Good day, ladies and gentlemen, and welcome to the Diamondback Energy and Viper Energy Partners first quarter 2015 earnings conference call. At this time, all participants are in a listen-only mode. Later, we will conduct a question and answer session, and instructions will follow at that time. If anyone should require operator assistance, please press star then zero on your touchtone telephone. 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 Teresa 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. We raised production guidance as a result of well performance, increase in completion activity, and accretive acquisitions. We plan to add a second completion crew in June to work down the inventory of drilled but uncompleted wells because cooperation with service providers have lowered our well costs 20%-30% since the service cost peak in the third quarter of 2014. Additionally, we plan to add two 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 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 six and seven, 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 two-thirds 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-$6.7 million guided well cost range for 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-$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 frack crew next month to work down our backlog of drilled but uncompleted wells.
We plan to increase our rig count from three to five rigs in the third and fourth quarter of this year and could potentially add another two or three 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-$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 29,000-31,000 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 30.6 thousand 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 a two-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% for 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 acres from private parties for $438 million, including 2,500 barrels a day of production on a three-stream basis from 117 gross vertical wells and three gross horizontal wells. These transactions demonstrate both of our acquisition strategies: to bolt on acquisitions in and around our core areas and adding a new 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 three 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 low acquisition cost of approximately $2 a barrel. We expect roughly 40% of these locations to be drilled as 10,000-foot laterals, with the remaining locations being predominantly 7,500-foot laterals. Longer laterals support lower finding costs, higher capital efficiency, and stronger rates of returns. Additional upside may exist in the Middle Spraberry. There are over a 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 de-risked 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% MRI. We expect to begin developing this acreage in 2016 or sooner, depending on the timing of infrastructure needed to support a two-rig program.
You have heard me consider it as all Tier 1, which is the 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 mark-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. 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 details of our current hedge position in last night's earning release and on slide 22 of the presentation. Turning to costs.
Our LOE was $8.14 per BOE for the quarter, a 17% reduction from fourth quarter of 2014. We continue to seek 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 a result of acquiring 117 gross vertical wells in the announced acquisition. We think this new guidance of $7-$8 per BOE is manageable, given that we decreased LOE 17% quarter-over-quarter due to reductions in well servicing units, route development, water trucking, chemicals, and other components. Our cash G&A costs came in at $1.20 per BOE, while non-cash 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, or $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-$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 costs. As of March 31st, 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 borrowing availability provides us with plenty of liquidity. We estimate our 2015 year-end debt to EBITDA will be less than two times. 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 expectations. 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 31st, 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 4,600-5,000 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 remarks.
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.
Thank you. Ladies and gentlemen, if you have a question at this time, please press star then the one key on your touch tone telephone. If your question has been answered or you wish to remove yourself from the queue, please press the pound key. Our first question comes from Mike Kelly of Global Hunter Securities. Your line is now opened.
Hey, guys. Good morning.
Morning, Mike.
Really great release here on multiple fronts. I think the first thing I'd ask you is on your decision here to go back to work, you mentioned the release that you could see the rig count going from three all the way up to eight rigs at some point in 2016. I was just hoping, Travis, you could detail what the criteria is to get there and how fast you might be able to ramp to eight rigs.
Sure, Mike. It's really a function of a couple of things. We've got to maintain discipline on cost from the service community commodity prices continue to need to improve. In 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. Right now, we've got a rig coming in the third quarter, one in the fourth quarter, 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, 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. When we ran new numbers last night, we saw that even after paying for this deal and ramping to eight rigs over the course of next year, debt to EBITDA doesn't really even go over 2.5 times. Just curious how you guys think about what's an appropriate target for leverage and the need to do equity going forward. Thank you.
Yeah. Our stance on leverage really hasn't changed since before we took the company public. We state that we like to keep a leverage ratio of below two. 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, we also have our ownership in Viper Energy Partners. We've really got multiple ways to fund this acquisition going forward.
Got it. Thanks, guys. I'll hop back in the queue. Thank you.
Thank you. Our next question comes from David Amoth of Iberia Capital Partners. Your line is now open.
Morning, guys.
Morning, David.
Travis, you mentioned infrastructure as something that you need to get on the acquisition before you start to do the work there. Can you talk about what specifically you're looking for? Then, what kind of timeframe 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 a two-rig horizontal program. What that really entails is primarily the accumulation of stimulation fluid. It's stem 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 a significantly higher fluid handling capacity. As soon as we close this deal, we'll go out at Diamondback, not a third party, and we'll begin that infrastructure. One thing that I'm pleased with, and we outlined in the acquisition, is that we also acquired a saltwater disposal system for about $5 million.
We've quite a bit, but can't start work until we close the acquisition, which is middle of June. That being said, though, we've got our plans firmly underway at least on paper, to make a rapid transition to horizontally develop this acreage.
Got it. Thanks. Then, looking at your slide 17, it looks like the Wolfcamp B on the acquisition is actually considerably thicker than it is at Spanish Trail. Do you actually expect the B to be a more attractive target at the acquisition? How should we think about that going forward?
Yeah. Really when we look at these three primary zones here, if you look at slide 16 and you look at the offset results, we put quite a few of them on here on the nearest wells to this acreage block. The Lower Spraberry and the Wolfcamp A are the two best performing zones. The Wolfcamp B is not quite as good as those other two, but if you look at the location of those Wolfcamp B wells, they're east of the acreage block, and that Wolfcamp B does thicken as you go to the west. We think we've got a good chance of the Wolfcamp B being better on this acreage than it is on the wells to the east. Overall, we think we've got three really nice targets here.
Great, thanks. 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? 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. It's again, working very collaboratively with our business partners because if costs go up faster than commodity price goes up, Diamondback, using our same mantra of capital discipline, will tap the brakes again. I'd like to say, yeah, we've locked in these low costs for all time. The reality is that you just can't do that right now. 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 still have that lever going forward as well, too.
Great. Appreciate the commentary and congrats on a great quarter.
Thank you, David.
Thank you. Our next question comes from John Nelson of Goldman Sachs. Your line is now opened.
Good morning, and congratulations on the acquisition and a really strong quarter.
Thank you, John.
Comments from most of your peers are that asset sales that have come to market over the last 6 months have been situated more at the fringes of the field or lower in quality. I was wondering if you could first maybe comment on, certainly this was an attractive acquisition price, but what makes you so certain that these assets are high quality? If you could, what IRRs you would expect on that 600 million-900 million MBOE type curve at $60. Secondarily, are you actually seeing a shift in the M&A pipeline to higher quality assets starting to make an entrance?
Yeah. 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 the most de-risked acquisition in Diamondback's history. I don't make that statement casually. We've got over 60 wells where we had open hole logs, where we were able to do our geochemical and petrophysical work supported by a whole core analysis that really highlighted the oil in place and the significance of these shale horizons. Also, while I think we've only put about a 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 had IP30s and established production that allowed us to go in and put reserve forecasts on those wells. 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 acreage block. I know 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 do so going forward.
That's very helpful.
Hey, John, I'm sorry. You had another question on the rates of returns for those 600,000, 900,000 type wells. They're going to be in that 40%-70% range at today's price and today's service costs. Really, I made the comment that these wells are in the top quartile of Diamondback Energy's portfolio, and it's supported when you look at these rates of returns.
That's very helpful. Thank you. I was hoping just get one clarification on your earlier comment. Would the addition of rigs six to eight then be contingent on a further improvement in commodity price? Are you just saying that we need to sort of stay the course versus?
Yeah, it's more of the latter.
Great. I'll let somebody else hop on. Congratulations again.
Thank you, John.
Thank you. Our next question comes from Dave Kistler of Simmons & Company. Your line is now open.
Morning, guys.
Hey, Dave.
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 as you ramp the rig count up, in the past you've talked about this, as you continue to acquire, do you feel like you have the appropriate staff in place to run an eight rig or even larger rig program? If you could just refresh us in terms of what kind of capacity you think your staff has at this juncture.
Yeah. As an executive team, we've sort of always talked about building the bandwidth that's capable of running 10 horizontal rigs. When I made the comment that we now got acreage footprint that supports a 10-rig program, I believe that we're close to having that bandwidth right now. There may be one or two additional key contributors that we need to add to kind of help support that. Yeah, sort of in that 10-rig cadence is what we've tried to build the organization around.
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 two 10,000-foot laterals drilled in about a month's time. We keep an eye on that on our organization, and again, we've tried to build it around that 10-rig cadence.
I appreciate that color, 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. I'm just curious how you're thinking about that.
We've got on the production side what we call a PIWIP. It's a production well improvement program that's a PIWIP plan that weekly and monthly goes through and analyzes the producing performance of all of these wells, also does a detailed deep dive on any wells that have failed to try to be proactive in failure identification. Really it's that failure identification, pumping practices that eliminate those failures. Most of these vertical wells we've acquired over the last 12 months have a failure rate of somewhere north of 1.5. 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.
Obviously, that has a very positive effect, particularly in the well maintenance category of LOE expenses. We're closing in on 1,000 total wellbores right now, that's not a casual number for our field organization to try to optimize. To further make that a little bit more difficult is that we're all the way from Upton County now into Howard County and to Martin County. We're close to closing in on about nine counties where we operate wells, sometimes that dispersion causes a little bit of inefficiencies, but that's what we do, though. Jeff Lighten, he's our vice president of operations, his whole organization is up to the challenge of making sure we maintain best-in-class operations from our field organization's perspective.
Appreciate that added color. One last one, just relative to the ability to ramp up, 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 contractual over several months to a year? Any kind of color on that would be helpful.
Of the rigs we've got that are coming on, they're all under different contract periods. As we go from rigs six, seven, and eight, we'll be picking those rigs up on a well to well basis. That's one of the slides, I can't remember which one it is, that references the rig cost. You can see that our rig costs have only come down 3%. That's because most of those were under preexisting contracts. As we continue to add rigs, one of the more significant cost savings we'll have is the day rate 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, as long as the commodity price holds, we'll continue to work that.
They're not operating under any form of long-term contract.
Perfect. I appreciate the added color. Great work, guys.
Thank you, Dave.
Thank you. Our next question comes from Gordon Dovat of Wells Fargo. Your line is now open.
Thanks. Good morning, everybody. As you look to ramp your rig activity, it looks as if there's a potential for two 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 operating perspective, a max of two to three rigs. 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. We'll keep two to three rigs there. We'll keep probably two rigs up to the north, bouncing around between Northeast Andrews County, Northwest Howard County, where we've got good million barrel type wells there in the Lower Spraberry. We'll be able to work one or so in the Glasscock County area. Again, that's that new acquisition that we had last year. We'll keep two in Howard County.
We'll have a couple that bounce around, we'll keep, I think, one more rig in Southwest Martin County, that should get you somewhere in that 8-10 rig cadence, depending on commodity price and service costs.
Okay. That's helpful. Just wanted to get your thoughts on hedging. I know Tracy, you mentioned that you're looking to add some for 2016, 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 had an internal mark on the wall of about $65 a barrel WTI, I think this week for the first time, our hedges crossed over to about $65 and $65.50, something like that. I haven't looked at it today, 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, just trying to keep them informed as well too. Dave, the board has guidance to us of somewhere between 40% and 70%, we're not anywhere near that in 2016. 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.
All right. Thank you.
Thank you. Our next question comes from Gayle Nicholson of KLR Group. Your line is now open.
Good morning, everyone. As you increase that rig activity really looking at the 2016, 4 timeframe, should we anticipate that the number of wells on your pads will also increase? How should we think about that?
Gayle, I think the most efficient capital that you can deploy is when you keep a rig on a pad as many times as you can. Our sweet spot looks to be about a three-well pad. That takes into a lot of things, drilling, simultaneous operations with offset completions. 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 especially 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 bounce around a little bit in Northeast Andrews County and Northwest Martin County. Other than that, we should be doing mostly pad work.
Okay, great. Just the standpoint of, I was wondering if you gave any update on the Lower Spraberry well in Dawson County and how that has performed.
Yeah. The Dawson County well, it's been on for quite a while now. 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 is, I'd say above our threshold rate of return. It doesn't quite compete with some of our other Lower Spraberry results that we think is hopefully commodity price continues to improve and over time, we'll develop that acreage block as well.
Great. Thank you.
Thank you. Our next question comes from Jeff Grampp of Northland Capital Markets. Your line is now open.
Morning, guys. Just 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. Looking like maybe 2Q may be a little bit stagnant as you start to, and then maybe as you start working down the backlog, I assume the second half will be stronger. Is the assumption that a lot of that's probably going to hit 4Q or maybe some contribution in 3Q? Just getting your thoughts on production cadence throughout the remainder of the year.
Yeah, Jeff, good question. You're right, we don't give quarterly guidance. I'll tell you, as Diamondback 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 the second quarter, and it's going to be measured by fewer wells completed in the quarter than we did in the first quarter. 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 Q1 2016 impact, as you increase rigs and increase completion activity, we'll go back to that volume building trend.
Okay. That's helpful. On the acquired properties, obviously getting a nice slug of production there. Do you guys have a sense for what the base decline is with those existing wells? Seems like with a mix of newer horizontals and I guess some legacy verticals there.
Yeah. 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 four or five years, so we're down in that 15%-20% decline rate on the PDP.
Okay, perfect. 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 going for the known quantities in your portfolio?
Yeah, 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. 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. In a general sense, it's more tweaks than complete overhauls.
Okay, great. Great results, guys. Thanks.
Thank you. Our next question comes from Jeffrey Connelly of Clarksons Securities. Your line is now open.
Hi, guys. Can you give us an update on the Lower Spraberry wells you drilled on 500-foot spacing? If you think that the 500-foot spacing is applicable across your acreage, and if you're not there yet, what you need to see before you get comfortable with that?
Yeah. If you look at that slide that shows our Lower Spraberry results for Midland County, I believe it's slide number six. That 500-foot spacing is the ST West 7-1LS and 7-2LS. We show the average of those two wells on that pad. You can see so far, it's tracking with the results of the other wells. Now, still early. We've got somewhere around 150 days of production on those two wells, but very encouraging results so far. Right now in the Spanish Trail area, we're going forward with the 500-foot spacing, and we'll be testing that 500-foot spacing in other areas as well. We recently completed a microseismic survey on a three-well pad in Spanish Trail that we actually did at 660-foot spacing. We're just now getting the results back on that.
We'll take a hard look at the results of the microseismic and refine our spacing as we go forward.
Okay, great. Diamondback's talked about being cash flow neutral or positive in the second half of this year. Is that still the case if you choose to add the 2 rigs? Are those 2 rigs included in the $400 million-$450 million CapEx program?
Yeah, Jeff, as I 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 to date. That's a not too subtle message that we're able to stay within our original CapEx guidance, not increase it, but yet increase activity.
Okay, great. Thanks, Travis.
Thanks, Jeff.
Thank you. Our next question comes from Jeb Bachman of Scotia Howard Weil. Your line is now open.
Morning, everyone.
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?
Yeah, absolutely, Jeb. We've got a real fulsome analysis from a cross-section perspective, both east to west and north to south across this acreage block. Extremely good coverage with vertical well control. Again, as I highlighted and we've included in our slide deck, there's enough offset production data as well to further enhance our confidence.
Just briefly on 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 had put you at earlier this year?
Well, as I mentioned to the previous caller, we're not making major overhauls to our completion design. We continue to go 300 or so, 300,000, 350,000 pounds per stage. Our per foot concentration is 1,200-1,500 pounds per foot. We're predominantly using white sand in our Wolfcamp completions and brown sand mostly now in 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. We've done that on a couple of two-well pads now, and we're monitoring results real closely to see if tighter spacing has a corresponding impact to the EUR.
Great. I appreciate it, Travis.
Thank you. Our next question comes from Jason Wangler of Wunderlich. Your line is now open.
Good morning, Travis. Just had one for you. Obviously, coming back and starting with the inventory, 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'll look like on a steady-state basis as we get to the end of the year?
Yeah. We're probably in that maybe 15-plus range right now of wells waiting on completion. What's a reasonable backlog per rig is around two to three 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. Just from a planning perspective, you got to look at two to three wells waiting on completion ahead of each drilling rig.
That's helpful. Thank you. I'll turn it back.
Thanks, Jason.
Thank you. Our next question comes from Richard Tullis of Capital One Securities. Your line is now open. Richard, please check your mute button. We'll move on to the next question. It comes from Welles Fitzpatrick of Johnson Rice. Your line is now open.
Hey, good morning. Congrats on the strong acquisition.
Thank you, Welles.
On the acquired acreage, do you guys own all depths? If so, does Cline rank anywhere on the to-do list?
Yeah. It depends on the particular lease, but on almost all of them, we at least own down through Cline. There is some Cline potential. There has been some reasonably good Cline wells south of our acreage. As you move north, the Cline gets to be more carbonate than shale. We really like the A, B, Lower Spraberry and Middle Spraberry here more than the Cline. At some commodity price, there probably is some prospectivity for Cline.
Okay, perfect. Then just one more. Did you say that the $20 million in infrastructure spend was included in the $438 number?
Well, as we modeled it from a CapEx spend going forward, that's a CapEx number that we think we'll have to have going forward. It's not included in the $438. 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.
Okay, perfect. Thanks and congrats.
Thank you, Welles.
Thank you. Our next question comes from Richard Tullis of Capital One Securities. Your line is now open.
Thanks. Sorry about that. Congratulations to the team, Travis, on a real nice quarter. Two quick questions. This acquisition should bring your total to around 89,000 net in the Permian. 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 the acreage in Central Andrews. I guess you have maybe upward of 10,000 acres there. What's the outlook for that?
Sure, Richard. We 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. We will continue to be active in the M&A. We're not necessarily what you'd categorize as an exploration-oriented company. We're going to continue to be active in the M&A market starting today. I'll let Russell answer the question on Central Andrews County.
Yeah. If you remember, in Central Andrews County, we tested the Clear Fork there with a couple horizontal wells. I think as we've mentioned before, that second Clear Fork well that we drilled in the Lower Clear Fork shale has continued to perform well. The declines are actually much flatter than we originally projected. That Clear Fork really is looking better and better all the time based on the performance of that second well that we drilled. At current commodity prices, it's certainly economic, but not in the top quartile of our inventory. You'll probably see us test the Clear Fork again sometime over the next year to confirm those results, but not at the 2015 program at this time.
Okay, Russell, that's helpful. Thank you. Just lastly, Travis, I'm not sure if you touched on this a little earlier, but 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. You have to keep in mind that as we've built this company over the last three years, our efficiency. We're 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.
All right. Thanks, Travis. Appreciate it.
Thank you. Our next question comes from Neal Dingmann of SunTrust. Your line is now open.
Good morning, guys. Travis, just wondering on that slide you have that shows the downspacing and stack pay potential. I guess my question, are you still pretty optimistic about on the three areas there, on the Middle Spraberry going from six to eight per section, and then looking at the Lower from eight to 10, and then obviously in the Wolfcamp from four to eight, on not just in Spanish Trail, but your thoughts about that similar downspacing if I look at either Southwest or Northwest Martin or Howard or Glasscock?
Yeah, Neal, maybe we're a little conservative in the way that we look at the number of laterals that go across this section. We sort of use that as a risking mechanism. The least we know about a zone, the fewer laterals we'll put in it. I think industry has shown if the shale works and generates economics, somewhere between six and 10 is going to be the right number. Middle Spraberry, while we've got a couple of wells drilled and some testing going on, we just don't have a lot of information there. I think industry has shown not only in the Permian, but also in all the other basins with these shale development that they tend to get tighter, not broader over time as more and more wells get drilled.
Most of our well cadence or well counts in our inventory are biased upwards given success in each of these productive zones.
Got it. Just lastly, maybe for you or Tracy, just on your comment about the positive second half cash flow. I forget what commodity prices are you using? Are you assuming current costs?
Yeah, current cost, but we modeled the company at $50 flat.
Got it. That's what I need. Thanks, Travis.
Thank you. Our next question comes from Michael Rowe of Tudor, Pickering, Holt & Co. Your line is now open.
Good morning. I just had a quick follow-up question on the Howard County acquisition. This 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 compare that to the Glasscock assets that you acquired last year?
Yeah, really what we've seen on the porosity side is 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 hasn't been near as much horizontal activity in the area, although there's some recent Apache well results within a couple of miles of our acreage block there in Glasscock County. Based on the public data from those wells, it's very encouraging. 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. 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. I was just 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 a $33.7 million? Thank you.
Yeah, Michael, 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 nine months for acquisitions at the Viper level, it's pretty unique to find this kind of growth profile. As we outlined our Viper strategy, we wanted to get 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, and is going to be occurring here in the near future.
High oil component, which is, like I said, around 75%-80%. This acquisition fit into all of those categories.
That's helpful. Thanks.
Thank you. As a reminder, ladies and gentlemen, if you do have a question, please press star then one on your touch tone telephone. If your question has been answered or you wish to remove yourself from the queue, please press the pound key. Our next question comes from Michael Hall of Heikkinen Energy Advisors. Your line is now open.
Thanks. Good morning.
Good morning, Michael.
I guess, one question I just wanted to try and get at was, given the accelerated ramp in 2015, slightly accelerated, and then the outlook for potential additional rig adds in 2016, any color or commentary on what that could do for 2016 production growth and what that might look like in the two different scenarios?
Yeah, Michael, again, in early May, we've not really focused on exactly what 2016's going to look like. 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's going to look like. One thing I do know is as you add rigs and you increase completion activity, volume growth responds accordingly. Certainly our expectations are to, under accelerating rigs and accelerating completion activities, that our growth profile is going to continue going forward in the future.
Fair enough. Makes sense. Figured it's early, but worth a shot. I guess I was also curious on your views around kind of concurrent completions in the Wolfcamp and Spraberry, and how important that is, or not important, as you think about full development of the various assets.
I think when you look at our assets on the western side of 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. While we've not definitively come out and exactly spelled out what our strategy's 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 northwest Howard County block as well.
Okay. That makes sense. That's helpful. On the cost front, what's the average AFE you guys are expecting now in the second half for a 7,500-foot lateral?
We'll probably be at the low end of our guidance, where we say $6.2 million to $6.7 million, we'll probably be at the low end of that. As I highlighted in my prepared remarks, we've got some wells that we're finalizing right now, and although costs aren't in right now, they look like they'll be in that $6 million range, but we don't have all the costs in on yet. 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. Yep. Last one on my end is just around completion capacity. You've got the rigs outlined or contracted, it sounds like, or lined up for the back half of the year. Any needed additional completion capacity, and have you arranged for that? I imagine there's plenty available.
Yeah, that part is a fact, there is plenty available. Our cadence sort of supports one dedicated crew per about 2 to 3 rigs. We get up to the eight rig, we'll probably have two fully dedicated crews and one probably partial dedicated crew. As you move up, that kind of ratio of one dedicated crew to 2 to 3 rigs is a good planning number.
Great. Appreciate all the answers. Thanks much. Congrats on a good deal.
Thanks, Michael. Thank you.
Thank you. 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 forward 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.