Concho Resources Management Discusses Q2 2013 Results - Earnings Call Transcript

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

Concho Resources (NYSE:CXO)

Q2 2013 Earnings Call

August 08, 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

Andrew Venker - Morgan Stanley, Research Division

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

Phillip Jungwirth - BMO Capital Markets U.S.

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

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

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Ryan Todd - Deutsche Bank AG, Research Division

Michael Kelly - Global Hunter Securities, LLC, Research Division

Arun Jayaram - Crédit Suisse AG, Research Division

Mostafa Dahhane - Wunderlich Securities Inc., Research Division

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Jason Smith - BofA Merrill Lynch, Research Division

Louis Baltimore - Macquarie Research

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

Brian Singer - Goldman Sachs Group Inc., Research Division

Eli J. Kantor - Iberia Capital Partners, Research Division

Operator

Good day, ladies and gentlemen, and welcome to the Concho Second Quarter Earnings Conference Call. My name is Leanne, and I will be your operator for today. [Operator Instructions] As a reminder, this call is being recorded. I would now like to turn the call over to Price Moncrief, Vice President of Capital Markets and Strategy. Please go ahead.

L. Price Moncrief

Good morning. Thank you for joining us today for Concho's second quarter conference call. I'd like to take a minute to direct your attention to the forward-looking statement disclaimer contained in the press release. In summary, it states 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 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.

On today's call, I'm joined by Tim Leach, our Chairman, President and CEO, as well as other members of our management team who will be available to take questions.

Before we get started, I'd like to point out that in addition to our earnings release, we have posted a slide deck to accompany this conference call, which can be found in our website at concho.com.

On the agenda today, Tim will cover our second quarter results and highlights before getting into an operations update. We'll conclude with an outlook on our expected drilling activity for the remainder of the year and then move to Q&A.

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

Timothy A. Leach

Good morning. I hope everyone has had a chance to download the earnings call presentation and can follow along starting on Slide #3. The second quarter was an outstanding quarter for Concho. Production, cash flow and earnings all grew meaningfully over the previous quarter due in large part to a solid jump in crude oil volume. Additionally, the team executed well, completing about 175 operated wells, including a record number of horizontal wells in a single quarter.

You may have heard me say this before, but it's a great time to be a Permian-focused company. Slide 4 really makes that case. We accomplished quite a bit during the second quarter. Our cash margin, which is a critical component of our growth strategy, rebounded following a period of Permian oil takeaway challenges that affected our realizations.

In the Delaware Basin, we achieved 2 major milestones. For the first time, the Delaware Basin eclipsed the New Mexico Shelf as our largest core area in terms of production. That's an amazing accomplishment when you consider this core area is just a little over 2 years old.

Another notable milestone is that our horizontal production in the Delaware Basin grew 37% over the previous quarter, which represents our highest quarter-over-quarter growth to date, not an easy task considering the size of the production base. With respect to overall production growth, it's important to note that our growth is crude oil-driven. Over the last 4 quarters, crude oil has increased 22% and now represents 63% of our overall mix, the highest crude oil mix for Concho in 2 years.

Another encouraging thing is that our oil growth is coming from the Delaware Basin, which is our fastest-growing area. Our rapid growth in the Delaware is directly related to the strength of our operations and technical teams. They are best in the Permian. In the Northern Delaware Basin, we brought on 35 new wells with average rates that continue to set records. And our de-risking effort in the Southern Delaware Basin is paying off. Following some solid early wells, we've identified an initial set of horizontal location 6 months ahead of schedule. The Delaware Basin is truly a remarkable asset, and I expect we'll be busy there for many decades.

For those of you who have been focused on the excitement in the Midland Basin, let me remind you that we have a significant position there, too. In fact, our early horizontal Wolfcamp results in the Wolfberry play are among the best in the industry. So we're planning to expand our activity there through the rest of '13.

Finally, we've clearly had lots of horizontal success over the last few months, and later on this call, I will outline our plan for the rest of '13 with respect to capital allocation within our $1.6 billion budget.

Let's turn now to Slide #5. I mentioned earlier that cash margin is a critical component of our growth, so it's worth looking at this a little closer. Our cash margin has returned to its historic level following an unprecedented widening of the Midland-to-Cushing basis differential. We have the highest cash margin in one of the lowest cost structures among all of our Permian peers. No one in the Permian is capable of recycling cash as efficiently and quickly as Concho. What sets us apart from the pack is our crude oil weighted production mix and our focus on keeping costs as low as possible for a growing organization. This is a key measure of our success.

Let's shift gears and move on to an operational update starting on Slide #6. The New Mexico Shelf has been and remains a key asset for Concho, having drilled over 1,500 wells there and identified over 1,700 remaining high rate of return drilling opportunities. It was this asset base that allowed us to go public exactly 6 years ago, and it's the platform that has enabled us to go in other parts of the Permian, including the Delaware and Midland Basins. Given the high-quality nature of these assets and its manufacturing-like operation, industry activities reached a level that current midstream infrastructure struggles to support. Historically, we've been able to account for things like extended plant turnarounds and high line pressures in our production guidance, but the challenges today are beyond those risk assumptions.

As an example, a 15-mile high pressure gas line operated by Frontier Field Services failed after only a few years of service. That line is in a critical area of our shelf asset and was moving about 25% of our shelf volume. In addition, new plant expansions have been delayed. We estimate that the impact to our production due to midstream challenges was approximately 375,000 Boes year-to-date. And if these conditions persists, we expect the full year impact of approximately 700,000 equivalent barrels.

Our midstream service providers are working diligently to resolve these issues. However, until we see meaningful relief in the system, we will continue to operate at a restricted level. We're currently running one horizontal rig in the Yeso, down from 5 during the first half of the year, and we're reallocating Yeso drilling dollars to our horizontal drilling operations in the Delaware and Midland Basins.

With respect to our ability to grow overall production, I don't see these midstream challenges as an issue we can't overcome. Over the last couple of years, we've actively allocated bigger -- a bigger component of our capital budget to areas like the Delaware, which is our most significant growth driver.

So let's turn to Slide 7 and talk about the Delaware Basin, which is performing like the most prolific oil basin in the Permian. There seems to be a lot of focus these days on big initial rates and big resource capture, yet it seems to us that it's time to talk about execution and real and measurable results. I'm going to talk about big rates in just a few minutes, but I want to start off by talking about the results.

Exactly 1 year ago, during the second quarter 2012 conference call, I outlined a plan that called for a strategic shift in our drilling program to accelerate the development of our more capital-efficient, higher rate of return horizontal operations in the Delaware Basin. We laid down some vertical rigs in our legacy Yeso and Wolfberry plays and stayed on budget through the end of 2012. And in just 1 year, we have more than doubled our horizontal Delaware Basin production, which now stands at 32,000 Boes per day. Our quarter-over-quarter growth from the horizontal Delaware Basin has never been as high as it was this most recent quarter at 37%. But the most notable trend here is the progression of our crude oil production mix. A year ago, crude oil represented about 50% of our production from this asset and now stands at 63%. So while our horizontal Delaware production more than doubled in a year, our oil production nearly tripled.

The performance of this asset continues to exceed our expectations. Not only is the Delaware production compensating for the midstream challenges in the shelf, but it's also carrying the overall growth of the company. We're not adjusting our full year production guidance at this time as we expect to finish the year within our range. However, 700,000 Boe impact to production in the shelf is not immaterial and can be the difference between finishing at the high end or the low end of our guidance.

I promised I would talk to you about rates, so let's turn to Slide 8 and take a look at what's driving our results in the Northern Delaware Basin. At Concho, we continue to emphasize the relevance of 30-day initial rates as an indicator of well performance. But for those of you that track and compare 24-hour rates, we now have something for you, too. Let me start off by putting this slide into context. Since 2011, Concho has drilled and completed 184 horizontal wells in the Northern Delaware with an average lateral length of 4,193 feet. The average 30-day rate of all those wells is 739 Boes per day, 67% oil. And the average 24-hour peak rate on those same wells is 1,224 Boes per day. Again, that's over 1,200 Boes per day from 184 wells with 4,200-foot laterals. And as you can see from this slide, our well productivity and oil mix has consistently improved quarter-over-quarter since 2012.

Now I'm going to rattle off a whole bunch of statistics that I think you'll find interesting. If you don't keep up, don't worry, I'll be happy to repeat myself in the Q&A. During our most recent quarter, we added 35 new wells with an average 30-day rate of 857 Boes per day, 77% oil, and an average 24-hour peak rate of just over 1,400 Boes per day. Both of those average rates represent the highest rates we've achieved in a single quarter. Those wells included 3 extended length laterals and 1 dual lateral, but the average lateral length of all 35 was a little over 4,400 feet. 31 of those 35 most recent wells had 24-hour peak rates of at least 1,000 Boes per day, and 20 of those same 35 wells had a 24-hour peak crude oil rate alone of at least 1,000 barrels per day.

The majority of our success has come in the Bone Spring sand. However, as you can see from the table at the bottom the slide, we've had great success across all zones, including the shallower Brushy Canyon zone. Our first 2 Brushy Canyon wells look good. We plan to drill around 8 more before the end of the year. As a reminder, our entire Northern Delaware inventory at year-end '12 consisted primarily of Avalon, Bone Spring and Wolfcamp. I think we're just beginning to appreciate the productive capacity of the Northern Delaware. It's not hype. It's based on consistently better well performance and proven results.

Let's move on to Slide 9 and talk about the Southern Delaware where we've had some very encouraging results on our first 11 horizontal wells. As you can see on the slide, those wells had an average 30-day rate of 691 Boes per day, 78% oil, and an average 24-hour peak rate of 1,082 Boes per day. Our average lateral length was 4,182 feet. The map illustrates where our wells are located, and based on that data, we feel that we de-risked about 20% of our total net acreage in the Southern Delaware for the Upper Wolfcamp zone.

I know we've been saying that our plan was to get to the end of the year before talking about drilling inventory in the South, but we're going to get a headstart on it now. The team has identified 200 gross locations on our de-risked acreage in North Harpoon and Big Chief, all of which are targeting the Upper Wolfcamp. Over half those locations assume longer laterals of approximately 8,000 feet. Our cost in EURs are dependent on prospect area and lateral length, and you can see our range is roughly 500,000 to 700,000 equivalent barrels, 75% oil at $8.5 million to $10.5 million per well. For the balance of the year, we will continue to test the productive extent of our acreages as well as other prospective zones like the Delaware sands, the Avalon, Bone Spring and Middle Wolfcamp.

Let's move on to Slide 10 and talk about the Midland Basin and our horizontal Wolfberry program. Four of our horizontal Wolfberry wells are currently producing. We're very pleased with the early results. They had an average 30-day rate of 742 Boes per day, 74% oil, and an average 24-hour peak rate of 1,010 Boes per day. The average lateral length was only 3,975 feet. So these wells are among the best in the Midland Basin. I'd like to point out that 2 of our horizontal producers were drilled across vertical Wolfberry, 20-acre in-fill locations. This is just one of the concepts we're testing across our core Wolfberry position. All of our existing wells landed in the Wolfcamp A or B, but we'll also test other zones in the Wolfcamp and even the Spraberry for horizontal development. We're also planning to push outside of Upton County and test Ector, Andrews and possibly Midland counties before the end of the year. In total, I expect we will have 15 or 16 horizontal Wolfberry wells by year end.

Let's turn to Slide 11 now and quickly take a look at our planned activity level and how we expect to spend the remainder of our '13 capital budget. As you can see, we expect to average 10 fewer rigs in the second half of the year than we averaged during the second quarter. However, that drop in rig count is all vertical. In fact, we will average one more horizontal rig in the second half, and our rig count mix will be over 80% horizontal. We've already dropped our rig count in the New Mexico Shelf in response to the midstream challenges and dropped our vertical rig count in the Texas Permian. We're picking up horizontal rigs in the Delaware Basin and the Texas Permian. This plan should allow for us to land our '13 capital budget and position us for future horizontal growth in our key strategic core areas.

Let me wrap up on Slide 12. It's a great time to be in the Permian Basin. There's so much activity and new ideas that are being tested all over this oil-rich region, and the widespread success has put the Permian back on the map. And I've never been more convinced that we have the best assets and people in the Permian. We have significant resource exposure in both the Delaware and Midland Basins. Besides having the highest-quality assets across the Permian, the key differentiating factor for Concho is our ability to execute and deliver exceptional growth year after year.

The fact that we drill many of the best IPs in both the Delaware and the Midland Basins is noteworthy. However, we're especially proud of our production growth and cash margin. The next few years will be very exciting for Concho. We have the perfect combination of an opportunity-rich asset base and unmatched profitability, which provides us with significant flexibility on how we chose to execute our plan. So clearly, we're well positioned to grow our drilling operations and firmly establish ourselves as a leading Permian Basin operator.

I appreciate your continued interest in Concho, and now I'd like to turn this call back over to the moderator and take questions.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from Scott Hanold from RBC.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Can you talk in terms of -- when you look at the Northern Delaware Basin, obviously, Wolfcamp is present there and you've got, I guess, roughly about a dozen wells there. And correct me if I'm wrong, there is some more parts of that trend that are a little bit more oily. Can you tell us if you do see some of that on your acreage and if there are a variety of ventures [ph] within the Wolfcamp that's also prospective in the Northern Delaware?

Timothy A. Leach

Yes. Well, let me remind you that what we're drilling in the South, Scott, is all Wolfcamp, and it's very oily. The wells that we've drilled up in the Northern Delaware tend to have a higher gas content but are prolific as well. So I think that we have lots of opportunity in Wolfcamp. We're just focusing more on the second Bone Spring at this time, and that seems to have the highest oil content than anything we're doing up there.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay, okay, fair enough. And just as a follow-up. On some of the long laterals that you all are drilling, can you talk in terms of like relative performance of long laterals from the history you have? I mean, do you see -- based on the well cost, if that optimally the way you think that you can -- you're going to try to develop it if you can?

Timothy A. Leach

Yes. I think our technical teams believe on all of our 4 core assets drilling long laterals is the most efficient way to produce the oil. And so where we have the land position and where we can, we're going to drill extended length laterals. And we think that you're getting the 2x, the production at maybe 1.5x the cost, and it raises the rate of return and has a smaller surface footprint.

Scott Hanold - RBC Capital Markets, LLC, Research Division

So if you're getting that kind of improvement for the cost, I mean, what does that mean for IRRs if -- I forget. Is it like mid-40s for your base kind of well case there? Does that get it up into the 60s?

Timothy A. Leach

60s or higher.

Operator

Your next question comes from Drew Venker from Morgan Stanley.

Andrew Venker - Morgan Stanley, Research Division

I was hoping -- you've obviously had good results on both sides of the Permian. I was hoping you could discuss your thinking on the Midland side. I think in the past, you maybe have been considering some [ph] depletion in your Wolfberry area from your existing drilling. Does the results you've seen so far in that in-fill area kind of change your mind there? Or do you want to see more production history?

Timothy A. Leach

Yes. Let me say that the success we've had with the horizontal in the Midland Basin was one of the reasons we laid down so many of our vertical rigs. And I think we're concluding that where we can, drilling horizontal may be the most effective way to harvest those properties. On our vertical drilling program, as we talked to you in the past about going from 80s to 40s to 20-acre spacing, there was an assumption about drainage as you down space and that as we went into this horizontal program, and that's why I mentioned that we laid this horizontal down, down a row of 20-acre space locations. So the big question was, were you going to see any drainage? And the answer is we haven't seen any drainage yet. Admittedly, it's early times. But the offset wells didn't -- haven't been affected, and the horizontal didn't appear to be drained. And I'll just remind you, I mean, we're laying this horizontal down in one zone. The verticals are completed in multi-zones. So if you're talking about drainage, it would be in one zone alone.

Andrew Venker - Morgan Stanley, Research Division

And Tim, how long has that well been on production?

Timothy A. Leach

One month.

Unknown Executive

One year.

Timothy A. Leach

No, no, no. I'm sorry, one year.

Andrew Venker - Morgan Stanley, Research Division

Okay. So consistent so far with other horizontals that you guys have drilled?

Timothy A. Leach

We're encouraged enough that we're stopping vertical program to a large extent, and we plan to drill a lot more horizontal wells.

Andrew Venker - Morgan Stanley, Research Division

Okay. Do see any opportunity to expand your position there? Or is that something you're interested in?

Timothy A. Leach

I'm always interested in expanding my position.

Operator

Your next question comes from David Deckelbaum from KeyBanc.

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

Specifically, Tim, you mentioned earlier that you're a little bit early in terms of talking about location count here. Can you elaborate a little bit more on why you chose to talk about it now versus the end of the year? Do you feel is it more a sense that you've de-risked most of your horizontal locations across the acreage? And I guess should we expect -- I guess, going forward now, obviously, you've high graded horizontal side. As we go into 2014, should we think about that more of a year that includes minimal de-risking activity?

Timothy A. Leach

No. I think there will continue to be a lot of de-risking. We have a large acreage position. We've said before, part of our caution about talking about the South was, one, we wanted to understand it first. And two, it was competitive situation. A lot -- we've drilled a lot of wells down there. I think I talked about 11 wells. A lot of that production is coming out in public information now. So I think it's appropriate at this time to provide some commentary to help you -- give you some insight on how we're thinking about it and to help you think about it. That whole area is not fully de-risked, but we've had a lot of great success down there. The original concept was that the Southern Delaware Basin would have production characteristics like the North. We think that's -- that theory is proving out. We're encouraged by it.

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

Sure. I appreciate that. I guess -- obviously, you've reduced your rig count along the shelf due to facility constraints. In your experience so far with the horizontal Yeso, how do you view those wells in terms of how they've progressed relative to the Delaware and Midland opportunities?

Timothy A. Leach

Yes. Well, on the shelf, the shelf had been drilled vertically to a pretty dense pattern. So the places we're applying horizontals were in extension areas primarily or in areas where we didn't have all the zones present that we were capturing vertically. The horizontals on the shelf have worked great, and we just -- we're in the early stages of applying that technology on the shelf. That was kind of the last place we started drilling horizontals.

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

Sure. And then my last question is just in relation to CapEx, you guys have obviously been running a bit ahead of the budget of $1.6 billion so far. Now you're reworking the rig count a little bit, but you are adding some net horizontal rigs. As you go through the rest of the year, could you sort of walk us through how you see CapEx trending? And are there well cost savings baked into that, less science work? Or is there a more of a gradual decline into the fourth quarter in terms of completions?

Timothy A. Leach

Yes, yes. Those were a lot of questions strung together. Let me kind of give you just my stream of consciousness on our capital budget. As we went into '13, it was very similar to '12 and '11. As we plan out our activity, we tend to front-end load the year and get as much done in the first half of the year as we can so that you leave yourself room to make midyear corrections, either to increase or decrease the pace based on changing conditions. That's no different than it has been in the past. This year, we're seeing improved efficiencies. The wells are getting drilled faster and cheaper. The cost savings are driven both by the efficiencies we're seeing in drilling the wells and just overall costs coming down. We may be, since the first of the year, on cost, down 15%, which is helpful. So the second half of the year -- the wells that we drilled in the first half of the year, the activity we had in the first half of the year really sets up the second half of the year well for production. You get all those wells online. We've been completing a lot of wells each quarter. So the second half of the year still will be dominated by horizontal drilling, and it's kind of a planned landing of our capital budget where we said we're going to land it, and I think we're going to be pleased with the production that comes from all of these big wells we're drilling.

Operator

Your next question comes from Phillip Jungwirth from BMO Capital Markets.

Phillip Jungwirth - BMO Capital Markets U.S.

Given the high number of wells completed in the second quarter and the reallocation of rig count, dropping verticals, adding horizontals, how many wells, both vertical and horizontal, do you think you'll be able to complete and bring on production by year end?

Timothy A. Leach

You mean for the full year?

Phillip Jungwirth - BMO Capital Markets U.S.

Just second half. Or for the full year.

Timothy A. Leach

Second half?

Phillip Jungwirth - BMO Capital Markets U.S.

Yes, second half.

Timothy A. Leach

Let me look around the table, see if anybody's got that data. I don't have the data at hand in terms of how many total wells we'll complete between now and the end of the year. But also keep in mind, as we lay those rigs down, we've still got to complete the wells that they drilled. Our completion numbers per quarter may not be as high as it was in the second quarter, but it's still going to be very high as we kind of finish up. The fourth quarter, we'll probably be down . That will be the quarter you'll start seeing some reduced completion on those vertical -- that we won't have the -- to complete the vertical wells.

Phillip Jungwirth - BMO Capital Markets U.S.

And can you tell us what the base decline rate is on the New Mexico Shelf? And then you talked about eventually resuming normal drilling. When do you think that will be? And then how many rigs would you consider to be normal drilling up there, given all the horizontal opportunity you now have?

Timothy A. Leach

When you're in this condition with restricted takeaway, the base decline rate, it's kind of a complicated answer that I'm going to give you. But we've been constrained up there, so we haven't really -- the natural decline rate has been masked by shut-ins and restrictions. So -- and quite frankly, that's the reason to lay rigs down. There's no reason to add productive capacity up there if you can't move it at the moment. Now we think all of that is going to resolve itself fairly quickly, and I think that's the upside for the year. When you think about where we're going to land production for the year, it's going to be -- I mean, the Delaware Basin has really been performing well, and it's even made up for the production restrictions we've had on the shelf. When the shelf comes back on, I think that's going to be the swing factor for how well the year turns out.

Phillip Jungwirth - BMO Capital Markets U.S.

And then last question, on the Southern Delaware, how did the decline rate on the 11 wells that you have on production compare to what you've experienced in the Northern Delaware to date?

Timothy A. Leach

About the same.

Operator

And your next question comes from John Freeman from Raymond James.

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

On the Northern Delaware Basin, your original sort of Bone Spring EUR guidance was based on a 650 barrel a day 30-day average. And just looking at these recent wells, they're closer to, call it, 850, and that's even before the benefit of more of these extended reach laterals that you've only done a few of on so far. I'm just trying to get a sense of when you think you'd have enough data to where maybe you'd want to revisit, kind of update the guidance on the EURs in that area.

Timothy A. Leach

Yes, probably end of the year. And I mean, we're clearly upwardly biased on that kind of early time data. But we'll go through that process with our third-party engineers, and those things, I would expect them to be changing toward the end of the year.

Unknown Executive

John, none of those type curves in the Northern Delaware contemplate extended length laterals either.

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

Right. And along those lines, could you give me just sort of some color for maybe how the mix changes and maybe like the third quarter? Like if this quarter, if you exclude the dual laterals, you had, call it, just a few -- 3 of these extended reach laterals. Like kind of just ballpark, how many of those are you doing in the third quarter?

E. Joseph Wright

This is Joe. About 20% of our horizontal drilling is extended lateral. So when you think about kind of that makeup, I'd look around 20% today. Everything in the South Delaware, we're really moving towards full 2-mile laterals down there. So that will go up slightly.

Timothy A. Leach

And about 20% in the North.

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

I'm sorry, was it -- did you say 20% kind of just across the board, it was 20% in the north as well?

Timothy A. Leach

He was saying 20% in the North and 100% in the South.

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

Okay, got it. And then last question for me. I'll turn it over to somebody else. Just what's the current spud to sales times running in the Northern Delaware?

E. Joseph Wright

90 days, a little less. We use 90 days when we do our projections.

Operator

And your next question comes from Pearce Hammond from Simmons & Company.

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

Tim, I wanted to get some thoughts from you on the Brushy Canyon. 2 good wells there. If you can provide a little more color. Do you think this extends across your acreage throughout the Northern Delaware Basin?

Timothy A. Leach

One of the good things about Concho is we have a big acreage position in the Northern Delaware. The Brushy in places in New Mexico has been completed prolifically vertically. So there's some Brushy Canyon fields that are vertical developments and historic fields. I think our thinking is that in -- it will be more -- isolated location is not the right word, but it's going to have something to do with structure and stratigraphy as opposed to an unconventional type of reservoir.

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

And then my follow-up...

Timothy A. Leach

Let me say, though, I think it's going to be important to us. I don't think this is just a one-off type of opportunity. I think it's going to be important to us. It's going to be a little bit different than the other zones.

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

Great. And then my follow-up is as you start your budgeting process for 2014, given the level of interest within the industry for both the Midland the Delaware Basin, how do you see service costs trending for next year?

Timothy A. Leach

I think they're trending downward. And there's 2 components. There's service cost, what is one-stage frac cost; and then there's just how efficient are you, how long does it take you to drill that well, how does it take you to -- how efficient are you at moving around those frac spreads. But I think the trend is downward.

Operator

Your next question comes from Matt Portillo from Tudor, Pickering, Holt.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Just 2 quick questions for me. In terms of the Midland Basin, I was hoping you could give us a little bit of breakdown on your acreage exposure in the Wolfcamp in particular. And then just a second question, as you guys have drilled some sort of laterals here, the industry looks like they're moving towards longer lateral completion in the Midland. And I was hoping that you could give us some color on your plans to potentially extend laterals on the Midland side as well.

Timothy A. Leach

Okay. Our acreage position in the Midland Basin for the horizontal Wolfcamp is about 170,000 gross acres, and our ownership is a little bit over 50%, on average. And the laterals we're drilling, I guess, most of those have been relatively short laterals. It's all -- we would drill as long as a lateral is possible. It's all dictated by the shape of your leases and can you pull these things together. But I don't think that we're going to drill as many long laterals in the Midland Basin as what we do in the Southern Delaware, for sure, and maybe in the Northern Delaware.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Great. And just to clarify, that 170, that's primarily in Upton, Midland and Andrews County?

Timothy A. Leach

That's correct.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Perfect. And then just in terms of your well cost in the Southern Delaware, kind of the $8.5 million to $10 million well cost. We've obviously seen the industry and yourselves do a great job of driving down costs over time. I was hoping you may give a little color in terms of how those well costs may trend over time and how you think about maybe the technical limitations to bringing down those costs?

Timothy A. Leach

That's always a hard prediction to make since you're promising things from other people. But I mean, historically, as infrastructures improve, technologies improve, we don't have do drill a pilot hole for every well. We get a better understanding of all the surface conditions on drilling a shallow hole. You'd hope you'll be able -- I mean, you can look at other areas and kind of draw an analogy from other areas, and maybe 10% to 15% more over time as it turns into a manufacturing operation.

Operator

Your next question comes from Ryan Todd from Deutsche Bank.

Ryan Todd - Deutsche Bank AG, Research Division

A couple of quick ones. In the Midland Basin, we haven't talked much about the Eastern part of your acreage over in Glasscock and Irion. Any thoughts on what you've seen over there in activity levels? And then as we look into 2014, given the level of inventory that you have, particularly in the Delaware Basin, any thoughts about the potential, how you think about acceleration of activity level? Or is it purely going to be driven by operating cash flow?

Timothy A. Leach

Okay. Yes, I don't have any new news this quarter on our Eastern Midland Basin activity. We're still continuing to work both those areas, both in Glasscock County and in Irion County. We've got rigs running in both areas. It hasn't really -- we don't have the acreage position or the momentum there to really have that as a core area. But it's a good place to really observe what's going on in the East with the Wolfcamp and the Cline. And I really don't have any new information this quarter on that. As we go into 2014, I'll refer to some in my prepared comments about the flexibility that we see we have. Our balance sheet is strengthening. We're going to try to do as much activity as this Concho machine will allow us to do. And we have lots of good inventory to go invest and drill wells. So there's a lot of moving parts in our industry right now, though. I mean, lots of folks on this call are calling for much lower oil prices in '14. We'll watch that very carefully. We'll plan a budget that leaves us -- I mean, we hedge and do all that to try to protect our cash flow. But I think that barring that oil price falling out from under us, I think we're pretty feeling pretty good about what we're doing and kind of feeling that it's time to step on the accelerator.

Ryan Todd - Deutsche Bank AG, Research Division

That's great. And I mean, we've obviously seen improvements on the crude side. And how much this infrastructure at this point figure into your thoughts around acceleration? And are you still seeing many issues, infrastructure related, particularly in the Delaware Basin?

Timothy A. Leach

No. I mean, the infrastructure is doing a good job keeping up in the Delaware, and there's more competition for infrastructure in the Delaware Basin. And so that's been a good thing. And the nature of those wells allows us, if we choose, to invest a big part of our capital budget over there. So the issue we've seen in takeaway capacity on the shelf, we're in a good position where we can pretty quickly switch capital from one area to another. And again, we haven't seen those same kind of problems in the Delaware Basin.

Operator

Your next question comes from Mike Kelly from Global Hunter Securities.

Michael Kelly - Global Hunter Securities, LLC, Research Division

I was hoping to follow up on some of the earlier questions regarding your move to drill longer laterals. Really, I'd like to hear your expectations for 30-day rates in the Northern Delaware for wells that are drilled at 8,000 feet plus on the laterals. I guess I'm trying to translate what 857 Boe per day rate on the 4,000 lateral would compare to a lateral that's twice that length.

E. Joseph Wright

Certainly, our longest lateral that we've drilled hadn't been completed yet. So I wish I could give you a real good number from that. But generally, when you think about those lateral lengths, you can go anywhere from a 1.7x to 2x as you think about your EURs. Your IPs maybe a little bit -- a little different because just from a flow capacity kind of issues, service equipment and being able to lift that much fluid. But you will see somewhere between that 1.5x and 2x on an IP, I believe.

L. Price Moncrief

Mike, this is Price. Our most recent long laterals was a little over 8,000 feet. And it was about 2x kind of that average rate, 2x those average rates we quoted.

Michael Kelly - Global Hunter Securities, LLC, Research Division

All right, great. And a follow-up on that, just on costs, on the 4,000-foot lateral type of well versus one twice that.

E. Joseph Wright

Yes, I'd say usually what we'll see is 1.4x to 1.5x.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Got it, all right, great. In the Southern Delaware, the 200 wells that you've laid out here is -- there was inventory there. I was hoping you could break that up between the North Harpoon area and Big Chief.

E. Joseph Wright

The majority -- it's about half and half. And we have high interest in both of them. So when you think about a net, it's kind of 100% of Big Chief. It's probably about half and half.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Got it. If I could sneak one more in. As it pertains to the infrastructure constraints in the shelf, as that alleviates, is there potential to see production pop back pretty nicely, let's call it, maybe early 2014?

Timothy A. Leach

We're not banking on it, but it could happen sooner than that.

Operator

Your next question comes from Arun Jayaram from Crédit Suisse.

Arun Jayaram - Crédit Suisse AG, Research Division

Tim, I just wanted to ask you a little bit about as you shift towards more horizontal drilling from vertical drilling, does it bring any near-term challenges in terms of production just given longer spud to pop times for horizontal wells in general? Or is that baked in, in terms of your guidance, that shift?

Timothy A. Leach

Yes. Well, I think that is within the estimating accuracy. So it's baked in. And I mean, think -- in the entire industry and for Concho specifically, I mean, the drill times and the spud to -- all of that is getting much more efficient. So all those days are coming down.

Arun Jayaram - Crédit Suisse AG, Research Division

Okay. But in terms of your overall well count on horizontal side, how many more wells are you going to do with the new program versus your previous guidance? I think it was 175 range.

Timothy A. Leach

Do you know the answer to that?

L. Price Moncrief

Yes. I think when we think of horizontally the last half, we'll be well over 100. We'll be about 110 to 120 more completions within that.

Arun Jayaram - Crédit Suisse AG, Research Division

Okay, that's helpful. Just a clarification. Tim, I appreciate the additional disclosure. You talked a little bit about decline rates in Northern Delaware being similar to Southern Delaware. You have pretty similar IPs, 30-day rates for the Bone Spring versus the initial 11 wells in the South. Yet, the EURs are quite a bit different. Can you just maybe reconcile that or talk to us a little bit about maybe that delta there? I think your initial guidance for the Bone Spring was around 360 or so.

Timothy A. Leach

Yes. Well, it's early days to really be talking about EURs. And as you've seen our models go up, the EURs continue to increase. So as you think about ultimate recoveries, at least the way we're modeling it out and the way we look at the rocks, in the South, we got the South in hopes that it would be as good as the North. We think there's more oil in place in the South than there is in the North. Now, like I say, it's early time. And when you look at those EUR models, those things -- EURs change over time. And the decline rates -- I still -- the way I would think about all of that is I still think it's true that you get about 1/3 of your total EUR out in the first 2 or 3 years. To answer your question directly, the South, we're putting more in oil in the ground there, modeling-wise, as we've got in the North. That's one of the big attractions.

Arun Jayaram - Crédit Suisse AG, Research Division

Fair enough. And Just my last question was, Tim, the DD&A rate guidance went up a little bit. Is that just reflecting lower production given the infrastructure challenges on the shelf?

Timothy A. Leach

No, not really. that's not the big -- the big factor is all this horizontal drilling across the basin and specifically in the Southern Delaware, the amount of science and the amount of early time work you do kind of pops that DD&A.

Operator

Your next question comes from Irene Haas from Wunderlich Securities.

Mostafa Dahhane - Wunderlich Securities Inc., Research Division

Yes. This is Mo Dahhane in for Irene. I have 2 quick questions about Southern Delaware Basin. First question, do you see any consistency from the 11 Wolfcamp wells in Reeves County in terms of flow rates decline and oil and gas mix?

Timothy A. Leach

Did we see any -- what was it [ph]? Yes, yes, that's -- yes, we do. We're happy about consistency.

Mostafa Dahhane - Wunderlich Securities Inc., Research Division

Okay. Second question, what spacing have you assumed for the 200 locations for the Wolfcamp?

Timothy A. Leach

Well, on those long laterals, it's a little bit tricky to talk about spacing. But for modeling, I'd say 100 -- I would say 4 per section or a 160-acre spacing per zone.

Operator

Your next question comes from Joe Allman from JPMorgan.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

With the midstream issues on the shelf, Tim, is it just restricted to the New Frontier gas line? Or are there any other issues?

Timothy A. Leach

No, that's about it. Well, pressure has always been an issue, but I would tell you that DCP has done a great job on compression, and the big issue is just that one line.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Okay. And then in your guidance, what's the assumption about a recovery of those volumes?

Timothy A. Leach

Well, I mean, I kind of gave you the range. With no recovery, it's going to affect us a little bit over 700,000 barrels. And it's affected us 375,000 barrels so far through the first half of the year. They're working like crazy trying to get that thing fixed. And I think they're making good progress.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Okay. So the full year production guidance assumes a recovery at what point?

Timothy A. Leach

We're not assuming a recovery. It's -- our production guidance, the low end of the range is about 15% growth, and the high end of the range is about 20%. And we feel pretty confident we'll land in there.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Okay, I got you, okay. And then with Midland horizontal Wolfberry program, remind us how many wells. I think you're talking about 4 wells in your presentation. Are you seeing differences in productivity between the A and the B?

Timothy A. Leach

Oh, we haven't really drilled enough to draw any conclusions. We're going to have 15 to 16 more wells by the end of the year. But -- so I'd say, no, we don't have enough data to draw any conclusions about differences between those zones.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Okay. And then as you indicated earlier in the call, your verticals perforated different formations, and in your presentation, you indicated you're going to potentially try horizontals there. Do you see this potentially as an exclusive horizontal program for the different formations? Or do you think you're going to mix some horizontals with some verticals for some other zones?

Timothy A. Leach

It's complicated because some of the leases you have make it more difficult to drill horizontally. I think there will always be a mixture of horizontal and vertical. But I think with the enhancement in rate of return, I think us and the industry will try to drill horizontal wells as often as we can.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Okay. And then lastly, Tim, I think earlier you said that the lateral length in the Midland probably won't be as long as that in the Delaware Basin. So just confirm that that's what you said. And is that just because of just the lease configuration and your inability likely to block it up a whole lot more?

E. Joseph Wright

Yes, this is Joe. The Midland -- the thing about the Midland Basin and our Wolfberry acreage, it's very blocked up. But it's just going to take a little more land work for us to do extended laterals there. We will be doing some extended laterals there eventually. It's just going to take a little more work from the land side.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

So to put it in general, you think the laterals are going to be longer in the Delaware Basin versus the Midland?

E. Joseph Wright

I think Midland will be just as long as the North Delaware Basin.

Operator

Your next question comes from Jason Smith from Bank of America.

Jason Smith - BofA Merrill Lynch, Research Division

I know we covered a lot of grounds so far today. But I just wanted to touch on -- in the Southern Delaware, can you just remind us again what you guys -- how many rigs you guys need to run in order to hold your acreage there? And then maybe any other acreage issues you might have within the portfolio? I know you guys don't obviously talk much about the Northern Midland anymore. I mean, are you probably going to let that acreage expire? Or do you see yourself eventually going up there and trying to drill that up as well?

Timothy A. Leach

The Northern Midland is an exploration idea, and we are drilling and completing the well up there as we speak. So it's still -- I still think of that as an exploration idea. In the South, we've got how many?

E. Joseph Wright

We have 4 horizontals running in the South Delaware Basin. That is plenty of rigs to run for the North Harpoon and South Harpoon or what we call North Harpoon and Big G [ph]. That will cover any exploration there. And we're still working our further Southern acreage position down in Pecos, which now we've got 5 or 6 wells, a horizontal and some vertical wells in that. And we will continue to work that. It will require a few more rigs ultimately, but we have some time left on our leases there.

Operator

Your next question comes from Louis Baltimore from Macquarie.

Louis Baltimore - Macquarie Research

I've just got one question and a quick follow-up. Can you comment about any water production issues that you may have encountered, either in different formations or across the aerial extent of your acreage, maybe specifically in horizon above the Bone Spring? I think some other operators have talked about encountering issues with water hurting the economics despite strong oil production.

Timothy A. Leach

No, I don't really have a comment on that other than to say the way we're cored up and the way we have core areas, the cost of disposing the produced water is always an issue. And we think a big part of our program, and you can see in our capital budget, how much we allocate to facilities. Those facilities are predominantly saltwater disposal facilities. So we think that you need to be in the water disposal business as well as the oil production business in all of the areas. But I don't have a comment about -- if you're talking about above the Bone Spring, you'd be talking about the Delaware sands or part of the Avalon, I don't have a comment on water production there.

Louis Baltimore - Macquarie Research

Okay, great. And then I guess as far as vertical versus horizontal drilling goes, are there any continuous development clause, issues with leases that would limit your ability to transition further from vertical to horizontal, I guess, specifically maybe in the Midland Basin?

Timothy A. Leach

Yes, I mean, in all areas, there are leases with -- leases designed for vertical drilling with continuous development clauses, those you either have to continue to develop the way you are or renegotiate different terms. That's -- so the answer is technically yes. But I mean, it's not a huge part of our business. And that's why we've been able to lay down so many vertical rigs, because that's not a big factor.

Operator

Your next question comes from David Tameron from Wells Fargo.

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

Can I step back? A couple of bigger picture questions. Tim, you've always been candid about the M&A market. Can you just comment on where that is relative to 6 months ago or even a year ago? Just give us any highlights on that. And then I've got a follow-up.

Timothy A. Leach

Yes. I think the big forces that you and I talked about being at work in the past are still there, the consolidation forces and the importance of having the companies that have the ability to execute and drill all these wells. So there's a lot of things in the market. There's a lot of properties that are owned by companies that really aren't and never were intended to be the ones that fully develop these assets. So it implies over time that there's going to have to be a lot of consolidation. The bid-ask spread is just enormous right now, and I think that slows down transactions. And as everybody is trying to figure things out, one of the reasons the bid-ask spread is so large is that most of the traditional acquirers have plenty of inventory right now. So the need to add inventory at a high cost is kind of low. And so there's kind of a disconnect right now, I think, in the M&A market.

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

Okay, that's helpful. And then second, there's a lot of talk about your long-term growth rate, you can't hit what you used to, and then I hear you're saying, "step on the accelerator." Can you just -- if you care to comment on...

Timothy A. Leach

All those rumors you mentioned are just a bunch of bull. That's my first comment. Our ability to grow through the drillbit is as good as it's ever been, maybe better.

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

Are you still at that 15% to 20% kind of long-term target, is that where we're at?

Timothy A. Leach

I think with the kind of a productivity we have, if we can't do better than that, there's something wrong with us.

Operator

Your next question comes from Brian Singer from Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc., Research Division

In the Delaware Basin, the production mix looks like it has become a bit more oilier here and that it looks like it was the driver of total company oil production becoming a bit more oily. And it seems like it might have been above and beyond just drilling offsetting the Three Rivers acquisition when we look at your IPs from some of your Northern Delaware horizontal wells that have seen greater oil content. Is there any secular factors that are driving this? And then should we expect your oil mix to move back down slightly towards the midpoint of your guidance?

Timothy A. Leach

I think the answer to all that is no. We're drilling a lot of big oil wells. And I'll also point out that when we talk about our oil mix being at 63% that's crude oil. If you add in the natural gas liquids, we're still like a 90% liquids company. So, no. I mean, what's driving the company's growth in oil is all this drilling we're doing in the Delaware Basin. I don't see that changing. It will probably continue to decline.

Brian Singer - Goldman Sachs Group Inc., Research Division

Okay. The Delaware wells themselves look like they've gotten oilier. Is that just temporary on the IPs? Or do you see anything unique to the horizontal Delaware wells you're drilling where they're oilier than you expected? Or is it just geographically timing issues?

Timothy A. Leach

Well, if you remember, if you've been following us, when we started 2012 and when this play really started, the first wells were Western Avalon Shale wells or Wolfcamp wells, and those were gassy. So I mean, the first kind of half of 2012, we brought on some pretty big gas wells. We moved away from that, went to other zones. And so there are some zones that are gassy. The economics still may be pretty good in those zones, but for now, we're really focusing on the oil zones.

Brian Singer - Goldman Sachs Group Inc., Research Division

That's great. And then shifting to the Midland Basin. What do you expect or what should we expect of the impact, the net impacts to be from the drop that you're planning of your vertical rigs and the increase you're planning from the horizontal rigs on your production? And when we think about how you've gotten more positive here, is that just a function of the well results that you've seen yourself drill or from industry as well?

Timothy A. Leach

No. As far as that portion of our business, they've been running ahead of schedule. They've been doing a great job. Even as we drop rigs, with the addition of these horizontals, they'll stay on plan, if not ahead of plan. And it's hard to overstate the impact of drilling a 1,500 barrel a day well and having a big interest in it and having a lot of those to do. So that's why we're excited about our opportunities going forward, and that's why we think instead of drilling a bunch of vertical small wells, these bigger wells can really drive our growth.

Operator

We have a question from David Deckelbaum from KeyBanc.

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

Tim, I just have a quick follow-up. You talked about the Northern Midland Delaware -- sorry, Northern Midland Basin sort of still in exploration mode. I know at one time you all were considering looking at a JV partner there. Is that still on the table at all? Or are there any other areas that you'd prefer to have a JV partner in to sort of defray some of the exploration risk?

Timothy A. Leach

I wouldn't comment on any deal like that. Those wells we are drilling in the Northern Midland Basin, though, we don't own 100% of. So we have partners in those wells.

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

Okay. And should we expect to see any other -- after the sale at the end of last year, should we expect any other proactive pruning of any meaningful size in the near future?

Timothy A. Leach

No. We like what we got.

Operator

And your next question comes from Eli Kantor from Iberia Capital Partners.

Eli J. Kantor - Iberia Capital Partners, Research Division

Just a couple of questions on South Delaware. You mentioned 4 additional zones, Delaware sands, Avalon, Bone Spring, Middle Wolfcamp. Which of those provides the most optimism in being able to implement a full scale development program?

Timothy A. Leach

It's early. It's very similar to what it was like in the North. But I would say today, our view is the Bone Spring sands is kind of the next target.

Eli J. Kantor - Iberia Capital Partners, Research Division

On your last quarter's conference call, you mentioned you had completed one well into the Bone Spring. Do you have a peak month rate and the oil mix for that well?

Timothy A. Leach

No. We're not going to talk about that well or single well performance.

Eli J. Kantor - Iberia Capital Partners, Research Division

Okay. Any sense of timing for the next inventory update for South Delaware?

Timothy A. Leach

End of the year, yes. And we'll have a lot more activity and more data by the end of the year.

Operator

I would now like to turn the call over to Tim for closing remarks.

Timothy A. Leach

All right, great. We did cover lots of ground today. I appreciate your attention. I hope this information is useful to you. I hope you can detect how good I feel about it. So thanks for your participation in the call. I look forward to talking to you next quarter. Thanks.

Operator

Thank you, and thank you for your participation in today's conference. This concludes the presentation. You may now disconnect, and have a great day.

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