Diamondback Energy, Inc. (FANG) Q1 2015 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the Diamondback Energy and Viper Energy Partners First Quarter 2015 Earnings Conference Call. [Operator Instructions] As a reminder, this conference is being recorded. I would now like to introduce your host for today's conference, Adam Lawlis of Investor Relations. Sir, you may begin.

Thank you, Sarah. Good morning, and welcome to Diamondback Energy and Viper Energy Partners Joint First Quarter 2015 Conference Call. During our call today, we will reference an updated investor presentation which can be found on Diamondback's website. Representing Diamondback today are Travis Stice, CEO; and Tracy Dick, CFO; as well as other members of our exec team. During this conference call, the participants may make certain forward-looking statements relating to the company's financial condition, results of operations, plans, objectives, future performance and businesses. We caution you that actual results could differ materially from those that are indicated in these forward-looking statements due to a variety of factors. Information concerning these factors can be found in the company's filings with the SEC. I will now turn the call over to Travis Stice.

Thank you, Adam. Welcome, everyone, and thank you, all, for listening to Diamondback's and Viper Energy Partners First Quarter 2015 Conference Call. It was another great quarter for Diamondback as we had production that exceeded expectations and we raised production guidance as a result of well performance, increasing completion activity and accretive acquisitions. We plan to add a second completion crew in June to go to work down the inventory of drilled but completed wells because cooperation with service providers had lowered our well costs 20% to 30% since the service cost peak in the third quarter of 2014. Additionally, we plan to add 2 horizontal rigs later this year. As a result of service cost concessions and efficiency gains, we are keeping CapEx unchanged despite increasing activity. The accretive acquisitions are located in the core of the northern Midland Basin primarily in northwest Howard County where economics and productivity rival those of Spanish Trail in the Midland County. I will talk more about the details of those acquisitions later in the call. I will now turn to our updated slide deck that can be found on our website. The Lower Spraberry shale continues to exceed our expectations. As shown in Slides 6 and 7, Lower Spraberry completions in Midland County continue to exceed our million-barrel type curve while those in Martin and Andrews County are tracking well above the 800,000-barrel type curve. As a reminder, about 2/3 of our completions this year will target the Lower Spraberry formation. Now turning to costs. AFEs are trending towards the low end of the $6.2 million to $6.7 million guided well cost range per 7,500-foot lateral. Several of our upcoming 7,500-foot lateral wells are on track to cost less than $6 million. We've also seen approximately 15% of cost concessions associated with LOE. Specific cost reductions are broken out on Slide 10. Since we're still completing wells drilled before we received cost concessions, we continue to expect to be within this guided well cost range of $6.2 million to $6.7 million for the year. We're projecting that at $60 a barrel for WTI, our cost savings and efficiency gains will allow us to generate project rates of returns comparable to those generated when WTI was at $75 a barrel. With the improvement in service costs and oil prices, we will resume our former pace of completion activity by adding a second dedicated frac crew next month to work down our backlog of drilled but uncompleted wells. We plan to increase our rig count from 3 to 5 rigs in the third and fourth quarter of this year and could potentially add another 2 or 3 rigs in 2016 to continue this growth trajectory. With the inclusion of our announced acquisitions, we now have an acreage footprint that can accommodate up to 10 horizontal rigs. We are reiterating our guidance for a total capital spend of $400 million to $450 million despite expecting to drill and complete more wells. Including the effect of the acquisitions, increased completion activity and strong productivity, we are also increasing our production guidance 11% at the midpoint to a range of a 29,000 to 31,000 BOEs a day. More than half of the increase is due to increased completion activity and productivity with the remainder of the increase coming from pending acquisitions which we expect to close by the end of June. Diamondback increased production 19% quarter-over-quarter to 30,600 boes a day, which exceeded expectations. The increase in production is primarily associated with the strong productivity of wells that came online during the quarter. Diamondback's track record for peer-leading efficiency and execution continues, resulting in cheaper wells and higher rates of return. Slide 12 shows that during the first quarter, we drilled 2 well pad with an average lateral length of 10,000 feet per well in 31 days from spud of the first well to TD of the second. In Martin County, we drilled a well with an approximate lateral length of 8,200 feet in 12 days, our best drilling performance to date on this acreage block. With these service cost reductions and continued efficiency improvements, rates of returns are now more than 85% per Spanish Trail Lower Spraberry well and nearly 200% where Viper owns the underlying minerals, as shown on Slide 13. Last night, Diamondback announced that we have acquired or entered into definitive agreements to acquire approximately 12,000 net acreage from private parties for $438 million, including 2,500 barrels a day of production on a 3-stream basis from 117 gross vertical wells and 3 gross horizontal wells. These transactions demonstrate both of our acquisition strategies: The bolt-on acquisitions in and around our core areas and adding new a development area. These assets, located primarily in northwest Howard County, provide us with approximately 232 net horizontal locations primarily in the Lower Spraberry, Wolfcamp A and Wolfcamp B formations on blocky acreage that is ideal for drilling longer laterals. Recent horizontal wells in the area of northwest Howard County confirm our geochemical data that indicates our 3 primary targets are well into the mature oil window. We expect EURs for these locations to range from 600,000 to 900,000 boes, which provides a low acquisition cost of approximately $2 a barrel. We expect roughly 40% of these locations to be drilled at 10,000-foot laterals, with the remaining locations being predominantly 7,500-foot laterals. Longer laterals support low refining costs, higher capital efficiency and stronger rates of returns. Additional upside may exist in the Middle Spraberry. There are over half a dozen Middle Spraberry wells drilled in and around the Spanish Trail acreage in Midland County with encouraging results. And the target looks very similar in Howard County. With over 25 wells completed in the immediate vicinity of the northwest Howard County, we consider this to be a proven area and the most derisked acquisition in Diamondback 's history. As shown on Slide 16, offset EURs range from 600,000 to 900,000 BOEs, which make the asset in the top quartile of our inventory with economics that are competitive with Spanish Trail. Slide 17 includes a cross section showing that the horizontal target shale formations in northwest Howard County are comparable to Spanish Trail in Midland County. Included in this acquisition is a 1.5% overriding royalty interest that we've offered to Viper Energy Partners for $34 million, which would leave Diamondback Energy with approximate 75% NRI. We expect to begin developing this acreage in 2016 or sooner depending on the timing of infrastructure needed to support a 2-rig program. You have heard me [indiscernible] all Tier 1, which is a type of acreage that generates the highest cash margins and rates of returns to our investors. As I have said many times before, Diamondback is committed to delivering best-in-class operations and the highest cash margins in the Permian Basin. With these comments now complete, I will turn the call over to Tracy.

Thank you, Travis. Diamondback's net income for the quarter was $5.8 million or $0.10 per diluted share after adjusting earnings for our non-cash market-to-market derivative losses of $25 million. Netting out the related income tax effect, our adjusted net income was $22 million or $0.38 per diluted share. Diamondback's adjusted EBITDA for the quarter was $110 million, roughly flat quarter-over-quarter due to increased production despite lower commodity prices. Our average realized price per BOE for the first quarter was $36.78 and due to the positive impact of our hedge position, our average realized price per BOE, including the effect of hedges, was $52.57. We are currently looking at opportunities to layer on hedges for 2016. We laid out the detail of our current hedge position in last night's earnings release and on Slide 22 of the presentation. Turning to cost. Our LOE was $8.14 per BOE for the quarter, a 17% reduction from fourth quarter of 2014. We continue to see cost concessions and to implement best practices on the acreage acquired in 2014. Learning from our experience of last year when we acquired nearly 300 gross vertical wells, we're making a minor adjustment to our LOE guidance as the result of acquiring 117 gross vertical wells in the announced acquisition. We think this new guidance of $7 to $8 per BOE is manageable given that we decreased LOE 17% quarter-over-quarter due to reductions in well servicing units, route about [ph], water, trucking, chemicals and other components. Our cash G&A cost come in at $1.20 per BOE while noncash G&A was $1.79 per BOE for the quarter, both within full-year guidance ranges. We believe that our total G&A of $2.99 per BOE is among the lowest in the Permian Basin on a per-BOE basis. In the first quarter of 2015, Diamondback generated $99 million of operating cash flow and $109 million of discretionary cash flow for $1.69 and $1.86 per diluted share, respectively. During first quarter of 2015, we spent approximately $149 million for drilling, completion and infrastructure. The majority of first quarter 2015 capital spend was associated with 2014 projects. We continue to expect our total capital spend to be in the range of $400 million to $450 million for 2015, unchanged from previous guidance due to cost savings and efficiency improvements. We anticipate our CapEx will trend down due to reduced rig count in the first half of 2015 and lower well cost. As of March 31, 2015, we had $162 million drawn on our secured revolving credit facility. Diamondback's agent lender under its revolving credit facility recently recommended a borrowing base of $725 million. However, the company intends to continue to limit the lender's aggregate commitment to $500 million. We believe our current volume availability provides us with plenty of liquidity. We estimate our 2015 year-end debt-to-EBITDA will be less than 2x. At current commodity prices, and with the current drilling program, we expect that we will turn cash flow positive in the second half of this year. I'll now turn briefly to Viper Energy Partners, which recently announced a cash distribution of $0.19 per unit for the first quarter. This exceeded expectation. During the quarter, cash available for distributions was $15 million and production increased 16% quarter-over-quarter to 4,844 BOE per day. Viper has no debt and an undrawn revolver of $110 million as of March 31, 2015. Viper's agent lender under its revolving credit facility has recently recommended a borrowing base increase of 60% to $175 million subject to the approval of the other lenders. Turning to Viper 's guidance, we expect 2015 volumes in the range of 4,600 to 5,000 BOE per day, up 10% from prior guidance. As a reminder, Viper does not incur lease operating expenses or capital expenditures. With that, I'll now turn the call back over to Travis for his closing marks.

Thank you, Tracy. To summarize, this quarter, we've increased production guidance, resumed our completion activity and announced several Tier 1 acreage acquisitions. Service cost concessions and continued operational efficiencies have improved rates of returns equivalent to when WTI was $75 a barrel. As a result, we plan to pick up additional rigs later this year. Our intense focus on execution and generating differential cash margins has never wavered even as we go through this down cycle in commodity prices. I'm proud of all that our employees have accomplished so far this year and look forward to updating you on our progress. On behalf of the board and employees of Diamondback and Viper, I would like to thank you for your participation today. Operator, please open the call to questions.

[Operator Instructions] Our first question comes from Mike Kelly of Global Hunter Securities.

I think the first thing I'd ask is on your decision here to go back to work. And you mentioned in the release that you could see the rig count going from 3 all the way up to 8 rigs at some point in 2016. And I was just hoping Travis, you could detail kind of what the criteria is to get there? And how fast you might be able to ramp to 8 rigs.

Sure, Mike. It's really a function of a couple of things. We've got to maintain discipline on costs from the service community and commodity prices continue to need to improve. But on a general sense, as I outlined in our call, we believe we're generating rates of returns when commodity price was equivalent to $75 for WTI. So right now, we'll look at that. We've got a rig coming in the third quarter, one in the fourth quarter. And certainly, as commodity price continues to improve, we'll be able to add late fourth quarter, early first quarter, additional rigs to primarily go to work in our newly acquired acreage in Howard County.

Okay, Great. As a follow-up on that, just as you think about the balance sheet, and you mentioned in the release, too, that you'd look to fund the acquisition and, really, the pending ramp here in activity with potentially a combo of debt and equity. And when we ran your numbers last night, we saw that even after paying for this deal and ramping to 8 rigs over the course of next year, debt-to-EBITDA doesn't really even go over 2.5x. Just curious, what -- how you guys think about what's an appropriate target for leverage and the need to do equity going forward?

Yes, our stance on leverage really hasn't changed since before we took the company public. We always -- we state that we like to keep a leverage ratio of below 2. And I think that's logical to assume going forward as well. What's really unique about Diamondback is the different forms of financing that we have available to us. We have the opportunity to issue equity like we've done historically for acquisitions. We also have the high-yield market that's open to us. We have unused capacity on our revolver. And we also have a ownership in Viper Energy Partners. So we really got multiple ways to fund this acquisition going forward.

Our next question comes from David Amoss of Iberia Capital Partners.

Travis, you mentioned the infrastructure as kind of something that you need to get on the acquisition before you start to go to work there. Can you talk about what specifically you're looking for? And then what kind of time frame you're looking at to get that put in place? And is that something that Diamondback's going to do themselves? Or is that a third-party deal?

Sure. David, well, we set aside roughly $20 million in the acquisition to put an infrastructure in place that's necessary to support the -- a 2-rig horizontal program. And what that really entails is primarily the accumulation of stimulation fluid. So it's stim fluid accumulation ponds, it's pipes and facilities able to accommodate high volumes. This property was developed with vertical wells, and while we're pleased at the condition of the facilities associated with the vertical well development, most of those are going to need to be upgraded to accommodate significantly higher fluid handling capacity. So as soon as we close this deal, we'll go out at Diamondback, not a third party, and will begin that infrastructure. One thing I'm pleased with and we outlined in the acquisition is that we also acquired a saltwater disposal system for about $5 million. So we -- quite a bit. But can't start work until the close the acquisition, which is in the middle of June. That being said, we've got our plans firmly underway, at least on paper, to make a rapid transition to horizontally develop this acreage.

Got it. And then looking at your Slide 17, I mean, it looks like the Wolfcamp B on the acquisition is actually considerably thicker than it is at Spanish Trail. Do you actually expect to be a more attractive target at the acquisition? How should we think about that going forward?

Really, when we look at these 3 primary zones here, if you look at Slide 16 and you look at the offset results, we put quite a few of them here nearest wells to this acreage block. The Lower Spraberry and the Wolfcamp A are the 2 best performing zones. The Wolfcamp B is not quite as good as those other 2, but if you look at the location of the Wolfcamp B well, they're east of acreage block. And that Wolfcamp B does thicken as you go to the west. So we think the -- we've got a good chance of the Wolfcamp B being better on this acreage than it is on the wells to the east. So overall, we think we've got 3 really nice targets here.

Great. And then -- and one last one if I can. Just as you accelerate and you think about the cyclical cost reductions that you've seen so far, how do you think about potentially locking those in? Or is there a point where you're getting a service company coming back and trying to claw a portion of that back? How do you keep the cost component in a place that you're comfortable with as you accelerate?

Well, we'll always try to hold the line on costs. Service companies are not willing to lock-in long-term contracts at what appears to be close to the bottom of the cost cycle. So it's, again, working very collaboratively with business partners because if costs continue go -- if cost go up faster than commodity price goes up, Diamondback, using our same mantra of capital discipline, we'll tap the brakes again. So I'd like to say yes, we've locked-in these low-cost for all time. But the reality is, is that you just can't do that right now. But again, the natural governor is increased activity versus laying rigs down, and that's certainly what drove the behaviors that got us to going back to work right now. And we have -- we still have that lever going forward as well, too.

Your next question comes from John Nelson of Goldman Sachs.

Comments from most of your peers are that asset sales that have come to market over last 6 months had been situated more at the fringes of the field are lower in quality. I was wondering if you could first maybe comment on certainly, this was an attractive acquisition price. But do you feel that the -- what makes you so certain that these assets are high quality? And if you could, what IRRs you expect on that 600 million to 900 million MBOE -- I'm sorry, MBOE type curve at $60? And then secondarily, are we -- are you actually seeing a shift in the M&A pipeline to higher quality assets starting to make an entrance?

Yes, John, several good questions there. I'll try to take them in the order you asked them. As I outlined in my prepared remarks, this acquisition in northwest Howard County marks of the most derisked acquisition in Diamondback's history. And I don't make that statement casually. We've had -- got over 60 wells where we had open-hole logs where we were able to do our geochemical and petrophysical work supported by hole-core analysis that really highlighted the oil in place and the significance of these shale horizons. And also, while I think we've only put about 1 dozen or maybe 13 wells that have public data available in our slide deck, we really had over 25 slides in and around this area -- 25 wells in and around this area that's had IP-30s and established production that allowed us to go in and put reserve forecast on those wells. And so we've never had that many data points, both from a geoscience perspective and/or from a well performance perspective, that gave us confidence in this research block. And I know the there's a lot of question on what other quality deals are out in the M&A market, and my history has been that we don't really talk about acquisitions that are underway. I can tell you, though, that my shareholders should expect that Diamondback is actively involved in the M&A arena. And we intend to continue to be so going forward.

And if I could just...

John, I'm sorry. You had another question on rates of returns for those 600,000 and 900,000 type wells. They're going to be in that 40% to 70% range at today's price and today's service costs. So really, I didn't -- I made the comment that these wells were in the top quartile of Diamondback's Energy's portfolio, and it's supported when you look at these rates of returns.

That's very helpful. And I was just hoping just get one clarification on your earlier comment. Would the addition of rigs 6 to 8 then be contingent on further improvement in commodity price? Or are you just saying that we need to sort of stay the course with this?

Yes, it's more of the latter.

Your next question comes from a Dave Kistler of Simmons & Company.

One, congrats on a great acquisition. And obviously another stellar quarter, weather clearly didn't impact you guys, as others commented on. One of the things that I'm curious about is you ramped the rig count up, and in the past, you've talked about this. And as you continue to acquire, do you feel like you have the appropriate staff in place to run an 8-rig or even a larger rig program? If you could just refresh us in terms of what kind of capacity you think your staff has at this juncture.

Yes. You know what, as an executive team, we've sort of always talked about building a bandwidth that's capable of running 10 horizontal rigs. And so when I made the comment that we now have got an acreage footprint that supports a 10-rig program, I believe that we're close to having that bandwidth right now. There may be 1 or 2 additional key contributors that we need to add to kind of help support that. But yes, sort of in that 10-rig cadence is what we've tried to build the organization around. And I've just -- just as an aside to that, even though we talk about a bandwidth for a 10-rig program, really, when you look at the pace at which we drill these wells, I think a 10-rig program is really like a 15- or a 20-rig program just how fast that we can get these wells drilled, which is sort of why I highlighted the fact that we got 2 10,000-foot laterals drilled in about a month's time. So we keep an eye on that, on our organization. And again, we try to build it around that 10-rig cadence.

I appreciate that color. And then kind of following up on that, obviously, with the speed at which you're drilling, the inventory of wells that are producing right now, have you looked at building up? Or do you already have in place a kind of field or well control team to ensure uptime of the existing production? Obviously, as the footprint gets wider, that becomes harder to control. And just curious how you're thinking about that.

Yes. We've got on the production side what we call a PWIP, it's a production well improvement program, that's the PWIP plan that weekly and monthly goes through and analyzes the producing performance of all of these wells and then also does a detailed deep dive on any wells that have failed to try to be proactive in failure identification. Because really, it's that failure identification, pumping practices that eliminate those failures. Our -- most of these vertical wells we've acquired over the last 12 months have a failure rate of somewhere north of 1.5. And the wells that we acquired last year, those 300, I was looking at our first quarter report. And we've driven that well failure rate down from 1.5 down to, I believe, it's about 0.7 right now. So obviously, that has a very positive effect, particularly in the well maintenance category of LOE expenses. So we're closing in on 1,000 total well bores right now, and that's not a casual number to -- for our field organization to try to optimize. And to further make that a little bit more difficult is that we're all the way from Upton County now into the Howard County and into Martin County. So we're close closing in on about 9 counties where we operate wells. And so sometimes, that dispersion causes a little bit of a -- gives a little bit of efficiencies. But it's -- that's what we do though. We have Jeff White, he's our Vice President of Operations, and his whole organization is up to the challenge of making sure we can maintain best-in-class operations from our field organization's perspective.

One last one. Just relative to the ability to ramp up but also the ability to ramp down as you highlighted. The rigs that you'd be picking up, the completion crew that you're picking up, what kind of terms are you looking at on those? Are we talking well to well? Are we talking more a contractual over several months to a year? Any kind of color on that would be helpful.

Yes, we've got -- the rigs we've got that are coming on, they're all under different contract periods. And as we go from rigs 6, 7 and 8, we'll be picking those rigs up on a well-to-well basis. And that's one of the slides, and I can't remember which one it is, it references the rig cost. You can see that it -- our rig cost has only come down 3%, that's because most of those were under pre-existing contracts. As we continue to add rigs, one of the more significant cost savings we'll have is the day rate on the -- on those drilling rigs. The completion crew, we picked it up, we've committed to them that we've got a dozen-plus wells that we need to work off of in our inventory. And as long as the commodity price holds, we'll continue to work that. But they're not operating under any form of long-term contract.

Our next question comes from Gordon Douthat from Wells Fargo.

As you look to ramp your rig activity, it looks as if there's a potential for 2 to go in Howard County. Just wondering beyond that, how you look to spread your rigs across your acreage.

Gordon, we'll always keep as many rigs in Spanish Trail as we can, which is somewhere, just from an operated perspective, a max of 2 to 3 rigs. And that includes that acquisition that we bought in the fourth quarter of last year, the Gridiron area and some of the acreage that's slightly outside the Spanish Trail. So we'll keep 2 to 3 rigs there. We'll keep probably 2 rigs up to the North bouncing around between Northeast Andrews County, Northwest Howard County, where we've got good $1 million [ph] barrel type wells there in the Lower Spraberry. We'll keep -- go to work one or so in the Glasscock County area. Again, that's a new acquisition that we had last year, and then we'll keep 2 in Howard County. So we'll have a couple that bounce around, and we'll keep I think 1 more rig in Southwest Martin County. And that should get you somewhere in that 8- to 10-rig cadence, depending on commodity price and service costs.

Okay, that's helpful. And then just wanted to get your thoughts on hedging. I know Tracy, you mentioned that you're looking to add some for 2016. And just wanted to get your thoughts on what you're looking for in order to get more aggressive with the hedging position next year.

Sure, we've kind of had an internal mark on the well, it's about $65 a barrel WTI. And I think this week, for the first time, hedges crossed over, the forward strip crossed over to about $65 and $65.50, something like that. I haven't looked at it today. But we're pretty close to the point at which I think we want to start building our hedge book. It's something I work with the board with a couple of times a week and just trying to keep them informed as well, too. Dave, the board, has guidance of -- to us, it's somewhere between 40% and 70%. And we're not anywhere near that in 2016. So I think we've got a nice little run in commodity price, we're watching it real closely, and potentially could start adding hedges in the not-too-distant future.

Our next question comes from Gail Nicholson of KLR Group.

As you increase that rig activity, really kind of looking at the '16 forward time frame, should we anticipate that the number of wells on your pads will also increase? Or how should we think about that?

Yes, Gail, I think the most efficient capital of that you can deploy is when you keep a rig on the pad as many times as you can. And sort of our sweet spot looks to be about 3 rig -- a 3-well pad. That takes in a lot of things, drilling, simultaneous operation with offset completions. And so as you -- as we continue to add and pick up rigs, more and more of our additional rigs will be on multi-well pads. In 2016, although we've not really looked at it in detail yet, and specially including this new acquisition, most of our rigs will be on multi-well pads. The only horizontal rigs that we have that won't be will be the ones that kind of bounce around a little bit in the Northeast Andrews County and Northwest Martin County. But other than that, we should be doing mostly pad work.

Okay, great. And then on -- just a standpoint -- I was wondering if you can give any update on the Lower Spraberry well in Dawson County and how that has performed.

Yes, the Dawson County well, it's been on for quite a while now. You get a really -- still continuing to perform in line with what we were projecting before, which is somewhere around that 600 MBOE type well, which again, at current commodity prices. I'd say above our threshold rate of return. It doesn't quite compete with some of our other Lower Spraberry result. But we think as hopefully, commodity price continues to improve, and over time, we'll develop that acreage block as well.

Our next question comes from Jeff Grampp from Northland Capital Markets.

I was hoping to maybe get your thoughts on production growth throughout the remainder of the year, I know you guys don't like to give quarterly guidance, but looking like maybe 2Q, maybe a little bit stagnant as you start. And then maybe you just start working down the backlog. I assume second half will be stronger. And is the assumption that a lot that is probably going to hit 4Q? Or maybe some contribution in 3Q? Just kind of getting your thoughts on production cadence throughout the remainder of the year.

Yes, Jeff, good question. And you're right, we don't give quarterly guidance. But I'll tell you as Diamondback kind of stood up earlier this year and said that capital disciplines matters and returns matters, we started deferring completions and laying rigs down. Most of the effects of that capital discipline decision are going to be felt in second quarter, and it's going to be measured by fewer wells completed in the quarter than we did in the first quarter. So I think your original assessment of how production profile's going to look is probably a good way to think about it. Whether it's exit or 4Q impact or early 1Q '16 impact, it will -- as you increase rigs and increase completion activity, we'll go back to that volume building trend.

Okay, that's helpful. And on the acquired properties, obviously getting a nice leg of production there. Do you guys kind of have a sense for what the base decline is with those existing wells? Seems like with the -- a mix in newer horizontal and I guess some legacy verticals there.

Obviously, the biggest majority of those are vertical wells. And the horizontal wells that are on there right now are some non-operated wells where we have a low working interest, so that's very little impact. Most of those vertical wells have been on production for 4 or 5 years. So we're down in kind of that 15%, 20% decline rate on the PDP.

Okay, perfect. And then last one for me. I guess with the planned acceleration in activities, is there an increased interest on your end to test more downspacing, other types of upside projects across your acreage position? Or is it still just kind of going for the known quantities in your portfolio?

Yes, Jeff, that's a good question. I don't think we're ever satisfied that we're extracting all that we can out of these unconventional rocks. So we continue to try different things. More, I would say, tweaks as opposed to complete overhauls on our completion strategy. Again, Jeff White and his completion organization, they stay up to speed on all the ongoing completion enhancements that are taking place out here in the Permian. And on selective instances, they try that, and we monitor it so that we make sure we can get good feedback on the changes that were made. But in the general sense, it's more tweaks than complete overhauls.

Our next question comes from Jeffrey Connolly of Clarkson Capital Markets.

Can you give us an update on the Lower Spraberry wells you drilled on 500-foot spacing? And if you think that the 500-foot spacing is applicable across your acreage? And if you're not there yet, kind of what you need to see before you get comfortable with that?

Yes, if you look at that slide that shows our Lower Spraberry results for Midland County, I believe it's in Slide #6. That 500-foot spacing is -- the ST West, 7-1LS and 7-2LS, we've show the average of those 2 wells on that pad. And you can see so far -- I mean, it's tracking with the results of the other wells. That's still early. We've got somewhere around 150 days of production on those 2 wells, they're very encouraging results so far. So right now, the Spanish Trail area, we're going forward with the 500-foot spacing and we'll be testing that 500-foot spacing in our other areas as well. We recently completed a microseismic survey on a 3-well pad in Spanish trail that we actually did at 660-foot spacing. We're just now getting the results back on that. So we'll take a hard look at the results of the microseismic and refine our spacing as we go forward.

Okay, great. And then Diamondback's talked about being cash flow neutral or positive in the second half this year. Is that still the case if you choose to add the 2 rigs? And then are those 2 rigs included in the $400 million to $450 million CapEx program?

Yes, Jeff, as was indicated in our prepared remarks, this increased activity will still be within our original guided CapEx range because of the cost concessions that we've seen today. So that's a not too subtle message that we're able to stay within our original CapEx guidance, not increase it, but get increased activity.

Our next question comes from Jeb Bachmann of Scotia Howard Weil.

Travis, just a quick question on the acquisition. Just wondering, the vertical well control, is that across the acreage to give you enough confidence in that cross section that you provided, I guess, on Slide 17, with the different targets?

Yes, absolutely, Jeb. We've got real fulsome analysis from a cross-section perspective, both East to West and North to South, across this acreage block. So extremely good coverage with vertical well control. And then again, as I highlighted and then we've included in our slide deck, there's enough offset production data as well to further enhance our confidence.

And then just briefly on kind of the completion design. Can you update us on what you guys are doing right now to maybe help improve those EURs above what Ryder Scott has did -- put you at earlier this year?

Well, as I mentioned on the previous call, we're not making major overhauls to our completion design. We continue to go 300,000 or so, 300,000, 350,000 pounds per stage, our per-foot concentration is 1,200 to 1,500 pounds per foot. And we're predominantly using white sand in our Wolfcamp completions and brown sand mostly now on our Lower Spraberry completions. We continue to tweak the number of clusters between each stage and also tighten the interstage distances to get a few more fracs in there. And we've done that on a couple of 2-well pads now. And we're monitoring results real closely to see if tighter spacing has a corresponding impact to the EUR.

Our next question comes from a Jason Wangler of Wunderlich.

Travis, just had one for you. Obviously, coming back and starting with the inventory and then the second frac crew. Just curious, do you have a rough idea of what your backlog looks like now? And what you think it will look like on the steady-state basis as we get to the end of the year?

Yes, we're probably about -- we're probably in that maybe 15-plus range right now of wells waiting on completion. What's kind of a reasonable backlog per rig is around 2 to 3 completions behind each rig. That sort of seems to be the most efficient way for us to manage and being able to move the crew to the next well that's ready. And so just as a -- from a planning perspective, you got to look at 2 to 3 wells waiting on completion ahead of each drilling rig.

Our next question comes from Richard Tullis with Capital One Securities. We'll move on to the next question, it comes from Welles Fitzpatrick of Johnson Rice.

Congrats on the strong acquisition. On the acquired acreage, do you guys own all depths? And if so, does the Cline rank anywhere on the to-do list?

Yes, I mean, it depends on the particular lease, but in almost all of them, we have leased, own them through the Cline. There is some, I'd say, some Cline potential, there has been some -- and I'd say reasonably good Cline wells south of our acreage. As you move north, the Cline gets to be more carbonate than shale. So we really like the A, B, Lower Spraberry and Middle Spraberry here more than the Cline. But in at some commodity price, there probably is some prospectivity for the Cline.

Okay, perfect. And then just one more. Did you say that the $20 million in infrastructure spend was included in the $438 million number?

Well, as we modeled it from the CapEx spend going forward, we included -- that's a CapEx number that we think we'll have to have going forward. So it's not included in the $438 million. It's just a CapEx number that we think is going to be spread out over the next 12 to 24 months as we initiate and implement that infrastructure spend.

Our next question comes from Richard Tullis of Capital One Securities.

Two quick questions. So this acquisition should bring your total to around 89,000 net in the Permian. You looks like you let a couple thousand acres go in February in Crockett County. What's the outlook for any additional exploration of acreage this year? Particularly interested in acreage in Central Andrews. I guess you have a maybe upward of 10,000 acres there. What's the outlook for that?

Sure, Richard. We kind of joke around here that we're hunters, not farmers, and so we're never really satisfied that the inventory that we've got is the right number. We're always looking to expand our footprint by doing accretive acquisitions. I'll let -- we will continue to be active in M&A. We're not necessarily what you'd categorize as an exploration-oriented company. But we're going to continue to be active in the M&A market starting today. So I'll let Russell answer the -- kind of the question on Central Andrews County.

From -- if you remember, in Central Andrews County, we've tested the Clearfork there with a couple of horizontal wells. And I think as we've mentioned before, that second Clearfork well that we drilled in the Lower Clearfork Shale has continued to perform well, the declines are actually much flatter than we originally projected. And so that Clearfork really looks -- is looking better and better all the time based on the performance of that second well that we drilled. So at current commodity prices, it's certainly economic, but not in the top quartile of our inventory. So you probably see us test the Clearfork again sometime over the next year to kind of confirm those results, but not a '15 program at this time.

Okay, Russell. That's helpful. And then just lastly, Travis, I'm not sure if you touched on this a little earlier. But of the -- how do you split that, say, between internal efficiencies versus vendor reductions?

That's a good question, Richard. I think the split is probably closer to 80-20, maybe 90-10. But you have to keep in mind that as we've built this company over the last 3 years, our efficiencies [ph]. So we've never satisfied that we've got all the pennies picked up off the ground from an efficiency perspective. But probably 80-20, 90-10, with the larger number being associated with service cost concessions.

Our next question comes from Neal Dingmann of SunTrust.

Travis, I was just wondering that slide you have that shows the downspace and stack pay potential, I guess my question, are you still pretty optimistic about on the 3 areas there on the Middle Spraberry going from 6 to 8 per section? And then looking at the lower 8 to 10? And then obviously, the Wolfcamp from 4 to 8? On not just in Spanish Trail, but your thoughts about sort of that similar downspacing if I look at either Southwestern or Northwest Martin or Howard or Glasscock.

Yes, Neal, maybe we're a little conservative in the way that we look at the numbers of laterals that go across the section. We sort of use that as a risking mechanism. But the least we know about a zone, the fewer laterals we'll put in. And I think industry has shown, if the shale works and generates the economics, somewhere between 6 and 10 is going to be the right number. So Middle Spraberry, while we've got a couple of wells drilled and some testing going on. We're -- we just don't have a lot of information there. And so I think industry has shown, not only in the Permian but also on all the other basins with these shale development, that they tend to get tighter, not broader, over time as the -- as more and more wells get drilled. So most of our well cadence or well counts in our inventory are biased upwards given success in each of these productive zones.

Got it. Then just lastly, maybe for you or Tracy, just on your comment about the positive second half cash flow. What -- I forget, what commodity prices are you using there? Are you assuming current cost?

Yes, current cost, but we modeled it -- we modeled the company at $50 flat.

Our next question comes from Michael Rowe of Tudor, Pickering, Holt & Co.

I just had a quick follow-up question on the Howard County acquisition. So the acreage there looks to have very good oil in place and thermal maturity. Can you just talk to the porosity and permeability that you're seeing there? And maybe kind of compare that to the Glasscock asset that you acquired last year?

Really, what we've seen on the porosity side, it's fairly similar. Permeability is a tough thing to measure, but when you look at the well performance of those offset horizontal wells to our Howard County acreage it obviously looks like the perms are very good in that area based on the well performance. If you remember, in Glasscock County, the overall Wolfcamp section in particular, is thicker. You've actually got more oil in place in Glasscock County. There's not -- hasn't been near as much horizontal activity in the area, although there's some recent Apache well results within couple of miles of our acreage block there in Glasscock County. And based on the public data from those wells, it's very, very encouraging. And so we're still very excited about our Glasscock County acreage. And we'll be drilling our first wells there in the second half of this year.

Okay, that's helpful. And just last question related to Viper. It's my understanding there's not much cash flow associated with the override from this Howard County acquisition embedded in 2015 production guidance that's been revised for Viper. But I'm just kind of curious if you could talk about how you foresee the cash flow profile of that asset growing and maybe how you came up with the valuation for the -- I think it was the $33.7 million.

Mike, one of the things that we were so excited about at the Viper level was that the growth profile associated with the overrides that Diamondback has offered to Viper actually exceeds the growth profile that's embedded in the legacy Viper assets. Now that we've been looking across the country for the last 9 months for acquisitions at the Viper level, it's pretty unique to find this kind of growth profile. And so as we outlined our Viper strategy, we wanted to get the assets that are operated by a competent operator. In this case, it's Diamondback Energy. We wanted to get assets that are actively being developed or on the verge of being developed, which this -- as Russell has highlighted, with a lot of activity, it's going to be occurring here in the near future. And the high oil component, which is like I said, around 75% to 80%. So this acquisition fit in the -- in all of those -- into all of those categories.

[Operator Instructions] Our next question comes from Michael Hall of Heikkinen Energy Advisors.

I guess one question. I just wanted to try and get at was given the accelerated ramp in '15, slightly accelerated, and the outlook for potential additional rig adds in '16. Any color or commentary on what that could do for 2016 production growth? And what that might look like in 2 different scenarios?

Yes. Michael, again, we've not -- in early May, we've not really focused on exactly what 2016 is going to look like. But I think as we march along this year, as we pick these additional rigs up, we'll be able to provide a lot more clarity about what 2016 is going to look like. But one thing I do know is as you add rigs and you increase completion activity, volume growth responds accordingly. So certainly, our expectations are under -- accelerating rigs and accelerating completion activities that our growth profile is going to continue going forward in the future.

Make sense. Figured it was early, but worth a shot. And then I guess, I was also curious on your views on kind of concurrent completions in the Wolfcamp and Spraberry and how important that is, or not important, as you think about full development on the various assets.

Yes. I think when you look at our assets on the Western side on the Northern Midland Basin, you've got some pretty nice distinctive zones with some nice frac barriers in between the Wolfcamp and, say, the Lower Spraberry, for example. As you move east and you get some thickening in the shale depositions, it starts to make more sense to us to do stacked laterals. And so while we've not definitively come out and exactly spelled out what our strategy is going to look like, I think it's more likely than not that we'll be drilling stacked laterals, not only in Glasscock County but also in this Northern -- Northwest Howard County block as well.

Okay, that's helpful. And then on the cost front, what's the average AFE you guys are expecting now in second half for a 7,500-foot lateral?

Yes. We'll probably be at the low end of our guidance. We're -- what did we say? $6.2 million to $6.7 million, we'll probably be at the low end of that. There's a highlight in my prepared remarks. We've got some wells that we're finalizing right now and although costs aren't in right now, the -- look like they'll be in the $6 million range. But they're not -- we don't have all the cost in on yet. But as I said in my prepared remarks, because we're completing a lot of wells that were drilled last year before all the cost concessions were in, we're still going to stay within that guidance for 7,500-foot well of $6.2 million to $6.7 million.

Okay. And then last one on my end is just around completion capacity. You've got the rigs outlined or contracts, it sounds like, are lined for the back half of the year. Any needed additional completion capacity? And have your arranged for that? I imagine there's plenty available.

Yes. That part is a factor. There is plenty available. But our cadence sort of supports 1 dedicated crew for about 2 to 3 rigs. And so we get up to the 8 rig, we'll probably have a 2 fully dedicated crews and 1 probably partial dedicated crew. And then as you would love [ph], that kind of ratio of 2 to 3 dedicated -- 1 dedicated crew to 2 to 3 rigs is a good planning number.

And at this time, I'm not showing any further questions. I'd like to turn the call back to Travis Stice, CEO, for closing comments.

Thanks again for everyone participating in today's call. If you've got any questions, please reach out to us using the contact information provided. Thanks, everyone, and look for to talking to you again in the future.

Ladies and gentlemen, thank you for participating in today's conference. This does conclude today's program, and you may all disconnect. Everyone, have a wonderful day.