Diamondback Energy Inc (FANG) 2015 Q1 法說會逐字稿

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, Sandra. 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 executive 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 uncompleted wells because cooperation with service providers have lowered our well costs 20% to 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 the 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 1 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 cost, [AEPs] are trending towards the low end of the $6.2 million to $6.7 million guided well cost range for 7500 foot lateral. Several of our upcoming 7500 foot lateral wells are on track to cost less than $6 million. We have also seen approximately 15% of cost concessions associated with LOE. Specific cost reductions are broken out on slide 10.

Since we are 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 are 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 of service cost 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 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 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 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 8200 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 2500 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 a low acquisition cost of approximately $2 a barrel. We expect roughly 40% of these locations to be drilled in 10,000 foot laterals with the remaining locations being predominantly 7500 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 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, offsetting EURs range from 600,000, to 900,000 BOE 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 have 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 two-rig program.

You have heard me consistently communicate the importance of cash margins to Diamondback. The acreage we are adding to our inventory is 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 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 details of our current hedge position in last night's earnings 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 are 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 to $8 per BOE is manageable given that we decreased LOEs 17% quarter over quarter due to reductions in well servicing units, roustabouts, 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 the 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 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 will 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 distribution was $15 million and production increase 16% quarter over quarter to 4844 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 volume in the range of 4600 to 5000 BOE per day, up 10% from prior guidance. As a reminder, Viper does not incur lease operating expenses or capital expenditures.

With that I will now turn the call back over to Travis for his closing remarks.

Thank you, Tracy. To summarize, this quarter we have 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 am 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). Mike Kelly, Global Hunter Securities.

Good morning. Really great release here on multiple fronts and I think the first thing I would ask you 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 three all of the way up to eight rigs at some point in 2016. And 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 is 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 in a general sense as I outlined in our call, we believe we are generating rates of returns when commodity price was equivalent to $75 for WTI. So right now we've got a rig coming in the third quarter, one in the fourth quarter and certainly as commodity price continues to improve, we will 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 would 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 is an appropriate target for leverage and the need to do equity going forward? Thank you.

You know our stance on leverage really hasn't changed since before we took the Company public. We always -- we state that we like to keep the leverage ratio below 2 and I think that is logical to assume going forward as well.

What is 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 have done historically for acquisitions. We also have the high-yield market that is open to us. We have unused capacity on our revolver and we also have our ownership in Viper Energy Partners. So we've really got multiple ways to fund this acquisition going forward.

Got it. Thanks, guys. I will hop back in the queue. Thank you.

David Amoss, IBERIA Capital Partners.

Good morning, guys. Travis, you mentioned 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 are looking for and then what kind of timeframe you are looking at to get that put in place and is that something that Diamondback is going to do themselves or is that a third-party deal?

Sure. David, we set aside roughly $20 million in the acquisition to put an infrastructure in place that is necessary to support a two-rig horizontal program. And what that really entails is primarily the accumulation of simulation fluid so it stem fluid accumulation ponds, it is pipes and facilities able to accommodate high volumes. This property was developed with vertical wells and while we are 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.

So as soon as we close this deal we will go out at Diamondback, not a third-party, and we will begin that infrastructure. One thing that I am pleased with and we outlined in the acquisition is that we also acquired a saltwater disposal system for about $5 million. So we have already got a saltwater disposal system in place. We will likely need to upgrade it quite a bit but we can't start work until we close the acquisition which is the 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. And 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 B to be a more attractive target at the acquisition? How should we think about that going forward?

Yes, 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, 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 are east of the acreage block and that Wolfcamp B does thicken as you go to the West. So we think we have 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 have seen so far, how do you think about potentially locking those in or is there a point where you are 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 are comfortable with as you accelerate?

We will always try to hold the line on cost. 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 is again working very collaboratively with business partners because if costs go up faster than commodity price goes up, with Diamondback using our same mantra of capital discipline, we will tap the brakes again. So I would like to say yes, we have locked in these low costs for all times but the reality is that we just can't do that right now.

But again the natural governor has increased activity versus laying rigs down and that is 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.

John Nelson, Goldman Sachs.

Good morning and congratulations on the acquisition and a really strong quarter. Comments from most of your peers are that asset sales that have come to market over the last six months have been situated more at the fringes of the field or 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 -- what makes you so certain that these assets are high quality and if you could, what IRRs you would expect on that 600 million to 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?

John, several good questions there. I will try to take them in the order that you asked them. As I outlined in my prepared remarks, this acquisition in Northwest Howard County marks the most derisk acquisition in Diamondback's history and I don't make that statement casually. We have got over 60 wells where we had open hole logs, where we were able to do geochemical and petrophysical work supported by whole core analysis that really highlighted the oil in place and the significance of these shale horizons.

And also while I think we have 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 IP 30s and established production that allowed us to go in and put reserve forecast on those wells. And so we have 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 is 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 is very helpful. And then 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 are going to be in that 40% to 70% range at today's price and today's service cost. So really I made the comment that these wells are in the top quartile of Diamondback Energy's portfolio and it is supported when you look at these rates of returns.

That is very helpful, thank you. I was hoping to get just one clarification on your earlier comment. Would the addition of rigs six to eight then be contingent on a further improvement in commodity price or are you just saying that we need to sort of stay the course either where the [strip] is or maintain current service cost in commodity prices?

It is more of the latter.

Great. I will let somebody else on. Congratulations again.

David Kistler, Simmons & Company.

Good morning, guys. 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 am curious about as you ramp the rig count up and in the past you have 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?

Yes, you know, as an executive team we have sort of always talked about building a bandwidth that is capable of running 10 horizontal rigs and so when I made the comment that we've now got acreage footprint that support a 10 rig program I believe that we are 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.

But yes, sort of in that 10 rig cadence is what we have tried to build the organization around and I will 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 we can get these wells drilled which is sort of why I highlighted the fact that we've got two 10,000 foot laterals drilled in about a month's time. So we keep an eye on that on our organization and again we have tried 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 are 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 are thinking about that?

Yes, we have got on the production side what we call a PWIP, it is a production well improvement program that it is a PWIP plan that weekly and monthly goes through and analyzes the producing performance of all of those 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 is that failure identification that helps us change pumping practices that eliminate those failures.

Most of these vertical wells we have 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 have driven that well failure rate down from 1.5 down to I believe it is about 0.7 right now. So obviously that has a very positive effect particularly in the well maintenance category of LOE extension.

So we are closing in on 1000 total wellbores right now and that is not a casual number for our field organization to try to optimize. And to further make that a little bit more difficult is that we are all the way from Upton County now into Howard County and into Martin County so we are close to closing in on about nine counties where we operate wells and so sometimes that dispersion causes a little bit of inefficiencies but that is what we do.

I've got Jeff White, and he is our Vice President of Operations and 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 but also the ability to ramp down as you highlighted. The rigs that you would be picking up, the completion crew that you are 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 are all under different contract periods. As we go from rigs six, seven and eight, we will be picking those rigs up on a well to well basis and that is one of the slides -- I can't remember which one it is -- it references the rig cost, you can see that our fig costs have f only come down 3%. That is because most of those were under pre-existing contracts. As we continue to add rigs, one of the more significant cost savings we will have is the day rate on those drilling rigs.

The completion crew we picked it up, we have committed to them that we have got one dozen plus wells that we need to work off of in our inventory and as long as the commodity price holds, we will continue to work that but they are not operating under any formal long-term contract.

Perfect. I appreciate the added color. Great work, guys.

Gordon Douthat, Wells Fargo.

Thanks, good morning, everybody. As you look to ramp your rig activity, it looks as if there is the potential for two to go into Howard County. Just wondering beyond that, how you look to spread your rigs across your acreage?

Gordon, we will always keep as many rigs in Spanish Trail as we can which is somewhere just from an operated perspective a max of two to three rigs and that includes that acquisition that we bought in the fourth quarter of last year, the grid iron area and some of the acreage that is slightly outside the Spanish Trail.

So we will keep two to three rigs there. We will keep probably two rigs up to the North bouncing around between Northeast Andrews County and Northwest Howard County where we've got good 1 million barrel type wells there in the Lower Spraberry. We will keep -- drill to work one or so in the Glasscock County area. Again, that is that new acquisition that we had last year and then we will keep two in Howard County.

So we will have a couple that bounce around and we will keep I think one more rig in Southwest Martin County and that should get you somewhere in that eight to 10 rig cadence depending on commodity price and service costs.

Okay, that is helpful. And then just wanted to get your thoughts on hedging. And I know Tracy, you mentioned you are looking to add some for 2016 and just wanted to get your thoughts on what you are 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 wall of about $65 a barrel WTI and I think this week for the first time our hedge has crossed over or the forward strip crossed over to about $65 and $65.50, something like that. I haven't looked at it today but we are pretty close to the point at which I think we want to start building our hedge book. It is something I work with the Board with a couple of times a week and just trying to keep them informed as well too.

The Board has guidance to us at somewhere between 40% and 70% and we are not anywhere near that in in 2016 so I think we've got a nice kind of a nice for the run in commodity price. We are watching it real closely and potentially it could start adding hedges in the not-too-distant future.

All right, thank you.

Gail Nicholson, KLR Group.

Good morning, everyone. As you increase that rig activity really kind of looking at 2016 timeframe, should we anticipate that the number of wells on your pads will also increase? How should we think about that?

Yes, Gail, 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 and sort of our sweet spot looks to be about three -- a 3-well pad. That takes into a lot of things, drilling simultaneous operations with offset completions and so as we continue to add and pick up rigs more and more of our traditional rigs will be on multi-well pads. And 2016 although we have 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 kind of bounce around a little bit in Northeast Andrews County and Northwest Martin County but other than that, we should be drilling mostly pad work.

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

The Dawson County well has 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 would say above our threshold rate of return. It doesn't quite compete with some of our other Lower Spraberry results but we think as hopefully commodity price continues to improve and over time we will develop that acreage block as well.

Great, thank you.

Jeff Grampp, Northland Capital Markets.

Good morning, guys. 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 might be a little bit stagnant as you maybe start working down the backlog. I assume second half will be stronger and is the assumption that a lot of that is 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.

Good question and you are right, we don't give quarterly guidance but I will tell you as Diamondback kind of stood up earlier this year and said that capital discipline 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 is 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 is going to look is probably a good way to think about it. Whether it is exit or 4Q impact or early 1Q 2016 impact, as you increase rigs and increase completion activity we will go back to that volume building trend.

Okay, that is 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 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 lot of working interest so that is very little impact. Most of those vertical wells have been on production for four, five years so we are down in kind of that 15% to 20% decline rate on the PDP.

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

Jeff, that is a good question. You know, I don't think we are ever satisfied that we are extracting all that we can out of these unconventional locks. 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 of the ongoing completion enhancements that are taking place out here in the Permian and in 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 a general sense it is more tweaks than complete overhauls.

Okay, great. Great results. Thanks.

Jeffrey Connolly, 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 are not there yet, kind of what you need to see before you get comfortable with that?

Yes, you know, if you look at that slide that shows our Lower Spraberry results for Midland County, I believe it is slide number six, that 500 foot spacing is -- the ST West and 71 LS and 72 LS show the average of those two wells on that pad. And you can see so far it is tracking with the results of the other wells.

Still early, we have got somewhere around 150 days of production on those two wells but very encouraging results so far. So right now the Spanish Trail area we are going forward with 500 foot spacing and we will be testing that 500 foot spacing in other areas as well. We recently completed a micro seismic survey on a three-well pad in Spanish Trail that we actually did at 660 foot spacing. We are just now getting the results back on that so we will take a hard look at the results of the micro seismic and refine our spacing as we go forward.

Okay, great. And then Diamondback has 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 two rigs and then are those two rigs included in the $400 million to $450 million CapEx program?

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 have seen to date. So that is a not too subtle message that we are able to stay within our original CapEx guidance, not increase it. But yet increase activity.

Okay, great. Thanks, Travis.

Jeb Bachmann, Howard Weil.

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 on slide 17 with the different targets?

Yes, absolutely, Jeb. We have 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 included in our slide deck, there is 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 put you at earlier this year?

As I mentioned to a previous caller we are 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 1200 to 1500 pounds per foot. And we are 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 and we have done that on a couple of two-well pads now and we are monitoring results real closely to see if tighter spacing has a corresponding impact to the EUR.

Great. I appreciate it, Travis.

Jason Wangler, Wunderlich.

Good morning, Travis. Just had one for you. Obviously coming back and starting with the inventory and in 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 a steady-state basis as we get to the end of the year?

Yes, we are probably about -- we're probably in that maybe 15+ range right now of wells waiting on completion. What is kind of 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 the inevitable problems that you have during the completion, being able to move the crew to the next well that is ready. And so just from a planning perspective, you ought to look at two to three wells waiting on completion ahead of each drilling rig.

That is helpful. Thank you. I will turn it back.

Richard Tullis, Capital One Securities. Welles Fitzpatrick, Johnson Rice.

Good morning and congrats on the strong acquisition. On the acquired acreage, do you guys own all depth and if so does the Cline rank anywhere on the to do list?

Yes, it depends on the particular lease but in almost all of them, we at least own down through the Cline. There is some I would say some Cline potential, there has been some -- there is a reasonably good Cline well 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 at some commodity price there probably is some prospectivity for the Cline.

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

As we modeled it from a CapEx spend going forward, we included -- that is a CapEx number that we think we will have to have going forward so it is not included in the 438. It is 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.

Richard Tullis, Capital One Securities.

Thanks. Sorry about that. Congratulations to the team, Travis, on a real nice quarter. Two quick questions. So this acquisition should bring your total to around 89,000 net in the Permian. It looks like you let a couple of thousand acres go in February in Crockett County. What is the outlook for any additional exploration of acreage this year and particularly interested in acreage in Central Andrews. I guess you have maybe upwards of 10,000 acres there. What is the outlook for that?

True, Richard, we kind of joke around here that we are hunters, not farmers and so we are never really satisfied that the inventory that we have got is the right number. We are always looking to expand our footprint by doing accretive acquisitions. We will continue to be active in M&A. We are not necessarily what you would categorize as an exploration oriented company but we are going to continue to be active in the M&A market starting today.

So I will let Russell answer kind of the question on Central Andrews County.

If you remember in Central Andrews County, we tested the clear Fork there with a couple of horizontal wells and I think as we 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. And so 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 is certainly economic but not in the top quartile of our inventory. So you will probably see us test the Clear Fork again sometime over the next year to kind of confirm those results but not a big part of our remaining 2015 program at this time.

Okay, Russell. That is helpful. Thank you. And then just lastly, Travis, I'm not sure if you touched on this a little earlier but of the well cost reductions you have seen year to date, how do you split that between internal efficiencies versus vendor reductions?

That is 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 have built this company over the last three years, our efficiency we continue to push the envelope on efficiency so we are never satisfied that we have got all of the pennies picked up off of the ground from an efficiency perspective. But probably 80/20, 90/10 with the larger number being associated with service cost concessions.

Thanks, Travis. Appreciate it.

Neal Dingmann, SunTrust.

Good money, guys. Travis, just one on that slide you had that shows the down spacing 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 of eight to 10 and then obviously in the Wolfcamp from four to eight on not just in Spanish Trail but your thoughts about sort of that similar down spacing if I look at either Southwest or Northwest Martin or Howard or Glasscock?

Neal, maybe we are a little conservative in the way that we look at the number of laterals that go across a section, we sort of use that as a risking mechanism. But the least we know about a zone the fewer laterals we will 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.

So 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 and so I think industry has shown not only in the Permian but also in the other basins with these shale developments that they tend to get tighter, not broader over time 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. And 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?

Yes, current cost but we model the Company at $50 flat.

Got it. That is what I need. Thanks, Travis.

Michael Rowe, Tudor, Pickering, Holt & Co.

Good morning. 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 are seeing there and maybe kind of compare that to the Glasscock assets that you acquired last year?

Yes, really what we have 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 permeability is 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 have actually got more will in place and Glasscock County. There is not -- hasn't been is near as much horizontal activity in the area although there is some recent Apache well results within a couple of miles of our acreage block there in Glasscock County and based on the public data from those wells, it is very, very encouraging. And so we are still very excited about our Glasscock County acreage and we will be drilling our first wells there in the second half of this year.

Okay, that is helpful. Just last question related to Viper, it is my understanding there is not much cash flow associated with the override from this Howard County acquisition embedded in the 2015 production guidance. That has been revised for Viper but 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 $33.7 million? Thank you.

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 is embedded in the legacy Viper assets and now that we have been looking across the country for the last nine months for acquisitions at the Viper level, it is pretty unique to find this kind of growth profile.

And so as we outlined our Viper strategy, we wanted to get assets that are operated by a confident operator, in this case it is Diamondback Energy. We wanted to get assets that are actively being developed are on the verge of being developed which as Russell has highlighted with a lot of activity is going to be occurring here in the near future and a high oil component which as you know like I said around 75% to 80%. So this acquisition fit in all of those categories.

That is helpful, thanks.

(Operator Instructions). Michael Hall, Heikkinen Energy Advisors.

Thanks, good morning. I guess one question I just wanted to try and get at was given the accelerated ramp in 2015, slightly accelerated and the outlook for potential additional rigs 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?

Yes, Michael, again, in early May, we have 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 will be able to provide a lot more clarity about what 2016 is going to look like.

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.

Fair enough. Makes sense. Figured it is early but worth a shot. And then 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?

Yes, 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 berries 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 have not definitively come out and exactly spelled out what our strategy is going to look like, I think it is more likely than not that we will be drilling stacked laterals not only in Glasscock County but also in this Northwest Howard County block as well.

Okay, that makes sense. That is helpful. And then on the cost front, what is the average AFE you guys are expecting now in the second half for a 7500-foot lateral?

We will probably be at the low-end of our guidance where we've said 6.2 to 6.7. We will probably be at the low end of that. As I highlighted in our prepared remarks, we've got some wells that we are finalizing right now and all the costs aren't in right now. It looked like they will be in the $6 million range but we don't have all of the costs in on them yet. But as I said in my prepared remarks because we are completing a lot of wells that were drilled last year before all the costs concessions were in, we are still going to stay within that guidance for 7500 foot wells with $6.2 million to $6.7 million.

Okay, and then last one on my end is just around completion capacity. You have got the rigs rates 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 is plenty available?

That part of the factor, there is money available but our cadence supports one dedicated crew for about two to three rigs and so when we get up to the eight rig, we will probably have two fully dedicated crews and one probably partially dedicated crew and then as you move up that kind of ratio of two to three dedicated -- one dedicated crew to two to three rigs is a good planning number.

Great. Appreciate all the answers. Thanks a lot. Congrats on the good deal.

Thank you and at this time I'm not showing any further questions. I would 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.