Concho Resources Management Discusses Q3 2013 Results - Earnings Call Transcript

Nov. 7.13 | About: Concho Resources (CXO)

Concho Resources (NYSE:CXO)

Q3 2013 Earnings Call

November 07, 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

Matthew G. Hyde - Senior Vice President of Exploration

Analysts

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

Scott Hanold - RBC Capital Markets, LLC, Research Division

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

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

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

Ryan Todd - Deutsche Bank AG, Research Division

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

Brian Singer - Goldman Sachs Group Inc., Research Division

Joseph Bachmann - Howard Weil Incorporated, Research Division

Arun Jayaram - Crédit Suisse AG, Research Division

Mostafa Dahhane - Wunderlich Securities Inc., Research Division

John C. Nelson - Citigroup Inc, Research Division

Ipsit Mohanty - Canaccord Genuity, Research Division

Joseph Patrick Magner - Macquarie Research

Michael Kelly - Global Hunter Securities, LLC, Research Division

Operator

Good day, ladies and gentlemen, and welcome to the Third Quarter Concho Resources Earnings Conference Call. My name is Silia, 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 Strategy. Please proceed, sir.

L. Price Moncrief

Good morning. Thank you for joining Concho's third quarter conference call. I'd like to take a minute to direct your attention to the forward-looking statements disclaimer contained in the press release.

In summary, it says that statements in last night's press release and on this conference call, regarding 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 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 other filings with the SEC.

In addition, we will reference certain non-GAAP measures, so please see the reconciliations in our earnings release.

On today's call, I'm joined by Tim Leach, our Chairman, President and CEO.

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 on our website at concho.com.

On the agenda today, Tim will cover our third quarter results and highlights, provide an operations update, and discuss our 2014 capital budget and accelerated growth plan. Members of our management team will be available at the end of the call for Q&A.

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

Timothy A. Leach

Good morning. Both the management team and I are higher very excited to finally have an opportunity to provide some details around our plans to accelerate our growth and maximize our value for our stockholders. Before I do that, I'd ask you to follow along on the earnings call presentation starting on Slide 3.

The third quarter was an excellent quarter for Concho across the board. Our quarterly EBITDAX was the highest in the company's history at nearly $460 million, growing 7% over the previous quarter. Our growth in cash flow is due in large part to the ongoing growth of our oil-weighted production volumes. We averaged just under 95,000 Boes per day, representing 5% growth over the previous quarter and 19% over the third quarter of last year. As we look to the end of the year, we are tightening our full year '13 production guidance to 33.5 million to 34 million Boes, and expect our crude oil mix to settle just above 62%.

Our growth in crude oil over the last 4 quarters has driven our expansion in our cash margin and a reduction to our leverage ratio. That trend is reflective of our continued execution success across the Permian. We continue to deliver excellent results in the northern Delaware Basin, and we're making good progress with our horizontal programs, in both the southern Delaware and Midland Basins. It's hard to ignore all the momentum. Our success on our properties, combined with our financial strengths suggest that we have the capability and the capacity to increase our growth rate. So later on this call, I'll outline our plans to double our production by 2016, beginning with an accelerated 2014 capital budget of $2.3 billion.

Let's turn now to Slide 4. One of the most significant highlights from the quarter is our cash margin. On a non-hedge basis, we earned approximately $58 per equivalent barrel. High cash margins drive our plan. As we accelerate, our ability to maximize and reinvest profits will be critical. No one in the Permian is capable of recycling cash as efficiently and as quickly as Concho. We have the highest cash margin and one of the lowest cost structures among all of our Permian peers. What sets us apart is our crude oil-weighted production mix and our focus on keeping costs as low as possible for a growth company.

Let's move over to Slide 5 and begin our operational update with the Delaware Basin. You probably recall the second quarter, when we reported the Delaware grew 37% over the first quarter. That was an impressive accomplishment, but a really tough act to follow, especially, when you consider this asset now accounts for roughly 1/3 of our total production base. However, during the third quarter, the Delaware Basin did grow 6% over the previous quarter, and 111% over the third quarter of 2012. Much of the recent growth is in response to a strategic shift in our drilling program, which we initiated in 2012 to accelerate development in the Delaware Basin. Over the last 5 quarters, we've nearly doubled our rig count across the Delaware. The production response exceeded our expectations. Total volumes have more than doubled, and importantly, our oil volumes have nearly tripled. Thanks to the oily nature of the multi-zone opportunities throughout the Delaware. As a growth engine for Concho, this asset feature prominently in our future capital programs. And given the depth of opportunities that we know exist today and the potential to identify new opportunities in the future, we're jump-starting the next acceleration phase right now.

During the fourth quarter, we're increasing our capital budget by $185 million to drill 23 additional Delaware Basin operated wells, approximately 15% more than we originally planned for the entire year, and exit '13 with 16 horizontal rigs in the Delaware. Obviously, it's too late in the year to see the production benefit in '13. However, we've added capital -- the added capital dollars will go a long way in testing several concepts. We scheduled multiple extended laterals in both the Northern and Southern Delaware, and we'll spud another dual lateral in our Alaska area. We will test more of our Pecos County acreage in the Southern Delaware, and continue our early delineation work of the third Bone Spring in the State Line area. The combination of these concepts and others are part of an effort to expand our resource delineation.

Let's move on to Slide 6 and drill down on some of the recent developments in the Northern Delaware Basin, which is our most active area. This is a new slide and it illustrates just how busy we've been for nearly 3 years. Since 2011, Concho has drilled and completed 211 wells targeting 6 zones. The map provides an excellent visual of where each well is located and is also color-coded by zone. There's lots of talk about multi-zone potential across the Permian, but nowhere is it more real than right here in the Northern Delaware. As you can see from the table, we're having great success in every zone that we've tested, including all 3 Bone Spring horizons. The metrics and averages on the table don't represent a select few wells in each zone, they represent every well in each stone. Beyond our drilling success to date, the good news is that we are still very early in the effort to fully identify the multi-zone opportunity across our properties.

An example of our current multi-zone work is with the Brushy Canyon, which is not featured in our current inventory count. We'll continue to dedicate a rig to the Brushy Canyon to the end of the year, and should have a total of 8 wells spudded or completed. In addition to the 2 Brushy Canyon wells highlighted on the table, we recently brought on 2 new Brushy Canyon wells in the fourth quarter with an average 30-day rate of 696 Boes per day, 84% oil and an average peak 24-hour rate of 935 Boes per day.

Another recent development here is the addition of the Delaware Ranch acreage. 30,000 net acres in Northern Culberson County in our State Line area. We recently leased this acreage and are currently completing our first well there. Much of our recent success has occurred in this State Line area, primarily in New Mexico and partially in Texas. But there's been very little development around our Delaware Ranch property. However -- and I know I'm breaking form here, we just brought online the best well we have ever drilled and it might be -- even be the best in the Permian Basin in modern history. It's in our State Line area, just east of the Delaware ranch. This particular well is in the second Bone Spring and had a peak 24-hour rate of over 4,500 Boes per day. After 20 days, it's still making over 3,700 Boes per day. This well has a 4600-foot lateral and cost $6.8 million. It's likely to make 1 million Boes and should pay-out in less than 6 months.

I'm telling you this because the flow of information is such that you probably are going to hear about it anyway and soon. I would caution you not to draw sweeping analogues across the entire Delaware Basin. Instead, it serves as an example of just how far we've come in understanding the productive extent and opportunity of the Northern Delaware. Success like this requires a massive technical effort and I have no doubt that Concho has the most talented technical team in the Permian.

Clearly, our activity level in the Northern Delaware Basin is very high and as you can see on Slide 7, our results a very consistent. The average 30-day rate on all 211 wells is 744 Boes per day, 68% of well. And the average 24-hour peak rate is 1,240 Boes per day. The 27 new wells that we added during the third quarter performed above average and in line with some of our best quarters to date. You'll notice on this slide that our average lateral length has not changed, roughly, 4,000 to 4,500 feet. So when we think about potential value and growth leverage going forward, you'll likely see us drill more extended laterals in the near future.

Another area of great focus for us is the Southern Delaware Basin. On Slide 8, you can see that we have been very active with over 25 horizontal spuds, and we now have 15 wells with 30-day rates. Last quarter, we provided an update on average rates, which looked very good. I'm not going to add any new information for you today for competitive reasons. But I want you to know that our returns are as good as other key assets in our portfolio and justify greater activity and capital allocation. We have a distinct competitive advantage in the Southern Delaware, and as this play evolves, we need to strike the right balance between public disclosure and strategic objectives. And at the appropriate time, we'll provide a more robust update on well results, development strategy and delineation efforts.

Just a quick update on the Midland Basin on Slide 9. We're advancing our understanding of the horizontal opportunity across our acreage in the western portion of the basin. While we will continue our legacy vertical Wolfberry program, the horizontal upside provides a distinct opportunity to maximize capital efficiency and returns. With only 7 wells recording at least 30 days of production data, we still have a ways to go. However, we do have another 10 wells coming on soon, including our first Andrews County well that's currently completing. In the near term, we will test other Wolfcamp zones, as well as the Spraberry, and are beginning to move toward extended laterals.

It's obvious that we have much to be excited about, so now I'd like to turn to Slide 10, and describe the factors that are driving our decision to launch a 3-year acceleration plan. Strategically, we have a significant flexibility in how we choose to execute our business. That flexibility is a direct result of the success across our assets in both the Delaware and Midland Basins. The performance of our assets and the depth of our inventory suggests that we can increase our growth rate. Combined with a strong balance sheet, robust cash margin and compelling economics, we couldn't be in a better position than we are today to accelerate growth.

I've said this before and I can't stress enough that horizontal drilling has changed the game in the Permian. Those with big drilling programs and talented technical teams are going to succeed over the long term. We have built a company capable of running a big scalable development machine, and we have proven quarter after quarter that we can execute horizontally across the Permian Basin.

So as we move forward with our accelerated growth plan, let me outline our major execution goals. First, we expect to double our production by 2016. Historically, we have averaged annual organic growth of about 20%. So over the next 3 years, we expect to average around 25% annualized growth of a much larger production base. Secondly, we will continue to pursue measurable operational efficiencies. As we move closer to development mode in many of our growth areas, we will continue to optimize capital efficiencies and cycle times. Next, we expect to reduce our leverage ratio, which we define as debt to trailing EBITDAX. Our robust oil-driven cash flow is expected to grow at the same rapid rate as our production. And given our strong cash margin, that rate of growth should exceed the growth in capital spending, enabling us to meaningfully de-lever and taking our debt adjusted growth metric, well above 20%.

Finally, by accelerating our development, we will also accelerate our understanding of the multi-zone potential of our existing assets, such that I expect to exit 2016 with more inventory on our existing acreage than we have today. Even with all of our success to date, I'm convinced that we're still in the very early innings of resource discovery and optimization on our assets across the Permian.

The first phase of our 3-year acceleration strategy is presented on Slide 11 and details how we plan to allocate our 2014 total capital budget of $2.3 billion. Drilling capital is expected to be $2 billion, with 90% of those dollars directed to horizontal drilling, up from roughly 66% of our '13 budget. This capital program is noticeably different from prior years in several ways. First, we typically have front-end loaded our budget early in the year, just like we've done in '13. This enables us to realize more of the production impact in the same capital cycle. As you can see in the quarterly rig count graph at the bottom left of the slide, in '14, we will steadily increase our rig count each quarter and spend progressively more capital each quarter. This will effectively push out more of our volume growth into the -- to later in the year and even until '15. Another difference in this capital program over previous years is that we have typically targeted a budget that largely resembles our annual cash flow.

Assuming commodity prices of $90 oil and $4 natural gas, we will moderately outspend our cash flow and will fund that outspend with our balance sheet and still have ample liquidity. Importantly, our debt-to-EBITDAX ratio each quarter in '14 is expected to stay at or below the current level, given the strength of our margins and rapid growth of our cash flow.

The last significant distinction of this capital budget relative to others is the allocation. The Delaware Basin is our highest growth asset and we plan to spend 70% of our drilling capital on projects in both the Northern and Southern Delaware. Almost all of which will be horizontal. In terms of total dollars, that's about twice the amount we're spending in the Delaware in '13. From a rig count standpoint, we averaged 13 horizontal rigs in the Delaware Basin last quarter and will roughly double that count by the fourth quarter of '14. The Midland Basin will be our second most active area, with roughly 1/4 of our drilling capital. The majority of those dollars will go towards our horizontal Wolfberry program.

Finally, we're allocating less than 10% of our budget to the shelf. While the midstream infrastructure situation is improving, we're still looking for material relief and we'll continue to evaluate opportunities to allocate more dollars to the shelf in the future.

Finally, a potential variable in our '14 capital program is the speed in which we're able to ramp-up and drill all 600-plus of our planned gross locations. Our '14 program is ambitious, but it's achievable. We're becoming more efficient and moving more quickly with each well we drill. In the context of a 3-year acceleration program, we may choose to do more over the course of '14, if we find ourselves realizing greater efficiencies, assuming well performance, service cost and commodity prices stay on track.

Now that you have a sense for how we plan to deploy our capital, let's go to Slide 12 and review our growth expectations for '14 and beyond. Depending on '13 full year volumes, we expect to grow 18% to 22% in '14. As I mentioned before, much of our volume growth will pick up toward the end of the year and carry us into '15 '16. But over the course of the 3-year program, we're looking for annual production growth to average 25%, which will double 2016's production over '13 on a Boe basis.

Given the oily nature of our inventory, we do expect our oil volumes to grow at even a higher rate over the same 3-year period, pushing our oil mix from 62% today, up to 66% in '16. As our cash flow growth really starts to ramp-up in '15 and '16, we see our debt-to-EBITDAX leverage multiple dropping below 1.5x in the $90 oil and $4 gas environment.

We're also going to try something a little different next year with respect to guidance. Beginning on our next earnings conference call in February, we're going to provide quarterly volume guidance for the next quarter. Against the backdrop of a long-term plan, we believe it's in everyone's best interest to provide near-term visibility. This is a really exciting time for Concho. We have the perfect combination of an opportunity rich asset base, unmatched profitability, a strong balance sheet and one of the industry's most dynamic and scalable drilling platforms. We are well positioned to do more and increase our rate of growth, but while doubling production is an outstanding result, I'm even more excited about the strategic implications of a distinguishing Concho, as a leading Permian Basin operator and the opportunities that we will have beyond 2016.

So with that, I appreciate your continued interest in Concho. I look forward to taking your questions.

Question-and-Answer Session

Operator

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

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

The first question I had in regards to the robust 3-year growth plan, and I appreciate, Tim, that you have alluded to the fact that the production ramp will be quite a bit back end-weighted in '14, but maybe if you could just take it one step further to help us kind of connect the dots between the '14 to where you're going to end in '16. When I think about 2015, in terms of the rig count, I know in the past you've talked about maybe the ability to double the Delaware Basin rig count, so should I assume in '15, you kind of keep stepping up that rig count by a rig or 2 each quarter, maybe kind of the shape of what '15 kind of looks like?

Timothy A. Leach

Yes, John, good morning. Yes. The rig count looks like -- in '14 we're going to average in the mid 30s for rigs, that's in '14 and '15, we'll average in the mid 40s, and in '16, we'll be averaging in the mid 50s. And so from a ramp-up in production, it's pretty ratable after '15. So we're going to grow the rates I've talked about in '14, or that 18% to 22%, and then you start hitting kind of a 30% growth rate in '15 and beyond.

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

That's perfect. And then, looking at this record Permian well that you all drilled in the second Bone Spring, I mean, it appears based on at least what you said in terms of the lateral length and what you did, it wasn't terribly different from what you've been doing in the second Bone Spring yet. The well was 3.5x larger than your average. So I just -- I mean, anything else you see? Is it just purely the rock or was there anything else that you think you might have done?

Timothy A. Leach

Yes. We're continuing to improve our completions. So I think the rate that well is exhibiting is a function of a really good completion technique.

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

And then, just the last question from me, I'll turn it over to somebody else. I know last quarter, Joe, you had mentioned that about 20% of what you're doing in the North were these extended length laterals. And, I guess, I'm just -- I was a little bit surprised that it's still not showing up in terms of the average lateral length getting bigger, I mean, it really, basically hadn't changed over the last year, I'm just kind of trying to get a sense of, maybe, when we start to see more and more of those extended length laterals start to show up?

E. Joseph Wright

I think that -- yes, John, this is Joe. From a land standpoint, it takes us a little bit. But they're coming and we're getting longer laterals all the time. And I think our budget for next year, almost over 1/3 is going to be long laterals.

Operator

The next question comes from the line of Scott Hanold, RBC Capital Markets.

Scott Hanold - RBC Capital Markets, LLC, Research Division

And so, just a little bit more on that record growth, I could needle in a little bit more, a couple things: One, for us data junkies like myself, do you have a well name on that, so we can kind of plot it on the map, just visually? And the second thing is, you mentioned that it was just a good completion, specifically, was there anything different that you did with that in terms of like how you completed it, like was it a bigger frac job in the different types of proppant or is it just experience?

Timothy A. Leach

Yes. We're not going to identify the exact location of that well. It is on the Texas side of the state line. And that well had more sand in it than our average -- the completion had more sand in it.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay, fair enough. And then, when you look at your accelerate plan, obviously, with all the growth that's happened in the Permian Basin, big pipe infrastructure, we see it's build up, but what about the -- more towards a field level? Is there going to be some infrastructure constraint that you're already planning into '14 as you provide this kind of ramped activity level?

Timothy A. Leach

Well, not really. I'd say the only infrastructure constraint that we're struggling with is on the Shelf in the New Mexico from a gas takeaway standpoint. That's not really a takeaway constraint, as it is kind of, a processing problem right now. We think that's going to be alleviated in the near term, and -- but, other -- I think that the infrastructure and the growth of the infrastructure is going to keep up with our drilling. So we don't have any planned outages or anything.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay, fair enough. And then, one last one, if I might, on that acreage acquisition. It seems it's pretty hard to buy good acreage for at a reasonable price in the Permian today. Can you give us a sense of, kind of, the range of price you paid and how that deal got done? I mean, it seems pretty competitive out there, and how was it negotiated? Can you give a little more color on that?

Timothy A. Leach

I'll give you a little color. It was negotiated, and I think, we had an advantage because we are a preferred operator.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Anything on cost that you'd willing to give?

Timothy A. Leach

No. That's -- no, I will keep that to myself.

Operator

The next question comes from the line of David Tameron, Wells Fargo.

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

If I look at the Southern Delaware, I know, you said for competitive reasons, you're keeping it tight, but the bullet point you put in here about the new wells are performing. It looks like better than the prior 11. Can you talk about how the first 11 are holding up, as far as the type curve or are you taking to that curve or are they beating the curve, where we are in that process? And then, one other question I had, you said you're going to average 6 rigs here, is a limiting factor just the infrastructure out here? Why you don't go higher on that allocation? Can you just talk about those 2 things?

Timothy A. Leach

Yes. The wells are performing in line or above our expectations. So we feel really good about it and you can tell that by the fact that we're allocating a lot more capital there next year. The rate of growth that we see down there is affected by a couple of things. It is a new area for us, so we are -- we've got a lot of delineation work that we're doing. So that kind of dictates the pace and you're right that the infrastructure, you're kind of in a frontier area, there the infrastructure kind of sets the pace as well.

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

Okay. And then, just going back to the Northern Delaware, it's obviously, there's a lot of talks out there about efficiencies and optimization, et cetera. Can you talk about where you're on that process? I know a year ago, you were drilling -- drilling wells, still figuring out the right place land laterals, et cetera, can you just talk about where you're at, as far as efficiencies, and how much more downside do you think you can squeeze out of the cost out there?

Timothy A. Leach

Yes. Well. We're expecting more efficiencies in this acceleration plan we have over the next 3 years. So we think there will be material, just from what we're seeing today. And I'd say on top of that, I think, what you're going to see from us and others as we get into more of a development mode over the next 3 years, you're going to see more and more pad drilling and other types of techniques that are going to drive the cost down. But, I will tell you, and you know this that, this is a very, very capital intensive operation. So it's -- while there are a lot of efficiencies and we expect the cost efficiency to continue to improve, this is a game, where scale is really important. And, so I think, that's one of the things I'm most excited about, when I think about a future is this execution machine that we are building and have built here.

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

Do you care to take a shot at -- is that a 10% efficiency you'd expect to see next year? Or care to give us a range?

Timothy A. Leach

Oh, that's probably an okay range for next year. But, I think in years beyond that, you can improve on that.

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

Okay. And then, just one follow-up question about the 3-year plan, I mean, I'm not very good at math, but obviously, if you're doing 20% next year and then you're pegging at 25% CAGR for the 3-year.

Timothy A. Leach

Right.

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

Should we think about a linear ramp? '15, if you continue to see the same step-up in rigs like you show on '14? And then, are you leveling now, is it at a 50-ish, 55 rig type number in 2016? Or how should we...

Timothy A. Leach

Well. That's what you get in 2016. And by 2016, the cash flow of all this operation really catches up with what you've done. So you're generating a tremendous amount of cash flow as you exit 2016. And then, as I said on the call, we're talking about kind of the midpoint is 20% growth through '14. But then you go kind of in the 30% range for '15 and '16.

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

Okay, so -- in 2015, are you showing free cash flow excess -- free cash flow above capital in your model?

Timothy A. Leach

Yes. And as you know, that's not going to happen. We're going to find something to invest it in, so that's just kind of demonstrates the strength of what we're drilling.

Operator

The next question comes from the line of Ryan Oatman, SunTrust.

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

I wanted to talk a little bit about the well cost in the Northern Delaware Basin. You mentioned a $6.8 million cost for this second Bone Spring well. How does that compare with your typical cost out there?

E. Joseph Wright

Yes. Typically our cost on that second Bone Spring in that area is about $6.3 million to $6.4 million. And we did a few things a little different, as Tim mentioned, on our stimulation. So there's a little extra cost there.

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

With regards to the New Mexico Shelf, can you discuss what's currently curtailed? And when you expect that production back?

Timothy A. Leach

Well, on the shelf, we're still -- we think for the full year that we probably have the curtailment effect of about 600,000 Boes, and we expect to kind of be fully back online by the end of the year, maybe the first quarter of next year.

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

Okay. And then, one final one for me, the Northern Delaware Basin, the lateral length is already mentioned, if kind of stayed in that 4,000 to 4500-foot range to date. You mentioned those moving longer into 2014 and 2015, can you quantify kind of how you anticipate that program evolving towards the longer laterals? And then, what sort of cost you're anticipating for these long laterals wells? And I'll leave it at that.

E. Joseph Wright

You're specifically talking about the North Delaware Basin?

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

Yes, sir.

E. Joseph Wright

Yes, I think the -- as you think about those costs, as you increase the lateral length, I think, they're going to run somewhere in that -- for that state line area, I think somewhere around $7 million, $7.5 million. I think I misquoted you a while ago. On a normal link, lateral is down the state line. At those rates, these are really about $5.2 million, $5.3 million. I think I said $6 million, so I apologize. If you'd look at the longer laterals, you're adding a couple of million dollars to that.

Operator

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

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

Tim, in the history of Concho, you've had tremendous success with bolt-on acquisitions like Marbob, Three Rivers, et cetera. Now with the acceleration plan being the primary focus of the company to double production, do you think that signifies a turn away from the bolt-on acquisitions in the past? And do you have enough inventory at this point to really push the drill bit and get the drilling machine going? Or do you see consolidation as part of that strategy?

Timothy A. Leach

Well, I think our base business has never been in better shape. So when I think about how we've done things in the past, I think this organic growth through the drill bit, higher rates of return and higher value creation is better than it's ever been. So that raises the bar on the acquisition -- the bolt-on acquisitions side of our business. We do have a tremendous amount of inventory. So having said all that, I will tell you, both parts of our business, we're still very active in. Everything that's moving in the Permian Basin, we're taking a look at. We're very picky. We're very selective about our core areas and things like that. Clearly, the plan I laid out for you on our accelerated growth, we're doing it with our own balance sheet, and we think our balance sheet will continue to be very strong. And we're not issuing any equity around that. On the other hand, these bolt-on acquisitions and the consolidation opportunities, if the right one comes along, we wouldn't hesitate from pulling the trigger on it because I think we have a big advantage on our ability to execute. And if we pull the trigger on it and if it was of any material size at all, it have to include some portion of equity to keep our balance sheet strong.

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

My follow-up is what are your thoughts on the Midland-to-Cushing differentials as you looked at putting out your '14 guidance that widened a little bit here recently?

Timothy A. Leach

Yes, they kind of returned to historic levels for a while and then widened back out a little bit. The market has developed now that we can hedge all that, and we have hedges in place for all the barrels that we have hedged in '14. So -- and I think we've put out information on what the Midland-to-Cushing hedge number is. I think it's around $1 somewhere. So we'll continue to do that. We'll continue to hedge that differential. I do think, as we've talked in past quarters, as these pipelines have come on to move the Permian crudes straight to the Gulf Coast, I think our pricing will improve. It has improved. The differentials we're receiving on the crude oil we sell seem to have gotten better. But I still think that it's going to be a bumpy road in terms of -- if a refinery goes down or a fractionation goes down or something like that, you're going to see blips, I think, in all those differentials. But we're going to be pretty aggressive on hedging those things.

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

Great. And then just one last one for me, over in the Midland Basin, are your lateral links constrained because of legacy high density vertical drilling which has occurred there?

Timothy A. Leach

No. I mean, it may be constrained because of lease constraints, but it's not constrained because of the vertical drilling. And I think you'll see just as much extended link lateral in the Midland Basin as you do over in the Delaware.

Operator

The next question comes from the line of Ryan Todd, Deutsche Bank.

Ryan Todd - Deutsche Bank AG, Research Division

A quick question. You've alluded to the fact that you'll provide more clarity in this area in the future, but any way you can find in kind of a ballpark range about how you think about CapEx in 2015, '16? I mean, we can back into it from some of your comments, but I guess maybe any help there in terms of how much more efficient you think you can get would be helpful.

Timothy A. Leach

I didn't understand the first part. You're talking about one specific area or our total capital budget.

Ryan Todd - Deutsche Bank AG, Research Division

Oh no, the total capital budget for '15 and '16.

Timothy A. Leach

Yes, yes. So we're talking about $2.3 billion in '14. And I think, nominally, if you look out in '15 and '16, we're like at $2.5 billion and $2.6 billion -- I'm sorry, $2.6 billion or $2.7 billion for '15 and '16.

Ryan Todd - Deutsche Bank AG, Research Division

Okay. And the -- I guess if we look at the Delaware ranch acquisition that you did, it looks -- from a targeting point of view, is that primarily focused on the second Bone Springs, Wolfcamp, same targets as generally what you see in the other side of the line?

Timothy A. Leach

That's true, and I mentioned delineation work in the third Bone Spring as well. And Avalon is also a target out there.

Ryan Todd - Deutsche Bank AG, Research Division

Okay. And then it looks -- I mean, maybe it just looks this way in the picture. It looks like a checkerboard. Is there an opportunity to fill in that checkerboard at some point? And is it going to be lateral?

Timothy A. Leach

As you'd probably know that in that country, most of your checkerboarded partner is our friends at Chevron.

Ryan Todd - Deutsche Bank AG, Research Division

Right. And I would assume you're in conversations with them?

Timothy A. Leach

We've -- they've been great partners of ours in other areas of the Permian Basin.

Ryan Todd - Deutsche Bank AG, Research Division

Okay. And then in the South, I know you've mentioned at times in the past, you'd like to be quite a bit bigger acreage-wise in the South. I mean, is that still the plan? Any idea on how much acreage you'll eventually like to have down there? And are you seeing much in the way of opportunities?

Timothy A. Leach

I don't have any specific plans to talk about right now. And because it's mostly in the hands of independents down there, there's all kind of opportunities.

Ryan Todd - Deutsche Bank AG, Research Division

Okay. That's good. And then I guess, one final one, the Brushy Canyon, how much will that figure into your 2014 development plans?

Timothy A. Leach

I don't think we have the number around here somewhere.

E. Joseph Wright

Drilling 11 wells, is that right?

Timothy A. Leach

Yes, right now we've scheduled 11 wells for '14, but that could go up.

Operator

The next question comes from the line of Matt Portillo.

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

Just a few quick questions for me. In regards to the Midland program, the 9 rigs you're planning on running, will any of those rigs be on your Glasscock or your Irion acreage?

Timothy A. Leach

We're not drilling horizontally in those areas.

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

Okay, perfect. And as you guys look at that part of your acreage position versus the rest of your Upton and Midland acreage, is that potentially something that could be divested over time?

Timothy A. Leach

We don't have any plans to sell it today. In fact, I think it probably will be valuable acreage in the future.

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

Great. And then just around the completions, I know you guys have talked about extending the lateral link. I also was wondering if you've started to test some of the tighter spacing between the stages and kind of where you guys are today in the stage spacing and where you may move to over time.

Timothy A. Leach

I'm going to give you several different answers to that question. I'm -- generally, we're in the early innings of delineation. So I've heard someone around here say, "We're not down-spacing yet, we're still spacing." And now I think we're in the process of developing plans to test different spacing options in areas where we've got the most data and the highest confidence of repeatability that we've got the delineation completed. So you'll see us start to roll stuff out like that. And today, when we think about spacing these horizontals and when we talk to you about location counts, generally, we're still in the 4 laterals per section. So it implies 1,200 feet or so between laterals. And I think that's probably real conservative across the Permian Basin, but that's just where we are right now in the early innings.

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

Okay. And then my last question, just in regards to, I guess, your stage count, how many stages you're doing per well on you shorter lateral wells. Where do you guys stand today in terms of the number of stages? And do you see some opportunity to potentially increase your stage count over time?

Timothy A. Leach

Yes, that's changing rapidly right now. And I think we're going to kind of keep that information to ourselves.

Operator

The next question comes from the line of Brian Singer, Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc., Research Division

On the acceleration, you've always been a major Midland or the major Midland operator. But at times, we've certainly seen cost inflation. And at times, we've seen a tougher environment to find people. I'm wondering if you could just comment on whether you think as you begin the acceleration process here to a greater-than-20% type growth number, whether you feel like you have the people, infrastructure, all at hand or whether there are still items that are on the critical path and what that may be.

Timothy A. Leach

Yes. Well, one of the good things about our company right now is we got the high of 45 rigs or so back in '12. And so we have the infrastructure and the people in Concho that can do that kind of work. The other thing is as you transition from vertical drilling to horizontal drilling, it seems like the cycle times and the capital efficiency is greater. So you can get more done with fewer people in general throughout the industry. So I think there's going to be some efficiencies that help our industry. Now having said all that, I do think this acceleration program, part of what's driving this for me is, strategically, I want to be the first company that really is running 50 rigs and doing a really good job of doing that. And to get to that point over the next 3 years, we will be adding horizontal drilling personnel and geoscience personnel and things like that to help support a bigger machine.

Brian Singer - Goldman Sachs Group Inc., Research Division

That's helpful. And then secondly, on the Brushy Canyon zone specifically, I was wondering if you can add a little bit more color on your thoughts there? On Slide 6 of your presentation, you talk about 2 recent wells that have 30-day rates of almost 700 Boe a day. And it seems like that might be incremental up to the 2 wells to the right of that. But I'm just wondering if you could just maybe add some more color on how widespread you think that zone could be given that it's looking pretty oily?

Timothy A. Leach

Yes. Well, the economics on that are really pretty good. The rates are high. The costs are low because the zone's shallow. And I think the whole question is how extensive is that -- I mean, the zone is extensive. It's going to be a question of how the rock changes over the entire area of the Delaware Basin. And that's why we're going to drill some more wells there. It's -- by the work we're doing deeper, all that stuff will be held by the deeper work we're doing. We get to look at it as we drill through it in all these different areas. So I think it is a substantial upside to what we're doing right now.

Brian Singer - Goldman Sachs Group Inc., Research Division

Do you have a sense to how many wells you plan to drill there over the next year? Or what the level of commitment is?

Timothy A. Leach

Let's see. Hold on a second.

E. Joseph Wright

11.

Timothy A. Leach

Yes, it was 11, 11 Brushy Canyon wells next year.

E. Joseph Wright

On top of the 8 that we're drilling this year.

Operator

The next question comes from the line of Jeb Bachmann for Howard Weil.

Joseph Bachmann - Howard Weil Incorporated, Research Division

I just want a follow-up on the last question. Looking at the ramp and the rig count over the next 3 years, particularly in '15 and '16, just wondering if you've had preliminary conversations with the rig companies on that ramp or to your comments, Tim, getting a head start of maybe the industry. Do you not think that there's going to be any kind of difficulty getting those rigs when you need them?

Timothy A. Leach

Yes. I don't anticipate we'll have any difficulty getting the rigs when we need them, but you sure don't want to be the company in this industry that's picking up the last rig. And so I think our position, we have a currently running -- a large drilling fleet is going to be a big advantage as we add rigs. That's also why you -- I think a program to add a few rigs every quarter is better than trying to add them all at one time. And so I think the equipment is going to be out there. The other thing that, I think, is hard to anticipate over a 3-year time span is how much more efficient we're going to get. I talked about the rig ramp and how many rigs we're going to need for the next 2 or 3 years. But my real expectation is, as we go through that period of time, we're going to be able to do more with less rigs. These rigs will be moving faster. And so while I'm telling you my estimate today, if I was biased, I'd be biased on the side of I bet we can get more done with fewer rigs.

Joseph Bachmann - Howard Weil Incorporated, Research Division

Okay, great. And last one for me. Any idea of when you guys might give an update on the total location count across your acreage in both Delaware and the Midland?

Timothy A. Leach

Yes. I think that'll be after the end of the year when we do our fourth quarter, probably, conference call. We'll have brand-new engineering that's been reviewed with all the third parties and all that stuff, and I think we'll come out with a more robust kind of inventory count.

Operator

The next question comes from the line of Arun Jayaram, Crédit Suisse.

Arun Jayaram - Crédit Suisse AG, Research Division

Tim, I was just wondering if you could comment on any feedback you've received from your non-op partners regarding the new program. Obviously, Chevron is one of your biggest partner, but I just wanted to see what kind of feedback you've gotten from your partners.

Timothy A. Leach

Well, the great thing about our acreage position is we don't have that many non-op partners. The ones we do have are all full steam ahead. And Chevron and Apache are probably our biggest non-op partners.

Arun Jayaram - Crédit Suisse AG, Research Division

And just my follow-up, Tim, as you think about -- I know your team has put a lot of effort and analytical and spreadsheet time on this new forecast and activity levels. I just wanted to see where you think the biggest risk in terms of you guys getting to this lofty growth target is?

Timothy A. Leach

Yes. Well, I think that -- I'm really focused on my debt metric. I think we're going to be able to delever at the same time we accelerate, which I think is an incredible thing. But a lot of it's driven by commodity prices. And so I do not want my debt metric to go up. And so I think that's the -- these projects are real robust. Our cash margins are high. We can stand some price volatility. But as always, in this business, commodity prices are probably the biggest swing factor and how fast you work.

Arun Jayaram - Crédit Suisse AG, Research Division

Got you. And just a one follow up just regarding the CapEx, $2.3 billion next year, maybe going to $2.7 billion, $2.8 billion the following couple of years. What drives the fact that CapEx doesn't go up as much, but you get a lot more production growth? Just wanted to get some thoughts on maybe your assumptions around those efficiency gains.

Timothy A. Leach

Yes. I think one thing that's -- the performance of horizontal wells, timing-wise, is different than vertical wells. It takes longer to drill. And so the ramp looks different over time. And for the first time, we've built this plan around the concept not of financial constraints. We've built this concept around what is the appropriate ramp on our properties with our people and with our rigs. And that's what's driving the activity in '14, '15 and '16.

Operator

The next question comes from the line of Irene Haas, Wunderlich Securities.

Mostafa Dahhane - Wunderlich Securities Inc., Research Division

Yes, this is actually Mo Dahhane for Irene. Just a quick question, it looks like you guys brought online 4 horizontal Wolfcamp in Culberson County. Is that right?

Timothy A. Leach

We have over a period of time, not necessarily recently this past quarter. If you're referring to the map on Page 6, that represents all of the wells that we've drilled over -- almost nearly 3 years here.

Mostafa Dahhane - Wunderlich Securities Inc., Research Division

Okay. Can you talk a little bit about these 4 wells in Culberson County in terms of how similar they are to Reeves County Wolfcamp wells?

Matthew G. Hyde

Sure. I think we've commented on those. This is Matt Hyde, by the way. We commented on those previously, and we actually have our rate information there on the bottom of Slide 6, where you see the collective effort, if you will, around 11 wells and the associated rights.

Mostafa Dahhane - Wunderlich Securities Inc., Research Division

Okay. And so a second question, over at Midland Basin, do you guys have a breakdown of how many tests you're going to drill into the Spraberry Formation in Wolfcamp D in 2014?

Timothy A. Leach

I don't think we have -- well, in the Wolfcamp D, I don't think we have any more tests planned over there. We will could that climbing, I think. And then on the Spraberry, it's just -- we just have 1 test planned for the Spraberry zone. All the rest of them will be in the upper benches of the Wolfcamp.

Operator

The next question comes from the line of John Nelson, Citigroup.

John C. Nelson - Citigroup Inc, Research Division

I wanted to circle back on the earlier comments or questions about midstream capacity. I'm just curious, have you already held discussions with your midstream partners about sort of this accelerated growth plan such that you feel comfortable with the ramp? And I know, historically, Concho has tried to avoid entering into long-term agreements given the industry has pushed to accelerate growth. Is that something we should potentially look to change going forward?

Timothy A. Leach

We have had conversations. We do have confidence around the midstream assets that will be necessary for this ramp. And so like I said, I think the only area that we're going to wait and see before we invest any more capital is up on the shelf with the gas takeaway capacity. I think everything else -- there's projects going on. There's work to be done, but I think all of that will happen at kind of the same pace that we're doing our accelerated development.

John C. Nelson - Citigroup Inc, Research Division

And then if I could just follow up to your comments on sort of productivity, and we use the term sort of pad drilling or development drilling. But can you help us think about the number of horizontal rigs that are maybe in '14, being a more development mode? And how that will shift as we get into '15 and '16 such that we can think about the efficiency gains?

Timothy A. Leach

That's a tough one. In terms of -- well, lots of things we're still doing, I wouldn't say are in the real development mode yet. And I think we are just beginning to have areas where you go lay down multiple rigs or multiple wells side-by-side and then frac them together. We still -- up until this very point, we still are doing a lot of our drilling, delineating the entire extent, both vertically and horizontally of all the pays and zones that we have. So I think the -- what you're getting at, the pad drilling and really driving that efficiency is going to start in '14. But I think it's more of a '15 and '16 kind of operation, and I think you'll see continued gains and efficiency over that period of time.

John C. Nelson - Citigroup Inc, Research Division

I guess, I would -- for a little color, I mean, would 25% of rigs at year end '14 sound reasonable? Or is that already too high to think about?

Timothy A. Leach

That'd be probably on the high end of the range is what I'm thinking.

Operator

The next question comes from the line of Ipsit Mohanty, Canaccord.

Ipsit Mohanty - Canaccord Genuity, Research Division

Let's me stick to the Midland Basin and just shoot in a few. Going -- looking at your ramp from 2 rigs in '13 to about an average of 9 in '14, will it just primarily be the Upton County? Are you going to spread out to Midland and Andrews?

Timothy A. Leach

Yes, it's a spreading-out exercise. It'll be Upton, Midland and Andrews. You're right.

Ipsit Mohanty - Canaccord Genuity, Research Division

And then just a broader question, you've been kind of the champion in the Delaware, and you've shown this big ramp-up, big plan. How comfortable are you that the Midland Basin part will also kind of go hand-in-hand with the Delaware Basin?

Timothy A. Leach

I'm very comfortable with that notion. And the great thing about our plan is we're going to be ramping up quarter-over-quarter. So you're going to kind of learn as you go here. But I think right now, the plan we've laid out for 3 years is very achievable. We feel very comfortable with it.

Ipsit Mohanty - Canaccord Genuity, Research Division

And then my one last, among the average of 7 wells in the Midland basin -- I'm sorry, I'm sticking to that. But in that average of 7 wells, how did your Andrews County well fare in that? Did it -- or was it within the range of what's kind of lower or higher on the range if you care to comment?

Timothy A. Leach

No, we're just still working on that well.

Operator

The next question comes from the line of Joe Magner, Macquarie.

Joseph Patrick Magner - Macquarie Research

I just wanted to kind of step back to Q2. Coming out of that release, there's a lot of discussion around 15% to 20% sort of your being base level of production growth within cash flow. The new accelerated plan now requires pretty significant step up in capital spending and somewhat of a lag until we see that inflection point on the ramp-up in growth. Can you just kind of walk through it? I just want to make sure I get a better understanding of what might be holding back the start of that ramp.

Timothy A. Leach

Yes. And I'm glad you asked that question because first, let me say that the 15% to 20% growth within cash flow is still a business plan we could execute. That's very doable. And then when you think about those shifting to more and more rigs and where you invest more and more capital, we described a shift from a front-end loaded capital budget in '13 where you spend most of your capital on the first half of the year to now we're starting to ramp these horizontal rigs in a way that we think is very doable for Concho. But the end effect is most of your capital is going to be invested in the second half of '14. So you're matching up 2 years that have -- '13 was front-end loaded. '14 is going to be back-end loaded. And so the second half of '13 and the first half of '14, of course, you expect to look a little bit different than once you get in steady-state growth after kind of mid-'14. So if you look at exit rates, I think the exit rate for '14 is going to kind of be 25% growth compared to the starting rate of '14, if that helps.

Joseph Patrick Magner - Macquarie Research

Okay, that's helpful. And then I guess to follow on the previous question. Then when you shift into more pad development that has had an impact on cycle times for other folks, how do you think about managing that as you're also trying to hit on these '15 and '16 targets?

Timothy A. Leach

Sure. We don't have the pad drilling shift modeled into this acceleration program. So now I think as you -- and I think the way I would think about it as we transition into that over a long period of time, I think the changes will be incremental. So I think we will be talking about that over time. It takes longer to get those wells drilled, longer to put the production on but you get higher rates and more efficiency and lower cost. I don't think that, that will happen overnight throughout industry, throughout the Permian Basin or at Concho. But I think you'll see that incrementally until one day, when you turn around and most of what we'll be doing is that kind of activity probably. But it's not contemplated in this plan or the efficiencies aren't built into this plan yet.

Joseph Patrick Magner - Macquarie Research

Okay, that's helpful. And then just one on oil prices, the discussion a couple of months back. There was a lot of concern about sensitivity or the volatility in oil prices, and that was somewhat holding you back from being willing to step out and talk about this type of plan. Maybe not this specific acceleration plan, but a type of plan that would require you to outspend. What's changed? It doesn't look like you've layered on much in the way of new hedges. Should we expect that to change or expect any changes in your hedging policy going forward?

Timothy A. Leach

I guess, for me, personally, a year ago, I was more expecting a dramatic decline in oil price, and I didn't want to be accelerating into a dramatically falling oil price. And I don't think I was alone in the industry thinking that. But today, I think there's more confidence around a stable oil price between $80 and $100, and this plan works beautifully between $80 and $100. And we have hedged as much of our PDP as we can. We've pushed it out through 2015. And so that provides us downside protection on some of this drilling program.

Operator

The next question comes from the line of Mike Kelly, Global Hunter Securities.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Tim, I was hoping you could really just talk at a very high level about the geological differences between the Northern Delaware Basin and the Midland Basin. And it's really my sense that us finance guys have kind of bought into the narrative that in the Midland Basin because it's more unconventional shaley, that it could take a company's net acreage position divide it by 80 acres spacing and instantaneously have 100 years of drilling inventory. And that same credit is not being given in the Northern Delaware Basin. And I'm just hoping you could speak on that because I think you'd have some opinions there.

E. Joseph Wright

Yes. I hope I'm going to touch on the subjects you want me to touch on. But the Northern Delaware Basin, as far as an opportunity rich environment, is the best I've ever seen. We've drilled 211 wells there now horizontally in 6 different zones. All of them at high rates. All of them have a lot of success. Now when you think of those 6 different zones, they all have a little bit different characteristics. Some of them are shaley. Some of them have more carbonate and sand. Some of them are mudstones from a geologic standpoint. And then from an operational standpoint, there's just been a whole lot more activity in the Northern Delaware. There's more wells. There's more data. There's more success. Also, I'd say, in the Northern Delaware, some of those zones are really oily. Some of them have quite a bit of gas. And the Wolfcamp has more gas up in the North than it does down in the South. It probably has more gas in the North than it does over in the Midland Basin. But the Bone Springs are more conventional reservoirs. They have a high oil content, and they seem to be widespread, which will be equivalent to kind of the Spraberry zones over in the Midland Basin. So I -- the basins are different somewhat. But they have very similar characteristics in the number of zones they have, the oil in place. I just think that the Delaware Basin got started first and probably has had more widespread activity, and we got more information on it, on how it performs horizontally. And it's really driving the company growth, and it's that whole area's production is growing pretty dramatically. And I think the Midland Basin is really just in the very early stages of showing production growth. I hope that answers your question.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Yes. So is it fair to characterize it as its more complex geology in the Northern Delaware Basin, and you're going to have to do a little bit more work on the engineering side and location kind of side versus maybe what you have in the Midland?

Timothy A. Leach

No, I don't think that at all. I think both of them are complex. I think you need good geologic information on both sides. It's just -- it seems like there's been a lot more acreage mass left around in the Midland Basin, and the companies in the Delaware Basin haven't really done that yet. They either haven't talked about it at all, or they haven't talked about it in terms of acreage mass.

Operator

With no further questions, we'll turn the call over to Mr. Tim Leach for closing remarks.

Timothy A. Leach

Yes. Once again, I thank you for participating in this call. I know it's a busy time for you. I hope you can tell by our plan that we're very excited about the -- of what we think we can do with this company, and I look forward to talking to you more about that in the future. Thank you.

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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