Good day, ladies and gentlemen, and welcome to the Diamondback Energy and Viper Energy Partners Second Quarter 2016 Earnings Conference Call. At this time, all participants are in a listen-only mode. Later we will conduct a question-and-answer session and operation instructions will follow at that time. As a reminder, this conference is being recorded. I would now like to introduce your host for today's conference, Adam Lawlis, Investor Relations. Sir, you may begin.

Thank you, Kevin. Good morning, and welcome to Diamondback Energy and Viper Energy Partners joint second quarter 2016 conference call. During our call today we'll reference an updated investor presentation which can be found on Diamondback's web site. We've also posted an updated Viper presentation, which can be found on Viper's website. Representing Diamondback today are Travis Stice, CEO; Mike Hollis, COO; and Tracy Dick, CFO. 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 of 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. In addition, we will make reference to certain non-GAAP measures. The reconciliations with the appropriate GAAP measures can be found in our earnings release issued yesterday afternoon. I'll now turn the call of the Travis Stice.

Thank you, Adam. Welcome, everyone, and thank you for listening to Diamondback and Viper Energy Partners second quarter 2016 conference call. While our industry faced a challenging start to 2016, during the second quarter commodity prices improved and Diamondback began to reaccelerate the pace of activity by adding a second frac crew in May and a fourth drilling rig last month. We expect the majority of our current inventory of 20 drilled but uncompleted wells to be completed by the end of this year, putting us in a position of strength as we enter into 2017. As a reminder, we recently increased our production guidance range to 38,000 to 40,000 BOEs a day from 34,000 to 38,000 barrels of oil equivalent a day. Additionally, we continue to evaluate adding a fifth drilling rig before the end of this year should commodity prices strengthen. This rig would likely focus within the footprint of our pending Southern Delaware Basin transaction, which we expect to close in September. Last month, we announced our strategic entry into the Delaware Basin through the pending accretive acquisition of approximately 19,180 net acres for $560 million. This acreage is primarily located along the Pecos River in Reeves and Ward Counties, with an estimated 1,000 barrels a day of production and 2.2 million barrels of estimated net proved developed reserves. We have identified 290 net locations with an average lateral length of approximately 9,500 feet across four zones with potential horizontal upside from additional zones and further down spacing. This acquisition will provide Diamondback with a strategic foothold in the core oil window of the Southern Delaware Basin at a lower entry price and greater potential for bolt-on acquisitions than what we find in the Midland Basin. As shown on slide eight, the acreage contains greater thickness and…

Thank you, Travis. Diamondback continues to post encouraging results and achieve new company execution records. Slide 13 shows early performance in Howard County, where we recently completed our first operated pad consisting of three wells targeting the Lower Spraberry, Wolfcamp A and Wolfcamp B intervals. The Wolfcamp A well achieved an average peak 30-day IP rate of 1,374 BOE per day, 89% of which was oil, while the Wolfcamp B well achieved an average 30-day IP rate of 1,225 BOE per day with an 83% oil cut. This confirms two distinct economic reproductive zones within the Wolfcamp on our acreage position. The Lower Spraberry well continues to clean up and has not yet reached peak production. Diamondback plans to complete another three-well pad by the end of 2016 targeting the same three zones and we are conducting a micro-seismic and tracer survey to continue to enhance completion optimization. Slide 14 shows extended performance from our Glasscock County wells, which continue to track a 1 billion barrel pipe run (6:16) on average. We are currently flowing back two more wells and expect to have results in the coming months. Slide 16 shows that Diamondback continues to drill wells at peer-leading levels. During the second quarter of 2016, we drilled two 10,000-plus foot lateral wells in less than nine days each from spud to TD, which is our fastest time ever for a 10,000-foot lateral. We also drilled a 10,800-foot lateral well in Spanish Trail in 10.5 days from spud to TD, a new company record in Midland County. Our well costs have come down roughly 43% since the peak in 2014 and approximately 2% quarter-over-quarter. Leading edge drill, complete and equip costs are trending below $6 million for a 10,000-foot lateral well and below $5 million for a 7,500-foot lateral well. Diamondback continues to maintain a rate of return focused completion optimization program. We are testing high-density near wellbore fracs, diversion agents, nanosurfactants and dissolvable plugs. These tests are ongoing as we continue to weigh the benefits of each technique versus the additional cost. Slide 17 shows reductions to our operating expenses since the peak in 2014. Looking back a year ago, we have reduced our LOE by 26% to $5.57 per BOE in the second quarter of 2016 due to improved pumping practices and service cost concessions. As a result, we've recently reduced our LOE guidance to a range of $5.50 to $6.25 per BOE, down from $5.50 to $6.50 per BOE previously. Our ability to keep driving down costs reflects the efforts of our team to continue to implement efficient and sustainable improvements. With these comments now complete, I'll turn the call over to Tracy.

Thank you, Mike. Diamondback's second quarter 2016 net income adjusted for non-cash derivative losses and impairment was $19 million or $0.26 per diluted share. Our consolidated adjusted EBITDA for the quarter was $78 million. Our second quarter 2016 average realized price per BOE including hedges was approximately $33. During the quarter, our cash G&A costs were $1.04 per BOE while non-cash G&A costs were $1.80. During the quarter, our capital spent for drilling, completing and equipping was $55 million. Our infrastructure costs were $6 million and we payed $4 million on our non-operated properties. We spent an additional $10 million on acquisitions during the second quarter of 2016. At the end of June 2016, we were undrawn on our secured revolving credit facility. With over $219 million in cash and $500 million in undrawn revolver capacity, we have ample liquidity to fund our budgeted 2016 drilling program. Our net debt to trailing 12-month adjusted EBITDA is 0.8 times, as shown on slide 18. Our practice of limiting our commitment to a portion of our borrowing base again reflects our track record of financial discipline. Moving to slide 19, we provide our guidance for 2016. In July, we updated our guidance to reflect continued strong well performance and increased drilling and completion activity. As part of that update, we now expect to complete 60 to 75 gross wells and have increased our full-year 2016 production guidance to a range of 38,000 to 40,000 BOE per day, up 11% from February 2016 guidance. Also, we increased CapEx guidance to $350 million to $425 million as a result of increased activity in 2016. This will primarily be reflected in 2017 volumes. Additionally, we lowered our 2016 LOE guidance range to $5.50 to $6.25 per BOE. Subsequently, we have lowered 2016 DD&A guidance range to $11 to $13 per BOE, down from the prior range of $13 to $15 per BOE. I'll now turn to Viper Energy Partners, which announced on July 25 a cash distribution of $0.189 per unit for the second quarter. This is up 27% from prior quarter. As a reminder, Viper has no required quarterly distributions or complex ownership hierarchy. The majority of cash flow is returned to unitholders through quarterly distributions, providing upside when oil prices rebound. As Spanish Trail remains one of the most economic areas in the Permian Basin, we expect the current DUC backlog will be significantly reduced by the end of 2016. As in its July 25 release, there are 35 DUCs on Viper's acreage. This includes approximately 10 wells that are normal inventory. At the end of the second quarter 2016, Viper had $51.5 million drawn on its revolver. This increased to $132.5 million on July 25 to finance recent acquisitions. Following the close of Viper's recent common unit offering, we expect outstanding borrowings will be reduced by $78 million. I'll now turn the call back over to Travis for his closing remarks.

Thank you, Tracy. Diamondback was able to deliver another strong quarter because of our commitment to execution and low-cost operations. Our financial flexibility allows us to respond quickly when prices improve, and we remain well-positioned to bring value forward across our asset base. We are pleased with early results in Howard and Glasscock Counties, increased acquisition activity at the Viper level and are excited to begin development in the Southern Delaware Basin. Before I open the call for questions, I want to pause and acknowledge our employees for the extraordinary effort they continue to show, especially with all of our activity in the month of July. I'm extremely grateful that I get to work with such dedicated and focused colleagues. Operator, please open the line for questions.

Our first question comes from John Nelson with Goldman Sachs.

Good morning and congratulations on the Southern Delaware Basin entrance.

Thank you, John.

I have two questions, a modeling one and then a higher level one. The modeling one first, regarding working interest. I think the Delaware Basin acquisition press release said we should expect at least one rig on the assets in 2017. And as I look at the working interest, it's a bit lower than I think what you typically have over in the Midland Basin side at roughly 50%. I guess using the $80 million to $100 million per year per rig line rule of thumb, just wanted to check, should we be thinking about baseline capital in 2017 as just that $40 million to $50 million because of the lower working interest? Or should we think about something else?

Yeah, John, I think your math is correct. We're going to start on the higher working interest wells to begin with. So as we move a rig in there later this year and certainly the early drilling in 2017 will be focused on much higher net interest wells. And so I would stay with what your earlier number was, around $80 million to $100 million per rig.

Okay. That's helpful. And then second question, more higher level. I think the Diamondback team is generally regarded by investors as having been successful in executing bolt-on acquisitions in a manner that's shareholder friendly. So I guess I'm just trying to think about as you do step into the Delaware Basin and you paid what at time what was the highest price per acre I think that had been paid by an operator, could you just maybe speak to the underlying quality of these assets or what you think is undervalued? And should we as investors really be expecting Delaware's acreage prices to be moving higher from here?

Well, I think, John, about a week after Diamondback made the announcement there was another large transaction made that was about 30% or 40% higher on the per acre costs than what Diamondback paid for its acreage. So I think the bigger story in the Delaware is the rate of change. The operators over there have quickly optimized the lateral landing point. They've enhanced the completion techniques to make them more competitive. And I think, like I said my prepared remarks, I think the opportunity for Diamondback to continue to do what we've always done, which is do accretive bolt-on acquisitions, is there. And while we don't talk specifically about what our acquisition activity is, I think it's reasonable to assume that, just like in the Midland Basin, Diamondbacks fingerprints will be all over the trades in the Delaware Basin as well.

Great. I'll let somebody else hop on. Thanks.

Our next question comes from Michael Glick with JPMorgan.

Good morning. Just thought on Howard County...

Morning, Michael.

On Howard County, obviously impressive results out of the gate and understanding it's early days there. How do you think that area stacks up versus your other areas? And maybe higher level, how are thinking about allocating rigs and capital between your core areas in the Midland Basin and Delaware Basin?

Well, Michael, your first comment was the correct one. We try not to make too many far-reaching decisions based on a 30-day IP rate, but certainly we're very, very pleased with how these wells have started off. The Wolfcamp A, particularly if it continues to hold in there, it's going to be competitive with some of the Lower Spraberry wells we have in Midland County. And as we look forward to increasing activity levels, we've now got a very firmly established core development areas, not only in Howard County, where that will hold one rig, or in Glasscock County, also hold one rig. So if you look at what we've intimated in 2017 and maybe by the end of this year to be at five rigs, you'd have four in the Midland Basin and one in the Delaware. And the four in the Midland Basin would be two in and around the Spanish Trail area and one in Howard and one in Glasscock. And then the bigger picture as we continue to accelerate activity with improving commodity prices, we've got these core areas now that can each handle a couple of rigs and we'll look forward to really bringing that value forward when commodity prices continue to improve.

Got it. And then switching over to the Delaware, could you maybe give us some color on how you're thinking about delineating that asset initially and how you're thinking about completion design on that side of the Basin versus the Midland Basin?

Well, we believe that the completion designs that we're seeing in the Midland Basin and some of the operators are doing in the Delaware Basin now are what we'd immediately started doing in the Delaware Basin, somewhere around 1,500 pounds a foot to 2,000 pounds per foot. We like the Third Bone Spring, we like the Wolfcamp A, and certainly those would be our initial target zones. Both of those based on offset well performance indicate close to 1 million-barrel type curves for both those two zones. So, again, like we always do, we put the drill bit in the zones that give our shareholders the greatest returns. And that's what we believed when we started development in the Delaware.

All right. Thank you very much.

Our next question comes from Drew Venker with Morgan Stanley.

Good morning, everyone. Travis, you just mentioned that you like in the Delaware Basin the Wolfcamp A and the Third Bone Spring. Can you talk about how much will be delineation of those two zones across your position and testing other zones versus just developing the assets?

Well, Drew, I think go back to my earlier comment that Diamondback's known for always putting the drill bit in the highest rate-of-return zone, and that certainly where we'll start. And I think with a drilling rig there all of next year, we'll get 12 wells drilled and I think the majority of those wells will be in the Third Bone and the Wolfcamp A. And as also has been our style, there's a lot of activity in the Delaware and we intend to be fast followers. As other operators prove up additional zones, we'll monitor the rate of return that we can give our shareholders by putting the drill bit in those additional zones and we'll respond accordingly.

In terms the Bone Spring, a lot of your acreage is right along the river. Does that generally lead to the sand being more present on your acreage than being more discreet deposits?

We expect where we are, just south of the river there, that we've got similar reservoir characteristics in the Third Bone Springs as we do on that acreage just north of the river where we've seen some really good results.

So present, fairly widespread, somewhat similar to the Wolfcamp?

Yeah, I think in general, Drew, that's how we're thinking about it.

Okay. Thank you.

The next question comes from Neal Dingmann with SunTrust.

Good morning, guys. Hey, Travis, just had a question on looking at your Delaware as far as, how do you tackle that? You mentioned – I know you've got a lot of perspective zones there. So going in there, I think you mention about working interest and all. But from a zone perspective, will you kind of just go in there like you have in the Midland and tackle a couple, two, three zones immediately on pads? Or how do you expect to do that?

Yeah, we think the most efficient way to do it is pad drilling. And how important efficiency is to Diamondback. So when we go in there, we'll likely look at stacked-pay development. But some of those decisions our asset teams are digging into right now as we put our development plan together and some of those things are being worked right now.

Okay. And then just same thing in the Midland. I mean, as far as going forward now I guess more on Spanish Trail, is there still a lot of virgin area you have there, meaning could you come in there – are you coming back to existing wells that you have? Or are you going in there and just blanket coming in with these multi-well pads like you were originally?

Yeah, we're doing multi-well pads in Spanish Trail.

Okay. And just following somebody else, I know it is early, but just your initial thoughts now after Howard versus something as obviously highly economic as Spanish Trail, how do you think those compare?

Well, I think the Wolfcamp A and, again, we have to tap the brakes a little bit on a 30-day IP rate. But the Wolfcamp A, if it holds in there like we think it will, appears to be competitive with the Lower Spraberry in Midland County.

Very good. Thanks, Travis.

And, Neal, just on that point, we think the Wolfcamp A down in Glasscock County looks also very robust.

And that's assuming current cost that you're on for both?

Correct.

Got it. Got it. Thank you.

Our next question comes from Gordon Douthat with Wells Fargo.

Good morning, everybody. Question on M&A. To what extent does your entry into the Delaware perhaps signal that acreage opportunities on the Midland side of the Basin are drying up? And if indeed that is the case, what's your propensity to look at corporate type of transactions?

Gordon, again, we don't spend a lot of time talking about the M&A strategies publicly. We keep all those internal. But I have been on record as saying even since before the IPO, we've always looked at ways to grow the company accretively to our shareholders, and that includes corporate transactions. It also includes acreage transactions and small bolt-on deals. All of those tools to grow Diamondback accretively for our shareholders are things that we would continue to investigate. When you look at the most recent trade in the Northern Midland Basin, I think it was somewhere around $60,000 a net acre. And to the extent that sellers are emboldened by that acreage price, it's going to continue to be difficult to try to close that gap between bid and ask. So just like I said earlier, we continue to look at all deals. And Diamondback's fingerprints are on every trade that's out here in the Permian.

Okay. And then a question on the completion designs, specifically as it relates to slide 14 and Glasscock. From the chart there, it looks as if there were different proppant loadings on, let's see, the Saxon and the Riley pads. And it looks like the results are a bit varied. Any conclusions to be drawn, at least recognizing that it's a limited data set there? But given the early data you've seen, any there any conclusions to be drawn from the proppant loading side as it relates to well results?

Gordon, on the Riley, so the Saxon wells were our first wells in the area in Glasscock. And as typical, we go in and try to complete them with what we consider our base completion technique. And we did that on the Saxons, all three zones. We came and did the Riley later, and we did a high-density frac on it. It's not quite our latest version of high-density near-wellbore, where we've changed some of the sand concentration differences as well as some of the pumping rates. But this one was basically our same job done more times within the well. We're looking at it from an economic standpoint, rate of return standpoint. We're getting enough data to where we can conclude that it is better or appears to be better as a two-point test. So again, we don't have a lot of data from different tests, but both wells do appear to be on a normalized footage basis doing better. We're still looking at what that rate of return is. We are testing other techniques in the area as well, so we'll have some more fulsome data that we can give you in the future.

Okay. And then one last one from me. Just looking at the oil and gas mix reported in the second quarter from you guys and then also from others in the Permian that have reported thus far, trending a bit more gassy. And I'm wondering is that a function of slowdown in activity in wells, the gas/oil ratio rising over time as they get a little longer in life? I guess can you discuss those trends and how you expect that to go going forward?

Yeah, Gordon, it's hard to look – we don't give quarterly guidance, much less quarterly guidance on a gas cut. But in general all we're seeing is the effect of timing on our oil cut in this quarter. We only completed a few wells in the first quarter. And in the fourth quarter of last year, we completed a lot of wells. In the first quarter of this year, we had like a 76% oil cut. So I think in general, Gordon, just plan on about 74%, 75% oil as the best way to model Diamondback.

That's it for me. Thanks, everybody.

The next question comes from Michael Hall with Heikkinen Energy Advisors.

Thanks. Good morning. A couple questions on my end and I guess just curious. You guys are really pushing on the long laterals where you can. How do you think about recoveries per foot on long laterals relative to somewhat shorter laterals and then how that compares to cost per foot? And have you approached a tip-over point? And what do you think the most efficient lateral length is at this point?

Well, we do believe, Michael, that there's a pretty direct linear relationship between EURs and lateral length. We believe longer is better. Right now we're currently drilling, what, a 13,500-foot well right now. So as long as – the longer we can drill these wells, the better economics we're going to be able to generate for our shareholders. I think somewhere in that 10,000 to 12,000-foot completed interval is probably going to be the sweet spot for now. But who knows? Technology continues to work in our favor to drill these wells longer and longer.

Okay. Helpful. And then on the Southern Delaware Basin asset, I'm just curious. As you ran out the acquisition economics on that originally, what rig ramp was contemplated and on what commodity price was that predicated on?

Well, I won't discuss the commodity price we used in our acquisition model, but I will give you our rig ramp.

Okay.

We talked about one rig in 2017 and we ramp one rig per year until we get to four rigs and we develop the rest of the asset at a four-rig cadence.

Okay. And I guess how would you think about maybe upside and downside risks around that rig ramp?

Well, it's all going to be a function of the performance of the rock and the commodity price we're receiving for that converting rock into cash flow equation we talk about. So as returns to our investors would go up, we would look to accelerate and bring forward value. But I think four rigs looks like the best cycle rate for drilling and completion operations on that acreage footprint.

Okay. Great. Helpful. Thank you. Appreciate the color.

Our next question comes from Jason Wangler with Wunderlich.

Morning, Travis. You guys have always done a nice job of walking through how fast the drilling times are going and how quick they're getting. Can you talk about on the frac side how quickly and maybe how that's evolved over the last couple years, about how fast you're getting these fracs done, whether it's on the individual wells or on the pads, just to kind of get an assessment of that DUC count as we look forward for the rest of the year?

Jason, this is Mike. As we continue to change the completion designs, it's more difficult to talk about the number of stages we do in a day because we've changed the size of the stages and the number of stages per rig – or per well. We try to look more at how much lateral foot we complete in a day. And we run roughly 1,500 to 2,000 foot of lateral length completed in a day. How that compares to in the past, it's pretty similar because in the past we did half as many stages, but they were twice as big. So it's about the same amount of time. So if you're looking at how many wells we can do per month per frac crew, it's roughly about five. But, again, as we continue to optimize and change that completion cadence and technique, it may move around a bit. But basically five 7,500 to 10,000-foot wells per frac crew per month.

Okay. That's really helpful. Thank you, Mike. And maybe just one other one. Again, the costs keep coming down. And obviously the last 18 months or so a lot of it was just the cyclical nature of the business and costs dropping. But it seems like those have started to level out and yet you're still being able to push these down. Are these costs we're seeing again probably because of the lower drill times, things that are, for lack of a better word, things that you can keep when we turn around and get back into maybe an upswing? Just maybe a comment on that.

Yeah, so, Jason, we're looking at about 30% to 40% on the drilling side of the savings that we've seen is from the optimization piece. Clearly, we're pushing and working to try to get cost concessions wherever we can, but we're also trying to do everything we can from the optimization side to be able to keep those if and when prices do move the other direction. And we're seeing that across the board on the completion side and the production side as well.

Great. Thank you. I'll turn it back.

Yes.

Our next question comes from Richard Tullis with Capital One Securities. Richard, if your line is muted, could you please unmute the phone line? Did you just want me to go ahead and move on to the next questioner?

Sure.

All right. Our next question comes from John Aschenbeck with Seaport Global.

Good morning. Thanks for taking my question. I wanted to get your thoughts here on how you think about near-term acceleration and activity. If you rewind only a matter of weeks ago, the strips closer to $50 and it seemed more likely than not that adding that fifth rig later this year made a lot of sense, almost like a sure thing. Fast forward to today, where oil prices have softened considerably and the fifth rig potentially seems less likely than previously. And if we hang around $40 flat, maybe it makes sense to add the one rig in the Delaware and then in 2017 actually drop to three rigs in the Midland, similar to what's laid out on your commodity price sensitivity analysis on slide 15. So, Travis, I know we'd all appreciate any type of color you could provide on how you're thinking about acceleration going forward, especially in regard to more qualitative factors and not just oil (33:48). Thanks.

Sure. John, I think the likelihood right now that we add that fifth rig later this year is still pretty high. If we needed, for whatever reason, to preserve some capital probably the first lever we would crank on would be to start building DUCs again in order to get some strategic drilling done in our newly-acquired Delaware Basin asset. We don't try to change our drilling schedule because we've had six or seven days of low commodity price. Whether this is an over-correction or a temporary pullback or if it's permanent, we'll just have to wait and see. But if you go back and look at what our behaviors have always been, that when returns to our investors go up, we accelerate activity into that environment. And returns go down, we also slow down activity. So what exactly that looks like towards the end of this year or into 2017, it's going to depend on those factors. Whether our returns – costs come down in conjunction with a lower commodity price, the fundamentalists of supply and demand, are they corrected and we believe recoveries imminent. So there's some macro factors that we have to also consider as we make these decisions. But again, from our financial strength position, we're not going to do anything that's going to put us in jeopardy. We've got cash on the balance sheet right now and we have an undrawn revolver. So we're in a pretty good position to be able to adjust quickly to whatever market conditions dictate.

Got it. That's very helpful. And then one more for me, really a longer-term question. In your Delaware acquisition press release, Travis, you mentioned the company had a path to reach 100,000 barrels per day in the coming years. Obviously a pretty significant jump from today's levels. So I was wondering if you could share any thoughts about how you see that happening in terms of the timelines reaching that level of production? And then also what other things we'd need to see along the way, both in terms of how many rigs need to be added per year and then also what type of commodity price environment would warrant those additional rigs?

Yeah, John, the reason that we made that comment, I made the comment specifically because I wanted to share with our investors that we now have an inventory that could support that kind of growth. The timing at which it gets there, the pace at which we get there, the ability to do it within cash flow are all dependent on how many rigs we run, what the commodity price is, and so it's in the future. And the reason I just made the comment was to be specific about we now have an inventory that can grow us to that point without getting into the specifics of when.

Got it. Very helpful. I'll turn it over. Thanks.

Our next question comes from Chris Stevens with KeyBanc.

Hey. Morning, guys. I have a question on the comment that you guys made regarding double-digit growth within cash flow in a $55 environment. Is the goal over the next three years to be growing double digits within cash flow, or is that really more of a comment to say that at a $50 to $55 environment, you'd be most likely ramping above that five rig number that you guys put out there?

It's really just to say that we built the company around an inventory that can support growth within cash flow. And the third leg of that commentary is that we're doing so at very high rate of return on individual projects. And so as you look forward for Diamondback in the future, we have the ability to accelerate, we've got the balance sheet to be able to do that. We've got the rock to be able to do that. And we wanted to say, again, that we've never been about growth just for growth's sake. I think our industry at times has lost sight of that, that returns really do matter. And I wanted to just make the comment that Diamondback can grow within cash flow and we can do so at a very high rate of return.

Okay. That makes sense. And then on the weighted Howard County well results, I guess the completion design that you guys use is more of the standard design that you've used elsewhere in the Permian. Can you talk a little bit about the next set of wells, the Reed pad and whether or not you'd change anything on the actual completion design there?

You bet, Chris. This is Mike. We are going to change several things on it. We're running micro-seismic and a tracer survey. We're going to test the high-density near-wellbore fracs. We're also going look at some diversion techniques as well as some flow rate tests. We're going to a lot of things on this so that we can see how it interacts with the wellbore in the rock in Howard County so that we can better optimize our completions in the future.

Okay. Appreciate the color. Thanks a lot.

Thank you.

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

Hey. Good morning. Sorry about that. I had to drop off for a couple of minutes a little earlier. Travis, do you see any potential pressure on short-term OpEx efficiencies once you begin drilling in the Delaware Basin? Or is the rig build up moderate enough so it should have little or no impact?

It should have little or no impact, Richard.

Okay. And then just moving on. The Viper, of course, had the recent acquisition. How are things setting up for adding additional mineral interest to the Viper portfolio, say, over the next several quarters?

When we did the cap raise last week, I made the comment that the pipeline of inventory of opportunities has really increased and we continue to see that. And then I'll also say that after we made the announcement, the inbound activity has really picked up. And we think there's some good opportunities in front of Viper Energy Partners in upcoming quarters.

And you're still willing to look outside the Permian, I guess?

Yeah, for Viper Energy Partners, we've never been geographically constrained like we've positioned Diamondback. Viper, since its inception, has looked in other Basins while Diamondback has been singularly focused on the Permian.

Okay. And then just lastly from me, Travis, I know you addressed this a little bit earlier about current oil gas component. But as you look our further, say, one, two years, as you drill more, say, in Glasscock County and then into the Delaware Basin, do you think the oil/gas mix could get a little gassier over time, although maybe bigger wells from the Delaware Basin?

That's possible, Richard. I'm not sure that we've got the granularity to model what our oil/gas cut's going to be in the future. I think notionally you could see an increase. But, again, we may be putting a micrometer on a brick there trying to forecast that.

Sure. I understand. Well, that's all from me. And thank you. Appreciate it.

Thanks, Richard.

Our next question comes from Ben Wyatt with Stephens.

Hey. Good morning, everyone. One just quick question from me, more on the Southern Delaware and infrastructure in place. You guys mentioned, at least in the press release, when you did the acquisition you have saltwater disposal, you've got gathering in place right now. But how much can you guys ramp until you feel that the existing or planned infrastructure in place is enough? And then maybe as a follow-up to that, who at the midstream level should we be keeping our eyes on, whether it's public or private, to really monitor the pace of infrastructure development in the Southern Delaware?

Well, I won't comment on the midstream guys that are out there. There's a lot of them. You guys do a lot of research on that. But I'll tell you when we laid out a development plan that I spoke of earlier, with one rig at the end of this year and then one rig all of next year and then ramping activity to two, three and four rigs, that all has taken the infrastructure build-out and the associated requirements for stimulation fluids, et cetera, those are all taken into account. That's what we do. So we don't put a drilling schedule out there that doesn't contemplate having the adequate infrastructure in place to execute on that drilling program.

Very good. Well, Travis, I appreciate it. That's it for me. Thanks, guys.

Thank you, Ben.

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

Thanks again to everyone participating in today's call. If you have any questions, please contact us using the contact information provided.

Ladies and gentlemen, this does conclude today's presentation. You may now disconnect and have a wonderful day.