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Concho Resources Inc. (NYSE:CXO)

Q1 2014 Results Earnings Conference Call

May 12, 2014, 10:00 AM ET

Executives

Price Moncrief - VP, Capital Markets & Strategy

Tim Leach - Chairman & CEO

Joe Wright - COO

Analysts

Matthew Portillo - PTH

Brian Singer - Goldman Sachs

Scott Hanold - RBC Capital Markets

Ryan Oatman - SunTrust

Pearce Hammond - Simmons & Company

Michael Hall - Heikkinen Energy Advisors

Jason Smith - Bank of America Merrill Lynch

Jeffrey Campbell - Tuohy Brothers

Mike Kelly - Global Hunter

John Nelson - Citigroup

James Sullivan - Alembic Global Advisor

Richard Tullis - Capital One

Joe Allman - JPMorgan

Operator

Ladies and gentlemen, welcome to Concho Resources First Quarter Earnings Conference Call. My name is Lisa, and I’ll be your coordinator for today. Today’s conference is being recorded. At this time, all participants are in a listen-only mode. Following the prepared remarks, there will be a question-and-answer session. (Operator Instructions)

I would now like to turn the conference over to Mr. Price Moncrief, Vice President of Capital Markets and Strategy for opening remarks. Please proceed.

Price Moncrief

Good morning. Thank you for joining us. This morning Concho issued a press release announcing an underwritten public offering of common stock. We will not discuss that offering on this call or take any questions about it. We refer you to our press release and the prospectus supplement filed this morning with the SEC.

In addition, we have a hard stop today at 10.45 Eastern. Before we get started with Concho’s first quarter conference call, I'd like to take a minute to direct your attention to the disclaimers, including the forward-looking statement disclaimer contained in our press release.

In summary, the forward-looking statement disclaimer says that statements in this morning’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 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 other filings with the SEC. In addition, we will reference certain non-GAAP measures, so please see the reconciliations in our earnings release.

I’m going to quickly turn this call over to Tim Leach, but before I do I’d like to point out that in addition to our earnings release, we have posted a presentation to accompany this conference call, which can be found on our website at concho.com.

On the agenda today, Tim will cover our first quarter results and highlights, provide an operations update, and discuss our expanding midstream strategy, which now features our first midstream JV. 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.

Tim Leach

Good morning. If you follow along with me in our earnings presentation, I’m going to start on Slide 4. The first quarter of our 2x3 growth plan is off to a terrific start. We reported record EBITDAX of over $480 million for the first time in the company’s history. We averaged over 100,000 BOEs per day in a quarter. In fact, we produced about 102,000 BOEs per day during the first quarter which is above the high end of our guidance range and is 5% over the previous quarter.

Our crude oil mix during the quarter is right around 64%, which is also at the high end of our annual guidance. The early success of our growth plan is attributed primarily to our impressive well performance as well as improved operational efficiencies. While we’re on track with our annual capital budget through the first three months of the year, it’s clear that we’ll complete our original $2.3 billion budget earlier than expected.

By maintaining our activity level through the end of the year, we expect to drill more net wells and we’ll add approximately $300 million to our ‘14 capital budget. We’re also increasing our annual ‘14 production growth guidance range to 20% to 24%, up from 18% to 22% and expect to see even more barrels arrive in ‘15 as a result of the incremental capital investment, which is weighted towards the second half of ‘14.

With respect to our quarterly production guidance, we expect to average somewhere between 104,000 and 108,000 BOEs per day during the second quarter. This range reflects our expectation that the second quarter is typically a peak turnaround season for gas processors and refiners. And we continue to see our rate of growth accelerating in the second half of ‘14.

Among the highlights of our most recent quarter is our well performance. We set new company records in the northern Delaware Basin for average 30-day and peak 24-hour IP rates. In addition, our southern Delaware Basin and Midland Basin horizontal wells continue to deliver consistently strong results.

The New Mexico Shelf is an area in which we’ve allocated minimal capital in the last year due to infrastructure constraints. But that situation continues to improve and we’re planning to allocate additional capital there in the second half of this year. Finally, we’re moving forward with a midstream strategy that has both economic and strategic objectives. And this morning’s announcement of our first midstream investment in the northern Delaware Basin is a significant step toward accomplishing those objectives.

Let’s turn to Slide 5 now for an update on our 2x3 growth plan. I’ve said before that the key to the success of our plan is execution. And we’re very pleased with the way we’re executing at the outset of the plan.

We’re right on track to achieve our three-year execution goals to ultimately double production in ‘16. In this commodity price and service cost environment, we’ll continue to delever. I’ll speak more specifically about our operating efficiencies in just a minute but the improvements we are seeing are enabling us to accomplish more than we originally planned. As a result of our faster pace, we’re increasing our annual production growth rate guidance range in ‘14 to 20% to 24%.

Over to Slide 6, through the first quarter, we spent approximately $540 million, excluding acquisitions, which is in line with our first-quarter capital expectations. However, we’re proceeding through our development program faster and more efficiently than expected, primarily due to improved drilling times, additional frac crews and shortened spread to sales cycles in each of our major horizontal areas.

Today, we’re operating 33 rigs, 29 of which are horizontal and expect to average 33 to 35 rigs over the remainder of the year. That’s fewer than we originally planned, and expect that we’ll not only complete our original ‘14 development plan ahead of schedule, but also have the operational capacity to do more. All of this is really good news.

The initial ramp phase during the first quarter proceeded better than expected. Our horizontal rig count increased from 18 in the fourth quarter to 30 in the first quarter and now represents one of the Permian Basin’s largest and most efficient horizontal drilling operations. Plus, we are just in the first year of a three-year growth plan. In order to maintain that activity level through the end of ‘14 and into ‘15, we expect we can drill approximately 40 more net wells than we originally budgeted in ‘14.

The capital associated with these additional wells is approximately $300 million. While we’ve not established ‘15 production guidance or changed our three-year growth objective, we expect that accelerating our execution timing will have positive implications to our growth plan.

Our motivation to accelerate the development of our capital is driven by our continued execution strength across our assets, and Slide 7 really illustrates the success we’re having in the northern Delaware Basin. We’ve now drilled 276 horizontal wells in this area and our results have been very consistent while lateral lengths have averaged between 4,000 to 4,500 feet.

We set new records during the first quarter in terms of average rates. The 39 new wells averaged over 400 BOEs per day over the first 30 days, 74% crude oil and nearly 1,500 BOEs on a peak 24-hour basis. The average lateral length for those wells was about 4,500 feet, meaning that on a 30-day basis our first-quarter wells averaged 200 BOEs per 1,000 foot of lateral while the average of all our northern Delaware wells is 184 BOEs per 1,000 feet of lateral. All those rates are among the best in the northern Delaware and are on a two-stream production basis.

Equally impressive is the fact that during the first quarter of ‘14 we averaged over 42,000 BOEs per day in our horizontal Delaware asset representing 18% growth over the fourth quarter of ‘13. The added drilling capital in the northern Delaware is approximately $130 million, bringing our total drilling budget here to about $1.2 billion.

Our plan in the northern Delaware for the remainder of ‘14 is to continue to define and delineate new areas and zones, evaluate increased well density and test the potential for improved efficiencies through pad drilling, stimulation design and long lateral development. The Delaware Basin is an exciting area and our success is not limited to just the northern portion of the play.

Let’s turn to Slide 8 and talk about the southern Delaware. We’re delivering some impressive well results in the southern Delaware. We now have 28 wells online with an average 30-day IP rate of 1,014 BOEs per day, 79% crude oil and an average 24-hour peak rate of 1,340 BOEs. The average lateral length on all those wells was 4,714 feet, meaning 220 BOEs per 1,000 foot of lateral on a 30-day basis. These averages represent all of our southern Delaware wells including our exploration wells in the South Harpoon area.

Our most recent seven wells from the first quarter had an average 30-day IP rate of over 1,100 BOEs per day and an average 24-hour peak rate of over 1,450 BOEs with a lateral length averaging just 4,385 feet, which is a robust 255 BOEs per 1,000 foot of lateral on a 30-day basis. Again these rates are amongst the best in the southern Delaware and are on a two-stream stream production basis.

As part of our capital budget expansion, we’re adding approximately $100 million of drilling capital to our southern Delaware program bringing our total ‘14 capital allocation here to $450 million.

Let’s turn to Slide 9 and touch on the Midland Basin where we continue to find ways to optimize our completion techniques. Our reduced cluster spacing tests are showing encouraging signs. Our latest six new wells during the first quarter recorded an average 30-day IP rate of 714 BOEs per day, 83% crude oil and an average 24-hour peak rate of 1,115 BOEs with a lateral length averaging approximately 5,000 feet, meaning 143 BOEs per 1,000 foot of lateral on a 30-day basis.

Our activity remains concentrated in the Wolfcamp A and B but we had plans to spud our first horizontal Spraberry by the third quarter and test deeper Wolfcamp benches later in ‘14. Our ‘14 capital budget in the Midland Basin is now just over $500 million.

An area that we’ve not discussed lately is the New Mexico Shelf shown on Slide 10. The theme here during 2013 was takeaway and processing bottlenecks. A year later, those issues have improved significantly. This is a reminder that Mexico Shelf is a world-class asset with higher rate of return horizontal and vertical drilling opportunities.

It’s been a major platform and has funded our growth in the Delaware and the Midland Basins. We’ve drilled over 1,500 successful vertical wells and over 100 successful horizontal wells here targeting the Paddock and Blinebry zones in the Yeso formation. Today, we are running a horizontal program primarily focused on the lower Paddock zone with successful wells spread across the Yeso fairway and down through the Southwest extension.

We’re also having success with the horizontal Blinebry in the Yeso fairway and later this quarter, we’ll spud our first horizontal Blinebry in the Southwest extension. We are currently running just two horizontal rigs. This is an asset that still has room to run at attractive economics. As we continue to see improved infrastructure support in the Shelf, we are allocating more capital here in the second half of the year.

I’d like end on Slide 11 and describe an expanded strategic initiative for Concho. As one of the Permian Basin’s largest producers, developing a more comprehensive midstream and marketing solution is critical to building long-term value.

Our midstream strategy’s primary objectives are to secure physical transportation of our product to the best markets available and improve the prices we realized for our crude oil and natural gas production at the well head. Our first midstream project serves both objectives while providing the option to realize additional value down the road.

The partnership will construct and operate a crude oil transportation system that connects to virtually every Concho tank battery in the northern Delaware Band provide us delivery point flexibility. Currently, all of our northern Delaware barrels are transported via truck to various pipelines and refiners. While this is our first direct investment in a midstream project, I don’t expect it will be the last as we continue to seek other opportunities that meet our strategic objectives.

In summary, this is a record quarter for Concho and our three-year plan is ahead of schedule. We continue to be encouraged by our operational results and are excited about the rest of the year.

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

Question-And-Answer Session

Operator

(Operator Instructions) And your first question is from the line of Matthew Portillo of PTH. Please go ahead.

Matthew Portillo - PTH

Just two quick questions from me.

Tim Leach

Matt, before you get started can I clarify something? I misspoke on Slide 7. The 39 new wells that we brought on averaged -- I think I said 400 BOEs per day, I meant 900.

Matthew Portillo - PTH

On a 30-day basis?

Tim Leach

On a 30-day basis. So that was a typo in my head I guess. So if you’re following that, it was 900 not 400. So go ahead with your question Matt, I’m sorry.

Matthew Portillo - PTH

Just alongside kind of the acceleration you guys have talked about here, I was wondering if you could maybe just provide a little bit more context of how you think about kind of continuing to accelerate that growth over the next year or two and as you guys kind of delever the balance sheet how we should think about some of your leverage targets here? Just trying to get a better sense of the ability to accelerate and pull forward some of that value that you clearly highlighted with the deep inventory depth you have.

Tim Leach

I think one of the major messages this quarter we just had is our ability to do more and the efficiencies we are seeing in our operations. So the additional capital for this year will fund 40 new net wells and the production of those 40 new wells will affect 2014’s production.

We’ve increased our guidance there but more importantly it will affect ‘15 and beyond. And I think the efficiencies we’re seeing this year also will continue to accelerate and carry into ’15 and ’16. So I think we come out of the first quarter very confident about our ability to deliver the plan that we discussed and I think we have growing confidence that we can do more than that plan outlined.

Matthew Portillo - PTH

And just my second quick follow-up question will be in regards to -- you highlighted some pretty clear improvements, it looks like, on your rates either on a per lateral foot basis or on a 30-day basis both in the northern and southern Delaware Basin. And I was wondering if you can just talk about, as you think about the about those, are those in relationship to your new completions you’re using in the Basin and how those maybe potentially enhancing your rate of return?

Tim Leach

I think that we are seeing better results for a number of reasons; larger frac jobs, stages that are closer together, longer lateral lengths and a better understanding of where to land the lateral and the section. So I just think the learning curve that we describe to you over time is continuing to pay off for us and these wells continue to get better for a number of reasons and I think when you look at the entire Permian Basin, the areas where we’re located are some of the best rock in the Permian Basin.

Operator

And moving on to our next question, it’s from the line of Brian Singer of Goldman Sachs. Please go ahead.

Brian Singer - Goldman Sachs

Just one question, looking at Slide 13 and 14 and then looking at the strength of your well performance that you highlighted, it looks like it’s the Second Bone Spring that consistently in the northern Delaware Basin was where we saw an increase in the 30-day rates. Can you talk more to that one, is there something unique that you’re doing there or seeing there and can you talk to the aerial extent across both the State Line acreage and the Lusk, Deep, Red Hills block in terms of how widely you’ve tested there?

Tim Leach

The Second Bone Spring is a zone in the Bone Spring where most of our capital is going and as we drill more wells there, our results continue to improve and the second Bone Spring has enlarged in an aerial extended; it is in all of our major areas. That’s not the takeaway from these other zones. I mean I think that as we drilled the zone first, we are continuing to drill other wells in the Third Bone Spring and in the Wolfcamp and the Avalon. And I think over time, those zones will be just as important to our company and just as productive.

But right now, the Second Bone Spring is our primary target, it’s where most of the capital is going and we continue to invest additional capital, marginal capital in these other zones to delineate and to find them as well. That’s the comment I made about the focus of our drilling being to delineate and expand our inventory count, that’s kind of what that gets to.

Brian Singer - Goldman Sachs

Is there anything you are doing on the completion front? Just noticed that your average lateral length looked like it came down on State Line and yet your 30-day IP went up for the incremental wells. Or are you drilling closely to where you've already drilled successful wells? Or are there any more specifics on that zone and what you've done on State Line?

Tim Leach

It’s a mixture of both those. I will say that the answer to most frac questions is pump more sand and that’s what’s happening here as well.

Operator

Our next question is from the line of Scott Hanold of RBC. Please go ahead.

Scott Hanold - RBC Capital Markets

I was hoping you could give a little bit more color on some of the infrastructure additions you are going to have, or the joint venture. What do you perceive as the potential cost savings of moving the volume through the pipelines from the tank battery versus trucking?

Tim Leach

I mean for us this is a particularly interesting opportunity because the pipeline has its own economics that it generates from tariffs on the pipeline. But at the same time, connecting all these tank batteries directly to a pipeline is much more efficient and it removes and reduces that trucking cost. There is more efficiencies than just the trucks, I mean you get it on an automatic measuring system and things like that. So and that has direct economic benefit to Concho outside of this pipeline project.

In addition to this, Eddy and Lea County, New Mexico are going to be a major source of new production development. This pipeline will move between 100,000 and 120,000 barrels a day and it’s in our strategic interest to see that this pipeline is built and by being involved in it, we can make sure that our wells are connected and that our interests are protected in getting this pipeline positioned. So I’m really happy about this project. It also will allow us to gather our production at one point and then give us multiple options on what markets we can send it to.

Scott Hanold - RBC Capital Markets

That's some great color. And so, it sounds like then, when you look at it, you are producing about 42 a day in the northern Delaware Basin from horizontal Delaware stuff. So, there's a lot of capacity to help bring third-party stuff in there too. Is that what I'm hearing, as well?

Tim Leach

Yes, that’s right. And that 42 is -- that’s a net number as well.

Scott Hanold - RBC Capital Markets

On your rig counts going forward, it sounds like you've got some better operational efficiencies going on there because you are able to kind of do more with less. Where are you really seeing some of the savings? Is it drill time? Is it rig moves? Is it completion times? Where are you seeing some of the most efficiencies coming into play?

Tim Leach

The drilling times have come down dramatically, but probably the biggest cost savings in addition to drilling times -- we’ve just added our fifth frac crew that’s working 24 hours a day. And the way we plan our business and the way we work with the pressure pumping companies really allows that to become an efficient operation. And so that’s one of the benefits of scale that we can plan our business to allow these frac crews to work around the clock.

Scott Hanold - RBC Capital Markets

Can you give us a comparison on what -- and I know you have different formations you're targeting, but your core -- your big focus right now is the Second Bone Spring. What does a typical well cost now, say, to what it costs a quarter or two ago?

Tim Leach

Compared to a quarter, things are changing so much. I told you that the frac design pumps more sand, that’s more expensive, but it makes a better well. The lateral lengths continue to increase. That costs more, but makes a better well. But I think we’ve said on the whole if you compare it to six months ago, we’re something like that. Per foot of completed lateral is something like that. We’re probably down 10% to 20%.

Part of it too is what area are you talking about because as we get more confidence around these wells, you get not only efficiency with your suppliers, but you also get efficiency and how you drill the wells and that drives your cost down also.

Operator

Moving on to our next question, it’s from the line of Ryan Oatman of SunTrust. Please go ahead.

Ryan Oatman - SunTrust

With the Brushy Canyon wells, it looked like you all stepped out in the past quarter. Can you describe how the wells literally on that State Line with Culberson County and then further east into Lea County compared with those first tests that you've drilled?

Tim Leach

My first point on the Brushy Canyon is it’s early, I think we only have eight wells in the dataset. My second point is we’re still very encouraged about the potential of the Brushy Canyon as being the shallowest and oiliest zone, the step outs were successful, but I think we knew all along that they would produce water and in some places, it looks like these will be the kind of wells that you get your entire frac load back before you cut oil and then the oil rate builds over time.

So a little bit different profile than when you have a 30-day IP and then it goes on a dramatic decline right away. So these wells are new. There is not a whole lot of data we are encouraged and -- but it’s depending on where you are, I think the profile of the well production is going to be different.

Ryan Oatman - SunTrust

So, these Brushy Canyon wells are similar to, say, what we see from some of the other operators on the Midland Basin side with the Spraberry, in terms of how they kind of clean up over time. I guess speaking to that, have you guys set the location for your first Spraberry test, and kind of what your pre-drill expectations are for those wells relative to your Wolfcamp wells?

Tim Leach

Yes, but we haven’t publicly talked about it.

Ryan Oatman - SunTrust

And then one final one for me. Guidance for 2014 differentials is unchanged. Yet we are seeing some weakness here in the second quarter. Can you talk about what gives you confidence in differentials moving forward, kind of what drives the expectation for things to get better?

Tim Leach

I think the biggest driver for us in the Permian is this BridgeTex line as supposed to come on in July. So I think most folks that are working on those differentials are thinking that we will have improved differentials once the oil starts flowing on BridgeTex.

Joe Wright

LongHorn expansion, too, is right behind that.

Operator

Our next question is from the line of Pearce Hammond of Simmons. Please go ahead.

Pearce Hammond - Simmons & Company

Tim, can you provide an update on service cost right now in the Permian, especially given the big rig ramp we've seen from a bunch of different producers?

Tim Leach

Yes. I think if you’re not a close follower of the Permian, the rig count has gone up by 100 in the last year. And so I think for most operators in the Permian, more rig activity translates to higher costs and I think you’ve heard some of that. I think that one of the great things about being Concho is that with our scale and our efficiency, we haven’t really experienced that up to this point.

Pearce Hammond - Simmons & Company

And then can you provide some color on the LOE guidance range? I saw that it was increased just slightly. You mentioned an increase in activity across the Permian and then certain related infrastructure challenges.

Tim Leach

Yes. I think that the increased guidance on the LOE is primarily driven by these new wells that we’re bringing on that we’re more frequently now running electrical submersible pumps into the hole to move more volume. Those typically generate higher LOE in the early time and then the saltwater disposal costs until we get in -- we’ve had so much new oil come on in these areas that we’re still drilling infrastructure to get the saltwater disposals in. So the increased costs primarily are electricity costs for the submersible pumps and also disposal costs of that saltwater. I do think that long-term that’s a range that we can maintain though.

Operator

Our next question is from the line of Michael Hall of Heikkinen Energy Advisors. Please go ahead.

Michael Hall - Heikkinen Energy Advisors

I just wanted to hit on the Southern Delaware a little bit. You had some good updated results there. How would you characterize what you are seeing in the Northern Harpoon area versus Big Chief and Southern Harpoon, currently, any additional characterization across the results from those areas?

Tim Leach

I don’t know if there’s any additional characterization over what we’ve given in the last quarter, I mean our wells in North Harpoon are very, very good wells. Our wells in Big Chief are very, very good wells. So the wells we’re drilling down at Big Chief tend to be on big leases and therefore allow us to drill longer laterals and -- but that entire area is really something we’re excited about. And some of the acreage that we’ve added recently to our company has been down in that Big Chief area so that’s a real area of focus for us.

Michael Hall - Heikkinen Energy Advisors

Then, on the additional 40 wells, are those -- am I kind of reading it right that maybe a third of that would be in the Northern Del, and then kind of spread the rest of it evenly across Southern Del, Midland, and the New Mexico Shelf, is that --?

Tim Leach

I think that the additional 40 wells should be distributed about the same way as the capital is being distributed throughout our capital budget, so more focused on the northern Delaware Basin.

Michael Hall - Heikkinen Energy Advisors

Then last one on my end, as it relates to the additional spend in ‘14, should we kind of expect those levels of activity to just continue to ride forward? Any additional commentary there?

Tim Leach

Yes. Well, I think, as I said on the call, that I think that the efficiencies we are seeing will carry into ‘15 and ‘16 and beyond. So I think being able to deploy billions and billions of dollars of capital at 50% to 60% rates of return is really the big value proposition here and the faster we can do that and the more we can bring that forward I think it’s just creates a better business.

Operator

Our next question is from the line of Jason Smith of Bank of America Merrill Lynch. Please go ahead.

Jason Smith - Bank of America Merrill Lynch

On the Wolfcamp, it looks like you drilled a few more wells in the State Line area. Can you just talk about the crude quality you are seeing there and maybe crude quality elsewhere across your acreage?

Tim Leach

Sure. The Wolfcamp in the State Line area is the area that you probably heard of throughout the industry where the crude has a higher gravity, maybe 50 degree API that makes it closer to a condensate. We haven’t drilled that many Wolfcamp wells in that area, but that would be my expectation.

Now that’s to be contrasted with the Wolfcamp down in the southern Delaware Basin, that has more 40 gravity-type of crude oil and all the Bone Spring stuff we’re doing and all the Yeso or on the Shelf is a crude quality of about 40 or so. And so really the only area that we are drilling in the Permian where we’ve experienced that high gravity crude oil is the Wolfcamp kind of around the State Line area.

Jason Smith - Bank of America Merrill Lynch

And it looks like you focused mainly on the Wolfcamp. Do you so far have any plans to go further up and test the C and A this year?

Tim Leach

We have a modest Wolfcamp in the northern Delaware Basin budget, so we will be testing different zones, but not as aggressively and most of our capital is going into development of the Bone Spring section.

Jason Smith - Bank of America Merrill Lynch

And one last one. On the Shelf, you guys mentioned that you might look at adding another rig. Can you just maybe talk about the potential timing around that?

Tim Leach

I don’t think I mentioned adding another rig. I think I mentioned just deploying more capital, so I think we can deploy more capital with the two rigs we have there and drill more horizontal wells as we move into the Southwestern extension of that field.

Operator

Our next question is from the line of Jeffrey Campbell of Tuohy Brothers. Please go ahead.

Jeffrey Campbell - Tuohy Brothers

My first question was, as you pointed out in your preliminary remarks, you provided a wealth of data on average production rates and lateral length in your major plays. I was just wondering, do you have average stages per lateral handy for Northern Delaware, Southern Delaware, and Midland Basin?

Tim Leach

I’m going to look around the table here, I’m getting --.

Jeffrey Campbell - Tuohy Brothers

We could go off-line.

Tim Leach

Let’s handle that one off-line.

Jeffrey Campbell - Tuohy Brothers

And my other question was going back to Big Chief. It looks like you are currently producing Wolfcamp A and Bone Spring. I was just wondering, do have exposure to any other zones of interest there? And, if so, when they might become exploration targets?

Tim Leach

We’re working on that right now moving up the hole into the Bone Spring and also testing deeper Wolfcamp and that’s going on currently.

Operator

Our next question is from the line of Mike Kelly, Global Hunter. Please go ahead. Thank you.

Mike Kelly - Global Hunter

I was hoping you could just talk about your expectations for the South Harpoon area in the Southern Delaware Basin, if there's any notable geological differences between there and Big Chief in the North Harpoon area. Thank you.

Tim Leach

Yes. We’ve talked a lot about that area and South Harpoon and as you move in that direction, you are getting shallower, the maturity of the clays change, but recently we’ve drilled a couple of encouraging wells out there and we are adding to our database of understanding and we’ll probably be doing more out there. But at some point, down in that region, I think you run into clay maturity at least in the Wolfcamp zone that will be a challenge.

Operator

Our next question is from the line of John Nelson of Citigroup. Please go ahead.

John Nelson - Citigroup

I wanted to build on an earlier question. I think at the time of the 3Q call you guys characterized the ‘15 and ‘16 CapEx budget, as a good placeholder, might be something like $2.6 billion. With the efficiency gains you guys are talking about today, would it be fair to say that there is potential upside to that number, but then also probably some higher production associated with it should we get there? Any color around ‘15 and ‘16, and how we should think about it?

Tim Leach

Yes, I think you described it accurately.

John Nelson - Citigroup

Any thoughts on how much higher that might be or just sort of wait and see?

Tim Leach

Well, we haven’t given guidance for ‘15 or ’16. I would just say that I think the levels that we’re at now and the type of growth targets we have now will carry into those years and 2x3 plan that we talked about I think is very achievable.

John Nelson - Citigroup

And then just color on the New Mexico Shelf? You guys talked about a second half activity ramp. Any more details with regards to what that could be?

Tim Leach

No, it’s not anything great. It’s just deploying more capital there. We’ve got several thousand locations left to drill there that are very high rate of returns. So we will be happy to get back to deploying capital on the Shelf and that crude oil is very high quality and is in a good location relative to where it’s refined.

Operator

Our next question is from the line of James Sullivan of Alembic Global Advisor. Thank you.

James Sullivan - Alembic Global Advisor

I just want to go back for a second to the midstream JV. You guys had made a point a couple of times of saying that this is the first of what may be -- well, at least more than one agreement out there. Can you speak to whether this current agreement is geographically delimited in any way? And if it is, or if it isn't, where the kind of area of initial focus for the build-out, this first phase of the build-out, is.

Tim Leach

Sure. We have dedicated a substantial portion of our acreage in the northern Delaware Basin and Lea and Eddy county, New Mexico, to the project.

James Sullivan - Alembic Global Advisor

And, so, agreements beyond that would be in the same area? Or how does that work kind of in terms of the dedicated areas?

Tim Leach

This is for oil production. It’s an oil pipeline and we’ve talked about that we have infrastructure opportunities for both oil and gas and the southern Delaware Basin is also a greenfield area that there are opportunities to build-out and control your destiny on where your oil goes and the opportunities you have to move it to different markets.

James Sullivan - Alembic Global Advisor

The second thing was, obviously recognizing it's very early on this, but you guys did drill a couple of wells on the Delaware Ranch acreage, can you characterize that at all, beyond just that you drilled them? Is there a section thickness? Is there any color you can give on that?

Tim Leach

I don’t think we’re giving additional color there. I mean we’re very pleased with that acreage. We’re happy we’ve got it, it’s early and continuing to drill.

Operator

Our next question is from the line of Richard Tullis of Capital One. Please go ahead.

Richard Tullis - Capital One

Just two quick questions. Tim, it looks like the last six wells drilled in Midland Basin horizontals took a pretty nice step up in average 30-day rate too. I know you've talked a lot about the Delaware Basin. But any talk or detail on those Midland Basin wells, and then what gets you a little more active in that Basin, as well?

Tim Leach

We, in our -- this year’s capital budget plan to become more active. We’ve got quite a few rigs dedicated to that activity. It’s primarily in the Wolfcamp A and B. We’re continuing to optimize frac designs, that’s primarily the area where we’re going with denser cluster spacings and that seems to be working quite well. So I think you can count on seeing that ramp up over time.

Richard Tullis - Capital One

And then, just lastly, I'm not sure if you mentioned this, what share of the cost -- the total cost for the oil transportation system in Northern Delaware Basin will Concho be funding? What percentage of the JV?

Tim Leach

We’re currently about 50/50 partnership.

Operator

And the last question is from the line of Joe Allman of JPMorgan. Please go ahead.

Joe Allman - JPMorgan

Tim, I think you gave an indication of the reduction in cost per 1,000 foot of lateral. But could you just give us some recent well costs on an absolute basis? So, for example, on your northern Delaware Basin, Second Bone Spring, what are some of those wells costing now versus six months ago? And what's the uptick in EURs versus six months ago or a year ago?

Tim Leach

I’m going to turn it over to Joe. He is sitting across the table from me.

Joe Wright

Yes, Joe, this is Joe Wright. I think a good area to talk about the State Line where probably six to 12 months ago, those wells were costing about $5.6 million to drill a one mile lateral with kind of a typical stimulation job on it in the Second Bone Spring. Today that well is AFE-ing right around $5 million, to give you a good indication in that area. And those areas that are development like that, that’s what we’ve seen.

Joe Allman - JPMorgan

So, Joe, you are talking about a lower cost with a bigger frac?

Joe Wright

I’m trying to compare the same size frac job, what I call, a typical job between that time frame you gave me.

Joe Allman - JPMorgan

With the bigger frac, how much are those wells costing these days?

Joe Wright

Where we can use a, what we had termed before, larger job, they can add somewhere around $1 million.

Joe Allman - JPMorgan

And what kind of uptick -- what EURs are we looking at, say, six months ago, for those wells? And what kind of EURs are you looking at with the bigger fracs?

Joe Wright

We’ve not given any of those -- I don’t believe we’ve given any models on that up to this point.

Joe Allman - JPMorgan

Could you just describe on a percentage basis what the increase in EUR might be?

Joe Wright

Well, it’s the same type of economics, if not, just a little bit better, so to give you a little handle there.

Operator

Thank you for your questions. I’d now like to turn the conference over to Mr. Tim Leach for closing remarks. Thank you.

Tim Leach

Okay. Thank you again everybody, and I hope you can tell that our whole team is very excited about the first quarter and all the operational success we’ve been having and we think this will carry well into ‘15 and ‘16 and I look forward to talking to you more about in the future. Thank you very much.

Operator

Thank you for participating, ladies and gentlemen. That concludes today’s conference call. You may now disconnect your lines. Have a good day.

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Source: Concho Resources' (CXO) CEO Tim Leach on Q1 2014 Results - Earnings Call Transcript
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