probably not apples-to-apples. I mean, when we bought Three Rivers, we said that the way we're going to finance that $1 billion acquisition was by selling $200 million to $400 million of assets, in that range. And -- but that wasn't really a target for our entire divestment program. So we identified assets that we thought were ones that weren't in our core area or part of our core program, and that totaled more than the $200 million to $400 million.

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

Got you. So I think you included the Abo in there, is that correct?

Timothy A. Leach

Right, but I think on most of that Abo acreage, we kept the Yeso rights.

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

Are you done now for a while with divestitures or is there anything else you'd like to let go?

Timothy A. Leach

No, that was it. We're not very good at divesting of things that we -- because we like to be selective in what we acquire so I don't think we're going to be selling anything else in the near future.

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

Was there any capital gain associated with that $520 million sale?

Timothy A. Leach

Darin's here. I think we did a tax break exchange on most of that. So there wasn't any -- the capital gains on the sale?

Darin G. Holderness

Right. We will seal that through a 1031 exchange.

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

Good, I'd like to see that. And then you mentioned the $8 million to $9 million well cost for Southern Delaware Basin wells because they're in the science phase, but how does that compare to where your horizontal wells are in the Northern Delaware right now?

Timothy A. Leach

Most of those Bone Spring sand wells are kind in the $5 million to $6 million range.

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

Is it fair to say that over time you could get the Southern Delaware Basin down to that range or they're geological different, where that's not possible?

Timothy A. Leach

It's a little bit deeper but -- I'd say, still in the North, we're in the process of still squeezing more efficiency out of it.

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

So $5 million to $6 million may not be the limit there. How about over in the Midland side, well costs for horizontal Wolfcamp incline?

Timothy A. Leach

Oh, those things are kind of all over the board depending on where you are but ...

Unknown Executive

It's $7 million on the East and a little more on that on the West, at this point.

Timothy A. Leach

And it depends on whether it's one section lateral or extended. You got to make sure you know what kind well you're talking about.

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

Okay. And then just, I guess, conceptually from your dual lateral, it sounds like you're getting your well costs down at pretty low levels. What are you really hoping to accomplish there? It seems like on the surface, you're saving the well costs of just a vertical portion of the hole. Is there anything beyond that? Or is that...

Timothy A. Leach

Yes, I think there's -- I'm mean, that the -- the point of that is, there's 2 points. One is better capital efficiency just from saving part of the wellbore. But the other thing is acceleration of inventory, being able to get 2 of them done at one time.

Operator

The next question comes from the line of Pearce Hammond from Simmons.

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

How do you see rig efficiencies, in specifically maybe in spud to sales time evolving in '13 for Concho? Do you have a lot of running room to improve efficiencies?

E. Joseph Wright

Yes, this is Joe. We always like to think we definitely have running room for that. We can always get better. Especially when you think about the Delaware Basin and all the different type of areas that we're drilling in, so we've got a lot of room to improve in and, like the question before, when you think about that Southern Delaware Basin wells and the cost there, I mean, we will be getting those costs down and from an efficiency to spud to sales, think a lot of that will depend upon just the area that you're in, but I believe we will get better. It's going fairly well, as you think about the Northern Delaware Basin in terms of that timing. Of course, our core areas, like the Yeso and the Wolfberry, the timing in those areas is very good. So...

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

Great. And do you think you're reaching the plateau on the number for frac stages per well? Or do you expect a meaningful change year-over-year?

E. Joseph Wright

I think it'll all depend upon lateral length, as you think about the areas that we've developed so far. Now the Midland Basin, we haven't really kind of pinned that down yet, but that has some room, a little more science to go, but it'll all depend on lateral length really.

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

And what is your average lateral length in like the Northern Delaware Basin and then the Southern Delaware Basin?

E. Joseph Wright

Well, most of the original drilling was just what we call a section lateral. That's starting to -- we're starting to move out a little bit than that and we have drilled up to 2 mile, about 1.5 mile. Some of the areas that we have there, we don't have quite the acreage in terms of blocking it up and drill 2 mile laterals. So at this time, limited to one section laterals.

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

Great. And just last one for me, how good do you feel from a personnel standpoint, as far as executing your plan for next year, are you still actively trying to hire people? And is it still difficult to secure good quality technical folks?

Timothy A. Leach

That's not a phenomena of just today. It's always been hard to find good quality technical folks, so we're really pleased with what we've got. As I said earlier that because of the efficiency in the horizontal drilling, we could run at a higher rate than we're running today with 30 rigs. So we still have a lot of job openings here. We still have room to add a lot of people. We've had success so far in 2012 at getting people, but we have the capacity to do more with what we've got.

Operator

Your next question comes from the line of Joe Magner with Macquarie Capital.

Joseph Patrick Magner - Macquarie Research

Just wanted to, I guess, ask about the shift in -- there's a bit of a shift in the oil/gas mix in the third quarter. Just curious, with a lot of the Delaware focus being in the North where, I guess, at least, it appears on the surface that wells are a little less oily than some of your other areas. How do you see that sort of playing out through this year and into the next?

E. Joseph Wright

I think what you're seeing in the third quarter is the effect of having a full quarter of Three Rivers production, because that was -- they had more gas production in their base. However, the growth in our production is in oily areas and, as I mentioned on those, the different wells we've added in the Northern Delaware Basin, they're very oily. So I think that's going to have a big influence on future quarters.

Joseph Patrick Magner - Macquarie Research

Okay. And then just on that comment a second ago about the 1031 exchange, to shield from the taxes from the taxes on the sale. Is there a look back allowed there, can it be applied to Three Rivers? Or will that need be applied to future acquisitions?

Unknown Executive

It's a look back to Three Rivers.

Operator

Your next question comes from the line of Sven Del Pozzo from IHS.

Sven Del Pozzo - IHS Herold, Inc.

It's Sven. Just conceptually, it wasn't too long ago that you had favored vertical development as opposed to horizontal development, because of the areas where you were in, I'm thinking, particularly, in the Midland Basin with thicker vertical sections. So now, call it about -- fast-forward a year, it seems like you've switched over to embracing the horizontal development concept. Could you just give me a general description of that change in attitude?

Timothy A. Leach

Yes. I mean, most of the reservoirs that we're tapping today are not the same reservoirs we were tapping 2 years ago. So all the resource oil play that are in the Bone Spring and the Wolfcamp vertical development won't really provide you the same kind of economics. So it's a reflection of the new stuff we found and even like in the Yeso, for example, the best applications of horizontal in the Yeso are in areas where the vertical would've been challenged for one reason or another.

Sven Del Pozzo - IHS Herold, Inc.

So you could extend the limits of the -- of your fields, I mean, in terms of areal extent, moving to the periphery of the fields, developing them horizontally?

Timothy A. Leach

Right. And in that Yeso, as you move to the edges, that was a 2-zone development. Some of the edges, you only have one zone so you couldn't capture that with a vertical wellbore, but it's very economic with the horizontal wellbore.

Sven Del Pozzo - IHS Herold, Inc.

Okay. And then back to Mike's question about the dual laterals. I just have heard of dual laterals introducing complications in the completion procedures or by introducing down hole risks. I mean, I guess, as you -- I guess, we're still pretty early stage in this dual laterals so it's not all set and done that you would definitely use this development, the dual lateral development on a lot of your drilling in the future?

Timothy A. Leach

I think, by definition, we haven't even drilled our first one yet, so we're in the very early stages. But there will be things like that, that we will continue to experiment with and that's, I think that's how all this innovation has come about in our industry is, try new things. So the dual lateral is one type of thing that we will experiment with, but there'll be other things.

Sven Del Pozzo - IHS Herold, Inc.

Okay. And would you just describe -- I've heard the Abo and the Dawson County acreage being part of the sales package. In a top-down sense, I'm thinking, you kind of swapped these -- the assets that you announced in this sale in the third quarter with -- for the Three Rivers stuff. So just generally, what is that -- is it right to think of in terms of a swap of that kind -- of the Three Rivers exposure for the stuff you just sold? And what did you just sell so I can have a better feel for what you're giving up and what you're gaining?

Timothy A. Leach

Well, what we sold didn't have this -- it's close to having the same amount of production, but not quite. However, I think the way you ought to think about it is, we acquired from Three Rivers, acreage that had lots of drilling locations. We sold Central Basin Platform assets, they were out of those core areas that had good production, but they didn't have very much growth opportunity.

Sven Del Pozzo - IHS Herold, Inc.

Okay. So not much horizontal upside in those areas, you might say?

Timothy A. Leach

Not anything that we saw at Concho.

Sven Del Pozzo - IHS Herold, Inc.

Okay. And then, just out of curiosity, what can you tell me about the prospectivity of the Cline shale in Terry County versus Glasscock County, where you're drilling? Because, yes, they're far way from each other and I'm just kind of curious as to what draws you to those 2 areas? What might make the Cline prospective in both those areas?

Timothy A. Leach

Well, the Cline is a very large formation in the Midland Basin and its equivalent exists in the Delaware Basin as well. So it's a basin-wide type of deposit and industry has pushed the play, starting from the very southern end of the Midland Basin. There's been -- entire companies have been built around Cline development in that Glasscock County area, so you've got a lot of wells coming online there and up the North, it's just in the early stages. There's not that much data on it.

The rocks look similar though.

Operator

Your next question comes from the line of Kevin Frank [ph] with Fortress.

Unknown Analyst

Just a quick follow-up to the question that was just asked, up in the Northern Midland Basin, Terry County. Do you know how many other horizontal wells are being drilled up there right now? And also, I mean, is there anything you learned from that Red Headed Stranger well that you'll use in drilling the -- I think it's the Midnight Rider well that you're currently drilling?

Matthew G. Hyde

Yes, this is Matt, I'll take that question. There are a couple of other competitors up there that have moved into the horizontal realm. They're privates that are doing the drilling in addition to Concho at this point in time. I believe there are 4 incremental horizontals to our Red Headed Stranger. As to using the Red Headed Stranger data, absolutely, we're continuing to evaluate both the rock data and then our completion of stimulation results up there as we think about our next well. The Midnight Rider is a permit. We are evaluating data from the Red Headed Stranger and are continuing to evaluate locations for a go forward drilling.

Operator

Your next question comes from the line of Scott Hanold with RBC Capital Markets.

Scott Hanold - RBC Capital Markets, LLC, Research Division

When looking at some of that horizontal Yeso activity you have right now, you say IRR is in that sort of 40-plus range at $85 per barrel and that seems surprisingly pretty strong and actually, when I look at some of your returns that you provide on your slide deck, it's competitive to basically your other core areas. Can you kind of give a sense or color on what it really would take for you guys to think about turning that horizontal play primarily and accelerating the activity more?

Timothy A. Leach

The Yeso? Yes. Well, I mean in Yeso play, we drilled 1,000 wells vertically on 10-acre spacing, so the horizontal was a nice surprise, but it really gives us the opportunity for expansion of the size of the play. It's hard to go back on existing areas that are drilled up and really accelerate. So I think up there, you can think about it more, I think there'll be expansion on the margins. I mentioned that we -- that Abo acreage, we kept the Yeso rights, well that -- as you move North, that we have a pretty good block of acreage that way. But I think the better way to think about it is just -- of our remaining vertical locations, how many of those can be converted and made more efficient through horizontal drilling. And if I was going to direct you to expansion, I would say the expansion acceleration is taking place more in the Delaware Basin, to the South, with the Bone Spring, and then we're pretty excited about what we're seeing in the Southern Delaware with the new wells down there.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay. So just for me to clarify. So really, the opportunity in the horizontal stuff is in the margins because development is done so tightly in the core Yeso play. Is that a fair statement?

Timothy A. Leach

Yes, I think that's right. I mean, we've identified like 300 and something locations there that are $3 million to $4 million apiece. They have great economics, but we're talking about thousands of locations to the South that are more capital intensive and -- so that's where the real impact of the company is going to come from.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay.

Operator

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

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

Did you guys give a infrastructure constraint number, meaning how much production was constrained in the quarter? Or could you give that, if you haven't.

E. Joseph Wright

No, we didn't. We haven't quantified that or...

Unknown Executive

We weren't constrained, except from line pressures, which is... that it's hard to quantify that number, right?

E. Joseph Wright

Just an ongoing...

Jack F. Harper

It happens every day.

E. Joseph Wright

Every day. Right.

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

Okay. All right. Fair enough. And then, Tim, in the Northern Delaware, you talked a lot about the other zones, but have you guys done a lot in the Delaware Sands or the Penn in the Northern Delaware?

Timothy A. Leach

The Delaware Sands, we've only drilled a handful of wells and that looks like potential and looks successful. The Penn Shale is much deeper and, no, we haven't really brought on any wells from the Penn.

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

So all the focus for next year is going to be in Avalon, the Bone Spring and the Wolfcamp?

Timothy A. Leach

That's right.

Operator

There are no additional questions at this time. I would now like to turn the presentation back to Mr. Tim Leach for closing remarks.

Timothy A. Leach

All right. Well, I think we had a great list of people attending this call. So thank you very much. Again, as far as the metrics go, I think we've turned in a quarter that we are pleased with the production and the cost and, I think, it builds momentum into the fourth quarter and going into next year. So I hope you can tell from our discussion that we're pretty enthusiastic about the fundamentals of our business and I appreciate all the good questions. Thank you very much.

Operator

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

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